Dealing with mature offshore oilfield has complicated problems both surface and subsurface. In the reservoir condition high water cut wells make some bad impact in the production stages. Liquid handling facilities, tubing pipeline erosion, broken sand control, and high power consumption are several problem caused by high water cut wells. WW is an offshore oil field which has developed since 1990s with OOIP 758 MMBO. This reservoir was divided into several layer, 33 series is depleted reservoir with water injection since year 2000s (RF 23%) and 35 Series has strong water drive as its driving mechanism (RF 56%). Almost 85% of the oil wells is producing with water cut more than 97%. Increasing water cut or even watered out phenomenon was frequently happen during production stage, some of this problem was happen after well intervention such as after pump replacement. This paper will show the successful case of decreasing water cut significantly from WW D-29, WW H-12, II A-22. Laboratory test was firstly done to check the compatibility test of the rock with modified completion fluid. This chemical was mainly works as phase change water control and oil stabilize well for completion fluid. It was pumped simultaneously with regular completion fluid (filtered drill water and additives). Killing well was mandatory procedure when shut in wells will be repaired. GGR team supported by Production and Workover Team did integrated study to choose the chemical and well selection based on some criteria. WW D-29, WW H-12, and II A-22 are wells which have implemented modified completion fluid treatment. Those wells are produced from sandstone reservoir and drilled more than 10 years ago. During production period, water cut was significantly jumped due to several reason, such as pump replacement job, re-start up after the well trip off, etc. The result of the project were very excellent, WW D-29 (from 98% to 86%, gain +/− 180 bopd), WW H-12 (from 80% to 40%, gain +/− 250 bopd) and II A-22 (96% to 75%, gain +/− 130 bopd). These result give a lot of impact of increasing oil production in WW Field. This paper will elaborate how to solve the problem in offshore mature oil field special case for high water cut wells using modification of completion fluid treatment. We have succeeded increasing oil reserves.
The 34-X sand is a solitary sand reservoir and locally sinuous sandstone body. This reservoir is displaced by major normal fault zone known as the Widuri Fault that divided in two contrast areas of 34-X facies and production characteristic. The objective of this paper is to present how the combination drive reservoir redevelopment project was planned, extensive evaluation process has been made, and successful cases in enhancing reservoir ultimate recovery. The solution for this title is multi-disciplinary approach to create sharp analysis. The first step is numerical calculations of material balance to determine oil-in-place in a reservoir and to predict the future performance, this phase is tricky due to multi-driving mechanism reservoir behavior, therefore material balance analysis need to be supported by deep sub-surface analysis in property distribution on second step. This part simultaneous inversion, 4D timelapse seismic and sweep pattern analysis have been done to get comprehensive interpretation of reservoir characterization and reservoir connectivity monitoring. The third phase is supporting analysis by tracer injection, we implement tracer in several wells to ensure connectivity of the reservoir, and to evaluate injection performance. The last phase is technical difficulties in operation area, complex reservoir evidently cause complex operation difficulties, sand problem, formation damage, tubing leak, water out, plug-up injector well, etc. are problems we have to deal with. From reservoir pressure data distribution, surface gas-oil ratio, water production, and well behavior concludes that 34-X is combination drive reservoir (water drive-solution gas drive) and based on fault analysis we divided into two areas east and west, 34-X West area sandstone body is straight, with approximately 100-300m wide and 8m thick. The western part water cut is over 90%, this indicates the conduits for preferential water flow has established. From material balance calculation OOIP estimated 16.3 MMSTB. The eastern part of the 34-X sand appears to be isolated from western portion of the channel by a fault with a throw of 90 feet. The eastern portion of the widuri field is influenced by a partial water drive, indicated by high water cut histories. However the water drive is weak, the average pressure has declined to 520 psi, estimated OOIP 56.2 MMSTP. Before the redevelopment project recovery factor is 22%, and increase significantly to 27.4% simultaneously with oil production rate increase up to 40%. Dominantly pressure-depletion drive during hydrocarbon production in 34-X sand in west area occur since that area provide poor connection to an aquifer and for east area of Widuri Fault condition is limited aquifer. The water cut of production in 34-X sand well varies across the axis of the sandstone body, it caused by controlled by internal heteroginity.
Deal with brown oil field with runlife of the production more than 35 years has many challenges. Pressure depletion was one of the main concerns of maintaining survival of the field. From the geological aspect, reservoir which produced from limestone was also have many challenges, especially for heterogeneity of the reservoir. Both problems were faced in Rama field which impact the low recovery factor of this brown limestone field. Some approaches was held to increase oil recovery of this field, integrated sub surface review was done aggressively to bring some concept and followed up by some efforts from drilling, workover also surface facility.Rama field was developed in 1975 with the initial production was about 20,000 BOPD. As of June 2009, Rama field has been producing more than 137 MMBO with production Ϯ 4,000 BOPD mainly from Upper Baturaja. A waterflood project was held in the field from 1982 until 1991 where a large amount of sea water had been injected into Baturaja formation. As the result, the reservoir pressure increased and maintained from 700 psi into 950 psi during the water flood period. However, early water breakthrough was occurred as well and got the water cut jumped into more than 90% from initially 60%. In some wells the water cut could be as high as 99%. Due to its bad impact on the oil production the water flood project was suspended in 1991. Ten years later an oil re-saturation phenomenon has been observed from some wells produce from Upper Baturaja with water cut in the range of 50 -90%. The oil production rate from Upper Baturaja was 3,000 BOPD with 85% -90% water cut. In early 2009 two infill well was drilled and one well was reactivated and gave good indication of decreasing water cut Rama E wells are among the wells that got bad impact from massive waterflood due to water cut increase, and one by one those wells are abandoned. The platform itself has been abandoned since 1999. Regarding good result of two infill and one reactivation wells, it was proposed to reactivate Rama E platform by modification of Rama-E platform include refurbishment of existing platform, installation of mezzanine deck, Power Control Room, iso-transformer, production process piping and equipment. Reactivation of the wells themselves would be done using jack up rig and snubbing unit.The objective of this project is to add oil reserves and production with sufficient cost by doing reactivation abandoned platform without drilling new wells.The recovery factor by June 2009 from Upper Baturaja is estimated 14% (OOIP Ϸ 505 MMBO). By reactivation of five wells in Rama E, reserve increase up to 631 MBO (2011), it was increase recovery factor significantly.
The Cinta Field is one of fields in Offshore South East Sumatera Block which discovered on 1970. The first well development was in 1971 in Talang Akar Formation (TAF) which consist of Zelda and Gita member. Peak production was 70,721 barrel oil per day on Jan, 1977. Initial reservoir pressure was 1488 psi and current reservoir pressure is 500 psi. Nowadays, Cinta field has produced 4,300 barrel oil per day and average water cut 96%. The production challenges in TAF are depleted reservoir pressure that leads to sand and gas production. Artificial lift method applied in Cinta Field is Electric Submersible Pump (ESP). Sand production can create problem in ESP that lead to trip off overload or the worst is shaft broken. Loss of production due to waiting barge to replace the broken ESP will occur. Mechanical sand control has been applied such as gravel pack, expandable sand screen and standalone sand screen to prevent sand produced through ESP. Most of them have failed due to massive sand production. Re-sand control can be alternative solution for this problem, but it can't be done due to low reservoir pressure and most of sand control will lowering productivity index of the wells. Immediate solution of this situation will be improvement of ESP itself. ESP will adapt with sand production situation by improving material and design of pump stages. This paper will present improvement run life of ESP by using new type ESP that is more suitable in sand production situation in Cinta Field.
This paper covered success collaboration between sub-surface and surface engineer in managing mature offshore oil field in Asri basin, Southeast Sumatera, Indonesia. The main objective was to maintain oil production rate and increase ultimate recovery in the most efficient way, technologies that applied strictly selective to minimize risk while optimize oil production. Common problem faced are extremely high water cut and high operating cost due to massive artificial lift application. The three effective tailored methods in this paper are: (1) Determining residual oil volume and locating the position. Material balanced calculation and core analysis are the tools to determining residual oil volume, while tracer test conducted in order to determine the location and distribution of the oil remained. (2) Surface facilities assessment, facilities are ageing and need to refurbished/replaced after 27 years of production, it creates limitation in operation area. (3) Potency screening, in this phase we focused more on technical difficulties assessment, both sub-surface and surface (from method 1 and 2) result analysis are combined to determined technology selection. After that we put into action, and do evaluation on cost spending and production performance. Efficiency is the key issue in mature field redevelopment, solid collaboration between sub-surface and surface team lead to satisfying result to reduce production decline. Several case studies have been included in the paper to highlight the detail project: (1) Idle wells, to increase production it is very important to increase well count, the wise way is by utilize existing wells in idle condition. Mechanical failure, water out, formation damage, low potential, etc. are cause of idle wells, in the last 3 years 13 wells successfully back to production. (2) Modified completion fluid, one of technology applications with ‘breakthrough’ result. In depletion drive reservoir we found lot of residual oil potency that can't be sweep, the solution is to reduce oil viscosity around wellbore and increase the mobility using modified completion fluid, and the result is beyond expectation. (3) Water injection redirection, based on performance evaluation and tracer injection analysis, several injectors is ineffective due to reservoir connectivity and mechanical issue, this project creates new sweep pattern and successfully increase recovery factor. (4) Mechanical loss handling, we found big losses contribution from tubing leak, after laboratory and field analysis losses can be reduced. Technology and integration of sub-surface and surface capabilities are vital to unlocking the full potential of mature assets and achieving higher recovery factors. Application of the three tailored methods was considered as an appropriate way to approach and manage a complex mature field redevelopment.
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