Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Abstract fieldThe field, located 120 km offshore in the Malaysian deep water, was discovered in December 2003 and put on production in November 2012. As per the Field Development Plan (FDP), Reservoir Management Plan (RMP) for G-K field is to inject water and gas from the beginning of oil production in Pink1/2 and UK1 reservoirs. The objective of the study was to optimize the voidage replacement by WI, so as to maximize the up-dip oil recovery. The study was conducted on a sector model. A compositional PVT model, having 17 pseudo components, was developed. To explain the compositional variation in reservoir, the PVT variation has been incorporated. The SCAL data, same as used in FDP, have been used for the study. Two producers were considered in the sector model so as to study the oil movement between the two wells. One Injector each was placed in GCG and aquifer. For UK1 reservoir, the plan is to re-inject 60% of the produced gas from UK1. For PINK1/2, it is planned to re-inject all the produced gas from PINK 1/2 plus any remaining gas left after internal usage. The total VRR target for both the reservoirs is 1.0, and the remaining part of the voidage replacement is made up by water injection. The FDP RMP was reviewed, because it was thought that in view of the small gas cap size (m ratio about 0.2 for PINK1/2 and 0.18 for UK1) and limited Gas Injection capacity, making up VRR equal to one by WI may not allow GC to expand rapidly. During the study, the whole process of Gas Injection and water Injection was divided in two parts, viz, Pre-Gas Breakthrough period and Post-Gas Breakthrough period so as to separately assess the impact of limited gas injection capacity after gas breakthrough. For PINK1/2 reservoirs, WI at 25% of the Instantaneous Voidage Rate (IVR) provides the best recovery before gas breakthrough. To avoid gas flaring after gas breakthrough, WI rate has to be increased to 40% of the IVR. For UK-1 reservoir, WI at 35% of the IVR provides the best recovery. Due to this study, there is an improvement of about 10% oil recovery over FDP study, which is equivalent to over 70 MMSTB of oil. In UK1 even after this improvement, a significant amount of up-dip oil still remains un-swept. This may require additional gas injection or drilling infill wells up-dip to the present location. During FDP the study was conducted on a Black Oil model, the present study was conducted on a compositional model.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.57)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
Abstract Production optimization and improved recovery efficiency while reducing operating and capital expenditure has been the main goal of the operators, and makes it imperative under the current oil prices. Reservoir Management Programme (RMP) is a comprehensive and integrated process of establishing control over hydrocarbons appraisal, extraction, voidage replacement, and optimizing production and reservoir performance, and it is the key to achieving maximum recovery. Monitoring well and reservoir performance from initial completion to abandonment is critical to ensure efficient operation, optimum economics, and safe environment. Tracking production rates, water cut, wellhead pressure, casing pressure, well integrity, and planning recompletion, workovers, sidetracks, in-fill drilling, enhanced oil recovery etc. will require close watch, accurate analysis, and timely execution at considerable cost and effort. Therefore, it is critical to stay up-to-date on the latest developments in technological advancements in this area, be judicious in the methods used in acquiring the right data at the right time, and more importantly, integrating all acquired data to discern performance patterns, predict future behavior, and avert any problems. More detailed understanding of reservoir characterization and reservoir physics are the need of the hour to be efficient and successful in the various stages of the exploitation of the reservoir. Furthermore, advances in horizontal drilling, smart well completions, deep-sea drilling, and highly complex operation, have changed the playing field and rendered many old conventional tools inadequate to meet the new challenges. For example, rates from some intervals along a horizontal well can be too low to be measured by a typical flowmeter. The cost of measuring reservoir pressure in individual layers can be cost prohibitive, especially once the completion is in place. Reservoir characterization, understanding lateral continuity, and permeability anisotropy can be time consuming and expensive. Locating the source of a casing pressure accurately, quickly, and without having to mobilize special equipment (rig-less) is critical. This paper illustrates the application of the above principles by showing actual cases, methodology of data acquisition and processing, focusing on the added value from the new information.
- Asia > Middle East (0.28)
- Asia > Malaysia (0.28)
Abstract Enhanced Oil Recovery (EOR) has been touted as the Holy Grail for achieving the highest possible recovery factor. This technology is fairly matured in land based development, with older fields in Bakersfield and Indonesia achieving up to 90% recovery factors. However, EOR considerations take on a whole new dimension in an offshore environment. Astronomical rig rates and escalating operational costs have deterred operators from pursuing ambitious offshore EOR programs. Most EOR pre-development studies are focused on the reservoir; in particular altering relative permeabilities, reducing residual hydrocarbon saturations, and improving sweep efficiencies. But with up to 40% of slated huge EOR capital development cost earmarked for well construction, more technical focus should be emphasized on well architecture. This paper details the well architecture work done on several Malaysian fields scheduled for EOR redevelopment. A workflow featuring the various design and operational considerations is explained. Well architecture is composed of two main components: Trajectory and completions functionality. Malaysia's portfolio of complex reservoirs requires EOR development to be done through a creative lens of complex trajectories and multilateral wells. Marginal economics have precluded the practicality of conventional well construction. A key enabler in cost efficient EOR redevelopment is advanced completions, namely remote downhole flow control and monitoring. In order to achieve incremental production beyond secondary recovery, reservoir conformance is of critical importance. Remote real time monitoring will allow decisions to be made accurately in a timely manner. Downhole flow control permits purposeful manipulation of injection and production streams. Proper installations of advanced completions will also reduce future intervention and operational costs. Advanced well architecture however, also comes with a whole range of operational and installation risks. But these can be mitigated with proper planning and coordination with all parties involved.
- Asia (1.00)
- North America > United States > Alaska (0.28)
- North America > United States > California > Kern County > Bakersfield (0.24)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field (0.99)
- Asia > Malaysia > Sabah > South China Sea > Sabah Basin > North Sabah PSC > Block SB 308 > St. Joseph Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Abstract Angsi field is located offshore Terengganu, Malaysia. It was identified as the candidate for a pilot project to evaluate the effectiveness of chemical enhanced oil recovery (CEOR). Injection of alkali-surfactant (AS) slug was used to improve recovery factor through the reduction of residual oil saturation (Sor). The pilot project utilized single well chemical tracer test technique (SWCTT) to measure Sor change near well bore due to reactions of CEOR process. The pilot results were later used to update the reservoir dynamic model and to support decision making for potential expanded field application. The pilot project faced many challenging technical and operational obstacles: offshore location, high reservoir temperature, sea water as injection water, water softening facilities requirement, and unmanned satellite platform with limited space. In addition, compliance to all Health, Safety, and Environment (HSE) requirements is a must, to ensure the pilot operation is carried out in a safe manner. This paper will focus on the overall pilot design, planning and some results. Operational, HSE and quality control will also be discussed as background to the pilot project.
- North America > United States (1.00)
- Asia > Malaysia > Terengganu > South China Sea (0.25)
- North America > United States > Kentucky > Big Sinking Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > West Central Graben > PL2244 > Block 21/27a > Pilot Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > West Central Graben > P2244 > Block 21/27a > Pilot Field (0.99)
- Asia > Malaysia > Terengganu > South China Sea > Malay Basin > Block PM 305 > Angsi Field (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Reduction of residual oil saturation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Tracer test analysis (1.00)
Angsi Waterflood Management and Surveillance - An Integrated Team Approach
Othman, Mohamad (Petronas Carigali Sdn Bhd) | Salleh, Zaimi (Petronas Carigali Sdn Bhd) | Redmond, John (Petronas Carigali Sdn Bhd) | Jakobsson, Nils M. (ExxonMobil Exploration Production Malaysia Inc.) | Yunus, A. Rahman (Champion-Servo BV) | Abu, A. Kamarolaili (Premier Enterprise Corp. Sdn. Bhd.)
Abstract The Angsi field is a new oil and gas development in its early production phase. The field is operated by PETRONAS Carigali Sendirian Berhad (PCSB), Peninsular Malaysia Operations (PMO). Water flooding is being used to improve oil recovery. The waterflood is expected to yield close to a three fold increase of the oil recovery compared to a scenario without injection. The production from waterflood reservoirs contributes 90% of the overall Angsi oil production. It is imperative that the waterflood is managed in a prudent way to ensure its full potential is realized. An instrumental element of prudent management is a well-planned and well-executed surveillance program. The Angsi waterflood project, as many other waterflood projects, is significant in scope and multi-disciplinary in nature. It was determined that the adoption of an integrated team approach would be the optimal way to facilitate prudent management and surveillance of the Angsi waterflood project, and consequently that it would be an essential key to a successful waterflood. The purpose of this paper is to discuss the integrated team approach adopted for the Angsi waterflood project. The paper describes how the team was built and how it has functioned during its first year. Included in the paper is a discussion on the Angsi integrated waterflood management and surveillance program. The program was developed by the team and now serves as a guideline for all Angsi waterflood related activities. Adopting an integrated team has provided the necessary forum for open and inter-disciplinary exchange of ideas and experiences on waterflood related matters. As a result, it has aided the fostering of cooperative actions and the capturing of synergism, all to the benefit of the Angsi waterflood project. Thus far, the integrated team approach has resulted in a timely commissioning of the water injection plant, and a high plant uptime and water injection availability. Introduction The Angsi field is located in the South China Sea, 170 km off the East Coast of Peninsular Malaysia (Fig.1). The field was discovered in 1974 and is currently being developed by PETRONAS Carigali Sdn. Bhd. (PCSB) and ExxonMobil Exploration Production Malaysia Inc. (EMEPMI) as joint venture partners. The field is operated by PCSB as a Production Sharing Contractor (PSC) to Petroliam Nasional Bhd. (PETRONAS), the Malaysian National Oil Company. The field is a major contributor to the gas and oil production of PCSB, Peninsular Malaysia Operations (PMO). The Angsi field is an asymmetrical anticline elongated in the Northwest to Southeast direction and is part of the Angsi-Besar-Duyong regional structure trend. Based on the areal distribution of hydrocarbon-bearing reservoirs, the field has been divided into five areas namely Main, West, North, South and Southwest (Fig.2). Stratigraphically, hydrocarbons are found to be distributed in the Groups I, J and K sandstones of Lower Oligocene to Middle Miocene age. Volumetrically, the major gas bearing reservoirs are the I-1, I-85, I-100, K-20/22, K-25/30 while the I-35 and I-68 sandstones form the major oil bearing reservoirs. Reservoir simulation studies indicate that water injection into the I-35 and I-68 sandstones will efficiently sweep the reservoirs, and that it will yield high production rates and high ultimate oil recovery. Field Development Overview The current field development plan covers the development of the Main and West areas. The South and North areas of the field are planned for future development. The Angsi complex consists of a central processing platform (ANPG-A) and a bridge-connected drilling/riser platform (ANDR-A). The complex is the host and processing platform for the Angsi West platform (ANDP-B), and future satellite platforms, Angsi South (ANDP-C) and Angsi North (ANDP-E). Fig.3 shows platforms layout.
- Phanerozoic > Cenozoic > Paleogene > Oligocene (0.54)
- Phanerozoic > Cenozoic > Neogene > Miocene (0.54)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (7 more...)