Complex hydrocarbon distributions where reservoirs are filled by oil and gas phases with different densities and genetic types interfingering within a basin are a common phenomenon in Southeast Asia and are often attributed to vertical migration. Attempts to understanding the controlling factors of vertical hydrocarbon migration by modeling the hydrocarbon charging and entrapment history from two Cenozoic basins in Southeast Asia—West Java and the Madura Platform—are discussed.
A modified invasion percolation algorithm was used to simulate the secondary migration models, which follows the principle that migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy and capillary forces. Three-dimensional (3D) seismic data were used as the base grid for migration simulation to capture the effect of both structure and facies variations on fluid flow.
Two models, one from the West Java Basin (fault-bounded structure) and the East Java Basin (nonfault-bounded structure), are presented. For both cases, interfingering between oil and gas occurred, with most oils trapped within the lower formations, a mixture of oil and gas dominates the middle formations, and mostly gas in the upper formation. These vertical arrangements are possible because of the relatively weak formational seals within the basin. For vertically distributed reservoirs, oil is often trapped within the lower interval, and gas is trapped at the upper interval. For a basin dominated by a vertical migration regime, the potential risk for hydrocarbon lateral travel far away from the kitchen is high, thus increasing the potential risk of prospectivity away from the kitchen. Understanding factors that help control vertical migration also help geologists better understand hydrocarbon distributions within the basins.
Case studies during which modeling helped determine the factors that influenced vertical hydrocarbon migration and the resulting potential phase distribution prospectivity risks in the studied basins are discussed.
This course discusses the fundamental sand control considerations involved in completing a well and introduces the various sand control techniques commonly used across the industry, including standalone screens, gravel packs, high rate water packs and frac-packs. It requires only a basic understanding of oilfield operations and is intended for drilling, completion and production personnel with some sand control experience who are looking to gain a better understanding of each technique’s advantages, limitations and application window for use in their upcoming completions.
Not too long ago, horizontal drilling revolutionized the petroleum industry. Emerging logging-while-drilling and geosteering technologies helped bring about multilateral, maximum-contact, and smart-completion wells, allowing reservoirs to be developed and produced much more efficiently and economically. This increased recovery, thus boosting reserves. In the process, formation evaluation plays a critical role in determining whether a producer or an injector is successful. More recently, efficient mass horizontal drilling and optimized multistage massive fracturing have turned traditionally nonreservoir source rock into sweet spots of energy strategy on a global scale.
Abu Dhabi Fields are showing the presence of several leads/prospects with a significant amount of hydrocarbon accumulations, where the faults provide the critical up-dip closure. The classical approach of fault sealing based on the construction of a deterministic juxtaposition and Shale gouge ratio analysis will not work in Abu Dhabi fields, as most of the section is mainly consisting of carbonates and the faulting history is mainly overcoming by strike-slip movement, where the vertical offset along the faults are minimum. Therefore, implementing a new approach based on construction of an integrated modeling using well logs, seismic, outcrop analogues, 1D MEM and 3D MEM, complemented with modeled and measured pressure data is necessary.
The sealing behavior of faults is known to control aspects of hydrocarbon migration and reservoir distribution in space and time, the least understood factor in petroleum system. Fault planes can be sealing and prevent flow of fluids in one time and be leaking in another time. It can be sealing for oil and leaking for gas/oil or it can be sealing at one horizon and leaking at another horizon. This paper provides a workflow for assessing the risk of fault seal in undrilled prospects. This is an integrated approach based on statistical analysis of a database of sealing and non-sealing faults to solving fault seal issues, which involves a combination of: Detailed microstructural, geometries and petrophysical property analysis of fault rocks; fault zone poroperm histories, sealing mechanisms, sealing capacities, stability and the timing of fault activity during the burial history. In addition to the geomechanical modeling aspects with the characterization of fault array geometry, population, distribution of sub-seismic faults from wells, cores and outcrop data and an evaluation of the seismic scale fault array attributes.
Faulting mechanisms in Abu Dhabi petroleum system have complicated movement histories involving numerous periods of reactivation and, in some cases multiple reversals of fault-movement direction. Therefore, to fully assess fault-seal potential it is necessary to examine the evolution of faults through time and the stress history, in addition to fault characterization, population, sealing criteria, and fault geometry/orientation. The results offer useful insights in the main factors and highlights how the faults behave, with risk evaluation, in terms of uncertainty ranges and sensitivities. As a result, the explorationist will have indication to remove the "uncertain" results. In addition, well data, 3D seismic data, and advanced interpretation tools can make it possible to accurately characterize the geometry/distribution and kinematics of faults, the in situ pressure differences across them and the possible compartmentalization.
During this low oil price era, E&P operators are challenged to reduce operating costs by evaluating their production system. Integrated production model (IPM), which combined subsurface model and surface production system, is a tool that can be utilized to evaluate the existing production system and to arrange the upcoming production strategy. This paper focuses on Kaji-Semoga oil field which consists of three field processing stations, three compressor stations, 130 ESP and 63 gas lift (GL) wells.
The system evaluation started with evaluating the total GL injection required for all GL wells to observe the opportunity to increase the oil production or reduce the active compressor. This required gas lift performance curve for each wells with sensitivity to the various well head pressure. The ESP, as equipped with variable speed drive, can be optimized in accordance to the pump capacity and facility constraints. The artificial lift reliability was also evaluated to reduce the oil deferment and to foresee the next production strategy. The IPM for Kaji-Semoga was built to integrate those issues.
Based on the IPM, the total GL injection rate can be reduced by up to 17% while maintaining the total oil production. With the aim of cost optimization by saving the gas fuel and reducing compressor cost, then the gas lift compressors had been shut down and relocated to another asset. As the result, 24% of total annual compressors cost was saved. From the artificial lift reliability evaluation shows that GL system reliability was reduced along with the gas shortage, whereby contributed 71% of total oil deferment. The artificial lift conversion from GL to ESP then selected as a solution. The strategy for shutdown the next gas lift compressors was then generated in accordance with the artificial lift conversion schedule and the gas lift network distribution. To overcome the limitation of liquid handling capacity at the field stations due to the conversion project, the IPM could optimize the GL and ESP simultaneously thus total fluid production can be maintained at a minimum level by continuing to retain the oil production.
The paper describes some of lesson learned in constructing and utilizing the IPM as an effective tool, not only to optimize the existing production system, but also to generate the future production strategy, cost reduction opportunity and operation maneuver.
This paper describes an efficient approach to evaluate waterflood connectivity performance in complex compartmentalized reservoir, the objectives are to increase the oil production performance and manage mature fields effectively, and also to enhance ultimate recovery in the long run. It is also very useful to get better understanding of detail reservoir characterization, reservoir internal architecture, reservoir distribution, pressure monitoring and subsequent water flood sweep pattern efficiency. Multi-disciplinary methods applied to maximizing all of data and create strong analysis. The first phase is deep sub-surface analysis in property distribution, simultaneous inversion, 4D time lapse seismic and sweep pattern analysis, those analysis have been done to get comprehensive interpretation of reservoir characterization and waterflood monitoring. The second phase is tracer injection, we implement tracer in several wells to ensure connectivity from injector to several producers are efficient and optimal. These methods were performed for several regions of this area which contains a large number of well, nearly 200 wells consist of vertical, deviated and horizontal wells. Reservoir distribution in Windri area interpreted as stacking channel with high sinuosity geometry. This reservoir consists of predominantly of marginal marine claystone interbedded with deltaic sandstones, thin limestone and coal. Bio-stratigraphic analysis from cores shows that the reservoir was deposited in estuarine setting, interrupted by a brief shallow marine incursion. Seismic amplitude mapping at the upper base Gita horizon reveals a system of meandering channels. Compartmentalised reservoir in Windri area divided into 5 sweep pattern to make analysis more detail and accurate. Each of compartment have different characteristic, this is the challenging part in Windri area. East of windri area channel divided into 4 channels and it shows the evolution and movement of the channel that can control the property distribution and reservoir connectivity. Group two shows good result from tracer injection and it is supporting the interpretation of reservoir distribution and characterization within the area. Integrated 4D time lapse seismic generate pressure monitoring movement from each of waterflood phase. The results of this integrated study implementation are excellent, the ineffective water injection pattern now become effective, there is no unavailing injection well, every pattern is connected and link to each other, so that we can achieve our goal to enhanced recovery factor from 16% to 20%. Reservoir characterization using multi-discipline method reduce uncertainty of heteroginity sand and fluid prediction. Integrated waterflood analysis has been implemented for prospect generation, production optimization and overcome pressure degredation in this area.
Prayoga, Ongki Ari (State College of Technology STTNAS) | Alvrida, Desy Ayu (State College of Technology STTNAS) | Taslim, Muhammad (PT. PERTAMINA EP) | Ginanjar, Aji Rahmat (PT. Pranalika Energi Nusa) | Nurhadi, Dhea Rizky (PT. Pranalika Energi Nusa) | Barkah, Annisa (PT. Pranalika Energi Nusa)
Java Field is located in the North West Java Basin that is one of the hydrocarbon prolific basins in Indonesia. The most of oil and gas in this area was produced from Jatibarang volcanic reservoir that consist of volcanic rock such as tuff, pyroclastic breccia, and lava andesite. In general, volcanic rocks have been ignored because a perceived lack of reservoir quality. Fractures were detected in the Jatibarang volcanic formation which enhanced porosity and permeability allowing hydrocarbon production. To exploit this type of reservoir to the fullest, comprehensive study must be done including determination of distribution and orientation of fault and fractures, possible migrations, and trap of hydrocarbon. Fractures identification and distribution modelling has been carried out in Java field with a combination of seismic interpretation by post-stack seismic geometrical attributes extraction, wireline log, imaging log and cores. A well log interpretation technique on the artificial neural network concept has been developed for evaluation of the volcanic rock reservoir and it was calibrated with imaging log and sidewall core data. Detailed petrophysical and petrographycal analysis have shown that the volcanic facies of Jatibarang formation is characterized by several types of tuff, andesite breccia, and andesite-basalt lava. The tuff facies is the best reservoir that has a multiporosity types with a range value of total porosity 6-19%, secondary porosity index value is 2-12% and average of fracture permeability value is ± 42,90 mD. The formation evaluation analysis of several productive well in Java field suggested that the distribution of productive well is mainly controlled by distribution of fractures beside by distribution of volcanic facies. The fractures in study area has three general orientation that is N-S, NNW-SSE and NE-SW trend strike of fractures. The all of fracture subsets were generated by polyphase tectonic event interpreted by N-S compressive stress during Mio-Pliocene and originally thought to be an extensional regime of the Cretaceous-Oligocene Meratus System that was rejuvenated during Pliocene. The N-S trend of conductive fractures is a potential open fractures that have ability to save and flow the hydrocarbon. Regarding the orientation of potential fractures, a horizontal well lateral from west to east is suggested for producing potential fractured volcanic reservoir in order to penetrate perpendicular to strike of productive fractures. This study can be analogue for all of unexplored volcanic reservoir, so this type of reservoir can be future target for hydrocarbon plays in Indonesia.
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.
Afi, F. N. (CNOOC SES Ltd) | Gunawan, H. (CNOOC SES Ltd) | Widiatmo, R. (CNOOC SES Ltd) | Waskito, L. B. (CNOOC SES Ltd) | Nugroho, P. (CNOOC SES Ltd) | Luthfan, M. (CNOOC SES Ltd) | Prayogo, R. (CNOOC SES Ltd) | Suryana, A. (CNOOC SES Ltd)
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.
Offshore Noth West Java (ONWJ) production sharing contract block has been producing since 1970s. The block consists of many oil and gas sturctures, both clastic and carbonate reservoirs. The era of "easy reservoirs" is almost to an end as the fields are maturing over time. Long term development plan is desired to sustain the ONWJ block oil and gas production. The development strategies are focusing on low resistivity development, bypassed oil as the low hanging fruit, add reserves from deeper reservoir and shallow gas development.
Bypassed zones exploitation contributes in sustaining ONWJ oil and gas production. Drill stem test data back from the 70s was revisited, well log and correlation was reviewed to find the proven "low hanging fruit" and possible reserves. Sidetracking well to twin the proven exploration well or simply recomplete existing wells were done to add reserves.
Low resistivity reservoir was considered unattractive or even identified as non-reservoir in the early life of the block exploitation. However, with thourough evaluation and suitable hydraulic fracturing treatment, the reservoir contributes significantly in sustaining production decline. These zones become one of the keys in future development
The gas demand from the near market is continue growing with attractive price. It becomes one of the drivers to find more hydrocarbon gas. In the old days, shallow gas became one of hazard that need to be mitigated. Recently, as the major gas reservoirs continue on its depletion, this shallow was produced; converting from hazard to reserves.
Above strategies were successfully applied within fields in ONWJ block and doubled its production to the level of 43,000 bopd and 180 mmscfd within less than 5 years since operated by Pertamina Hulu Energi (PHE) ONWJ. This paper will discuss subsurface strategies to achieve and sustaining hydrocarbon production and related case studies of several fields in Offshore North West Java. It will also discuss the learning curve for future strategy and application in further redevelopment.