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Results
Summary In waterfloods, the existence of highly conductive thief zones causes poor volumetric sweep efficiency, resulting in early breakthrough and excessive production of water. A conventional strategy of redirecting injection by closing off perforations yields short-term benefits because diversion occurs near the wellbore. As an alternative, temperature-triggered submicron polymers with low viscosity (popping agents), which give an opportunity for conformance control deep in the reservoir, have been introduced in recent years. This technology aids conformance control by plugging the high-permeability zones and diverting the fluid to the unswept portion of the reservoir. Understanding the critical parameters that lead to a successful treatment and accurate determination of the slug size are two important criteria for a technically and economically successful treatment. In this study, we first investigate the effect of different parameters on the success of a conformance control treatment. A comprehensive design-of-experiments (DOE) study resolves the effects (and combined effects) of kv/kh, treatment fluid concentration, thief-zone to matrix-permeability ratio, mobility ratio, and location of the placement in the reservoir. Next, a methodology is developed for accurate determination of the conformance slug size. The method is built on the temporal moment and residence time distribution analysis (RTDA) of interwell tracers. Dynamic flow- and storage-capacity curves are used to identify the optimum slug size. 3D thermal computer simulations show that thief-zone to matrix-permeability ratio and placement location of the polymer are the most important parameters that affect the success of a treatment. The most desirable setting is placement of the polymer deep in the reservoir, closer to the producer within high kv/kh reservoirs. Furthermore, the computer simulations confirm the power of the new technique for optimal slug-size determination. This new technique can avoid underestimation of the volume that must be treated, which is critical for the success of a treatment.
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Salema Field (0.99)
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- (3 more...)
Analysis of Flow and the Presence of Fractures and Hot Streaks in Waterflood Field Cases
Baker, Richard (Baker Hughes RDS) | Stephenson, Tim (Gaffney Cline & Associate) | Lok, Crystal (Gaffney Cline & Associate) | Radovic, Predrag (Gaffney Cline & Associate) | Jobling, Robert (Gaffney Cline & Associate) | McBurney, Cameron (Gaffney Cline & Associate)
Abstract Over a thousand well pairs in five different fields in Western Canada have been examined using communication analysis techniques. The results of this analysis strongly suggest that in addition to conventional Darcy type flow through the matrix rock, there is also strong communication between wells through induced fractures, and/or natural fractures. Most of these five fields are not typically thought of as naturally fractured. Nonetheless this type of fracture flow exists. It is highly likely that these hot streaks are pressure sensitive and therefore have a geo-mechanical component that controls permeability. The geo-mechanical component means that permeability can vary with time and injection pressure. This work on the Western Canadian Sedimentary Basin (WCSB) is similar to work done by Heffer in the North Sea.
- North America > Canada > Alberta (0.87)
- North America > United States > Texas (0.69)
- North America > Canada > Saskatchewan (0.68)
- (3 more...)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (5 more...)
Abstract More than 80% oil reservs is heavy oil in Bohai Bay of China.This paper describes the practice and research for comprehensive adjustment of SZ oil filed which is a large scale multi-layer sandstone heavy oil reservoir in China Offshore.In order to explore the potential of the reservoir, based on the fine geological studies, dynamic data of production and testing, we got water-cut contour of sub-layers by reservoir engineering method. Quantitative description of the remaining oil in the vertical and plane direction was gained by reservoir numerical simulation method, which could be the foundation for deployment of infilling wells and adjustment program of the oilfield. All the above were verified by the pilot well. Based on these studies, we designed infill wells between the edge and corner production wells and the the well network of the oilfield changed from nine-spot pattern to line drive well network. And in the comprehensive adjustment plan we designed 52 wells, the recovery of the oilfield will increase 7.8% compared to basic program.Combined with scaled corning data and the inversion of original resistivity, we established perforating program on the basis of fine numerical model and similar oilfield experiences. Water-cut of the new drilled wells were decreased, the potential productivity of them was fully released, and the effect of the water flooding was improved. Untill Dec 2011, 48 wells have been drilled, and the cumulative oil production of the new wells was about 174 × 10m, the recovery is expected to be enhanced more than 10.4%.The production performance of the new wells shows that the direction of the adjustment for the heavy oilfield and the method for studying the remaining oil distribution are scientifical and reasonable. The research ideas during this comprehensive adjustment and the method for studying the distribution of remaining oil in the vertical and plane direction of the reservoir can be taken as a reference for similar oilfields, such as JZ and QHD oilfields in Bohai bay.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
Abstract Oil wells in mature fields with strong aquifer influx and the first row of producers near peripheral water injectors experience very high water cuts (above 80%), which cause lower oil production and increasing disposal costs. To mitigate this situation, various production strategies have been implemented in this simulation study to reduce water production, optimize oil production and revive dead wells. One strategy is to implement a cyclic production scheme (CPS). The CPS requires alternate shutting and flowing of wells with high water cuts over predetermined time cycles. The main objectives of the cyclic strategy is to reduce water production by optimizing oil production, minimizing coning effect and having a better control of the uniform waterflood front to the up-dip producers. This strategy enhances the sweep efficiency, improving pressure maintenance and minimizing water production. This simulation study assesses the effectiveness and the performance of CPS implemented in a reservoir simulation model of a mature oil field. Simulation runs with several scenarios were conducted to understand and optimize the impact of CPS. The simulation results provided the best cyclic production/shut-in period and showed significant advantages of applying CPS over the regular noncyclic production in all scenarios. In this study, more than 93 wells have been evaluated and most of these wells showed good overall oil recovery after applying the CPS strategy.
- Europe (0.94)
- Asia > Middle East > Saudi Arabia (0.69)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Production and Well Operations > Well Operations and Optimization > Produced water management and control (1.00)
Improving Sweep Efficiency In A Mature Waterflood: Balcon Field, Colombia
Perez, D.. (Hocol) | Muñoz, L. F. (Hocol) | Acosta, W.. (Hocol) | Falla, J.. (Hocol) | Martínez, J.. (Hocol) | Vidal, G.. (Hocol) | Manrique, E.. (Tiorco) | Cabrera, F.. (Tiorco) | Romero, J.. (Tiorco) | Izadikamoue, M.. (Tiorco) | Norman, C.. (Tiorco)
Abstract The Balcon Field, operated by HOCOL S.A., is located in Colombia's Upper Magdalena Valley Basin. Oil production began in 1988, reaching a maximum primary rate of 5,742 BOPD in January 1994. Secondary recovery started in 1996, achieving a maximum secondary production of 9,198 BOPD in June 2001. Subsequently, water production has increased rapidly accompanied by declining oil production, due primarily to reservoir heterogeneity and an unfavorable mobility ratio. The oil recovery factor as of July 2011, as a percentage of OOIP, is estimated to be approximately 30% at a current water cut of about 84%. This work presents a methodology to determine the feasibility of polymer gels to reduce water channeling, including water injection and production analysis, diagnostic charts, fluid movement and geological characterization. Results of this integrated analysis led to a comprehensive laboratory study to identify the appropriate gel formulation (e.g. polymer, polymer concentration and cross linker ratio) at reservoir conditions. The recommended gel system developed was validated by a core flood before field implementation. The first gel treatment was implemented in July 2010, followed by a second injection well treatment in an adjacent pattern with significant water channeling. The treatment designs included several stages of varying gel concentrations and injection rates, which were modified during the field implementation based on surface pressure response. Post treatment oil response occurred within approximately two months and payout was achieved in 6 months. As of April 2011 incremental oil of 212,000 bbl. has been produced. However, offset producers are still showing incremental production. These promising results led to a second (and ongoing) campaign in 2011. Polymer gels have been successfully applied in sandstones reservoirs for decades. However, reservoir characterization tools continue to evolve contributing to the improvement of conformance treatment designs. This field case study will provide an updated framework for operators considering chemical sweep improvement technologies as part of an integrated reservoir management strategy.
- South America > Colombia > Huila Department (1.00)
- North America > United States > Texas (1.00)
- South America > Venezuela > Lake Maracaibo > Maracaibo Basin > Lagomar Field (0.99)
- South America > Colombia > Tolima Department > Upper Magdalena Basin (0.99)
- South America > Colombia > Huila Department > Upper Magdalena Basin (0.99)
- (29 more...)
Improving Sweep Efficiency in Fractured Carbonate Reservoirs by Microbial Biomass
Al-Hattali, R.. (Sultan Qaboos University) | Al-Sulaimani, H.. (Sultan Qaboos University) | Al-Wahaibi, Y.. (Sultan Qaboos University) | Al-Bahry, S.. (Sultan Qaboos University) | Elshafie, A.. (Sultan Qaboos University) | Al-Bemani, A.. (Sultan Qaboos University) | Joshi, S.. (Sultan Qaboos University)
Abstract Selective plugging by microbial biomass is one of the proposed mechanisms for improving reservoir sweep efficiency in fractured reservoirs. In this study, the potential of Bacillus licheniformis strains isolated from oil contaminated soil from the Sultanate of Oman was tested for their ability to grow in induced fractures in carbonate rocks and to divert subsequent injection water to the unswept matrix zones. Three Bacillus licheniformis strains were tested with name codes; B29, B17 and W16. Their growth behavior using different nitrogen sources; yeast extract, peptone and urea was investigated. Glucose and sucrose were tested as carbon sources. Carbon/nitrogen ratios were optimized where it was found that sucrose was the carbon source that maximized bacterial growth at 2% concentration and yeast extract was the selected nitrogen source with concentration of 0.1%. The combination of B. licheniformis strain W16 in a minimal medium containing sucrose was the optimum condition for maximum cell growth within 10-12 hours of incubation. Standard Indiana limestone core plugs were used for coreflooding experiments where a fracture was simulated by slicing the cores vertically into two sections using a thin blade. The bacterial cells were injected into the cores and the ability of the microbes to grow and plug the fracture was examined. Scanning electron microscopy was used to prove the growth of the microbial cells in the fracture after the experiment. Coreflooding experiments showed promising results where enhancement of oil recovery was observed after bacterial injection. A total of 27-30% of the residual oil was produced after 11 hours of incubation. This shows the high potential of using microbial biomass for selective plugging in fractured reservoirs.
- Asia > Middle East > Oman (0.35)
- North America > United States > Indiana (0.25)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.55)
- Geology > Petroleum Play Type > Unconventional Play > Fractured Carbonate Reservoir Play (0.40)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
Abstract This work investigates dehydration of polymer gel by capillary imbibition of water bound in gel into a strongly water-wet matrix. Polymer gel is a cross linked polymer solution of high water content, where water can leave the gel and propagate through porous media, whereas the large 3D polymer gel structures cannot. In fractured reservoirs, polymer gel can be used for conformance control by reducing fracture conductivity. Dehydration of polymer gel by spontaneous imbibition contributes to shrinkage of the gel, which may open parts of the initially gel filled fracture to flow and significantly reduce the pressure resistance of the gel treatment. Spontaneous imbibition of water bound in aged Cr(III)-Acetate-HPAM gel was observed and quantified. Oil saturated chalk core plugs were submerged in gel and the rate of spontaneous imbibition was measured. Two boundary conditions were tested; 1) all faces open (AFO) and 2) two ends open-oil-water (TEO-OW), where one end was in contact with the imbibing fluid (gel or brine) and the other was in contact with oil. The rate of spontaneous imbibition was significantly slower in gel compared to brine, and was highly sensitive to the ratio between matrix volume and surface open to flow, decreasing with increasing ratios. The presence of a dehydrated gel layer on the core surface lowered the rate of imbibition; continuous loss of water to the core increased the gel layer concentration and thus the barrier to flow between the core and fresh gel. Severe gel dehydration and shrinkage up to 99 % was observed in the experiments, suggesting that gel treatments may lose efficiency over time in field applications where spontaneous imbibition is a contributing recovery mechanism. The implications of gel dehydration by spontaneous imbibition, and its relevance in field applications, are discussed for both gel and gelant field treatments.
- Europe (1.00)
- North America > United States > Oklahoma (0.28)
- North America > United States > Texas (0.28)
- Research Report > Experimental Study (1.00)
- Research Report > New Finding (0.87)
Thermally Activated Particle Treatment to Improve Sweep Efficiency: Pilot Test Results and Field Scale Application Design in El Borma Field (Tunisia)
Galli, Giuseppe (University of Oklahoma) | Morra, Daniela (University of Oklahoma) | Ghaddab, Fethi (University of Oklahoma) | Sitep, Marcello Tesconi (University of Oklahoma) | Manrique, Eduardo (University of Oklahoma) | Tiorco, Glyn Freeman (University of Oklahoma)
Abstract El Borma is a mature oil field located onshore in the Northern Sahara Desert, Tunisia. Oil production commenced in 1966 and is currently supported by water injection; the high water cut (96%) and permeability contrast in the main reservoir (Level "A") indicated thief zones with less than optimum sweep efficiency prompting the evaluation of a tertiary method for improved oil recovery. In January of 2010 a pilot project (injector-producer) was implemented to evaluate a thermally activated particle (TAP) system as a strategy to improve the sweep efficiency of ongoing water injection program. This paper will summarize TAP pilot implementation and will describe methodology and results of project monitoring and injection-production performance. The evident good results of this TAP application (decrease in water cut with consequent increase in oil recovery up to 55%) in the last fourteen months justified a larger scale application in the field. The field scale application design was performed in two different steps: 1) Comprehensive production-injection data analysis of injectors based on the number of connected (offset) producers and channel volume estimations and; 2) The numerical simulation studies of most promising patterns calibrated with information generated during the first TAP pilot. Screening of patterns candidates and simulation approach of TAP will be also presented. El Borma pilot results validate the potential of TAP as an in-depth conformance strategy that can improve sweep efficiency of mature waterfloods. El Borma workflow to screen and rank patterns candidates combined with pilot project implementation, monitoring and evaluation can be used as a reference to evaluate the benefits of TAP technology in waterflooded oil reservoirs.
- Africa > Middle East > Tunisia > Tataouine (0.51)
- Africa > Middle East > Tunisia > Tataouine Governorate > El Borma District (0.41)
- Africa > Middle East > Algeria > Ouargla Province (0.41)
- Africa > Middle East > Tunisia > Tataouine Governorate > El Borma District > Berkine Basin (Trias/Ghadames Basin) > El Borma Concession > El Borma Field (0.99)
- Africa > Middle East > Tunisia > Berkine Basin (Trias/Ghadames Basin) (0.99)
- Africa > Middle East > Libya > Berkine Basin (Trias/Ghadames Basin) (0.99)
- Africa > Middle East > Algeria > Berkine Basin (Trias/Ghadames Basin) (0.99)
ABSTRACT The Cerro Dragon (CD) Field, located in the San Jorge Gulf Basin (SJGB) of Argentina, offers a significant opportunity for improved volumetric sweep efficiency because of an adverse mobility ratio and spatial anisotropy, typical of the multilayered channels deposits of SJGB. The center of these channels becomes a highly conductive "thief zone", resulting in preferential channeling of injected water to the offset producers without creating an oil bank. As a consequence, sweep efficiency is reduced and operating costs are increased due to the handling of large volumes of produced water. These thief zones are the target for improved reservoir conformance using a thermally activated particle technology known as BrightWater® (BW), developed and patented by BP, Chevron and Nalco Company. Testing of deep reservoir conformance in Argentina utilizing the BW technology began in 2006 with pilots in the Piedra Clavada and Koluel Kaike fields (Mustoni, et al., 2010). Screening, design and implementation of the BW conformance project in the CD Field was the result of experience gained from these earlier applications. The CD Field conformance project represents a larger scale application of the BW technology in terms of number of wells treated, layers per well, oil reserves, and treatment volumes. This paper describes the methodology utilized to evaluate and rank BW conformance candidates from a database of more than 100 blocks in the CD Field. A detailed discussion of the candidate selection methodology will be presented, including laboratory testing, chemical formulation and volumes, well surveillance, inter-well tracer, and simulation studies. This paper will also describe details of internally developed processes that optimized the logistics of field implementation, including simultaneous injection of the chemical solution in multiple injection wells and multiple subsurface mandrels.
- North America > United States > Oklahoma (0.28)
- South America > Argentina > Santa Cruz Province (0.24)
- Geology > Sedimentary Geology > Depositional Environment (0.46)
- Geology > Structural Geology (0.46)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Salema Field (0.99)
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
- South America > Argentina > Chubut > Golfo San Jorge Basin > Cerro Dragon Field (0.99)
- (3 more...)
Abstract A giant multi-layered carbonate reservoir in offshore India is undergoing water-flooding since 1987. Historically there have been about 930 producer and 250 injection strings in the field with about half of them active today. In order to have quick flood surveillance, flow streamline snapshots and flood-front maps have been attempted using in-house developed analytical technique assuming homogeneous, incompressible, unit mobility ratio displacement process. The eleven producing unit of the reservoir are clubbed as five major stacks for streamline generation. Injection and production volumes are divided among these five stacks on the basis of existing history matched simulation model. The volumes are then normalized to obtain the relative strengths of the producers and injectors Macro level reservoir anisotropy is inherently taken care by the normalization process of rates. Reservoir boundary for each stack is simulated by placing large number of image wells along each boundary. The velocity and potential distribution in the reservoir are obtained using the principle of superposition. The velocity equation tracks the path of the fluid particle generating the flow streamlines. Flood-front positions are generated by repeating the above process. The field water cut vs. pore volume of water injected is compared against the actual water cut vs. pore volume of water injected as a history matching process. Individual well water-cut are then superposed on the flood-front positions in the corresponding stack. Flood front positions are corroborated to a large extent with the superposed water-cut in individual wells. Deviations in the actual water-cut trend are also observed in few areas. Recommendations for redistribution of injected water among the identified stacks are presented on a holistic basis to achieve better sweep efficiency in the reservoir and field trials are awaited. The attempt is to use this fast and simple analytical technique on a desktop computer for quick water-flood surveillance of a large field.
- Information Technology > Modeling & Simulation (0.48)
- Information Technology > Hardware (0.34)