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Al-Murayri, M. T. (Kuwait Oil Company) | Al-Mayyan, H. E. (Kuwait Oil Company) | Moudi, Kamal (Kuwait Oil Company) | Al-Ajmi, F.. (Kuwait Oil Company) | Pitts, D.. (Inc.) | Wyatt, M. J. (Inc.) | French, K.. (Inc.) | Surtek, J (Inc.) | Dean, E.. (Colorado School of Mines)
Abstract Chemical EOR (CEOR) can be economic in a low-price environment, but it requires economic insights be integrated into the initial reservoir screening, laboratory and numerical simulation evaluations, and continued review through field implementation. The CEOR economic evaluation for the Sabriyah Lower Burgan (SALB) using this integrated process found that surfactant-polymer and alkaline-surfactant-polymer flood had different economic potentials due to different oil recoveries, facility costs, and operating costs. Initial reservoir screening of the SLAB indicated that LoSal and CO2, flooding might also have economic potential. Laboratory corefloods injecting field proportioned volumes of chemical solutions using dead oil and reservoir rock resulted in chemical cost average $3.12 per incremental barrel of oil for alkaline-surfactant-polymer formulations and $18.61 for surfactant-polymer formulations. Live oil corefloods for corresponding chemical formulations cost per incremental barrel estimates were $3.70 and $7.83. LoSal process provided no incremental oil based on laboratory coreflood results. Numerical simulation forecast economics included chemical costs, estimated operating costs, facilities cost, drilling of wells, and other capital costs. 2.2, 5.4, and 60 MMbbl pilots forecast by numerical simulation indicated that alkaline-surfactant-polymer cost per incremental barrel of oil was $28.63, $10.42, and $10.95 for the respective pilot sizes. Smaller pilots show a greater impact of fixed costs such a facilities and new wells. 5.4 and 60 MMbbl pilots paid out at 3.4 years or less. Corresponding discounted rates of return were up to 14%. Sensitivity analysis indicated that crude oil price has the greatest effect on chemical enhanced oil recovery economics, regardless of pilot size. This paper summarizes how economic applications at each phase of a chemical flood evaluation are performed and how those evaluations can be understood and applied to prevent adverse project selection. Economic parameters should be evaluated at various phases of project evaluation, influencing decisions to move forward. Methods of evaluation at each phase are documented and discussed using the Sabriyah, Lower Burgan study as a basis.
The Greater Burgan field in Kuwait is the largest sandstone oilfield in the world. Kuwait Oil Company (KOC) recognizes that enhanced oil recovery (EOR) is of strategic importance to maximize recovery and extend field life. We studied several EOR options using reservoir simulation to evaluate the benefits of using low salinity waterflood (LSW), low salinity polymer (LSP) injection and high salinity polymer (HSP) injection applications in Wara and Burgan upper (3SU) reservoirs.
Full-field reservoir-simulation with adequate resolution for EOR assessment of giant fields (e.g., Greater Burgan) is computationally expensive, if even possible. To overcome this, we ran high-resolution sector-models, representing different areas, with inputs from laboratory and single-well-chemical-tracer-tests and generated type-curve profiles (e.g. oil recovery vs. cumulative pore-volume injection). A scaling-up tool was developed that considers infrastructure-facility constraints (e.g., high- and low-salinity capacities and injection priority of field areas), combines type-curve profiles, and outputs field-level profiles. At sector-level, we optimized all EOR slug sizes. For cases with polymer, polymer concentration was optimized on basis of polymer amount required per incremental oil barrel.
The following five development scenarios were studied: 1) HSP everywhere across Wara and Burgan (3SU) reservoirs 2) LSW everywhere across the reservoirs 3) LSP everywhere across the reservoirs 4) secondary LSW for certain areas of the reservoirs and HSP for remaining areas 5) secondary LSP for certain areas of the reservoirs and HSP for remaining areas. The scenario #3 shows the highest incremental oil as it adds the benefits of both LSW and polymer injection. However, using low salinity-polymer in conjunction with high salinity-polymer (i.e., scenario #5) gives the highest incremental oil peak rate. In general, polymer flooding reduces the amount of water production. Use of low salinity without polymer resulted in higher water production. Significantly less volumes of polymer are associated with low-salinity water injection as compared with high-salinity water injection. Optimal polymer concentration was found to be well above that which gave unit mobility ratio. Although, the EOR incremental benefits and their corresponding screening-level economics look reasonable for the EOR schemes investigated, the schemes vary significantly in feasibility, capital costs and operating costs. A long-term injectivity pilot of high-salinity polymer is planned.
Our approach combines the understanding of recovery efficiency that comes from detailed type pattern modelling with understanding of realistic facility constraints to rapidly generate realistic field-wide projections. We evaluated several facilities options corresponding to the five EOR development scenarios and generated cost profiles that were used in economic modelling.
Al-Qattan, Abrar (Kuwait Oil Company) | Sanaseeri, Abbas (Kuwait Oil Company) | Al-Saleh, Zainab (Kuwait Oil Company) | Singh, B.B.. B. (Kuwait Oil Company) | Al-Kaaoud, Hassan (Kuwait Oil Company) | Delshad, Mojdeh (Ultimate EOR Services, LLC) | Hernandez, Richard (Ultimate EOR Services, LLC) | Winoto, Winoto (Ultimate EOR Services, LLC) | Badham, Scott (Chemical Tracers, Inc.) | Bouma, Chris (Chemical Tracers, Inc.) | Brown, John (Chemical Tracers, Inc.) | Kumer, Kory (Chemical Tracers, Inc.)
Abstract The Greater Burgan Field, first discovered in 1938, is the second largest oilfield in the world. Production from the Greater Burgan began in 1946 from the Wara reservoir via primary recovery. Recently, field-wide waterflood as a secondary recovery mechanism has been implemented. The current insight on the potential of hybrid low salinity water and polymer flooding in the Greater Burgan is presented. The goal of the Greater Burgan Study team in this enhanced oil recovery (EOR) evaluation program was to compare the benefits of using low salinity waterflood (LSW) and low salinity polymer (LSP) injection as tertiary oil recovery methods in the Wara sandstone reservoir of the Greater Burgan field. The efficacy of low salinity and low salinity polymer injection has been investigated in the laboratory and by conducting a series of single-well chemical tracer (SWCT) tests in one Wara producer. In the field trial carried out on Well A, three separate determinations of residual oil saturation (Sor) were made. The first SWCT test measured waterflood Sor after injecting a slug of high salinity water (HSW) that is compositionally comparable to the produced water utilized field-wide for waterflooding operations. The second and third SWCT tests measured the remaining oil saturation after LSW and LSP, respectively. Laboratory corefloods were also performed to evaluate LSW and LSP recoveries and their impacts on injectivity. The injection water salinity, injection design, oil viscosity, and polymer viscosity used in the laboratory experiments were identical to those used in the field SWCT tests. These SWCT test trial results establish a baseline waterflood Sor (i.e., after high salinity water injection) and show that further reductions in Sor may be achieved with low salinity waterflooding and low salinity polymer injection. The laboratory results showed no plugging or injectivity issues during LSW or LSP corefloods. Overall, LSW and LSP were shown to be technically workable tertiary processes in the Greater Burgan.
Abstract The natural decline in oil production in Alaskan reservoirs is challenging producers to find methods to extend production. The current stage of reservoir development has reached the point where consideration of enhanced oil recovery methods is appropriate. Such methods could include CO2, chemical, microbial or thermal recovery. However, these methods require significant capital and/or operational investment. This paper evaluates the application of wettability alteration for Alaskan reservoirs by changing injection water chemistry also known as advanced water flooding. We use empirically-based screening and scoping methodologies to evaluate the suitability, cost and benefits of advanced water flooding for Alaskan reservoirs using public domain data. First, laboratory and field examples of successes and failures are considered. Using this basis, a theory is developed that directly links water chemistry and reservoir wettability. The theory also illuminates the key characteristics of the reservoir that control wettability. We use empirically-based screening and scoping methodologies to evaluate the suitability, cost and benefits of advanced water flooding for Alaskan reservoirs with sufficient public domain data. The screening tool is built on empirical data from laboratory and field tests that identify the critical factors contributing to incremental production. The scoping tool uses a modified Kinder Morgan approach (dimensionless recovery curve) to evaluate the economic case for each reservoir. The first field-scale tests of this technique were conducted by BP in the Endicott reservoir on the North Slope and produced good results by lowering the salinity of injection water. Those tests showed that alteration to injection water chemistry can increase recovery significantly. These results have been duplicated in laboratory and field tests in other locations. The tests were conducted without an understanding of the fundamental mechanisms nor optimization of the injected water chemistry, and thus represent minimum recovery. We find the increased recovery is profitable for several fields depending on assumptions about water sources, water treatment costs and rates of injection. The successful approach to advanced waterflooding requires several key steps: screening the formation to evaluate the applicability of the technique, simple laboratory tests to determine the optimal water chemistry and quantify the increased recovery, economic evaluations to estimate costs and benefits, and finally, comprehensive geochemical models to design the wettability-modifying fluids. The technique has several advantages compared to current methodologies for wettability alteration including substantially lower costs, no environmental impacts and ease of application.
Waterflooding involves the use of injected water to displace oil in a reseroir. This process is a method of secondary recovery. Conventional oil recovery involves improving volumetric sweep efficiency via a variety of technologies and practices, including in-fill drilling, multilateral wells, improved reservoir characterization, high resolution reservoir simulation, and advanced monitoring and surveillance. Around 50% of the world's known oil resolves are in carbonate reservoirs. As Primary recovery mechanisms yield low recovery factors and therefore companies seek Secondary or even Tertiary recovery methods.