Conformance improvement is the key to success in most enhanced oil recovery (EOR) processes, especially CO2 foaming or steamflooding. Despite technical and economical restrictions, foam has been used as dispersions of microgas bubbles in the reservoir to help improve mobility. Steam-foam has many applications in the industry, including but not limited to heavy oil reservoirs, which are an important part of the future energy supply. Steam-foam applications have been used to help prevent steam channeling and steam override, thus improving overall sweep efficiency, not only in continuous steam but also in cyclic steam injection processes. Because of the high temperatures achieved during steamfloods, a robust understanding of chemistry, including the thermal stability of surfactants, is important. The effectiveness and therefore economics of the steam-foam process are strongly dependent on surfactant adsorption and retention. With that in mind, effective sizing of the foam injected requires a good understanding of the process. In this study, a reservoir simulator is used in which surfactant transport is modeled, with surfactant availability determined by a combination of surfactant adsorption, surfactant thermal decomposition, and oil partitioning due to temperature. A robust commercial optimization and uncertainty tool is coupled with the reservoir simulator to generate the scenarios defined by control variables for optimization and uncertainty parameters for sensitivity analysis. The degree of mobility reduction is interpolated as a product of factors that include aqueous surfactant type and concentration, the presence of an oil phase, and the capillary number. An empirical foam modeling approach is employed with foam mobility reduction treated by means of modified gas relative permeability curves. The simulation results including the sensitivity of the parameters and controlling agents, providing a better understanding on the influence of surfactant adsorption and thus the amount of chemicals to be used are presented and discussed to serve as a guide for future applications. It is not easy to find documented examples of realistic optimization studies where significance of each control and uncertainty parameter is outlined and discussed using a realistic reservoir model. The simultaneous use of optimization and uncertainty led to a better understanding and thus control of decision variables in varying ranges of uncertainty that will be useful in analyzing prospective assets.
Depleting hydrocarbon reserves and increasing greenhouse gases present a major challenge to the energy sectors. As a result, emphasis needs to be placed on ensuring optimum depletion of known hydrocarbon reserves and reduction of greenhouse gases. This paper presents the effects of various injection well placements on the efficiency of Enhanced Gas Recovery (EGR) and sequestration, using reservoir simulation, in an attempt to optimize EGR coupled with CO2 sequestration. The compositional simulator CMG-GEM was used to build a reservoir model with a simple 3D geometric shape (cuboid), which was populated with various layers with properties analogous to a real condensate field to improve the accuracy of the flow path modeling. WINPROP was used to create a detailed fluid model. Using the model as discussed above, the injector placement was varied whilst using a fixed injection pressure of 2000 psi at the end of primary recovery for all scenarios. These well placements included a single vertical injector, two vertical injectors and a single horizontal injector. At the end of each injection scenario, the simulation was run for an additional 1000 years to model the movement of the CO2 plume in the reservoir. From the simulations, over 60% of the injected CO2 remained in the reservoir. On average, approximately 20% of the injected CO2 was trapped by hysteresis. These relatively high storage values for this research can be attributed to relatively small volumes of CO2 being injected (on average 4 MtCO2 total over 5 years) into a relatively large reservoir (estimated hydrocarbon pore volume of 622.5 MMCF) at low injection pressures. The various injection scenarios resulted in as high as an additional 6.9% condensate recovery over primary production only. The results of this simple analytical model show that there is the potential to optimize gas and condensate recovery through the use of CO2 injection whilst mitigating a percentage of greenhouse gases. It also provides a base for future well planning models to build upon in order to effectively optimize CO2 EGR and sequestration in condensate fields.
The paper seeks to assess the technical and economic feasibility of implementing carbon dioxide enhanced oil recovery (CO 2 EOR) in Trinidad and Tobago from flue gas production whilst mitigating the effect of greenhouse gases via CO 2 sequestration. An existing power plant in Trinidad was selected as the CO2 source. As such, actual CO2 volumes and properties were found and used in this analysis. However, a hypothetical field was chosen as the appropriate sink, which can be analogous to a field in onshore Trinidad.A detailed reservoir model was built using the compositional fluid model CMG-GEM. Various scenarios were simulated to determine the optimum number of producers for primary production and the best location of the injectors for CO 2 EOR. The optimum number of producers for the reservoir during primary production was found. In addition, the most favorable location of the injector to avoid early breakthrough and increase oil recovery was also determined.Many key parameters were reported from this investigation. These included OIIP, forecasted production and primary recovery. After primary production, CO2 EOR was then implemented with the use of the reservoir and fluid models and the additional recovery is reported. Other Key CO2-EOR parameters such as CO2 utilization rate and total sequestered CO2 were also quantified.Though a hypothetical reservoir was used, all associated data were defined and once an actual reservoir is known, the same technically rigid methodology can be applied.The OIIP was found to be 6.74 MMSTB for the selected reservoir. Based on an economic net present value (NPV) assessment, the optimum number of production wells for field development was found to be 3. At the end of primary production from these three wells (with 2.375 in. tubing), a total of 1.83 MMSTB were produced. This corresponded to a primary recovery factor of 27.2% over 4 years and 2 months.For CO 2 EOR coupled with sequestration, these three wells were manipulated and used as 1 injector and 2 producers. CO 2 EOR led to another 1.07 MMSTB of recovery for a total of 2.9 MMSTB (43.04% Recovery) for the ten year life of the project. A total of 5427 MMSCF (287 000 tons) of CO 2 was sequestered in the reservoir (40.39% Storage) at an injection pressure of 1400 psi.
The paper seeks to assess the technical and economic feasibility of implementing carbon dioxide enhanced oil recovery (CO2 EOR) in Trinidad and Tobago from flue gas production whilst mitigating the effect of greenhouse gases via CO2 sequestration. An existing power plant in Trinidad was selected as the CO2 source. As such, actual CO2 volumes and properties were found and used in this analysis. However, a hypothetical field was chosen as the appropriate sink, which can be analogous to a field in onshore Trinidad. A detailed reservoir model was built using the compositional fluid model CMG-GEM. Various scenarios were simulated to determine the optimum number of producers for primary production and the best location of the injectors for CO2 EOR. The optimum number of producers for the reservoir during primary production was found. In addition, the most favorable location of the injector to avoid early breakthrough and increase oil recovery was also determined. Many key parameters were reported from this investigation. These included OIIP, forecasted production and primary recovery. After primary production, CO2 EOR was then implemented with the use of the reservoir and fluid models and the additional recovery is reported. Other Key CO2-EOR parameters such as CO2 utilization rate and total sequestered CO2 were also quantified. Though a hypothetical reservoir was used, all associated data were defined and once an actual reservoir is known, the same technically rigid methodology can be applied. The OIIP was found to be 6.74 MMSTB for the selected reservoir. Based on an economic net present value (NPV) assessment, the optimum number of production wells for field development was found to be 3. At the end of primary production from these three wells (with 2.375 in. tubing), a total of 1.83 MMSTB were produced. This corresponded to a primary recovery factor of 27.2% over 4 years and 2 months. For CO2 EOR coupled with sequestration, these three wells were manipulated and used as 1 injector and 2 producers. CO2 EOR led to another 1.07 MMSTB of recovery for a total of 2.9 MMSTB (43.04% Recovery) for the ten year life of the project. A total of 5427 MMSCF (287 000 tons) of CO2 was sequestered in the reservoir (40.39% Storage) at an injection pressure of 1400 psi.
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