Economic Analysis for Enhanced CO 2. Injection and Sequestration Using Horizontal Wells

Transcription

1 Economic Analysis for Enhanced Injection and Sequestration Using Horizontal Wells TECHNICAL NOTE p. gui, x. jia, j.c. cunha*, l.b. cunha University of Alberta *currently with Petrobras America, Inc. Abstract Carbon dioxide flooding has been recognized widely as one of the most effective enhanced oil recovery processes applicable for light to medium oil reservoirs. Moreover, the injection of into an oil reservoir is a promising technology for reducing greenhouse emissions while increasing the ultimate recovery of oil. Numerical reservoir simulation is an important and inexpensive tool for designing EOR projects and predicting optimal operational parameters. In this work, reservoir simulations performed with a compositional simulator were applied to investigate the macroscopic mechanisms of a injection process. Horizontal injectors were used to increase injectivity. Compared to traditional vertical wells, horizontal wells are more attractive to improve flooding economics by increasing injection rate, improving areal sweep and increasing storage. The effects of several important parameters on the performance of the process were studied to optimize the process. Operational parameters such as different production schemes, the injector pressure and injection rate were investigated to determine the optimal op- erating conditions for simultaneous objectives of higher recovery and higher storage. The application of flooding using horizontal wells can shorten project life, which is critical to its economics. The simulation results served as the basic input parameters for the economic analysis performed. Furthermore, net present value (NPV) and profitability index results were used to optimize the profitability of the project and to compare the application using vertical and horizontal wells. The analysis used actual design parameters, including equipment and operating costs. The evaluation emphasized the importance of reservoir characteristics, optimum design of operation parameters and economic factors in the economic feasibility of injection projects for enhanced oil recovery and sequestration. Introduction The carbon dioxide flooding process can increase oil recovery by means of swelling, evaporating and lowering oil viscosity (1, 2). Many injection schemes using have been applied (3), including gas injection (continuously), gas slug followed by water, and others. There are some important factors to be considered during the design of flooding, including the availability and amount of to inject, the reservoir conditions, whether mobility control techniques are required and other general operating conditions (4, 5). Among these factors, the knowledge of reservoir conditions is essential to the injection/production process and, thereafter, the economic success of the project. These include the reservoir temperature and pressure, reservoir permeability and porosity, fractures and faults, etc. Field tests of floods have shown that reservoir heterogeneities, such as fractures, strata discontinuities and pinch-outs, can reduce the effectiveness of the process. is a highly mobile fluid because of its low viscosity, so fingering and channeling of or bypassing of oil can affect the volumetric sweep efficiency in flooding. In this case, mobility control becomes an important issue for the improvement of applications (6). With the increase of productivity performance and the decrease of drilling and completion costs, horizontal wells became more cost effective. This paper compares the conventional flooding process using vertical wells and using horizontal wells. The flooding process could be miscible depending on the composition of the reservoir oil and on the reservoir pressure and temperature. Therefore, an equation-of-state (EOS) compositional simulator should be used to handle both the thermodynamic and the fluid flow aspects that happen inside the reservoir during a flooding process (7-9). With the use of a compositional flow simulator, different flooding mechanisms can be simulated, including vapourization and swelling of oil, condensation of gas, viscosity and interfacial tension reduction. Based on a compositional model, a comparison is made between schemes using vertical wells and using horizontal wells. With the simulation of different injection and production scenarios, the study can give a good estimate of the recovery improvement under injection. On the other hand, atmospheric concentrations of are increasingly raising concerns. Different possibilities for sequestration are being carried out to reduce the greenhouse effect. One strategy is to store in aquifers or abandoned gas and oil reservoirs. In this category, some field storage projects have proved to be very successful (10). Another very interesting strategy is the combination of enhanced oil recovery (EOR) and flooding, which reduces greenhouse emissions while increasing the ultimate recovery of oil (11). Bennaceur et al. (12) reviewed the enhanced oil recovery project using in Weyburn, Saskatchewan, Canada. The Weyburn EOR- storage project has increased daily production rates from 1,590 std.m 3 /day (10,000 STB/day) to 4,770 std.m 3 /day (30,000 STB/day). Meanwhile, it is estimated that 22 million metric tons of will ultimately be stored in the Weyburn Field during the project s lifetime. This study falls into the second strategy mentioned above (EOR- ) which discusses the application of the flooding process to simultaneously enhance oil recovery and increase storage. Although there are mainly two trapping mechanisms in storage, hydrodynamic trapping and mineral trapping (13), only the first trapping mechanism is considered during the computer modelling process in this work. This paper studies the flooding process using horizontal wells to simultaneously enhance recovery and increase storage. Obviously, this is an economic, social and environmental PEER REVIEWED PAPER PUBLISHED AS A Technical Note ( REVIEW AND PUBLICATION PROCESS CAN BE FOUND ON OUR WEBSITE) 34 Journal of Canadian Petroleum Technology

2 4,000 FIGURE 1: Option 1 with vertical producers and injector. Well Bottomhole Pressure (psi) 3,500 3,000 2,500 2,000 FIGURE 3: Comparison of bottomhole pressure for injectors 1.20e+7 FIGURE 2: Option 2 with horizontal producer and injector. issue and optimization will contribute to reach the two objectives: enhanced oil recovery and storage. Economic analysis is especially important in a flooding project because most of such projects have high investment and operating costs, but low profit expectation. In this work, the application of a conventional miscible flooding process (continuous injection) using horizontal wells is studied. A comparison is made between schemes, using vertical producer/injector wells and using horizontal wells. A commercial compositional simulator is used to conduct the miscible flooding studies (14). With the simulation of different injection and production scenarios, the study can give a good estimate of the recovery improvement under gas injection. The simulation results were the basic input parameters for the economic feasibility study. Synthetic Reservoir Case The proposed reservoir is part of a lease area with both a length and width of m and an average reservoir thickness of m (irregularly distributed). The reservoir physical properties are not homogenously distributed. Based on the porosity and permeability data map, the histogram of the porosity and permeability distribution can be generated and analyzed. Then the reservoir heterogeneity can be represented by a histogram of porosity and permeability distribution. The histogram of the porosity distribution shows that over 80% porosity values fall in between 0.15 and The histogram of the permeability distribution shows that over 80% permeability values fall in between 14 md and 54 md. The reservoir model has an average initial oil saturation of 0.71 and oil formation volume factor (FVF) of The original oil-in-place (OOIP) can be calculated as being around 2 million std.m 3. The initial average reservoir pressure is 16,340 KPa (2,370 psi) and the temperature is 55 C. The temperature is assumed to be constant during production and injection. Initially, the oil was undersaturated, so there was no original gas cap. The average density of the oil in this reservoir is 42 API, with about 30% of C7+ components. In this paper, flooding is characterized as a miscible displacement of reservoir oil. The minimum miscible pressure (MMP) is mainly dependent on the reservoir temperature and the composition of the oil. Using commercial phase behaviour software (15), the MMP can be determined for a given solvent composition by testing a range of pressures. According to the flooding screening standards summarized by Stalkup (5), the reservoir physical properties and character of its oil make this reservoir a good candidate for flooding, as well as storage. Two injection and production options for the process were compared and analyzed. One uses a vertical injector and four vertical producers and another uses a horizontal injector and a horizontal producer combination. Figures 1 and 2 show the two reservoir models with different well geometry strategies (vertical and horizontal injector, respectively). For the vertical case, there are a total of five wells drilled, including four producers spaced close to each corner of the square lease area and one injector located in the centre of the pattern (see Figure 1.) The proposed vertical case, as seen in Figure 1, is the optimum option among the vertical well scenario cases. The constraints for this case are: termination of simulation when GOR reaches 3,562 m 3 /m 3 (20,000 ft 3 /bbl) for each well or total production of the well group drops to 7.95 std.m 3 /day (50 STB/day). The production considers a constant BHP control scheme and the injection has two scenarios simulated; a constant BHP injection and constant injection rate. Figure 2 shows the same reservoir when horizontal wells are used for the flooding process. For the horizontal well case, there is only one producer and one injector; each one installed on opposite sides of the lease area. As in the vertical case, the selection of location for the horizontal wells was determined considering the previously mentioned factors and comparing different scenarios. November 2008, Volume 47, No Cumulative Oil SC (bbl) 1.00e e e e e+6 FIGURE 4: Comparison of cumulative oil production curve

3 4.00e e+7 Cumulative Oil SC (bbl) 1.00e e e e e FIGURE 5: Comparison of cumulative gas production curve FIGURE 8: Comparison of cumulative oil production curve (constant injection BHP). 30, e+10 Gas Oil Ratio SC (ft 3 /bbl) 20,000 10,000 0 FIGURE 6: Comparison of gas oil ratio curve (constant injection rate) FIGURE 9: Comparison of cumulative gas production curve (constant injection BHP). 7.00e e e e+10 Gas Oil Ratio SC (ft 3 /bbl) 30,000 20,000 10, FIGURE 7: Comparison of cumulative gas injection curve (constant injection BHP) FIGURE 10: Comparison of gas oil ratio curve (constant injection BHP). Simulation Results and Analysis This section summarizes the simulation results for both the vertical and horizontal cases. As mentioned before, there are two injection and production scenarios performed in the simulation; the constant injection rate of 311,485 std.m 3 /day (11 MMscfd) and the constant injection BHP of either 17,237 KPa (2,500 psi) or 19,305 KPa (2,800 psi). Figures 3 to 6 show the simulation results for a constant injection rate scenario. From Figure 3, it is obvious that under the same constant injection, the vertical injector needs higher injection pressure to maintain the injection rate. In other words, the horizontal injector has better injectivity. To further verify this conclusion, a comparison is made between the vertical and horizontal injectors using constant injection BHP, shown in Figures 7 to 10. Figure 7 shows that, at the same injection BHP of 17,237 KPa (2,500 psi), it takes only half of the time for the horizontal injector to reach the same amount of cumulative gas injection of the vertical injector. Better injectivity for the horizontal well case will improve the economics of the project due to lower operation costs, increased oil production and higher cash flow in the early developing stages. To 36 Journal of Canadian Petroleum Technology

4 3.00E NPV comparison of different development plans Total Stored (scf) 2.50E E E E E+09 Horizontal case_2500 Psi Vertical case_2500 Psi Vertical case_2800 Psi NPV (million $) Vertical_Const Q Horizontal_ConstQ Horizontal_Const P2500 Vertical_Const P2500 Development Plan 0.00E ,000 2,000 3,000 4,000 5,000 6,000 7,000 Time (day) FIGURE 11: Comparison of storage curve (constant injection BHP). study the direct effect of these aspects, the cumulative oil production for both cases is compared in Figures 4 and 8. The cumulative oil production for the horizontal well case is about 1.7 million std. m 3. For the constant injection rate scenario, the difference between horizontal injection and vertical injection is not that obvious because the vertical injector has a higher injection BHP to maintain the same injection rate. However, even in that situation, the horizontal well case, not only has higher oil production (5% higher in recovery factor), but also produces faster than the vertical case (two years shorter production life). Better injectivity and sweep efficiency can also make storage faster and more effective. Figure 11 shows that, at the same BHP for the injector, the horizontal case only needs half of the time to store the same amount of. The total amount of stored reached 680 million std.m 3 in the horizontal case. Only when increasing the vertical injector BHP to 19,305 KPa (2,800 psi), does the storage process get close to the results obtained for the horizontal case. In brief, horizontal wells show better injectivity and sweep efficiencies at similar pressures. Use of a horizontal injector presents increased flooding rates with the same, or even lower, injection pressures. Compared to horizontal wells, vertical wells may have early gas breakthrough, and the storage of is not as efficient as that of horizontal wells. FIGURE 12: Comparison of NPV performance of different flooding options. most sensitive factor on the net present value among the abovementioned factors. With a 10% fluctuation in the oil price, the NPV of this project will change from $6 to $10 million accordingly, depending on different cases. The influence of other factors is relatively close, with the sensitivity order in this study as follows: tax rate, royalty rate, the rate of return and price. Net present value is calculated for both development options. Figure 12 compares the NPV values for both the vertical and horizontal cases with either a constant BHP scheme or a constant injection rate scheme. The NPV has considered the depreciation of all the capital expenditures. Therefore, positive NPV based on a 12% ROR means a positive profitability index (PI ranges from 1.44 to 1.96 in this case). Figure 12 shows that all development plans will profit at assumed economic parameters. Comparing the different schemes, flooding using horizontal injectors and producers has a higher NPV than that using vertical injectors and producers. When comparing the same BHP injection (17,237 KPa) for vertical and horizontal wells, the NPV for the horizontal case is $64.16 million, which is 157% of the NPV for the vertical case. For the constant injection rate cases, the difference between the horizontal case and vertical case is smaller, but the horizontal well scenario still presents a better performance. Conclusion Economical Analysis The simulation results served as the basic input parameters for the economic analysis for both the vertical and horizontal flooding options. The economic evaluation also considered, as main expenses for the project, the initial capital investment for drilling the wells and the cost of well operation and maintenance. The capital expenditure in this project is assumed to be $15 million for surface facilities, including regular well operation facilities, treatment and injection equipment and the recycling plant. Cost of drilling a new injector is assumed to be $0.5 million. The cost of drilling and completion of a horizontal well is assumed to be twice that of the vertical well. The expenses for the well operation and maintenance are split into a fixed cost ($0.6 million/year) and a unit cost for each barrel of oil produced ($4/bbl). Although the produced gas can be separated into and hydrocarbons that can be used for fuel and sale, this benefit is significantly offset by the large capital investment for the separation facilities. In this project, the produced gas will be recycled and re-injected into the reservoir without processing, which proved to be the more economically attractive option. The recycle and re-injection cost is assumed as $0.0134/m 3. It is assumed that 98% of the recycled gas can be re-injected into the reservoir and the remaining 2% gas and corresponding treatment cost is ignored. Financial parameters include the ROR, oil and prices, royalties, taxes and depreciation (15-year as a straight line). Sensitivity analysis is conducted by changing each one of the above parameters in the simulation. Not surprisingly, the oil price is the This paper analyzed the economic feasibility of an EOR- flooding project in a proposed reservoir. The simulation results show that this project is technically and economically feasible. The study compares flooding using vertical wells and horizontal wells. Horizontal wells have proven to be more efficient to improve recovery while increasing storage within the reservoir. In the cases with a constant injection rate, the recovery factor using horizontal wells is 5% higher than those using the vertical wells, with a two year shorter production life. When comparing cases with similar BHP injection, horizontal wells have better injectivity and sweep efficiencies. The horizontal well injector has higher flooding rates with the same BHP injection. Compared to vertical wells, the horizontal case only needs half of the time to store the same amount of. The cumulative oil production for the horizontal well case is about 1.7 million std. m 3, whereas, the total amount of stored using the horizontal well reached 680 million std.m 3. Although both vertical and horizontal cases are profitable for the synthetic reservoir case considered here, flooding using horizontal wells has a higher NPV than that for vertical wells. The profitability index for the horizontal well case achieves 1.96 for this project. The horizontal well case with constant injection BHP has the highest NPV ($64.16 million), which is 157% of the NPV of the vertical case with the same BHP injection. Sensitivity analysis shows that the oil price is the most sensitive factor for the profitability of this project, followed by tax and the royalty rate. November 2008, Volume 47, No

5 Acknowledgements The authors would like to acknowledge Computer Modelling Group (CMG) for providing the software used in this study. SI Metric Conversion Factors bbl E 01 = m 3 ft 3.048* E 01 = m psi E+00 = kpa *Conversion factor is exact. Provenance Original Petroleum Society manuscript, Economic Analysis for Enhanced Injection and Sequestration Using Horizontal Wells ( TN), first presented at the 7th Canadian International Petroleum Conference (the 57th Annual Technical Meeting of the Petroleum Society), June 13-15, 2006, in Calgary, Alberta. Abstract submitted for review December 3, 2005; editorial comments sent to the author(s) May 1, 2008; revised manuscript received June 24, 2008; paper approved for prepress June 25, 2008; final approval October 26, NOMENCLATURE BHP = bottomhole pressure, KPa EOR = enhanced oil recovery FVF = oil formation volume factor, m 3 /m 3 (reservoir condition/standard condition) MMP = minimum miscible pressure NPV = net present value, C$ OOIP = original oil-in-place, m 3 at the standard condition PI = profitability index ROR = rate of return References 1. Kelm, C.H., Appraising Feasibility of Tertiary Recovery with Carbon Dioxide; paper SPE 9830 presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, OK, 5-8 April Abdassah, D., Siregar, S. and Kristanto, D., The Potential of Carbon Dioxide Gas Injection Application in Improving Oil Recovery; paper SPE presented at the SPE International Oil and Gas Conference and Exhibition in China, Beijing, China, 7-10 November Goodrich, J.H., Review and Analysis of Past and Ongoing Carbon Dioxide Injection Field Tests; paper SPE 8832 presented at the SPE/ DOE Enhanced Oil Recovery Symposium, Tulsa, OK, April Holm, W.L., Evolution of the Carbon Flooding Processes; Journal of Petroleum Technology, Vol. 39, No. 11, pp , November Stalkup, F.I., Carbon Dioxide Miscible Flooding: Past, Present, and Outlook for the Future; Journal of Petroleum Technology, Vol. 30, No. 8, pp , August Pande, P.K. and Heller, J.P., Economic Model of Mobility Control Methods for Flooding; paper SPE presented at the SPE California Regional Meeting, Long Beach, CA, April Computer Modelling Group Ltd., GEM and WinProp Technology Manuals and Training Documents; Computer Modelling Group Ltd., Calgary, AB 8. Killough, J.E. and Kossack, C.A., Fifth Comparative Solution Project: Evaluation of Miscible Flood Simulators; paper SPE presented at the SPE Symposium on Reservoir Simulation, San Antonio, TX, 1-4 February Chaback, J.J. and Williams, M.L., Phase Equilibria in the SACROC Oil/ System; SPE Reservoir Engineering, Vol. 3, No. 1, pp , February Baklid, A., Korbol, R. and Owren, G., Sleipner Vest Disposal, Injection into a Shallow Underground Aquifer; paper SPE presented at the SPE Annual Technical Conference and Exhibition, Denver, CO, 6-9 October Shaw, J.C. and Bachu, S., Flooding Performance Prediction for Alberta Oil Pools; paper presented at the Petroleum Society s Canadian International Petroleum Conference, Calgary, AB, June Bennaceur, K., Gupta, N., Monea, M., Ramakrishnan, T.S., Randen, T., Sakurai, S. and Whittaker, S., Capture and Storage A Solution Within; Oilfield Review, pp , Autumn Nghiem, L., Sammon, P., Grabenstetter, J. and Ohkuma, H., Modelling Storage in Aquifers with a Fully-Coupled Geochemical EOS Compositional Simulator; paper SPE presented at the SPE/DOE Symposium on Improved Oil Recovery, Tulsa, OK, April Computer Modelling Group Ltd., GEM User Manual; Version , Computer Modelling Group Ltd., WinProp User Manual; Version , Authors Biographies Ping Gui is currently a Reservoir Simulation Scientist with the Computer Modelling Group Ltd. in Calgary, Alberta. He holds an M.Sc. degree in petroleum engineering from the University of Alberta, Canada, an M.Eng. degree in petroleum engineering and a B.Eng. degree in mechanical engineering, both from the University of Petroleum, China. Previously, Ping Gui worked in the field of numerical simulation, flow assurance and oil/gas pipeline transportation. He is a member of APEGGA, SPE and the Petroleum Society. Xiaowei Jia is currently a Reservoir Engineer with Penn West Energy Trust in Calgary, Alberta. She graduated with an M.Eng. degree in petroleum engineering from the University of Alberta, Canada. She also obtained her M.Eng. and B.Eng. degrees in petroleum engineering from the University of Petroleum and Jianghan Petroleum University, respectively. Xiaowei Jia is a member of APEGGA, SPE and the Petroleum Society. J.C. Cunha, Ph.D., P.Eng., is a Senior Technical Advisor for Petrobras America in Houston and an Adjunct Professor at the University of Alberta. He has published a number of papers on offshore deepwater drilling, underbalanced and managed pressure drilling, drillstring mechanics and risk analysis applications for petroleum engineering processes. A member of the Petroleum Society, SPE, ASME and the American Society for Engineering Education, Cunha serves on the editorial committees of the Journal of Petroleum Technology and SPE Drilling & Completion. In 2005, he received the University of Alberta s Faculty of Engineering Undergraduate Teaching Award. Luciane B. Cunha is an Associate Professor of Petroleum Engineering at the University of Alberta, Edmonton, Alberta. Before joining the University of Alberta in 2001, she worked for 16 years for Petrobras as a Reservoir Engineer and a Staff Research Scientist in the areas of reservoir characterization and simulation. Cunha holds a B.Sc. degree in civil engineering from the Federal University of Rio de Janeiro, Brazil, an M.Sc. degree in petroleum engineering from Campinas State University, Brazil and a Ph.D. degree in petroleum engineering from University of Tulsa, Tulsa, Oklahoma. Her research interests include reservoir management, characterization and simulation. Dr. Cunha is a member of APEGGA, SPE and the Petroleum Society. 38 Journal of Canadian Petroleum Technology