34 Journal of Canadian Petroleum Technology Economic Analysis for Enhanced CO 2 Injection and Sequestration Using Horizontal Wells P. GUI, X. JIA, J.C. CUNHA*, L.B. CUNHA University of Alberta *currently with Petrobras America, Inc. PEER REVIEWED PAPER PUBLISHED AS A TECHNICAL NOTE (“REVIEW AND PUBLICATION PROCESS” CAN BE FOUND ON OUR WEBSITE) 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 CO 2 have been applied (3) , including CO 2 gas injection (continuously), CO 2 gas slug followed by water, and others. There are some important factors to be considered during the design of CO 2 flooding, including the availability and amount of CO 2 to inject, the reservoir conditions, whether mobility control techniques are required and other general operating condi� tions (4, 5) . Among these factors, the knowledge of reservoir condi� tions 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, 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 CO 2 into an oil reservoir is a promising technology for reducing green� house emissions while increasing the ultimate recovery of oil. Numerical reservoir simulation is an important and inexpen� sive tool for designing EOR CO 2 projects and predicting optimal operational parameters. In this work, reservoir simulations per� formed with a compositional simulator were applied to inves� tigate the macroscopic mechanisms of a CO 2 injection process. Horizontal injectors were used to increase injectivity. Compared to traditional vertical wells, horizontal wells are more attractive to improve CO 2 flooding economics by increasing injection rate, improving areal sweep and increasing CO 2 storage. The effects of several important parameters on the performance of the CO 2 process were studied to optimize the process. Operational param� eters such as different production schemes, the injector pressure and injection rate were investigated to determine the optimal op� op� op� erating conditions for simultaneous objectives of higher recovery and higher CO 2 storage. The application of CO 2 flooding using horizontal wells can shorten project life, which is critical to its economics. The sim� project life, which is critical to its economics. The sim� project life, which is critical to its economics. The sim� which is critical to its economics. The sim� its economics. The sim� . The sim� The sim� ulation results served as the basic input parameters for the eco� nomic analysis performed. Furthermore, net present value (NPV) and profitability index results were used to optimize the profit� ability of the project and to compare the CO 2 application using vertical and horizontal wells. The analysis used actual design pa� rameters, including equipment and operating costs. The evalu� ation emphasized the importance of reservoir characteristics, optimum design of operation parameters and economic factors in the economic feasibility of CO 2 injection projects for enhanced oil recovery and sequestration. fractures and faults, etc. Field tests of CO 2 floods have shown that reservoir heterogeneities, such as fractures, strata discontinui� ties and pinch�outs, can reduce the effectiveness of the process. CO 2 is a highly mobile fluid because of its low viscosity, so fin� gering and channeling of CO 2 or bypassing of oil can affect the volumetric sweep efficiency in CO 2 flooding. In this case, mobility control becomes an important issue for the improvement of CO 2 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 CO 2 flooding process using vertical wells and using horizontal wells. The CO 2 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 CO 2 flooding process (7�9) . With the use of a compositional flow simulator, dif� ferent CO 2 flooding mechanisms can be simulated, including va� pourization 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 CO 2 injection. On the other hand, atmospheric concentrations of CO 2 are in� creasingly raising concerns. Different possibilities for CO 2 seques� tration are being carried out to reduce the greenhouse effect. One strategy is to store CO 2 in aquifers or abandoned gas and oil reser� voirs. In this category, some field CO 2 storage projects have proved to be very successful (10) . Another very interesting strategy is the combination of enhanced oil recovery (EOR) and CO 2 flooding, which reduces greenhouse emissions while increasing the ultimate recovery of oil (11) . Bennaceur et al. (12) reviewed the enhanced oil recovery project using CO 2 in Weyburn, Saskatchewan, Canada. The Weyburn EOR�CO 2 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 CO 2 will ultimately be stored in the Weyburn Field during the project’s lifetime. This study falls into the second strategy men� tioned above (EOR�CO 2 ) which discusses the application of the CO 2 flooding process to simultaneously enhance oil recovery and increase CO 2 storage. Although there are mainly two trapping mechanisms in CO 2 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 CO 2 flooding process using horizontal wells to simultaneously enhance recovery and increase CO 2 storage. Obviously, this is an economic, social and environmental TECHNICAL NOTE TECHNICAL NOTE
Transcript
34 Journal of Canadian Petroleum Technology
Economic Analysis for Enhanced CO2 Injection and Sequestration
Using Horizontal Wells
P. gui, x. Jia, J.C. Cunha*, l.b. Cunha university of alberta
*currently with Petrobras America, Inc.
PEER REVIEWED PAPER PUBLISHED AS A TEcHnIcAL noTE (“REVIEW AnD PUBLIcATIon PRocESS” cAn BE FoUnD on oUR WEBSITE)
IntroductionThe carbon dioxide flooding process can increase oil recovery
by means of swelling, evaporating and lowering oil viscosity(1, 2). Many injection schemes using CO2 have been applied(3), including CO2 gas injection (continuously), CO2 gas slug followed by water, and others. There are some important factors to be considered during the design of CO2 flooding, including the availability and amount of CO2 to inject, the reservoir conditions, whether mobility control techniques are required and other general operating condi�tions(4, 5). Among these factors, the knowledge of reservoir condi�tions 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,
AbstractCarbon 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 CO2 into an oil reservoir is a promising technology for reducing green�house emissions while increasing the ultimate recovery of oil.
Numerical reservoir simulation is an important and inexpen�sive tool for designing EOR CO2 projects and predicting optimal operational parameters. In this work, reservoir simulations per�formed with a compositional simulator were applied to inves�tigate the macroscopic mechanisms of a CO2 injection process. Horizontal injectors were used to increase injectivity. Compared to traditional vertical wells, horizontal wells are more attractive to improve CO2 flooding economics by increasing injection rate, improving areal sweep and increasing CO2 storage. The effects of several important parameters on the performance of the CO2 process were studied to optimize the process. Operational param�eters such as different production schemes, the injector pressure and injection rate were investigated to determine the optimal op� op�op�erating conditions for simultaneous objectives of higher recovery and higher CO2 storage.
The application of CO2 flooding using horizontal wells can shorten project life, which is critical to its economics. The sim� project life, which is critical to its economics. The sim�project life, which is critical to its economics. The sim�which is critical to its economics. The sim�its economics. The sim�. The sim� The sim�ulation results served as the basic input parameters for the eco�nomic analysis performed. Furthermore, net present value (NPV) and profitability index results were used to optimize the profit�ability of the project and to compare the CO2 application using vertical and horizontal wells. The analysis used actual design pa�rameters, including equipment and operating costs. The evalu�ation emphasized the importance of reservoir characteristics, optimum design of operation parameters and economic factors in the economic feasibility of CO2 injection projects for enhanced oil recovery and sequestration.
fractures and faults, etc. Field tests of CO2 floods have shown that reservoir heterogeneities, such as fractures, strata discontinui�ties and pinch�outs, can reduce the effectiveness of the process. CO2 is a highly mobile fluid because of its low viscosity, so fin�gering and channeling of CO2 or bypassing of oil can affect the volumetric sweep efficiency in CO2 flooding. In this case, mobility control becomes an important issue for the improvement of CO2 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 CO2 flooding process using vertical wells and using horizontal wells. The CO2 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 CO2 flooding process(7�9). With the use of a compositional flow simulator, dif�ferent CO2 flooding mechanisms can be simulated, including va�pourization 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 CO2 injection.
On the other hand, atmospheric concentrations of CO2 are in�creasingly raising concerns. Different possibilities for CO2 seques�tration are being carried out to reduce the greenhouse effect. One strategy is to store CO2 in aquifers or abandoned gas and oil reser�voirs. In this category, some field CO2 storage projects have proved to be very successful(10). Another very interesting strategy is the combination of enhanced oil recovery (EOR) and CO2 flooding, which reduces greenhouse emissions while increasing the ultimate recovery of oil(11).
Bennaceur et al.(12) reviewed the enhanced oil recovery project using CO2 in Weyburn, Saskatchewan, Canada. The Weyburn EOR�CO2 storage project has increased daily production rates from 1,590 std.m3/day (10,000 STB/day) to 4,770 std.m3/day (30,000 STB/day). Meanwhile, it is estimated that 22 million metric tons of CO2 will ultimately be stored in the Weyburn Field during the project’s lifetime. This study falls into the second strategy men�tioned above (EOR�CO2) which discusses the application of the CO2 flooding process to simultaneously enhance oil recovery and increase CO2 storage. Although there are mainly two trapping mechanisms in CO2 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 CO2 flooding process using horizontal wells to simultaneously enhance recovery and increase CO2 storage. Obviously, this is an economic, social and environmental
TECHNICAL NOTETECHNICAL NOTE
november 2008, Volume 47, no. 11 35
issue and optimization will contribute to reach the two objectives: enhanced oil recovery and CO2 storage. Economic analysis is es�pecially important in a CO2 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 CO2 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 commer�cial compositional simulator is used to conduct the CO2 miscible flooding studies(14). With the simulation of different injection and production scenarios, the study can give a good estimate of the re�covery improvement under CO2 gas injection. The simulation re�sults were the basic input parameters for the economic feasibility study.
Synthetic Reservoir CaseThe proposed reservoir is part of a lease area with both a length
and width of 685.8 m and an average reservoir thickness of 50.29 m (irregularly distributed). The reservoir physical properties are not homogenously distributed. Based on the porosity and perme�ability data map, the histogram of the porosity and permeability distribution can be generated and analyzed. Then the reservoir het�erogeneity can be represented by a histogram of porosity and per�meability distribution. The histogram of the porosity distribution shows that over 80% porosity values fall in between 0.15 and 0.20. 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 1.56. The original oil�in�place (OOIP) can be calculated as being around 2 million std.m3.
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 un�dersaturated, so there was no original gas cap. The average den�sity of the oil in this reservoir is 42°API, with about 30% of C7+ components.
In this paper, CO2 flooding is characterized as a miscible dis�placement of reservoir oil. The minimum miscible pressure (MMP)
is mainly dependent on the reservoir temperature and the composi�tion 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 CO2 flooding screening stan�dards summarized by Stalkup(5), the reservoir physical properties and character of its oil make this reservoir a good candidate for CO2 flooding, as well as CO2 storage.
Two injection and production options for the CO2 process were compared and analyzed. One uses a vertical injector and four ver�tical producers and another uses a horizontal injector and a hor�izontal 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, in�cluding four producers spaced close to each corner of the square lease area and one CO2 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 m3/m3 (20,000 ft3/bbl) for each well or total produc�tion of the well group drops to 7.95 std.m3/day (50 STB/day). The production considers a constant BHP control scheme and the in�jection 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 CO2 flooding process. For the horizontal well case, there is only one producer and one CO2 injector; each one installed on opposite sides of the lease area. As in the vertical case, the se�lection of location for the horizontal wells was determined con�sidering the previously mentioned factors and comparing different scenarios.
FIGURE 1: Option 1 with vertical producers and injector.
FIGURE 2: Option 2 with horizontal producer and injector.
FIGURE 4: Comparison of cumulative oil production curve (constant injection rate).
36 Journal of Canadian Petroleum Technology
Simulation Results and AnalysisThis section summarizes the simulation results for both the ver�
tical and horizontal cases. As mentioned before, there are two in�jection and production scenarios performed in the simulation; the constant CO2 injection rate of 311,485 std.m3/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 CO2 injection rate scenario. From Figure 3, it is obvious that under the same constant CO2 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 con�clusion, a comparison is made between the vertical and horizontal injectors using constant CO2 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 ver�tical 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
FIGURE 10: Comparison of gas oil ratio curve (constant injection BHP).
november 2008, Volume 47, no. 11 37
study the direct effect of these aspects, the cumulative oil produc�tion 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.m3. For the constant injection rate scenario, the difference between horizontal injection and vertical injection is not that obvious be�cause the vertical injector has a higher injection BHP to maintain the same injection rate. However, even in that situation, the hori�zontal 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 CO2 storage faster and more effective. Figure 11 shows that, at the same BHP for the injector, the hori�zontal case only needs half of the time to store the same amount of CO2. The total amount of CO2 stored reached 680 million std.m3 in the horizontal case. Only when increasing the vertical injector BHP to 19,305 KPa (2,800 psi), does the CO2 storage process get close to the results obtained for the horizontal case.
In brief, horizontal wells show better injectivity and sweep effi�ciencies 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 CO2 is not as efficient as that of horizontal wells.
Economical AnalysisThe simulation results served as the basic input parameters for
the economic analysis for both the vertical and horizontal CO2 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, CO2 treatment and injection equipment and the recycling plant. Cost of drilling a new CO2 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 oper�ation 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 CO2 and hydrocarbons that can be used for fuel and sale, this benefit is significantly offset by the large capital investment for the CO2 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 eco�nomically attractive option. The CO2 recycle and re�injection cost is assumed as $0.0134/m3. 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 CO2 prices, roy�alties, taxes and depreciation (15�year as a straight line). Sensi�tivity analysis is conducted by changing each one of the above parameters in the simulation. Not surprisingly, the oil price is the
most sensitive factor on the net present value among the above�mentioned factors. With a 10% fluctuation in the oil price, the NPV of this project will change from $6 to $10 million accordingly, de�pending on different cases. The influence of other factors is rela�tively close, with the sensitivity order in this study as follows: tax rate, royalty rate, the rate of return and CO2 price.
Net present value is calculated for both development options. Figure 12 compares the NPV values for both the vertical and hori�zontal cases with either a constant BHP scheme or a constant injec�tion 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, CO2 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
This paper analyzed the economic feasibility of an EOR�CO2 flooding project in a proposed reservoir. The simulation results show that this project is technically and economically feasible. The study compares CO2 flooding using vertical wells and horizontal wells. Horizontal wells have proven to be more efficient to im�prove recovery while increasing CO2 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 injec�tion. Compared to vertical wells, the horizontal case only needs half of the time to store the same amount of CO2. The cumulative oil production for the horizontal well case is about 1.7 million std.m3, whereas, the total amount of CO2 stored using the horizontal well reached 680 million std.m3.
Although both vertical and horizontal cases are profitable for the synthetic reservoir case considered here, CO2 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 ($64.16 million), which is 157% of the NPV of the vertical case with the same BHP injection. Sensitivity anal�ysis shows that the oil price is the most sensitive factor for the prof�itability of this project, followed by tax and the royalty rate.
(reservoir condition/standard condition)MMP = minimum miscible pressureNPV = net present value, C$OOIP = original oil�in�place, m3 at the standard conditionPI = profitability indexROR = rate of return
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Provenance—Original Petroleum Society manuscript, Economic Anal-ysis for Enhanced CO2 Injection and Sequestration Using Horizontal Wells (2006�123TN), first presented at the 7th Canadian International Pe�troleum Conference (the 57th Annual Technical Meeting of the Petroleum Society), June 13�15, 2006, in Calgary, Alberta. Abstract submitted for re�view December 3, 2005; editorial comments sent to the author(s) May 1, 2008; revised manuscript received June 24, 2008; paper approved for pre�press June 25, 2008; final approval October 26, 2008.
Authors’ BiographiesPing Gui is currently a Reservoir Simu�lation Scientist with the Computer Mod�elling Group ltd. in Calgary, Alberta. He holds an M.Sc. degree in petroleum engi�an M.Sc. degree in petroleum engi�M.Sc. degree in petroleum engi�neering from the University of Alberta, Canada, an M.Eng. degree in petroleum en�gineering and a B.Eng. degree in mechan�ical engineering, both from the University of Petroleum, China. Previously, Ping Gui worked in the field of numerical simulation, flow assurance and oil/gas pipeline trans�
portation. He is a member of APEGGA, SPE and the Petroleum Society.
Xiaowei Jia is currently a Reservoir En�gineer 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 Pe�troleum 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 pres�sure drilling, drillstring mechanics and risk analysis applications for petroleum engi�neering processes. A member of the Pe�troleum Society, SPE, ASME and the American Society for Engineering Educa�
tion, 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 Un�dergraduate Teaching Award.
Luciane B. Cunha is an Associate Pro�fessor 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 character�ization and simulation. Cunha holds a B.Sc. degree in civil engineering from the Fed�eral University of Rio de Janeiro, Brazil, an M.Sc. degree in petroleum engineering
from Campinas State University, Brazil and a Ph.D. degree in pe�troleum engineering from University of Tulsa, Tulsa, Oklahoma. Her research interests include reservoir management, characteriza�tion and simulation. Dr. Cunha is a member of APEGGA, SPE and the Petroleum Society.
