AIChE paper ID#: Evaluation of the EOR Potential of Gas and Water Injection in Shale Oil Reservoirs

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1 AIChE paper ID#: Evaluation of the EOR Potential of Gas and Water Injection in Shale Oil Reservoirs Ke Chen and James J. Sheng, Texas Tech University, Lubbock, TX Abstract With the relatively modest natural gas price, producing oil from unconventional shale reservoirs, which are less common and less well understood than conventional sandstone and carbonate reservoirs, has attracted more and more interest from oil operators. Though many tremendous efforts have been made to develop shale resources, the ultimate oil recovery is still low (5-10%). Because of the important role of shale resources in the future oil and gas industry, more stimulation and production strategies are being considered and tested to find ways to improve oil production from shale reservoirs. In this paper we use a simulation approach to evaluate the EOR potential in shale oil reservoirs by gas flooding and water flooding. Production behavior and oil recovery of different schemes are discussed through sensitivity studies. Simulation results of primary production, gas injection and water injection are compared in this paper. Results show that miscible gas injection has a higher potential to improve oil recovery from shale oil reservoirs than water injection. Gas injection above MMP can be fully miscible with oil, and reducing oil viscosity greatly, in addition to the mechanism of pressure maintenance. Our simulation results indicate that the oil recovery factor can be increased by up to 15.1% by gas injection in a hydraulically fractured shale reservoir, compared with the 6.5% from the primary depletion. The oil recovery from water flooding is about 11.9% which is lower than those from gas flooding. The results indicate that miscible gas flooding could be a way to enhance oil recovery in shale oil reservoirs. Introduction Unconventional shale reservoirs are generally produced by stimulation techniques. A horizontal well with multiple transverse fractures has proven to be an effective technique for shale gas and shale oil production. However, shale oil production faces more challenges compared with shale gas production. Even applying multi-stage hydraulic fracturing techniques, the final oil recovery factors using existing methods are only a few percent. And oil rate and reservoir pressure drops very quickly. We initiate this study to evaluate whether conventional enhanced oil recovery techniques could have a potential in improving oil production in shale oil reservoirs. Gas flooding and water flooding, relatively simple and cheaper EOR techniques, have been successfully implemented in conventional and some unconventional tight oil reservoirs for a long time. Therefore, we simulate gas flooding and water flooding in this paper to evaluate their potentials in improving oil recovery in shale oil reservoirs. Base model setup

2 The objective of our study is to evaluate the potential of gas and water injection for improving oil production from shale oil reservoirs. Modeling a whole reservoir requires a large number of grid blocks, and it is of course time-consuming to model these complex fracture networks. Therefore, we built a small model which is 200 ft long, 1000 ft wide and 200 ft thick (Fig. 1). This small model is produced with two half-vertical wells connected with two half-fractures, respectively. Thus each fracture is 1-ft wide and has a conductivity of md-ft. We use such a simple model to simulate the flow between the two lateral hydraulic fractures of a horizontal well. Assume the flow between any two lateral fractures is the same, such small model can be used to simulate the flow for a part of a horizontal well. The reservoir properties data used in this model is shown in Table 1. Our base model is similar to Wan s model (2013) which has been validated. The base model uses a 4-component system which consisting of water, oil, dissolved gas and solvent. Both the solvent (injected gas) and the original dissolved gas have the density of 0.8. The oil compressibility is 1*10-5 psi -1. The injected gas is composed of 77% C 1, 20% C 2 and 3% C 6. The mixing of solvent and free gas is governed by ω g (OMEGASG in IMEX), which is assumed pressure independent. ω g is bounded by zero and one. Since solvent-gas has a lower mobility ratio than oil-solvent, ω g is usually greater than ω omax. In our case OMEGASG is set as 1.0, assuming solvent and free gas have a complete mixing. In this base simulation model, the injection is controlled by the maximum solvent injection rate for a half well of 400 Mscf/day and the maximum injection pressure of 7000 psi. For the production well, the flowing bottom-hole pressure is 2500 psi. Simulation results and analysis In this section, gas injection and water flooding scenarios are presented and analyzed. Gas injection We first compare several gas injection scenarios. Scenario G1: 3600 days of primary production followed by 60 years of gas flooding production In this scenario, gas injection starts after 3600 days (10 years) of primary production. Figs. 2 and 3 show the results for oil recovery factor, average pressure and oil rate versus time. The reservoir pressure decreases fast from the initial reservoir pressure to 3000 psi as the reservoir is mainly in depletion drive in the first 10 years primary production. Once gas is injected, the reservoir pressure increases from 3000 psi to more than 5000 psi gradually. From the oil production rate graph (Fig. 3), the oil rate decreases from the initial rate bbl/day to bbl/day after 200 days of production and to 2.72 bbl/day within 5 year. At the end of primary production period, the oil rate is 0.57 bbl/day. After gas injection is started, the oil rate gradually increases to 1.3 bbl/day. At the end of 60 years of gas injection, MSTB oil is produced, corresponding to an oil

3 recovery factor of 15.12%. Fig. 4 shows the pressure variation and oil saturation distribution during the production period. When starting gas injection process, the solvent is injected into the reservoir through injection well and mix with reservoir fluids, leading oil viscosity decrease. Oil is pushed away from the injection well as shown in the saturation map. In the meantime the reservoir pressure builds up. Owing to the ultra-low permeability, fluid transport in such kind of reservoirs is much more difficult than that in conventional reservoirs. This also results in small increase in oil rate after gas injection. Scenario G2: 3600 days of primary production followed by 60 years of cyclic gas flooding production For this scenario, cyclic gas injection begins after 3600 days (10 years) of primary production. Each injection cycle has 5 years-injection and 5 years-shut in. The overall recovery factor at the end of 70 years is 14.42%. Scenario G3: 70 years of gas flooding production In this scenario, gas injection is started at the beginning of the development. Keep gas flooding and oil production simultaneously for 70 years which is the total production period in the previous scenarios. Because of gas injection, the reservoir pressure maintain high around 5000 psi. However, the total oil recovery is 13.48%. We have considered three production scenarios so far. In the first scenario, gas injection begins after 10 year primary production and continues gas injection for 60 years MMSCF of gas is injected, and MSTB of oil is produced which corresponds to 15.12% oil recovery factor. In the second scenario, cyclic gas injection starts after 10 year primary production. The cyclic process has 5 year injection and 5 year shut in. In this process, MMSCF of gas is used to produce about 14.42% of original oil in place. For the scenario 3, gas injection is implemented at the beginning of the development. It can be seen that scenario 3 has a lower oil production in first 10 years because only one production well is used instead of two production wells in the other two scenarios (Table 2). Therefore, it s better to implement gas flooding after several years of natural pressure depletion. The results of three simulation scenarios show that the ultimate recovery factors are not quite different for these three different injection scenarios, but less solvent is injected in scenario 2 and the ultimate oil recovery obtained from the scenario 2 is close to that of the scenario 1. Therefore, cyclic gas injection after 10 year primary production may be a better option. For an analysis purpose, we simulated 70 years. 70 years may be too long in reality, we present the results in at the end of 10, 30, 50 and 70 years. Water flooding simulation In this section, we present several water injection scenarios similar to the gas injection discussed above. Scenario W1: 3600 days of primary production followed by 60 years of water flooding production

4 In the production scenario 1, water injection begins after 3600 days (10 years) of primary production. The production is driven by natural pressure depletion in the first 10 years. The reservoir pressure decreases from 6425 psi to 3000 psi in primary production period and then gradually increases to more than 4000 psi after water injection. The initial oil rate is bbl/day, after 200 days of primary production it decreases to bbl/day. At the end of primary production, the oil rate is 0.57 bbl/d. When water injection begins, the increase in production rate cannot be seen. Because shale reservoir has an ultra-low permeability, the injection fluids have difficulty to transport from the injection to producer. The response of production well to water flooding is poor. This also results in a low injection rate. During waterflooding, the oil rate is about 0.8 bbl/ day, and the oil recovery factor is 11.9% at the end. Scenario W2: 3600 days of primary production followed by 60 years of cyclic water production For this scenario, water injection begins after 3600 days (10 years) of primary production. In this scenario, cyclic water injection is implemented. Each injection cycle has 5 years-injection and 5 years-shut in. The overall recovery factor at the end of 70 years is 11.03%. Scenario W3: 70 years of water flooding production In this scenario, water injection is started at the beginning of the development. Keep water injection and oil production simultaneously for 70 years. Because of water injection starts at the beginning of the production, the initial production rate are lower than previous scenarios and the reservoir pressure decreases slowly from initial reservoir pressure to 4000 psi, corresponding to a ultimate oil recovery factor of 11%. Three production scenarios have been tested in waterflooding simulation work with results presented in Table 3. In the first scenario, water injection begins after 10 year primary production and continues for 60 years MSTB of water is injected, and MSTB of oil is produced which corresponds to 11.9% oil recovery factor. In the second scenario, cyclic water injection begins after 10 year primary production. The cyclic injection process has 5 years of injection and 5 years of shut in. In this process, MSTB of water is used to produce about 11.03% of original oil in place. For the plan 3, water injection is implemented at the beginning of the development. We can understand that the scenario W3 has a lower oil production in the first 10 years because only one half-production well is used instead of two half-production wells in the other two scenarios. So it s better to implement water flooding after several years of natural pressure depletion. The results of three simulation scenarios show that the ultimate recovery is not quite different for these three different injection scenarios. Shale reservoirs have ultra-low porosity and permeability; it s difficult for injected fluids flow from injection well to production well, leading a low productivity and low injectivity.

5 Conclusions Gas and water flooding are studied in this paper using the simulation approach. Based on this study, the following conclusions are reached. 1. Because of the ultra-low permeability of shale reservoirs, in a 200-ft-wide shale oil reservoir model, it is more difficult for injected fluids to transport and displace oil than in conventional reservoirs or tight oil reservoirs. Even in the miscible condition, oil viscosity can only be reduced near the fractures. The main mechanism of gas injection is the pressure maintenance. 2. According to the sensitivity analysis, low matrix permeability is the main factor that causes low oil recovery from shale reservoirs. A close fracture spacing will have a significant effect on shale oil production. It leads to a higher initial production rate and a much better sweep efficiency for miscible gas flooding. 3. In an ultra-low porosity and ultra-low permeability shale oil reservoir, water injection through high conductivity fracture has less effect on improving oil recovery than gas injection. Unlike miscible gas injection which can reduce oil viscosity, water injection can only provide limited pressure maintenance because of high pressure loss from an injector to a producer. Ultra-low permeability results in a low productivity and low injectivity. Therefore, the performance of water injection is poor. 4. Comparing the simulation results of gas flooding and water flooding, miscible gas injection has a better effect on improving oil recovery in shale reservoirs. Injected solvent can be miscible with oil, reducing oil viscosity, and lead a higher stimulated volume than water, in addition to pressure maintenance. Gas injection may be a potential method to improve oil production in shale oil reservoirs. References Bazan, L.W., Larkin, S.D., Lattibeaudiere, M.G., and Palisch, T.T Improving production in the Eagle Ford Shale with fracture modeling, increased conductivity and optimized stage and cluster spacing along the horizontal wellbore, paper SPE presented at the Tight Gas Completions Conference, 2-3 November, San Antonio, Texas. Chaudhary, A., Ehlig-Economides, C., and Wattenbarger, R Shale Oil Production Performance from a Stimulated Reservoir Volume, paper presented at the SPE Annual Technical Conference and Exhibition, 30 October-2 November, Denver, Colorado. Chen, K Evaluation of the EOR Potential by gas and water flooding in Shale Oil Reservoirs, Master thesis, Texas Tech University. IMEX user manual, Computer Modeling Group, Rubin, B Accurate Simulation of Non Darcy Flow in Stimulated Fractured Shale Reservoirs. paper SPE presented at the SPE Western Regional Meeting, May, Anaheim, California. Todd, M.R. and Longstaff, W.J The Development, Testing, and Application Of a Numerical Simulator for Predicting Miscible Flood Performance, JPT, 24(7),

6 Wan, T Evaluation of the EOR Potential in Shale Oil Reservoirs by Cyclic Gas Injection, Master thesis, Texas Tech University. Table 1 Reservoir properties for Eagle Ford shale Initial Reservoir Pressure 6425 psi Porosity of Shale Matrix 0.06 Initial Water Saturation 0.3 Compressibility of Shale 5*10-6 psi -1 Shale Matrix Permeability md Reservoir Temperature F Gas Specific Gravity 0.8 Reservoir Thickness 200 ft Bubble Point for Oil 2398 psi Table 2 Gas flooding simulation results Scenario G1 primary+gas Scenario G2 Primary+cyclic Scenario G3 gas flooding Cumulative Oil Production MSTB MSTB MSTB Cumulative Gas Injection MSTB MSTB MSTB Overall Oil Recovery(10 years) 5.75% 5.75% 3.4% Overall Oil Recovery(30 years) 8.14% 7.95% 6.68% Overall Oil Recovery(50 years) 11.49% 11.05% 9.97% Overall Oil Recovery(70 years) 15.12% % % Table 3 Water flooding simulation results Scenario W1 primary+water Scenario W2 primary+cyclic Scenario W3 waterflooding Cumulative Oil Production MSTB MSTB MSTB Cumulative Water Injection MSTB MSTB MSTB Overall Oil Recovery(10 years) 5.73% 5.73% 3.39% Overall Oil Recovery(30 years) 7.59% 7.21% 6.41% Overall Oil Recovery(50 years) 9.8% 9.30% 8.87% Overall Oil Recovery(70 years) 11.9% 11.03% 11.05%

7 Fig. 1 Base reservoir model Fig. 2 Average reservoir pressure and oil recovery factor vs. Time

8 Fig. 3 Oil production rate vs. Time Fig. 4 Reservoir pressure distribution and oil saturation distribution as a function of time