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Simulation of low and high salinity water injection method to determine the optimum salinity
Petroleum Research xxx (xxxx) xxx
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Simulation of low and high salinity water injection method to determine the optimum salinity Seyed Mohammad Mehdi Nassabeh a, Afshin Davarpanah b, *, Joata Bayrami a a b
Department of Petroleum Engineering, Faculty of Engineering and Technology, Omidiyeh Branch, Islamic Azad University, Omidiyeh, Iran Department of Petroleum Engineering, Science and Research Branch, Islamic Azad University, Tehran, Iran
a r t i c l e i n f o
a b s t r a c t
Article history: Received 16 December 2018 Received in revised form 25 July 2019 Accepted 31 July 2019 Available online xxx
Investigating the enhanced oil recovery leads to optimal production, protection and reduction of lateral impacts. Low salinity water injection (LSWI) is one of the significantly improved oil recovery (IOR) techniques for changing the amount of wettability in the carbonate fractured reservoirs. The utilization of this methodology in terms of high efficiency in displacing light crude oils to the medium-gravity crude oils, water sources availability and its sustainability for pushing the oil which leads to appropriate economic occasions, are being compared with other IOR/EOR techniques. In this study, the best injection modelling pattern is based on the highest rate of recovery factor. Comparison of “high and low salinity water injection method” with “pure water injection method” is performed in an oil reservoir. Overall, analyzing the sensitivity on the high and low salinity according to the moderately low recovery factor of high and low salinity among the injection scenarios illustrates the low sensitivity of this parameter on a fractured carbonate reservoir. By reviewing different scenarios, it could be demonstrated that if the water injection could be applied to the reservoir from the preliminary times of production, the recovery factor rate would be increased. Thereby, higher appropriate efficiency and better supplement have resulted. Pure water injection has a high recovery factor than salty water injection. By the way, these two methods have little differences in calculating recovery methods. Besides, this parameter is significantly depended on wellhead equipment properties, safety factor and economic issues (water production). © 2019 Chinese Petroleum Society. Publishing Services by Elsevier B.V. on behalf of KeAi. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
Keywords: Low salinity water injection Enhance oil recovery Injection scenarios Oil recovery factor Water production
1. Introduction Due to the increasing demand for crude oil consumption for different energy sections, it seems that these non-renewable resources should be optimally used, but also survival of future generations has been facing a severe crisis (Davarpanah 2018a, 2018c; Razmjoo and Davarpanah, 2019; Razmjoo et al., 2019; Shirmohammadi and Gilani, 2018). As it is evident, regarding the non-recoverable parts of fossil fuels which are considered as the large volumes in hydrocarbon reservoirs, it is necessary to administer enhanced oil recovery techniques to produce the remained oil and gas (Al-Shalabi et al., 2015; Valizadeh and Davarpanah, 2019; Vikara et al., 2019; Zarei et al., 2019). Porous and permeable underground structural hydrocarbon reservoir is a natural accumulation of hydrocarbons in a liquid or gas in its place by isolation of non-permeable rocks from the surrounding environment (Al-
* Corresponding author. E-mail address: [email protected] (A. Davarpanah).
Shalabi and Sepehrnoori, 2016; Davarpanah et al. 2019a, 2019b; Davarpanah and Mirshekari, 2018; Lewandowska-Smierzchalska et al., 2018; Zhang et al., 2018). In the more concrete description, hydrocarbon reservoirs can be likened to kite filled with air, and the shell of this kite plays the role of non-permeable rocks. Upon piercing the balanced environment, reservoir fluids by hydraulic forces are driven into a well. The power of this natural drift is reduced along with the production of the reservoir (Akin and Kovscek 1999; AL-Shehri et al., 2009; Arfaee and Sola, 2014; Armin Razmjoo et al., 2019; Davarpanah and Mirshekari, 2019b; Davarpanah and Mirshekari, 2019c; Davarpanah and Mirshekari, 2019d; Teklu et al., 2016). General information such as the total amount of oil in place, oil layers, depth of oil layer and other parameters in the production stage are of significance (Bello et al., 2018; Bhowmik and Dutta, 2013; Boujelben et al., 2018; Davarpanah 2018b, 2018d). According to the original plan, each reservoir in the early stage and the final stage of production is determined and affected (Chen et al., 2018; Dang et al., 2016; Davarpanah and Mirshekari, 2019a; Davarpanah et al. 2018a, 2019c). As is known, Iranian reservoirs
https://doi.org/10.1016/j.ptlrs.2019.07.003 2096-2495/© 2019 Chinese Petroleum Society. Publishing Services by Elsevier B.V. on behalf of KeAi. This is an open access article under the CC BY-NC-ND license (http:// creativecommons.org/licenses/by-nc-nd/4.0/).
Please cite this article as: Nassabeh, S.M.M et al., Simulation of low and high salinity water injection method to determine the optimum salinity, Petroleum Research, https://doi.org/10.1016/j.ptlrs.2019.07.003
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have an average of 8e10 percent natural decline in reservoir pressure and the production rate for wells (wells with low reservoir pressure drop is directly related to production rate). With the continuous drop in reservoir pressure, the production rate gradually reduces until the normal production of the reservoir will not be cost-effective. This point occurs when the oil recovery from the reservoir is relatively low. This recovery for Iranian reservoirs is about 15e20 percent; in other words, 80 to 85 percent of the oil remains in the formation (Al-Shalabi et al., 2017; Davarpanah et al. 2018c, 2019d; Ebadati et al., 2018; Torrijos et al., 2016). Large amounts of oil in the world in the Middle East from Syria to Oman in the carbonate reservoirs with low permeability are nonhydrophilic. Some of the reservoirs are entirely fractured, and some usually are and non-fractured that various periods of heavy oil to light oil with different combinations are included (AlHammadi et al. 2018; Alhuraishawy et al., 2018; Davarpanah et al., 2018b). Naturally, fractured carbonate reservoirs contain significant volumes of oil in different areas of the world. In Iran, about 30 percent of such reservoirs, which means billions of barrels of oil are available. These fractured and non-fractured reservoirs by natural forces such as the water drive or water injection applications are in oil production, but the efficiency is very low (Chen et al., 2018; Puntervold et al., 2018). 2. Simulation procedure Iran's oil reservoir is located in the southwest and was put into operation in 1999; the reservoir is an anticline that its reservoir is Asmari carbonate with Gachsaran cap rock. Based on field reports, the reservoir is fractured and saturated and has three phases of oil, water and gas. The first well of this reservoir was drilled in 1999 that with a maximum production of 3000 barrels per day production and was closed in late 2003 due to operational issues. Two other wells (wells 2 and 3) had been excavated in 2000 and reached the maximum production of 3000 barrels a day until 2007. In total, three wells in the reservoir had been drilled, among which, two wells were vertical wells, and one well was horizontal well. By 2007, the cumulative oil rate was approximately 15.228 million barrels, and the daily production is 6000 barrels per day. According to reports, the initial pressure is 4100 psi at a depth of 900 feet. Despite the oil leak because the connection between the band gap and oil reservoir, the fractured reservoir can be confirmed. The water-oil contact is at a depth of 1950 feet, and the gas-oil contact is at a depth of 600 feet. Reservoir rock properties are provided in Table 1. Moreover, reservoir fluid composition properties are explained in Table 2. 3. Results and discussion The economic output of the reservoir of this parameter plays an
Table 1 Reservoir rock properties. Sampling data
Date
5/12/1998
Sampling depth Sampling flowing pressure Reservoir pressure Reservoir temperature Test temperature Bubble point pressure Bo @ Pb The density of total gas evolved @S.C Density of stock tank @S.C The density of reservoir fluid @Pb GOR @S.C
Feet Psia Psia C ℉ Psia rb/STB g/lit g/cc g/cc SCF/STB
1200 1760 4350 175 180 3715 1.6822 1.1761 0.8575 0.6636 1230.22
important role, and whatever water cut rate is less the production efficiency has played a positive effect, if the water cut is higher than a certain extent, so it causes the closing of the production well. To investigate the impact of salinity. Six different scenarios are defined based on the analysis of varying salinity. However, scenarios 1, 2, and three focus on the effects of salinity on the oil recovery factor, scenarios 4, 5 and 6 is based on the comparison of natural depletion. Moreover, the low salinity of 5 gr/kg (density, 1005 kg per cubic meter and 1.15 cP at 15 C) and the high salinity of 40 gr/kg (density 1030 kg per cubic meter and viscosity, 1.23 at 15 C) are assumed. 3.1. Scenario 1 According to the simulation procedure, the injection well No. 4 was selected at the injection rate of 1000 barrels per day. Of course, this rate was based on a possible operational rate and the tolerable amount of pressure wellhead equipment, and the injection pump was selected. In this scenario, the injection rate is 1000 barrels per day; a complete analysis of low and high salinity was performed. Since the salinity of the water effect on viscosity and density, and this parameter is the fundamental parameter in the reservoir simulation model especially in the analysis of the injected water salinity changes on the rate of recovery factor, the absolute salinity curve based on the viscosity and density at 15 C which is depicted in Fig. 1. Through studying the low and high salinity rate, an injection with the maximum rate of recovery factor was done. This injection rate from the beginning of the life of the reservoir in 2007 was taken into account and will be predicted and simulated by the end of 2025. Before 2007, well-acted as a natural depletion, the minimum production rate of 1000 barrels per day was considered. If the produced quantity is less than this value, the well is closed automatically. The results of the flooding are illustrated in Fig. 2. 3.2. Scenario 2 According to the design, to higher efficiency (recovery factor), the rate of 2000 barrels per day in the injection well No.4 is considered that injected amount based on operational justifications have been studied and selected. However, it should be noted that the higher injection rate, the higher reservoir recovery factor. But due to wellhead equipment, other parameters mentioned in the previous section were defined and studied in 2000. In this scenario, to increase recovery factor, production rate from 2007 until the end of 2025 was considered. And before this date, the natural depletion has been produced, and the minimum production rate of 1000 barrels per day is considered. If the amount of production is less than this value, the well is closed automatically. Also, minimum wellhead pressure of 900 psi, maximum water cut of 50% and maximum GOR of 1.2 are specified. In this case, the sensitivity analysis of the injected water salinity (high salinity and low salinity) is calculated. The results and documentation of the design are shown in Fig. 3. 3.3. Scenario 3 According to this design, to higher efficiency (recovery factor), the rate of 2000 barrels per day as an injection rate into the injection well No.4 is considered. In this scenario results of low and high salinity scenario from 2017 until the end of 2025 were reviewed. And before this date, as the natural depletion has been produced, the minimum production rate of 1000 barrels per day is considered. If the amount of production is less than this value, the well is closed automatically. Also, minimum wellhead pressure of
Please cite this article as: Nassabeh, S.M.M et al., Simulation of low and high salinity water injection method to determine the optimum salinity, Petroleum Research, https://doi.org/10.1016/j.ptlrs.2019.07.003
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Table 2 Reservoir fluid composition properties. Component
Flashed oil (mole %)
Flashed gas (mole %)
Reservoir oil (mole %)
N2 CO2 H2 S C1 C2 C3 iC 4 nC 4 iC 5 nC 5 C6 Cþ 7 GOR
0 0 0 0 0.02 0.34 0.23 1.03 0.88 1.24 6.87 89.39
0.2 4.56 4.71 64.64 10.43 6.43 1.25 3.2 1.24 1.52 1.28 0.54
0.14 3.23 3.33 45.74 7.39 4.65 0.95 2.57 1.14 1.44 2.91 26.51
1245 SCF/STB
100
Fig. 1. Perfect salinity diagram based on the viscosity and density (kg per cubic meter) at 15 C, which represents the linear trend of increasing density and viscosity with increasing absolute concentration.
Fig. 2. The first scenario based on a recovery factor versus time (days) in both high and low salinity with an injection rate of 1000 barrels per day in the early period.
900 psi, maximum water cut of 50% and maximum GOR of 1.2 are specified. In this case, the sensitivity analysis of the injected water salinity (high salinity and low salinity) is calculated. The results and documentation of the design are shown in Fig. 4.
closed automatically. Also, wellhead pressure of at least 900 psi and maximum water cut of 50% and a maximum GOR of 1.2 are specified. The results of this scenario are shown in Fig. 5. 3.5. Scenario 5
3.4. Scenario 4 In this scenario, compared to the previous scenarios with a natural driving mechanism of reservoir production, this design was done without water injection. From the beginning of production until the end of 2025, each well produces 4000 barrels per day, and the minimum production rate of 1000 barrels per day is considered. If the amount of production rate is less than this value, the well is
According to this design, the amount of 2000 barrels per day as the injection rate at the injection well No. 4 was considered. This injection quantity based on operational justification is also examined. In this scenario, to compare previous scenarios with density and viscosity defaulted in reservoir simulation program (pure water with a viscosity of 0.986 cP and density of 62.428 pounds per cubic foot), this injection rate of the early life of the reservoir from
Please cite this article as: Nassabeh, S.M.M et al., Simulation of low and high salinity water injection method to determine the optimum salinity, Petroleum Research, https://doi.org/10.1016/j.ptlrs.2019.07.003
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Fig. 3. The second scenario based on a recovery factor versus time (days) in both high and low salinity injection at a rate of 2000 barrels per day in the early period.
Fig. 4. The third scenario based on a recovery factor versus time (days) in both high and low salinity injection at a rate of 2000 barrels per day at the end of the period.
Fig. 5. The fourth scenario based on a recovery factor versus time (days) in natural depletion state.
2007 until the end of 2025 is considered. And before this date, wells have been produced in natural depletion state, and minimum production rate of 1000 barrels per day is considered, if the amount of production rate is less than this value, the well is closed automatically and also wellhead pressure of at least 900 psi and maximum water cut of 50% and maximum GOR of 1.2 are specified. The results of this scenario are shown in Fig. 6. 3.6. Scenario 6 In this scenario, compared to the previous scenarios with density and viscosity defaulted in reservoir simulation program in which viscosity was 0.986 cP, and density was assumed 62.428
pounds per cubic foot. Accordingly, this design of 1000 barrels per day is the injection rate at the injection well No.4, this injection rate from the early life of the reservoir from 2007 to the end of 2025 is considered. Before this date, wells have been produced in natural depletion state, and minimum production rate of 1000 barrels per day is considered, if the amount of production rate is less than this value, the well is closed automatically. Also, wellhead pressure of at least 900 psi, maximum water cut of 50% and maximum GOR of 1.2 are specified. The results of this scenario are shown in Fig. 7. Among different scenarios of water injection, Scenario 5, with an injection rate of 2000 barrels per day is the best-known injection plan, which has been shown in Fig. 8.
Please cite this article as: Nassabeh, S.M.M et al., Simulation of low and high salinity water injection method to determine the optimum salinity, Petroleum Research, https://doi.org/10.1016/j.ptlrs.2019.07.003
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Fig. 6. The fifth scenario based on a recovery factor versus time (days) at a rate of 2000 barrels per day in early injection.
Fig. 7. The sixth scenario based on a recovery factor versus time (days) at a rate of 1000 barrels per day in early injection.
Fig. 8. Various scenarios of water injection and natural depletion-mode.
4. Conclusions The following conclusions are; - Salinity in Scenario 2 shows low salinity, better support and performance efficiency and generally marginal recovery. - From examining various scenarios, if the water injection from the start of production and parallel to production is done.
- In a survey of injection rate, whatever the amount of water injection rate increase, accordingly, there will be a higher coefficient, of course, this matter depends on wellhead equipment details, safety factor and economic discussion. - By investigation of plots, low salinity levels in all injection scenarios and maximum production efficiency have the highest rate of recovery.
Please cite this article as: Nassabeh, S.M.M et al., Simulation of low and high salinity water injection method to determine the optimum salinity, Petroleum Research, https://doi.org/10.1016/j.ptlrs.2019.07.003
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- By passing the production time, the salinity difference between the top and bottom of the production well indicated an upward trend which reflects the increased salinity water injection. - Injecting pure high salinity water have a higher recovery factor than low salinity water injection. It is noteworthy that this matter shows the minimal difference in recovery factor between the two cases. This injection rate applies in both 1000 barrels per day and 2000 barrels per day (Scenario 5 and Scenario 6). References Akin, S., Kovscek, A., 1999. Imbibition studies of low-permeability porous media. In: SPE Western Regional Meeting. Society of Petroleum Engineers. Al-Shalabi, E.W., Sepehrnoori, K., 2016. A comprehensive review of low salinity/ engineered water injections and their applications in sandstone and carbonate rocks. J. Pet. Sci. Eng. 139, 137e161. Al-Shalabi, E.W., Sepehrnoori, K., Pope, G., 2015. Geochemical Interpretation of LowSalinity-Water Injection in Carbonate Oil Reservoirs SPE Journal 20:1, vol. 226, 212-211. Al-Shalabi, E.W., Luo, H., Delshad, M., Sepehrnoori, K., 2017. Single-well ChemicalTracer Modeling of Low-Salinity-Water Injection in Carbonates SPE Reservoir Evaluation & Engineering, vol. 20, pp. 118e133. AL-Shehri, A., Sagatov, E., Kovscek, A.R., 2009. Pore-level mechanics of forced and spontaneous imbibition of aqueous surfactant solutions in fractured porous media. In: SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers. AlHammadi, M., Mahzari, P., Sohrabi, M., 2018. Fundamental Investigation of Underlying Mechanisms behind Improved Oil Recovery by Low Salinity Water Injection in Carbonate Rocks Fuel, vol. 220, pp. 345e357. Alhuraishawy, A.K., Bai, B., Wei, M., Geng, J., Pu, J., 2018. Mineral dissolution and fine migration effect on oil recovery factor by low-salinity water flooding in lowpermeability sandstone reservoir. Fuel 220, 898e907. Arfaee, M.I.R., Sola, B.S., 2014. Investigating the effect of fractureematrix interaction in underground gas storage process at condensate naturally fractured reservoirs. J. Nat. Gas Sci. Eng. 19, 161e174. Armin Razmjoo, A., Sumper, A., Davarpanah, A., 2019. Energy Sustainability Analysis Based on SDGs for Developing Countries. Energy Sources, Part A Recovery, Util. Environ. Eff. 1e16. Bello, O., Perozo, N., Huseynov, P., Grijalva-Meza, O., Asgharzadeh, A., Holzmann, J., Oppelt, J., 2018. A simplified framework and performance analysis for whiledrilling telemetry systems in underbalanced drilling operations. Environ. Earth Sci. 77, 512. Bhowmik, S., Dutta, P., 2013. Adsorption rate characteristics of methane and CO2 in coal samples from Raniganj and Jharia coalfields of India. Int. J. Coal Geol. 113, 50e59. Boujelben, A., McDougall, S., Watson, M., Bondino, I., Agenet, N., 2018. Pore network modelling of low salinity water injection under unsteady-state flow conditions. J. Pet. Sci. Eng. 165, 462e476. Chen, Y., Xie, Q., Sari, A., Brady, P.V., Saeedi, A., 2018. Oil/water/rock wettability: influencing factors and implications for low salinity water flooding in carbonate reservoirs. Fuel 215, 171e177. Dang, C., Nghiem, L., Nguyen, N., Chen, Z., Nguyen, Q., 2016. Mechanistic modeling of low salinity water flooding. J. Pet. Sci. Eng. 146, 191e209. Davarpanah, A., 2018. A feasible visual investigation for associative foam >y polymer injectivity performances in the oil recovery enhancement European. Polym. J. 105, 405e411. https://doi.org/10.1016/j.eurpolymj.2018.06.017. Davarpanah, A., 2018. The feasible visual laboratory investigation of formate fluids on the rheological properties of a shale formation. Int. J. Environ. Sci. Technol. https://doi.org/10.1007/s13762-018-1877-6. Davarpanah, A., 2018. The integrated feasibility analysis of water reuse management in the petroleum exploration performances of unconventional shale reservoirs. Appl. Water Sci. 8, 75. https://doi.org/10.1007/s13201-018-0717-7. Davarpanah, A., 2018. A visual investigation of different pollutants on the rheological properties of sodium/potassium formate fluids. Appl. Water Sci. 8, 117. https://doi.org/10.1007/s13201-018-0762-2. Davarpanah, A., Mirshekari, B., 2018. A simulation study to control the oil production rate of oil-rim reservoir under different injectivity scenarios. Energy Rep. vol. 4, 664e670. https://doi.org/10.1016/j.egyr.2018.10.011. Davarpanah, A., Mirshekari, B., 2019. Experimental investigation and mathematical
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Petroleum Research journal homepage: http://www.keaipublishing.com/en/journals/ petroleum-research/
Simulation of low and high salinity water injection method to determine the optimum salinity Seyed Mohammad Mehdi Nassabeh a, Afshin Davarpanah b, *, Joata Bayrami a a b
Department of Petroleum Engineering, Faculty of Engineering and Technology, Omidiyeh Branch, Islamic Azad University, Omidiyeh, Iran Department of Petroleum Engineering, Science and Research Branch, Islamic Azad University, Tehran, Iran
a r t i c l e i n f o
a b s t r a c t
Article history: Received 16 December 2018 Received in revised form 25 July 2019 Accepted 31 July 2019 Available online xxx
Investigating the enhanced oil recovery leads to optimal production, protection and reduction of lateral impacts. Low salinity water injection (LSWI) is one of the significantly improved oil recovery (IOR) techniques for changing the amount of wettability in the carbonate fractured reservoirs. The utilization of this methodology in terms of high efficiency in displacing light crude oils to the medium-gravity crude oils, water sources availability and its sustainability for pushing the oil which leads to appropriate economic occasions, are being compared with other IOR/EOR techniques. In this study, the best injection modelling pattern is based on the highest rate of recovery factor. Comparison of “high and low salinity water injection method” with “pure water injection method” is performed in an oil reservoir. Overall, analyzing the sensitivity on the high and low salinity according to the moderately low recovery factor of high and low salinity among the injection scenarios illustrates the low sensitivity of this parameter on a fractured carbonate reservoir. By reviewing different scenarios, it could be demonstrated that if the water injection could be applied to the reservoir from the preliminary times of production, the recovery factor rate would be increased. Thereby, higher appropriate efficiency and better supplement have resulted. Pure water injection has a high recovery factor than salty water injection. By the way, these two methods have little differences in calculating recovery methods. Besides, this parameter is significantly depended on wellhead equipment properties, safety factor and economic issues (water production). © 2019 Chinese Petroleum Society. Publishing Services by Elsevier B.V. on behalf of KeAi. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
Keywords: Low salinity water injection Enhance oil recovery Injection scenarios Oil recovery factor Water production
1. Introduction Due to the increasing demand for crude oil consumption for different energy sections, it seems that these non-renewable resources should be optimally used, but also survival of future generations has been facing a severe crisis (Davarpanah 2018a, 2018c; Razmjoo and Davarpanah, 2019; Razmjoo et al., 2019; Shirmohammadi and Gilani, 2018). As it is evident, regarding the non-recoverable parts of fossil fuels which are considered as the large volumes in hydrocarbon reservoirs, it is necessary to administer enhanced oil recovery techniques to produce the remained oil and gas (Al-Shalabi et al., 2015; Valizadeh and Davarpanah, 2019; Vikara et al., 2019; Zarei et al., 2019). Porous and permeable underground structural hydrocarbon reservoir is a natural accumulation of hydrocarbons in a liquid or gas in its place by isolation of non-permeable rocks from the surrounding environment (Al-
* Corresponding author. E-mail address: [email protected] (A. Davarpanah).
Shalabi and Sepehrnoori, 2016; Davarpanah et al. 2019a, 2019b; Davarpanah and Mirshekari, 2018; Lewandowska-Smierzchalska et al., 2018; Zhang et al., 2018). In the more concrete description, hydrocarbon reservoirs can be likened to kite filled with air, and the shell of this kite plays the role of non-permeable rocks. Upon piercing the balanced environment, reservoir fluids by hydraulic forces are driven into a well. The power of this natural drift is reduced along with the production of the reservoir (Akin and Kovscek 1999; AL-Shehri et al., 2009; Arfaee and Sola, 2014; Armin Razmjoo et al., 2019; Davarpanah and Mirshekari, 2019b; Davarpanah and Mirshekari, 2019c; Davarpanah and Mirshekari, 2019d; Teklu et al., 2016). General information such as the total amount of oil in place, oil layers, depth of oil layer and other parameters in the production stage are of significance (Bello et al., 2018; Bhowmik and Dutta, 2013; Boujelben et al., 2018; Davarpanah 2018b, 2018d). According to the original plan, each reservoir in the early stage and the final stage of production is determined and affected (Chen et al., 2018; Dang et al., 2016; Davarpanah and Mirshekari, 2019a; Davarpanah et al. 2018a, 2019c). As is known, Iranian reservoirs
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have an average of 8e10 percent natural decline in reservoir pressure and the production rate for wells (wells with low reservoir pressure drop is directly related to production rate). With the continuous drop in reservoir pressure, the production rate gradually reduces until the normal production of the reservoir will not be cost-effective. This point occurs when the oil recovery from the reservoir is relatively low. This recovery for Iranian reservoirs is about 15e20 percent; in other words, 80 to 85 percent of the oil remains in the formation (Al-Shalabi et al., 2017; Davarpanah et al. 2018c, 2019d; Ebadati et al., 2018; Torrijos et al., 2016). Large amounts of oil in the world in the Middle East from Syria to Oman in the carbonate reservoirs with low permeability are nonhydrophilic. Some of the reservoirs are entirely fractured, and some usually are and non-fractured that various periods of heavy oil to light oil with different combinations are included (AlHammadi et al. 2018; Alhuraishawy et al., 2018; Davarpanah et al., 2018b). Naturally, fractured carbonate reservoirs contain significant volumes of oil in different areas of the world. In Iran, about 30 percent of such reservoirs, which means billions of barrels of oil are available. These fractured and non-fractured reservoirs by natural forces such as the water drive or water injection applications are in oil production, but the efficiency is very low (Chen et al., 2018; Puntervold et al., 2018). 2. Simulation procedure Iran's oil reservoir is located in the southwest and was put into operation in 1999; the reservoir is an anticline that its reservoir is Asmari carbonate with Gachsaran cap rock. Based on field reports, the reservoir is fractured and saturated and has three phases of oil, water and gas. The first well of this reservoir was drilled in 1999 that with a maximum production of 3000 barrels per day production and was closed in late 2003 due to operational issues. Two other wells (wells 2 and 3) had been excavated in 2000 and reached the maximum production of 3000 barrels a day until 2007. In total, three wells in the reservoir had been drilled, among which, two wells were vertical wells, and one well was horizontal well. By 2007, the cumulative oil rate was approximately 15.228 million barrels, and the daily production is 6000 barrels per day. According to reports, the initial pressure is 4100 psi at a depth of 900 feet. Despite the oil leak because the connection between the band gap and oil reservoir, the fractured reservoir can be confirmed. The water-oil contact is at a depth of 1950 feet, and the gas-oil contact is at a depth of 600 feet. Reservoir rock properties are provided in Table 1. Moreover, reservoir fluid composition properties are explained in Table 2. 3. Results and discussion The economic output of the reservoir of this parameter plays an
Table 1 Reservoir rock properties. Sampling data
Date
5/12/1998
Sampling depth Sampling flowing pressure Reservoir pressure Reservoir temperature Test temperature Bubble point pressure Bo @ Pb The density of total gas evolved @S.C Density of stock tank @S.C The density of reservoir fluid @Pb GOR @S.C
Feet Psia Psia C ℉ Psia rb/STB g/lit g/cc g/cc SCF/STB
1200 1760 4350 175 180 3715 1.6822 1.1761 0.8575 0.6636 1230.22
important role, and whatever water cut rate is less the production efficiency has played a positive effect, if the water cut is higher than a certain extent, so it causes the closing of the production well. To investigate the impact of salinity. Six different scenarios are defined based on the analysis of varying salinity. However, scenarios 1, 2, and three focus on the effects of salinity on the oil recovery factor, scenarios 4, 5 and 6 is based on the comparison of natural depletion. Moreover, the low salinity of 5 gr/kg (density, 1005 kg per cubic meter and 1.15 cP at 15 C) and the high salinity of 40 gr/kg (density 1030 kg per cubic meter and viscosity, 1.23 at 15 C) are assumed. 3.1. Scenario 1 According to the simulation procedure, the injection well No. 4 was selected at the injection rate of 1000 barrels per day. Of course, this rate was based on a possible operational rate and the tolerable amount of pressure wellhead equipment, and the injection pump was selected. In this scenario, the injection rate is 1000 barrels per day; a complete analysis of low and high salinity was performed. Since the salinity of the water effect on viscosity and density, and this parameter is the fundamental parameter in the reservoir simulation model especially in the analysis of the injected water salinity changes on the rate of recovery factor, the absolute salinity curve based on the viscosity and density at 15 C which is depicted in Fig. 1. Through studying the low and high salinity rate, an injection with the maximum rate of recovery factor was done. This injection rate from the beginning of the life of the reservoir in 2007 was taken into account and will be predicted and simulated by the end of 2025. Before 2007, well-acted as a natural depletion, the minimum production rate of 1000 barrels per day was considered. If the produced quantity is less than this value, the well is closed automatically. The results of the flooding are illustrated in Fig. 2. 3.2. Scenario 2 According to the design, to higher efficiency (recovery factor), the rate of 2000 barrels per day in the injection well No.4 is considered that injected amount based on operational justifications have been studied and selected. However, it should be noted that the higher injection rate, the higher reservoir recovery factor. But due to wellhead equipment, other parameters mentioned in the previous section were defined and studied in 2000. In this scenario, to increase recovery factor, production rate from 2007 until the end of 2025 was considered. And before this date, the natural depletion has been produced, and the minimum production rate of 1000 barrels per day is considered. If the amount of production is less than this value, the well is closed automatically. Also, minimum wellhead pressure of 900 psi, maximum water cut of 50% and maximum GOR of 1.2 are specified. In this case, the sensitivity analysis of the injected water salinity (high salinity and low salinity) is calculated. The results and documentation of the design are shown in Fig. 3. 3.3. Scenario 3 According to this design, to higher efficiency (recovery factor), the rate of 2000 barrels per day as an injection rate into the injection well No.4 is considered. In this scenario results of low and high salinity scenario from 2017 until the end of 2025 were reviewed. And before this date, as the natural depletion has been produced, the minimum production rate of 1000 barrels per day is considered. If the amount of production is less than this value, the well is closed automatically. Also, minimum wellhead pressure of
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Table 2 Reservoir fluid composition properties. Component
Flashed oil (mole %)
Flashed gas (mole %)
Reservoir oil (mole %)
N2 CO2 H2 S C1 C2 C3 iC 4 nC 4 iC 5 nC 5 C6 Cþ 7 GOR
0 0 0 0 0.02 0.34 0.23 1.03 0.88 1.24 6.87 89.39
0.2 4.56 4.71 64.64 10.43 6.43 1.25 3.2 1.24 1.52 1.28 0.54
0.14 3.23 3.33 45.74 7.39 4.65 0.95 2.57 1.14 1.44 2.91 26.51
1245 SCF/STB
100
Fig. 1. Perfect salinity diagram based on the viscosity and density (kg per cubic meter) at 15 C, which represents the linear trend of increasing density and viscosity with increasing absolute concentration.
Fig. 2. The first scenario based on a recovery factor versus time (days) in both high and low salinity with an injection rate of 1000 barrels per day in the early period.
900 psi, maximum water cut of 50% and maximum GOR of 1.2 are specified. In this case, the sensitivity analysis of the injected water salinity (high salinity and low salinity) is calculated. The results and documentation of the design are shown in Fig. 4.
closed automatically. Also, wellhead pressure of at least 900 psi and maximum water cut of 50% and a maximum GOR of 1.2 are specified. The results of this scenario are shown in Fig. 5. 3.5. Scenario 5
3.4. Scenario 4 In this scenario, compared to the previous scenarios with a natural driving mechanism of reservoir production, this design was done without water injection. From the beginning of production until the end of 2025, each well produces 4000 barrels per day, and the minimum production rate of 1000 barrels per day is considered. If the amount of production rate is less than this value, the well is
According to this design, the amount of 2000 barrels per day as the injection rate at the injection well No. 4 was considered. This injection quantity based on operational justification is also examined. In this scenario, to compare previous scenarios with density and viscosity defaulted in reservoir simulation program (pure water with a viscosity of 0.986 cP and density of 62.428 pounds per cubic foot), this injection rate of the early life of the reservoir from
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Fig. 3. The second scenario based on a recovery factor versus time (days) in both high and low salinity injection at a rate of 2000 barrels per day in the early period.
Fig. 4. The third scenario based on a recovery factor versus time (days) in both high and low salinity injection at a rate of 2000 barrels per day at the end of the period.
Fig. 5. The fourth scenario based on a recovery factor versus time (days) in natural depletion state.
2007 until the end of 2025 is considered. And before this date, wells have been produced in natural depletion state, and minimum production rate of 1000 barrels per day is considered, if the amount of production rate is less than this value, the well is closed automatically and also wellhead pressure of at least 900 psi and maximum water cut of 50% and maximum GOR of 1.2 are specified. The results of this scenario are shown in Fig. 6. 3.6. Scenario 6 In this scenario, compared to the previous scenarios with density and viscosity defaulted in reservoir simulation program in which viscosity was 0.986 cP, and density was assumed 62.428
pounds per cubic foot. Accordingly, this design of 1000 barrels per day is the injection rate at the injection well No.4, this injection rate from the early life of the reservoir from 2007 to the end of 2025 is considered. Before this date, wells have been produced in natural depletion state, and minimum production rate of 1000 barrels per day is considered, if the amount of production rate is less than this value, the well is closed automatically. Also, wellhead pressure of at least 900 psi, maximum water cut of 50% and maximum GOR of 1.2 are specified. The results of this scenario are shown in Fig. 7. Among different scenarios of water injection, Scenario 5, with an injection rate of 2000 barrels per day is the best-known injection plan, which has been shown in Fig. 8.
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Fig. 6. The fifth scenario based on a recovery factor versus time (days) at a rate of 2000 barrels per day in early injection.
Fig. 7. The sixth scenario based on a recovery factor versus time (days) at a rate of 1000 barrels per day in early injection.
Fig. 8. Various scenarios of water injection and natural depletion-mode.
4. Conclusions The following conclusions are; - Salinity in Scenario 2 shows low salinity, better support and performance efficiency and generally marginal recovery. - From examining various scenarios, if the water injection from the start of production and parallel to production is done.
- In a survey of injection rate, whatever the amount of water injection rate increase, accordingly, there will be a higher coefficient, of course, this matter depends on wellhead equipment details, safety factor and economic discussion. - By investigation of plots, low salinity levels in all injection scenarios and maximum production efficiency have the highest rate of recovery.
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Please cite this article as: Nassabeh, S.M.M et al., Simulation of low and high salinity water injection method to determine the optimum salinity, Petroleum Research, https://doi.org/10.1016/j.ptlrs.2019.07.003