Effects of Water and Gas Injection Rates in WAG Flooding for a Heterogeneous Oil Reservoir: A Simulation Study

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The technique was applied as a secondary recovery process and a heterogeneous reservoir model was used. The aim of the study is to determine the optimum injection rate of water and CO 2 as well as the trend of oil recovery with varying injection rates. The dimension of the model is 5000 ft x 5000 ft x 120 ft which was divided into 20 x 20 x 7 grid blocks. The STOOIP is 68 MMSTB. Primary recovery from the reservoir was 15% of STOOIP. 5 spot injection pattern was used for this study. Water flooding when used as the secondary recovery technique produced 38% of the STOOIP. WAG flooding using WAG ratio of 1:1, 2:3 and 3:2 each produced 41.5%, 44% and 39.5% of STOOIP respectively. WAG proved to be the better secondary recovery technique with WAG ratio of 2:3 being the optimum WAG ratio. Oil recovery factor increases with the injection rate of gas and water until the optimum injection rate and then the recovery starts to decline. The optimum injection rate for water is in the range of 2000 to 2500 STB/D while for CO 2 is about 2500 to 3000 MSCF/D. The effect of heterogeneity was felt during this simulation as oil in the low permeability layers could not be produced easily. The results of this study are good indication of the future of WAG as a secondary recovery technique. Technical viability and economic feasibility of WAG should be studied intensively while other WAG parameters should be optimized. This study strongly suggests the use of WAG as the secondary recovery technique whenever the situation permits. Figures Figure 1 Figure 2 Figure 3 Figure 4 Figure 5 Figure 6 Figure 7 Figure 8 INTRODUCTION Water Alternate Gas or WAG flooding is being used extensively in the field application as an Enhanced Oil Recovery Technique in many parts of the world especially in the United States. Use of WAG as a secondary technique is currently under experimentation. Currently, water flooding and gas injection are being used as secondary recovery techniques but oil recovery utilizing these methods is not satisfactory. High mobility ratio and trapped oil in the reservoir phenomenon is observed with these methods. Gravity segregation and viscous fingering are the main mechanisms behind these phenomenons. Injection rates of water and gas as well as the WAG ratio are two of the main parameters which effects WAG recovery. However, heterogeneity of the formation complicates the optimization process of WAG flooding. It is important to define the relationship of oil recovery and WAG ratio as well as gas and water injection rates. High water and gas injection rate leads to early breakthrough of water and gas respectively. This reduces oil recovery significantly. Low injection rates meanwhile leads to gravity segregation as well as low productivity which is very much undesired. So, this together with the heterogeneity of the formation problem leads to lower oil recovery than expected. This problem can only be dealt with by detailed study on WAG ratio and injection rates of water and gas. The aim of this study is to define a relationship between injection rate of water and gas with oil recovery. Then, the relationship of WAG ratio with oil recovery factor will be studied. Range of optimum water and gas injection rates will be the other output of this study. Finally WAG flooding as a secondary recovery technique will be compared with water flooding in terms of oil recovery. This study would be conducted in Eclipse 100 (black oil simulator) utilizing a heterogeneous reservoir model. Studied water injection rates are in the range from 1500 STB/D to 2500 STB/D while gas injection rates are in the range of 1000 MSCF/D to 4000 MSCF/D. three different WAG ratios will be considered which are 1:1, 2:3 and 3:2. Slug size would be kept constant for all the runs. As a conclusion, this study is aimed at solving the problems related to optimization of WAG design parameters in the field application today. By doing this, the oil reserve could be increased significantly and keep the energy crisis at the bay for the moment. METHODOLOGY Reservoir Model Figure 1 shows the reservoir model utilized for this study. As it can be seen, there are 3 layers. The permeabilities of the layers are 10 mD, 100 mD and 1 mD respectively. The total thickness of the reservoir model is 120 ft with an areal extent of 530 acres. Injection Pattern A 5 spot injection pattern such as the one shown in Fig. 2 was utilized to flood this reservoir model. This term refers to 4 injection wells surrounding any one production well. There will be a total of 4 sets of this 5 spot injection pattern because there are 4 producing wells in this reservoir. Reservoir Properties Basically, this is a sandstone oil reservoir with a porosity value of 0.20 and initial reservoir pressure of 2800 Psia. The datum of the reservoir is at 5010 ft. The main reservoir properties are listed in the Table 1 . Reservoir Fluid Properties The API gravity of the oil is 43.3 while the gas specific gravity is 0.65. Other reservoir fluid parameters are summarized in the Table 2 . Simulation Model The reservoir model was divided into 20 x 20 x 7 grid blocks. The simulation model was validated by comparing the Stock Tank Oil Originally In Place or STOOIP obtained from the simulator with manual calculation using material balance. Base Case The base case run was done for three main purposes. First, to determine the beginning of the injection time and the second is to obtain the oil recovery factor through primary depletion. The final purpose is to justify the simulation model by comparing the STOOIP obtained through simulation and manual calculation. Solution gas drive and water drive are the main drives of this reservoir. Water Flooding Water flooding run serves as a comparison study to compare oil recovery factor using WAG and water flooding as the secondary technique. The density of the water used in the injection process is 62.4 lb/cuft and the salinity is 3%. The injection rate used is 2000 STB/D as this value is the typical injection rate value used in the field application nowadays. The reservoir is water flooded for 23 years after primary recovery. Table 1 Reservoir Properties Area (Acres) 530 Gas Oil Contact, GOC (ft) 5010 Oil Water Contact, OWC (ft) 5130 Datum Depth (feet) 5010 Initial Pressure at Datum (psia) 2800 Bubble Point (psia) 2500 Reservoir Temperature (°F) 230 Porosity (Fraction) 0.30 Initial Water Saturation 0.20 Standard Temperature (°F) 60 Standard Pressure (Psia) 14.7 WAG Flooding A total of 135 runs were conducted to study the WAG flooding process. There are a total of 5 different water injection rates and 9 different gas injection rates with 3 different WAG ratios. The slug size is set constant at 0.5% of Hydrocarbon Pore Volume or HCPV for all runs. Table 3 summarizes the injection fluid properties and the water and gas injection rates utilized in this study. Table 2 Reservoir Fluid Properties API Gravity, degrees 43.3 Oil Volumetric factor (RB/STB) 1.26 Oil Viscosity (cp) 0.64 Salt Concentration Weight (%) 3 Gas Specific Gravity 0.65 Water Density (lb/cuft) 62.4 Gas Formation Volume Factor (Rescuft/SCF) 0.0063 Table 3 WAG Flooding and Injection Fluid Properties Water Density (lb/cuft) 62.40 CO 2 Density (lb/cuft) 30.00 Water Viscosity (cP) 0.31 CO 2 Viscosity (cP) 0.041 Water injection rate (STB/day) 1500, 1700, 2000, 2300, 2500 CO 2 injection rate (MMSCF/day) 1000, 1500, 2000, 2200, 2500, 2700, 3000, 3500 and 4000 WAG Ratio (W : G) 1:1, 2:3, 3:2 Slug Size per cycle 0.5% HCPV RESULTS AND DISCUSSION Simulation Model Validation The simulation model created was verified by comparing the STOOIP obtained from simulation and material balance calculation performed manually. Manual calculation resulted in an STOOIP value of 72 MMSTB as shown in Table 4 . STOOIP value from simulation model suggested an STOOIP value of 68 MMSTB which is almost same. This validates this model. Table 3 Stock Tank Oil Originally In Place Layer Oil In Place (MMSTB) 1 36 2 12 3 24 Total 72 Base Case Study Base case run refers to production of oil through natural drive mechanisms of the reservoir. The base case production rate is shown in the Fig. 3 . Production of the reservoir is at 4000 STB/D. Production starts to decline in the 7th year which is the point where injection is required. Recovery from the primary stage is 15% from STOOIP or 10.2 MMSTB. Figure 4 meanwhile depicts the reservoir pressure during the primary recovery. This is important in order to verify that the reservoir pressure is higher than the Minimum Miscibility Pressure or MMP of Carbon Dioxide which is approximately 1600 psia. The reason for this is to establish a miscible WAG injection process. This refers to the mechanism where CO 2 becomes miscible in the oil bank. Miscible WAG gives a better recovery compared to immiscible WAG. As it can be seen, at the 7th year where injection is due to take place, reservoir pressure is approximately 1700 psia which is well above the MMP of CO 2 . Water Flooding Study Figure 5 shows the cumulative oil recovery utilizing water flooding as the secondary recovery technique. After 30 years, recovery from water flooding is 27 MMSTB or 38% of STOOIP which is an increment of 23% from primary recovery. WAG Flooding – WAG Ratio 1:1 Figure 6 shows the cumulative oil recovery for WAG flooding utilizing WAG ratio of 1:1 with various combinations of injection rates. WAG ratio here refers to ratio of water slug size to CO 2 slug size. As it can be seen, recovery factor of oil increases with water and gas injection rate until an optimum point, than it starts to decline. The optimum injection rate range is from 2300–2500 STB/D for water and 2500–3000 MSCF/D for CO 2 . Recovery using this optimum injection rates after 30 years is approximately 42% of STOOIP which is an increment of 27% from primary recovery. WAG Flooding – WAG Ratio 2:3 Figure 7 shows the cumulative oil recovery for WAG flooding utilizing WAG ratio of 2:3 with various combinations of injection rates. Again, recovery factor of oil increases with water and gas injection rate until an optimum point, than it starts to decline. The optimum injection rate range is from 2000–2300 STB/D for water and 2500–3000 MSCF/D for CO 2 . Recovery using this optimum injection rates after 30 years is approximately 44% of STOOIP which is an increment of 29% from primary recovery. WAG Flooding – WAG Ratio 3:2 The final WAG ratio of 3:2 provided a somewhat similar result as shown in Fig. 8 . Still, recovery factor of oil increases with water and gas injection rate until an optimum point, than it starts to decline. The optimum injection rate range is from 2000–2300 STB/D for water and 2500–3000 MSCF/D for CO 2 . Recovery using this optimum injection rates after 30 years is approximately 40% of STOOIP which is an increment of 25% from primary recovery. So far, this is the worst recovery factor in terms of WAG flooding but still then it is better than water flooding. Comparison Between Studied WAG Ratios WAG ratio of 2:3 gives the highest recovery of 44% of STOOIP followed by WAG ratio of 1:1 at 42% and WAG ratio of 3:2 at 40% (the poorest recovery) of STOOIP. However, economic evaluation is necessary to investigate the truth of this fact. It might be feasible technically but not economically. Economic evaluation is beyond the scope of this study. Comparison Between WAG Flooding and Water Flooding All the 3 WAG ratios studied gives a higher oil recovery compared to that of water flooding. Recovery from water flooding as mentioned earlier is 38% of STOOIP. The differences between water flooding and WAG flooding are then 4%, 6% and 2% respectively for WAG ratio of 1:1, 2:3 and 3:2. Again, this is only a technical evaluation where economic considerations are necessary. It is important to take in account of the pumping facilities involved, availability of CO 2 and price of CO 2 which is again beyond the scope of this study. The differences in recovery factor might not be much compared to the complications involved with WAG especially in small fields. Effect of Water Injection Rate on Recovery Factor Low water injection rate leads to a higher ultimate oil recovery but low injection rate of water is accompanied with low oil production rate. Generally speaking, this is in most case very uneconomic. Another phenomenon related to low water injection rate is gravity segregation where water sweeps only the lower portion of the reservoir due to its higher density. The desired piston like displacement is then unachievable. Increasing injection rate will increase the reservoir pressure forcing free gas to go into solution. This will reduce the relative permeability of gas and which in hand increases the relative permeability of oil. This contributes to the faster production of oil. Once increasing injection rates have increased the reservoir pressure high enough to force all the gas into solution, increasing injection rate any further is of no use. High water injection rate meanwhile leads to early water breakthrough due to phenomena as viscous fingering or water override. This greatly reduces oil production because injected water bypasses oil and thus oil remains trapped in the reservoir. High water production poses many economic and technical problems such as water treatment cost. Optimum water injection rate shows a piston like displacement of the oil bank. Gravity segregation is negligible while water breakthrough is not due to happen very soon. Effect of Gas Injection Rate on Recovery Factor Heterogeneity and injection rates play an important role in affecting oil recovery and gas breakthrough. When gas injection rate is very high, an early gas breakthrough problem is encountered. This happens due to viscous fingering of gas through high permeability streaks. Injected CO 2 will selectively travel through higher permeability layers. This effect is more dominant in a heterogeneous reservoir such as the one used in this study. However, since water is being injected subsequently, viscous fingering is controlled to a certain extend. This is because water enters the higher permeability layers and forces gas to travel through the lower permeability layers. Besides, the injected water covers the lower portion of the reservoir which is not swept by gas due to gravity segregation. At low injection rate of gas, gravity segregation occurs in the reservoir where the low density CO 2 sweeps through the upper portion of the reservoir. This causes the oil in the lower portion to be bypassed. So, high injection rate promises higher recovery factor only until a certain extend. After this extend, the recovery factor will be lower than the process using lower injection rate. This is exactly what is proven by this study. CO 2 utilization is also high at a high injection rate. Early gas breakthrough also yields higher Gas Oil Ratio or GOR. It is important to note that most countries have set a maximum limit for the GOR. Finally, it is also important to note that there are limitations of injection rates that could be applied in the field. For example, the tubing size, pumping capacity and formation fracture gradient are among some considerations. Low injection rate meanwhile gives a better sweep. This is mainly because the injected gas has more time to be in the miscible phase with the oil. Oil swelling and viscosity reduction is the two main advantage of using a miscible flood. This process will improve recovery factor. However, we must remember that the production rate of oil will be lower if we use a low injection rate. Low production rate is weak as far as production economic is concerned. Anyway, CO 2 utilization is lower at a lower injection rate. So, injection rate of CO 2 should be optimized before the start of injection. Two main factors to be considered are the economic feasibility and the technical viability of the injection rate. Effect of WAG Ratio on Recovery Factor Many studies have cited that higher WAG ratio contributes to higher oil recovery but this is not the case in a tight heterogeneous reservoir as this. This is because the thickness of the low permeability layers is about 100 ft compared to the total thickness which is 120 ft as shown in Fig. 1 . Thus, water sweeps the high permeability (100 mD) layer, forcing CO 2 to sweep the low permeability layers. Due to the thick low permeability layer, bigger gas slug size leads to a higher oil recovery. This fact is supported by this study when WAG ratio of 2:3 gives highest recovery compared to WAG ratio of 1:1 or 3:2. Effects of Heterogeneity on Recovery Factor Heterogeneity affects the oil recovery factor by various mechanisms. This is one of the primary reasons why every reservoir is treated uniquely. Homogeneous reservoir is more of an imaginary reservoir as it doesn’t exist in this world. The low permeability layers, 1 mD and 10 mD is the main culprit which causes low recovery factor from the water flooding technique. Injected water will selectively channel through the high permeability layer (100 mD). This will cause the oil in the other 2 layers to be bypassed. The same phenomenon will also occur if gas flooding is used. Injected gas will channel through the high permeability streaks and bypass the lower permeability layers. Besides, gravity segregation will cause gas to sweep only the upper portion of the reservoir. However by using WAG technique, this fingering and gravity segregation effect could be controlled. Injected CO 2 will be forced to enter the lower permeability layers by water which is injected subsequently. Water will sweep the lower portion of the reservoir while gas will sweep the upper portion of the reservoir. So, as the heterogeneity of the reservoir increases, the amount of oil bypassed increases too. WAG flooding is a better technique to overcome this problem and increase the recovery of oil compared to water or gas flooding alone. CONCLUSION The conclusion of the results of this study is tabulated in the Table 4 . As we can see, the optimum WAG ratio among the three studied WAG ratios would be WAG ratio 2:3. It yields 44% of STOOIP. The recovery from water flooding technique is only 38%. This shows that WAG flooding is a better technique to be used in the field application. Primary recovery from reservoir depletion is only 15%. The conclusion for the injection rate study suggests that the optimum injection rate for water lies in the range of 2000 STB/D to 2500 STB/D while the optimum injection rate for CO 2 lies in the range of 2500 MSCF/D to 3000 MSCF/D. Oil recovery factor increases both when the injection rate of CO 2 or water increases until a certain point where the recovery starts to decline again. Heterogeneity is a major factor which affects the recovery factor of oil and low WAG ratios are suitable for a heterogeneous reservoir which contains low permeability layers. Table 4 Summary of WAG Flooding Results WAG Ratio Optimum Water Injection Rate, (STB/D) Optimum Gas Injection Rate, (MSCF/D) Recovery Factor Utilizing Optimum Injection Rates 1:1 2300–2500 2500–3000 42% 2:3 2000–2300 2500–3000 44% 3:2 2000–2300 2500–3000 40% RECOMMENDATIONS This study could be greatly enhanced by detailed study on other related parameters of WAG as wells as reservoir conditions used. Following are a few recommendations for future study. An economic model should be created to analyze the economics of WAG flooding as a secondary recovery technique. Increase the number of slug size used as slug size was set constant for this study. Increase the heterogeneity of the formation with more permeability streaks and also compare with recovery from homogeneous formation. Only 3 WAG ratios were used for this study. The number of WAG ratios studied could be increased utilizing WAG ratios such as 1:2, 2:1, 4:1 and 1:4. Compare the technical viability and economic feasibility of WAG as secondary recovery technique as compared to WAG flooding as a tertiary recovery technique. Compare the oil recovery from simple WAG and Simultaneous Water Alternate Gas or SWAG flooding. WAG tapering is a process where the injection rate of water and gas is varied throughout the WAG flooding period whenever necessary, in order to increase oil recover. The effectiveness of this process as compared to simple WAG could be studied upon. CO 2 is used as the injection gas in this study due to its lower MMP. The efficiency of other gases such as hydrocarbon gas and nitrogen gas could be compared. NOMENCLATURES CO 2 Carbon dioxide Ft Feet GOC Gas Oil Contact GOR Gas Oil Ratio HCPV Hydrocarbon Pore Volume lb/cuft Pound per cubic feet mD miliDarcy MMP Minimum Miscibility Pressure OWC Oil Water Contact psia Pound per square inch (absolute) RB Reservoir barrel SCF/D Standard cubic feet per day STB Stock Tank Barrel STOOIP Stock Tank Oil Originally In Place SWAG Simultaneous Water Alternate Gas WAG Water Alternate Gas Declarations Author Contribution Conceptualization: S.R.H.J.Methodology: S.R.H.J.Investigation: S.R.H.J.Data Curation: S.R.H.J.Formal Analysis: S.R.H.J.Visualization: S.R.H.J.Writing – Original Draft: S.R.H.J., S.A.Writing – Review & Editing: S.R.H.J., S.A., M.J.Supervision: M.J.Project Administration: S.R.H.J.All authors contributed to the review and editing of the manuscript, approved the final version and agreed to be accountable for all aspects of the work. ACKNOWLEDGEMENTS The author would like to express his gratitude to PM Abdul Aziz Bin Hussin for his guidance and support. References Attanuci, V., Aslesen, K.S., Hejl, K.L., Wright, C.A. (1993). “WAG Process Optimization in the Rangely CO 2 Miscible Flood.” SPE 26622 Blackwell, R.J. (1980). ”Miscible Displacement: Its Status and Potential for Enhanced Oil Recovery.” SPE 10014 Christensen, R., Stenby, E., Skauge, A. (1998). “Review of WAG Field Experience.” SPE 39833 Christie, M.A., Muggeridge, A.H., Barley, J.J. (1993). “3D Simulation of Viscous Fingering and WAG Schemes.” SPE 21238 Crogh, N.A., Eide, K., Morterud, S.E. (2002). “WAG Injection at the Statfjord Field, A Success Story.” SPE 78348 Cullick, A.S., Lu, H.S., Jones, L.G., Cohen, M.F., Watson, J.P. (1993). “WAG May Improve Gas-Condensate Recovery.” SPE 19114 Dyer, S.B., Farouq, Ali S.M. (1994). “Linear Model Studies of the Immiscible CO 2 WAG Process for Heavy Oil Recovery.” SPE 21162 Genrich, J.F. 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(1996). “Determination of Relative Permeability and Trapped Gas Saturation for Predictions of WAG Performance in the South Cowden CO 2 Flood.” SPE 35429 Yamamoto, J., Satoh, T., Ishii, H., Okatsu, K. (1997). “An Analysis of CO 2 WAG Coreflood by Use of X-Ray CT.” SPE 38068 Zain, Z.M., Kechut, N.I., Nadeson, G., Ahmad, N. (2001). “Evaluation of CO 2 Gas Injection for Major Oil Production Fields in Malaysia.” SPE 72106 Additional Declarations No competing interests reported. Cite Share Download PDF Status: Posted Version 1 posted You are reading this latest preprint version Research Square lets you share your work early, gain feedback from the community, and start making changes to your manuscript prior to peer review in a journal. As a division of Research Square Company, we’re committed to making research communication faster, fairer, and more useful. We do this by developing innovative software and high quality services for the global research community. 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Also discoverable on Platform About Our Team In Review Editorial Policies Advisory Board Help Center Resources Author Services Accessibility API Access RSS feed Manage Cookie Preferences © Research Square 2026 | ISSN 2693-5015 (online) Privacy Policy Terms of Service Do Not Sell My Personal Information {"props":{"pageProps":{"initialData":{"identity":"rs-7179572","acceptedTermsAndConditions":true,"allowDirectSubmit":true,"archivedVersions":[],"articleType":"Research Article","associatedPublications":[],"authors":[{"id":496300380,"identity":"20fe7872-5f7e-46ee-af96-f6f55d545943","order_by":0,"name":"Syed Rafay Hussain Jafri","email":"","orcid":"","institution":"National University of Sciences and Technology","correspondingAuthor":false,"prefix":"","firstName":"Syed","middleName":"Rafay Hussain","lastName":"Jafri","suffix":""},{"id":496300381,"identity":"df1079eb-6291-45e6-be29-78b0f8f97f4c","order_by":1,"name":"Moulishree Joshi","email":"","orcid":"","institution":"University of 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16:38:16","currentVersionCode":1,"declarations":"","doi":"10.21203/rs.3.rs-7179572/v1","doiUrl":"https://doi.org/10.21203/rs.3.rs-7179572/v1","draftVersion":[],"editorialEvents":[],"editorialNote":"","failedWorkflow":false,"files":[{"id":88622378,"identity":"11bb6079-396f-404a-846b-a735e769bae3","added_by":"auto","created_at":"2025-08-08 12:15:22","extension":"jpg","order_by":1,"title":"Figure 1","display":"","copyAsset":false,"role":"figure","size":55409,"visible":true,"origin":"","legend":"\u003cp\u003e\u003cstrong\u003eReservoir Model\u003c/strong\u003e\u003c/p\u003e","description":"","filename":"1.jpg","url":"https://assets-eu.researchsquare.com/files/rs-7179572/v1/df9793b7951791b413617058.jpg"},{"id":88622379,"identity":"1815814a-232f-4483-a74a-ec0be6379d89","added_by":"auto","created_at":"2025-08-08 12:15:22","extension":"jpg","order_by":2,"title":"Figure 2","display":"","copyAsset":false,"role":"figure","size":34118,"visible":true,"origin":"","legend":"\u003cp\u003e\u003cstrong\u003ePlan View of the Reservoir Model Showing the 5 Spot Injection Pattern\u003c/strong\u003e\u003c/p\u003e","description":"","filename":"2.jpg","url":"https://assets-eu.researchsquare.com/files/rs-7179572/v1/06d581a63687896ceba0ee58.jpg"},{"id":88622392,"identity":"e50f58b1-4a54-4c0f-9981-f463c352eae3","added_by":"auto","created_at":"2025-08-08 12:15:23","extension":"jpg","order_by":3,"title":"Figure 3","display":"","copyAsset":false,"role":"figure","size":120953,"visible":true,"origin":"","legend":"\u003cp\u003e\u003cstrong\u003eBase Case Production Rate\u003c/strong\u003e\u003c/p\u003e","description":"","filename":"3.jpg","url":"https://assets-eu.researchsquare.com/files/rs-7179572/v1/553099c3fe729426faaf76cd.jpg"},{"id":88622410,"identity":"1d97830b-2a7a-487d-92a7-720d05633939","added_by":"auto","created_at":"2025-08-08 12:15:24","extension":"jpg","order_by":4,"title":"Figure 4","display":"","copyAsset":false,"role":"figure","size":77054,"visible":true,"origin":"","legend":"\u003cp\u003e\u003cstrong\u003eReservoir Pressure during Primary Recovery.\u003c/strong\u003e\u003c/p\u003e","description":"","filename":"4.jpg","url":"https://assets-eu.researchsquare.com/files/rs-7179572/v1/a3b4c5f22f64b098bb780c88.jpg"},{"id":88623078,"identity":"e12c4cb4-5119-4689-a327-a099c27c2044","added_by":"auto","created_at":"2025-08-08 12:23:24","extension":"jpg","order_by":5,"title":"Figure 5","display":"","copyAsset":false,"role":"figure","size":96765,"visible":true,"origin":"","legend":"\u003cp\u003e\u003cstrong\u003eCumulative Field Production Total Using Water Flooding\u003c/strong\u003e\u003c/p\u003e","description":"","filename":"5.jpg","url":"https://assets-eu.researchsquare.com/files/rs-7179572/v1/25e2e8c5b5fb18cae355b6ef.jpg"},{"id":88622381,"identity":"bfac8278-d8ee-4bd9-8eb1-881a0e84dac0","added_by":"auto","created_at":"2025-08-08 12:15:23","extension":"jpg","order_by":6,"title":"Figure 6","display":"","copyAsset":false,"role":"figure","size":119494,"visible":true,"origin":"","legend":"\u003cp\u003e\u003cstrong\u003eRecovery Factor vs. Gas Injection Rate with Different Water Injection Rates for WAG Ratio 1:1\u003c/strong\u003e\u003c/p\u003e","description":"","filename":"6.jpg","url":"https://assets-eu.researchsquare.com/files/rs-7179572/v1/0d857b15d7391c62d963baa5.jpg"},{"id":88622383,"identity":"7dd0bea9-247e-4345-b94d-0c3a00b78fd3","added_by":"auto","created_at":"2025-08-08 12:15:23","extension":"jpg","order_by":7,"title":"Figure 7","display":"","copyAsset":false,"role":"figure","size":116069,"visible":true,"origin":"","legend":"\u003cp\u003e\u003cstrong\u003eRecovery Factor vs. Gas Injection Rate with Different Water Injection Rates for WAG Ratio 2:3\u003c/strong\u003e\u003c/p\u003e","description":"","filename":"7.jpg","url":"https://assets-eu.researchsquare.com/files/rs-7179572/v1/5c822bedb38d5e52e75021ba.jpg"},{"id":88623063,"identity":"17c684a6-ef3b-40a7-9aec-830800dde4b2","added_by":"auto","created_at":"2025-08-08 12:23:23","extension":"jpg","order_by":8,"title":"Figure 8","display":"","copyAsset":false,"role":"figure","size":123552,"visible":true,"origin":"","legend":"\u003cp\u003e\u003cstrong\u003eRecovery Factor vs. Gas Injection Rate with Different Water Injection Rates for WAG Ratio 3:2\u003c/strong\u003e\u003c/p\u003e","description":"","filename":"8.jpg","url":"https://assets-eu.researchsquare.com/files/rs-7179572/v1/7fb7b3e520a5b61b9e259424.jpg"},{"id":93110754,"identity":"9fbd0abc-5462-4006-9b93-489dda18065d","added_by":"auto","created_at":"2025-10-09 07:40:00","extension":"pdf","order_by":0,"title":"","display":"","copyAsset":false,"role":"manuscript-pdf","size":1646110,"visible":true,"origin":"","legend":"","description":"","filename":"manuscript.pdf","url":"https://assets-eu.researchsquare.com/files/rs-7179572/v1/9754ce2e-b975-4df5-b7ef-64365927bd03.pdf"}],"financialInterests":"No competing interests reported.","formattedTitle":"Effects of Water and Gas Injection Rates in WAG Flooding for a Heterogeneous Oil Reservoir: A Simulation Study","fulltext":[{"header":"INTRODUCTION","content":"\u003cp\u003eWater Alternate Gas or WAG flooding is being used extensively in the field application as an Enhanced Oil Recovery Technique in many parts of the world especially in the United States. Use of WAG as a secondary technique is currently under experimentation. \u003c/p\u003e\n\u003cp\u003eCurrently, water flooding and gas injection are being used as secondary recovery techniques but oil recovery utilizing these methods is not satisfactory. High mobility ratio and trapped oil in the reservoir phenomenon is observed with these methods. Gravity segregation and viscous fingering are the main mechanisms behind these phenomenons. \u003c/p\u003e\n\u003cp\u003eInjection rates of water and gas as well as the WAG ratio are two of the main parameters which effects WAG recovery. However, heterogeneity of the formation complicates the optimization process of WAG flooding. It is important to define the relationship of oil recovery and WAG ratio as well as gas and water injection rates. \u003c/p\u003e\n\u003cp\u003eHigh water and gas injection rate leads to early breakthrough of water and gas respectively. This reduces oil recovery significantly. Low injection rates meanwhile leads to gravity segregation as well as low productivity which is very much undesired.\u003c/p\u003e\n\u003cp\u003eSo, this together with the heterogeneity of the formation problem leads to lower oil recovery than expected. This problem can only be dealt with by detailed study on WAG ratio and injection rates of water and gas. \u003c/p\u003e\n\u003cp\u003eThe aim of this study is to define a relationship between injection rate of water and gas with oil recovery. Then, the relationship of WAG ratio with oil recovery factor will be studied. Range of optimum water and gas injection rates will be the other output of this study. Finally WAG flooding as a secondary recovery technique will be compared with water flooding in terms of oil recovery.\u003c/p\u003e\n\u003cp\u003eThis study would be conducted in Eclipse 100 (black oil simulator) utilizing a heterogeneous reservoir model. Studied water injection rates are in the range from 1500 STB/D to 2500 STB/D while gas injection rates are in the range of 1000 MSCF/D to 4000 MSCF/D. three different WAG ratios will be considered which are 1:1, 2:3 and 3:2. Slug size would be kept constant for all the runs. \u003c/p\u003e\n\u003cp\u003eAs a conclusion, this study is aimed at solving the problems related to optimization of WAG design parameters in the field application today. By doing this, the oil reserve could be increased significantly and keep the energy crisis at the bay for the moment. \u003c/p\u003e"},{"header":"METHODOLOGY","content":"\u003cp\u003e\u003cb\u003eReservoir Model\u003c/b\u003e\u003c/p\u003e\u003cp\u003eFigure \u003cspan refid=\"Fig1\" class=\"InternalRef\"\u003e1\u003c/span\u003e shows the reservoir model utilized for this study. As it can be seen, there are 3 layers. The permeabilities of the layers are 10 mD, 100 mD and 1 mD respectively. The total thickness of the reservoir model is 120 ft with an areal extent of 530 acres.\u003c/p\u003e\u003cp\u003e\u003c/p\u003e\u003cp\u003e\u003cb\u003eInjection Pattern\u003c/b\u003e\u003c/p\u003e\u003cp\u003eA 5 spot injection pattern such as the one shown in Fig.\u0026nbsp;\u003cspan refid=\"Fig2\" class=\"InternalRef\"\u003e2\u003c/span\u003e was utilized to flood this reservoir model. This term refers to 4 injection wells surrounding any one production well. There will be a total of 4 sets of this 5 spot injection pattern because there are 4 producing wells in this reservoir.\u003c/p\u003e\u003cp\u003e\u003cb\u003eReservoir Properties\u003c/b\u003e\u003c/p\u003e\u003cp\u003eBasically, this is a sandstone oil reservoir with a porosity value of 0.20 and initial reservoir pressure of 2800 Psia. The datum of the reservoir is at 5010 ft.\u003c/p\u003e\u003cp\u003eThe main reservoir properties are listed in the Table\u0026nbsp;\u003cspan refid=\"Tab1\" class=\"InternalRef\"\u003e1\u003c/span\u003e.\u003c/p\u003e\u003cp\u003e\u003cb\u003eReservoir Fluid Properties\u003c/b\u003e\u003c/p\u003e\u003cp\u003eThe API gravity of the oil is 43.3 while the gas specific gravity is 0.65. Other reservoir fluid parameters are summarized in the Table\u0026nbsp;\u003cspan refid=\"Tab2\" class=\"InternalRef\"\u003e2\u003c/span\u003e.\u003c/p\u003e\u003cp\u003e\u003cb\u003eSimulation Model\u003c/b\u003e\u003c/p\u003e\u003cp\u003eThe reservoir model was divided into 20 x 20 x 7 grid blocks. The simulation model was validated by comparing the Stock Tank Oil Originally In Place or STOOIP obtained from the simulator with manual calculation using material balance.\u003c/p\u003e\u003cp\u003e\u003cb\u003eBase Case\u003c/b\u003e\u003c/p\u003e\u003cp\u003eThe base case run was done for three main purposes. First, to determine the beginning of the injection time and the second is to obtain the oil recovery factor through primary depletion. The final purpose is to justify the simulation model by comparing the STOOIP obtained through simulation and manual calculation. Solution gas drive and water drive are the main drives of this reservoir.\u003c/p\u003e\u003cp\u003e\u003cb\u003eWater Flooding\u003c/b\u003e\u003c/p\u003e\u003cp\u003eWater flooding run serves as a comparison study to compare oil recovery factor using WAG and water flooding as the secondary technique. The density of the water used in the injection process is 62.4 lb/cuft and the salinity is 3%.\u003c/p\u003e\u003cp\u003eThe injection rate used is 2000 STB/D as this value is the typical injection rate value used in the field application nowadays. The reservoir is water flooded for 23 years after primary recovery.\u003c/p\u003e\u003cp\u003e\u003c/p\u003e\u003cp\u003e\u003cdiv class=\"gridtable\"\u003e\u003ctable float=\"Yes\" id=\"Tab1\" border=\"1\"\u003e\u003ccaption language=\"En\"\u003e\u003cdiv class=\"CaptionNumber\"\u003eTable 1\u003c/div\u003e\u003cdiv class=\"CaptionContent\"\u003e\u003cp\u003eReservoir Properties\u003c/p\u003e\u003c/div\u003e\u003c/caption\u003e\u003ccolgroup cols=\"2\"\u003e\u003cdiv align=\"left\" class=\"colspec\" colname=\"c1\" colnum=\"1\"\u003e\u003c/div\u003e\u003cdiv align=\"left\" class=\"colspec\" colname=\"c2\" colnum=\"2\"\u003e\u003c/div\u003e\u003cthead\u003e\u003ctr\u003e\u003cth align=\"left\" colname=\"c1\"\u003e\u003cp\u003eArea (Acres)\u003c/p\u003e\u003c/th\u003e\u003cth align=\"left\" colname=\"c2\"\u003e\u003cp\u003e530\u003c/p\u003e\u003c/th\u003e\u003c/tr\u003e\u003c/thead\u003e\u003ctbody\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eGas Oil Contact, GOC (ft)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e5010\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eOil Water Contact, OWC (ft)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e5130\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eDatum Depth (feet)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e5010\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eInitial Pressure at Datum (psia)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e2800\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eBubble Point (psia)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e2500\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eReservoir Temperature (\u0026deg;F)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e230\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003ePorosity (Fraction)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e0.30\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eInitial Water Saturation\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e0.20\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eStandard Temperature (\u0026deg;F)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e60\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eStandard Pressure (Psia)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e14.7\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003c/tbody\u003e\u003c/colgroup\u003e\u003c/table\u003e\u003c/div\u003e\u003c/p\u003e\u003cp\u003e\u003cb\u003eWAG Flooding\u003c/b\u003e\u003c/p\u003e\u003cp\u003eA total of 135 runs were conducted to study the WAG flooding process. There are a total of 5 different water injection rates and 9 different gas injection rates with 3 different WAG ratios. The slug size is set constant at 0.5% of Hydrocarbon Pore Volume or HCPV for all runs. Table\u0026nbsp;\u003cspan refid=\"Tab4\" class=\"InternalRef\"\u003e3\u003c/span\u003e summarizes the injection fluid properties and the water and gas injection rates utilized in this study.\u003c/p\u003e\u003cp\u003e\u003cdiv class=\"gridtable\"\u003e\u003ctable float=\"Yes\" id=\"Tab2\" border=\"1\"\u003e\u003ccaption language=\"En\"\u003e\u003cdiv class=\"CaptionNumber\"\u003eTable 2\u003c/div\u003e\u003cdiv class=\"CaptionContent\"\u003e\u003cp\u003eReservoir Fluid Properties\u003c/p\u003e\u003c/div\u003e\u003c/caption\u003e\u003ccolgroup cols=\"2\"\u003e\u003cdiv align=\"left\" class=\"colspec\" colname=\"c1\" colnum=\"1\"\u003e\u003c/div\u003e\u003cdiv align=\"left\" class=\"colspec\" colname=\"c2\" colnum=\"2\"\u003e\u003c/div\u003e\u003cthead\u003e\u003ctr\u003e\u003cth align=\"left\" colname=\"c1\"\u003e\u003cp\u003eAPI Gravity, degrees\u003c/p\u003e\u003c/th\u003e\u003cth align=\"left\" colname=\"c2\"\u003e\u003cp\u003e43.3\u003c/p\u003e\u003c/th\u003e\u003c/tr\u003e\u003c/thead\u003e\u003ctbody\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eOil Volumetric factor (RB/STB)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e1.26\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eOil Viscosity (cp)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e0.64\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eSalt Concentration Weight (%)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e3\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eGas Specific Gravity\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e0.65\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eWater Density (lb/cuft)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e62.4\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eGas Formation Volume Factor (Rescuft/SCF)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e0.0063\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003c/tbody\u003e\u003c/colgroup\u003e\u003c/table\u003e\u003c/div\u003e\u003c/p\u003e\u003cp\u003e\u003cdiv class=\"gridtable\"\u003e\u003ctable float=\"Yes\" id=\"Tab3\" border=\"1\"\u003e\u003ccaption language=\"En\"\u003e\u003cdiv class=\"CaptionNumber\"\u003eTable 3\u003c/div\u003e\u003cdiv class=\"CaptionContent\"\u003e\u003cp\u003eWAG Flooding and Injection Fluid Properties\u003c/p\u003e\u003c/div\u003e\u003c/caption\u003e\u003ccolgroup cols=\"2\"\u003e\u003cdiv align=\"left\" class=\"colspec\" colname=\"c1\" colnum=\"1\"\u003e\u003c/div\u003e\u003cdiv align=\"left\" class=\"colspec\" colname=\"c2\" colnum=\"2\"\u003e\u003c/div\u003e\u003cthead\u003e\u003ctr\u003e\u003cth align=\"left\" colname=\"c1\"\u003e\u003cp\u003eWater Density (lb/cuft)\u003c/p\u003e\u003c/th\u003e\u003cth align=\"left\" colname=\"c2\"\u003e\u003cp\u003e62.40\u003c/p\u003e\u003c/th\u003e\u003c/tr\u003e\u003c/thead\u003e\u003ctbody\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e Density (lb/cuft)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e30.00\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eWater Viscosity (cP)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e0.31\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e Viscosity (cP)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e0.041\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eWater injection rate (STB/day)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e1500, 1700, 2000, 2300, 2500\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e injection rate (MMSCF/day)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e1000, 1500, 2000, 2200, 2500, 2700, 3000, 3500 and 4000\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eWAG Ratio (W : G)\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e1:1, 2:3, 3:2\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003eSlug Size per cycle\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e0.5% HCPV\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003c/tbody\u003e\u003c/colgroup\u003e\u003c/table\u003e\u003c/div\u003e\u003c/p\u003e"},{"header":"RESULTS AND DISCUSSION","content":"\u003cp\u003e\u003cb\u003eSimulation Model Validation\u003c/b\u003e\u003c/p\u003e\u003cp\u003eThe simulation model created was verified by comparing the STOOIP obtained from simulation and material balance calculation\u003c/p\u003e\u003cp\u003eperformed manually. Manual calculation resulted in an STOOIP value of 72 MMSTB as shown in Table\u0026nbsp;\u003cspan refid=\"Tab5\" class=\"InternalRef\"\u003e4\u003c/span\u003e. STOOIP value from simulation model suggested an STOOIP value of 68 MMSTB which is almost same. This validates this model.\u003c/p\u003e\u003cp\u003e\u003cdiv class=\"gridtable\"\u003e\u003ctable float=\"Yes\" id=\"Tab4\" border=\"1\"\u003e\u003ccaption language=\"En\"\u003e\u003cdiv class=\"CaptionNumber\"\u003eTable 3\u003c/div\u003e\u003cdiv class=\"CaptionContent\"\u003e\u003cp\u003eStock Tank Oil Originally In Place\u003c/p\u003e\u003c/div\u003e\u003c/caption\u003e\u003ccolgroup cols=\"2\"\u003e\u003cdiv align=\"left\" class=\"colspec\" colname=\"c1\" colnum=\"1\"\u003e\u003c/div\u003e\u003cdiv align=\"char\" char=\".\" class=\"colspec\" colname=\"c2\" colnum=\"2\"\u003e\u003c/div\u003e\u003cthead\u003e\u003ctr\u003e\u003cth align=\"left\" colname=\"c1\"\u003e\u003cp\u003eLayer\u003c/p\u003e\u003c/th\u003e\u003cth align=\"left\" colname=\"c2\"\u003e\u003cp\u003eOil In Place (MMSTB)\u003c/p\u003e\u003c/th\u003e\u003c/tr\u003e\u003c/thead\u003e\u003ctbody\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003e1\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e\u003cp\u003e36\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003e2\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e\u003cp\u003e12\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003e3\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e\u003cp\u003e24\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003e\u003cb\u003eTotal\u003c/b\u003e\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"char\" char=\".\" colname=\"c2\"\u003e\u003cp\u003e\u003cb\u003e72\u003c/b\u003e\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003c/tbody\u003e\u003c/colgroup\u003e\u003c/table\u003e\u003c/div\u003e\u003c/p\u003e\u003cp\u003e\u003cb\u003eBase Case Study\u003c/b\u003e\u003c/p\u003e\u003cp\u003eBase case run refers to production of oil through natural drive mechanisms of the reservoir. The base case production rate is shown in the Fig.\u0026nbsp;\u003cspan refid=\"Fig3\" class=\"InternalRef\"\u003e3\u003c/span\u003e. Production of the reservoir is at 4000 STB/D. Production starts to decline in the 7th year which is the point where injection is required. Recovery from the primary stage is 15% from STOOIP or 10.2 MMSTB.\u003c/p\u003e\u003cp\u003e\u003c/p\u003e\u003cp\u003eFigure \u003cspan refid=\"Fig4\" class=\"InternalRef\"\u003e4\u003c/span\u003e meanwhile depicts the reservoir pressure during the primary recovery. This is important in order to verify that the reservoir pressure is higher than the Minimum Miscibility Pressure or MMP of Carbon Dioxide which is approximately 1600 psia. The reason for this is to establish a miscible WAG injection process. This refers to the mechanism where CO\u003csub\u003e2\u003c/sub\u003e becomes miscible in the oil bank. Miscible WAG gives a better recovery compared to immiscible WAG.\u003c/p\u003e\u003cp\u003e\u003c/p\u003e\u003cp\u003eAs it can be seen, at the 7th year where injection is due to take place, reservoir pressure is approximately 1700 psia which is well above the MMP of CO\u003csub\u003e2\u003c/sub\u003e.\u003c/p\u003e\u003cp\u003e\u003cb\u003eWater Flooding Study\u003c/b\u003e\u003c/p\u003e\u003cp\u003eFigure \u003cspan refid=\"Fig5\" class=\"InternalRef\"\u003e5\u003c/span\u003e shows the cumulative oil recovery utilizing water flooding as the secondary recovery technique. After 30 years, recovery from water flooding is 27 MMSTB or 38% of STOOIP which is an increment of 23% from primary recovery.\u003c/p\u003e\u003cp\u003e\u003c/p\u003e\u003cp\u003e\u003cb\u003eWAG Flooding \u0026ndash; WAG Ratio 1:1\u003c/b\u003e\u003c/p\u003e\u003cp\u003eFigure \u003cspan refid=\"Fig6\" class=\"InternalRef\"\u003e6\u003c/span\u003e shows the cumulative oil recovery for WAG flooding utilizing WAG ratio of 1:1 with various combinations of injection rates. WAG ratio here refers to ratio of water slug size to CO\u003csub\u003e2\u003c/sub\u003e slug size. As it can be seen, recovery factor of oil increases with water and gas injection rate until an optimum point, than it starts to decline. The optimum injection rate range is from 2300\u0026ndash;2500 STB/D for water and 2500\u0026ndash;3000 MSCF/D for CO\u003csub\u003e2\u003c/sub\u003e. Recovery using this optimum injection rates after 30 years is approximately 42% of STOOIP which is an increment of 27% from primary recovery.\u003c/p\u003e\u003cp\u003e\u003c/p\u003e\u003cp\u003e\u003cb\u003eWAG Flooding \u0026ndash; WAG Ratio 2:3\u003c/b\u003e\u003c/p\u003e\u003cp\u003eFigure \u003cspan refid=\"Fig7\" class=\"InternalRef\"\u003e7\u003c/span\u003e shows the cumulative oil recovery for WAG flooding utilizing WAG ratio of 2:3 with various combinations of injection rates. Again, recovery factor of oil increases with water and gas injection rate until an optimum point, than it starts to decline. The optimum injection rate range is from 2000\u0026ndash;2300 STB/D for water and 2500\u0026ndash;3000 MSCF/D for CO\u003csub\u003e2\u003c/sub\u003e. Recovery using this optimum injection rates after 30 years is approximately 44% of STOOIP which is an increment of 29% from primary recovery.\u003c/p\u003e\u003cp\u003e\u003c/p\u003e\u003cp\u003e\u003cb\u003eWAG Flooding \u0026ndash; WAG Ratio 3:2\u003c/b\u003e\u003c/p\u003e\u003cp\u003eThe final WAG ratio of 3:2 provided a somewhat similar result as shown in Fig.\u0026nbsp;\u003cspan refid=\"Fig8\" class=\"InternalRef\"\u003e8\u003c/span\u003e. Still, recovery factor of oil increases with water and gas injection rate until an optimum point, than it starts to decline. The optimum injection rate range is from 2000\u0026ndash;2300 STB/D for water and 2500\u0026ndash;3000 MSCF/D for CO\u003csub\u003e2\u003c/sub\u003e. Recovery using this optimum injection rates after 30 years is approximately 40% of STOOIP which is an increment of 25% from primary recovery. So far, this is the worst recovery factor in terms of WAG flooding but still then it is better than water flooding.\u003c/p\u003e\u003cp\u003e\u003c/p\u003e\u003cp\u003e\u003cb\u003eComparison Between Studied WAG Ratios\u003c/b\u003e\u003c/p\u003e\u003cp\u003eWAG ratio of 2:3 gives the highest recovery of 44% of STOOIP followed by WAG ratio of 1:1 at 42% and WAG ratio of 3:2 at 40% (the poorest recovery) of STOOIP. However, economic evaluation is necessary to investigate the truth of this fact. It might be feasible technically but not economically. Economic evaluation is beyond the scope of this study.\u003c/p\u003e\u003cp\u003e\u003cb\u003eComparison Between WAG Flooding and Water Flooding\u003c/b\u003e\u003c/p\u003e\u003cp\u003eAll the 3 WAG ratios studied gives a higher oil recovery compared to that of water flooding. Recovery from water flooding as mentioned earlier is 38% of STOOIP. The differences between water flooding and WAG flooding are then 4%, 6% and 2% respectively for WAG ratio of 1:1, 2:3 and 3:2.\u003c/p\u003e\u003cp\u003eAgain, this is only a technical evaluation where economic considerations are necessary. It is important to take in account of the pumping facilities involved, availability of CO\u003csub\u003e2\u003c/sub\u003e and price of CO\u003csub\u003e2\u003c/sub\u003e which is again beyond the scope of this study.\u003c/p\u003e\u003cp\u003eThe differences in recovery factor might not be much compared to the complications involved with WAG especially in small fields.\u003c/p\u003e\u003cp\u003e\u003cb\u003eEffect of Water Injection Rate on Recovery Factor\u003c/b\u003e\u003c/p\u003e\u003cp\u003eLow water injection rate leads to a higher ultimate oil recovery but low injection rate of water is accompanied with low oil production rate. Generally speaking, this is in most case very uneconomic.\u003c/p\u003e\u003cp\u003eAnother phenomenon related to low water injection rate is gravity segregation where water sweeps only the lower portion of the reservoir due to its higher density. The desired piston like displacement is then unachievable.\u003c/p\u003e\u003cp\u003eIncreasing injection rate will increase the reservoir pressure forcing free gas to go into solution. This will reduce the relative permeability of gas and which in hand increases the relative permeability of oil. This contributes to the faster production of oil. Once increasing injection rates have increased the reservoir pressure high enough to force all the gas into solution, increasing injection rate any further is of no use.\u003c/p\u003e\u003cp\u003eHigh water injection rate meanwhile leads to early water breakthrough due to phenomena as viscous fingering or water override. This greatly reduces oil production because injected water bypasses oil and thus oil remains trapped in the reservoir. High water production poses many economic and technical problems such as water treatment cost.\u003c/p\u003e\u003cp\u003eOptimum water injection rate shows a piston like displacement of the oil bank. Gravity segregation is negligible while water breakthrough is not due to happen very soon.\u003c/p\u003e\u003cp\u003e\u003cb\u003eEffect of Gas Injection Rate on Recovery Factor\u003c/b\u003e\u003c/p\u003e\u003cp\u003eHeterogeneity and injection rates play an important role in affecting oil recovery and gas breakthrough.\u003c/p\u003e\u003cp\u003eWhen gas injection rate is very high, an early gas breakthrough problem is encountered. This happens due to viscous fingering of gas through high permeability streaks. Injected CO\u003csub\u003e2\u003c/sub\u003e will selectively travel through higher permeability layers. This effect is more dominant in a heterogeneous reservoir such as the one used in this study. However, since water is being injected subsequently, viscous fingering is controlled to a certain extend. This is because water enters the higher permeability layers and forces gas to travel through the lower permeability layers. Besides, the injected water covers the lower portion of the reservoir which is not swept by gas due to gravity segregation.\u003c/p\u003e\u003cp\u003eAt low injection rate of gas, gravity segregation occurs in the reservoir where the low density CO\u003csub\u003e2\u003c/sub\u003e sweeps through the upper portion of the reservoir. This causes the oil in the lower portion to be bypassed.\u003c/p\u003e\u003cp\u003eSo, high injection rate promises higher recovery factor only until a certain extend. After this extend, the recovery factor will be lower than the process using lower injection rate. This is exactly what is proven by this study. CO\u003csub\u003e2\u003c/sub\u003e utilization is also high at a high injection rate. Early gas breakthrough also yields higher Gas Oil Ratio or GOR. It is important to note that most countries have set a maximum limit for the GOR. Finally, it is also important to note that there are limitations of injection rates that could be applied in the field. For example, the tubing size, pumping capacity and formation fracture gradient are among some considerations.\u003c/p\u003e\u003cp\u003eLow injection rate meanwhile gives a better sweep. This is mainly because the injected gas has more time to be in the miscible phase with the oil. Oil swelling and viscosity reduction is the two main advantage of using a miscible flood. This process will improve recovery factor. However, we must remember that the production rate of oil will be lower if we use a low injection rate. Low production rate is weak as far as production economic is concerned. Anyway, CO\u003csub\u003e2\u003c/sub\u003e utilization is lower at a lower injection rate.\u003c/p\u003e\u003cp\u003eSo, injection rate of CO\u003csub\u003e2\u003c/sub\u003e should be optimized before the start of injection. Two main factors to be considered are the economic feasibility and the technical viability of the injection rate.\u003c/p\u003e\u003cp\u003e\u003cb\u003eEffect of WAG Ratio on Recovery Factor\u003c/b\u003e\u003c/p\u003e\u003cp\u003eMany studies have cited that higher WAG ratio contributes to higher oil recovery but this is not the case in a tight heterogeneous reservoir as this. This is because the thickness of the low permeability layers is about 100 ft compared to the total thickness which is 120 ft as shown in Fig.\u0026nbsp;\u003cspan refid=\"Fig1\" class=\"InternalRef\"\u003e1\u003c/span\u003e. Thus, water sweeps the high permeability (100 mD) layer, forcing CO\u003csub\u003e2\u003c/sub\u003e to sweep the low permeability layers. Due to the thick low permeability layer, bigger gas slug size leads to a higher oil recovery.\u003c/p\u003e\u003cp\u003eThis fact is supported by this study when WAG ratio of 2:3 gives highest recovery compared to WAG ratio of 1:1 or 3:2.\u003c/p\u003e\u003cp\u003e\u003cb\u003eEffects of Heterogeneity on Recovery Factor\u003c/b\u003e\u003c/p\u003e\u003cp\u003eHeterogeneity affects the oil recovery factor by various mechanisms. This is one of the primary reasons why every reservoir is treated uniquely. Homogeneous reservoir is more of an imaginary reservoir as it doesn\u0026rsquo;t exist in this world.\u003c/p\u003e\u003cp\u003eThe low permeability layers, 1 mD and 10 mD is the main culprit which causes low recovery factor from the water flooding technique. Injected water will selectively channel through the high permeability layer (100 mD). This will cause the oil in the other 2 layers to be bypassed. The same phenomenon will also occur if gas flooding is used. Injected gas will channel through the high permeability streaks and bypass the lower permeability layers.\u003c/p\u003e\u003cp\u003eBesides, gravity segregation will cause gas to sweep only the upper portion of the reservoir. However by using WAG technique, this fingering and gravity segregation effect could be controlled. Injected CO\u003csub\u003e2\u003c/sub\u003e will be forced to enter the lower permeability layers by water which is injected subsequently. Water will sweep the lower portion of the reservoir while gas will sweep the upper portion of the reservoir.\u003c/p\u003e\u003cp\u003eSo, as the heterogeneity of the reservoir increases, the amount of oil bypassed increases too. WAG flooding is a better technique to overcome this problem and increase the recovery of oil compared to water or gas flooding alone.\u003c/p\u003e"},{"header":"CONCLUSION","content":"\u003cp\u003eThe conclusion of the results of this study is tabulated in the Table\u0026nbsp;\u003cspan refid=\"Tab5\" class=\"InternalRef\"\u003e4\u003c/span\u003e. As we can see, the optimum WAG ratio among the three studied WAG ratios would be WAG ratio 2:3. It yields 44% of STOOIP. The recovery from water flooding technique is only 38%. This shows that WAG flooding is a better technique to be used in the field application. Primary recovery from reservoir depletion is only 15%.\u003c/p\u003e\u003cp\u003eThe conclusion for the injection rate study suggests that the optimum injection rate for water lies in the range of 2000 STB/D to 2500 STB/D while the optimum injection rate for CO\u003csub\u003e2\u003c/sub\u003e lies in the range of 2500 MSCF/D to 3000 MSCF/D.\u003c/p\u003e\u003cp\u003eOil recovery factor increases both when the injection rate of CO\u003csub\u003e2\u003c/sub\u003e or water increases until a certain point where the recovery starts to decline again. Heterogeneity is a major factor which affects the recovery factor of oil and low WAG ratios are suitable for a heterogeneous reservoir which contains low permeability layers.\u003c/p\u003e\u003cp\u003e\u003c/p\u003e\u003cdiv class=\"gridtable\"\u003e\u003cdiv align=\"left\" class=\"colspec\" colname=\"c1\" colnum=\"1\"\u003e\u003c/div\u003e\u003cdiv align=\"left\" class=\"colspec\" colname=\"c2\" colnum=\"2\"\u003e\u003c/div\u003e\u003cdiv align=\"left\" class=\"colspec\" colname=\"c3\" colnum=\"3\"\u003e\u003c/div\u003e\u003cdiv align=\"left\" class=\"colspec\" colname=\"c4\" colnum=\"4\"\u003e\u003c/div\u003e\u003ctable float=\"Yes\" id=\"Tab5\" border=\"1\"\u003e\u003ccaption language=\"En\"\u003e\u003cdiv class=\"CaptionNumber\"\u003eTable 4\u003c/div\u003e\u003cdiv class=\"CaptionContent\"\u003e\u003cp\u003eSummary of WAG Flooding Results\u003c/p\u003e\u003c/div\u003e\u003c/caption\u003e\u003ccolgroup cols=\"4\"\u003e\u003c/colgroup\u003e\u003cthead\u003e\u003ctr\u003e\u003cth align=\"left\" colname=\"c1\"\u003e\u003cp\u003eWAG Ratio\u003c/p\u003e\u003c/th\u003e\u003cth align=\"left\" colname=\"c2\"\u003e\u003cp\u003eOptimum Water Injection Rate, (STB/D)\u003c/p\u003e\u003c/th\u003e\u003cth align=\"left\" colname=\"c3\"\u003e\u003cp\u003eOptimum Gas Injection Rate, (MSCF/D)\u003c/p\u003e\u003c/th\u003e\u003cth align=\"left\" colname=\"c4\"\u003e\u003cp\u003eRecovery Factor Utilizing Optimum Injection Rates\u003c/p\u003e\u003c/th\u003e\u003c/tr\u003e\u003c/thead\u003e\u003ctbody\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003e\u003cb\u003e1:1\u003c/b\u003e\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e2300–2500\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c3\"\u003e\u003cp\u003e2500–3000\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c4\"\u003e\u003cp\u003e42%\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003e\u003cb\u003e2:3\u003c/b\u003e\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e2000–2300\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c3\"\u003e\u003cp\u003e2500–3000\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c4\"\u003e\u003cp\u003e44%\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003ctr\u003e\u003ctd align=\"left\" colname=\"c1\"\u003e\u003cp\u003e\u003cb\u003e3:2\u003c/b\u003e\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c2\"\u003e\u003cp\u003e2000–2300\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c3\"\u003e\u003cp\u003e2500–3000\u003c/p\u003e\u003c/td\u003e\u003ctd align=\"left\" colname=\"c4\"\u003e\u003cp\u003e40%\u003c/p\u003e\u003c/td\u003e\u003c/tr\u003e\u003c/tbody\u003e\u003c/table\u003e\u003c/div\u003e\u003cp\u003e\u003c/p\u003e\u003cp\u003e\u003cb\u003eRECOMMENDATIONS\u003c/b\u003e\u003c/p\u003e\u003cp\u003eThis study could be greatly enhanced by detailed study on other related parameters of WAG as wells as reservoir conditions used. Following are a few recommendations for future study.\u003c/p\u003e\u003cp\u003e\u003c/p\u003e\u003col\u003e\u003cspan\u003e\u003cli\u003e\u003cp\u003eAn economic model should be created to analyze the economics of WAG flooding as a secondary recovery technique.\u003c/p\u003e\u003c/li\u003e\u003c/span\u003e\u003cspan\u003e\u003cli\u003e\u003cp\u003eIncrease the number of slug size used as slug size was set constant for this study.\u003c/p\u003e\u003c/li\u003e\u003c/span\u003e\u003cspan\u003e\u003cli\u003e\u003cp\u003eIncrease the heterogeneity of the formation with more permeability streaks and also compare with recovery from homogeneous formation.\u003c/p\u003e\u003c/li\u003e\u003c/span\u003e\u003cspan\u003e\u003cli\u003e\u003cp\u003eOnly 3 WAG ratios were used for this study. The number of WAG ratios studied could be increased utilizing WAG ratios such as 1:2, 2:1, 4:1 and 1:4.\u003c/p\u003e\u003c/li\u003e\u003c/span\u003e\u003cspan\u003e\u003cli\u003e\u003cp\u003eCompare the technical viability and economic feasibility of WAG as secondary recovery technique as compared to WAG flooding as a tertiary recovery technique.\u003c/p\u003e\u003c/li\u003e\u003c/span\u003e\u003cspan\u003e\u003cli\u003e\u003cp\u003eCompare the oil recovery from simple WAG and Simultaneous Water Alternate Gas or SWAG flooding.\u003c/p\u003e\u003c/li\u003e\u003c/span\u003e\u003cspan\u003e\u003cli\u003e\u003cp\u003eWAG tapering is a process where the injection rate of water and gas is varied throughout the WAG flooding period whenever necessary, in order to increase oil recover. The effectiveness of this process as compared to simple WAG could be studied upon.\u003c/p\u003e\u003c/li\u003e\u003c/span\u003e\u003cspan\u003e\u003cli\u003e\u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e is used as the injection gas in this study due to its lower MMP. The efficiency of other gases such as hydrocarbon gas and nitrogen gas could be compared.\u003c/p\u003e\u003c/li\u003e\u003c/span\u003e\u003c/ol\u003e\u003cp\u003e\u003c/p\u003e"},{"header":"NOMENCLATURES","content":"\u003cp\u003eCO\u003csub\u003e2\u003c/sub\u003e Carbon dioxide\u003c/p\u003e\u003cp\u003eFt Feet\u003c/p\u003e\u003cp\u003eGOC Gas Oil Contact\u003c/p\u003e\u003cp\u003eGOR Gas Oil Ratio\u003c/p\u003e\u003cp\u003eHCPV Hydrocarbon Pore Volume\u003c/p\u003e\u003cp\u003elb/cuft Pound per cubic feet\u003c/p\u003e\u003cp\u003emD miliDarcy\u003c/p\u003e\u003cp\u003eMMP Minimum Miscibility Pressure\u003c/p\u003e\u003cp\u003eOWC Oil Water Contact\u003c/p\u003e\u003cp\u003epsia Pound per square inch (absolute)\u003c/p\u003e\u003cp\u003eRB Reservoir barrel\u003c/p\u003e\u003cp\u003eSCF/D Standard cubic feet per day\u003c/p\u003e\u003cp\u003eSTB Stock Tank Barrel\u003c/p\u003e\u003cp\u003eSTOOIP Stock Tank Oil Originally In Place\u003c/p\u003e\u003cp\u003eSWAG Simultaneous Water Alternate Gas\u003c/p\u003e\u003cp\u003eWAG Water Alternate Gas\u003c/p\u003e"},{"header":"Declarations","content":"\u003ch2\u003eAuthor Contribution\u003c/h2\u003e\u003cp\u003eConceptualization: S.R.H.J.Methodology: S.R.H.J.Investigation: S.R.H.J.Data Curation: S.R.H.J.Formal Analysis: S.R.H.J.Visualization: S.R.H.J.Writing \u0026ndash; Original Draft: S.R.H.J., S.A.Writing \u0026ndash; Review \u0026amp; Editing: S.R.H.J., S.A., M.J.Supervision: M.J.Project Administration: S.R.H.J.All authors contributed to the review and editing of the manuscript, approved the final version and agreed to be accountable for all aspects of the work.\u003c/p\u003e\u003ch2\u003eACKNOWLEDGEMENTS\u003c/h2\u003e\u003cp\u003eThe author would like to express his gratitude to PM Abdul Aziz Bin Hussin for his guidance and support.\u003c/p\u003e"},{"header":"References","content":"\u003col\u003e\n\u003cli\u003eAttanuci, V., Aslesen, K.S., Hejl, K.L., Wright, C.A. (1993). \u0026ldquo;WAG Process Optimization in the Rangely CO\u003csub\u003e2\u003c/sub\u003e Miscible Flood.\u0026rdquo; SPE 26622\u003c/li\u003e\n\u003cli\u003eBlackwell, R.J. (1980). \u0026rdquo;Miscible Displacement: Its Status and Potential for Enhanced Oil Recovery.\u0026rdquo; SPE 10014\u003c/li\u003e\n\u003cli\u003eChristensen, R., Stenby, E., Skauge, A. (1998). \u0026ldquo;Review of WAG Field Experience.\u0026rdquo; SPE 39833\u003c/li\u003e\n\u003cli\u003eChristie, M.A., Muggeridge, A.H., Barley, J.J. (1993). \u0026ldquo;3D Simulation of Viscous Fingering and WAG Schemes.\u0026rdquo; SPE 21238\u003c/li\u003e\n\u003cli\u003eCrogh, N.A., Eide, K., Morterud, S.E. (2002). \u0026ldquo;WAG Injection at the Statfjord Field, A Success Story.\u0026rdquo; SPE 78348\u003c/li\u003e\n\u003cli\u003eCullick, A.S., Lu, H.S., Jones, L.G., Cohen, M.F., Watson, J.P. (1993). \u0026ldquo;WAG May Improve Gas-Condensate Recovery.\u0026rdquo; SPE 19114\u003c/li\u003e\n\u003cli\u003eDyer, S.B., Farouq, Ali S.M. (1994). \u0026ldquo;Linear Model Studies of the Immiscible CO\u003csub\u003e2\u003c/sub\u003e WAG Process for Heavy Oil Recovery.\u0026rdquo; SPE 21162\u003c/li\u003e\n\u003cli\u003eGenrich, J.F. (1986). \u0026ldquo;A Simplified Model to Predict Heterogeneity Effects on WAG Flooding Performance.\u0026rdquo; SPE 15388\u003c/li\u003e\n\u003cli\u003eGorell, S.B. (1988). \u0026ldquo;Modeling the Effects of Trapping and Water Alternate Gas (WAG) Injection on Tertiary Miscible Displacement.\u0026rdquo; SPE 17340\u003c/li\u003e\n\u003cli\u003eGuzman, R.E., Giordano, D., Fayers, F.J., Aziz, K., Godi, A. (1994). \u0026ldquo;Three \u0026ndash; Phase Flow in Field \u0026ndash; Scale Simulation of Gas and WAG.\u0026rdquo; SPE 28897\u003c/li\u003e\n\u003cli\u003eHernandez, C, Alvarez, C., Saman, A., De Jongh, A., Audemard, N. (2002). \u0026ldquo;Monitoring WAG Pilot at VLE Field, Maracaibo Lake, By Perfluorocarbon and Fluorined Benzoic Acid Tracers.\u0026rdquo; SPE 75259\u003c/li\u003e\n\u003cli\u003eInstefjord, R., Todnem, A.C. (2002). \u0026ldquo;10 Years of WAG Injection in Lower Brent at the Gulfaks Field.\u0026rdquo; SPE 78344\u003c/li\u003e\n\u003cli\u003eLawrence, J.J., Teletzke, G.F., Hutfilz, J.M., Wilkinson, J.R. (2003). \u0026ldquo;Reservoir Simulation of Gas Injection Processes.\u0026rdquo; SPE 81459\u003c/li\u003e\n\u003cli\u003eLi, D., Kumar, K., Mohanty, K.K. (2003). \u0026ldquo;Compositional Simulation of WAG Processes for a Viscous Oil.\u0026rdquo; SPE 84074\u003c/li\u003e\n\u003cli\u003eLo, L.L., McGregor, D.S., Wang, P., DeGolyer, MacNaughton, Boucedra, S. (2003). \u0026ldquo;WAG Pilot Design and Observation Well Data Analysis for Hassi Berkine South Field.\u0026rdquo; SPE 84076\u003c/li\u003e\n\u003cli\u003eManrique, E., Calderon, G., Mayo, L., Stirpe, M.T. (1998). \u0026ldquo;Water-Alternating-Gas Flooding in Venezuela: Selection of Candidates Based on Screening Criteria of International Field Experiences.\u0026rdquo; SPE 50645\u003c/li\u003e\n\u003cli\u003eNadeson, G, Zain, Z.M., Sayegh, S.G., Girard, M. (2001). \u0026ldquo;Assessment of Dulang Field Immiscible Water\u0026ndash;Alternating\u0026ndash;Gas (WAG) Injection Through Composite Core Displacement Studies.\u0026rdquo; SPE 72140\u003c/li\u003e\n\u003cli\u003ePande, K. (1992). \u0026ldquo;Effects of Gravity and Viscous Crossflow on Hydrocarbon Miscible Flood Performance in Heterogeneous Reservoirs.\u0026rdquo; SPE 24935\u003c/li\u003e\n\u003cli\u003ePrieditis, J., Wolle, C.R., Notz, P.K. (1991). \u0026ldquo;A Laboratory and Field Injectivity Study: CO\u003csub\u003e2\u003c/sub\u003e WAG in the San Andres Formation of West Texas.\u0026rdquo; SPE 22653\u003c/li\u003e\n\u003cli\u003eSanchez, N.L. (1999). \u0026ldquo;Management of Water Alternating Gas (WAG) Injection Projects.\u0026rdquo; SPE 53714\u003c/li\u003e\n\u003cli\u003eSharma, A.K., Lucille, E. (1996). \u0026ldquo;From Simulator to Field Management: Optimum WAG Application in a West Texas CO\u003csub\u003e2\u003c/sub\u003e Flood \u0026ndash; A Case History.\u0026rdquo; SPE 36711\u003c/li\u003e\n\u003cli\u003eStone, H.L. (1982). \u0026ldquo;Vertical Conformance in an Alternating Water-Miscible Gas Flood.\u0026rdquo; SPE 11130\u003c/li\u003e\n\u003cli\u003eSurguchev, L.M., Korboi, R., Haugen, S., Krakstad, O.S. (1992). \u0026ldquo;Optimum Water Alternate Gas Injection Schemes for Stratified Reservoirs.\u0026rdquo; SPE 24646\u003c/li\u003e\n\u003cli\u003eSurguchev, L.M., Korboi, R., Haugen, S., Krakstad, O.S. (1992). \u0026ldquo;Screening of WAG Injection Strategies for Heterogeneous Reservoirs.\u0026rdquo; SPE 25075\u003c/li\u003e\n\u003cli\u003eVan Lingen, P.P. Barzanji, O.H.M., Van Kruijsdijk, C.P. (1996). \u0026ldquo;WAG Injection to Reduce Capillary Entrapment in Small-Scale Heterogeneities.\u0026rdquo; SPE 36662\u003c/li\u003e\n\u003cli\u003eVirnovsky, G.A., Helset, H.M., Skjaeveland, S.M. (1994). \u0026ldquo;Stability of Displacement Fronts WAG Operations.\u0026rdquo; SPE 28622\u003c/li\u003e\n\u003cli\u003eWegener, D.C., Harpole, K.J. (1996). \u0026ldquo;Determination of Relative Permeability and Trapped Gas Saturation for Predictions of WAG Performance in the South Cowden CO\u003csub\u003e2\u003c/sub\u003e Flood.\u0026rdquo; SPE 35429\u003c/li\u003e\n\u003cli\u003eYamamoto, J., Satoh, T., Ishii, H., Okatsu, K. (1997). \u0026ldquo;An Analysis of CO\u003csub\u003e2\u003c/sub\u003e WAG Coreflood by Use of X-Ray CT.\u0026rdquo; SPE 38068\u003c/li\u003e\n\u003cli\u003eZain, Z.M., Kechut, N.I., Nadeson, G., Ahmad, N. (2001). \u0026ldquo;Evaluation of CO\u003csub\u003e2\u003c/sub\u003e Gas Injection for Major Oil Production Fields in Malaysia.\u0026rdquo; SPE 72106\u003c/li\u003e\n\u003c/ol\u003e"}],"fulltextSource":"","fullText":"","funders":[],"hasAdminPriorityOnWorkflow":false,"hasManuscriptDocX":true,"hasOptedInToPreprint":true,"hasPassedJournalQc":"","hasAnyPriority":false,"hideJournal":true,"highlight":"","institution":"","isAcceptedByJournal":false,"isAuthorSuppliedPdf":false,"isDeskRejected":"","isHiddenFromSearch":false,"isInQc":false,"isInWorkflow":false,"isPdf":false,"isPdfUpToDate":true,"isWithdrawnOrRetracted":false,"journal":{"display":true,"email":"[email protected]","identity":"researchsquare","isNatureJournal":false,"hasQc":true,"allowDirectSubmit":true,"externalIdentity":"","sideBox":"","snPcode":"","submissionUrl":"/submission","title":"Research Square","twitterHandle":"researchsquare","acdcEnabled":true,"dfaEnabled":false,"editorialSystem":"","reportingPortfolio":"","inReviewEnabled":false,"inReviewRevisionsEnabled":true},"keywords":"","lastPublishedDoi":"10.21203/rs.3.rs-7179572/v1","lastPublishedDoiUrl":"https://doi.org/10.21203/rs.3.rs-7179572/v1","license":{"name":"CC BY 4.0","url":"https://creativecommons.org/licenses/by/4.0/"},"manuscriptAbstract":"\u003cp\u003eA simulation study to find the effect of water and gas injection rates to the oil recovery factor from WAG flooding was undertook. The technique was applied as a secondary recovery process and a heterogeneous reservoir model was used. The aim of the study is to determine the optimum injection rate of water and CO\u003csub\u003e2\u003c/sub\u003e as well as the trend of oil recovery with varying injection rates. The dimension of the model is 5000 ft x 5000 ft x 120 ft which was divided into 20 x 20 x 7 grid blocks. The STOOIP is 68 MMSTB. Primary recovery from the reservoir was 15% of STOOIP. 5 spot injection pattern was used for this study. Water flooding when used as the secondary recovery technique produced 38% of the STOOIP. WAG flooding using WAG ratio of 1:1, 2:3 and 3:2 each produced 41.5%, 44% and 39.5% of STOOIP respectively. WAG proved to be the better secondary recovery technique with WAG ratio of 2:3 being the optimum WAG ratio. Oil recovery factor increases with the injection rate of gas and water until the optimum injection rate and then the recovery starts to decline. The optimum injection rate for water is in the range of 2000 to 2500 STB/D while for CO\u003csub\u003e2\u003c/sub\u003e is about 2500 to 3000 MSCF/D. The effect of heterogeneity was felt during this simulation as oil in the low permeability layers could not be produced easily. The results of this study are good indication of the future of WAG as a secondary recovery technique. Technical viability and economic feasibility of WAG should be studied intensively while other WAG parameters should be optimized. This study strongly suggests the use of WAG as the secondary recovery technique whenever the situation permits.\u003c/p\u003e","manuscriptTitle":"Effects of Water and Gas Injection Rates in WAG Flooding for a Heterogeneous Oil Reservoir: A Simulation Study","msid":"","msnumber":"","nonDraftVersions":[{"code":1,"date":"2025-08-08 12:15:17","doi":"10.21203/rs.3.rs-7179572/v1","editorialEvents":[{"type":"communityComments","content":0}],"status":"published","journal":{"display":true,"email":"[email protected]","identity":"researchsquare","isNatureJournal":false,"hasQc":true,"allowDirectSubmit":true,"externalIdentity":"","sideBox":"","snPcode":"","submissionUrl":"/submission","title":"Research Square","twitterHandle":"researchsquare","acdcEnabled":true,"dfaEnabled":false,"editorialSystem":"","reportingPortfolio":"","inReviewEnabled":false,"inReviewRevisionsEnabled":true}}],"origin":"","ownerIdentity":"3f3e5288-e8ec-4884-a429-aa051942a1e8","owner":[],"postedDate":"August 8th, 2025","published":true,"recentEditorialEvents":[],"rejectedJournal":[],"revision":"","amendment":"","status":"posted","subjectAreas":[],"tags":[],"updatedAt":"2025-10-09T07:38:23+00:00","versionOfRecord":[],"versionCreatedAt":"2025-08-08 12:15:17","video":"","vorDoi":"","vorDoiUrl":"","workflowStages":[]},"version":"v1","identity":"rs-7179572","journalConfig":"researchsquare"},"__N_SSP":true},"page":"/article/[identity]/[[...version]]","query":{"redirect":"/article/rs-7179572","identity":"rs-7179572","version":["v1"]},"buildId":"8U1c8b4HqxoKbykW_rLl7","isFallback":false,"isExperimentalCompile":false,"dynamicIds":[84888],"gssp":true,"scriptLoader":[]}