{"title":"Correction to: Application Of Numerical Well Testing In Strong Anisotropic Sandstone Gas Field","authors":"","doi":"10.14800/iogr.1214","DOIUrl":"https://doi.org/10.14800/iogr.1214","url":null,"abstract":"","PeriodicalId":52731,"journal":{"name":"Improved Oil and Gas Recovery","volume":" ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42305513","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Numerous laboratory and pilot tests have verified low salinity waterflooding (LSWF) as a promising enhanced oil recovery (EOR) method in carbonate reservoirs. The multi-ion exchange (MIE) and anhydrite dissolution mechanisms are widely accepted mechanisms for the LSWF. This study investigates the effects of the low salinity condensed water (LSCW) and anhydrite dissolution on oil recovery during steam injection in carbonate reservoirs. The work has been verified using actual laboratory and production data of an existing cyclic steam injection project in carbonate reservoir. Several core samples were extracted from the reservoir under study. The wettability index of two cores was measured. The first core was taken from Well-01 before starting any steam injection in its area. However, the second core was extracted from Well-02, which was drilled in the area affected by steam injection. The analysis of the production data of the 9 oil wells was performed to study the effect of anhydrite percentage on oil recovery. The analysis showed that the LSCW could alter wettability in the direction of water wet. The analysis also concluded that although the anhydrite dissolution caused alteration of wettability, the increase of anhydrite percentage could cause a reduction in reservoir quality and oil production.
{"title":"Role of the Low Salinity Condensate Water during Steam Injection in Carbonate Reservoirs","authors":"","doi":"10.14800/iogr.1229","DOIUrl":"https://doi.org/10.14800/iogr.1229","url":null,"abstract":"Numerous laboratory and pilot tests have verified low salinity waterflooding (LSWF) as a promising enhanced oil recovery (EOR) method in carbonate reservoirs. The multi-ion exchange (MIE) and anhydrite dissolution mechanisms are widely accepted mechanisms for the LSWF. This study investigates the effects of the low salinity condensed water (LSCW) and anhydrite dissolution on oil recovery during steam injection in carbonate reservoirs. The work has been verified using actual laboratory and production data of an existing cyclic steam injection project in carbonate reservoir. Several core samples were extracted from the reservoir under study. The wettability index of two cores was measured. The first core was taken from Well-01 before starting any steam injection in its area. However, the second core was extracted from Well-02, which was drilled in the area affected by steam injection. The analysis of the production data of the 9 oil wells was performed to study the effect of anhydrite percentage on oil recovery. The analysis showed that the LSCW could alter wettability in the direction of water wet. The analysis also concluded that although the anhydrite dissolution caused alteration of wettability, the increase of anhydrite percentage could cause a reduction in reservoir quality and oil production.","PeriodicalId":52731,"journal":{"name":"Improved Oil and Gas Recovery","volume":"168 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136002647","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Oil recovery from thin oil rims under a strong aquifer and large cap is challenging. Low oil recovery efficiency, water coning, gas cusping and the upward and downward shifts of the oil water contact (OWC) and gas oil contact (GOC) respectively are problems. However, studies have shown that injecting natural gas at the OWC can significantly improve oil recovery efficiency and reduce water production. But the effect of varying gas injection rates on the performance of such reservoirs needs to be studied, and that is the focus of the simulation conducted in this work. The model of a thin oil rim with a strong underlying aquifer and large gas cap in the Niger Delta was simulated under six different gas injection rates at the OWC to study the performance of the reservoir. Results show that as gas injection rate increased, the oil recovery efficiency and gas-oil ratio (GOR) increased almost linearly with the exception of gas injection rate of 2500Mscf/d which is not strong enough to push back water influx into the reservoir. The highest recovery efficiency was almost 62% at the highest gas injection rate of 15000Mscf/d which also gave the highest GOR and an insignificant volume of produced water. Every gas injection rate has its merits and demerits but the critical factors are oil recovery efficiency, volume of produced water and GOR. Hence, it is recommended that gas injection rates at the OWC be carefully selected based on goals the operating company wants to achieve.
{"title":"Effect of Gas Injection Rates on the Performance of a Thin Oil Rim: A Simulation Study","authors":"","doi":"10.14800/iogr.1242","DOIUrl":"https://doi.org/10.14800/iogr.1242","url":null,"abstract":"Oil recovery from thin oil rims under a strong aquifer and large cap is challenging. Low oil recovery efficiency, water coning, gas cusping and the upward and downward shifts of the oil water contact (OWC) and gas oil contact (GOC) respectively are problems. However, studies have shown that injecting natural gas at the OWC can significantly improve oil recovery efficiency and reduce water production. But the effect of varying gas injection rates on the performance of such reservoirs needs to be studied, and that is the focus of the simulation conducted in this work. The model of a thin oil rim with a strong underlying aquifer and large gas cap in the Niger Delta was simulated under six different gas injection rates at the OWC to study the performance of the reservoir. Results show that as gas injection rate increased, the oil recovery efficiency and gas-oil ratio (GOR) increased almost linearly with the exception of gas injection rate of 2500Mscf/d which is not strong enough to push back water influx into the reservoir. The highest recovery efficiency was almost 62% at the highest gas injection rate of 15000Mscf/d which also gave the highest GOR and an insignificant volume of produced water. Every gas injection rate has its merits and demerits but the critical factors are oil recovery efficiency, volume of produced water and GOR. Hence, it is recommended that gas injection rates at the OWC be carefully selected based on goals the operating company wants to achieve.  ","PeriodicalId":52731,"journal":{"name":"Improved Oil and Gas Recovery","volume":"77 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136002649","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In the development of ultra-deep fractured-vuggy carbonate reservoirs, normally only few wells were drilled and hydraulically fractured to create channels connecting the large vugs. Production decline at early stages due to rapid pressure decline appears to be the main problem, and water and gas injection via huff and puff mode can be applied to maintain oil production. For the targeted reservoir (6000-7500 meter depth) in the Northwest China, nitrogen injection has shown good IOR (improved oil recovery) response. In current study, injection of CO2 and methane rich natural gas with different injection-production modes was studied in the laboratory. The laboratory techniques are using a specially designed experimental set-up with multiple cavities connected by small channels to simulate the fractured-vuggy carbonate reservoir. The physical model was designed based on the characteristics of the fractured-vuggy carbonate reservoir and similarity theory, to investigate the influencing factors and the mechanisms of oil recovery of gas injection. Gas huff and puff experiments were conducted using three different injection-production modes, including vertical model with injection well at top and production well at the bottom, vertical model with injection and production wells at the bottom, and horizontal model with injection and production wells at the same end, under pressure up to 65 MPa. The minimum miscible pressure (MMP) of CO2 and natural gas with the crude oil studied were measured through a slime-tube displacement testing. The effects of gravity stabilization and miscibility on oil production were analyzed. The experimental results show that the MMP of CO2 with the targeted oil is 30.1 MPa, and over 47.6 MPa of that for the methane-rich natural gas, and the IOR performance of the methane-rich natural gas is better than that of CO2 at ultra-high pressure conditions. It indicates that the action of gravity stabilized oil displacement can be the most important mechanism in the development of high pressure fractured-vuggy reservoirs for gas injection, overshadowing the miscibility effect of CO2 for high pressure applications. The results of the study can provide important guidelines for designing gas injection processes in ultra-high pressure fractured-vuggy carbonate reservoirs.
{"title":"Experimental Study on Gas Injection for Ultra Deep and high-pressure Fractured-vuggy Carbonate Oil Reservoirs","authors":"","doi":"10.14800/iogr.1250","DOIUrl":"https://doi.org/10.14800/iogr.1250","url":null,"abstract":"In the development of ultra-deep fractured-vuggy carbonate reservoirs, normally only few wells were drilled and hydraulically fractured to create channels connecting the large vugs. Production decline at early stages due to rapid pressure decline appears to be the main problem, and water and gas injection via huff and puff mode can be applied to maintain oil production. For the targeted reservoir (6000-7500 meter depth) in the Northwest China, nitrogen injection has shown good IOR (improved oil recovery) response. In current study, injection of CO2 and methane rich natural gas with different injection-production modes was studied in the laboratory. The laboratory techniques are using a specially designed experimental set-up with multiple cavities connected by small channels to simulate the fractured-vuggy carbonate reservoir. The physical model was designed based on the characteristics of the fractured-vuggy carbonate reservoir and similarity theory, to investigate the influencing factors and the mechanisms of oil recovery of gas injection. Gas huff and puff experiments were conducted using three different injection-production modes, including vertical model with injection well at top and production well at the bottom, vertical model with injection and production wells at the bottom, and horizontal model with injection and production wells at the same end, under pressure up to 65 MPa. The minimum miscible pressure (MMP) of CO2 and natural gas with the crude oil studied were measured through a slime-tube displacement testing. The effects of gravity stabilization and miscibility on oil production were analyzed. The experimental results show that the MMP of CO2 with the targeted oil is 30.1 MPa, and over 47.6 MPa of that for the methane-rich natural gas, and the IOR performance of the methane-rich natural gas is better than that of CO2 at ultra-high pressure conditions. It indicates that the action of gravity stabilized oil displacement can be the most important mechanism in the development of high pressure fractured-vuggy reservoirs for gas injection, overshadowing the miscibility effect of CO2 for high pressure applications. The results of the study can provide important guidelines for designing gas injection processes in ultra-high pressure fractured-vuggy carbonate reservoirs.","PeriodicalId":52731,"journal":{"name":"Improved Oil and Gas Recovery","volume":"121 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136002654","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The development of the dominant channel seriously affects the water-flooding effect of the oil field and leads to a decrease in the recovery. How to effectively describe the dominant channel is an urgent problem to further improve the recovery rate of water-flooding in high water cut oilfields. Therefore, the quantitative calculation of the dominant channel’s parameters was carried out by using the seepage theory and mathematical models in this study. The reservoir that developed the dominant channel was regarded as the parallel of the normal reservoir and the dominant channel. The ineffective water injection was calculated from the ineffective circulating water model. According to the principle of equivalence, the ineffective water production of the oil well and the water production of the normal reservoir were calculated. Then the parameters of the dominant channel were quantitatively described by the volume analogy and the Carman-Kozeny formula. The interwell connectivity model was used to calculate the parameters of the dominant channel in the well group. The results showed a good agreement with the actual offshore oilfield situation, and the effectiveness of the method was verified.
{"title":"A New Method for Quantitative Description of Dominant Channels in High Water-Cut Stage","authors":"","doi":"10.14800/iogr.1212","DOIUrl":"https://doi.org/10.14800/iogr.1212","url":null,"abstract":"The development of the dominant channel seriously affects the water-flooding effect of the oil field and leads to a decrease in the recovery. How to effectively describe the dominant channel is an urgent problem to further improve the recovery rate of water-flooding in high water cut oilfields. Therefore, the quantitative calculation of the dominant channel’s parameters was carried out by using the seepage theory and mathematical models in this study. The reservoir that developed the dominant channel was regarded as the parallel of the normal reservoir and the dominant channel. The ineffective water injection was calculated from the ineffective circulating water model. According to the principle of equivalence, the ineffective water production of the oil well and the water production of the normal reservoir were calculated. Then the parameters of the dominant channel were quantitatively described by the volume analogy and the Carman-Kozeny formula. The interwell connectivity model was used to calculate the parameters of the dominant channel in the well group. The results showed a good agreement with the actual offshore oilfield situation, and the effectiveness of the method was verified.","PeriodicalId":52731,"journal":{"name":"Improved Oil and Gas Recovery","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136002671","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
{"title":"Smart Seismic Modeling - Artificial Intelligence in the Petroleum Industry","authors":"","doi":"10.14800/iogr.1203","DOIUrl":"https://doi.org/10.14800/iogr.1203","url":null,"abstract":"","PeriodicalId":52731,"journal":{"name":"Improved Oil and Gas Recovery","volume":" ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48909660","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
{"title":"A Comparative Study on Different Machine Learning Algorithms for Petroleum Production Forecasting","authors":"","doi":"10.14800/iogr.1205","DOIUrl":"https://doi.org/10.14800/iogr.1205","url":null,"abstract":"","PeriodicalId":52731,"journal":{"name":"Improved Oil and Gas Recovery","volume":" ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46381808","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Considering the long-term and slow processes of CO2 Sequestration in brine formation, it is hardly to systematically investigate the underlying mechanisms of CO2 sequestration in a saline aquifer with bench-scale experiments. In this work, a simulation research of CO2 sequestration in a real saline aquifer is proposed and conducted to probe the effects of CO2 injection on the formation and the potential CO2 sequestration mechanisms. To be specific, the simulation of CO2 sequestration is carried out with both homogeneous model and heterogeneous model. The former is aiming to investigate the effect of CO2 injection rate on the reservoir conditions and the formation properties. Also, the latter is focused on unveiling the impacts of heterogeneity of formation properties and geological structure, two importantly inherent properties of a real saline aquifer, on the CO2 distribution and trapping. The results show that the distribution of pH is affected by the distance to the injector, geological structure and heterogeneity of permeability. The lowest pH, which is controlled by the maximum formation pressure and corresponding solubility of CO2, can be found in the location of CO2 injector. The porosity changes caused by the reaction with solid minerals in both two models are quite small after 30 years of CO2 injection. Meanwhile, the maximum formation pressure is undisputedly located at the CO2 injector. Then, the formation pressure will gradually decrease with an increase in the distance to the injector satisfying a power function.
{"title":"Reservoir Simulation of CO2 Sequestration in Brine Formation","authors":"","doi":"10.14800/iogr.1227","DOIUrl":"https://doi.org/10.14800/iogr.1227","url":null,"abstract":"Considering the long-term and slow processes of CO2 Sequestration in brine formation, it is hardly to systematically investigate the underlying mechanisms of CO2 sequestration in a saline aquifer with bench-scale experiments. In this work, a simulation research of CO2 sequestration in a real saline aquifer is proposed and conducted to probe the effects of CO2 injection on the formation and the potential CO2 sequestration mechanisms. To be specific, the simulation of CO2 sequestration is carried out with both homogeneous model and heterogeneous model. The former is aiming to investigate the effect of CO2 injection rate on the reservoir conditions and the formation properties. Also, the latter is focused on unveiling the impacts of heterogeneity of formation properties and geological structure, two importantly inherent properties of a real saline aquifer, on the CO2 distribution and trapping. The results show that the distribution of pH is affected by the distance to the injector, geological structure and heterogeneity of permeability. The lowest pH, which is controlled by the maximum formation pressure and corresponding solubility of CO2, can be found in the location of CO2 injector. The porosity changes caused by the reaction with solid minerals in both two models are quite small after 30 years of CO2 injection. Meanwhile, the maximum formation pressure is undisputedly located at the CO2 injector. Then, the formation pressure will gradually decrease with an increase in the distance to the injector satisfying a power function.","PeriodicalId":52731,"journal":{"name":"Improved Oil and Gas Recovery","volume":"28 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136004428","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
{"title":"Minimum Miscibility Pressure Prediction Method Based On PSO-GBDT Model","authors":"","doi":"10.14800/iogr.1219","DOIUrl":"https://doi.org/10.14800/iogr.1219","url":null,"abstract":"","PeriodicalId":52731,"journal":{"name":"Improved Oil and Gas Recovery","volume":" ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43882795","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Alkali-surfactant-alternated-gas (ASAG) alternating injection is a method used to enhance oil recovery. In the water injection stage of the WAG process, chemicals (alkaline-surfactant) are added to the plug. This paper presents a numerical simulation study at the reservoir scale to analyze the influencing factors of ASAG process on improving recovery efficiency. The research results indicate that ASAG process can achieve an ultimate recovery efficiency of 67%, which is approximately 22% higher compared to water flooding. Among the various influencing factors, injection rate, plug volume, and chemical concentration have a significant impact on the recovery efficiency.
{"title":"Numerical Simulation of Alkali-Surfactant-Alternated-Gas(ASAG) Injection: Effects of Key Parameters","authors":"","doi":"10.14800/iogr.1249","DOIUrl":"https://doi.org/10.14800/iogr.1249","url":null,"abstract":"Alkali-surfactant-alternated-gas (ASAG) alternating injection is a method used to enhance oil recovery. In the water injection stage of the WAG process, chemicals (alkaline-surfactant) are added to the plug. This paper presents a numerical simulation study at the reservoir scale to analyze the influencing factors of ASAG process on improving recovery efficiency. The research results indicate that ASAG process can achieve an ultimate recovery efficiency of 67%, which is approximately 22% higher compared to water flooding. Among the various influencing factors, injection rate, plug volume, and chemical concentration have a significant impact on the recovery efficiency.","PeriodicalId":52731,"journal":{"name":"Improved Oil and Gas Recovery","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136004425","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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