Farzan Sahari Moghaddam, Ali Y. Hamid, M. Abdi, L. James
This study investigates the effect of various parameters on hydrate formation under two scenarios of regular and cold start-up operations in a flowline and a subsea network. Parameters including hydrate adhesion forces, required subcooling for hydrate nucleation, and a weighting parameter for hydrate-oil slip (COIL) are evaluated. The effect of methanol injection and the mentioned parameters on hydrate formation are compared to 0.2 hydrate fraction threshold from literature. Hydrate formation from oil having 184 m3/m3 GOR and 35% WC is studied using two scenarios of regular and cold start-up operations in a 6-km flowline and a subsea tieback network (consisting of two branches and a main flowline). The overall heat transfer coefficient is 22.7 W/(m2.K), and the simulation is conducted by OLGA-CSMHyK-MUTIFLASH. Slurry relative viscosity, hydrate fraction, and hydrate propensity in terms of temperature difference known as DTHYD are used as indicators, and a hydrate fraction threshold of 0.2 is considered. Adhesion forces (0.5 - 0.005 N/m), required subcooling (3.61 - 10 °C), COIL (0.2-1), and methanol injection are investigated. During regular operation, the flow pattern remains stratified in a single flowline having 35% WC and 1 COIL. By increasing the required subcooling for hydrate nucleation from 3.6 °C to 10 °C, the hydrate fraction was reduced from approximately 1.7% to zero. COIL has the greatest effect on hydrate fraction. The reduction of adhesion forces had a noticeable effect on oil viscosity compared to the other indicators. Plug formation is not expected in the studied single flowline and subsea network under normal operation. On the other hand, a potential plug based on higher hydrate formation occurs in a cold start-up operation even under the effect of the studied parameters. However, the chance of plug formation is considerably reduced by injecting 20 wt% methanol. Overall, assessing the three indicators of hydrate formation (slurry relative viscosity, hydrate fraction, and DTHYD) are critical and provide more realistic insight about hydrate formation compared to using only one of the indicators for the evaluations. This work investigates the three aforementioned indicators of hydrate formation rather than relying on only one indicator (e.g., hydrate fraction) under regular and cold restart operations. The study evaluates hydrate formation based on a hydrate fraction threshold of 0.2 for a potential plug, compared to thermodynamically preventing hydrate formation.
{"title":"Consideration of Various Parameters and Scenarios in the Simulation of Hydrate Formation","authors":"Farzan Sahari Moghaddam, Ali Y. Hamid, M. Abdi, L. James","doi":"10.2118/208881-ms","DOIUrl":"https://doi.org/10.2118/208881-ms","url":null,"abstract":"\u0000 This study investigates the effect of various parameters on hydrate formation under two scenarios of regular and cold start-up operations in a flowline and a subsea network. Parameters including hydrate adhesion forces, required subcooling for hydrate nucleation, and a weighting parameter for hydrate-oil slip (COIL) are evaluated. The effect of methanol injection and the mentioned parameters on hydrate formation are compared to 0.2 hydrate fraction threshold from literature.\u0000 Hydrate formation from oil having 184 m3/m3 GOR and 35% WC is studied using two scenarios of regular and cold start-up operations in a 6-km flowline and a subsea tieback network (consisting of two branches and a main flowline). The overall heat transfer coefficient is 22.7 W/(m2.K), and the simulation is conducted by OLGA-CSMHyK-MUTIFLASH. Slurry relative viscosity, hydrate fraction, and hydrate propensity in terms of temperature difference known as DTHYD are used as indicators, and a hydrate fraction threshold of 0.2 is considered. Adhesion forces (0.5 - 0.005 N/m), required subcooling (3.61 - 10 °C), COIL (0.2-1), and methanol injection are investigated.\u0000 During regular operation, the flow pattern remains stratified in a single flowline having 35% WC and 1 COIL. By increasing the required subcooling for hydrate nucleation from 3.6 °C to 10 °C, the hydrate fraction was reduced from approximately 1.7% to zero. COIL has the greatest effect on hydrate fraction. The reduction of adhesion forces had a noticeable effect on oil viscosity compared to the other indicators. Plug formation is not expected in the studied single flowline and subsea network under normal operation. On the other hand, a potential plug based on higher hydrate formation occurs in a cold start-up operation even under the effect of the studied parameters. However, the chance of plug formation is considerably reduced by injecting 20 wt% methanol. Overall, assessing the three indicators of hydrate formation (slurry relative viscosity, hydrate fraction, and DTHYD) are critical and provide more realistic insight about hydrate formation compared to using only one of the indicators for the evaluations.\u0000 This work investigates the three aforementioned indicators of hydrate formation rather than relying on only one indicator (e.g., hydrate fraction) under regular and cold restart operations. The study evaluates hydrate formation based on a hydrate fraction threshold of 0.2 for a potential plug, compared to thermodynamically preventing hydrate formation.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80325335","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}
Gas and water transport behavior, which is controlled by the pore characteristics and capillarity in hydrate-bearing sediments (HBS), is one of the key factors affecting the gas production. Hydrate distribution morphology (HDM) can significantly influence the pore structures of HBS, affecting the relative permeabilities of gas and water. To elucidate the impacts of HDM in microscopic scale, a phase-field lattice Boltzmann (LB) model is developed to describe the gas and water transport in HBS.To simulate the transport of immiscible fluids, which exist obvious density and viscosity contrasts, a phase-field LB model with the conservative form of interface-tracking equation is developed to suppress the spurious currents at phase interfaces. To describe the fluid-solid interactions, the bounce-back condition is applied for both solid phases (hydrate and grains) to achieve the non-slip condition and the wettability condition is applied for grains and hydrate to describe the wettability behavior. To improve the numerical stability, the multi-relaxation-time (MRT) collision operator is applied and the discretization schemes with 8th order accuracy for the gradient operator are selected. In this work, we first validated our model by applying several benchmark cases aiming at fluids with obvious density contrasts such as the layered Couette/Poiseuille flows, Rayleigh–Taylor instability. Then the synthetic geometries of the pore-filling and grain-coating HBS with several hydrate saturation (Shyd) were constructed by guaranteeing the same extent of connectivity. Then the steady-state relative permeability measurement and drainage capillary pressure measurement processes were simulated by the LB model for two HDM cases under several Shyd. The results showed that in the hydrophilic HBS, the relative permeability of gas in the pore-filling case is obviously larger than that in the grain-coating case at the same Shyd, and larger capillary pressure can be obtained in the pore-filling case. In addition, as the Shyd increased, it would notably enhance these differences of fluids relative permeability and capillary pressure between two HDM cases. Because the HDM can not only influence the pore space structures but also the wettability of the porous medium by creating solid surfaces of varying wettability, the distribution and transport of fluid phases in different HDM cases can be obviously affected. The phase-filed LB model applied in this study is capable to handle and suppress the spurious currents at phase interfaces, ensuring a satisfactory numerical stability and accuracy. Thus, the real density and viscosity contrasts between the water and gas under the in-situ thermodynamic conditions can be considered in the simulation. The impacts of HDM on the gas and water transport were quantitively analyzed by simulating multiphase flow processes in HBS.
{"title":"Pore-Scale Modellings on the Impacts of Hydrate Distribution Morphology on Gas and Water Transport in Hydrate-Bearing Sediments","authors":"Zhuoran Li, Jiahui You, G. Qin","doi":"10.2118/208983-ms","DOIUrl":"https://doi.org/10.2118/208983-ms","url":null,"abstract":"\u0000 Gas and water transport behavior, which is controlled by the pore characteristics and capillarity in hydrate-bearing sediments (HBS), is one of the key factors affecting the gas production. Hydrate distribution morphology (HDM) can significantly influence the pore structures of HBS, affecting the relative permeabilities of gas and water. To elucidate the impacts of HDM in microscopic scale, a phase-field lattice Boltzmann (LB) model is developed to describe the gas and water transport in HBS.To simulate the transport of immiscible fluids, which exist obvious density and viscosity contrasts, a phase-field LB model with the conservative form of interface-tracking equation is developed to suppress the spurious currents at phase interfaces. To describe the fluid-solid interactions, the bounce-back condition is applied for both solid phases (hydrate and grains) to achieve the non-slip condition and the wettability condition is applied for grains and hydrate to describe the wettability behavior. To improve the numerical stability, the multi-relaxation-time (MRT) collision operator is applied and the discretization schemes with 8th order accuracy for the gradient operator are selected. In this work, we first validated our model by applying several benchmark cases aiming at fluids with obvious density contrasts such as the layered Couette/Poiseuille flows, Rayleigh–Taylor instability. Then the synthetic geometries of the pore-filling and grain-coating HBS with several hydrate saturation (Shyd) were constructed by guaranteeing the same extent of connectivity. Then the steady-state relative permeability measurement and drainage capillary pressure measurement processes were simulated by the LB model for two HDM cases under several Shyd. The results showed that in the hydrophilic HBS, the relative permeability of gas in the pore-filling case is obviously larger than that in the grain-coating case at the same Shyd, and larger capillary pressure can be obtained in the pore-filling case. In addition, as the Shyd increased, it would notably enhance these differences of fluids relative permeability and capillary pressure between two HDM cases. Because the HDM can not only influence the pore space structures but also the wettability of the porous medium by creating solid surfaces of varying wettability, the distribution and transport of fluid phases in different HDM cases can be obviously affected. The phase-filed LB model applied in this study is capable to handle and suppress the spurious currents at phase interfaces, ensuring a satisfactory numerical stability and accuracy. Thus, the real density and viscosity contrasts between the water and gas under the in-situ thermodynamic conditions can be considered in the simulation. The impacts of HDM on the gas and water transport were quantitively analyzed by simulating multiphase flow processes in HBS.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"45 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88077099","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}
A. Hajizadeh, Mohamad Mohamadi-Baghmolaei, F. Mirghaderi, R. Azin, S. Zendehboudi, Taghi Saneei, H. Rajaei, Sajjad Keshavarzian
Gas condensate stabilization is a common process in gas refineries and petrochemical industries. This process is energy-consuming since it uses distillation columns and furnaces to separate different cuts from the condensate feed. This study aims to improve the performance of the gas condensate stabilization unit in a large petrochemical company in terms of energy efficiency and loss prevention. The case under investigation is the gas condensate stabilization unit in the Nouri Petrochemical Company, treating 568 t/h of raw condensate feed. This plant includes two distillation columns, two furnaces, pumps, heat exchangers, and air coolers. A hybrid energy and exergy analysis is conducted in this study. First, the validation of the simulation phase is performed, and a parametric sensitivity analysis is conducted to explore the effects of various parameters, such as operating temperature and pressure, on the process performance. After that, the most influential variables are identified using thermodynamic analyses for optimization and design purposes. An optimization method is employed to attain the maximum production improvement and exergy efficiency. The exergy analysis shows 187.4 MW total exergy destruction in the plant; furnaces account for 79% of the total exergy destruction. According to the sensitivity analysis results, the energy consumption of the process could be reduced by 33.7 MW; this is an 18% reduction in the plant's energy consumption. The optimal process conditions outperform the current and design states (4.6% improvement in exergy efficiency). The fuel gas consumption is reduced by 2.1 t/h, leading to a reduction of 128 t/d CO2 emissions.
{"title":"Improvement of Energy Efficiency in Gas Condensate Stabilization Unit: Process Optimization Through Exergy Analysis","authors":"A. Hajizadeh, Mohamad Mohamadi-Baghmolaei, F. Mirghaderi, R. Azin, S. Zendehboudi, Taghi Saneei, H. Rajaei, Sajjad Keshavarzian","doi":"10.2118/208957-ms","DOIUrl":"https://doi.org/10.2118/208957-ms","url":null,"abstract":"\u0000 Gas condensate stabilization is a common process in gas refineries and petrochemical industries. This process is energy-consuming since it uses distillation columns and furnaces to separate different cuts from the condensate feed. This study aims to improve the performance of the gas condensate stabilization unit in a large petrochemical company in terms of energy efficiency and loss prevention. The case under investigation is the gas condensate stabilization unit in the Nouri Petrochemical Company, treating 568 t/h of raw condensate feed. This plant includes two distillation columns, two furnaces, pumps, heat exchangers, and air coolers. A hybrid energy and exergy analysis is conducted in this study. First, the validation of the simulation phase is performed, and a parametric sensitivity analysis is conducted to explore the effects of various parameters, such as operating temperature and pressure, on the process performance. After that, the most influential variables are identified using thermodynamic analyses for optimization and design purposes.\u0000 An optimization method is employed to attain the maximum production improvement and exergy efficiency. The exergy analysis shows 187.4 MW total exergy destruction in the plant; furnaces account for 79% of the total exergy destruction. According to the sensitivity analysis results, the energy consumption of the process could be reduced by 33.7 MW; this is an 18% reduction in the plant's energy consumption. The optimal process conditions outperform the current and design states (4.6% improvement in exergy efficiency). The fuel gas consumption is reduced by 2.1 t/h, leading to a reduction of 128 t/d CO2 emissions.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79843733","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}
K. Havre, C. Trudvang, G. Kjørrefjord, Sonia Smith, Colin C King, Jaqueline Vinicombe, Trevor A. Roberts
Cenovus Energy has deployed a rigorous multiphase flow assurance online solution to detect leaks and monitor hydrate formation conditions at the White Rose Field and satellite extensions 350 km east of St. John's, Newfoundland and Labrador, Canada. Twenty-five production wells are connected via subsea manifolds to the SeaRose floating production storage and offloading (FPSO) system, through four flexible flowlines and risers. An online subsea advisor has been developed to provide control-room operators with enhanced monitoring/visibility in detecting potential leaks and hydrate formation within the subsea system, including the mechanical flowline connectors. The online solution makes use of a commercial multiphase flow simulator. An online real-time mode (RTM) was developed to simulate the production loops connecting the manifolds to the SeaRose FPSO. The wells are equipped with multiphase flowmeters, which are calibrated at regular intervals during well test campaigns. Reconciled flow rates from the meters are used as inlet boundary conditions to the real-time multiphase model. This RTM acts as a digital twin of the production network. As part of the online subsea advisor leak detection system (LDS), Schlumberger has delivered improved algorithms for leak detection in multiphase production networks. The solution makes use of 14 signatures indicating leaks, which form the basis for a generalized multivariable LDS. Artificial intelligence and data clustering are used to determine whether the signature vector indicates a leak. By making use of multiple leak signatures, the system becomes more robust with respect to sensor faults and drift. Multiple signatures also reduce the number of false alarms and make the LDS less dependent on model calibration. The use of signatures, artificial intelligence and data clustering is new compared to traditional mass balance model-based LDS. The theory is described with results from four of these 14 signatures in the paper. The advisor system monitors the potential for hydrate formation conditions and calculates the hydrate margin at the flowline connectors, which have been identified as potential "cold spots." A rigorous flowline connector model has been implemented at positions along the flow path where they exist in the field. This model is fine-tuned to estimate mechanical flowline connector wall temperatures. This gives the control-room operators a realistic estimate of reaction time to manage an emergency shutdown and initiates an alarm when hydrate conditions will be reached, prompting immediate action of predefined safeguard measures.
{"title":"Use of Rigorous Multiphase Flow Models for Leak Detection and Online Flow Assurance","authors":"K. Havre, C. Trudvang, G. Kjørrefjord, Sonia Smith, Colin C King, Jaqueline Vinicombe, Trevor A. Roberts","doi":"10.2118/208899-ms","DOIUrl":"https://doi.org/10.2118/208899-ms","url":null,"abstract":"\u0000 Cenovus Energy has deployed a rigorous multiphase flow assurance online solution to detect leaks and monitor hydrate formation conditions at the White Rose Field and satellite extensions 350 km east of St. John's, Newfoundland and Labrador, Canada. Twenty-five production wells are connected via subsea manifolds to the SeaRose floating production storage and offloading (FPSO) system, through four flexible flowlines and risers.\u0000 An online subsea advisor has been developed to provide control-room operators with enhanced monitoring/visibility in detecting potential leaks and hydrate formation within the subsea system, including the mechanical flowline connectors. The online solution makes use of a commercial multiphase flow simulator. An online real-time mode (RTM) was developed to simulate the production loops connecting the manifolds to the SeaRose FPSO. The wells are equipped with multiphase flowmeters, which are calibrated at regular intervals during well test campaigns. Reconciled flow rates from the meters are used as inlet boundary conditions to the real-time multiphase model. This RTM acts as a digital twin of the production network.\u0000 As part of the online subsea advisor leak detection system (LDS), Schlumberger has delivered improved algorithms for leak detection in multiphase production networks. The solution makes use of 14 signatures indicating leaks, which form the basis for a generalized multivariable LDS. Artificial intelligence and data clustering are used to determine whether the signature vector indicates a leak. By making use of multiple leak signatures, the system becomes more robust with respect to sensor faults and drift. Multiple signatures also reduce the number of false alarms and make the LDS less dependent on model calibration. The use of signatures, artificial intelligence and data clustering is new compared to traditional mass balance model-based LDS. The theory is described with results from four of these 14 signatures in the paper.\u0000 The advisor system monitors the potential for hydrate formation conditions and calculates the hydrate margin at the flowline connectors, which have been identified as potential \"cold spots.\" A rigorous flowline connector model has been implemented at positions along the flow path where they exist in the field. This model is fine-tuned to estimate mechanical flowline connector wall temperatures. This gives the control-room operators a realistic estimate of reaction time to manage an emergency shutdown and initiates an alarm when hydrate conditions will be reached, prompting immediate action of predefined safeguard measures.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84400113","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}
Jingyi Zhu, Hao Wang, Zhaozhong Yang, Xiaogang Li, Jie Zhou
For the desorption of methane, thermal stimulation is an alternative to develop coalbed methane (CBM) when it is difficult to reduce the formation pressure. Microwave heating is a promising thermal method to increase the gas recovery of CBM especially for the CBM reservoir with high heterogeneity and low water content. The current study aims to establish a fully coupled numerical model to understand the enhanced gas recovery (EGR) mechanism of CBM under microwave heating. In the study, the CBM reservoir model was developed first. Then a mathematical model considering electromagnetic excitation, heat transfer, mass transfer, Langmuir adsorption, and fluid flow was built. Moreover, some important parameters were set as temperature-dependent to achieve the coupling effects among the multiphysics. Based on the above two models, a fully coupled electromagnetic-thermal-hydraulic-mechanical model was solved by the finite element, so that the distributions of electric field, reservoir temperature, methane concentration were able to be investigated. Finally, a sensitivity analysis including water content, microwave power and microwave heating mode was done based on the heating efficiency and EGR. Under microwave heating, the electric field distributes near the microwave heater with the maximum electric intensity as 1.07×103 V/m. The high electric intensity and low thermal conductivity easily enables microwaves to generate the required temperature region within CBM reservoir, so that 200 W power was applied to continuous heat the formation. Under 1 day, the maximum temperature of CBM reservoir increased to 81 °C, enabling the desorption of methane. Moreover, heating efficiency is controlled by the dielectric properties as well as electric field intensity of the CBM reservoir, although the existence of water content increases the dielectric constant within the CBM reservoir. In addition, by setting the temperature-dependent properties, microwave heating shows the ability to induce the pore volume changes by generating thermal stress, so that the porosity and permeability of CBM reservoir near the heater increase from 0.15 to 0.24 and from 0.36 mD to 1.47 mD, respectively. Based on the above positive effects of microwave heating, the CBM recovery could be significantly enhanced. Finally, in order to transfer the heat deeper into the reservoir, the feasibility of stepwise microwave heating mode has been successfully proven based on the temperature distribution within the CBM reservoir. In the study, microwave has showed great potential in enhancing the CBM recovery resulting from its high heating efficiency and pore induction effect. The results presented in this paper can provide comprehensive guidance for the optimization of microwave heating parameters.
{"title":"Thermal Stimulation on Enhanced Coalbed Methane Recovery Under Microwave Heating Based on a Fully Coupled Numerical Model","authors":"Jingyi Zhu, Hao Wang, Zhaozhong Yang, Xiaogang Li, Jie Zhou","doi":"10.2118/208904-ms","DOIUrl":"https://doi.org/10.2118/208904-ms","url":null,"abstract":"\u0000 For the desorption of methane, thermal stimulation is an alternative to develop coalbed methane (CBM) when it is difficult to reduce the formation pressure. Microwave heating is a promising thermal method to increase the gas recovery of CBM especially for the CBM reservoir with high heterogeneity and low water content. The current study aims to establish a fully coupled numerical model to understand the enhanced gas recovery (EGR) mechanism of CBM under microwave heating.\u0000 In the study, the CBM reservoir model was developed first. Then a mathematical model considering electromagnetic excitation, heat transfer, mass transfer, Langmuir adsorption, and fluid flow was built. Moreover, some important parameters were set as temperature-dependent to achieve the coupling effects among the multiphysics. Based on the above two models, a fully coupled electromagnetic-thermal-hydraulic-mechanical model was solved by the finite element, so that the distributions of electric field, reservoir temperature, methane concentration were able to be investigated. Finally, a sensitivity analysis including water content, microwave power and microwave heating mode was done based on the heating efficiency and EGR.\u0000 Under microwave heating, the electric field distributes near the microwave heater with the maximum electric intensity as 1.07×103 V/m. The high electric intensity and low thermal conductivity easily enables microwaves to generate the required temperature region within CBM reservoir, so that 200 W power was applied to continuous heat the formation. Under 1 day, the maximum temperature of CBM reservoir increased to 81 °C, enabling the desorption of methane. Moreover, heating efficiency is controlled by the dielectric properties as well as electric field intensity of the CBM reservoir, although the existence of water content increases the dielectric constant within the CBM reservoir. In addition, by setting the temperature-dependent properties, microwave heating shows the ability to induce the pore volume changes by generating thermal stress, so that the porosity and permeability of CBM reservoir near the heater increase from 0.15 to 0.24 and from 0.36 mD to 1.47 mD, respectively. Based on the above positive effects of microwave heating, the CBM recovery could be significantly enhanced. Finally, in order to transfer the heat deeper into the reservoir, the feasibility of stepwise microwave heating mode has been successfully proven based on the temperature distribution within the CBM reservoir.\u0000 In the study, microwave has showed great potential in enhancing the CBM recovery resulting from its high heating efficiency and pore induction effect. The results presented in this paper can provide comprehensive guidance for the optimization of microwave heating parameters.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83303862","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}
H. Izadi, Morteza Roostaei, Mahdi Mahmoudi, S. A. Hosseini, M. Soroush, G. Rosi, J. Stevenson, Aubrey Tuttle, Colby Sutton, J. Leung, Vahidoddin Fattahpour
Drilling the horizontal wells was the beginning of unlocking the enormous potential of Western Canada oil-sands. However, several technical and operational challenges avoid the so-called extended reach Steam Assisted Gravity Drainage (SAGD) wells. The last few years drive to reduce Capital Expenditures (CAPEX) encouraged the development of key innovative tools to make long thermal wells a reality. SAGD pad development using maximum possible well-length has taken significant leaps in economical assessment of SAGD projects. The goal of this paper is investigating the impact of Flow Control Devices (FCDs) on the overall performance of the long wells in SAGD projects. In this paper, seven major thermal projects in Western Canada were investigated. Production history of all the wells is normalized by the variation of the geological condition, operational parameters, and well length. Following a convention in the industry, the wells with lateral length longer than 850 meters are labeled as "long" and those shorter than 850 meters are labeled as "short". Eventually, normalized oil production by long wells completed or retrofitted with FCDs is compared with those without FCDs to supply insight on the role of completion design on relative performance of drilling long wells. The comparison has been conducted with respect to different completion types such as Liner or Tubing Deployed FCDs (LDFCD or TDFCDs). On average, long wells produced 2% more normalized oil compared to short wells for all projects, while they produced on average 16% more normalized oil in the projects 1, 2, 6, and 7 in which long wells successfully drilled. The historical production performances show that FCDs are the key enablers and innovative strategy to drill longer wells. For successful long wells with FCDs, the normalized oil production is improved as high as 81%, and the improvement rate is 108% and 10% for LD and TD FCDs, respectively. Furthermore, the completion strategy of combining long wells with FCDs improved the normalized oil production about 33% compared to short wells. This study shows that switching from short wells to long wells in SAGD projects and completing them with FCDs is a synergic approach to increase the oil production (33%). The results of this paper confirmed that drilling long wells with FCDs is a win-win strategy resulted in more oil production compared to long/ short wells without FCDs; since CAPEX is reduced by long wells and oil production is increased by FCDs. The results also help completion and production engineers to get a better understanding of the contribution of FCDs in long lateral wells.
{"title":"The Impact of Increase in Lateral Length on Production Performance of Horizontal Thermal Wells","authors":"H. Izadi, Morteza Roostaei, Mahdi Mahmoudi, S. A. Hosseini, M. Soroush, G. Rosi, J. Stevenson, Aubrey Tuttle, Colby Sutton, J. Leung, Vahidoddin Fattahpour","doi":"10.2118/208977-ms","DOIUrl":"https://doi.org/10.2118/208977-ms","url":null,"abstract":"\u0000 Drilling the horizontal wells was the beginning of unlocking the enormous potential of Western Canada oil-sands. However, several technical and operational challenges avoid the so-called extended reach Steam Assisted Gravity Drainage (SAGD) wells. The last few years drive to reduce Capital Expenditures (CAPEX) encouraged the development of key innovative tools to make long thermal wells a reality. SAGD pad development using maximum possible well-length has taken significant leaps in economical assessment of SAGD projects. The goal of this paper is investigating the impact of Flow Control Devices (FCDs) on the overall performance of the long wells in SAGD projects.\u0000 In this paper, seven major thermal projects in Western Canada were investigated. Production history of all the wells is normalized by the variation of the geological condition, operational parameters, and well length. Following a convention in the industry, the wells with lateral length longer than 850 meters are labeled as \"long\" and those shorter than 850 meters are labeled as \"short\". Eventually, normalized oil production by long wells completed or retrofitted with FCDs is compared with those without FCDs to supply insight on the role of completion design on relative performance of drilling long wells. The comparison has been conducted with respect to different completion types such as Liner or Tubing Deployed FCDs (LDFCD or TDFCDs).\u0000 On average, long wells produced 2% more normalized oil compared to short wells for all projects, while they produced on average 16% more normalized oil in the projects 1, 2, 6, and 7 in which long wells successfully drilled. The historical production performances show that FCDs are the key enablers and innovative strategy to drill longer wells. For successful long wells with FCDs, the normalized oil production is improved as high as 81%, and the improvement rate is 108% and 10% for LD and TD FCDs, respectively. Furthermore, the completion strategy of combining long wells with FCDs improved the normalized oil production about 33% compared to short wells. This study shows that switching from short wells to long wells in SAGD projects and completing them with FCDs is a synergic approach to increase the oil production (33%).\u0000 The results of this paper confirmed that drilling long wells with FCDs is a win-win strategy resulted in more oil production compared to long/ short wells without FCDs; since CAPEX is reduced by long wells and oil production is increased by FCDs. The results also help completion and production engineers to get a better understanding of the contribution of FCDs in long lateral wells.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"66 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90715934","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}
Junli Huang, Qingyou Meng, B. Chang, Chao Wang, Youliang Zeng, Xingbao Wu, Chengwen He
In the northern part of the South China Sea, P oilfield entered the mature stage with a high water cut. As an important contribution to the sustainable development of this field, a horizonal infill campaign targeted the unexploited areas for their valuable remaining oil for improving oil recovery. However, the sparse well control and low-resolution seismic data induced high uncertainties regarding the structural profile, reservoir properties, effective oil column, and remaining reserves with the bottomwater drive in the infill well area. These uncertainties greatly affected the production steering efficiency in the complex reservoirs and well performance, which cannot be effectively addressed by the conventional logging and modeling technologies. Predrilling modeling results and global successful cases could increase operators the confidence in using the high-definition boundary detection service (HDBDS) for achieving well objectives. Without any artificial assumptions, HDBDS could provide the stochastic resistivity inversion to remotely identify the quantitative subsurface features, including layer numbers, resistivity and anisotropy distribution, thickness, and dip. In the specific operation area, the inversion can detect the reservoir features up to 3 m from the borehole, which could quantitatively reconstruct the subsurface profile to efficiently guide the horizontal geosteering operation for maximum standoff from the water zone. Furthermore, the production steering can be enhanced through optimizing the corresponding water-controlled completion configurations. During the real-time execution of the horizontal infill wells with an approximate 500- to 600-m section, HDBDS inversion could map the effective boundaries with a distance of up to approximately 3 m, including reservoir top and bottom, water zone top, as well as some interbed boundaries. Combining conventional measurements and HDBDS inversion, the subsurface model was quantitatively reconstructed with the obvious deviations from the original elements. Subsequently, the horizontal wells were precisely controlled for enough oil column, even with a shorter production interval than prognosis in some wells. In the updated reservoir model, the inflow control device (ICD) water-controlled completion configuration was specifically optimized to delay bottomwater breakthrough. As a result, the effective production steering was achieved, with the actual well performance better than expected. Furthermore, the oil trap column and remaining oil reserves could be reassessed to evaluate the production potential and further development direction in this field. Generally, HDBDS inversion could update the quantitative model to induce the production steering, which was valuable to contribute to the sustainability of this bottomwater field in the deep-development stage.
{"title":"Quantitative Production Steering through High-Definition Boundary Detection Service for the Sustainable Development of the Bottomwater Reservoir","authors":"Junli Huang, Qingyou Meng, B. Chang, Chao Wang, Youliang Zeng, Xingbao Wu, Chengwen He","doi":"10.2118/208892-ms","DOIUrl":"https://doi.org/10.2118/208892-ms","url":null,"abstract":"\u0000 In the northern part of the South China Sea, P oilfield entered the mature stage with a high water cut. As an important contribution to the sustainable development of this field, a horizonal infill campaign targeted the unexploited areas for their valuable remaining oil for improving oil recovery. However, the sparse well control and low-resolution seismic data induced high uncertainties regarding the structural profile, reservoir properties, effective oil column, and remaining reserves with the bottomwater drive in the infill well area. These uncertainties greatly affected the production steering efficiency in the complex reservoirs and well performance, which cannot be effectively addressed by the conventional logging and modeling technologies.\u0000 Predrilling modeling results and global successful cases could increase operators the confidence in using the high-definition boundary detection service (HDBDS) for achieving well objectives. Without any artificial assumptions, HDBDS could provide the stochastic resistivity inversion to remotely identify the quantitative subsurface features, including layer numbers, resistivity and anisotropy distribution, thickness, and dip. In the specific operation area, the inversion can detect the reservoir features up to 3 m from the borehole, which could quantitatively reconstruct the subsurface profile to efficiently guide the horizontal geosteering operation for maximum standoff from the water zone. Furthermore, the production steering can be enhanced through optimizing the corresponding water-controlled completion configurations.\u0000 During the real-time execution of the horizontal infill wells with an approximate 500- to 600-m section, HDBDS inversion could map the effective boundaries with a distance of up to approximately 3 m, including reservoir top and bottom, water zone top, as well as some interbed boundaries. Combining conventional measurements and HDBDS inversion, the subsurface model was quantitatively reconstructed with the obvious deviations from the original elements. Subsequently, the horizontal wells were precisely controlled for enough oil column, even with a shorter production interval than prognosis in some wells. In the updated reservoir model, the inflow control device (ICD) water-controlled completion configuration was specifically optimized to delay bottomwater breakthrough. As a result, the effective production steering was achieved, with the actual well performance better than expected. Furthermore, the oil trap column and remaining oil reserves could be reassessed to evaluate the production potential and further development direction in this field.\u0000 Generally, HDBDS inversion could update the quantitative model to induce the production steering, which was valuable to contribute to the sustainability of this bottomwater field in the deep-development stage.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89781346","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}
Bo Zhang, Zhiwei Ma, Dongming Zheng, R. Chalaturnyk, J. Boisvert
Weak shale beddings are widely distributed in the overburden and reservoir of oil sand deposits and lead to reduced anisotropic shear strength. Understanding the shear strength of the overburden and the reservoir is important in risk assessment of slope stability in open-pit mining and caprock integrity of in-situ thermal recovery of oil sands while optimizing the production of bitumen. Due to the restrictions of computational efficiency, cells used for simulation cannot be smaller enough to capture the details of heterogeneity in the reservoir. Therefore, a robust and efficient upscaling technique is important for modeling the impact of heterogeneity on the deformation and failure of oil sands during mining and in-situ recovery. However, current analytical and numerical upscaling techniques cannot provide computationally efficient geomechanical models that consider the impact of inclined shale beddings on shear strength. Therefore, we propose a machine learning enhanced upscaling (MLEU) technique that leverages the accuracy of local numerical upscaling and the efficiency of machine learning techniques. MLEU generates a fast and accurate machine learning-based proxy model using an artificial neural network (ANN) to predict the anisotropic shear strength of heterogeneous oil sands embedded with shale beddings. The trained model improves accuracy by 12%-76% compared to traditional methods such as response surface methodology (RSM). MLEU provides a reasonable estimate of anisotropic shear strength while considering uncertainties caused by different configurations of shale beddings. With the increasing demand for regional scale modeling of geotechnical problems, the proposed MLEU technique can be extended to other geological settings where weak beddings play a significant role and the impact of heterogeneity on shear strength is important.
{"title":"Machine Learning Enhanced Upscaling of Anisotropic Shear Strength for Heterogeneous Oil Sands","authors":"Bo Zhang, Zhiwei Ma, Dongming Zheng, R. Chalaturnyk, J. Boisvert","doi":"10.2118/208885-ms","DOIUrl":"https://doi.org/10.2118/208885-ms","url":null,"abstract":"\u0000 Weak shale beddings are widely distributed in the overburden and reservoir of oil sand deposits and lead to reduced anisotropic shear strength. Understanding the shear strength of the overburden and the reservoir is important in risk assessment of slope stability in open-pit mining and caprock integrity of in-situ thermal recovery of oil sands while optimizing the production of bitumen.\u0000 Due to the restrictions of computational efficiency, cells used for simulation cannot be smaller enough to capture the details of heterogeneity in the reservoir. Therefore, a robust and efficient upscaling technique is important for modeling the impact of heterogeneity on the deformation and failure of oil sands during mining and in-situ recovery. However, current analytical and numerical upscaling techniques cannot provide computationally efficient geomechanical models that consider the impact of inclined shale beddings on shear strength. Therefore, we propose a machine learning enhanced upscaling (MLEU) technique that leverages the accuracy of local numerical upscaling and the efficiency of machine learning techniques. MLEU generates a fast and accurate machine learning-based proxy model using an artificial neural network (ANN) to predict the anisotropic shear strength of heterogeneous oil sands embedded with shale beddings. The trained model improves accuracy by 12%-76% compared to traditional methods such as response surface methodology (RSM). MLEU provides a reasonable estimate of anisotropic shear strength while considering uncertainties caused by different configurations of shale beddings. With the increasing demand for regional scale modeling of geotechnical problems, the proposed MLEU technique can be extended to other geological settings where weak beddings play a significant role and the impact of heterogeneity on shear strength is important.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"74 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85865054","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}
A significant amount of hydrocarbon in reservoirs is inaccessible even after deploying enhanced oil recovery methods such as gas, water, and chemical injections. Foams have been used for mobility control and fluid diversion for gas-based enhanced oil recovery, but they often lack stability in reservoir conditions. This study introduces the application of highly stable nanoparticle-based foam (nanofoam) for gas and water diversion and improving sweep efficiency and CO2 storage. A series of flow experiments in uniquely designed dual porous media were performed to investigate the performance of nanofoam in fluid diversion, sweep improvement, and CO2 storage. A permeability contrast of 5 was created to mimic the heterogeneity and fluid diversion capability of different fluids including CO2 gas, water, surfactant-based CO2 foam, and nanofoam. High permeability and low permeability porous media were saturated with water and oil (viscosity of 20 cp) respectively, mimicking a swept thief zone and bypassed oil zone. Two different types of nanoparticles were used to stabilize the nanofoam (silica-based and cellulose-based nanoparticles). These nanofoams were compared with a conventional foam stabilized only by surfactant. Due to high mobility contrast, injecting CO2 and water resulted only in displacement of water from the high permeability core, with negligible flow into the oil-saturated core. Foam was then injected with the intention of preferentially filling the high permeability core, so that subsequent CO2/water injection would be diverted into the oil-saturated core. Although surfactant foam generated relatively strong foam, it failed to divert subsequent water/CO2 into the oil-saturated core. The amount of oil recovery and additional CO2 storage was minimal. On the other hand, nanofoam (made with either type of nanoparticles) diverted both water and CO2 to the low permeability media improving oil recovery and increasing CO2 storage. Compared to pure CO2/water injection, nanofoam enhanced the incremental oil recovery by 40% of original oil in place with additional CO2 storage. This study reveals that an engineered designed nanofoam could result in step-change improvement of conventional foams performance hence delivering the results desired in field applications. A highly stable foam can play an important role to access more pore space for CO2 storage and which is inaccessible otherwise without drilling new wells.
{"title":"A Step-Change Improvement in Fluid Diversion, Oil Sweep Efficiency, and CO2 Storage Using Novel Nanoparticle-Based Foam","authors":"A. Telmadarreie, Christopher Johnsen, S. Bryant","doi":"10.2118/208933-ms","DOIUrl":"https://doi.org/10.2118/208933-ms","url":null,"abstract":"\u0000 A significant amount of hydrocarbon in reservoirs is inaccessible even after deploying enhanced oil recovery methods such as gas, water, and chemical injections. Foams have been used for mobility control and fluid diversion for gas-based enhanced oil recovery, but they often lack stability in reservoir conditions. This study introduces the application of highly stable nanoparticle-based foam (nanofoam) for gas and water diversion and improving sweep efficiency and CO2 storage.\u0000 A series of flow experiments in uniquely designed dual porous media were performed to investigate the performance of nanofoam in fluid diversion, sweep improvement, and CO2 storage. A permeability contrast of 5 was created to mimic the heterogeneity and fluid diversion capability of different fluids including CO2 gas, water, surfactant-based CO2 foam, and nanofoam. High permeability and low permeability porous media were saturated with water and oil (viscosity of 20 cp) respectively, mimicking a swept thief zone and bypassed oil zone. Two different types of nanoparticles were used to stabilize the nanofoam (silica-based and cellulose-based nanoparticles). These nanofoams were compared with a conventional foam stabilized only by surfactant.\u0000 Due to high mobility contrast, injecting CO2 and water resulted only in displacement of water from the high permeability core, with negligible flow into the oil-saturated core. Foam was then injected with the intention of preferentially filling the high permeability core, so that subsequent CO2/water injection would be diverted into the oil-saturated core. Although surfactant foam generated relatively strong foam, it failed to divert subsequent water/CO2 into the oil-saturated core. The amount of oil recovery and additional CO2 storage was minimal. On the other hand, nanofoam (made with either type of nanoparticles) diverted both water and CO2 to the low permeability media improving oil recovery and increasing CO2 storage. Compared to pure CO2/water injection, nanofoam enhanced the incremental oil recovery by 40% of original oil in place with additional CO2 storage.\u0000 This study reveals that an engineered designed nanofoam could result in step-change improvement of conventional foams performance hence delivering the results desired in field applications. A highly stable foam can play an important role to access more pore space for CO2 storage and which is inaccessible otherwise without drilling new wells.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90651281","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 recent years, the Flemish Pass Basin has been gaining momentum as an area of potential high-volume resources on the frontier of remote, deep-water offshore oil development. This simulation study utilizes three sector models representing regional, discovered reservoirs, and two tuned fluid models representing oil sampled from wells in the Flemish Pass Basin. Generally speaking, WAG is considered a late-life enhanced oil recovery (EOR) technique, while implementing WAG immediately upon first oil for secondary recovery is less common; however, may be equally or more valuable. This study aims to evaluate three secondary oil recovery methods, water flooding, gas flooding, and water-alternating-gas (WAG) flooding. Each recovery method is simulated with Schlumberger’s ECLIPSE reservoir simulator and uses a combination of three distinct reservoir geo-models and two fluid models. This study is a sensitivity analysis using geo-models that represent three discovered regions and two sampled fluids from the Flemish Pass Basin. The study is aimed at evaluating the effects of the various recovery methods over a duration of either five- or twenty-year forecast periods. Results from this study capture an inherent uncertainty by drawing from eighteen simulation cases to quantify the relative benefit of each recovery method. These results indicate that using WAG as a secondary recovery method can yield a 4% to 10% increase in recovery over water or gas flood, and that secondary WAG can extend a well pair’s production plateau by up to 80% in specific circumstances. Further observations indicate that secondary WAG in light oil reservoirs yield a ∼10% increase in recovery over secondary water or gas flooding. Using WAG in a medium oil reservoir yields a 4% to 9% increase in recovery over water flood, and a 2% to 16% increase in recovery over gas flood. In terms of geology, WAG is observed to be most valuable in ultra-high-quality reservoirs. The better the reservoir quality, the more recovery improvement. In terms of fluids, the medium oil responds best to the gas injection phase of WAG while the light oil appears to respond well to both phases. During development optimization, these trends can be accounted for in the injection cycle timing and duration for each phase. In terms of using WAG as a tertiary recovery method after a period of water or gas flooding, tertiary WAG is observed to be most beneficial in the low to medium quality reservoirs. Tertiary WAG extends the production duration and results in a ∼4% increase in recovery beyond water flooding. Study results go on to quantify the differences in water and gas breakthrough as a factor of pore volume injected (PVI) and conclusions further indicate which reservoirs are best suited for each recovery method.
{"title":"Assessment of Oil Recovery Methods for Reservoirs in the Flemish Pass Basin","authors":"C. Lafitte, L. James","doi":"10.2118/208906-ms","DOIUrl":"https://doi.org/10.2118/208906-ms","url":null,"abstract":"\u0000 In recent years, the Flemish Pass Basin has been gaining momentum as an area of potential high-volume resources on the frontier of remote, deep-water offshore oil development. This simulation study utilizes three sector models representing regional, discovered reservoirs, and two tuned fluid models representing oil sampled from wells in the Flemish Pass Basin. Generally speaking, WAG is considered a late-life enhanced oil recovery (EOR) technique, while implementing WAG immediately upon first oil for secondary recovery is less common; however, may be equally or more valuable.\u0000 This study aims to evaluate three secondary oil recovery methods, water flooding, gas flooding, and water-alternating-gas (WAG) flooding. Each recovery method is simulated with Schlumberger’s ECLIPSE reservoir simulator and uses a combination of three distinct reservoir geo-models and two fluid models. This study is a sensitivity analysis using geo-models that represent three discovered regions and two sampled fluids from the Flemish Pass Basin. The study is aimed at evaluating the effects of the various recovery methods over a duration of either five- or twenty-year forecast periods.\u0000 Results from this study capture an inherent uncertainty by drawing from eighteen simulation cases to quantify the relative benefit of each recovery method. These results indicate that using WAG as a secondary recovery method can yield a 4% to 10% increase in recovery over water or gas flood, and that secondary WAG can extend a well pair’s production plateau by up to 80% in specific circumstances.\u0000 Further observations indicate that secondary WAG in light oil reservoirs yield a ∼10% increase in recovery over secondary water or gas flooding. Using WAG in a medium oil reservoir yields a 4% to 9% increase in recovery over water flood, and a 2% to 16% increase in recovery over gas flood. In terms of geology, WAG is observed to be most valuable in ultra-high-quality reservoirs. The better the reservoir quality, the more recovery improvement. In terms of fluids, the medium oil responds best to the gas injection phase of WAG while the light oil appears to respond well to both phases. During development optimization, these trends can be accounted for in the injection cycle timing and duration for each phase.\u0000 In terms of using WAG as a tertiary recovery method after a period of water or gas flooding, tertiary WAG is observed to be most beneficial in the low to medium quality reservoirs. Tertiary WAG extends the production duration and results in a ∼4% increase in recovery beyond water flooding. Study results go on to quantify the differences in water and gas breakthrough as a factor of pore volume injected (PVI) and conclusions further indicate which reservoirs are best suited for each recovery method.","PeriodicalId":11077,"journal":{"name":"Day 2 Thu, March 17, 2022","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80744495","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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