Vertical hydraulic fracturing is widely used to develop low-permeability gas reservoirs. Uneven distribution of formation permeability and stress leads to multiple-wing hydraulic fractures with different lengths, which results in the wellbore not being the center of the circular stimulated reservoir volume (SRV) region. Therefore, to simulate the wellbore pressure of this phenomenon, a semianalytical model of the off-center multiwing fractured well in radial composite gas reservoirs is presented and the corresponding solution method is shown. The model is verified with the numerical solution, and eight flow regimes can be distinguished under the ideal case, which includes bilinear flow, fracture interference, linear flow, radial flow of inner region, transition flow of inner region, and radial flow of inner region. Compared with the previous model in which the well is at the center of radial composite gas reservoirs, in this paper we present an obvious “step” after the inner region radial flow regime, which is related to the off-center distance and radius of the inner region. In addition, the effects of some important parameters (such as off-center distance, permeability mobility, inner region radius, and fracture distribution) on typical curves are discussed. Finally, field well testing data are used to verify the accuracy of the model.
{"title":"Modeling Transient Flow Behavior of Off-Center Fractured Well with Multiple Fractures in Radial Composite Gas Reservoirs","authors":"You-jie Xu, Xiang Zuping, Mengnan Yu","doi":"10.2118/215808-pa","DOIUrl":"https://doi.org/10.2118/215808-pa","url":null,"abstract":"\u0000 Vertical hydraulic fracturing is widely used to develop low-permeability gas reservoirs. Uneven distribution of formation permeability and stress leads to multiple-wing hydraulic fractures with different lengths, which results in the wellbore not being the center of the circular stimulated reservoir volume (SRV) region. Therefore, to simulate the wellbore pressure of this phenomenon, a semianalytical model of the off-center multiwing fractured well in radial composite gas reservoirs is presented and the corresponding solution method is shown. The model is verified with the numerical solution, and eight flow regimes can be distinguished under the ideal case, which includes bilinear flow, fracture interference, linear flow, radial flow of inner region, transition flow of inner region, and radial flow of inner region. Compared with the previous model in which the well is at the center of radial composite gas reservoirs, in this paper we present an obvious “step” after the inner region radial flow regime, which is related to the off-center distance and radius of the inner region. In addition, the effects of some important parameters (such as off-center distance, permeability mobility, inner region radius, and fracture distribution) on typical curves are discussed. Finally, field well testing data are used to verify the accuracy of the model.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"32 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89314747","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Mohamed Osman Ebraheem, H. Ibrahim, H. Ewida, A. H. Senosy
The early Cretaceous formations in recent years are considered significant potential hydrocarbon-bearing rocks in many rift basins such as Komombo, south Egypt. Therefore, this study is focused on the critical analysis and interpretation of well logging together with seismic reflection data on the Al Baraka petroliferous reservoir in the Komombo subbasin. The interpretation of these data was used to construct the first 3D geophysical models in this area which were subsequently interpreted in terms of their potential to be hydrocarbon-bearing or not. The 3D petrophysical models were deduced to illustrate the spatial distribution and propagation of the petrophysical properties (laterally and vertically) within the reservoir. Additionally, 3D seismic models were prepared to get a comprehensive, in-depth picture of how the productive hydrocarbon reservoir zones are structurally controlled in different depths. So, these models are crucial for explaining reservoir characteristics and providing supported geological reservoir models for precise reservoir performance prediction. This study aims to differentiate and determine hydrocarbon potential zones in terms of the petroleum system. The results of these progressive analyses showed that only two zones (C and D) in the Six Hills Formation are considered the most productive zones because they have a large thickness of sand bodies, low-water saturation values, high porosity, and high permeability. These zones are located in the northeastern and central parts of the studied area, which represent the depocenter of the subbasin. This evidence supported and confirmed the presence of petroleum accumulations in certain zones within the Six Hills Formation. Therefore, this work can give and encourage experts with adequate knowledge to understand the development of the rift basins in Komombo and other basins in middle and south Egypt.
{"title":"Geophysical Modeling and Its Contribution on the Reservoir Characterization of Al Baraka in El Gallaba Plain, South Egypt","authors":"Mohamed Osman Ebraheem, H. Ibrahim, H. Ewida, A. H. Senosy","doi":"10.2118/214693-pa","DOIUrl":"https://doi.org/10.2118/214693-pa","url":null,"abstract":"\u0000 The early Cretaceous formations in recent years are considered significant potential hydrocarbon-bearing rocks in many rift basins such as Komombo, south Egypt. Therefore, this study is focused on the critical analysis and interpretation of well logging together with seismic reflection data on the Al Baraka petroliferous reservoir in the Komombo subbasin. The interpretation of these data was used to construct the first 3D geophysical models in this area which were subsequently interpreted in terms of their potential to be hydrocarbon-bearing or not. The 3D petrophysical models were deduced to illustrate the spatial distribution and propagation of the petrophysical properties (laterally and vertically) within the reservoir. Additionally, 3D seismic models were prepared to get a comprehensive, in-depth picture of how the productive hydrocarbon reservoir zones are structurally controlled in different depths. So, these models are crucial for explaining reservoir characteristics and providing supported geological reservoir models for precise reservoir performance prediction. This study aims to differentiate and determine hydrocarbon potential zones in terms of the petroleum system. The results of these progressive analyses showed that only two zones (C and D) in the Six Hills Formation are considered the most productive zones because they have a large thickness of sand bodies, low-water saturation values, high porosity, and high permeability. These zones are located in the northeastern and central parts of the studied area, which represent the depocenter of the subbasin. This evidence supported and confirmed the presence of petroleum accumulations in certain zones within the Six Hills Formation. Therefore, this work can give and encourage experts with adequate knowledge to understand the development of the rift basins in Komombo and other basins in middle and south Egypt.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"41 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81484767","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In recent years, time-lapse (4D) seismic (4DS) data have been widely used for reservoir monitoring to provide relevant information on dynamic changes occurring during production. In complex reservoirs, multiple seismic monitor surveys are usually available. Updating reservoir models with these data can be very beneficial to improve the field’s management. In the quantitative integration of 4DS data into the data assimilation (DA) process, it is crucial to define how to deal with more than one seismic monitor. In this work, we continue a series of investigations about seismic DA procedures and expand on them by analyzing ways to assimilate more than one seismic monitor. More specifically, we evaluate different ways of using production data and two monitor surveys (M3 and M5) to calibrate the dynamic models of a real Brazilian reservoir using the ensemble smoother with multiple data assimilation (ES-MDA) method. We performed the following experiments: (1) sequential assimilation of M3 and M5 with parts of well history divided according to the seismic acquisition dates; (2) assimilation of M3 with the entire well history and subsequent assimilation of M5; (3) assimilation of well and M3 data; and (4) assimilation of well and M5 data. For comparison purposes, we also assimilated only well data. From the results, we observed that well and 4DS data misfits were reduced when assimilating both monitors, compared to the cases where only a single monitor (any of them) was used with production data. This conclusion is also true in the comparison with results obtained when only assimilating well data. This indicates that both seismic monitors are important data to be quantitatively considered in DA. In this particular field, using a previous DA run to solely assimilate the newly available monitor (Case 2) delivered better models and long-term forecasts. Therefore, this would be our recommendation. This study highlights the importance of several 4DS acquisitions for reservoir monitoring and management and shows the challenges of their application in seismic DA for better life cycle field applications.
{"title":"Data Assimilation of Production and Multiple 4D Seismic Acquisitions in a Deepwater Field Using Ensemble Smoother with Multiple Data Assimilation","authors":"Daiane Rossi Rosa, D. Schiozer, A. Davolio","doi":"10.2118/215812-pa","DOIUrl":"https://doi.org/10.2118/215812-pa","url":null,"abstract":"\u0000 In recent years, time-lapse (4D) seismic (4DS) data have been widely used for reservoir monitoring to provide relevant information on dynamic changes occurring during production. In complex reservoirs, multiple seismic monitor surveys are usually available. Updating reservoir models with these data can be very beneficial to improve the field’s management. In the quantitative integration of 4DS data into the data assimilation (DA) process, it is crucial to define how to deal with more than one seismic monitor. In this work, we continue a series of investigations about seismic DA procedures and expand on them by analyzing ways to assimilate more than one seismic monitor. More specifically, we evaluate different ways of using production data and two monitor surveys (M3 and M5) to calibrate the dynamic models of a real Brazilian reservoir using the ensemble smoother with multiple data assimilation (ES-MDA) method. We performed the following experiments: (1) sequential assimilation of M3 and M5 with parts of well history divided according to the seismic acquisition dates; (2) assimilation of M3 with the entire well history and subsequent assimilation of M5; (3) assimilation of well and M3 data; and (4) assimilation of well and M5 data. For comparison purposes, we also assimilated only well data. From the results, we observed that well and 4DS data misfits were reduced when assimilating both monitors, compared to the cases where only a single monitor (any of them) was used with production data. This conclusion is also true in the comparison with results obtained when only assimilating well data. This indicates that both seismic monitors are important data to be quantitatively considered in DA. In this particular field, using a previous DA run to solely assimilate the newly available monitor (Case 2) delivered better models and long-term forecasts. Therefore, this would be our recommendation. This study highlights the importance of several 4DS acquisitions for reservoir monitoring and management and shows the challenges of their application in seismic DA for better life cycle field applications.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"48 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73749989","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Shehadeh Masalmeh, S. Amir Farzaneh, Mehran Sohrabi, M. Saeid Ataei, Muataz Alshuaibi
Summary Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoir that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, carbon dioxide (CO2) enhanced oil recovery (EOR) has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs. In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artifacts, long cores were used in the experiments, and to observe the effect of gravity, both 2 in. diameter and 4 in. diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by aging the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant, and both CO2 and a mixture of 50% C1 and 50% CO2 were used as miscible injectant. All gas injection experiments were performed using vertically oriented cores, and the gas was injected from the top unless it is stated otherwise. The main parameters investigated in this study are as follows: The effect of miscibility on oil recovery for both continuous gas injection and water alternating gas (WAG). The effect of gravity on gas sweep efficiency compared to waterflooding. The effect of gas-oil interfacial tension (IFT) on oil recovery when using the same oil. The effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions. The effect of immiscible gas injection on subsequent miscible gas injection performance. Impact of CO2 cycle length on ultimate oil recovery. The impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection. The main conclusions of this study are as follows: As expected, miscibility has a significant impact on displacement efficiency and oil recovery where miscible gas recovered more than 20% extra oil compared to immiscible gas. A significant variation in oil recovery is observed for miscible gas injection (i.e., more than 10 saturation units difference) depending on the minimum miscibility pressure (MMP) between the injected gas and crude oil, even when both experiments are performed at miscible conditions using the same injected gas. The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to ha
{"title":"A Systematic Experimental Study to Understand the Performance and Efficiency of Gas Injection in Carbonate Reservoirs","authors":"Shehadeh Masalmeh, S. Amir Farzaneh, Mehran Sohrabi, M. Saeid Ataei, Muataz Alshuaibi","doi":"10.2118/200057-pa","DOIUrl":"https://doi.org/10.2118/200057-pa","url":null,"abstract":"Summary Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoir that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, carbon dioxide (CO2) enhanced oil recovery (EOR) has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs. In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artifacts, long cores were used in the experiments, and to observe the effect of gravity, both 2 in. diameter and 4 in. diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by aging the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant, and both CO2 and a mixture of 50% C1 and 50% CO2 were used as miscible injectant. All gas injection experiments were performed using vertically oriented cores, and the gas was injected from the top unless it is stated otherwise. The main parameters investigated in this study are as follows: The effect of miscibility on oil recovery for both continuous gas injection and water alternating gas (WAG). The effect of gravity on gas sweep efficiency compared to waterflooding. The effect of gas-oil interfacial tension (IFT) on oil recovery when using the same oil. The effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions. The effect of immiscible gas injection on subsequent miscible gas injection performance. Impact of CO2 cycle length on ultimate oil recovery. The impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection. The main conclusions of this study are as follows: As expected, miscibility has a significant impact on displacement efficiency and oil recovery where miscible gas recovered more than 20% extra oil compared to immiscible gas. A significant variation in oil recovery is observed for miscible gas injection (i.e., more than 10 saturation units difference) depending on the minimum miscibility pressure (MMP) between the injected gas and crude oil, even when both experiments are performed at miscible conditions using the same injected gas. The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to ha","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"9 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135912691","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Abdulkareem Sofi, Jinxun Wang, Mathieu Salaün, David Rousseau, Mikel Morvan, Subhash C. Ayirala
Summary The potential synergy between smartwater and various enhanced oil recovery (EOR) processes has recently attracted significant attention. In previous work, we demonstrated such favorable synergy for polymer floods not only from a viscosity standpoint but also in terms of wettability. Recent studies suggest that smartwater synergy might even extend to surfactant floods. In this work, we investigate the potential synergy between smartwater and surfactant flooding. Opposed to previous work, the potential synergy is investigated from ground zero. We concurrently developed two surfactant formulations for conventional high-salinity injection water and low-salinity smartwater. To design the optimal surfactant-polymer (SP) formulations, we followed a systematic all-inclusive laboratory workflow. Oil displacement studies were performed in preserved core samples using the two developed formulations with conventional injection water and smartwater. The results demonstrated the promising potential of binary surfactant mixtures of olefin sulfonate (OS) and alkyl glyceryl ether sulfonate (AGES) for both waters. The designed binary formulations were able to form Winsor Type III emulsions besides achieving ultralow interfacial tensions (IFTs). Most importantly, in terms of oil displacement, the developed SP formulations in both injection water and low-salinity smartwater were capable of recovering more than 60% of the remaining oil post waterflooding. A key novelty of this work is that it investigates the potential synergy between smartwater and surfactant-based processes from the initial step of surfactant formulation design. Through well-designed from-scratch evaluation, we demonstrate that surfactant-based processes exhibit limited synergies with smartwater. Comparable processes in terms of performance can be designed for both high-salinity and low-salinity waters. It is also quite possible that the synergistic benefits of smartwater on oil recovery cannot be effective in SP flooding processes, especially with specific surfactant formulations under optimal salinity conditions.
{"title":"Smartwater Synergy with Chemical EOR: Studying the Potential Synergy with Surfactants","authors":"Abdulkareem Sofi, Jinxun Wang, Mathieu Salaün, David Rousseau, Mikel Morvan, Subhash C. Ayirala","doi":"10.2118/211475-pa","DOIUrl":"https://doi.org/10.2118/211475-pa","url":null,"abstract":"Summary The potential synergy between smartwater and various enhanced oil recovery (EOR) processes has recently attracted significant attention. In previous work, we demonstrated such favorable synergy for polymer floods not only from a viscosity standpoint but also in terms of wettability. Recent studies suggest that smartwater synergy might even extend to surfactant floods. In this work, we investigate the potential synergy between smartwater and surfactant flooding. Opposed to previous work, the potential synergy is investigated from ground zero. We concurrently developed two surfactant formulations for conventional high-salinity injection water and low-salinity smartwater. To design the optimal surfactant-polymer (SP) formulations, we followed a systematic all-inclusive laboratory workflow. Oil displacement studies were performed in preserved core samples using the two developed formulations with conventional injection water and smartwater. The results demonstrated the promising potential of binary surfactant mixtures of olefin sulfonate (OS) and alkyl glyceryl ether sulfonate (AGES) for both waters. The designed binary formulations were able to form Winsor Type III emulsions besides achieving ultralow interfacial tensions (IFTs). Most importantly, in terms of oil displacement, the developed SP formulations in both injection water and low-salinity smartwater were capable of recovering more than 60% of the remaining oil post waterflooding. A key novelty of this work is that it investigates the potential synergy between smartwater and surfactant-based processes from the initial step of surfactant formulation design. Through well-designed from-scratch evaluation, we demonstrate that surfactant-based processes exhibit limited synergies with smartwater. Comparable processes in terms of performance can be designed for both high-salinity and low-salinity waters. It is also quite possible that the synergistic benefits of smartwater on oil recovery cannot be effective in SP flooding processes, especially with specific surfactant formulations under optimal salinity conditions.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136080745","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
L. C. Silva, J. V. Roque, G. Oliveira, R. G. Souza, S. Paulino, C. Fonseca, D. Braga, J. Trujillo
Oil and gas production is measured in different units; therefore, there is a need to use a conversion factor of natural gas (NG) to barrels of oil equivalent (BOE). The SPE unit conversion factor, which is based on a reference oil, is often used. However, BOE conversion factors vary as a function of the high heating value (HHV) calculated for a gas, which in turn, varies as a function of the NG composition. Herein, by using Monte Carlo simulations, HHV and produced volumes of NG measured over the years were used in estimating BOE conversion factors for two offshore carbonate fields in ultradeep waters. Then, the new BOE conversion factors were used to review the production data collected in 2021. By comparing the new production data with the data obtained by using the SPE unit conversion factor, it is seen that the proposed conversion factors are more suitable for the specific assets than the standardized conversion factors.
{"title":"Stochastic Estimation of Barrels of Oil Equivalent Conversion Factor for Natural Gas Volumes from Offshore Carbonate Fields in Ultradeep Waters","authors":"L. C. Silva, J. V. Roque, G. Oliveira, R. G. Souza, S. Paulino, C. Fonseca, D. Braga, J. Trujillo","doi":"10.2118/214683-pa","DOIUrl":"https://doi.org/10.2118/214683-pa","url":null,"abstract":"\u0000 Oil and gas production is measured in different units; therefore, there is a need to use a conversion factor of natural gas (NG) to barrels of oil equivalent (BOE). The SPE unit conversion factor, which is based on a reference oil, is often used. However, BOE conversion factors vary as a function of the high heating value (HHV) calculated for a gas, which in turn, varies as a function of the NG composition. Herein, by using Monte Carlo simulations, HHV and produced volumes of NG measured over the years were used in estimating BOE conversion factors for two offshore carbonate fields in ultradeep waters. Then, the new BOE conversion factors were used to review the production data collected in 2021. By comparing the new production data with the data obtained by using the SPE unit conversion factor, it is seen that the proposed conversion factors are more suitable for the specific assets than the standardized conversion factors.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"49 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79126092","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Hassan, E. Al-Shalabi, W. Alameri, M. Kamal, S. Patil, S. M. S. Hussain
Low-salinity polymer (LSP) flooding is a synergic emergent enhanced oil recovery (EOR) technique. Previous laboratory experiments showed noticeable improvements in displacement efficiency, polymer rheology, injectivity, and viscoelasticity. Nevertheless, when it comes to modeling LSP flooding, it is still challenging to develop a mechanistic predictive model that captures polymer-brine-rock (PBR) interactions. Therefore, this study uses a coupled MATLAB reservoir simulation toolbox (MRST)-IPhreeqc simulator to investigate the effect of water chemistry on PBR interactions during LSP flooding through varying overall salinity and the concentrations of divalent and monovalent ions. For describing the related geochemistry, the presence of polymer in the aqueous phase was considered by introducing novel solution species (Poly) to the Phreeqc database. The developed model’s parameters were validated and history matched with experimental data reported in the literature. Moreover, different injection schemes were analyzed, including low-salinity (LS) water, LSP injection (1 × LSP), and 5-times spiked LSP injection (5 × LSP) with their related effects on polymer viscosity. Results showed that polymer viscosity during LSP flooding is affected directly by Ca2+ and Mg2+ and indirectly by SO42− owing to PBR interactions on a dolomite rock-forming mineral. Monovalent ions (viz. Na+ and K+) have minor effects on polymer viscosity. Ca2+ and Mg2+ ions discharged from dolomite dissolution create polymer complexes (acrylic acid, C3H4O2) to reduce polymer viscosity significantly. The increased SO42− concentration in the injected LSP solution affects the interactions between the polymer and positively charged aqueous species, leading to minimized polymer viscosity loss. For LSP flood derisking measures, the cation’s effect was related to the charge ratio (CR). Thus, it is key to obtain an optimal CR where viscosity loss is minimal. This paper is among the few to detail the mechanistic geochemical modeling of the LSP flooding technique. The validated MRST-IPhreeqc simulator evaluates the previously overlooked effects of water chemistry on polymer viscosity during the LSP process. Using this coupled simulator, several other geochemical reactions and parameters can be assessed, including rock and injected-water compositions, injection schemes, and other polymer characteristics.
{"title":"New Insights into Hybrid Low-Salinity Polymer Flooding through a Coupled Geochemical-Based Modeling Approach","authors":"A. Hassan, E. Al-Shalabi, W. Alameri, M. Kamal, S. Patil, S. M. S. Hussain","doi":"10.2118/210120-pa","DOIUrl":"https://doi.org/10.2118/210120-pa","url":null,"abstract":"\u0000 Low-salinity polymer (LSP) flooding is a synergic emergent enhanced oil recovery (EOR) technique. Previous laboratory experiments showed noticeable improvements in displacement efficiency, polymer rheology, injectivity, and viscoelasticity. Nevertheless, when it comes to modeling LSP flooding, it is still challenging to develop a mechanistic predictive model that captures polymer-brine-rock (PBR) interactions. Therefore, this study uses a coupled MATLAB reservoir simulation toolbox (MRST)-IPhreeqc simulator to investigate the effect of water chemistry on PBR interactions during LSP flooding through varying overall salinity and the concentrations of divalent and monovalent ions. For describing the related geochemistry, the presence of polymer in the aqueous phase was considered by introducing novel solution species (Poly) to the Phreeqc database. The developed model’s parameters were validated and history matched with experimental data reported in the literature. Moreover, different injection schemes were analyzed, including low-salinity (LS) water, LSP injection (1 × LSP), and 5-times spiked LSP injection (5 × LSP) with their related effects on polymer viscosity.\u0000 Results showed that polymer viscosity during LSP flooding is affected directly by Ca2+ and Mg2+ and indirectly by SO42− owing to PBR interactions on a dolomite rock-forming mineral. Monovalent ions (viz. Na+ and K+) have minor effects on polymer viscosity. Ca2+ and Mg2+ ions discharged from dolomite dissolution create polymer complexes (acrylic acid, C3H4O2) to reduce polymer viscosity significantly. The increased SO42− concentration in the injected LSP solution affects the interactions between the polymer and positively charged aqueous species, leading to minimized polymer viscosity loss. For LSP flood derisking measures, the cation’s effect was related to the charge ratio (CR). Thus, it is key to obtain an optimal CR where viscosity loss is minimal. This paper is among the few to detail the mechanistic geochemical modeling of the LSP flooding technique. The validated MRST-IPhreeqc simulator evaluates the previously overlooked effects of water chemistry on polymer viscosity during the LSP process. Using this coupled simulator, several other geochemical reactions and parameters can be assessed, including rock and injected-water compositions, injection schemes, and other polymer characteristics.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"40 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81314786","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Data assimilation (DA) for uncertainty reduction using reservoir simulation models normally demands high computational time; it may take days or even weeks to run a single reservoir application, depending on the reservoir model characteristics. Therefore, it is important to accelerate the process to make it more feasible for practical studies, especially those requiring many simulation runs. One possible way is by using proxy models to replace the reservoir simulator in some time-consuming parts of the procedure. However, the main challenge inherent in proxy models is the inclusion of 3D geostatistical realizations (block-to-block grid properties such as porosity and permeability) as uncertain attributes in the proxy construction. In most cases, it is impossible to treat the values of all grid properties explicitly as input to the proxy building process due to the high dimensionality issue. We present a new methodology for DA combining principal component analysis (PCA) with artificial neural networks (ANN) to solve this problem. The PCA technique is applied to reduce the dimension of the problem, making it possible and feasible to use grid properties in proxy modeling. The trained ANN is used as a proxy for the reservoir simulator, with the goal of reducing the total computational time spent on the application. We run three DA processes using a complex real-field reservoir model for validating the methodology. The first (DA1), used as the reference solution, is the conventional process in which the DA method updates all grid property values explicitly. The second (DA2) is only executed to validate the proposed parameterization via PCA. Both DA1 and DA2 use only the reservoir simulator to generate the reservoir outputs. In the third (DA3), the ANN replaces the reservoir simulator to save computational time. It is important to mention that after DA3, the results (the posterior ensemble) are validated with the reservoir simulator. The DA3, although a little bit less accurate than the DA1, allowed good overall results. Therefore, it seems reasonable to offer the decision-makers the possibility of choosing between the conventional approach (DA1), normally more accurate but slower, and the proposed DA3, much faster than DA1 (with overall good results). This choice may depend on the objective of the reservoir study, available resources, and time to perform the study. The key contribution of this paper is a practical methodology for DA combining PCA [for dimensional reduction (DR)] and ANN (for computational time reduction) applicable in real fields, filling a gap in the literature in this research area.
{"title":"Data Assimilation Using Principal Component Analysis and Artificial Neural Network","authors":"C. Maschio, G. Avansi, D. Schiozer","doi":"10.2118/214688-pa","DOIUrl":"https://doi.org/10.2118/214688-pa","url":null,"abstract":"\u0000 Data assimilation (DA) for uncertainty reduction using reservoir simulation models normally demands high computational time; it may take days or even weeks to run a single reservoir application, depending on the reservoir model characteristics. Therefore, it is important to accelerate the process to make it more feasible for practical studies, especially those requiring many simulation runs. One possible way is by using proxy models to replace the reservoir simulator in some time-consuming parts of the procedure. However, the main challenge inherent in proxy models is the inclusion of 3D geostatistical realizations (block-to-block grid properties such as porosity and permeability) as uncertain attributes in the proxy construction. In most cases, it is impossible to treat the values of all grid properties explicitly as input to the proxy building process due to the high dimensionality issue. We present a new methodology for DA combining principal component analysis (PCA) with artificial neural networks (ANN) to solve this problem. The PCA technique is applied to reduce the dimension of the problem, making it possible and feasible to use grid properties in proxy modeling. The trained ANN is used as a proxy for the reservoir simulator, with the goal of reducing the total computational time spent on the application. We run three DA processes using a complex real-field reservoir model for validating the methodology. The first (DA1), used as the reference solution, is the conventional process in which the DA method updates all grid property values explicitly. The second (DA2) is only executed to validate the proposed parameterization via PCA. Both DA1 and DA2 use only the reservoir simulator to generate the reservoir outputs. In the third (DA3), the ANN replaces the reservoir simulator to save computational time. It is important to mention that after DA3, the results (the posterior ensemble) are validated with the reservoir simulator. The DA3, although a little bit less accurate than the DA1, allowed good overall results. Therefore, it seems reasonable to offer the decision-makers the possibility of choosing between the conventional approach (DA1), normally more accurate but slower, and the proposed DA3, much faster than DA1 (with overall good results). This choice may depend on the objective of the reservoir study, available resources, and time to perform the study. The key contribution of this paper is a practical methodology for DA combining PCA [for dimensional reduction (DR)] and ANN (for computational time reduction) applicable in real fields, filling a gap in the literature in this research area.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"271 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79902136","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Hydrogen will play an important role in the quest to decarbonize the world’s economy by substituting fossil fuels. In addition to the development of hydrogen generation technologies, the energy industry will need to increase hydrogen storage capacity to facilitate the development of a robust hydrogen economy. The required hydrogen storage capacity will be much larger than current hydrogen and natural gas storage capacities. There are several geological storage options for hydrogen that include depleted hydrocarbon fields and aquifers, where more research is needed until the feasibility of storing hydrogen at scale is proved. Here, we investigate the buoyant flow of H2 (as a working gas) vs. CO2 (as a cushion gas) separately in a representative storage aquifer. Buoyant flow can affect the maximum storage, capillary trapping, likelihood of leakage, and deliverability of aquifer-stored hydrogen. After building a 2D geological reservoir model initially filled with saline water, we ran numerical simulations to determine how hydrogen placed at the bottom of an aquifer might rise through the water column. The Leverett j-function is used to generate heterogeneous capillary entry pressure fields that correlate with porosity and permeability fields. Hydrogen viscosities were based on the Jossi et al. correlation, and the density was modeled using the Peng-Robinson equation of state. We then simulated several scenarios to assess flow during short- (annually) and long- (several years) term storage. For comparison purposes, we also ran CO2 storage simulations using the same geological model but with CO2-brine-rock properties collected from the literature. For a representative storage aquifer (323 K, 15.7 MPa, and mean permeability of 200 md), significant fingering occurred as the hydrogen rose through the saline water column. The hydrogen experienced more buoyant flow and created flow paths with increased fingering when compared with CO2. Individual hydrogen fingers are thinner than the CO2 fingers in the simulations, and the tips of hydrogen finger fronts propagated upward roughly twice as fast as the CO2 front for a typical set of heterogeneity indicators (Dykstra-Parson’s coefficient Vdp = 0.80, and dimensionless autocorrelation length λDx = 2). The implications of buoyant flow for hydrogen in saline aquifers include an increased threat of leakage, more residual trapping of hydrogen, and, therefore, the need to focus more on the heterogeneity and lateral correlation behavior of the repository. If hydrogen penetrates the caprock of an aquifer, it will leak faster than CO2 and generate more vertical flow pathways. We identify possible depositional environments for clastic aquifers that would offer suitable characteristics for storage.
{"title":"Buoyant Flow of H2 Vs. CO2 in Storage Aquifers: Implications to Geological Screening","authors":"","doi":"10.2118/210327-pa","DOIUrl":"https://doi.org/10.2118/210327-pa","url":null,"abstract":"\u0000 Hydrogen will play an important role in the quest to decarbonize the world’s economy by substituting fossil fuels. In addition to the development of hydrogen generation technologies, the energy industry will need to increase hydrogen storage capacity to facilitate the development of a robust hydrogen economy. The required hydrogen storage capacity will be much larger than current hydrogen and natural gas storage capacities. There are several geological storage options for hydrogen that include depleted hydrocarbon fields and aquifers, where more research is needed until the feasibility of storing hydrogen at scale is proved. Here, we investigate the buoyant flow of H2 (as a working gas) vs. CO2 (as a cushion gas) separately in a representative storage aquifer. Buoyant flow can affect the maximum storage, capillary trapping, likelihood of leakage, and deliverability of aquifer-stored hydrogen.\u0000 After building a 2D geological reservoir model initially filled with saline water, we ran numerical simulations to determine how hydrogen placed at the bottom of an aquifer might rise through the water column. The Leverett j-function is used to generate heterogeneous capillary entry pressure fields that correlate with porosity and permeability fields. Hydrogen viscosities were based on the Jossi et al. correlation, and the density was modeled using the Peng-Robinson equation of state. We then simulated several scenarios to assess flow during short- (annually) and long- (several years) term storage. For comparison purposes, we also ran CO2 storage simulations using the same geological model but with CO2-brine-rock properties collected from the literature.\u0000 For a representative storage aquifer (323 K, 15.7 MPa, and mean permeability of 200 md), significant fingering occurred as the hydrogen rose through the saline water column. The hydrogen experienced more buoyant flow and created flow paths with increased fingering when compared with CO2. Individual hydrogen fingers are thinner than the CO2 fingers in the simulations, and the tips of hydrogen finger fronts propagated upward roughly twice as fast as the CO2 front for a typical set of heterogeneity indicators (Dykstra-Parson’s coefficient Vdp = 0.80, and dimensionless autocorrelation length λDx = 2).\u0000 The implications of buoyant flow for hydrogen in saline aquifers include an increased threat of leakage, more residual trapping of hydrogen, and, therefore, the need to focus more on the heterogeneity and lateral correlation behavior of the repository. If hydrogen penetrates the caprock of an aquifer, it will leak faster than CO2 and generate more vertical flow pathways. We identify possible depositional environments for clastic aquifers that would offer suitable characteristics for storage.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"33 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76223983","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The post-fracture pressure decay (PFPD) technique is a low-cost method allowing for stage-by-stage hydraulic fracture characterization. The analysis of the PFPD data is complex, with data affected by both hydraulic fracture and reservoir properties. Available analysis methods in the literature are oversimplified; reservoir or fracture properties are often assumed to be constant along the horizontal well, and therefore changes in the trend of pressure decay data are attributed to hydraulic fracture or reservoir properties only. Moreover, methods analogous to those applied to the analysis of conventional diagnostic fracture injection tests (DFITs) are often used and ignore critical mechanisms involved in main-stage hydraulic fracture stimulation. A conceptual numerical simulation study was first conducted herein to understand the key mechanisms involved in main-stage hydraulic fracturing. An analytical model was then developed to account for the dynamic behavior of the hydraulic fracture, leakoff, proppant distribution, multiple fractures, and propped- and unpropped-closure events. The analytical model is cast in the form of a new straightline analysis (SLA) method that provides stage-by-stage estimates of the ratio of unpropped fracture surface area to total fracture surface area. The SLA method was validated against numerical simulation results. Moreover, to account for the variation of reservoir properties along the horizontal well, the PFPD model is integrated with DFIT-flowback (DFIT-FBA) tests, performed at some points along the lateral, to obtain a reliable stage-by-stage hydraulic fracture and reservoir characterization approach. The practical application of the proposed integrated approach was demonstrated using PFPD and DFIT-FBA data from a horizontal well completed in 22 stages in the Montney Formation. The numerical simulation study demonstrated that the use of proppant and injection into multiple clusters (creating multiple fractures) results in multiple closure events. The closure process may start early after the pump-in period at a pressure significantly higher than the minimum in-situ stress. Using DFIT-based analytical models, which ignore the presence of proppant, causes significant errors in hydraulic fracture and reservoir property estimation. The PFPD field data examined herein exhibited a similar pressure trend to the numerical simulation cases. The ratio of unpropped fracture surface area to total fracture surface area was determined stage by stage using the PFPD SLA method, constrained by DFIT-FBA data. Engineers can use this information to optimize the hydraulic fracture stimulation design in real time, optimize the well spacing, and forecast the production. The cost and time advantages of this diagnostic method make this approach very attractive.
{"title":"Stage-by-Stage Hydraulic Fracture and Reservoir Characterization through Integration of Post-Fracture Pressure Decay Analysis and the Flowback Diagnostic Fracture Injection Test Method","authors":"D. Zeinabady, C. Clarkson","doi":"10.2118/212726-pa","DOIUrl":"https://doi.org/10.2118/212726-pa","url":null,"abstract":"\u0000 The post-fracture pressure decay (PFPD) technique is a low-cost method allowing for stage-by-stage hydraulic fracture characterization. The analysis of the PFPD data is complex, with data affected by both hydraulic fracture and reservoir properties. Available analysis methods in the literature are oversimplified; reservoir or fracture properties are often assumed to be constant along the horizontal well, and therefore changes in the trend of pressure decay data are attributed to hydraulic fracture or reservoir properties only. Moreover, methods analogous to those applied to the analysis of conventional diagnostic fracture injection tests (DFITs) are often used and ignore critical mechanisms involved in main-stage hydraulic fracture stimulation.\u0000 A conceptual numerical simulation study was first conducted herein to understand the key mechanisms involved in main-stage hydraulic fracturing. An analytical model was then developed to account for the dynamic behavior of the hydraulic fracture, leakoff, proppant distribution, multiple fractures, and propped- and unpropped-closure events. The analytical model is cast in the form of a new straightline analysis (SLA) method that provides stage-by-stage estimates of the ratio of unpropped fracture surface area to total fracture surface area. The SLA method was validated against numerical simulation results. Moreover, to account for the variation of reservoir properties along the horizontal well, the PFPD model is integrated with DFIT-flowback (DFIT-FBA) tests, performed at some points along the lateral, to obtain a reliable stage-by-stage hydraulic fracture and reservoir characterization approach. The practical application of the proposed integrated approach was demonstrated using PFPD and DFIT-FBA data from a horizontal well completed in 22 stages in the Montney Formation.\u0000 The numerical simulation study demonstrated that the use of proppant and injection into multiple clusters (creating multiple fractures) results in multiple closure events. The closure process may start early after the pump-in period at a pressure significantly higher than the minimum in-situ stress. Using DFIT-based analytical models, which ignore the presence of proppant, causes significant errors in hydraulic fracture and reservoir property estimation. The PFPD field data examined herein exhibited a similar pressure trend to the numerical simulation cases. The ratio of unpropped fracture surface area to total fracture surface area was determined stage by stage using the PFPD SLA method, constrained by DFIT-FBA data. Engineers can use this information to optimize the hydraulic fracture stimulation design in real time, optimize the well spacing, and forecast the production. The cost and time advantages of this diagnostic method make this approach very attractive.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"31 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81139324","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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