Water retention curve essentially determined by pore throat morphology, wettability, pore connectivity and so on has a close relationship with many physical properties of hydrate-bearing sediments. Figuring out its accurate dynamic evolution regularity is of significant importance to the efficient development of gas hydrate deposits. However, most currently used hydrate-bearing networks for capturing the dynamic evolution of water retention curve possess over simplified pore throat cross-sections, resulting in ambiguous evolution law. In this work, a regular hydrate-bearing network with complex pore throat morphology combining circles, squares, arbitrary triangles, regular n-cornered star, and regular polygons in the pattern of grain-coating hydrate is firstly constructed. Then, the capillary entry pressure of different pore throat morphology in the presence of hydrate and process of primary drainage are respectively introduced. Afterwards, primary drainage is carried out in the established network based on invasion percolation. The dynamic displacement characteristics and water retention curves are relatively obtained. Furthermore, factors influencing the dynamic displacement characteristics and evolution of water retention curves in hydrate-bearing sediments such as pore throat cross-section, wettability, coordination number and initial aspect ratio are investigated in detail. Results indicate that the capillary entry pressure increases with increased hydrate saturation due to the reduction of effective pore throat radius caused by hydrate occupation. The number of gas invaded pore bodies and throats grows small with the increase of hydrate saturation at the same capillary pressure, causing large water saturation. The water retention curve evolves to an increasing direction with increased hydrate saturation during primary drainage. Pore throat morphology plays a significant role in capillary entry pressure, the number of gas invaded pore throats at the same capillary pressure, fluid configuration at the same pore throat cross-section, and gas-water spatial distribution, resulting in great difference of water retention curves. With the decrease of wettability to aqueous phase, the capillary entry pressure grows small, and the number of gas invaded pore throats becomes large, resulting in small water saturation at the same capillary pressure. Meanwhile, the proportion of piston-like displacement without water film turns large, leading to large connate water saturation when all water-filled pore throats that satisfy the criteria for gas invasion are invaded. In addition, the number of gas invaded pore bodies and throats increases at the same capillary pressure with increased coordination number, causing small water saturation. At the same time, the proportion of piston-like displacement with water film becomes large, resulting in small connate water saturation. And the water retention curve evolves to the direction of large values with the inc
{"title":"A Complex Morphologically Regular Pore Network Model to Study Water Retention Curve of Hydrate-Bearing Sediments","authors":"Mingqiang Chen, Qingping Li, X. Lyu, W. Pang, Qiang Fu, Chaohui Lyu, Hongmei Jiao","doi":"10.2118/214443-ms","DOIUrl":"https://doi.org/10.2118/214443-ms","url":null,"abstract":"\u0000 Water retention curve essentially determined by pore throat morphology, wettability, pore connectivity and so on has a close relationship with many physical properties of hydrate-bearing sediments. Figuring out its accurate dynamic evolution regularity is of significant importance to the efficient development of gas hydrate deposits. However, most currently used hydrate-bearing networks for capturing the dynamic evolution of water retention curve possess over simplified pore throat cross-sections, resulting in ambiguous evolution law.\u0000 In this work, a regular hydrate-bearing network with complex pore throat morphology combining circles, squares, arbitrary triangles, regular n-cornered star, and regular polygons in the pattern of grain-coating hydrate is firstly constructed. Then, the capillary entry pressure of different pore throat morphology in the presence of hydrate and process of primary drainage are respectively introduced. Afterwards, primary drainage is carried out in the established network based on invasion percolation. The dynamic displacement characteristics and water retention curves are relatively obtained. Furthermore, factors influencing the dynamic displacement characteristics and evolution of water retention curves in hydrate-bearing sediments such as pore throat cross-section, wettability, coordination number and initial aspect ratio are investigated in detail.\u0000 Results indicate that the capillary entry pressure increases with increased hydrate saturation due to the reduction of effective pore throat radius caused by hydrate occupation. The number of gas invaded pore bodies and throats grows small with the increase of hydrate saturation at the same capillary pressure, causing large water saturation. The water retention curve evolves to an increasing direction with increased hydrate saturation during primary drainage. Pore throat morphology plays a significant role in capillary entry pressure, the number of gas invaded pore throats at the same capillary pressure, fluid configuration at the same pore throat cross-section, and gas-water spatial distribution, resulting in great difference of water retention curves. With the decrease of wettability to aqueous phase, the capillary entry pressure grows small, and the number of gas invaded pore throats becomes large, resulting in small water saturation at the same capillary pressure. Meanwhile, the proportion of piston-like displacement without water film turns large, leading to large connate water saturation when all water-filled pore throats that satisfy the criteria for gas invasion are invaded. In addition, the number of gas invaded pore bodies and throats increases at the same capillary pressure with increased coordination number, causing small water saturation. At the same time, the proportion of piston-like displacement with water film becomes large, resulting in small connate water saturation. And the water retention curve evolves to the direction of large values with the inc","PeriodicalId":306106,"journal":{"name":"Day 4 Thu, June 08, 2023","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131245399","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}
M. Khosravi, Yao Xu, S. Mirazimi, E. Stenby, Wei Yan
Carbon sequestration in depleted reservoirs or aquifers is highly demanded but still faced with technical challenges in many aspects. Among them, losing well injectivity during the storage process is a major concern. This can be caused by salt deposited in the reservoir, particularly near the injection well, which may sometimes creep into the injection well. Therefore, it is desirable to estimate the amount and distribution of salt precipitation at the injection conditions for a smooth implementation of CO2 sequestration. In this paper, we investigate how much commercial software CMG-GEM can help the evaluation of salt precipitation. We first review the critical mechanisms involved in salt precipitation and then analyze the challenges in simulating these mechanisms. According to the literature, water saturation and saturation index are the two most influential parameters that control the amount and pattern of salt precipitation and clogging due to water vaporization. Their values are determined by the complex interplay between viscous force, gravity, the evaporation of water into the CO2 stream, the molecular diffusion of dissolved salt in the brine, and surface phenomena such as the spreading of a thin water film on the rock surface, the Marangoni convection, and disjoining suction. Here we investigate the challenges of simulating the aforementioned mechanisms as well as salt precipitation due to the backflow of brine toward the injection well. The surface-related phenomena are difficult to account for in simulation. However, the extent of the CO2 plume can be significantly underestimated if they are neglected. Although water vaporization, salt diffusion, and capillary pressure can be formally included in the simulation, it is arguable whether they always describe the actual phenomena adequately. In most cases of CO2 injection into an aquifer, water spreads all over the rock surface, which increases the rate of vaporization and surface-related phenomena, such as the Marangoni effect, dramatically. Marangoni turbulent fluxes originating from the unbalanced shear stresses on the interface can accelerate the mixing effect in homogenizing the ions composition, which results in self-enhanced salt precipitation via the thin brine film spreading on the rock surface. We examine different simulation techniques as remedies to mimic those phenomena.
{"title":"Challenges in Simulation of Salt Clogging","authors":"M. Khosravi, Yao Xu, S. Mirazimi, E. Stenby, Wei Yan","doi":"10.2118/214350-ms","DOIUrl":"https://doi.org/10.2118/214350-ms","url":null,"abstract":"\u0000 Carbon sequestration in depleted reservoirs or aquifers is highly demanded but still faced with technical challenges in many aspects. Among them, losing well injectivity during the storage process is a major concern. This can be caused by salt deposited in the reservoir, particularly near the injection well, which may sometimes creep into the injection well. Therefore, it is desirable to estimate the amount and distribution of salt precipitation at the injection conditions for a smooth implementation of CO2 sequestration. In this paper, we investigate how much commercial software CMG-GEM can help the evaluation of salt precipitation. We first review the critical mechanisms involved in salt precipitation and then analyze the challenges in simulating these mechanisms.\u0000 According to the literature, water saturation and saturation index are the two most influential parameters that control the amount and pattern of salt precipitation and clogging due to water vaporization. Their values are determined by the complex interplay between viscous force, gravity, the evaporation of water into the CO2 stream, the molecular diffusion of dissolved salt in the brine, and surface phenomena such as the spreading of a thin water film on the rock surface, the Marangoni convection, and disjoining suction. Here we investigate the challenges of simulating the aforementioned mechanisms as well as salt precipitation due to the backflow of brine toward the injection well.\u0000 The surface-related phenomena are difficult to account for in simulation. However, the extent of the CO2 plume can be significantly underestimated if they are neglected. Although water vaporization, salt diffusion, and capillary pressure can be formally included in the simulation, it is arguable whether they always describe the actual phenomena adequately. In most cases of CO2 injection into an aquifer, water spreads all over the rock surface, which increases the rate of vaporization and surface-related phenomena, such as the Marangoni effect, dramatically. Marangoni turbulent fluxes originating from the unbalanced shear stresses on the interface can accelerate the mixing effect in homogenizing the ions composition, which results in self-enhanced salt precipitation via the thin brine film spreading on the rock surface. We examine different simulation techniques as remedies to mimic those phenomena.","PeriodicalId":306106,"journal":{"name":"Day 4 Thu, June 08, 2023","volume":"60 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131759179","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}
Abdulqawi Al Fakih, Sarah Natasya, O. Balamir, Slimane Sebbane, Michael Ari Dhanto
Geothermal well construction activity has been accelerating considerably to assist in meeting the zero carbon emissions goal of many countries and industries by 2050. In some areas, the geothermal well construction methods are inherited from oil and gas wells, and the construction activity is carried out using the same equipment and similar processes and guidelines. This is particularly visible when it comes to well-control management. However, as more and more oilfield professionals enter the geothermal arena, it becomes essential to understand the differences between oil and gas and geothermal wells that heavily impact the construction of the geothermal well. There is an emerging need to differentiate between the oil and gas and geothermal well control and well integrity criteria required to drill conventional geothermal wells. Considering the broad range of geothermal well types and their associated flow conditions, the authors limited the discussion to conventional geothermal wells and, more specifically, to the geothermal wells drilled in volcanic fields. Common failures pertaining to well control that were recorded throughout the history of geothermal well drilling (starting circa the 1920s) revolve around the handling of thermal (steam) kicks. After careful investigation, the root causes of most of the steam kicks were found to be (i) engineering and crew incompetence and lack of specific experience, (ii) lack of targeted risk assessment, and (iii) lack of clear standard work instructions to be followed during routine drilling and well control operations. A clear need was then identified for a specific well control procedure and detailed drilling plan enhancements, which would also address the differences between well control operations during drilling hydrocarbon and geothermal wells. This paper lays out the basics of the preferred approach to maintain the geothermal well integrity by well control during its well construction process, intended to reduce risk and improve performance. It will also illustrate the main differences between geothermal and hydrocarbon well control during the well construction phase.
{"title":"Maintaining the Integrity of Geothermal Wells During the Construction Process","authors":"Abdulqawi Al Fakih, Sarah Natasya, O. Balamir, Slimane Sebbane, Michael Ari Dhanto","doi":"10.2118/214409-ms","DOIUrl":"https://doi.org/10.2118/214409-ms","url":null,"abstract":"\u0000 Geothermal well construction activity has been accelerating considerably to assist in meeting the zero carbon emissions goal of many countries and industries by 2050. In some areas, the geothermal well construction methods are inherited from oil and gas wells, and the construction activity is carried out using the same equipment and similar processes and guidelines. This is particularly visible when it comes to well-control management. However, as more and more oilfield professionals enter the geothermal arena, it becomes essential to understand the differences between oil and gas and geothermal wells that heavily impact the construction of the geothermal well. There is an emerging need to differentiate between the oil and gas and geothermal well control and well integrity criteria required to drill conventional geothermal wells. Considering the broad range of geothermal well types and their associated flow conditions, the authors limited the discussion to conventional geothermal wells and, more specifically, to the geothermal wells drilled in volcanic fields.\u0000 Common failures pertaining to well control that were recorded throughout the history of geothermal well drilling (starting circa the 1920s) revolve around the handling of thermal (steam) kicks. After careful investigation, the root causes of most of the steam kicks were found to be (i) engineering and crew incompetence and lack of specific experience, (ii) lack of targeted risk assessment, and (iii) lack of clear standard work instructions to be followed during routine drilling and well control operations. A clear need was then identified for a specific well control procedure and detailed drilling plan enhancements, which would also address the differences between well control operations during drilling hydrocarbon and geothermal wells.\u0000 This paper lays out the basics of the preferred approach to maintain the geothermal well integrity by well control during its well construction process, intended to reduce risk and improve performance. It will also illustrate the main differences between geothermal and hydrocarbon well control during the well construction phase.","PeriodicalId":306106,"journal":{"name":"Day 4 Thu, June 08, 2023","volume":"2014 4","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"120920544","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. Bigdeli, J. C. von Hohendorff Filho, D. Schiozer
In this work, we present a case study of the integration of surface facility models and a deepwater reservoir, as well as an engineering evaluation of the implications of liquid-liquid subsea separation (LLSS) on the integration process. For this, a heavy oil sandstone reservoir and several surface facility layouts were computationally integrated using a commercial simulator. A gathering unit, subsea separator, and water disposal unit were added to the surface facility model layouts to support the LLSS system. The term "merge scenario" was used to refer to the quantity of production streams that were gathered and delivered to the subsea separator. To allow the production from the reservoir model, the minimum bottom-hole pressure (BHP) for the producing wells were defined for all the simulations. Our investigation includes fluids produced at platforms, produced water at disposal unit, the pressure drop in the riser in terms of hydrostatic and friction terms, and economic analyses of these investigations. This case study shows that, depending on the merging situation, the reservoir needs 2 to 5 times more injection water than the separated water. Despite efforts to reduce the pressure restriction in the surface facility by increasing the riser diameter, the oil recovery did not change significantly when the number of merging wells was adjusted. This happened because the wellhead was not affected by the production system's pressure disturbance and the surface facility models’ boundary conditions remained unchanged. The economic calculations also indicated that the value of the technology (the highest acceptable price for the technology) for eleven merge scenario was 130 MMUSD and the OPEX and CAPEX can be lowered by 95 and 35 MMUSD (3% and 5% on average), respectively. This economic benefit was due to the lower cost of platform water handling from the produced water separation. In later stages of simulations, when the water cut surpasses 90%, hydrostatic pressure loss overtakes friction pressure loss as the primary contributor to overall pressure losses in the riser for 11 merge scenarios. These tests demonstrated that adding LLSS increases the complexity of the integration process and engineers can apply the engineering ideas of this study to other field designs in development. This work is the first case study of its kind that examines the relationship between the impact of LLS and the integration of a deep-water reservoir and surface facility model. This article's production forecast problem description can be utilized as a starting point to develop a general methodology for simulating complicated offshore production systems using LLSS operations.
{"title":"Effect of Liquid-Liquid Subsea Separation on Production Forecast Considering Integration of a Deepwater Reservoir and Surface Facility Models","authors":"A. Bigdeli, J. C. von Hohendorff Filho, D. Schiozer","doi":"10.2118/214455-ms","DOIUrl":"https://doi.org/10.2118/214455-ms","url":null,"abstract":"\u0000 In this work, we present a case study of the integration of surface facility models and a deepwater reservoir, as well as an engineering evaluation of the implications of liquid-liquid subsea separation (LLSS) on the integration process. For this, a heavy oil sandstone reservoir and several surface facility layouts were computationally integrated using a commercial simulator.\u0000 A gathering unit, subsea separator, and water disposal unit were added to the surface facility model layouts to support the LLSS system. The term \"merge scenario\" was used to refer to the quantity of production streams that were gathered and delivered to the subsea separator. To allow the production from the reservoir model, the minimum bottom-hole pressure (BHP) for the producing wells were defined for all the simulations. Our investigation includes fluids produced at platforms, produced water at disposal unit, the pressure drop in the riser in terms of hydrostatic and friction terms, and economic analyses of these investigations.\u0000 This case study shows that, depending on the merging situation, the reservoir needs 2 to 5 times more injection water than the separated water. Despite efforts to reduce the pressure restriction in the surface facility by increasing the riser diameter, the oil recovery did not change significantly when the number of merging wells was adjusted. This happened because the wellhead was not affected by the production system's pressure disturbance and the surface facility models’ boundary conditions remained unchanged. The economic calculations also indicated that the value of the technology (the highest acceptable price for the technology) for eleven merge scenario was 130 MMUSD and the OPEX and CAPEX can be lowered by 95 and 35 MMUSD (3% and 5% on average), respectively. This economic benefit was due to the lower cost of platform water handling from the produced water separation. In later stages of simulations, when the water cut surpasses 90%, hydrostatic pressure loss overtakes friction pressure loss as the primary contributor to overall pressure losses in the riser for 11 merge scenarios. These tests demonstrated that adding LLSS increases the complexity of the integration process and engineers can apply the engineering ideas of this study to other field designs in development.\u0000 This work is the first case study of its kind that examines the relationship between the impact of LLS and the integration of a deep-water reservoir and surface facility model. This article's production forecast problem description can be utilized as a starting point to develop a general methodology for simulating complicated offshore production systems using LLSS operations.","PeriodicalId":306106,"journal":{"name":"Day 4 Thu, June 08, 2023","volume":"40 1-8 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133109337","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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