Unconventional reservoirs have nanoscale pores, complex pore structures, and heterogeneity that directly affect reservoir storage performance and fluid transport capacity. In this study, shale, mudstone, and sandstone, three typical coal sedimentary rocks from the Daqiang coal mine in the Tifa Basin, were selected for nuclear magnetic resonance (NMR) and scanning electron microscopy (SEM) investigation, with the aim to investigate the pore structure and multifractal characteristics of the coal sedimentary reservoirs and to qualitatively analyze the effects of the physical property parameters and the mineralogical compositions on the multifractal parameters. The distribution data of the NMR T2 spectra were analyzed. The results showed that (1) SEM analysis concluded that the pore system of the three different lithological samples (mudstone, shale, and sandstone) was dominated by mineral matrix pores (i.e., intergranular and intragranular pores) and in the sandstone samples, there were only a few biological pores found. (2) The distribution of the NMR T2 spectrum peaks indicates that the sandstone and shale T2 spectra are bimodal, dominated by micropores, and contain a small number of transitional pores; most of the T2 spectra of mudstone are single peaks in distribution, mainly dominated by micropores. (3) Multifractal parameters are positively correlated with porosity and significantly negatively correlated with permeability; multifractal parameters are significantly positively correlated with the content of clay minerals and kaolinite, which suggests that the increase in clay minerals and kaolinite content enhances the heterogeneity of the pore space. The negative correlation with the content of quartz suggests that the enrichment of quartz reduces the irregularity of the pore space.
{"title":"Fractal and Multifractal Characteristics on Pore Structure of Coal-Based Sedimentary Rocks Using Nuclear Magnetic Resonance","authors":"Na Zhang, Shuhui Guo, Shuaidong Wang, Yizhuo Tong, Zheng Li, Jiaqi Wu","doi":"10.2118/219457-pa","DOIUrl":"https://doi.org/10.2118/219457-pa","url":null,"abstract":"\u0000 Unconventional reservoirs have nanoscale pores, complex pore structures, and heterogeneity that directly affect reservoir storage performance and fluid transport capacity. In this study, shale, mudstone, and sandstone, three typical coal sedimentary rocks from the Daqiang coal mine in the Tifa Basin, were selected for nuclear magnetic resonance (NMR) and scanning electron microscopy (SEM) investigation, with the aim to investigate the pore structure and multifractal characteristics of the coal sedimentary reservoirs and to qualitatively analyze the effects of the physical property parameters and the mineralogical compositions on the multifractal parameters. The distribution data of the NMR T2 spectra were analyzed. The results showed that (1) SEM analysis concluded that the pore system of the three different lithological samples (mudstone, shale, and sandstone) was dominated by mineral matrix pores (i.e., intergranular and intragranular pores) and in the sandstone samples, there were only a few biological pores found. (2) The distribution of the NMR T2 spectrum peaks indicates that the sandstone and shale T2 spectra are bimodal, dominated by micropores, and contain a small number of transitional pores; most of the T2 spectra of mudstone are single peaks in distribution, mainly dominated by micropores. (3) Multifractal parameters are positively correlated with porosity and significantly negatively correlated with permeability; multifractal parameters are significantly positively correlated with the content of clay minerals and kaolinite, which suggests that the increase in clay minerals and kaolinite content enhances the heterogeneity of the pore space. The negative correlation with the content of quartz suggests that the enrichment of quartz reduces the irregularity of the pore space.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"51 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139827578","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}
Controlling the downhole pressure is an important parameter for successful and safe drilling operations. Several types of weighting agents (i.e., high-density particles), traditionally barite particles, are added to maintain the desired density of the drilling fluid (DF). The DF density is an important design parameter for preventing multiple drilling complications. These issues are caused by the settling of the dense particles, an undesired phenomenon also referred to as sagging. Therefore, there is a need to understand the settling characteristics of heavy particles in such scenarios. To this end, simultaneous measurements of liquid phase flow patterns and particle settling velocities have been conducted in a Taylor-Couette (TC) cell with a rotating inner cylinder and stationary outer cylinder separated by an annular gap of 9.0 mm. Liquid flow patterns and particle settling velocities have been measured using particle image velocimetry (PIV) and particle tracking velocimetry (PTV) techniques, respectively. Experiments have been performed by varying the rotational speed of the inner cylinder up to 200 rev/min, which is used in normal drilling operations. Spherical particles with diameters of 3.0 mm or 4.0 mm and densities between 1.2 g/cm3 and 3.95 g/cm3 were used. The liquid phases studied included deionized (DI) water and mineral oil, which are the basic components of a non-Newtonian DF with a shear-thinning viscosity. The DF is a mud-like emulsion of opaque appearance, which impedes the ability to observe the liquid flow field and particle settling in the TC cell. To address this issue, a solution of carboxymethyl cellulose (CMC) with a 6% weight concentration in DI water was used. This non-Newtonian solution displays shear-thinning rheological behavior and was used as a transparent alternative to the opaque DF. For water, PIV results have shown wavy vortex flow (WVF) to turbulent Taylor vortex flow (TTVF), which agrees with the flow patterns reported in the literature. For mineral oil, circular Couette flow (CCF) was observed at up to 100 rev/min and vortex formation at 200 rev/min. For CMC, no vortex formation was observed up to 200 rev/min, only CCF. The settling velocities for all particles in water matched with the particle settling velocities predicted using the Basset-Boussinesq-Oseen (BBO) equation of motion. For mineral oil and CMC, the results did not match well with the predicted settling velocities, especially for heavy particles due possibly to the radial particle migration and interactions with the outer cylinder wall.
{"title":"Liquid Flow Patterns and Particle Settling Velocity in a Taylor-Couette Cell Using Particle Image Velocimetry and Particle Tracking Velocimetry","authors":"Andres F. Velez, D. Kalaga, Masahiro Kawaji","doi":"10.2118/219459-pa","DOIUrl":"https://doi.org/10.2118/219459-pa","url":null,"abstract":"\u0000 Controlling the downhole pressure is an important parameter for successful and safe drilling operations. Several types of weighting agents (i.e., high-density particles), traditionally barite particles, are added to maintain the desired density of the drilling fluid (DF). The DF density is an important design parameter for preventing multiple drilling complications. These issues are caused by the settling of the dense particles, an undesired phenomenon also referred to as sagging. Therefore, there is a need to understand the settling characteristics of heavy particles in such scenarios. To this end, simultaneous measurements of liquid phase flow patterns and particle settling velocities have been conducted in a Taylor-Couette (TC) cell with a rotating inner cylinder and stationary outer cylinder separated by an annular gap of 9.0 mm. Liquid flow patterns and particle settling velocities have been measured using particle image velocimetry (PIV) and particle tracking velocimetry (PTV) techniques, respectively. Experiments have been performed by varying the rotational speed of the inner cylinder up to 200 rev/min, which is used in normal drilling operations. Spherical particles with diameters of 3.0 mm or 4.0 mm and densities between 1.2 g/cm3 and 3.95 g/cm3 were used. The liquid phases studied included deionized (DI) water and mineral oil, which are the basic components of a non-Newtonian DF with a shear-thinning viscosity. The DF is a mud-like emulsion of opaque appearance, which impedes the ability to observe the liquid flow field and particle settling in the TC cell. To address this issue, a solution of carboxymethyl cellulose (CMC) with a 6% weight concentration in DI water was used. This non-Newtonian solution displays shear-thinning rheological behavior and was used as a transparent alternative to the opaque DF. For water, PIV results have shown wavy vortex flow (WVF) to turbulent Taylor vortex flow (TTVF), which agrees with the flow patterns reported in the literature. For mineral oil, circular Couette flow (CCF) was observed at up to 100 rev/min and vortex formation at 200 rev/min. For CMC, no vortex formation was observed up to 200 rev/min, only CCF. The settling velocities for all particles in water matched with the particle settling velocities predicted using the Basset-Boussinesq-Oseen (BBO) equation of motion. For mineral oil and CMC, the results did not match well with the predicted settling velocities, especially for heavy particles due possibly to the radial particle migration and interactions with the outer cylinder wall.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"327 3-4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139877095","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}
This paper introduces an approach for the impact of skin factor on the decline curve analysis of hydraulically fractured reservoirs. The objective is to consider this impact in the production forecasting and the ultimate recovery estimation. The approach focuses on reducing the uncertainties that could be raised from this impact on the production history and increasing the accuracy of the predicted flow rates. It proposes an easy and promising tool for the decline curve analysis that could be applied confidently to different oil- and gas-producing wells and different reservoirs. This approach utilizes the rate-normalized flow rate derivative β behavior of the fractured reservoirs. This derivative demonstrates a constant behavior with time for each flow regime when the production history has not undergone the impact of the skin factor. However, the constant behavior no longer exists when this impact has influenced the production history. Instead, a power-law type model governs the relationship between the flow rate derivative and production time. New analytical flow rate decline curve models, exponential-type, are derived from the flow rate derivative power-law type models for the flow regimes. Different models for calculating the skin factor are developed for the three linear flow regimes that could be observed during the transient state flow conditions. The proposed flow rate models are used to simulate the production history and forecast the future performance. Moreover, the hydraulic fracture conductivity can be calculated using these models as well as the flow rate loss caused by skin factor. Several case studies are examined by the proposed approach where the production history is used to characterize the dominant flow regimes. The study has reached several observations and conclusions. The impact of skin factor is seen clearly throughout transient state flow regimes; however, this impact declines sharply before reaching pseudosteady-state flow (boundary-dominated flow regime). The impact of the skin factor alternates the constant behavior of the flow rate derivative with time to a power-law type relationship. A straight line of a slope (0.5) is diagnosed during hydraulic fracture and formation linear flow regime on the log-log plot of the flow rate derivative β and time, while the bilinear flow regime demonstrates a straight line of a slope (0.25). Because of the skin factor, exponential decline curve models replace the power-law type models of the flow rate during the abovementioned flow regimes. These models exhibit an excellent match between the calculated flow rate and the production history. The maximum flow rate loss occurs during very early production time even though the skin factor during this time is less than the intermediate production time. This study presents a novel approach for the decline curve analysis taking into account the impact of skin factor. The novelty is represented by considering the flow regimes in the prod
{"title":"Skin Factor Consideration in Decline Curve Analysis","authors":"S. Al-Rbeawi","doi":"10.2118/219451-pa","DOIUrl":"https://doi.org/10.2118/219451-pa","url":null,"abstract":"\u0000 This paper introduces an approach for the impact of skin factor on the decline curve analysis of hydraulically fractured reservoirs. The objective is to consider this impact in the production forecasting and the ultimate recovery estimation. The approach focuses on reducing the uncertainties that could be raised from this impact on the production history and increasing the accuracy of the predicted flow rates. It proposes an easy and promising tool for the decline curve analysis that could be applied confidently to different oil- and gas-producing wells and different reservoirs.\u0000 This approach utilizes the rate-normalized flow rate derivative β behavior of the fractured reservoirs. This derivative demonstrates a constant behavior with time for each flow regime when the production history has not undergone the impact of the skin factor. However, the constant behavior no longer exists when this impact has influenced the production history. Instead, a power-law type model governs the relationship between the flow rate derivative and production time. New analytical flow rate decline curve models, exponential-type, are derived from the flow rate derivative power-law type models for the flow regimes. Different models for calculating the skin factor are developed for the three linear flow regimes that could be observed during the transient state flow conditions. The proposed flow rate models are used to simulate the production history and forecast the future performance. Moreover, the hydraulic fracture conductivity can be calculated using these models as well as the flow rate loss caused by skin factor. Several case studies are examined by the proposed approach where the production history is used to characterize the dominant flow regimes.\u0000 The study has reached several observations and conclusions. The impact of skin factor is seen clearly throughout transient state flow regimes; however, this impact declines sharply before reaching pseudosteady-state flow (boundary-dominated flow regime). The impact of the skin factor alternates the constant behavior of the flow rate derivative with time to a power-law type relationship. A straight line of a slope (0.5) is diagnosed during hydraulic fracture and formation linear flow regime on the log-log plot of the flow rate derivative β and time, while the bilinear flow regime demonstrates a straight line of a slope (0.25). Because of the skin factor, exponential decline curve models replace the power-law type models of the flow rate during the abovementioned flow regimes. These models exhibit an excellent match between the calculated flow rate and the production history. The maximum flow rate loss occurs during very early production time even though the skin factor during this time is less than the intermediate production time.\u0000 This study presents a novel approach for the decline curve analysis taking into account the impact of skin factor. The novelty is represented by considering the flow regimes in the prod","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"13 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139888529","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. Baig, Sulaiman A. Alarifi, Mohamed Mahmoud, M. Kamal, Mobeen Murtaza, Manar M. AlAhmari, Abdulmohsen Alhumam
Sand production is one of the major problems that can occur in an oil or gas well. Enzyme-induced carbonate precipitation (EICP) methods have recently emerged as possible environment-friendly solutions for enhancing loose sand consolidation and preventing it from being produced with the fluids to the surface. This work explores increasing the consolidated sand strength and its treatment procedure using a modified EICP. The study also examines the characterization of precipitation generated by microorganisms using a computed tomography (CT) scan. To consolidate the sand specimen, nine different solutions were prepared. The solutions were a mixture of urea, urease, CaCl2, MgCl2, and xanthan gum in varying quantities. X-ray diffraction (XRD) analysis was conducted to determine the type of calcium carbonate (or CaCO3) polymorph. The morphology of calcium carbonate precipitation in the sand sample was visualized through scanning electron microscopy (SEM) imaging. The strength of consolidated samples was determined by the scratch test. The baseline EICP solution was exposed to different curing temperatures, namely, 25°C, 70°C, and 90°C. Out of these temperatures, the sample cured at 70°C showed the maximum strength, while the ones cured at 25°C demonstrated the weakest strength. This outcome emphasizes how crucial temperature control is in determining the strength development of the samples. The results highlight the importance of evaluating how varying curing temperatures affect specimen performance as well as emphasizing the need for accurate temperature control during experimental setups. Interestingly, samples made with a combination of CaCl2 and MgCl2 salts exhibited more strength when compared with EICP solutions formulated with only one type of salt. The consolidated sample that was prepared with xanthan gum with a concentration of 3 g/L showed high strength at 70°C. Notably, this technique offers a cost-effective solution compared with other methods developed to address sand production-related failures in production equipment. Furthermore, CT scans prove to be a valuable tool for investigating the characterization of microbially induced precipitation, including calcite, dolomite, and other minerals. This research underscores the professional approach in evaluating the efficacy of xanthan gum and CT scans in the context of EICP applications.
{"title":"Experimental Investigation of a Modified Enzyme-Induced Carbonate Precipitation Solution for Sand Production Control Applications","authors":"A. Baig, Sulaiman A. Alarifi, Mohamed Mahmoud, M. Kamal, Mobeen Murtaza, Manar M. AlAhmari, Abdulmohsen Alhumam","doi":"10.2118/219447-pa","DOIUrl":"https://doi.org/10.2118/219447-pa","url":null,"abstract":"\u0000 Sand production is one of the major problems that can occur in an oil or gas well. Enzyme-induced carbonate precipitation (EICP) methods have recently emerged as possible environment-friendly solutions for enhancing loose sand consolidation and preventing it from being produced with the fluids to the surface. This work explores increasing the consolidated sand strength and its treatment procedure using a modified EICP. The study also examines the characterization of precipitation generated by microorganisms using a computed tomography (CT) scan. To consolidate the sand specimen, nine different solutions were prepared. The solutions were a mixture of urea, urease, CaCl2, MgCl2, and xanthan gum in varying quantities. X-ray diffraction (XRD) analysis was conducted to determine the type of calcium carbonate (or CaCO3) polymorph. The morphology of calcium carbonate precipitation in the sand sample was visualized through scanning electron microscopy (SEM) imaging. The strength of consolidated samples was determined by the scratch test. The baseline EICP solution was exposed to different curing temperatures, namely, 25°C, 70°C, and 90°C. Out of these temperatures, the sample cured at 70°C showed the maximum strength, while the ones cured at 25°C demonstrated the weakest strength. This outcome emphasizes how crucial temperature control is in determining the strength development of the samples. The results highlight the importance of evaluating how varying curing temperatures affect specimen performance as well as emphasizing the need for accurate temperature control during experimental setups. Interestingly, samples made with a combination of CaCl2 and MgCl2 salts exhibited more strength when compared with EICP solutions formulated with only one type of salt. The consolidated sample that was prepared with xanthan gum with a concentration of 3 g/L showed high strength at 70°C. Notably, this technique offers a cost-effective solution compared with other methods developed to address sand production-related failures in production equipment. Furthermore, CT scans prove to be a valuable tool for investigating the characterization of microbially induced precipitation, including calcite, dolomite, and other minerals. This research underscores the professional approach in evaluating the efficacy of xanthan gum and CT scans in the context of EICP applications.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139821747","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}
How to effectively control the recoil response after an emergency disconnection is one of the core technical problems in ensuring the safe and reliable operation of a deepwater drilling riser. Currently, the theoretical analysis is based on a discretization model or numerical simulation, which ignores the continuity of the riser system and the coupling effects of load acting on the riser. To address this problem further, in this paper, we establish a mechanical model and control equation with infinite degree of freedom for riser recoil response, where the heave motion of the floating drilling platform, seawater damping, and the viscous resistance of drilling fluid discharge were taken into account. In addition, the correctness of the model and solving approach are verified against the Orcaflex software. On this basis, the influence of wave period, wave height, initial phase angle, and tension coefficient on the recoil characteristics are discussed. The success of riser emergency disconnection is related to the clearance between the lower marine riser package (LMRP) and the blowout preventer (BOP) and the axial force distribution of the riser. The influence of the above-mentioned factors on the riser recoil response is also complicated. On the basis of the assumptions put forward and the model established, some quantitative conclusions are drawn. This study is of reference significance for safety control of riser emergency disconnection operation.
{"title":"Application of Mode Superposition Method in the Recoil Response of Deepwater Drilling Risers after Emergency Disconnection","authors":"Yanbin Wang, Tian Luan, Deli Gao, Rui Li","doi":"10.2118/219455-pa","DOIUrl":"https://doi.org/10.2118/219455-pa","url":null,"abstract":"\u0000 How to effectively control the recoil response after an emergency disconnection is one of the core technical problems in ensuring the safe and reliable operation of a deepwater drilling riser. Currently, the theoretical analysis is based on a discretization model or numerical simulation, which ignores the continuity of the riser system and the coupling effects of load acting on the riser. To address this problem further, in this paper, we establish a mechanical model and control equation with infinite degree of freedom for riser recoil response, where the heave motion of the floating drilling platform, seawater damping, and the viscous resistance of drilling fluid discharge were taken into account. In addition, the correctness of the model and solving approach are verified against the Orcaflex software. On this basis, the influence of wave period, wave height, initial phase angle, and tension coefficient on the recoil characteristics are discussed. The success of riser emergency disconnection is related to the clearance between the lower marine riser package (LMRP) and the blowout preventer (BOP) and the axial force distribution of the riser. The influence of the above-mentioned factors on the riser recoil response is also complicated. On the basis of the assumptions put forward and the model established, some quantitative conclusions are drawn. This study is of reference significance for safety control of riser emergency disconnection operation.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"19 10","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139813542","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}
Controlling the downhole pressure is an important parameter for successful and safe drilling operations. Several types of weighting agents (i.e., high-density particles), traditionally barite particles, are added to maintain the desired density of the drilling fluid (DF). The DF density is an important design parameter for preventing multiple drilling complications. These issues are caused by the settling of the dense particles, an undesired phenomenon also referred to as sagging. Therefore, there is a need to understand the settling characteristics of heavy particles in such scenarios. To this end, simultaneous measurements of liquid phase flow patterns and particle settling velocities have been conducted in a Taylor-Couette (TC) cell with a rotating inner cylinder and stationary outer cylinder separated by an annular gap of 9.0 mm. Liquid flow patterns and particle settling velocities have been measured using particle image velocimetry (PIV) and particle tracking velocimetry (PTV) techniques, respectively. Experiments have been performed by varying the rotational speed of the inner cylinder up to 200 rev/min, which is used in normal drilling operations. Spherical particles with diameters of 3.0 mm or 4.0 mm and densities between 1.2 g/cm3 and 3.95 g/cm3 were used. The liquid phases studied included deionized (DI) water and mineral oil, which are the basic components of a non-Newtonian DF with a shear-thinning viscosity. The DF is a mud-like emulsion of opaque appearance, which impedes the ability to observe the liquid flow field and particle settling in the TC cell. To address this issue, a solution of carboxymethyl cellulose (CMC) with a 6% weight concentration in DI water was used. This non-Newtonian solution displays shear-thinning rheological behavior and was used as a transparent alternative to the opaque DF. For water, PIV results have shown wavy vortex flow (WVF) to turbulent Taylor vortex flow (TTVF), which agrees with the flow patterns reported in the literature. For mineral oil, circular Couette flow (CCF) was observed at up to 100 rev/min and vortex formation at 200 rev/min. For CMC, no vortex formation was observed up to 200 rev/min, only CCF. The settling velocities for all particles in water matched with the particle settling velocities predicted using the Basset-Boussinesq-Oseen (BBO) equation of motion. For mineral oil and CMC, the results did not match well with the predicted settling velocities, especially for heavy particles due possibly to the radial particle migration and interactions with the outer cylinder wall.
{"title":"Liquid Flow Patterns and Particle Settling Velocity in a Taylor-Couette Cell Using Particle Image Velocimetry and Particle Tracking Velocimetry","authors":"Andres F. Velez, D. Kalaga, Masahiro Kawaji","doi":"10.2118/219459-pa","DOIUrl":"https://doi.org/10.2118/219459-pa","url":null,"abstract":"\u0000 Controlling the downhole pressure is an important parameter for successful and safe drilling operations. Several types of weighting agents (i.e., high-density particles), traditionally barite particles, are added to maintain the desired density of the drilling fluid (DF). The DF density is an important design parameter for preventing multiple drilling complications. These issues are caused by the settling of the dense particles, an undesired phenomenon also referred to as sagging. Therefore, there is a need to understand the settling characteristics of heavy particles in such scenarios. To this end, simultaneous measurements of liquid phase flow patterns and particle settling velocities have been conducted in a Taylor-Couette (TC) cell with a rotating inner cylinder and stationary outer cylinder separated by an annular gap of 9.0 mm. Liquid flow patterns and particle settling velocities have been measured using particle image velocimetry (PIV) and particle tracking velocimetry (PTV) techniques, respectively. Experiments have been performed by varying the rotational speed of the inner cylinder up to 200 rev/min, which is used in normal drilling operations. Spherical particles with diameters of 3.0 mm or 4.0 mm and densities between 1.2 g/cm3 and 3.95 g/cm3 were used. The liquid phases studied included deionized (DI) water and mineral oil, which are the basic components of a non-Newtonian DF with a shear-thinning viscosity. The DF is a mud-like emulsion of opaque appearance, which impedes the ability to observe the liquid flow field and particle settling in the TC cell. To address this issue, a solution of carboxymethyl cellulose (CMC) with a 6% weight concentration in DI water was used. This non-Newtonian solution displays shear-thinning rheological behavior and was used as a transparent alternative to the opaque DF. For water, PIV results have shown wavy vortex flow (WVF) to turbulent Taylor vortex flow (TTVF), which agrees with the flow patterns reported in the literature. For mineral oil, circular Couette flow (CCF) was observed at up to 100 rev/min and vortex formation at 200 rev/min. For CMC, no vortex formation was observed up to 200 rev/min, only CCF. The settling velocities for all particles in water matched with the particle settling velocities predicted using the Basset-Boussinesq-Oseen (BBO) equation of motion. For mineral oil and CMC, the results did not match well with the predicted settling velocities, especially for heavy particles due possibly to the radial particle migration and interactions with the outer cylinder wall.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"3 S4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139817239","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}
Quantitative prediction of reservoir tectonic fracture development characteristics, opening pressures, and opening sequences is critical in the exploration and development of oil- and gas-bearing reservoirs and thus has received widespread attention. Using numerical simulations of the paleostress field during the formation of tectonic fractures and the rock fracture criterion, we predict the development and occurrence of fractures in the Middle Ordovician Yijianfang Formation in the Shunnan region of the Tarim Basin, China. The local paleostress fields reflected by the mechanical properties and occurrence of tectonic fractures obtained from core descriptions, acoustic emission (AE) experiments, paleomagnetic experiments, sound velocity measurements, and borehole breakouts were used to determine the regional paleostress and in-situ stress. We established a geomechanical model by combining the mechanical parameters of the rocks with the finite element method (FEM), optimizing the boundary conditions with a self-adaptive constraint algorithm, and conducting numerical simulations of the in-situ stresses. Fracture occurrence and numerical simulation results of the in-situ stress field were used to determine the opening pressure (Pk) and opening sequence of the fractures. The level of fracture development decreases away from the strike-slip fault in the study area. Fracture development is positively correlated with the Young’s modulus, paleostress difference, and paleostress difference coefficient of the rock. The direction of the maximum horizontal principal stress is from north-northeast (NNE) to northeast (NE). Initially, shear fractures and tensional fractures oriented NNE 30°–35° and NE 40°–45°, respectively, open during the water injection process. Pk is positively correlated with the horizontal stress difference coefficient and the angle between the fracture strike and the maximum horizontal principal stress. At the structural highs (burial depths shallower than 6450 m) and the structural lows (burial depths deeper than 6450 m), the burial depth correlates negatively and positively with Pk, respectively. This investigation of the development, occurrence, Pk, and opening sequence of tectonic fractures and their principal controlling factors will have a positive impact on the future exploration and production opportunities of similar fractured reservoirs.
储层构造裂缝发育特征、张开压力和张开序列的定量预测对含油气藏的勘探开发至关重要，因此受到广泛关注。利用构造裂缝形成过程中的古应力场数值模拟和岩石裂缝判据，我们预测了中国塔里木盆地顺南地区中奥陶统易家房组裂缝的发育和出现情况。利用岩芯描述、声发射（AE）实验、古地磁实验、声速测量和钻孔破口获得的力学性质和构造断裂发生所反映的局部古应力场，确定了区域古应力和原位应力。我们将岩石力学参数与有限元法（FEM）相结合，建立了地质力学模型，利用自适应约束算法优化了边界条件，并对原位应力进行了数值模拟。利用断裂的发生和原位应力场的数值模拟结果，确定了断裂的张开压力（Pk）和张开顺序。在研究区域，断裂发育程度在远离走向滑动断层的地方有所降低。断裂发育程度与岩石的杨氏模量、古应力差和古应力差系数呈正相关。最大水平主应力方向为北东北（NNE）至东北（NE）。最初，在注水过程中，方向分别为 NNE 30°-35°和 NE 40°-45°的剪切断裂和张拉断裂会打开。Pk 与水平应力差系数以及断裂走向与最大水平主应力之间的夹角呈正相关。在构造高位（埋深小于 6450 米）和构造低位（埋深大于 6450 米），埋深分别与 Pk 呈负相关和正相关。对构造裂缝的发育、出现、Pk 和张开顺序及其主要控制因素的研究，将对今后类似裂缝储层的勘探和生产机会产生积极影响。
{"title":"Quantitative Prediction of the Development and Opening Sequence of Fractures in an Ultradeep Carbonate Reservoir: A Case Study of the Middle Ordovician in the Shunnan Area, Tarim Basin, China","authors":"Yuntao Li, Wenlong Ding, Jun Han, Xuyun Chen, Cheng Huang, Jingtian Li, Shihao Ding","doi":"10.2118/219453-pa","DOIUrl":"https://doi.org/10.2118/219453-pa","url":null,"abstract":"\u0000 Quantitative prediction of reservoir tectonic fracture development characteristics, opening pressures, and opening sequences is critical in the exploration and development of oil- and gas-bearing reservoirs and thus has received widespread attention. Using numerical simulations of the paleostress field during the formation of tectonic fractures and the rock fracture criterion, we predict the development and occurrence of fractures in the Middle Ordovician Yijianfang Formation in the Shunnan region of the Tarim Basin, China. The local paleostress fields reflected by the mechanical properties and occurrence of tectonic fractures obtained from core descriptions, acoustic emission (AE) experiments, paleomagnetic experiments, sound velocity measurements, and borehole breakouts were used to determine the regional paleostress and in-situ stress. We established a geomechanical model by combining the mechanical parameters of the rocks with the finite element method (FEM), optimizing the boundary conditions with a self-adaptive constraint algorithm, and conducting numerical simulations of the in-situ stresses. Fracture occurrence and numerical simulation results of the in-situ stress field were used to determine the opening pressure (Pk) and opening sequence of the fractures. The level of fracture development decreases away from the strike-slip fault in the study area. Fracture development is positively correlated with the Young’s modulus, paleostress difference, and paleostress difference coefficient of the rock. The direction of the maximum horizontal principal stress is from north-northeast (NNE) to northeast (NE). Initially, shear fractures and tensional fractures oriented NNE 30°–35° and NE 40°–45°, respectively, open during the water injection process. Pk is positively correlated with the horizontal stress difference coefficient and the angle between the fracture strike and the maximum horizontal principal stress. At the structural highs (burial depths shallower than 6450 m) and the structural lows (burial depths deeper than 6450 m), the burial depth correlates negatively and positively with Pk, respectively. This investigation of the development, occurrence, Pk, and opening sequence of tectonic fractures and their principal controlling factors will have a positive impact on the future exploration and production opportunities of similar fractured reservoirs.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"44 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139878317","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}
Clement Afagwu, Saad Alafnan, Mohamed Mahmoud, Shabeeb Alajmei, S. Patil
Shale and ultratight gas reservoirs are multiscale, containing organic matter (OM) and inorganic minerals in multiple pore compartments of different pore shapes and scales. Selecting a suitable model to describe the multiscale transport mechanisms requires a minimum understanding of the inherent pore shape, OM content, typical pore size, and inherent flow regime. Interestingly, during gas production and associated pressure depletion, some mechanisms, such as pore compressibility, pore diffusion, and diffusion of sorbed gas molecules, become significant at lower pressure. In this study, multiscale and multiphysics permeability models are introduced that couple the effects of poroelasticity (especially in slit-shaped pores with <1.0 aspect ratio) and sorbed gas diffusion, Fick diffusion, transition diffusion, or Knudsen diffusion, depending on the pore structural properties at multiscale for shale and ultratight gas applications. Shale here refers to organic-rich low-permeability rock with >1–2 wt% OM, while ultratight gas has negligible organic content with <1.0 wt%. These experimentally and computationally validated models could be combined with Gaussian pressure transient solutions to effectively understand the uncertainty in multiphysics gas permeability in addition to the hydraulic and natural fracture parameters for large-scale flow simulation of hydraulically fractured unconventional reservoirs.
{"title":"Permeability Modeling of Pore Shapes, Compaction, Sorption, and Molecular Diffusivity in Unconventional Reservoirs","authors":"Clement Afagwu, Saad Alafnan, Mohamed Mahmoud, Shabeeb Alajmei, S. Patil","doi":"10.2118/219460-pa","DOIUrl":"https://doi.org/10.2118/219460-pa","url":null,"abstract":"\u0000 Shale and ultratight gas reservoirs are multiscale, containing organic matter (OM) and inorganic minerals in multiple pore compartments of different pore shapes and scales. Selecting a suitable model to describe the multiscale transport mechanisms requires a minimum understanding of the inherent pore shape, OM content, typical pore size, and inherent flow regime. Interestingly, during gas production and associated pressure depletion, some mechanisms, such as pore compressibility, pore diffusion, and diffusion of sorbed gas molecules, become significant at lower pressure. In this study, multiscale and multiphysics permeability models are introduced that couple the effects of poroelasticity (especially in slit-shaped pores with <1.0 aspect ratio) and sorbed gas diffusion, Fick diffusion, transition diffusion, or Knudsen diffusion, depending on the pore structural properties at multiscale for shale and ultratight gas applications. Shale here refers to organic-rich low-permeability rock with >1–2 wt% OM, while ultratight gas has negligible organic content with <1.0 wt%. These experimentally and computationally validated models could be combined with Gaussian pressure transient solutions to effectively understand the uncertainty in multiphysics gas permeability in addition to the hydraulic and natural fracture parameters for large-scale flow simulation of hydraulically fractured unconventional reservoirs.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"17 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139874271","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}
Songyan Li, Kexin Du, Yaohui Wei, Minghe Li, Zhoujie Wang
Imbibition is one of the main mechanisms for fluid transport in porous media. A combination of carbonated water and active water [active-carbonated water (ACW)] has great prospects in enhanced oil recovery (EOR) and carbon reduction processes. To date, the law of hydrocarbon recovery induced by ACW imbibition is not clear. In this paper, the optimal surfactant concentration was first selected through a spontaneous imbibition experiment, and on this basis, CO2 was dissolved to form ACW. The imbibition effects of formation water (FW), surfactant solution DX-1, and ACW under different pressures were compared. The changes in rock wettability in the three imbibition solutions during imbibition were studied by measuring the contact angle. The effect of fracture on ACW imbibition was studied. Finally, the improved NB−1 was calculated to elucidate the mechanism of forced imbibition for EOR. The results show that 0.1% DX-1 produces the optimal imbibition effect. Pressure is positively correlated with imbibition recovery. ACW can significantly improve the imbibition effect due to its wettability reversal ability being better than those of FW and DX-1. CO2 in ACW can be trapped in the formation through diffusion into small rock pores. The contact angles of the three imbibition solutions decrease with increasing pressure. The contact angle between the rock and oil droplet in the ACW is as low as 38.13°. In addition, the fracture increases the contact area between the matrix and the fluid, thereby improving the imbibition effect. The alteration of NB−1 indicates that FW imbibition is gravity-driven cocurrent imbibition. DX-1 and ACW imbibitions are countercurrent imbibitions driven by capillary force and gravity. The above results demonstrate the feasibility of ACW in low-permeability reservoir development and carbon reduction.
{"title":"Experimental Study on Forced Imbibition and Wettability Alteration of Active Carbonated Water in Low-Permeability Sandstone Reservoir","authors":"Songyan Li, Kexin Du, Yaohui Wei, Minghe Li, Zhoujie Wang","doi":"10.2118/219454-pa","DOIUrl":"https://doi.org/10.2118/219454-pa","url":null,"abstract":"\u0000 Imbibition is one of the main mechanisms for fluid transport in porous media. A combination of carbonated water and active water [active-carbonated water (ACW)] has great prospects in enhanced oil recovery (EOR) and carbon reduction processes. To date, the law of hydrocarbon recovery induced by ACW imbibition is not clear. In this paper, the optimal surfactant concentration was first selected through a spontaneous imbibition experiment, and on this basis, CO2 was dissolved to form ACW. The imbibition effects of formation water (FW), surfactant solution DX-1, and ACW under different pressures were compared. The changes in rock wettability in the three imbibition solutions during imbibition were studied by measuring the contact angle. The effect of fracture on ACW imbibition was studied. Finally, the improved NB−1 was calculated to elucidate the mechanism of forced imbibition for EOR. The results show that 0.1% DX-1 produces the optimal imbibition effect. Pressure is positively correlated with imbibition recovery. ACW can significantly improve the imbibition effect due to its wettability reversal ability being better than those of FW and DX-1. CO2 in ACW can be trapped in the formation through diffusion into small rock pores. The contact angles of the three imbibition solutions decrease with increasing pressure. The contact angle between the rock and oil droplet in the ACW is as low as 38.13°. In addition, the fracture increases the contact area between the matrix and the fluid, thereby improving the imbibition effect. The alteration of NB−1 indicates that FW imbibition is gravity-driven cocurrent imbibition. DX-1 and ACW imbibitions are countercurrent imbibitions driven by capillary force and gravity. The above results demonstrate the feasibility of ACW in low-permeability reservoir development and carbon reduction.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"34 5","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139811712","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}
We present artificial neural network (ANN) models for predicting the flowing bottomhole pressure (FBHP) of unconventional oil wells under gas lift operations. Well parameters, fluid properties, production/injection data, and bottomhole gauge pressures from 16 shale oil wells in Permian Basin, Texas, USA, are analyzed to determine key parameters affecting FBHP during the gas lift operation. For the reservoir fluid properties, several pressure-volume-temperature (PVT) models, such as Benedict-Webb-Rubin (BWR); Lee, Gonzalez, and Eakin; and Standing, among others, are examined against experimentally tuned fluid properties (i.e., viscosity, formation volume factor, and solution gas-oil ratio) to identify representative fluid (PVT) models for oil and gas properties. Pipe flow models (i.e., Hagedorn and Brown; Gray, Begs and Brill; and Petalas and Aziz) are also examined by comparing calculated FBHP against the bottomhole gauge pressures to identify a representative pipe flow model. Training and test data sets are then generated using the representative PVT and pipe flow models to develop a physics-based ANN model. The physics-based ANN model inputs are hydrocarbon fluid properties, liquid flow rate (qL), gas-liquid ratio (GLR), water-oil ratio (WOR), well true vertical depth (TVD), wellhead pressure (Pwh), wellhead temperature (Twh), and temperature gradient (dT/dh). A data-based ANN model is also developed based on only TVD, Pwh, qL, GLR, and WOR. Both physics- and data-based ANN models are trained through hyperparameter optimization using genetic algorithm and K-fold validation and then tested against the gauge FBHP. The results reveal that both models perform well with the FBHP prediction from field data with a normalized mean absolute error (NMAE) of around 10%. However, a comparison between results from the physics- and data-based ANN models shows that the accuracy of the physics-based model is higher at the later phase of the gas lift operation when the steady-state pipe flow is well established. On the contrary, the data-based model performs better for the early phase of gas lift operation when transient flow behavior is dominant. Developed ANN models and workflows can be applied to optimize gas lift operations under different fluid and well conditions.
我们提出了人工神经网络 (ANN) 模型，用于预测气举作业下非常规油井的流动井底压力 (FBHP)。我们分析了美国德克萨斯州二叠纪盆地 16 口页岩油井的油井参数、流体性质、生产/注入数据以及井底表压，以确定气举作业期间影响井底压力的关键参数。在储层流体属性方面，针对实验调整的流体属性（即粘度、地层体积因子和溶液气油比），研究了几种压力-体积-温度（PVT）模型，如 Benedict-Webb-Rubin (BWR)、Lee、Gonzalez 和 Eakin 以及 Standing 等，以确定油气属性的代表性流体（PVT）模型。还通过将计算的 FBHP 与井底表压进行比较来确定具有代表性的管流模型（即 Hagedorn 和 Brown；Gray、Begs 和 Brill；以及 Petalas 和 Aziz）。然后使用具有代表性的 PVT 和管流模型生成训练和测试数据集，以开发基于物理的 ANN 模型。基于物理的 ANN 模型输入包括碳氢化合物流体特性、液体流速 (qL)、气液比 (GLR)、水油比 (WOR)、油井实际垂直深度 (TVD)、井口压力 (Pwh)、井口温度 (Twh) 和温度梯度 (dT/dh)。此外，还开发了一个基于数据的 ANN 模型，该模型仅基于 TVD、Pwh、qL、GLR 和 WOR。使用遗传算法和 K-fold 验证，通过超参数优化对物理和数据 ANN 模型进行训练，然后根据仪器 FBHP 进行测试。结果表明，这两种模型都能很好地预测来自现场数据的 FBHP，归一化平均绝对误差 (NMAE) 约为 10%。然而，对基于物理的 ANN 模型和基于数据的 ANN 模型的结果进行比较后发现，基于物理的模型在气举运行的后期阶段，即稳态管道流量建立良好的阶段精度更高。相反，当瞬态流动行为占主导地位时，基于数据的模型在气举运行的早期阶段表现更好。开发的 ANN 模型和工作流程可用于优化不同流体和油井条件下的气举作业。
{"title":"Flowing Bottomhole Pressure during Gas Lift in Unconventional Oil Wells","authors":"Miao Jin, Hamid Emami‐Meybodi, Mohammad Ahmadi","doi":"10.2118/214832-pa","DOIUrl":"https://doi.org/10.2118/214832-pa","url":null,"abstract":"\u0000 We present artificial neural network (ANN) models for predicting the flowing bottomhole pressure (FBHP) of unconventional oil wells under gas lift operations. Well parameters, fluid properties, production/injection data, and bottomhole gauge pressures from 16 shale oil wells in Permian Basin, Texas, USA, are analyzed to determine key parameters affecting FBHP during the gas lift operation. For the reservoir fluid properties, several pressure-volume-temperature (PVT) models, such as Benedict-Webb-Rubin (BWR); Lee, Gonzalez, and Eakin; and Standing, among others, are examined against experimentally tuned fluid properties (i.e., viscosity, formation volume factor, and solution gas-oil ratio) to identify representative fluid (PVT) models for oil and gas properties. Pipe flow models (i.e., Hagedorn and Brown; Gray, Begs and Brill; and Petalas and Aziz) are also examined by comparing calculated FBHP against the bottomhole gauge pressures to identify a representative pipe flow model. Training and test data sets are then generated using the representative PVT and pipe flow models to develop a physics-based ANN model. The physics-based ANN model inputs are hydrocarbon fluid properties, liquid flow rate (qL), gas-liquid ratio (GLR), water-oil ratio (WOR), well true vertical depth (TVD), wellhead pressure (Pwh), wellhead temperature (Twh), and temperature gradient (dT/dh). A data-based ANN model is also developed based on only TVD, Pwh, qL, GLR, and WOR. Both physics- and data-based ANN models are trained through hyperparameter optimization using genetic algorithm and K-fold validation and then tested against the gauge FBHP. The results reveal that both models perform well with the FBHP prediction from field data with a normalized mean absolute error (NMAE) of around 10%. However, a comparison between results from the physics- and data-based ANN models shows that the accuracy of the physics-based model is higher at the later phase of the gas lift operation when the steady-state pipe flow is well established. On the contrary, the data-based model performs better for the early phase of gas lift operation when transient flow behavior is dominant. Developed ANN models and workflows can be applied to optimize gas lift operations under different fluid and well conditions.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"5 6","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139820195","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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