Guohua Gao, Horacio Florez, Sean Jost, Shakir Shaikh, Kefei Wang, Jeroen Vink, Carl Blom, Terence J. Wells, Fredrik Saaf
Summary Previous implementation of the distributed Gauss-Newton (DGN) optimization algorithm ran multiple optimization threads in parallel, employing a synchronous running mode (S-DGN). As a result, it waits for all simulations submitted in each iteration to complete, which may significantly degrade performance because a few simulations may run much longer than others, especially for time-consuming real-field cases. To overcome this limitation and thus improve the DGN optimizer’s execution, we propose two asynchronous DGN (A-DGN) optimization algorithms in this paper. The two A-DGN optimization algorithms are (1) the local-search algorithm (A-DGN-LS) to locate multiple maximum a-posteriori (MAP) estimates and (2) the integrated global-search algorithm with the randomized maximum likelihood (RML) method (A-DGN + RML) to generate hundreds of RML samples in parallel for uncertainty quantification. We propose using batch together with a checking time interval to control the optimization process. The A-DGN optimizers check the status of all running simulations after every checking time frame. The iteration index of each optimization thread is updated dynamically according to its simulation status. Thus, different optimization threads may have different iteration indices in the same batch. A new simulation case is proposed immediately once the simulation of an optimization thread is completed, without waiting for the completion of other simulations. We modified the training data set updating algorithm using each thread’s dynamically updated iteration index to implement the asynchronous running mode. We apply the modified QR decomposition method to estimate the sensitivity matrix at the best solution of each optimization thread by linear interpolation of all or a subset of the training data to avoid the issue of solving a linear system with a singular matrix because of insufficient training data points in early batches. A new simulation case (or search point) is generated by solving the Gauss-Newton (GN) trust-region subproblem (GNTRS) using the estimated sensitivity matrix. We developed a more efficient and robust GNTRS solver using eigenvalue decomposition (EVD). The proposed A-DGN optimization methods are tested and validated on a 2D analytical toy problem and a synthetic history-matching problem and then applied to a real-field deepwater reservoir model. Numerical tests confirm that the proposed A-DGN optimization methods can converge to solutions with matching quality comparable to those obtained by the S-DGN optimizers, saving on the time required for the optimizer to converge by a factor ranging from 1.3 to 2 when compared to the S-DGN optimizer depending on the problem. The new A-DGN optimization algorithms improve efficiency and robustness in solving history-matching or inversion problems, especially for uncertainty quantification of subsurface model parameters and production forecasts of real-field reservoirs by conditioning production data.
{"title":"Implementation of Asynchronous Distributed Gauss-Newton Optimization Algorithms for Uncertainty Quantification by Conditioning to Production Data","authors":"Guohua Gao, Horacio Florez, Sean Jost, Shakir Shaikh, Kefei Wang, Jeroen Vink, Carl Blom, Terence J. Wells, Fredrik Saaf","doi":"10.2118/210118-pa","DOIUrl":"https://doi.org/10.2118/210118-pa","url":null,"abstract":"Summary Previous implementation of the distributed Gauss-Newton (DGN) optimization algorithm ran multiple optimization threads in parallel, employing a synchronous running mode (S-DGN). As a result, it waits for all simulations submitted in each iteration to complete, which may significantly degrade performance because a few simulations may run much longer than others, especially for time-consuming real-field cases. To overcome this limitation and thus improve the DGN optimizer’s execution, we propose two asynchronous DGN (A-DGN) optimization algorithms in this paper. The two A-DGN optimization algorithms are (1) the local-search algorithm (A-DGN-LS) to locate multiple maximum a-posteriori (MAP) estimates and (2) the integrated global-search algorithm with the randomized maximum likelihood (RML) method (A-DGN + RML) to generate hundreds of RML samples in parallel for uncertainty quantification. We propose using batch together with a checking time interval to control the optimization process. The A-DGN optimizers check the status of all running simulations after every checking time frame. The iteration index of each optimization thread is updated dynamically according to its simulation status. Thus, different optimization threads may have different iteration indices in the same batch. A new simulation case is proposed immediately once the simulation of an optimization thread is completed, without waiting for the completion of other simulations. We modified the training data set updating algorithm using each thread’s dynamically updated iteration index to implement the asynchronous running mode. We apply the modified QR decomposition method to estimate the sensitivity matrix at the best solution of each optimization thread by linear interpolation of all or a subset of the training data to avoid the issue of solving a linear system with a singular matrix because of insufficient training data points in early batches. A new simulation case (or search point) is generated by solving the Gauss-Newton (GN) trust-region subproblem (GNTRS) using the estimated sensitivity matrix. We developed a more efficient and robust GNTRS solver using eigenvalue decomposition (EVD). The proposed A-DGN optimization methods are tested and validated on a 2D analytical toy problem and a synthetic history-matching problem and then applied to a real-field deepwater reservoir model. Numerical tests confirm that the proposed A-DGN optimization methods can converge to solutions with matching quality comparable to those obtained by the S-DGN optimizers, saving on the time required for the optimizer to converge by a factor ranging from 1.3 to 2 when compared to the S-DGN optimizer depending on the problem. The new A-DGN optimization algorithms improve efficiency and robustness in solving history-matching or inversion problems, especially for uncertainty quantification of subsurface model parameters and production forecasts of real-field reservoirs by conditioning production data.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"57 5-6","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135715082","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Moacyr N. Borges Filho, Thalles Mello, Claudia M. Scheid, Luis A. Calçada, A. T. Waldmann, André Leibsohn Martins, José C. Pinto
Summary The well drilling process requires constant monitoring to ensure that the properties of the drilling fluids remain within acceptable ranges for safe and effective operation of the well drilling process. The present work developed a principal component analysis (PCA)-based methodology for diagnosing anomalies in drilling fluids, and detecting and identifying abnormal drilling fluid properties during well drilling operations. The main novelty of the present work regards the application of multivariate techniques for diagnosing anomalies (faults) in drilling fluids, increasing the literature on fault diagnosis techniques applied to the petroleum industry, and producing a promising methodology for field applications. The proposed technique was implemented and validated in a pilot drilling fluid production unit through continuous online monitoring of the conductivity, density, and apparent viscosity of drilling fluids. Model training was carried out with data collected during assisted normal operation, allowing detection of abnormal conditions with less than 1% of false positives and less than 0.5% of false negatives. Additionally, the proposed methodology also allowed the correct diagnosis of the observed faults. The results indicated that PCA-based approaches can be used for the online monitoring of drilling fluid properties and fault diagnosis in real well drilling operations.
{"title":"The Monitoring of Abnormal Fluid Properties Based on PCA Technique as an Alternative Strategy to Support Autonomous Drilling Operations","authors":"Moacyr N. Borges Filho, Thalles Mello, Claudia M. Scheid, Luis A. Calçada, A. T. Waldmann, André Leibsohn Martins, José C. Pinto","doi":"10.2118/218012-pa","DOIUrl":"https://doi.org/10.2118/218012-pa","url":null,"abstract":"Summary The well drilling process requires constant monitoring to ensure that the properties of the drilling fluids remain within acceptable ranges for safe and effective operation of the well drilling process. The present work developed a principal component analysis (PCA)-based methodology for diagnosing anomalies in drilling fluids, and detecting and identifying abnormal drilling fluid properties during well drilling operations. The main novelty of the present work regards the application of multivariate techniques for diagnosing anomalies (faults) in drilling fluids, increasing the literature on fault diagnosis techniques applied to the petroleum industry, and producing a promising methodology for field applications. The proposed technique was implemented and validated in a pilot drilling fluid production unit through continuous online monitoring of the conductivity, density, and apparent viscosity of drilling fluids. Model training was carried out with data collected during assisted normal operation, allowing detection of abnormal conditions with less than 1% of false positives and less than 0.5% of false negatives. Additionally, the proposed methodology also allowed the correct diagnosis of the observed faults. The results indicated that PCA-based approaches can be used for the online monitoring of drilling fluid properties and fault diagnosis in real well drilling operations.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"43 2","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135271186","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Summary The friction coefficient is an important factor that affects the accurate calculation of wellbore annular pressure distribution and is of great significance for the safety of drilling operations. To date, investigations of the friction coefficient mainly focused on low-viscosity liquids (such as water and kerosene). Thus, the obtained friction coefficients have poor applicability in the calculation of gas–oil-based mud two-phase flow. This study reports gas–oil two-phase flow experiments for different viscosities (16–39 mPa·s) in the annulus of a large wellbore, performed using an experimental wellbore (Φ100×Φ60×12 000 mm). The gas–liquid mixture Reynolds number ranges from 500 to 10,000. The results reveal a consistent trend for the variation of the friction coefficient under different flow patterns. For the same mixture Reynolds number, a larger liquid viscosity corresponds to a smaller variation of the friction coefficient among different flow patterns. The larger the superficial liquid velocity, the greater the friction coefficient. Based on the dimensionless analysis of the experimental data, a model for the calculation of the friction coefficient of gas–oil two-phase flow in a large annulus is established, and its prediction error relative to the experimental data is found to be less than 30%. This study can provide a basis for accurate calculations of gas–oil-based mud two-phase flow in drilling wellbores.
{"title":"Experimental Study on Friction Coefficient of Gas–Oil Two-Phase Flow in a Large Annulus","authors":"Zhiyuan Wang, Junjie Hu, Shaowei Pan, Jianbo Zhang, Keshan Chen, Baojiang Sun","doi":"10.2118/218014-pa","DOIUrl":"https://doi.org/10.2118/218014-pa","url":null,"abstract":"Summary The friction coefficient is an important factor that affects the accurate calculation of wellbore annular pressure distribution and is of great significance for the safety of drilling operations. To date, investigations of the friction coefficient mainly focused on low-viscosity liquids (such as water and kerosene). Thus, the obtained friction coefficients have poor applicability in the calculation of gas–oil-based mud two-phase flow. This study reports gas–oil two-phase flow experiments for different viscosities (16–39 mPa·s) in the annulus of a large wellbore, performed using an experimental wellbore (Φ100×Φ60×12 000 mm). The gas–liquid mixture Reynolds number ranges from 500 to 10,000. The results reveal a consistent trend for the variation of the friction coefficient under different flow patterns. For the same mixture Reynolds number, a larger liquid viscosity corresponds to a smaller variation of the friction coefficient among different flow patterns. The larger the superficial liquid velocity, the greater the friction coefficient. Based on the dimensionless analysis of the experimental data, a model for the calculation of the friction coefficient of gas–oil two-phase flow in a large annulus is established, and its prediction error relative to the experimental data is found to be less than 30%. This study can provide a basis for accurate calculations of gas–oil-based mud two-phase flow in drilling wellbores.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"14 8","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135455753","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The traditional drill-in fluid used to construct open holes does not mitigate problems that arise in subsequent completion operations and the risk of formation damage. In this work, a degradable solid-free drill-in fluid was designed with excellent direct flowback and degradation capabilities to reduce potential reservoir damage. A new type of viscosifier (XC-LT), as the key additive in the solid-free drill-in fluid, was prepared by modifying xanthan (XC) with maleic anhydride, and its phase transition temperature (Tm) was 20°C lower than that of XC alone. The XC-LT molecules in an aqueous solution were completely degraded after standing for 3 days, resulting in a clear solution with minimal residue. Additionally, in our proposed degradable solid-free drill-in fluid system, the stability of XC-LT could be improved significantly due to the existence of other additives, including filtrate reducer, monoethanolamine (MEA), potassium chloride (KCl), and sodium sulfite (Na2SO3). After aging for 3 days, the degradable solid-free drill-in fluid system constructed with XC-LT and other additives still had good rheological properties, and the rheological parameters, such as apparent viscosity (AV), plastic viscosity (PV), and yield point (YP), remained relatively stable, meeting the requirements for carrying cuttings in the drilling process. Its low shear rate viscosity (LSRV) was 30 900 mPa·s, and the system had good degradation performance after standing for a long time, which can reduce the flowback breakthrough pressure of oil and gas resources. The permeability recovery values (Kod/Ko) of the contaminated cores with the degradable solid-free drill-in fluid were greater than 94%, and the degraded drill-in fluid could fully flow back through the pore throats, reflecting an excellent reservoir protection performance. Finally, the degradable solid-free drill-in fluid system was applied to wells in the South China Sea. Compared with the adjacent wells using the solid-free drill-in fluid and gel-breaking fluid systems, the well production using our proposed degradable solid-free drill-in fluid system exceeded the anticipated production and was much greater than that of the adjacent wells. Our proposed degradable solid-free drill-in fluid system had good reservoir protection performance, and its application simplified the completion process.
{"title":"Experimental Study of a Degradable Solid-Free Drill-In Fluid System and Its Reservoir Protection Mechanism","authors":"Fuchang You, Jia Zeng, Chunwu Gong, Yanlai Shen","doi":"10.2118/218388-pa","DOIUrl":"https://doi.org/10.2118/218388-pa","url":null,"abstract":"The traditional drill-in fluid used to construct open holes does not mitigate problems that arise in subsequent completion operations and the risk of formation damage. In this work, a degradable solid-free drill-in fluid was designed with excellent direct flowback and degradation capabilities to reduce potential reservoir damage. A new type of viscosifier (XC-LT), as the key additive in the solid-free drill-in fluid, was prepared by modifying xanthan (XC) with maleic anhydride, and its phase transition temperature (Tm) was 20°C lower than that of XC alone. The XC-LT molecules in an aqueous solution were completely degraded after standing for 3 days, resulting in a clear solution with minimal residue. Additionally, in our proposed degradable solid-free drill-in fluid system, the stability of XC-LT could be improved significantly due to the existence of other additives, including filtrate reducer, monoethanolamine (MEA), potassium chloride (KCl), and sodium sulfite (Na2SO3). After aging for 3 days, the degradable solid-free drill-in fluid system constructed with XC-LT and other additives still had good rheological properties, and the rheological parameters, such as apparent viscosity (AV), plastic viscosity (PV), and yield point (YP), remained relatively stable, meeting the requirements for carrying cuttings in the drilling process. Its low shear rate viscosity (LSRV) was 30 900 mPa·s, and the system had good degradation performance after standing for a long time, which can reduce the flowback breakthrough pressure of oil and gas resources. The permeability recovery values (Kod/Ko) of the contaminated cores with the degradable solid-free drill-in fluid were greater than 94%, and the degraded drill-in fluid could fully flow back through the pore throats, reflecting an excellent reservoir protection performance. Finally, the degradable solid-free drill-in fluid system was applied to wells in the South China Sea. Compared with the adjacent wells using the solid-free drill-in fluid and gel-breaking fluid systems, the well production using our proposed degradable solid-free drill-in fluid system exceeded the anticipated production and was much greater than that of the adjacent wells. Our proposed degradable solid-free drill-in fluid system had good reservoir protection performance, and its application simplified the completion process.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"6 1","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139296130","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. N. Borges Filho, A. Soares, Filipe Arantes Furtado, C. Scheid, L. Calçada
Natural or artificial fractures are common in the wellbore during drilling operations. These fractures allow the flow of drilling fluid into the rock formation. The loss of circulation increases the operation’s cost and nonproductive time, which may threaten the well’s structural integrity. To overcome this problem, it is necessary to understand the flow of fluids through fractures and develop methods to mitigate the loss of circulation. This work’s main contributions are expanding the knowledge on the flow of drilling fluids through fractured channels, conducting an experimental study on the flow of suspensions of lost circulation materials (LCM) in fractures, and performing a theoretical analysis to obtain mathematical models describing fractured channels’ sealing. This work proposes a correlation between the pressure drop and the volumetric flow rate of fluid through fractures. To validate the model, a physical simulator collected fluid flow data and pressure drop in fractures with 2-mm, 5-mm, and 10-mm apertures and 1.02-m length. A blend of polymers and calcium borate was used in suspension in water viscosified with xanthan gum (XG). Density and rheological behavior tests were performed to characterize the studied fluids. The LCM had a bimodal particle-size distribution, and the formulated fluids had a Herschel-Bulkley rheological behavior. Pressure drop, flow rate, and rheological data were used to propose a correlation between pressure drop and volumetric flow rate through the fracture. The proposed correlation was used to monitor the sealing of fractures by calculating their hydraulic diameter throughout the sealing process. The LCM suspensions underwent filtration tests to observe the effects of sealing particles on the mudcake and filtrate volume. The proposed correlation fitted the experimental data with less than 10% deviation. The fracture hydraulic diameter was estimated using experimental data of volumetric flow rate and pressure drop, which made it possible to monitor the sealing process of fractures through time. The sealing and filtration tests showed that the borate and polymer blends are effective as filtration control agents and LCM.
{"title":"A New Methodology to Evaluate the Sealing Process Based on Pressure Drop and Fluid Loss in Fractures during the Drilling Operation","authors":"M. N. Borges Filho, A. Soares, Filipe Arantes Furtado, C. Scheid, L. Calçada","doi":"10.2118/218376-pa","DOIUrl":"https://doi.org/10.2118/218376-pa","url":null,"abstract":"Natural or artificial fractures are common in the wellbore during drilling operations. These fractures allow the flow of drilling fluid into the rock formation. The loss of circulation increases the operation’s cost and nonproductive time, which may threaten the well’s structural integrity. To overcome this problem, it is necessary to understand the flow of fluids through fractures and develop methods to mitigate the loss of circulation. This work’s main contributions are expanding the knowledge on the flow of drilling fluids through fractured channels, conducting an experimental study on the flow of suspensions of lost circulation materials (LCM) in fractures, and performing a theoretical analysis to obtain mathematical models describing fractured channels’ sealing. This work proposes a correlation between the pressure drop and the volumetric flow rate of fluid through fractures. To validate the model, a physical simulator collected fluid flow data and pressure drop in fractures with 2-mm, 5-mm, and 10-mm apertures and 1.02-m length. A blend of polymers and calcium borate was used in suspension in water viscosified with xanthan gum (XG). Density and rheological behavior tests were performed to characterize the studied fluids. The LCM had a bimodal particle-size distribution, and the formulated fluids had a Herschel-Bulkley rheological behavior. Pressure drop, flow rate, and rheological data were used to propose a correlation between pressure drop and volumetric flow rate through the fracture. The proposed correlation was used to monitor the sealing of fractures by calculating their hydraulic diameter throughout the sealing process. The LCM suspensions underwent filtration tests to observe the effects of sealing particles on the mudcake and filtrate volume. The proposed correlation fitted the experimental data with less than 10% deviation. The fracture hydraulic diameter was estimated using experimental data of volumetric flow rate and pressure drop, which made it possible to monitor the sealing process of fractures through time. The sealing and filtration tests showed that the borate and polymer blends are effective as filtration control agents and LCM.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"84 1","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139296185","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In this work, a unified, consistent, and efficient framework has been proposed to better predict the density of a gas(es)-heavy oil/bitumen system by using the Peng-Robinson equation of state (PR EOS) and Soave-Redlich-Kwong (SRK) EOS together with α functions and volume-translation (VT) strategies, respectively. With a database comprising 218 experimentally measured densities for gas(es)-heavy oil/bitumen systems, five α functions defined at a reduced temperature (Tr) of 0.70 as well as three new α functions at Tr = 0.60 together with four VT strategies are selected and evaluated. For α Functions 1 to 4 defined at Tr = 0.70, VTs 1 to 4 lead to an overall absolute average relative deviation (AARD) of 7.21%, 9.74%, 7.02%, and 7.16%, respectively, for predicting the mixture densities. For α Function 5 defined at Tr = 0.70, these four VT strategies predict the mixture density with an AARD of 3.13%, 5.01%, 2.92%, and 2.56%, respectively. As for the two new α Functions 7 and 8 defined at Tr = 0.60, these four VT strategies predict the mixture density with an AARD of 1.38%, 2.57%, 1.34%, and 1.67%, respectively, among which VT 3 has a very close prediction compared to an AARD of 1.31% obtained from the ideal mixing rule with effective density (IM-E).
{"title":"Comparative Evaluation of a Functions and Volume-Translation Strategies to Predict Densities for Gas(es)-Heavy Oil/Bitumen Systems","authors":"Esther Anyi Atonge, Daoyong Yang","doi":"10.2118/217980-pa","DOIUrl":"https://doi.org/10.2118/217980-pa","url":null,"abstract":"In this work, a unified, consistent, and efficient framework has been proposed to better predict the density of a gas(es)-heavy oil/bitumen system by using the Peng-Robinson equation of state (PR EOS) and Soave-Redlich-Kwong (SRK) EOS together with α functions and volume-translation (VT) strategies, respectively. With a database comprising 218 experimentally measured densities for gas(es)-heavy oil/bitumen systems, five α functions defined at a reduced temperature (Tr) of 0.70 as well as three new α functions at Tr = 0.60 together with four VT strategies are selected and evaluated. For α Functions 1 to 4 defined at Tr = 0.70, VTs 1 to 4 lead to an overall absolute average relative deviation (AARD) of 7.21%, 9.74%, 7.02%, and 7.16%, respectively, for predicting the mixture densities. For α Function 5 defined at Tr = 0.70, these four VT strategies predict the mixture density with an AARD of 3.13%, 5.01%, 2.92%, and 2.56%, respectively. As for the two new α Functions 7 and 8 defined at Tr = 0.60, these four VT strategies predict the mixture density with an AARD of 1.38%, 2.57%, 1.34%, and 1.67%, respectively, among which VT 3 has a very close prediction compared to an AARD of 1.31% obtained from the ideal mixing rule with effective density (IM-E).","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"50 1","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139302816","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Aiming at the problems of slow drilling speed, low service life, and poor stability of conventional polycrystalline diamond compact (PDC) bits in deep formations that are difficult to drill, a new annular-grooved PDC bit is proposed. The bit adopts discontinuous tooth arrangement to set cutters, and a circumferential annular groove around the center of the bit is set on the bit body to form a fragile convex annular ridge at the bottom of the well, improving the bit’s ability to invade the formation and its rock-breaking efficiency. Combined with the formation characteristics of Shapai 11 well and Shixi 102 well in Xinjiang Oil Field, the PDC bit crown shape, annular-groove design, cutter selection, and other aspects are designed individually, and the dynamic rock-breaking and hydraulic characteristics of the annular-groove PDC bit are simulated and analyzed. Finally, two PDC bits with different diameters are developed—a Φ215.9-mm annular-groove PDC bit and the field application bit. The field application bit results show that compared with the bit in the same layer of adjacent wells, the mechanical penetration rate of the annular-groove PDC bit is increased by 29.8–176.7%, and the footage is increased by 142.5–273.1%. It is concluded that the annular-groove PDC bit can significantly reduce the rock-breaking energy consumption of the bit and improve the mechanical rate of penetration (ROP) of the bit. At the same time, the raised annular ridge can reduce the lateral vibration of the bit and extend the service life of the bit, which will accelerate the exploration and development of deep difficult-to-drill formations. It is of positive significance to reduce drilling costs.
{"title":"Individualized Design and Field Application of Annular-Groove Polycrystalline Diamond Composite Bit","authors":"Kuilin Huang, Cheng Fu, Yong Li, Jian Zhou, Yingxin Yang, Yueqiang Feng","doi":"10.2118/218379-pa","DOIUrl":"https://doi.org/10.2118/218379-pa","url":null,"abstract":"Aiming at the problems of slow drilling speed, low service life, and poor stability of conventional polycrystalline diamond compact (PDC) bits in deep formations that are difficult to drill, a new annular-grooved PDC bit is proposed. The bit adopts discontinuous tooth arrangement to set cutters, and a circumferential annular groove around the center of the bit is set on the bit body to form a fragile convex annular ridge at the bottom of the well, improving the bit’s ability to invade the formation and its rock-breaking efficiency. Combined with the formation characteristics of Shapai 11 well and Shixi 102 well in Xinjiang Oil Field, the PDC bit crown shape, annular-groove design, cutter selection, and other aspects are designed individually, and the dynamic rock-breaking and hydraulic characteristics of the annular-groove PDC bit are simulated and analyzed. Finally, two PDC bits with different diameters are developed—a Φ215.9-mm annular-groove PDC bit and the field application bit. The field application bit results show that compared with the bit in the same layer of adjacent wells, the mechanical penetration rate of the annular-groove PDC bit is increased by 29.8–176.7%, and the footage is increased by 142.5–273.1%. It is concluded that the annular-groove PDC bit can significantly reduce the rock-breaking energy consumption of the bit and improve the mechanical rate of penetration (ROP) of the bit. At the same time, the raised annular ridge can reduce the lateral vibration of the bit and extend the service life of the bit, which will accelerate the exploration and development of deep difficult-to-drill formations. It is of positive significance to reduce drilling costs.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"24 1","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139297541","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In evaluating the porosity system of the Bassein formation, high-resolution resistivity image (FMI) data have been used. Major features observed from the FMI data are the presence of low-angle fractures and solution channels of varying length and thickness. Against the layers with very-low-density neutron porosity, solution channels are seen as conductive features. These mud-filled solution channels can actively participate in production. Being very small-scale features, these types of porosities are not identifiable from conventional log data. To define and quantify porosity types such as vugs, solution channel, and matrix porosity, the resistivity image data are processed and image-based porosity is calculated. A core thin-section study is carried out and is used for calibration of the image-derived porosity system. Using resistivity image data, we have computed porosity types, for example, vugs, connected matrix and resistive, and their contribution to total porosity. Identification of hydrocarbons in reservoir layers with their porosity contribution (porosity partitioning) gives better insight into hydrocarbon production in these low-porosity layers which are producing after acid job.
{"title":"An Approach to Define and Quantify Porosity System in Heterogeneous Carbonate Reservoirs through Textural Analysis using High-Resolution Resistivity Image in the Bassein Formation of Mumbai Offshore Basin, India","authors":"Suraj Kumar, Soumya Chandan Panda","doi":"10.2118/218375-pa","DOIUrl":"https://doi.org/10.2118/218375-pa","url":null,"abstract":"In evaluating the porosity system of the Bassein formation, high-resolution resistivity image (FMI) data have been used. Major features observed from the FMI data are the presence of low-angle fractures and solution channels of varying length and thickness. Against the layers with very-low-density neutron porosity, solution channels are seen as conductive features. These mud-filled solution channels can actively participate in production. Being very small-scale features, these types of porosities are not identifiable from conventional log data. To define and quantify porosity types such as vugs, solution channel, and matrix porosity, the resistivity image data are processed and image-based porosity is calculated. A core thin-section study is carried out and is used for calibration of the image-derived porosity system. Using resistivity image data, we have computed porosity types, for example, vugs, connected matrix and resistive, and their contribution to total porosity. Identification of hydrocarbons in reservoir layers with their porosity contribution (porosity partitioning) gives better insight into hydrocarbon production in these low-porosity layers which are producing after acid job.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"2015 1","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139299117","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Summary Microscopic assessment of oil distribution and imbibition mechanisms within shale formations lays the groundwork for future development strategies. In this regard, the Songliao Basin’s continental shale oil holds immense exploration and development potential. In this study, we focus on shale samples extracted from the first member of the Qingshankou Formation (Q1) within the Songliao Basin. These samples were subjected to a comprehensive analysis, encompassing mercury injection capillary pressure (MICP), porosity, and permeability measurements and detailed monitoring processes. The experimental protocol involved multiple injection cycles, commencing with spontaneous oil imbibition, followed by a series of differential pressurized oil saturation stages (eight pressurization steps ranging from 0.2 MPa to 10 MPa). Subsequently, forced imbibition using slickwater under varying pressures was used, and the process was meticulously monitored via gravimetric and nuclear magnetic resonance (NMR) measurements to deduce relative fractions within distinct pores across the entire experimental process. Notably, the results unveiled that, during oil saturation through spontaneous imbibition, the interbedd-type shale core samples exhibit more efficient oil saturation compared with the organic-rich dark massive type. In the former, clay interlayers predominate in absorbing oil, while the latter showcases preferential saturation of mesopores and macropores. Following the differential pressurized oil saturation phase, clay interlayers continued to play a significant role in both sample types, accounting for 54.2% and 57.0% of the interbed-type and massive shale’s oil intake, respectively. Furthermore, a quantification of the slickwater imbibition recovery originating from pores of varying sizes under distinct pressures revealed that clay interlayers and micropores are the primary contributors to imbibition recovery in both sample types. Collectively, the experimental findings corroborate that shale oil can be displaced from nanopores to larger matrix pores and bedding fractures through imbibition, offering valuable insights for enhancing oil recovery operations in practical field scenarios.
{"title":"Unlocking Continental Shale Oil Potential: Microscopic Insights into Fluid Saturation Mechanisms via Imbibition for Future Development Strategies in the Songliao Basin","authors":"Ying Yang, Jianguang Wei, Erlong Yang, Fahimeh Hadavimoghaddam, Mehdi Ostadhassan, Shuang Liang, Xiaofeng Zhou","doi":"10.2118/218004-pa","DOIUrl":"https://doi.org/10.2118/218004-pa","url":null,"abstract":"Summary Microscopic assessment of oil distribution and imbibition mechanisms within shale formations lays the groundwork for future development strategies. In this regard, the Songliao Basin’s continental shale oil holds immense exploration and development potential. In this study, we focus on shale samples extracted from the first member of the Qingshankou Formation (Q1) within the Songliao Basin. These samples were subjected to a comprehensive analysis, encompassing mercury injection capillary pressure (MICP), porosity, and permeability measurements and detailed monitoring processes. The experimental protocol involved multiple injection cycles, commencing with spontaneous oil imbibition, followed by a series of differential pressurized oil saturation stages (eight pressurization steps ranging from 0.2 MPa to 10 MPa). Subsequently, forced imbibition using slickwater under varying pressures was used, and the process was meticulously monitored via gravimetric and nuclear magnetic resonance (NMR) measurements to deduce relative fractions within distinct pores across the entire experimental process. Notably, the results unveiled that, during oil saturation through spontaneous imbibition, the interbedd-type shale core samples exhibit more efficient oil saturation compared with the organic-rich dark massive type. In the former, clay interlayers predominate in absorbing oil, while the latter showcases preferential saturation of mesopores and macropores. Following the differential pressurized oil saturation phase, clay interlayers continued to play a significant role in both sample types, accounting for 54.2% and 57.0% of the interbed-type and massive shale’s oil intake, respectively. Furthermore, a quantification of the slickwater imbibition recovery originating from pores of varying sizes under distinct pressures revealed that clay interlayers and micropores are the primary contributors to imbibition recovery in both sample types. Collectively, the experimental findings corroborate that shale oil can be displaced from nanopores to larger matrix pores and bedding fractures through imbibition, offering valuable insights for enhancing oil recovery operations in practical field scenarios.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"66 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135566926","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Raj K. Das, Ravi K. Voolapalli, Sreedevi Upadhyayula, Rajeev Kumar
Summary In this paper, we investigate the role of asphaltenes derived from heavy crudes, which dictates the behavior of crude mix properties for hassle-free downstream refinery operation. Combined characterization techniques such as proton nuclear magnetic resonance (1H-NMR), cross-polarization magic-angle-spinning carbon-13 (CP/MAS 13C)-NMR, heteronuclear single-quantum coherence (HSQC), Fourier transform infrared (FTIR), thermogravimetric analysis (TGA), and X-ray diffraction (XRD) are used for the detailted study of Ratwai and Ras Gharib (RG)-derived asphaltenes to validate their structural role in selecting the optimal crude mix. As per our investigation, when the polyaromatic core of asphaltene structures are less substituted, the availability of aromatic hydrogen is more; it exhibits a stable crude mix as compared to heavy crudes that have more aromatic core substitution, despite the crudes possessing similar asphaltene content and physicochemical properties. This finding is further extended to West Canadian (WC) and Belayim (BL) heavy crudes for operational suitability. In this study, the key feature is to develop a CP/MAS 13C-NMR-based robust and quick characterization technique that could potentially become a prescreening method to assess crude oil compatibility and its various blend processability in the refinery system. Other characterization techniques, such as 1H-NMR, HSQC, FTIR, TGA, and XRD, would corroborate and confirm the reliability of the data obtained by CP/MAS 13C-NMR.
{"title":"Novel Structural Aspects of Heavy-Crude-Derived Asphaltene Molecules for Investigating the Crude Mix Processability in Refinery Operation","authors":"Raj K. Das, Ravi K. Voolapalli, Sreedevi Upadhyayula, Rajeev Kumar","doi":"10.2118/218002-pa","DOIUrl":"https://doi.org/10.2118/218002-pa","url":null,"abstract":"Summary In this paper, we investigate the role of asphaltenes derived from heavy crudes, which dictates the behavior of crude mix properties for hassle-free downstream refinery operation. Combined characterization techniques such as proton nuclear magnetic resonance (1H-NMR), cross-polarization magic-angle-spinning carbon-13 (CP/MAS 13C)-NMR, heteronuclear single-quantum coherence (HSQC), Fourier transform infrared (FTIR), thermogravimetric analysis (TGA), and X-ray diffraction (XRD) are used for the detailted study of Ratwai and Ras Gharib (RG)-derived asphaltenes to validate their structural role in selecting the optimal crude mix. As per our investigation, when the polyaromatic core of asphaltene structures are less substituted, the availability of aromatic hydrogen is more; it exhibits a stable crude mix as compared to heavy crudes that have more aromatic core substitution, despite the crudes possessing similar asphaltene content and physicochemical properties. This finding is further extended to West Canadian (WC) and Belayim (BL) heavy crudes for operational suitability. In this study, the key feature is to develop a CP/MAS 13C-NMR-based robust and quick characterization technique that could potentially become a prescreening method to assess crude oil compatibility and its various blend processability in the refinery system. Other characterization techniques, such as 1H-NMR, HSQC, FTIR, TGA, and XRD, would corroborate and confirm the reliability of the data obtained by CP/MAS 13C-NMR.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"56 3-4","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135715086","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"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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