Bisheng Wu, Haoze Zhang, Shengshen Wu, Yuanxun Nie, Xi Zhang, Robert G. Jeffrey
Summary A good understanding of the magnitude and direction of in-situ stresses is very important for oil and gas exploration. The conventional wellbore breakout method directly uses information about rock strength and wellbore shape (i.e., depth and width of breakout) to predict the in-situ stresses, but it is difficult to accurately describe the relationship between the breakout shape and the in-situ stresses. This paper presents a deep learning model, combining the generative adversarial networks (GAN) and backpropagation neural network (BPNN) to predict the maximum horizontal principal stress (MHPS) from breakout data. First, a GAN is used to effectively improve the quantity and quality of training data by generating a certain number of new training data that approximate the original data. Second, the training data enhanced by the GAN are used to train the BPNN, which predicts the MHPS based on wellbore breakout geometries. The two independent modules, the GAN and BPNN, use the training data to train themselves, respectively. This dual deep learning pattern ensures that the potential relationship between the in-situ stresses and wellbore breakout shape can be found. To examine the reliability of this technique, 86 sets of laboratory data from published literature are used to train the model, and 19 sets of laboratory data from other published literature are used to test the prediction performance of the trained model. The results show that the proposed model has good accuracy with an average relative error of 4.76% when predicting the MHPS. In addition, this deep learning model combining the GAN and BPNN requires only a few seconds to run on a laptop computer, thus providing an effective and efficient tool for predicting the MHPS.
{"title":"Prediction of the Maximum Horizontal Principal Stress from Breakout Data Using Generative Adversarial Networks and Backpropagation Neural Network","authors":"Bisheng Wu, Haoze Zhang, Shengshen Wu, Yuanxun Nie, Xi Zhang, Robert G. Jeffrey","doi":"10.2118/217970-pa","DOIUrl":"https://doi.org/10.2118/217970-pa","url":null,"abstract":"Summary A good understanding of the magnitude and direction of in-situ stresses is very important for oil and gas exploration. The conventional wellbore breakout method directly uses information about rock strength and wellbore shape (i.e., depth and width of breakout) to predict the in-situ stresses, but it is difficult to accurately describe the relationship between the breakout shape and the in-situ stresses. This paper presents a deep learning model, combining the generative adversarial networks (GAN) and backpropagation neural network (BPNN) to predict the maximum horizontal principal stress (MHPS) from breakout data. First, a GAN is used to effectively improve the quantity and quality of training data by generating a certain number of new training data that approximate the original data. Second, the training data enhanced by the GAN are used to train the BPNN, which predicts the MHPS based on wellbore breakout geometries. The two independent modules, the GAN and BPNN, use the training data to train themselves, respectively. This dual deep learning pattern ensures that the potential relationship between the in-situ stresses and wellbore breakout shape can be found. To examine the reliability of this technique, 86 sets of laboratory data from published literature are used to train the model, and 19 sets of laboratory data from other published literature are used to test the prediction performance of the trained model. The results show that the proposed model has good accuracy with an average relative error of 4.76% when predicting the MHPS. In addition, this deep learning model combining the GAN and BPNN requires only a few seconds to run on a laptop computer, thus providing an effective and efficient tool for predicting the MHPS.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"95 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135567686","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 Barite sag causes pressure fluctuations in the wellbore, which is undesirable. These problems usually occur with oil-based muds (OBMs; invert emulsion muds) and are associated with fluid properties and operation parameters. Drilling issues related to this undesirable phenomenon include wellbore instability, lost circulation, and stuck pipes. As barite sagging is a complex phenomenon, the mechanisms that cause and aggravate it still need to be fully understood to mitigate these problems. This study examines barite sagging in the wellbore with inner pipe rotation to understand the process and develop prevention strategies. Thus, a flow loop study with OBM is conducted in a concentric annular test section with varying inner pipe rotation and inclination angles. The tests were performed at an elevated temperature (49°C) to simulate borehole conditions. By measuring the pressure profile in a mud sample trapped in the test section, barite sagging was evaluated. Using the data, we calculated the density difference between the top and bottom sections of the column. The novelty of the work lies in continuous monitoring of the density profile of the mud column, which is sheared between two coaxial cylinders to simulate drillstring rotation in the wellbore, and utilizing the data for evaluating barite sag. The results show the evolution of the pressure profile with time, indicating the sagging of barite particles at the bottom of the test section. Due to barite sagging, the density of the top portion of the mud column decreased over time, while the density of the bottom part increased. The lateral sedimentation of barite particles toward the annulus outer wall enhances barite sag in inclined configurations. The sedimentation creates two suspension layers with different densities, leading to secondary flow, which enhances sagging. Hence, the primary factor driving barite sagging is inclination. An increase in inclination angle from 0° to 50° resulted in a significant (more than twofold) increase in mud density difference. Also, the rotation of the pipe delayed sagging during the early phases of the testing process (less than 20 minutes). However, it did not have much effect as the sagging progressed, resulting in approximately the same density difference in both cases (i.e., with and without rotation).
{"title":"Experimental Study on Dynamic Barite Sag and Effects of Inclination and Pipe Rotation","authors":"Muili F. Fakoya, Ramadan Ahmed","doi":"10.2118/217987-pa","DOIUrl":"https://doi.org/10.2118/217987-pa","url":null,"abstract":"Summary Barite sag causes pressure fluctuations in the wellbore, which is undesirable. These problems usually occur with oil-based muds (OBMs; invert emulsion muds) and are associated with fluid properties and operation parameters. Drilling issues related to this undesirable phenomenon include wellbore instability, lost circulation, and stuck pipes. As barite sagging is a complex phenomenon, the mechanisms that cause and aggravate it still need to be fully understood to mitigate these problems. This study examines barite sagging in the wellbore with inner pipe rotation to understand the process and develop prevention strategies. Thus, a flow loop study with OBM is conducted in a concentric annular test section with varying inner pipe rotation and inclination angles. The tests were performed at an elevated temperature (49°C) to simulate borehole conditions. By measuring the pressure profile in a mud sample trapped in the test section, barite sagging was evaluated. Using the data, we calculated the density difference between the top and bottom sections of the column. The novelty of the work lies in continuous monitoring of the density profile of the mud column, which is sheared between two coaxial cylinders to simulate drillstring rotation in the wellbore, and utilizing the data for evaluating barite sag. The results show the evolution of the pressure profile with time, indicating the sagging of barite particles at the bottom of the test section. Due to barite sagging, the density of the top portion of the mud column decreased over time, while the density of the bottom part increased. The lateral sedimentation of barite particles toward the annulus outer wall enhances barite sag in inclined configurations. The sedimentation creates two suspension layers with different densities, leading to secondary flow, which enhances sagging. Hence, the primary factor driving barite sagging is inclination. An increase in inclination angle from 0° to 50° resulted in a significant (more than twofold) increase in mud density difference. Also, the rotation of the pipe delayed sagging during the early phases of the testing process (less than 20 minutes). However, it did not have much effect as the sagging progressed, resulting in approximately the same density difference in both cases (i.e., with and without rotation).","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"40 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135762252","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}
Rahimah Abd Karim, Roberto Aguilera, Gustavo Flores Montilla, Hector Biglia
Summary Natural fractures in Vaca Muerta are very complex, such that their fracture width distributions cannot be analyzed simply by considering normal, log-normal, or log-log distributions. Natural fractures are commonly classified as macrofractures or microfractures; however, no consistent fracture width is attached to those fractures. In this study, two new approaches are proposed; an improved fracture width distribution and a classification for natural fractures that encompasses all physical widths found in petroleum reservoirs. The method developed in this study first evaluates the distribution of natural fracture widths from outcrops, cores, and microresistivity images of Vaca Muerta shale. An improved fracture width distribution is established through a variable shape distribution (VSD). The model provides a good fit, even if the shape of the distribution deviates from generally accepted distributions. This improves the accuracy of fracture width and intensity prediction, which is useful in generating synthetic production logging tools (PLTs) to estimate productivity from fractured intervals. Subsequently, a consistent classification for natural fractures is introduced to cover all fracture widths found in petroleum reservoirs. Results indicate that fracture widths in Vaca Muerta shale range between 0.0003 mm and 7 mm for outcrops, 0.0003 mm and 2 mm for cores, and 0.01 mm and 2 mm for microresistivity images. The VSD model provides a good fit of fracture widths from the three sources, without truncating any of the data. Truncation of data is usually required when using generally accepted distributions. With this improved distribution, size pattern extrapolation can be performed with greater accuracy. The physical widths can also be translated into hydraulic apertures to generate theoretical PLT. This is useful for estimating relative petroleum production potential from each fractured interval and for identifying future refracturing zones. Additionally, the study gives origin to a consistent classification of fracture widths that has application in Vaca Muerta and other oil and gas reservoirs. Five subclasses are introduced, which are megafractures (> 10 mm), macrofractures (1–10 mm), mesofractures (0.1–1 mm), microfractures (0.01–0.1 mm), and nanofractures (<0.01 mm). A careful review of the literature indicates that there is ambivalence as it is hard to find a clear and precise terminology that encompasses the entire range of fracture widths. The proposed classification eliminates that difficulty. In this paper, for the first time, a consistent fracture width classification is developed that encompasses the whole spectrum of widths found in petroleum reservoirs. It has wide application in Vaca Muerta, where widths, derived from outcrops, cores, and microresistivity image data are matched with a VSD model. Furthermore, the proposed classification can be used in other oil and gas reservoirs, thus eliminating the fracture widt
{"title":"Vaca Muerta: Improved Fracture Width Distribution and Classification of Natural Fracture Widths Based on Outcrops, Cores, and Microresistivity Images Data","authors":"Rahimah Abd Karim, Roberto Aguilera, Gustavo Flores Montilla, Hector Biglia","doi":"10.2118/212430-pa","DOIUrl":"https://doi.org/10.2118/212430-pa","url":null,"abstract":"Summary Natural fractures in Vaca Muerta are very complex, such that their fracture width distributions cannot be analyzed simply by considering normal, log-normal, or log-log distributions. Natural fractures are commonly classified as macrofractures or microfractures; however, no consistent fracture width is attached to those fractures. In this study, two new approaches are proposed; an improved fracture width distribution and a classification for natural fractures that encompasses all physical widths found in petroleum reservoirs. The method developed in this study first evaluates the distribution of natural fracture widths from outcrops, cores, and microresistivity images of Vaca Muerta shale. An improved fracture width distribution is established through a variable shape distribution (VSD). The model provides a good fit, even if the shape of the distribution deviates from generally accepted distributions. This improves the accuracy of fracture width and intensity prediction, which is useful in generating synthetic production logging tools (PLTs) to estimate productivity from fractured intervals. Subsequently, a consistent classification for natural fractures is introduced to cover all fracture widths found in petroleum reservoirs. Results indicate that fracture widths in Vaca Muerta shale range between 0.0003 mm and 7 mm for outcrops, 0.0003 mm and 2 mm for cores, and 0.01 mm and 2 mm for microresistivity images. The VSD model provides a good fit of fracture widths from the three sources, without truncating any of the data. Truncation of data is usually required when using generally accepted distributions. With this improved distribution, size pattern extrapolation can be performed with greater accuracy. The physical widths can also be translated into hydraulic apertures to generate theoretical PLT. This is useful for estimating relative petroleum production potential from each fractured interval and for identifying future refracturing zones. Additionally, the study gives origin to a consistent classification of fracture widths that has application in Vaca Muerta and other oil and gas reservoirs. Five subclasses are introduced, which are megafractures (&gt; 10 mm), macrofractures (1–10 mm), mesofractures (0.1–1 mm), microfractures (0.01–0.1 mm), and nanofractures (&lt;0.01 mm). A careful review of the literature indicates that there is ambivalence as it is hard to find a clear and precise terminology that encompasses the entire range of fracture widths. The proposed classification eliminates that difficulty. In this paper, for the first time, a consistent fracture width classification is developed that encompasses the whole spectrum of widths found in petroleum reservoirs. It has wide application in Vaca Muerta, where widths, derived from outcrops, cores, and microresistivity image data are matched with a VSD model. Furthermore, the proposed classification can be used in other oil and gas reservoirs, thus eliminating the fracture widt","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135810760","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 drilling efficiency of a polycrystalline diamond compact (PDC) bit plays a vital role in oil and gas exploration, which is greatly affected by the rock-cutting performance of a single PDC cutter. Although many research efforts have been put in, the rock-cutting mechanism of a single PDC cutter is still indistinct. In this work, the rock-cutting process of a single sharp cylinder-shaped PDC cutter was captured using a high-speed camera. The brittle failure mode mechanism in the rock cutting of the PDC cutter was thus revealed by this real-time observation combined with the findings in previous publications. The brittle rock-cutting failure zones in front of the cutter were separated into three different zones: crushing zone, plastic flow zone, and rock chipping zone. The crushing zone grew while the cutter cut forward and generated a plastic flow zone. When the crushing zone was large enough, a tensile crack would tear apart the rock, forming the rock chip. Based on this rock-cutting mechanism, a new mathematical model of brittle failure in rock cutting of PDC cutter was developed, considering the rock properties and cutting parameters. The boundary geometry of the crushing zone was calculated using elastoplastic theory and the Mohr-Coulomb criterion. All forces on the boundaries of these three failure zones were calculated and combined into the tangential and normal forces in the 3D mathematical model. Furthermore, a new parameter, named as crescent area, was proposed in the mathematical model. When compared to previous publications, the newly developed mathematical model had no variables that needed to be calibrated with experimental data fitting. Moreover, a series of single PDC cutter cutting tests were carried out at various depths of cut (DOCs) and backrake angles to validate the mathematical model. The results showed that the model-predicted forces basically matched the experimental data. The modeling and experimental results shared the same trend for both tangential and normal cutting forces. The experimental phenomena could be well explained by the developed mathematical model. For example, the cutting forces increase with increasing DOC and backrake angle, which is caused by the changing of the crescent area of the rock-cutter interaction. All resultant forces have almost the same inclination angle to the horizontal plane because of the almost constant boundary shape of the crushing zone. The differences between modeling and experimental results could be attributed to several reasons, one of which was the oversimplified plastic flow zone. This work presents a mathematical model that can guide the PDC bit design at different formation properties.
{"title":"Mechanism Analysis and Mathematical Modeling of Brittle Failure in Rock Cutting with a Single Sharp Cylinder-Shaped PDC Cutter","authors":"Jiusen Wei, Wei Liu, Deli Gao","doi":"10.2118/217988-pa","DOIUrl":"https://doi.org/10.2118/217988-pa","url":null,"abstract":"Summary The drilling efficiency of a polycrystalline diamond compact (PDC) bit plays a vital role in oil and gas exploration, which is greatly affected by the rock-cutting performance of a single PDC cutter. Although many research efforts have been put in, the rock-cutting mechanism of a single PDC cutter is still indistinct. In this work, the rock-cutting process of a single sharp cylinder-shaped PDC cutter was captured using a high-speed camera. The brittle failure mode mechanism in the rock cutting of the PDC cutter was thus revealed by this real-time observation combined with the findings in previous publications. The brittle rock-cutting failure zones in front of the cutter were separated into three different zones: crushing zone, plastic flow zone, and rock chipping zone. The crushing zone grew while the cutter cut forward and generated a plastic flow zone. When the crushing zone was large enough, a tensile crack would tear apart the rock, forming the rock chip. Based on this rock-cutting mechanism, a new mathematical model of brittle failure in rock cutting of PDC cutter was developed, considering the rock properties and cutting parameters. The boundary geometry of the crushing zone was calculated using elastoplastic theory and the Mohr-Coulomb criterion. All forces on the boundaries of these three failure zones were calculated and combined into the tangential and normal forces in the 3D mathematical model. Furthermore, a new parameter, named as crescent area, was proposed in the mathematical model. When compared to previous publications, the newly developed mathematical model had no variables that needed to be calibrated with experimental data fitting. Moreover, a series of single PDC cutter cutting tests were carried out at various depths of cut (DOCs) and backrake angles to validate the mathematical model. The results showed that the model-predicted forces basically matched the experimental data. The modeling and experimental results shared the same trend for both tangential and normal cutting forces. The experimental phenomena could be well explained by the developed mathematical model. For example, the cutting forces increase with increasing DOC and backrake angle, which is caused by the changing of the crescent area of the rock-cutter interaction. All resultant forces have almost the same inclination angle to the horizontal plane because of the almost constant boundary shape of the crushing zone. The differences between modeling and experimental results could be attributed to several reasons, one of which was the oversimplified plastic flow zone. This work presents a mathematical model that can guide the PDC bit design at different formation properties.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"31 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135811301","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}
Yingwen Li, Yongfei Yang, Mingzhe Dong, Gloire Imani, Jun Yao, Kai Zhang, Hai Sun, Junjie Zhong, Lei Zhang
Summary Permeability variation in the vertical direction, a typical sandstone reservoir heterogeneity, can trap a large amount of oil in the low-permeability layer. We performed water-alternating-gas (WAG) injection and CO2 foam flooding on a specially constructed millimeter-sized layered sandstone and investigated fluid distribution using high-resolution X-ray microtomography. Based on the segmented images, CO2 capillary-trapping capacity, oil recovery, Euler number, shaper factor, capillary pressure, and fluid flow conductivity were calculated. Our results show that increasing the number of WAG cycles favored CO2 capillary trapping, and oil recovery was enhanced by the WAG strategy. However, there was still a significant amount of oil trapped in the low-permeability layer. After the WAG injection, the connectivity of the residual oil clusters decreased, the capillary pressure of the oil clusters increased, and oil flow conductivity decreased. This was not conducive to further oil recovery. The subsequent injection of CO2 foam effectively recovered the oil in the low-permeability layer. During the no-injection period, we observed a crossflow phenomenon caused by gravity segregation (the high-permeability layer was located below the low-permeability layer), i.e., oil in the low-permeability layer decreased while oil in the high-permeability layer increased, which is beneficial for subsequent oil production. Furthermore, CO2 moved upward driven by gravity, and although capillary barriers could prevent CO2 from escaping, subsequent water injection was essential to improve the stability of CO2 capillary trapping. This work accurately quantifies the distribution of oil and gas in high- and low-permeability layers, thus providing fundamental data for oil recovery and CO2 trapping in reservoirs with vertical heterogeneity. Although the sample used in the experiment was not natural reservoir rock, our results imply that when the permeability ratio between the two layers is greater than 2, sufficient attention must be paid to the fluid distribution differences caused by this layered heterogeneity. Different displacement strategies, such as WAG and CO2 foam flooding, or gravity differences between oil and gas can be used to enhance oil recovery.
{"title":"Pore-Scale Characterization of CO2 Trapping and Oil Displacement in Three-Phase Flow in a Heterogeneous Layered Sandstone","authors":"Yingwen Li, Yongfei Yang, Mingzhe Dong, Gloire Imani, Jun Yao, Kai Zhang, Hai Sun, Junjie Zhong, Lei Zhang","doi":"10.2118/217996-pa","DOIUrl":"https://doi.org/10.2118/217996-pa","url":null,"abstract":"Summary Permeability variation in the vertical direction, a typical sandstone reservoir heterogeneity, can trap a large amount of oil in the low-permeability layer. We performed water-alternating-gas (WAG) injection and CO2 foam flooding on a specially constructed millimeter-sized layered sandstone and investigated fluid distribution using high-resolution X-ray microtomography. Based on the segmented images, CO2 capillary-trapping capacity, oil recovery, Euler number, shaper factor, capillary pressure, and fluid flow conductivity were calculated. Our results show that increasing the number of WAG cycles favored CO2 capillary trapping, and oil recovery was enhanced by the WAG strategy. However, there was still a significant amount of oil trapped in the low-permeability layer. After the WAG injection, the connectivity of the residual oil clusters decreased, the capillary pressure of the oil clusters increased, and oil flow conductivity decreased. This was not conducive to further oil recovery. The subsequent injection of CO2 foam effectively recovered the oil in the low-permeability layer. During the no-injection period, we observed a crossflow phenomenon caused by gravity segregation (the high-permeability layer was located below the low-permeability layer), i.e., oil in the low-permeability layer decreased while oil in the high-permeability layer increased, which is beneficial for subsequent oil production. Furthermore, CO2 moved upward driven by gravity, and although capillary barriers could prevent CO2 from escaping, subsequent water injection was essential to improve the stability of CO2 capillary trapping. This work accurately quantifies the distribution of oil and gas in high- and low-permeability layers, thus providing fundamental data for oil recovery and CO2 trapping in reservoirs with vertical heterogeneity. Although the sample used in the experiment was not natural reservoir rock, our results imply that when the permeability ratio between the two layers is greater than 2, sufficient attention must be paid to the fluid distribution differences caused by this layered heterogeneity. Different displacement strategies, such as WAG and CO2 foam flooding, or gravity differences between oil and gas can be used to enhance oil recovery.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"58 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135811826","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}
Arash Behrang, Hicham Abbas, Chris Istchenko, Angela Solano
Summary The development and operation of geothermal plants play a crucial role in the transition to sustainable and low-carbon energy systems. In this paper, we have presented a seamless and flexible pore-to-process digital solution for the design and assessment of geothermal systems, encompassing the geothermal reservoir, gathering network, and geothermal power plant. Our primary focus in this study centers on the geothermal power plant with a detailed analysis of the functionality and performance of two commonly used configurations—a single-flash power plant and a double-flash geothermal power plant. Our work highlights that overall exergy efficiency of the studied geothermal power plants declines over time, primarily due to a decrease in the quality of the geothermal reservoir. Additionally, our analysis demonstrated that variations in the inlet separator pressure have a notable impact on the overall behavior of the power plant. Parametric studies also reveal that increasing the inlet separator pressure leads to decreased overall exergy efficiency and turbine power, resulting from less efficient conversion of available exergy into useful work. Our studies showed that a substantial portion of the available exergy in the geothermal fluid is being dissipated in the condenser. Consequently, optimizing the design and operation of the condenser emerges as a crucial factor in enhancing the overall efficiency of geothermal power plants.
{"title":"A Pore-to-Process Digital Design Methodology to Evaluate Efficiency of Geothermal Power Plants","authors":"Arash Behrang, Hicham Abbas, Chris Istchenko, Angela Solano","doi":"10.2118/217976-pa","DOIUrl":"https://doi.org/10.2118/217976-pa","url":null,"abstract":"Summary The development and operation of geothermal plants play a crucial role in the transition to sustainable and low-carbon energy systems. In this paper, we have presented a seamless and flexible pore-to-process digital solution for the design and assessment of geothermal systems, encompassing the geothermal reservoir, gathering network, and geothermal power plant. Our primary focus in this study centers on the geothermal power plant with a detailed analysis of the functionality and performance of two commonly used configurations—a single-flash power plant and a double-flash geothermal power plant. Our work highlights that overall exergy efficiency of the studied geothermal power plants declines over time, primarily due to a decrease in the quality of the geothermal reservoir. Additionally, our analysis demonstrated that variations in the inlet separator pressure have a notable impact on the overall behavior of the power plant. Parametric studies also reveal that increasing the inlet separator pressure leads to decreased overall exergy efficiency and turbine power, resulting from less efficient conversion of available exergy into useful work. Our studies showed that a substantial portion of the available exergy in the geothermal fluid is being dissipated in the condenser. Consequently, optimizing the design and operation of the condenser emerges as a crucial factor in enhancing the overall efficiency of geothermal power plants.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"54 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134979056","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}
Abdulrauf R. Adebayo, Mohamed Gamal Rezk, Suaibu O. Badmus
Summary Years of laboratory studies and field tests show that there is still uncertainty about the ability of foam to propagate deep into a reservoir. Many factors have been identified as potential causes of nonpropagation, the most concerning being the lack of sufficient pressure gradient required to propagate foam at locations far from the point of injection. Most researchers that investigated foam propagation did so by coinjecting surfactant and gas. Coinjection offers limited information about transient foam processes due to limitations in the experimental methods needed to measure foam dynamics during transient flow. Foam injection by surfactant-alternating-gas (SAG) has proven to be more effective and common in field application. Repeated drainage and imbibition cycle offer a more favorable condition for the quick generation of foam. Foam can also be propagated at a lower pressure gradient in SAG mode. The objective of this study is to experimentally investigate how transient foam dynamics (trapping, mobilization, and bubble texture) change with multiple cycles of SAG and also with distance from the point of injection. A pair of X-ray source and receiver, differential pressure transducers, and electrical resistance sensors were placed along a 27-cm long, homogeneous, and high-permeability (KL = 70 md) Berea sandstone core. Foam was then generated in situ by SAG injection and allowed to propagate through the core sample under a capillary displacement by brine (brine injection rate = 0.5 cm3/min, Nca = 3×10-7). By use of a novel analytical method on coreflood data obtained from axial pressure and saturation sensors, we obtained trapped foam saturation, in-situ foam flow rates, apparent viscosities, and inferred qualitative foam texture at different core sections. We then observed the following: (i) Maximum trapped foam is uniform across the core sections, with saturation ranging from 47% to 52%. At the vicinity of foam injection, foam apparent viscosity is dominantly caused by gas trapping. At locations farther away, foam apparent viscosity is dominated by both gas trapping and refinement of foam texture. (ii) Cyclic injection of foam further enhances the refinement of foam texture. (iii) Textural refinement increases foam apparent viscosity as it propagates away from the point of injection. (iv) As the foam strength increases, the average gas flow rate in the core sample decreases from 0.5 cm3/min to 0.06 cm3/min. (v) There is no stagnation of foam as remobilization of trapped gas occurs during each cycle at an average flow rate of 0.002 cm3/min.
{"title":"The Effect of Multiple Cycles of Surfactant-Alternating-Gas Process on Foam Transient Flow and Propagation in a Homogeneous Sandstone","authors":"Abdulrauf R. Adebayo, Mohamed Gamal Rezk, Suaibu O. Badmus","doi":"10.2118/217999-pa","DOIUrl":"https://doi.org/10.2118/217999-pa","url":null,"abstract":"Summary Years of laboratory studies and field tests show that there is still uncertainty about the ability of foam to propagate deep into a reservoir. Many factors have been identified as potential causes of nonpropagation, the most concerning being the lack of sufficient pressure gradient required to propagate foam at locations far from the point of injection. Most researchers that investigated foam propagation did so by coinjecting surfactant and gas. Coinjection offers limited information about transient foam processes due to limitations in the experimental methods needed to measure foam dynamics during transient flow. Foam injection by surfactant-alternating-gas (SAG) has proven to be more effective and common in field application. Repeated drainage and imbibition cycle offer a more favorable condition for the quick generation of foam. Foam can also be propagated at a lower pressure gradient in SAG mode. The objective of this study is to experimentally investigate how transient foam dynamics (trapping, mobilization, and bubble texture) change with multiple cycles of SAG and also with distance from the point of injection. A pair of X-ray source and receiver, differential pressure transducers, and electrical resistance sensors were placed along a 27-cm long, homogeneous, and high-permeability (KL = 70 md) Berea sandstone core. Foam was then generated in situ by SAG injection and allowed to propagate through the core sample under a capillary displacement by brine (brine injection rate = 0.5 cm3/min, Nca = 3×10-7). By use of a novel analytical method on coreflood data obtained from axial pressure and saturation sensors, we obtained trapped foam saturation, in-situ foam flow rates, apparent viscosities, and inferred qualitative foam texture at different core sections. We then observed the following: (i) Maximum trapped foam is uniform across the core sections, with saturation ranging from 47% to 52%. At the vicinity of foam injection, foam apparent viscosity is dominantly caused by gas trapping. At locations farther away, foam apparent viscosity is dominated by both gas trapping and refinement of foam texture. (ii) Cyclic injection of foam further enhances the refinement of foam texture. (iii) Textural refinement increases foam apparent viscosity as it propagates away from the point of injection. (iv) As the foam strength increases, the average gas flow rate in the core sample decreases from 0.5 cm3/min to 0.06 cm3/min. (v) There is no stagnation of foam as remobilization of trapped gas occurs during each cycle at an average flow rate of 0.002 cm3/min.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"43 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136054391","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}
A. Gisolf, F. X. Dubost, H. Dumont, V. Achourov, N. Daniele, A. Anselmino, A. Crottini, N. A. Aarseth, P. H. Fjeld, S. Molla
Summary Representative fluid properties are required for a wide range of field life aspects such as initial sizing of reservoir hydrocarbon reserves and production planning. Fluid properties are routinely obtained from laboratory sample analysis, but some fluid properties can also be measured in situ with formation testers. A new downhole bubblepoint technique has been developed to supplement traditional downhole fluid analysis (DFA) measurements. Bubble-initiation pressure is measured on reservoir fluids enabling early estimations and sample representativity. The method outlined consists of two parts—bubble generation and bubblepoint-pressure detection. After the isolation of a volume of contamination-free fluid in the fluid analyzer module of a formation tester, a downhole pump is used to reduce flowline pressure at a low and precise flow rate. Bubble initiation is detected using optical spectroscopy measurements made at a 128-ms data sampling rate. Even very small bubbles scatter visible and near-infrared light directed through the flowline, ensuring that the initiation of bubbles is detected. Flowline decompression experiments are performed in minutes, at any time, and on a range of downhole fluids. Downhole bubblepoint pressure measurements were made on four different fluids. The gas/oil ratio (GOR) of the tested fluids ranged from 90 m3/m3 to 250 m3/m3. In each case, the downhole bubblepoint obtained from the flowline decompression experiment matched the saturation determined by constant composition expansion (CCE) in the laboratory to within 350 kPa. We observed that bubble initiation is first detected using near-infrared spectroscopy. As the pressure drops, gas bubbles coming out of the solution increase in size, and the bubble presence becomes identifiable on other downhole sensors such as the live fluid density and fluorescence, where it manifests as signal scattering. For each of the investigated fluids, pressure and density measurements acquired while the flowline pressure is above saturation pressure are also used to compute compressibility as a function of pressure. This downhole bubblepoint pressure measurement allows optimization of real-time sampling operations, enables fluid grading and compartmentalization studies, and can be used for an early elaboration of a fluid equation-of-state (EOS) model. The technique is suitable for black oils and volatile oils. For heavy oil with very low gas content, the accuracy of this technique may be reduced because of the energy required to overcome the nucleation barrier. Prior documented techniques often inferred downhole bubblepoints from the analysis of the rate of change of flowline pressure. Direct detection of the onset of gas bubble appearance without requiring additional dedicated downhole equipment and validated against laboratory measurements is shown for the first time. The measurement accuracy is enabled by the combination of 128-ms optical spectroscopy with low and accurate decomp
{"title":"In-Situ Bubblepoint Measurement by Optical Spectroscopy","authors":"A. Gisolf, F. X. Dubost, H. Dumont, V. Achourov, N. Daniele, A. Anselmino, A. Crottini, N. A. Aarseth, P. H. Fjeld, S. Molla","doi":"10.2118/210280-pa","DOIUrl":"https://doi.org/10.2118/210280-pa","url":null,"abstract":"Summary Representative fluid properties are required for a wide range of field life aspects such as initial sizing of reservoir hydrocarbon reserves and production planning. Fluid properties are routinely obtained from laboratory sample analysis, but some fluid properties can also be measured in situ with formation testers. A new downhole bubblepoint technique has been developed to supplement traditional downhole fluid analysis (DFA) measurements. Bubble-initiation pressure is measured on reservoir fluids enabling early estimations and sample representativity. The method outlined consists of two parts—bubble generation and bubblepoint-pressure detection. After the isolation of a volume of contamination-free fluid in the fluid analyzer module of a formation tester, a downhole pump is used to reduce flowline pressure at a low and precise flow rate. Bubble initiation is detected using optical spectroscopy measurements made at a 128-ms data sampling rate. Even very small bubbles scatter visible and near-infrared light directed through the flowline, ensuring that the initiation of bubbles is detected. Flowline decompression experiments are performed in minutes, at any time, and on a range of downhole fluids. Downhole bubblepoint pressure measurements were made on four different fluids. The gas/oil ratio (GOR) of the tested fluids ranged from 90 m3/m3 to 250 m3/m3. In each case, the downhole bubblepoint obtained from the flowline decompression experiment matched the saturation determined by constant composition expansion (CCE) in the laboratory to within 350 kPa. We observed that bubble initiation is first detected using near-infrared spectroscopy. As the pressure drops, gas bubbles coming out of the solution increase in size, and the bubble presence becomes identifiable on other downhole sensors such as the live fluid density and fluorescence, where it manifests as signal scattering. For each of the investigated fluids, pressure and density measurements acquired while the flowline pressure is above saturation pressure are also used to compute compressibility as a function of pressure. This downhole bubblepoint pressure measurement allows optimization of real-time sampling operations, enables fluid grading and compartmentalization studies, and can be used for an early elaboration of a fluid equation-of-state (EOS) model. The technique is suitable for black oils and volatile oils. For heavy oil with very low gas content, the accuracy of this technique may be reduced because of the energy required to overcome the nucleation barrier. Prior documented techniques often inferred downhole bubblepoints from the analysis of the rate of change of flowline pressure. Direct detection of the onset of gas bubble appearance without requiring additional dedicated downhole equipment and validated against laboratory measurements is shown for the first time. The measurement accuracy is enabled by the combination of 128-ms optical spectroscopy with low and accurate decomp","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"31 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136093940","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}
Guanglong Sheng, Hui Zhao, Luoyi Huang, Hao Huang, Jinghua Liu
Summary Fluid-flow fractures, through which fluids can move under pressure, make a more significant contribution to increasing production than do microseismic and propagation fractures. An accurate description of the distribution of fluid-flow fractures is the basis for evaluating hydraulic fracturing and oil/gas recovery. In this study, a real-time inversion approach for fluid-flow fractures was proposed, and the complex fluid-flow fracture morphology was obtained in real time by updating the data of the fracturing construction curve. First, a dynamic permeability model was proposed to describe the filtration rate of the fracturing fluid during hydraulic fracturing. Combined with the point source function, the flowing bottomhole pressure (pwf) can be quickly calculated based on the fracture morphology and displacement of the fracturing fluid. The variance of pwf and bottomhole pressure (pwb) obtained by pump pressure were used as an objective function, and the length of fluid-flow fractures and fracture morphology were used as fitting parameters. The length of the fluid-flow fractures was updated with the simultaneous perturbation stochastic approximation (SPSA) to achieve a rough fitting of the bottomhole pressure. On this basis, a probability function was used to constrain the randomness of the fractures, and the fracture morphology with a fixed fracture length was continuously simulated and finely matched. Finally, a complex fluid-flow fracture morphology was obtained. The method was used to analyze the fluid-flow fracture morphology of multifractured horizontal wells in shale reservoirs, and the fitting rate of the fracturing construction curve was more than 95%. The results show that the total length of the fluid-flow fractures in one stage in naturally fractured reservoirs was approximately 629 m, and those in homogeneous reservoirs and high-stress difference reservoirs were 564 m and 532 m, respectively. The length of fluid-flow fractures with “grooves” in the fracturing construction curve was longer than the length of fluid-flow fractures with “bulges.” The effectively stimulated reservoir area with fluid-flow fractures was only approximately 28–51% of the stimulated reservoir area with microseismic fractures.
{"title":"A Real-Time Inversion Approach for Fluid-Flow Fractures in Unconventional Stimulated Reservoirs","authors":"Guanglong Sheng, Hui Zhao, Luoyi Huang, Hao Huang, Jinghua Liu","doi":"10.2118/218001-pa","DOIUrl":"https://doi.org/10.2118/218001-pa","url":null,"abstract":"Summary Fluid-flow fractures, through which fluids can move under pressure, make a more significant contribution to increasing production than do microseismic and propagation fractures. An accurate description of the distribution of fluid-flow fractures is the basis for evaluating hydraulic fracturing and oil/gas recovery. In this study, a real-time inversion approach for fluid-flow fractures was proposed, and the complex fluid-flow fracture morphology was obtained in real time by updating the data of the fracturing construction curve. First, a dynamic permeability model was proposed to describe the filtration rate of the fracturing fluid during hydraulic fracturing. Combined with the point source function, the flowing bottomhole pressure (pwf) can be quickly calculated based on the fracture morphology and displacement of the fracturing fluid. The variance of pwf and bottomhole pressure (pwb) obtained by pump pressure were used as an objective function, and the length of fluid-flow fractures and fracture morphology were used as fitting parameters. The length of the fluid-flow fractures was updated with the simultaneous perturbation stochastic approximation (SPSA) to achieve a rough fitting of the bottomhole pressure. On this basis, a probability function was used to constrain the randomness of the fractures, and the fracture morphology with a fixed fracture length was continuously simulated and finely matched. Finally, a complex fluid-flow fracture morphology was obtained. The method was used to analyze the fluid-flow fracture morphology of multifractured horizontal wells in shale reservoirs, and the fitting rate of the fracturing construction curve was more than 95%. The results show that the total length of the fluid-flow fractures in one stage in naturally fractured reservoirs was approximately 629 m, and those in homogeneous reservoirs and high-stress difference reservoirs were 564 m and 532 m, respectively. The length of fluid-flow fractures with “grooves” in the fracturing construction curve was longer than the length of fluid-flow fractures with “bulges.” The effectively stimulated reservoir area with fluid-flow fractures was only approximately 28–51% of the stimulated reservoir area with microseismic fractures.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"53 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136094991","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 rotary steerable drilling system is an advanced drilling technology, with stabilized platform toolface attitude control being a critical component. Due to a multitude of downhole interference factors, coupled with nonlinearities and uncertainties, challenges arise in model establishment and attitude control. Furthermore, considering that stabilized platform toolface attitude determines the drilling direction of the entire drill bit, the effectiveness of toolface attitude control will directly impact the precision and success of drilling tool guidance. In this paper, a mathematical model and a friction model of the stabilized platform are established, and an improved deep deterministic policy gradient (I_DDPG) attitude control method is proposed to address the friction nonlinearity problem existing in the rotary steering drilling stabilized platform. A prioritized experience replay based on temporal difference (TD) error and policy gradient is introduced to improve sample usage, and high similarity samples are pruned to prevent overfitting. Furthermore, SumTree structure is adopted to sort samples for reducing computational effort, and a double critic network is used to alleviate the overestimated value. Numerical simulation results illustrate that the stabilized platform attitude control system based on I_DDPG can achieve high control accuracy with both strong anti-interference capability and good robustness.
{"title":"Attitude Control of Rotary Steering Drilling Stabilized Platform Based on Improved Deep Deterministic Policy Gradient","authors":"Aiqing Huo, Kun Zhang, Shuhan Zhang","doi":"10.2118/217992-pa","DOIUrl":"https://doi.org/10.2118/217992-pa","url":null,"abstract":"Summary The rotary steerable drilling system is an advanced drilling technology, with stabilized platform toolface attitude control being a critical component. Due to a multitude of downhole interference factors, coupled with nonlinearities and uncertainties, challenges arise in model establishment and attitude control. Furthermore, considering that stabilized platform toolface attitude determines the drilling direction of the entire drill bit, the effectiveness of toolface attitude control will directly impact the precision and success of drilling tool guidance. In this paper, a mathematical model and a friction model of the stabilized platform are established, and an improved deep deterministic policy gradient (I_DDPG) attitude control method is proposed to address the friction nonlinearity problem existing in the rotary steering drilling stabilized platform. A prioritized experience replay based on temporal difference (TD) error and policy gradient is introduced to improve sample usage, and high similarity samples are pruned to prevent overfitting. Furthermore, SumTree structure is adopted to sort samples for reducing computational effort, and a double critic network is used to alleviate the overestimated value. Numerical simulation results illustrate that the stabilized platform attitude control system based on I_DDPG can achieve high control accuracy with both strong anti-interference capability and good robustness.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"55 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136152405","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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