R. White, S. Mulas, P. Domini, Miguel Lopez, Faris Abusittah
The Modulated AC/DC Crude Desalting technology was successfully commissioned at several Saudi Aramco facilities. Enhancements to desalting performance and optimization of plant operating expenditures were realized. Benefits of the Modulated AC/DC Desalting technology, installation and operational best practices and a comparison to conventional AC technology is shared in the paper. The conventional AC desalting technology was replaced with the Modulated AC/DC Crude Desalting technology at some Saudi Aramco facilities. After the successful commissioning, the performance of the new units was tested in one of these facilities to identify operating limits, such as maximum water cut and minimum demulsifier injection at the production header, in which the stable operation is sustainable. A comparison of the performance of the technology compared to that of previous conventional AC desalting technology was conducted through analysis of grid/plate voltage stability, demulsifier injection rate, wash water rates and crude quality parameters. Some enhancements to the process were also introduced which resulted in realizing additional benefits. The technology resulted in several benefits, including: (1) A reduction in the required demulsifier injection rate during the testing period compared to the same time period from the previous year, leading to significant cost savings; (2) Ability to maintain normal operations beyond the design water cuts of the facility; (3) No major grid outages since installation; (4) Additional data that can be used to diagnose separation performance as each transformer provides a number of feedback signals to DCS that are good indicators of the separation process. Based on the observations and analysis, the Modulated AC/DC Crude Desalting Technology has several advantages over the conventional AC Crude Desalting Technology in regards to crude desalting performance and process stability. The Modulated AC/DC Crude Desalting technology at Saudi Aramco was the first installation in Saudi Arabia for Arab Light crude oil. The paper captures Saudi Aramco’s experience and best practices that other companies can find beneficial in their efforts to maintain crude quality and reduce operating expenditures.
{"title":"Modulated AC/DC Crude Desalting Technology Application & Best Practices","authors":"R. White, S. Mulas, P. Domini, Miguel Lopez, Faris Abusittah","doi":"10.2118/205860-ms","DOIUrl":"https://doi.org/10.2118/205860-ms","url":null,"abstract":"\u0000 The Modulated AC/DC Crude Desalting technology was successfully commissioned at several Saudi Aramco facilities. Enhancements to desalting performance and optimization of plant operating expenditures were realized. Benefits of the Modulated AC/DC Desalting technology, installation and operational best practices and a comparison to conventional AC technology is shared in the paper.\u0000 The conventional AC desalting technology was replaced with the Modulated AC/DC Crude Desalting technology at some Saudi Aramco facilities. After the successful commissioning, the performance of the new units was tested in one of these facilities to identify operating limits, such as maximum water cut and minimum demulsifier injection at the production header, in which the stable operation is sustainable. A comparison of the performance of the technology compared to that of previous conventional AC desalting technology was conducted through analysis of grid/plate voltage stability, demulsifier injection rate, wash water rates and crude quality parameters. Some enhancements to the process were also introduced which resulted in realizing additional benefits.\u0000 The technology resulted in several benefits, including: (1) A reduction in the required demulsifier injection rate during the testing period compared to the same time period from the previous year, leading to significant cost savings; (2) Ability to maintain normal operations beyond the design water cuts of the facility; (3) No major grid outages since installation; (4) Additional data that can be used to diagnose separation performance as each transformer provides a number of feedback signals to DCS that are good indicators of the separation process. Based on the observations and analysis, the Modulated AC/DC Crude Desalting Technology has several advantages over the conventional AC Crude Desalting Technology in regards to crude desalting performance and process stability.\u0000 The Modulated AC/DC Crude Desalting technology at Saudi Aramco was the first installation in Saudi Arabia for Arab Light crude oil. The paper captures Saudi Aramco’s experience and best practices that other companies can find beneficial in their efforts to maintain crude quality and reduce operating expenditures.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"28 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78106977","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Coalbed methane (CBM) has emerged as one of the clean unconventional resources to supplement the rising demand of conventional hydrocarbons. Analyzing and predicting CBM production performance is critical in choosing the optimal completion methods and parameters. However, the conventional numerical simulation has challenges of complicated gridding issues and expensive computational costs. The huge amount of available production data that has been collected in the field site opens up a new opportunity to develop data-driven approaches in predicting the production rate. Here, we proposed a novel physics-constrained data-driven workflow to effectively forecast the CBM productivity based on a Gated Recurrent Unit (GRU) and Multi-Layer Perceptron (MLP) combined neural network (GRU-MLP model). The model architecture is optimized by the multiobjective algorithm: nondominated sorting genetic algorithm Ⅱ (NSGA Ⅱ). The proposed framework was used to predict synthetic cases with various fracture-network-complexities and two multistage-fractured wells in field sites located at Qinshui basin and Ordos basin, China. The results indicated that the proposed GRU-MLP combined neural network was able to accurately and stably predict the production performance of multi-fractured horizontal CBM wells in a fast manner. Compared with Simple Recurrent Neural Network (RNN), Gated Recurrent Unit (GRU) and Long Short-Term Memory (LSTM), the proposed GRU-MLP had the highest accuracy and stability especially for gas production in late-time. Consequently, a physics-constrained data-driven approach performed better than a pure data-driven method. Moreover, the optimum GRU-MLP model architecture was a group of optimized solutions, rather than a single solution. Engineers can evaluate the tradeoffs within this set according to the field-site requirements. This study provides a novel machine learning approach based on a GRU-MLP combined neural network model to estimate production performances in CBM wells. The method is simple and gridless, but is capable of predicting the productivity in a computational cost-effective way. The key findings of this work are expected to provide a theoretical guidance for the intelligent development in oil and gas industry.
{"title":"A Physics-Constrained Data-Driven Workflow for Predicting Coalbed Methane Well Production Using A Combined Gated Recurrent Unit and Multi-Layer Perception Neural Network Model","authors":"Ruiyue Yang, Wei Liu, Xiaozhou Qin, Zhongwei Huang, Yuanyuan Shi, Zhaoyu Pang, Yiqun Zhang, Jingbin Li, Tianyu Wang","doi":"10.2118/205903-ms","DOIUrl":"https://doi.org/10.2118/205903-ms","url":null,"abstract":"\u0000 Coalbed methane (CBM) has emerged as one of the clean unconventional resources to supplement the rising demand of conventional hydrocarbons. Analyzing and predicting CBM production performance is critical in choosing the optimal completion methods and parameters. However, the conventional numerical simulation has challenges of complicated gridding issues and expensive computational costs. The huge amount of available production data that has been collected in the field site opens up a new opportunity to develop data-driven approaches in predicting the production rate. Here, we proposed a novel physics-constrained data-driven workflow to effectively forecast the CBM productivity based on a Gated Recurrent Unit (GRU) and Multi-Layer Perceptron (MLP) combined neural network (GRU-MLP model). The model architecture is optimized by the multiobjective algorithm: nondominated sorting genetic algorithm Ⅱ (NSGA Ⅱ). The proposed framework was used to predict synthetic cases with various fracture-network-complexities and two multistage-fractured wells in field sites located at Qinshui basin and Ordos basin, China. The results indicated that the proposed GRU-MLP combined neural network was able to accurately and stably predict the production performance of multi-fractured horizontal CBM wells in a fast manner. Compared with Simple Recurrent Neural Network (RNN), Gated Recurrent Unit (GRU) and Long Short-Term Memory (LSTM), the proposed GRU-MLP had the highest accuracy and stability especially for gas production in late-time. Consequently, a physics-constrained data-driven approach performed better than a pure data-driven method. Moreover, the optimum GRU-MLP model architecture was a group of optimized solutions, rather than a single solution. Engineers can evaluate the tradeoffs within this set according to the field-site requirements. This study provides a novel machine learning approach based on a GRU-MLP combined neural network model to estimate production performances in CBM wells. The method is simple and gridless, but is capable of predicting the productivity in a computational cost-effective way. The key findings of this work are expected to provide a theoretical guidance for the intelligent development in oil and gas industry.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"120 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89869669","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper highlights the application of downhole fiber optic (FO) distributed temperature sensing (DTS) measurements for well and reservoir management applications: 1) Wellbore water injectivity profiling. 2) Mapping of injection water movement in an underlying reservoir. The U.A.E. field in question is an elongated anticline containing several stacked carbonate oil bearing reservoirs (Figure 1). Reservoir A, where two DTS monitored, peripheral horizontal water injectors (Y-1 and Y-2) were drilled, is less developed and tighter than the immediately underlying, more prolific Reservoir B with 40 years of oil production and water injection history. Reservoirs A and B are of Lower Cretaceous age, limestone fabrics made up of several 4th order cycles, subdivided by several thin intra dense, 2-5 ft thick stylolitic intervals within the reservoir zones. Between Reservoir A and Reservoir B there is a dense limestone interval (30-50 ft), referred as dense layer in the Figure 1 well sections.
{"title":"Value of DTS in Multi-Stacked Reservoirs to Better Understand Injectivity and Water Flood Effectiveness – A Field Example from the UAE","authors":"J. Gomes, Jane Mason, Graham F. J. Edmonstone","doi":"10.2118/206103-ms","DOIUrl":"https://doi.org/10.2118/206103-ms","url":null,"abstract":"This paper highlights the application of downhole fiber optic (FO) distributed temperature sensing (DTS) measurements for well and reservoir management applications: 1) Wellbore water injectivity profiling. 2) Mapping of injection water movement in an underlying reservoir.\u0000 The U.A.E. field in question is an elongated anticline containing several stacked carbonate oil bearing reservoirs (Figure 1). Reservoir A, where two DTS monitored, peripheral horizontal water injectors (Y-1 and Y-2) were drilled, is less developed and tighter than the immediately underlying, more prolific Reservoir B with 40 years of oil production and water injection history.\u0000 Reservoirs A and B are of Lower Cretaceous age, limestone fabrics made up of several 4th order cycles, subdivided by several thin intra dense, 2-5 ft thick stylolitic intervals within the reservoir zones. Between Reservoir A and Reservoir B there is a dense limestone interval (30-50 ft), referred as dense layer in the Figure 1 well sections.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74457733","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Nefeli Moridis, W. J. Lee, Wayne Sim, T. Blasingame
The objective of this work is to numerically estimate the fraction of Reserves assigned to each Reserves category of the PRMS matrix through a cumulative distribution function. We selected 38 wells from a Permian Basin dataset available to Texas A&M University. Previous work has shown that Swanson's Mean, which relates the Reserves categories through a cdf of a normal distribution, is an inaccurate method to determine the relationship of the Reserves categories with asymmetric distributions. Production data are lognormally distributed, regardless of basin type, thus cannot follow the SM concept. The Gaussian Quadrature (GQ) provides a methodology to accurately estimate the fraction of Reserves that lie in 1P, 2P, and 3P categories – known as the weights. Gaussian Quadrature is a numerical integration method that uses discrete random variables and a distribution that matches the original data. For this work, we associate the lognormal cumulative distribution function (CDF) with a set of discrete random variables that replace the production data, and determine the associated probabilities. The production data for both conventional and unconventional fields are lognormally distributed, thus we expect that this methodology can be implemented in any field. To do this, we performed probabilistic decline curve analysis (DCA) using Arps’ Hyperbolic model and Monte Carlo simulation to obtain the 1P, 2P, and 3P volumes, and calculated the relative weights of each Reserves category. We performed probabilistic rate transient analysis (RTA) using a commercial software to obtain the 1P, 2P, and 3P volumes, and calculated the relative weights of each Reserves category. We implemented the 3-, 5-, and 10-point GQ to obtain the weight and percentiles for each well. Once this was completed, we validated the GQ results by calculating the percent-difference between the probabilistic DCA, RTA, and GQ results. We increase the standard deviation to account for the uncertainty of Contingent and Prospective resources and implemented 3-, 5-, and 10-point GQ to obtain the weight and percentiles for each well. This allows us to also approximate the weights of these volumes to track them through the life of a given project. The probabilistic DCA, RTA and Reserves results indicate that the SM is an inaccurate method for estimating the relative weights of each Reserves category. The 1C, 2C, 3C, and 1U, 2U, and 3U Contingent and Prospective Resources, respectively, are distributed in a similar way but with greater variance, incorporated in the standard deviation. The results show that the GQ is able to capture an accurate representation of the Reserves weights through a lognormal CDF. Based on the proposed results, we believe that the GQ is accurate and can be used to approximate the relationship between the PRMS categories. This relationship will aid in booking Reserves to the SEC because it can be recreated for any field. These distributions of Reserves and resources ot
{"title":"Gaussian Quadrature GQ Used to Accurately Approximate the Relative Weights of Reserves, Contingent Resources, and Prospective Resources Through A Cumulative Distribution Function","authors":"Nefeli Moridis, W. J. Lee, Wayne Sim, T. Blasingame","doi":"10.2118/206097-ms","DOIUrl":"https://doi.org/10.2118/206097-ms","url":null,"abstract":"\u0000 The objective of this work is to numerically estimate the fraction of Reserves assigned to each Reserves category of the PRMS matrix through a cumulative distribution function. We selected 38 wells from a Permian Basin dataset available to Texas A&M University. Previous work has shown that Swanson's Mean, which relates the Reserves categories through a cdf of a normal distribution, is an inaccurate method to determine the relationship of the Reserves categories with asymmetric distributions.\u0000 Production data are lognormally distributed, regardless of basin type, thus cannot follow the SM concept. The Gaussian Quadrature (GQ) provides a methodology to accurately estimate the fraction of Reserves that lie in 1P, 2P, and 3P categories – known as the weights. Gaussian Quadrature is a numerical integration method that uses discrete random variables and a distribution that matches the original data. For this work, we associate the lognormal cumulative distribution function (CDF) with a set of discrete random variables that replace the production data, and determine the associated probabilities. The production data for both conventional and unconventional fields are lognormally distributed, thus we expect that this methodology can be implemented in any field.\u0000 To do this, we performed probabilistic decline curve analysis (DCA) using Arps’ Hyperbolic model and Monte Carlo simulation to obtain the 1P, 2P, and 3P volumes, and calculated the relative weights of each Reserves category. We performed probabilistic rate transient analysis (RTA) using a commercial software to obtain the 1P, 2P, and 3P volumes, and calculated the relative weights of each Reserves category. We implemented the 3-, 5-, and 10-point GQ to obtain the weight and percentiles for each well. Once this was completed, we validated the GQ results by calculating the percent-difference between the probabilistic DCA, RTA, and GQ results.\u0000 We increase the standard deviation to account for the uncertainty of Contingent and Prospective resources and implemented 3-, 5-, and 10-point GQ to obtain the weight and percentiles for each well. This allows us to also approximate the weights of these volumes to track them through the life of a given project.\u0000 The probabilistic DCA, RTA and Reserves results indicate that the SM is an inaccurate method for estimating the relative weights of each Reserves category. The 1C, 2C, 3C, and 1U, 2U, and 3U Contingent and Prospective Resources, respectively, are distributed in a similar way but with greater variance, incorporated in the standard deviation. The results show that the GQ is able to capture an accurate representation of the Reserves weights through a lognormal CDF.\u0000 Based on the proposed results, we believe that the GQ is accurate and can be used to approximate the relationship between the PRMS categories. This relationship will aid in booking Reserves to the SEC because it can be recreated for any field. These distributions of Reserves and resources ot","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80107178","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Although polymer flooding technology has been widely applied and achieved remarkable effect of increasing oil. Yet the "entry profile inversion" phenomenon occurs inevitably in its later stage, which seriously affects the development effect. In recent years, the soft microgel particle dispersion is a novel developed flooding system. Due to its excellent performance and advanced mechanism, it can slow down the process of profile inversion, and achieve the goal of deep fluid diversion and expanding swept volume. The soft microgel particle dispersion consists of microgel particles and its carrier fluid. After coming into porous media, it shows the properties of "plugging large pore and leave the small one open" and the motion feature of "trapping, deformation, migration". In this paper, reservoir adaptability evaluation, plugging and deformation characteristics of soft microgel particle dispersion in pore throat is explored by using the microfluidic technology and 3D Printing technology. On this basis, by adopting the NMR and CT tomography technology, the research on its oil displacement mechanism is further carried out. Furthermore, the typical field application case is analyzed. Results show that, soft microgel particles have good performance and transport ability in porous media. According to the reservoir adaptability evaluation, the size relationships between particles and core pore throat is obtained, to provide basis for field application scheme design. Through microfluidic experiments, the temporary plugging and deformation characteristics of particles in the pore throat are explored. Also, when injecting soft microgel particle into the core, the particle phase separation happens, which makes the particles enter and plug the large pore in the high permeability layer. Therefore, their carrier fluid displace oil in the small pore, which works in cooperation and causes no damage to the low permeability layer. Furthermore, by using NMR and CT techniques, its micro percolation law in porous media and remaining oil distribution during displacement process is analyzed. During the experiment, microgels presents the motion feature of "migration, trapping, and deformation" in the core pore, which can realize deep fluid diversion and expand swept volume. From 3D macro experiment, microgels can realize the goal of enhance oil recovery. Finally, the soft microgel particle dispersion flooding technology has been applied in different oilfields, such as Oman, Bohai and other oilfields, which all obtained great success. Through interdisciplinary innovative research methods, the oil displacement mechanism and field application of soft microgel particle dispersion is researched, which proves its progressiveness and superiority. The research results provide theoretical basis and technical support for the enhancing oil recovery significantly.
{"title":"The New Development of Soft Microgel Particle Flooding Technology –From Theoretical Research in Laboratory to Field Trial","authors":"Zhe Sun, Xiujun Wang, Xiaodong Kang","doi":"10.2118/205911-ms","DOIUrl":"https://doi.org/10.2118/205911-ms","url":null,"abstract":"\u0000 Although polymer flooding technology has been widely applied and achieved remarkable effect of increasing oil. Yet the \"entry profile inversion\" phenomenon occurs inevitably in its later stage, which seriously affects the development effect. In recent years, the soft microgel particle dispersion is a novel developed flooding system. Due to its excellent performance and advanced mechanism, it can slow down the process of profile inversion, and achieve the goal of deep fluid diversion and expanding swept volume.\u0000 The soft microgel particle dispersion consists of microgel particles and its carrier fluid. After coming into porous media, it shows the properties of \"plugging large pore and leave the small one open\" and the motion feature of \"trapping, deformation, migration\". In this paper, reservoir adaptability evaluation, plugging and deformation characteristics of soft microgel particle dispersion in pore throat is explored by using the microfluidic technology and 3D Printing technology. On this basis, by adopting the NMR and CT tomography technology, the research on its oil displacement mechanism is further carried out. Furthermore, the typical field application case is analyzed.\u0000 Results show that, soft microgel particles have good performance and transport ability in porous media. According to the reservoir adaptability evaluation, the size relationships between particles and core pore throat is obtained, to provide basis for field application scheme design. Through microfluidic experiments, the temporary plugging and deformation characteristics of particles in the pore throat are explored. Also, when injecting soft microgel particle into the core, the particle phase separation happens, which makes the particles enter and plug the large pore in the high permeability layer. Therefore, their carrier fluid displace oil in the small pore, which works in cooperation and causes no damage to the low permeability layer. Furthermore, by using NMR and CT techniques, its micro percolation law in porous media and remaining oil distribution during displacement process is analyzed. During the experiment, microgels presents the motion feature of \"migration, trapping, and deformation\" in the core pore, which can realize deep fluid diversion and expand swept volume. From 3D macro experiment, microgels can realize the goal of enhance oil recovery. Finally, the soft microgel particle dispersion flooding technology has been applied in different oilfields, such as Oman, Bohai and other oilfields, which all obtained great success.\u0000 Through interdisciplinary innovative research methods, the oil displacement mechanism and field application of soft microgel particle dispersion is researched, which proves its progressiveness and superiority. The research results provide theoretical basis and technical support for the enhancing oil recovery significantly.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74206541","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Yibo Yang, T. Regueira, Hilario Martin Rodriguez, A. Shapiro, E. Stenby, Wei Yan
Molecular diffusion plays a critical role in gas injection in tight reservoirs such as liquid-rich shale. Despite recent efforts on measuring diffusion coefficients at high pressures, there is a general lack of the diffusion coefficients in live oil systems at reservoir conditions relevant to the development of these tight reservoirs. The reported diffusion coefficients often differ in orders of magnitude, and there is no consensus on the reliability of the common correlations for liquid phase diffusion coefficients, such as the extended Sigmund correlation. We employed the constant volume diffusion method to measure the high-pressure diffusion coefficients in a newly designed high-pressure tube. The experimental method was first validated using methane + hexadecane and methane + decane, and then used to measure the methane diffusion coefficients in two live oils at reservoir conditions. The obtained data were processed by compositional simulation to determine the diffusion coefficients. The diffusion coefficients measured for methane + hexadecane and methane + decane are in agreement with the existing literature data. For methane + live oil systems, however, the diffusion coefficients estimated by the extended Sigmund correlation are much lower than the measured results. An over ten times adjustment is needed to best fit the pressure decay curves. A further check reveals that for live oil systems, the reduced densities are often in the extrapolated region of the original Sigmund model. The curve in this region of the extended Sigmund correlation has a weak experimental basis, which may be the reason for its large deviation. The estimates from other correlations like Wilke-Chang and Hayduk-Minhas also give very different results. We compared the diffusion coefficients in high-pressure oils reported in the literature, showing a large variation in the reported values. All these indicate the necessity for further study on accurate determination of high-pressure diffusion coefficients in live oils of relevance to shale and other tight reservoirs.
{"title":"Determination of Methane Diffusion Coefficients in Live Oils for Tight Reservoirs at High Pressures","authors":"Yibo Yang, T. Regueira, Hilario Martin Rodriguez, A. Shapiro, E. Stenby, Wei Yan","doi":"10.2118/206100-ms","DOIUrl":"https://doi.org/10.2118/206100-ms","url":null,"abstract":"\u0000 Molecular diffusion plays a critical role in gas injection in tight reservoirs such as liquid-rich shale. Despite recent efforts on measuring diffusion coefficients at high pressures, there is a general lack of the diffusion coefficients in live oil systems at reservoir conditions relevant to the development of these tight reservoirs. The reported diffusion coefficients often differ in orders of magnitude, and there is no consensus on the reliability of the common correlations for liquid phase diffusion coefficients, such as the extended Sigmund correlation. We employed the constant volume diffusion method to measure the high-pressure diffusion coefficients in a newly designed high-pressure tube. The experimental method was first validated using methane + hexadecane and methane + decane, and then used to measure the methane diffusion coefficients in two live oils at reservoir conditions. The obtained data were processed by compositional simulation to determine the diffusion coefficients. The diffusion coefficients measured for methane + hexadecane and methane + decane are in agreement with the existing literature data. For methane + live oil systems, however, the diffusion coefficients estimated by the extended Sigmund correlation are much lower than the measured results. An over ten times adjustment is needed to best fit the pressure decay curves. A further check reveals that for live oil systems, the reduced densities are often in the extrapolated region of the original Sigmund model. The curve in this region of the extended Sigmund correlation has a weak experimental basis, which may be the reason for its large deviation. The estimates from other correlations like Wilke-Chang and Hayduk-Minhas also give very different results. We compared the diffusion coefficients in high-pressure oils reported in the literature, showing a large variation in the reported values. All these indicate the necessity for further study on accurate determination of high-pressure diffusion coefficients in live oils of relevance to shale and other tight reservoirs.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"82 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73953307","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Yuchen Wen, J. Hou, Ming Qu, Wei-Peng Wu, Tuo Liang, Wei Zhang, Wenming Wu
This paper summarizes the change rule of production performance and the EOR efficiency from the micro-dispersed gel foam injection in the fractured-vuggy carbonate reservoir of Tahe Oilfield. The TK722CH2 well group injected gas from August 2014 to September 2018. During the gas injection stage, the effect of periodic gas injection decreased obviously, the effective direction of gas injection was single and the risk of gas channeling increased greatly. The field pilot test f micro-dispersed gel foam was carried out on September 20, 2018. The fluid is injected into well group in three slugs: micro-dispersed gel foam, normal foam and nitrogen gas. As a part of the foam pilot test monitoring, a gas tracer study was performed before and after the injection of gel foam in the reservoir. After the pilot test was carried out in the TK722CH2 well group, the subsequent injection gas swept new fractures and vugs, and a new dynamic connectivity has been established. The connectivity of well group changed from 1 injection well connects with 1 production well to 1 injection well connects with 4 production wells. Through the field pilot test of micro-dispersed gel foam, this paper verifies the effect of improve gas flooding and increase sweep volume of micro-dispersed gel foam. By analyzing the results of the field pilot test, the relevant technical mechanism of micro-dispersed gel foam in fractured-vuggy reservoir is revealed. As a result, the field pilot test in this paper provides theoretical basis and technical support for the efficient development of fractured-vuggy carbonate reservoir.
{"title":"Field Pilot Test of Micro-Dispersed Gel Foam in Fractured-Vuggy Carbonate Reservoirs","authors":"Yuchen Wen, J. Hou, Ming Qu, Wei-Peng Wu, Tuo Liang, Wei Zhang, Wenming Wu","doi":"10.2118/206073-ms","DOIUrl":"https://doi.org/10.2118/206073-ms","url":null,"abstract":"\u0000 This paper summarizes the change rule of production performance and the EOR efficiency from the micro-dispersed gel foam injection in the fractured-vuggy carbonate reservoir of Tahe Oilfield. The TK722CH2 well group injected gas from August 2014 to September 2018. During the gas injection stage, the effect of periodic gas injection decreased obviously, the effective direction of gas injection was single and the risk of gas channeling increased greatly. The field pilot test f micro-dispersed gel foam was carried out on September 20, 2018. The fluid is injected into well group in three slugs: micro-dispersed gel foam, normal foam and nitrogen gas. As a part of the foam pilot test monitoring, a gas tracer study was performed before and after the injection of gel foam in the reservoir. After the pilot test was carried out in the TK722CH2 well group, the subsequent injection gas swept new fractures and vugs, and a new dynamic connectivity has been established. The connectivity of well group changed from 1 injection well connects with 1 production well to 1 injection well connects with 4 production wells. Through the field pilot test of micro-dispersed gel foam, this paper verifies the effect of improve gas flooding and increase sweep volume of micro-dispersed gel foam. By analyzing the results of the field pilot test, the relevant technical mechanism of micro-dispersed gel foam in fractured-vuggy reservoir is revealed. As a result, the field pilot test in this paper provides theoretical basis and technical support for the efficient development of fractured-vuggy carbonate reservoir.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"216 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87152929","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Elizabeth Ruiz, Brandon Thibodeaux, C. Dorion, Herman Mukisa, M. Faskhoodi, Bilal Hakim, G. Garcia, Wangbin Xu, S. Betancourt, Jesus A. Cañas, Tom Messonnier, O. Mullins
Optimized geomodeling and history matching of production data is presented by utilizing an integrated rock and fluid workflow. Facies identification is performed by use of image logs and other geological information. In addition, image logs are used to help define structural geodynamic processes that occurred in the reservoir. Methods of reservoir fluid geodynamics are used to assess the extent of fluid compositional equilibrium, especially the asphaltenes, and thereby the extent of connectivity in these facies. Geochemical determinations are shown to be consistent with measurements of compositional thermodynamic equilibrium. The ability to develop the geo-scenario of the reservoir, the coherent evolution of rock and contained fluids in the reservoir over geologic time, improves the robustness of the geomodel. In particular, the sequence of oil charge, compositional equilibrium, fault block throw, and primary biogenic gas charge are established in this middle Pliocene reservoir with implications for production, field extension,and local basin exploration. History matching of production data prove the accuracy of the geomodel; nevertheless, refinements to the geomodel and improved history matching were obtained by expanded deterministic property estimation from wireline log and other data. Theearly connection of fluid data, both thermodynamic and geochemical, with relevant facies andtheir properties determination enables a more facile method to incorporate this data into the geomodel. Logging data from future wells in the field can be imported into the geomodel allowingdeterministic optimization of this model long after production has commenced. While each reservoir is unique with its own idiosyncrasies, the workflow presented here is generally applicable to all reservoirs and always improves reservoir understanding.
{"title":"Integrated Rock and Fluid Workflow to Optimize Geomodeling and History Matching","authors":"Elizabeth Ruiz, Brandon Thibodeaux, C. Dorion, Herman Mukisa, M. Faskhoodi, Bilal Hakim, G. Garcia, Wangbin Xu, S. Betancourt, Jesus A. Cañas, Tom Messonnier, O. Mullins","doi":"10.2118/206299-ms","DOIUrl":"https://doi.org/10.2118/206299-ms","url":null,"abstract":"\u0000 Optimized geomodeling and history matching of production data is presented by utilizing an integrated rock and fluid workflow. Facies identification is performed by use of image logs and other geological information. In addition, image logs are used to help define structural geodynamic processes that occurred in the reservoir. Methods of reservoir fluid geodynamics are used to assess the extent of fluid compositional equilibrium, especially the asphaltenes, and thereby the extent of connectivity in these facies. Geochemical determinations are shown to be consistent with measurements of compositional thermodynamic equilibrium. The ability to develop the geo-scenario of the reservoir, the coherent evolution of rock and contained fluids in the reservoir over geologic time, improves the robustness of the geomodel. In particular, the sequence of oil charge, compositional equilibrium, fault block throw, and primary biogenic gas charge are established in this middle Pliocene reservoir with implications for production, field extension,and local basin exploration. History matching of production data prove the accuracy of the geomodel; nevertheless, refinements to the geomodel and improved history matching were obtained by expanded deterministic property estimation from wireline log and other data. Theearly connection of fluid data, both thermodynamic and geochemical, with relevant facies andtheir properties determination enables a more facile method to incorporate this data into the geomodel. Logging data from future wells in the field can be imported into the geomodel allowingdeterministic optimization of this model long after production has commenced. While each reservoir is unique with its own idiosyncrasies, the workflow presented here is generally applicable to all reservoirs and always improves reservoir understanding.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90780021","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Ross Markham, Alastair Michell, D. Noblett, Bernard McCartan, Septiandi Sugiarto, Tony Trung Huynh, Amrendra Kumar, B. Gadiyar
A reliable single-trip openhole multizone completion can significantly lower capital expenditure (CAPEX) by reducing rig time and well count. Recent improvements in openhole packers and enhanced shunt screen technology have enabled multizone openhole gravel pack completions with complete zonal isolation. A multizone openhole gravel-pack completion was installed in the Julimar Field with an enhanced shunt screen system, shunted mechnaical packers (SMP) and shunt tube isolation valves (STIV), to provide improved operating pressure envelope and erosion tolerance. Well design was tailored to derisk the installation and optimize performance of the multizone completion. Extensive reliability testing was undertaken on all new technology for this project. Completions were installed as planned, and the main objectives of sand control integrity, production attainment, and complete zonal isolation with selective production were validated through post-job gravel-pack analysis and subsequent well unloading. The successful implementation of these technologies significantly reduced project CAPEX and enabled access to reserves that would otherwise have been uneconomical to recover. This paper discusses design, execution, and evaluation of the multizone openhole gravel pack (OHGP) completions installed in the Julimar Field. This includes methodology followed for multizone completion selection, development of a new high-temperature formate-based viscous gravel-pack carrier fluid, detailed completion equipment qualification tests, post-job gravel-pack evaluation, and initial well performance from well unload. It is the industry's first field case study of enhanced shunt screens with novel shunt tube isolation valves and high-temperature xanthan-based gravel-pack carrier fluid.
{"title":"Multizone Openhole Gravel Packing with Enhanced Shunt Screens and Zonal Isolation in High-Rate Gas Wells","authors":"Ross Markham, Alastair Michell, D. Noblett, Bernard McCartan, Septiandi Sugiarto, Tony Trung Huynh, Amrendra Kumar, B. Gadiyar","doi":"10.2118/206000-ms","DOIUrl":"https://doi.org/10.2118/206000-ms","url":null,"abstract":"\u0000 A reliable single-trip openhole multizone completion can significantly lower capital expenditure (CAPEX) by reducing rig time and well count. Recent improvements in openhole packers and enhanced shunt screen technology have enabled multizone openhole gravel pack completions with complete zonal isolation. A multizone openhole gravel-pack completion was installed in the Julimar Field with an enhanced shunt screen system, shunted mechnaical packers (SMP) and shunt tube isolation valves (STIV), to provide improved operating pressure envelope and erosion tolerance. Well design was tailored to derisk the installation and optimize performance of the multizone completion. Extensive reliability testing was undertaken on all new technology for this project.\u0000 Completions were installed as planned, and the main objectives of sand control integrity, production attainment, and complete zonal isolation with selective production were validated through post-job gravel-pack analysis and subsequent well unloading. The successful implementation of these technologies significantly reduced project CAPEX and enabled access to reserves that would otherwise have been uneconomical to recover.\u0000 This paper discusses design, execution, and evaluation of the multizone openhole gravel pack (OHGP) completions installed in the Julimar Field. This includes methodology followed for multizone completion selection, development of a new high-temperature formate-based viscous gravel-pack carrier fluid, detailed completion equipment qualification tests, post-job gravel-pack evaluation, and initial well performance from well unload. It is the industry's first field case study of enhanced shunt screens with novel shunt tube isolation valves and high-temperature xanthan-based gravel-pack carrier fluid.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90480120","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The paper describes a fast and approximate 1D simulation algorithm for calculating the percent recovery that can be obtained from an oil reservoir if gas injection is carried out at a pressure lower than the minimum miscibility pressure. The algorithm is based on the Method of Characteristics. While a conventional 1D reservoir simulation of a gas injection scenario may take minutes or even hours, the proposed algorithm allows a full evaluation of the recovery to be completed within seconds. To make the method numerically robust, a number of approximations were needed. The result is an extremely fast algorithm that not only provides a good estimate of the recovery obtained by gas injection, but also gives a good visualization of how the gas displaces the oil.
{"title":"Modified Method of Characteristics for Generating EOR Oil Recovery Curves","authors":"Christian S. Agger, H. Sørensen","doi":"10.2118/205918-ms","DOIUrl":"https://doi.org/10.2118/205918-ms","url":null,"abstract":"\u0000 The paper describes a fast and approximate 1D simulation algorithm for calculating the percent recovery that can be obtained from an oil reservoir if gas injection is carried out at a pressure lower than the minimum miscibility pressure. The algorithm is based on the Method of Characteristics. While a conventional 1D reservoir simulation of a gas injection scenario may take minutes or even hours, the proposed algorithm allows a full evaluation of the recovery to be completed within seconds. To make the method numerically robust, a number of approximations were needed. The result is an extremely fast algorithm that not only provides a good estimate of the recovery obtained by gas injection, but also gives a good visualization of how the gas displaces the oil.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81202488","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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