M. T. Al-Murayri, Dawood S. Kamal, R. Al-Abbas, G. Shahin, Greg Chilek, S. Shukla
A one-spot EOR pilot was successfully completed to demonstrate the efficacy of a lab-optimized ASP formulation to mobilize remaining oil from a giant sandstone reservoir in Kuwait. This one-spot EOR pilot, which also referred to as a Single Well Chemical Tracer (SWCT) test, was a significant milestone in de-risking ASP flooding for multi-well pilot implementation. The vertical zone of investigation for the Raudhatain Zubair (RAZU) SWCT was chosen to be a confined channel sand with relatively homogeneous and representative properties in a producer near the proposed pilot area. Two SWCT tests were performed and the difference in residual oil saturation from post water flood and post ASP injection tracer tests quantitatively determines the displacement efficiency of the ASP slug. The tracer chemicals for the tests included a hydrolyzing, partitioning tracer (ethyl acetate) and two alcohols (n-propyl alcohol and isopropyl alcohol) that serve as cover tracer and material balance tracer, respectively, to ensure robustness of test interpretation. The water flood SWCT test showed ideal behavior with well-defined profiles. Interpretation of this test was accomplished using a single layer model and showed that at the end of the water flood, the residual oil saturation to water was 0.24 ± 0.02% in the 23 -ft interval for the SWCT test. The ASP tracer test was complicated due to poor injectivity, well mechanical issues, and dilution from a zone which did not accept any SWCT test injection fluids but contributed substantially to production. Due to the dilution from another zone, the ASP tracer test profiles were more dispersed than the water flood tracer test but were adequately modeled using a two-layer model with irreversible flow. Analysis of the ASP SWCT test showed that the average oil saturation was reduced to 0.06 ± 0.05%, which represents a ~67% reduction in residual oil saturation. Despite poor injectivity leading to a reduced polymer drive and taper injection and dilution from another zone resulting in a non-idealized tracer response, careful interpretation of the SWCT test measurements resulted in a reliable estimate of the post-ASP oil saturation. The SWCT test results demonstrate the feasibility of applying ASP flooding to increase oil recovery from a giant high-temperature sandstone reservoir in North Kuwait.
{"title":"Successful Implementation of a Single Well Chemical Tracer SWCT Test for a Giant Sandstone Reservoir in North Kuwait","authors":"M. T. Al-Murayri, Dawood S. Kamal, R. Al-Abbas, G. Shahin, Greg Chilek, S. Shukla","doi":"10.2118/198127-ms","DOIUrl":"https://doi.org/10.2118/198127-ms","url":null,"abstract":"\u0000 A one-spot EOR pilot was successfully completed to demonstrate the efficacy of a lab-optimized ASP formulation to mobilize remaining oil from a giant sandstone reservoir in Kuwait. This one-spot EOR pilot, which also referred to as a Single Well Chemical Tracer (SWCT) test, was a significant milestone in de-risking ASP flooding for multi-well pilot implementation.\u0000 The vertical zone of investigation for the Raudhatain Zubair (RAZU) SWCT was chosen to be a confined channel sand with relatively homogeneous and representative properties in a producer near the proposed pilot area. Two SWCT tests were performed and the difference in residual oil saturation from post water flood and post ASP injection tracer tests quantitatively determines the displacement efficiency of the ASP slug. The tracer chemicals for the tests included a hydrolyzing, partitioning tracer (ethyl acetate) and two alcohols (n-propyl alcohol and isopropyl alcohol) that serve as cover tracer and material balance tracer, respectively, to ensure robustness of test interpretation.\u0000 The water flood SWCT test showed ideal behavior with well-defined profiles. Interpretation of this test was accomplished using a single layer model and showed that at the end of the water flood, the residual oil saturation to water was 0.24 ± 0.02% in the 23 -ft interval for the SWCT test. The ASP tracer test was complicated due to poor injectivity, well mechanical issues, and dilution from a zone which did not accept any SWCT test injection fluids but contributed substantially to production. Due to the dilution from another zone, the ASP tracer test profiles were more dispersed than the water flood tracer test but were adequately modeled using a two-layer model with irreversible flow. Analysis of the ASP SWCT test showed that the average oil saturation was reduced to 0.06 ± 0.05%, which represents a ~67% reduction in residual oil saturation.\u0000 Despite poor injectivity leading to a reduced polymer drive and taper injection and dilution from another zone resulting in a non-idealized tracer response, careful interpretation of the SWCT test measurements resulted in a reliable estimate of the post-ASP oil saturation. The SWCT test results demonstrate the feasibility of applying ASP flooding to increase oil recovery from a giant high-temperature sandstone reservoir in North Kuwait.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"56 11","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121010648","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}
S. A. Hosseini, Morteza Roostaei, Mahdi Mahmoudi, Ahmad Alkouh, Vahidoddin Fattahpour
Production from weakly and unconsolidated sand formations relies on the efficiency of the employed sand control method. Performance of current sand control devices is based on surface size exclusion and depth filtration depending on their geometry and application. In this study, we investigate the possibility of using the advantage of both mechanisms in a single device. The standard cut point test was used to determine the micron rating of different meshes in order to categorize them in different classes based on the average pore size. Different mesh weaves, namely Dutch twill, reversed Dutch twill and square mesh screens with different micron rating were investigated in terms of filtration performance. In the next step, a dead-end filtration set-up was designed and commissioned to evaluate the flow performance and sand control capabilities of mesh screens. Additionally, a new, customized sand control device was designed and included in the testing matrix to compare its performance with the common mesh screens in the market. Dead-end filtration results indicated that by choosing the proper combination of morphology, both optimized open to flow area (OFA) and sand control could be achieved. The custom designed hybrid screen performed better compared to other investigated mesh screens with similar micron rating, in terms of both flow and filtration performance. Therefore, the customization was found to be the key parameter to achieve the optimized design. This further emphasizes that by employing the hybrid benefits of surface size exclusion and depth filtration, one can reach the optimized sand control and flow performance. Regarding the weave of different mesh screens, the results did not show any trends that could lead to a conclusion of better performance of a certain weave. Further investigations are required under different testing condition to achieve a conclusive comparison between different mesh types. This paper investigates the possibility of customized sand control design, which uses the hybrid benefits of surface size exclusion and depth filtration to reach the optimized sand control and flow performance.
{"title":"Development of the Hybrid Sand Control Screen for Surface Size Exclusion and Depth Filtration Media","authors":"S. A. Hosseini, Morteza Roostaei, Mahdi Mahmoudi, Ahmad Alkouh, Vahidoddin Fattahpour","doi":"10.2118/198056-ms","DOIUrl":"https://doi.org/10.2118/198056-ms","url":null,"abstract":"\u0000 Production from weakly and unconsolidated sand formations relies on the efficiency of the employed sand control method. Performance of current sand control devices is based on surface size exclusion and depth filtration depending on their geometry and application. In this study, we investigate the possibility of using the advantage of both mechanisms in a single device.\u0000 The standard cut point test was used to determine the micron rating of different meshes in order to categorize them in different classes based on the average pore size. Different mesh weaves, namely Dutch twill, reversed Dutch twill and square mesh screens with different micron rating were investigated in terms of filtration performance. In the next step, a dead-end filtration set-up was designed and commissioned to evaluate the flow performance and sand control capabilities of mesh screens. Additionally, a new, customized sand control device was designed and included in the testing matrix to compare its performance with the common mesh screens in the market.\u0000 Dead-end filtration results indicated that by choosing the proper combination of morphology, both optimized open to flow area (OFA) and sand control could be achieved. The custom designed hybrid screen performed better compared to other investigated mesh screens with similar micron rating, in terms of both flow and filtration performance. Therefore, the customization was found to be the key parameter to achieve the optimized design. This further emphasizes that by employing the hybrid benefits of surface size exclusion and depth filtration, one can reach the optimized sand control and flow performance. Regarding the weave of different mesh screens, the results did not show any trends that could lead to a conclusion of better performance of a certain weave. Further investigations are required under different testing condition to achieve a conclusive comparison between different mesh types.\u0000 This paper investigates the possibility of customized sand control design, which uses the hybrid benefits of surface size exclusion and depth filtration to reach the optimized sand control and flow performance.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"148 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121348595","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}
Amer Jaragh, Abdul Wahab Al-Ahmad, S. Prakash, Adel F. Almutairi, A. Mathew
Internal corrosion is a leading cause of failure of pipelines that transport crude oil. The small amounts of saline water present in crude oil separates over a period due to any stagnancy or low flow conditions. The separated water causes water wetting of the pipe surface and creates corrosive condition along with the presence of carbon dioxide and hydrogen sulfide and bacteria, especially the sulfate reducing bacteria (SRB) and acid producing general anaerobic bacteria (GAnB) that thrive under the anaerobic conditions existing in pipelines. This is the major reason for pitting and leakages of pipelines. The On-line Corrosion Monitoring (OCM) using corrosion coupons provide early indication of internal corrosion taking place on the pipe wall. The chemical analysis of deposits removed from cleaning pigging provide qualitative information of general corrosion and its possible mechanism, while the microbiological analysis can indicate the involvement of bacteria in the internal corrosion. In-line Inspection (ILI) conducted on a cleaned pipeline measure pit depth on the internal pipe wall. This paper analyzes the data collected by each of these internal corrosion monitoring techniques and suggests a means for ranking the internal corrosion severity of crude pipelines of the Oil Field Operating Company, based on interpretation of the data. This ranking can help in optimizing the ILI activities by changing to a need-based program from the current schedule-based program.
{"title":"Internal Corrosion Severity Ranking of Crude Oil Pipelines","authors":"Amer Jaragh, Abdul Wahab Al-Ahmad, S. Prakash, Adel F. Almutairi, A. Mathew","doi":"10.2118/198133-ms","DOIUrl":"https://doi.org/10.2118/198133-ms","url":null,"abstract":"\u0000 Internal corrosion is a leading cause of failure of pipelines that transport crude oil. The small amounts of saline water present in crude oil separates over a period due to any stagnancy or low flow conditions. The separated water causes water wetting of the pipe surface and creates corrosive condition along with the presence of carbon dioxide and hydrogen sulfide and bacteria, especially the sulfate reducing bacteria (SRB) and acid producing general anaerobic bacteria (GAnB) that thrive under the anaerobic conditions existing in pipelines. This is the major reason for pitting and leakages of pipelines.\u0000 The On-line Corrosion Monitoring (OCM) using corrosion coupons provide early indication of internal corrosion taking place on the pipe wall. The chemical analysis of deposits removed from cleaning pigging provide qualitative information of general corrosion and its possible mechanism, while the microbiological analysis can indicate the involvement of bacteria in the internal corrosion. In-line Inspection (ILI) conducted on a cleaned pipeline measure pit depth on the internal pipe wall.\u0000 This paper analyzes the data collected by each of these internal corrosion monitoring techniques and suggests a means for ranking the internal corrosion severity of crude pipelines of the Oil Field Operating Company, based on interpretation of the data. This ranking can help in optimizing the ILI activities by changing to a need-based program from the current schedule-based program.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"56 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129421872","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}
Currently, the process safety risk associated with the siting, layout, segregation and spacing of the facilities and equipment is managed through the application of a series of standards developed long ago, when the Kuwait Oil Company (KOC) (the Company) oil and gas operations were less complex, and the presence of associated H2S was relatively low. In terms of Building Risk Assessment (BRA), there is no specific company standard or procedure to reflect the best practices to be followed on this subject. However, international standards, mainly API 752 and 753, are followed for the siting and design of buildings located within the facilities. Additionally, the Company have embarked in an aggressive plan to substantially increase production by 2040 and beyond. This means that existing oil and gas fields will continue to be developed over the next two decades, which will entail a tendency to congestion, both in the fields and in the facilities layout. In order to successfully contribute to underpin the significant increase in activity and infrastructure required to safely achieve production growth for 2040 and beyond, the Company have decided to improve the approach to siting and layout by undertaking the development of world-class best practices to provide risk-based guidelines for field spacing. Clearly, the Company realized that optimum location (siting) and layout minimizes material and construction costs, but more importantly, significantly reduces risks, and hence, increases process safety throughout the facility's life cycle. It also allows for building inherent safety into the design of plants and facilities. It is also very important to mention that optimum location (siting) and layout of the facilities will clearly result in an enhanced use of land, which in turn contributes to an adequate management of this limited resource in the State of Kuwait. Considering all the above, the proper management of process risks derived from siting and layout has been identified as of key importance for the safe operation and success of the company's activities, both at present and particularly in the near future. This paper describes the process of developing the risk-based guidelines for field spacing, including the methodology, criteria, consequence modelling, etc. that was undertaken for KOC to create look-up tables, graphs, to facilitate layout in a consistent manner throughout all project phases from concept selection, when relatively little is known, through detailed engineering.
{"title":"Development of Risk-Based Field Spacing Guidelines for Kuwait Oil Company KOC","authors":"Maarten De Groot, N. Mandic, P. Mandić","doi":"10.2118/198176-ms","DOIUrl":"https://doi.org/10.2118/198176-ms","url":null,"abstract":"\u0000 Currently, the process safety risk associated with the siting, layout, segregation and spacing of the facilities and equipment is managed through the application of a series of standards developed long ago, when the Kuwait Oil Company (KOC) (the Company) oil and gas operations were less complex, and the presence of associated H2S was relatively low. In terms of Building Risk Assessment (BRA), there is no specific company standard or procedure to reflect the best practices to be followed on this subject. However, international standards, mainly API 752 and 753, are followed for the siting and design of buildings located within the facilities.\u0000 Additionally, the Company have embarked in an aggressive plan to substantially increase production by 2040 and beyond. This means that existing oil and gas fields will continue to be developed over the next two decades, which will entail a tendency to congestion, both in the fields and in the facilities layout.\u0000 In order to successfully contribute to underpin the significant increase in activity and infrastructure required to safely achieve production growth for 2040 and beyond, the Company have decided to improve the approach to siting and layout by undertaking the development of world-class best practices to provide risk-based guidelines for field spacing.\u0000 Clearly, the Company realized that optimum location (siting) and layout minimizes material and construction costs, but more importantly, significantly reduces risks, and hence, increases process safety throughout the facility's life cycle. It also allows for building inherent safety into the design of plants and facilities. It is also very important to mention that optimum location (siting) and layout of the facilities will clearly result in an enhanced use of land, which in turn contributes to an adequate management of this limited resource in the State of Kuwait.\u0000 Considering all the above, the proper management of process risks derived from siting and layout has been identified as of key importance for the safe operation and success of the company's activities, both at present and particularly in the near future.\u0000 This paper describes the process of developing the risk-based guidelines for field spacing, including the methodology, criteria, consequence modelling, etc. that was undertaken for KOC to create look-up tables, graphs, to facilitate layout in a consistent manner throughout all project phases from concept selection, when relatively little is known, through detailed engineering.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"111 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123220169","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}
In recent years, Petrophysicists have established that rock typing is an essential pre-requisite for estimating permeability in reservoir rocks. Any attempt that does not use rock typing for modeling permeability has been documented to be characterized by a large data scatter and associated with high uncertainty. In this paper, four common rock typing techniques are compared: Pittman, Lucia, Flow Zone Indicator (FZI), and Global Hydraulic Element (GHE). The performance of these rock typing approaches is assessed through intrinsic models for their ability to predict the permeability of a prominent carbonate field. The FZI and the Pittman approaches gave the best estimates of permeability with a coefficient of determination of approximately 0.98. By contrast, the Lucia approach gave the least precise estimates of permeability with a coefficient of determination of 0.81. The GHE approach gave a satisfactory estimation with a coefficient of determination of 0.90. A new technique for rock typing, based on dimensional analysis, is presented. Dimensional analysis leads to the derivation of two dimensionless groups: (λ) and (Ω). The λ group is a dimensionless Flow Zone Indicator (FZI) and the (Ω) group is the dimensionless photo-electric adsorption. The main advantage of the dimensional analysis technique is that it relies directly on open hole log measurements, such as the spontaneous potential, bulk density, interval transit time, and photoelectric absorption. A unique power-law relationship exists between the dimensionless FZI group (λ), and the dimensionless photo-electric adsorption group (Ω). For the studied carbonate field, a coefficient of determination of 0.98 was obtained when estimating reservoir permeability with the dimensional analysis rock typing. This paper will be of interest to subsurface modelers who need to estimate permeability. Using the dimensional analysis approach described and comparing this new method of estimation with established methods, it is proposed that rock typing by dimensional analysis for estimating permeability can be used as an alternative method.
近年来，岩石物理学家已经确定岩石类型是估计储层岩石渗透率的必要先决条件。任何不使用岩石分型来模拟渗透率的尝试都被证明具有大数据分散和高不确定性的特点。本文比较了Pittman、Lucia、Flow Zone Indicator (FZI)和Global Hydraulic Element (GHE)四种常用的岩石分型技术。这些岩石分型方法的性能是通过内在模型来评估的，因为它们能够预测一个突出的碳酸盐岩油田的渗透率。FZI和Pittman方法给出了渗透率的最佳估计，其决定系数约为0.98。相比之下，Lucia方法给出的渗透率估计最不精确，其决定系数为0.81。GHE法给出了令人满意的估计，决定系数为0.90。提出了一种基于量纲分析的岩石分型新方法。量纲分析导致两个无量纲群的推导:(λ)和(Ω)。λ基团为无量纲流动区指示器(FZI)， (Ω)基团为无量纲光电吸附。量程分析技术的主要优点是，它直接依赖于裸眼测井测量，如自发电位、体积密度、层间传递时间和光电吸收。无因次FZI基团(λ)与无因次光电吸附基团(Ω)之间存在独特的幂律关系。对于研究的碳酸盐岩油田，用量纲分析岩石分型估计储层渗透率的决定系数为0.98。对于需要估计渗透率的地下建模人员来说，这篇论文将会很有意义。利用所描述的量纲分析方法，并将这种新的估计方法与已有的方法进行比较，提出用量纲分析岩石分型来估计渗透率可以作为一种替代方法。
{"title":"A New Approach for Rock Typing Using Dimensional Analysis: A Case Study of Carbonate Reservoir","authors":"M. Abdullah, A. Garrouch","doi":"10.2118/198026-ms","DOIUrl":"https://doi.org/10.2118/198026-ms","url":null,"abstract":"\u0000 In recent years, Petrophysicists have established that rock typing is an essential pre-requisite for estimating permeability in reservoir rocks. Any attempt that does not use rock typing for modeling permeability has been documented to be characterized by a large data scatter and associated with high uncertainty.\u0000 In this paper, four common rock typing techniques are compared: Pittman, Lucia, Flow Zone Indicator (FZI), and Global Hydraulic Element (GHE). The performance of these rock typing approaches is assessed through intrinsic models for their ability to predict the permeability of a prominent carbonate field. The FZI and the Pittman approaches gave the best estimates of permeability with a coefficient of determination of approximately 0.98. By contrast, the Lucia approach gave the least precise estimates of permeability with a coefficient of determination of 0.81. The GHE approach gave a satisfactory estimation with a coefficient of determination of 0.90.\u0000 A new technique for rock typing, based on dimensional analysis, is presented. Dimensional analysis leads to the derivation of two dimensionless groups: (λ) and (Ω). The λ group is a dimensionless Flow Zone Indicator (FZI) and the (Ω) group is the dimensionless photo-electric adsorption. The main advantage of the dimensional analysis technique is that it relies directly on open hole log measurements, such as the spontaneous potential, bulk density, interval transit time, and photoelectric absorption. A unique power-law relationship exists between the dimensionless FZI group (λ), and the dimensionless photo-electric adsorption group (Ω). For the studied carbonate field, a coefficient of determination of 0.98 was obtained when estimating reservoir permeability with the dimensional analysis rock typing.\u0000 This paper will be of interest to subsurface modelers who need to estimate permeability. Using the dimensional analysis approach described and comparing this new method of estimation with established methods, it is proposed that rock typing by dimensional analysis for estimating permeability can be used as an alternative method.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"4 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127594151","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
We interpreted a series of single-well-chemical-tracer-tests (SWCTTs) estimating residual oil (SORW) to base high salinity waterflood, low salinity waterflood and subsequent polymer flood conducted on a Greater Burgan well. Interpretation of the tests requires history matching of the back-production of partitioning and non-partitioning tracers which is impacted by differing amounts of irreversible flow and differing amounts of dispersion as well as the amount of residual oil. We applied the state-of-the-art chemical reservoir simulator (UTCHEM) and an assisted history matching tool (BP’s Top-Down-Reservoir-Modeling) to interpret the tests and accurately quantify uncertainty in residual oil saturations post high salinity, low salinity, and polymer floods. Two optimization algorithms (i.e., Genetic algorithm (GA) and Particle-Swarm-Optimization (PSO)-Mesh-Adaptive-Direct-Search (MADS) algorithms) were applied to better address the uncertainty. Our results show a six saturation unit decrease in SORW post low salinity with no change to the SORW post polymer. This is in-line with our expectations - we expect no change in SORW post-polymer as the conventional HPAM, which does not exhibit visco-elastic behavior, was used in the test. We demonstrate that history matching the back-produced tracer profiles is a robust approach to estimate the SORW by showing that three-or four-layer simulation model assumption does not change the SORW estimated. We accounted for the uncertainty in partition-coefficient in our uncertainty estimates. We present several innovations that improve history matching back-produced tracer profiles; hence, better SORW estimations (e.g., different level of dispersivity for individual simulation layers to account for different heterogeneity level as opposed to assuming a single dispersion for all layers). We generate more robust estimates of uncertainty by finding a range of alternative history matches all of which are consistent with the measured data.
{"title":"Improved Interpretation of Single-Well-Chemical-Tracer for Low Salinity and Polymer Flooding","authors":"A. K. N. Korrani, G. Jerauld, A. Al-Qattan","doi":"10.2118/198022-ms","DOIUrl":"https://doi.org/10.2118/198022-ms","url":null,"abstract":"\u0000 We interpreted a series of single-well-chemical-tracer-tests (SWCTTs) estimating residual oil (SORW) to base high salinity waterflood, low salinity waterflood and subsequent polymer flood conducted on a Greater Burgan well. Interpretation of the tests requires history matching of the back-production of partitioning and non-partitioning tracers which is impacted by differing amounts of irreversible flow and differing amounts of dispersion as well as the amount of residual oil.\u0000 We applied the state-of-the-art chemical reservoir simulator (UTCHEM) and an assisted history matching tool (BP’s Top-Down-Reservoir-Modeling) to interpret the tests and accurately quantify uncertainty in residual oil saturations post high salinity, low salinity, and polymer floods. Two optimization algorithms (i.e., Genetic algorithm (GA) and Particle-Swarm-Optimization (PSO)-Mesh-Adaptive-Direct-Search (MADS) algorithms) were applied to better address the uncertainty.\u0000 Our results show a six saturation unit decrease in SORW post low salinity with no change to the SORW post polymer. This is in-line with our expectations - we expect no change in SORW post-polymer as the conventional HPAM, which does not exhibit visco-elastic behavior, was used in the test. We demonstrate that history matching the back-produced tracer profiles is a robust approach to estimate the SORW by showing that three-or four-layer simulation model assumption does not change the SORW estimated. We accounted for the uncertainty in partition-coefficient in our uncertainty estimates.\u0000 We present several innovations that improve history matching back-produced tracer profiles; hence, better SORW estimations (e.g., different level of dispersivity for individual simulation layers to account for different heterogeneity level as opposed to assuming a single dispersion for all layers). We generate more robust estimates of uncertainty by finding a range of alternative history matches all of which are consistent with the measured data.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"82 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133585134","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}
Building numerical reservoir simulation model with a view to model actual case requires enormous amount of data and information. Such modeling and simulation processes normally require lengthy time and different sets of field data and experimental tests that are usually very expensive. In addition, the availability, quality and accessibility of all necessary data are very limited, especially for the green field. The degree of complexities of such modelling increases significantly especially in the case of heterogeneous nature typically inherited in unconventional reservoirs. In this perspective, this study focuses on exploring the possibility of simplifying the numerical simulation process without compromising the accuracy of results for heterogeneous unconventional tight gas reservoir with an emphasis on optimisation of multi-stage hydraulic fractured parameters, such as fracture half-length and number of fractures towards maximization the net present value (NPV). The key objectives of this study are to mitigate the effect of reservoir heterogeneity through building an equivalent simplified homogeneous reservoir simulation model for forecasting the production performance of fractured horizontal well in a heterogeneous carbonate tight gas reservoir and optimize the fracture parameters such as number of fractures and fracture half-length based on maximizing the NPV. The homogeneous model, which is equivalent to a heterogeneous reservoir model was built based on the statistical analysis of the rock properties of heterogeneous model. The simulation results obtained were analysed for a number of cases covering a range of fracture number (from 1 to 80), fracture half-length (from 500 to 2000 ft). The result demonstrated that the simplified equivalent homogeneous model has the ability to provide a good estimate for production forecasting, and determine the optimum number of fractures and fracture half-length within a high accuracy. The model is simple, yet provides good approximation with high accuracy, but save huge computation time.
{"title":"Optimization of Fracture Parameters for Hydraulic Fractured Horizontal Well in a Heterogeneous Tight Reservoir: An Equivalent Homogeneous Modelling Approach","authors":"Omar Al-Fatlawi, Mofazzal Hossain, A. Essa","doi":"10.2118/198185-ms","DOIUrl":"https://doi.org/10.2118/198185-ms","url":null,"abstract":"\u0000 Building numerical reservoir simulation model with a view to model actual case requires enormous amount of data and information. Such modeling and simulation processes normally require lengthy time and different sets of field data and experimental tests that are usually very expensive. In addition, the availability, quality and accessibility of all necessary data are very limited, especially for the green field. The degree of complexities of such modelling increases significantly especially in the case of heterogeneous nature typically inherited in unconventional reservoirs. In this perspective, this study focuses on exploring the possibility of simplifying the numerical simulation process without compromising the accuracy of results for heterogeneous unconventional tight gas reservoir with an emphasis on optimisation of multi-stage hydraulic fractured parameters, such as fracture half-length and number of fractures towards maximization the net present value (NPV).\u0000 The key objectives of this study are to mitigate the effect of reservoir heterogeneity through building an equivalent simplified homogeneous reservoir simulation model for forecasting the production performance of fractured horizontal well in a heterogeneous carbonate tight gas reservoir and optimize the fracture parameters such as number of fractures and fracture half-length based on maximizing the NPV. The homogeneous model, which is equivalent to a heterogeneous reservoir model was built based on the statistical analysis of the rock properties of heterogeneous model. The simulation results obtained were analysed for a number of cases covering a range of fracture number (from 1 to 80), fracture half-length (from 500 to 2000 ft). The result demonstrated that the simplified equivalent homogeneous model has the ability to provide a good estimate for production forecasting, and determine the optimum number of fractures and fracture half-length within a high accuracy. The model is simple, yet provides good approximation with high accuracy, but save huge computation time.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116788891","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}
C. H. Canbaz, Melek Deniz-Paker, F. Hosgor, D. Putra, Raul Moreno, C. Temizel, Ahmad Alkouh
Geochemistry is not only a well-known tool in providing a better understanding of the distribution of fluids in the reservoir rock but also an efficient kit in developing reservoir by decreasing the uncertainty throughout the characterization process. Utilizing geochemistry, not only efficiently identify the fluids and type of oil alteration drastically laterally and vertically over short distances in heavy oil reservoirs where such differences are of significant importance in production of heavy oils in these already challenging reservoirs, but also outline the value of geochemistry to justify the value of information in the process of more robust reservoir characterization and management of heavy oil reservoirs. A conceptual model representative heavy oil reservoir recovery is utilized to compare the recoveries between a case where geochemistry is applied to characterize the reservoir and another case where geochemical methods are not employed by using a full-physics commercial reservoir simulator. A sensitivity and optimization software is coupled with the reservoir simulator to outline the relative significance of the important parameters in the recovery process. Geochemical characterization, not only, provides information on gas content and its likely behavior where it can also lead to better decisions on completion strategies to avoid zones of different viscosity, but also the essential correlation between the geochemistry and the thermodynamics of heavy oil. Comprehensive reservoir characterization leads to a more robust identification of reservoir fluids where such knowledge will greatly enhance the efficiency thus the economics of the process that is especially important in low oil price environments. There is lack of studies recently on the application of geochemical characterization on the recovery of the process analyzing the relative significance of components, key drivers and the value of the information throughout the process, even though some authors have been published their research on geochemistry and its use in the characterization of the reservoirs. Our study outlines a comprehensive background including latest developments, investigates the key factors, and the value of information on comparative cases considering the relevant components of the process.
{"title":"Optimization of Development of Heavy Oil Reservoirs through Geochemical Characterization","authors":"C. H. Canbaz, Melek Deniz-Paker, F. Hosgor, D. Putra, Raul Moreno, C. Temizel, Ahmad Alkouh","doi":"10.2118/198129-ms","DOIUrl":"https://doi.org/10.2118/198129-ms","url":null,"abstract":"\u0000 Geochemistry is not only a well-known tool in providing a better understanding of the distribution of fluids in the reservoir rock but also an efficient kit in developing reservoir by decreasing the uncertainty throughout the characterization process. Utilizing geochemistry, not only efficiently identify the fluids and type of oil alteration drastically laterally and vertically over short distances in heavy oil reservoirs where such differences are of significant importance in production of heavy oils in these already challenging reservoirs, but also outline the value of geochemistry to justify the value of information in the process of more robust reservoir characterization and management of heavy oil reservoirs.\u0000 A conceptual model representative heavy oil reservoir recovery is utilized to compare the recoveries between a case where geochemistry is applied to characterize the reservoir and another case where geochemical methods are not employed by using a full-physics commercial reservoir simulator. A sensitivity and optimization software is coupled with the reservoir simulator to outline the relative significance of the important parameters in the recovery process.\u0000 Geochemical characterization, not only, provides information on gas content and its likely behavior where it can also lead to better decisions on completion strategies to avoid zones of different viscosity, but also the essential correlation between the geochemistry and the thermodynamics of heavy oil. Comprehensive reservoir characterization leads to a more robust identification of reservoir fluids where such knowledge will greatly enhance the efficiency thus the economics of the process that is especially important in low oil price environments. There is lack of studies recently on the application of geochemical characterization on the recovery of the process analyzing the relative significance of components, key drivers and the value of the information throughout the process, even though some authors have been published their research on geochemistry and its use in the characterization of the reservoirs. Our study outlines a comprehensive background including latest developments, investigates the key factors, and the value of information on comparative cases considering the relevant components of the process.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131067872","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}
L. AlAbbasi, J. G. Garcia, E. Zijlstra, M. Almatrook, A. Al-Rabah, Faisal Qureshi, Mohammad T. Al-Murayri
This paper presents the design of a polymer flood pilot in a very heterogeneous, sour Heavy Oil reservoir (referred to as HO Reservoir in this paper), which has three times the salinty of sea water with a high mineral content. In addition, the paper illustrates the methodology for the pilot design, location selection, modelling, water source selection, data acquisition plan, and polymer selection and testing. The purpose of the polymer flood pilot is to derisk a full field development plan, which aims at improving recovery by flooding processes in a shallow Heavy Oil Field with only two years of production data. The aim is to demonstrate polymer flood technical feasibility in the field and to provide data to evaluate economic viability for further expansion to full field. Therefore, the pilot had to be designed in such a way that it leads to representative results and data for the full field development and enables identification of potential risks and reduction of uncertainties. The multi-well pilot is preceded by polymer lab tests and by single-well injection testing. By a thorough field analysis including static and dynamic modelling, a pilot pattern shape and size were selected and the pilot wells were drilled last year. An extensive data acquisition plan has been made to optimize learnings from the pilot execution phase. Pressure gradients and vertical interference tests measured in open hole on the injector wells show the presence of short scale heterogeneity. This provided also learnings for the variable water cut development observed in other parts of the field. Since produced water was selected as water source for chemical EOR, another challenge that was successfully overcome was the qualification of a HPAM polymer tthat performed stably under highly saline water conditions and high dissolved H2S concentration. This was the result of a comprehensive polymer formulation laboratory program and subsequently followed by a single well chemical tracer test. Polymer flood in a highly saline, sour reservoir is unprecedented worldwide and needs careful derisking by a pilot. Using produced water instead of seawater will reduce disposal and treatment costs as well as follow KOC's environmental strategy.
{"title":"Polymer Flood Pilot Design in a Heavy Oil Field North Kuwait","authors":"L. AlAbbasi, J. G. Garcia, E. Zijlstra, M. Almatrook, A. Al-Rabah, Faisal Qureshi, Mohammad T. Al-Murayri","doi":"10.2118/198169-ms","DOIUrl":"https://doi.org/10.2118/198169-ms","url":null,"abstract":"\u0000 This paper presents the design of a polymer flood pilot in a very heterogeneous, sour Heavy Oil reservoir (referred to as HO Reservoir in this paper), which has three times the salinty of sea water with a high mineral content. In addition, the paper illustrates the methodology for the pilot design, location selection, modelling, water source selection, data acquisition plan, and polymer selection and testing.\u0000 The purpose of the polymer flood pilot is to derisk a full field development plan, which aims at improving recovery by flooding processes in a shallow Heavy Oil Field with only two years of production data. The aim is to demonstrate polymer flood technical feasibility in the field and to provide data to evaluate economic viability for further expansion to full field. Therefore, the pilot had to be designed in such a way that it leads to representative results and data for the full field development and enables identification of potential risks and reduction of uncertainties. The multi-well pilot is preceded by polymer lab tests and by single-well injection testing.\u0000 By a thorough field analysis including static and dynamic modelling, a pilot pattern shape and size were selected and the pilot wells were drilled last year. An extensive data acquisition plan has been made to optimize learnings from the pilot execution phase. Pressure gradients and vertical interference tests measured in open hole on the injector wells show the presence of short scale heterogeneity. This provided also learnings for the variable water cut development observed in other parts of the field. Since produced water was selected as water source for chemical EOR, another challenge that was successfully overcome was the qualification of a HPAM polymer tthat performed stably under highly saline water conditions and high dissolved H2S concentration. This was the result of a comprehensive polymer formulation laboratory program and subsequently followed by a single well chemical tracer test.\u0000 Polymer flood in a highly saline, sour reservoir is unprecedented worldwide and needs careful derisking by a pilot. Using produced water instead of seawater will reduce disposal and treatment costs as well as follow KOC's environmental strategy.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125003002","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}
Mohammad Al-Ghnemi, M. Al-Bahar, A. Al-Najdi, Ashish Kumar, A. Bora, T. Chandan, Jarrah Al-Ruwayeh, Malek AlSaidi, Shareefah AlRashed, AlHawraa AlOmran, B. B. Singh, Rami Kansao, M. Surendra, Sander Sucimez
Maintaining and sustaining reservoir performance and health is a priority that requires ongoing assurance activities that will maximize recovery up to industry best practices. An automated and integrated reservoir performance tool has been developed to provide high-level assurances at both the reservoir and asset level. The Reservoir Management Performance Index (RMPI) is a set of indices that can identify key performance issues involving several aspects of the reservoir'sdevelopment and operational plans. This tool identifies mitigating measures that require action, assures production sustainability, promotes a reservoir-focused organization, and standardizes the reservoir performance evaluation in an organization. RMPIprovides a high-level overview and a platform for all management and operation levels, where observing the same set of results can initiate collective decisions that improve reservoir management. Such a system was developed for a company to monitor and measure the performance against expected standards and forecasts for the large number of reservoirs in its portfolio. This tool measures multiple aspects of reservoir management grouped into four major categories: Energy Management, Forcasting Relaibility, Reserves Management and Operations. The tool is tailored to account for various aspects such as: stage of maturity of the reservoir, primary or secondary depletion stage, etc. Each category consists of multiple individual metrics that combine actual field data with targets/forecasts and use an algorithm to calculate a score. These scores are weighted and aggregated for an overall score in each category and an overall score for the asset/reservoir itself. Several aspects accounted for in the metrics include (but not limited to): pressure management, voidage replacement, water and gas management, production and injection performance, reserves promotion and replacement, current RF, EURF, drilling and workover efficiency, Well-Up time, etc.
{"title":"A New Tool for Long-Term Monitoring and Management of Kuwait Oil Company KOC Reservoirs through Reservoir Management Performance Index RMPI Concept and Best Practices","authors":"Mohammad Al-Ghnemi, M. Al-Bahar, A. Al-Najdi, Ashish Kumar, A. Bora, T. Chandan, Jarrah Al-Ruwayeh, Malek AlSaidi, Shareefah AlRashed, AlHawraa AlOmran, B. B. Singh, Rami Kansao, M. Surendra, Sander Sucimez","doi":"10.2118/198180-ms","DOIUrl":"https://doi.org/10.2118/198180-ms","url":null,"abstract":"\u0000 Maintaining and sustaining reservoir performance and health is a priority that requires ongoing assurance activities that will maximize recovery up to industry best practices. An automated and integrated reservoir performance tool has been developed to provide high-level assurances at both the reservoir and asset level. The Reservoir Management Performance Index (RMPI) is a set of indices that can identify key performance issues involving several aspects of the reservoir'sdevelopment and operational plans. This tool identifies mitigating measures that require action, assures production sustainability, promotes a reservoir-focused organization, and standardizes the reservoir performance evaluation in an organization.\u0000 RMPIprovides a high-level overview and a platform for all management and operation levels, where observing the same set of results can initiate collective decisions that improve reservoir management. Such a system was developed for a company to monitor and measure the performance against expected standards and forecasts for the large number of reservoirs in its portfolio. This tool measures multiple aspects of reservoir management grouped into four major categories: Energy Management, Forcasting Relaibility, Reserves Management and Operations.\u0000 The tool is tailored to account for various aspects such as: stage of maturity of the reservoir, primary or secondary depletion stage, etc. Each category consists of multiple individual metrics that combine actual field data with targets/forecasts and use an algorithm to calculate a score.\u0000 These scores are weighted and aggregated for an overall score in each category and an overall score for the asset/reservoir itself. Several aspects accounted for in the metrics include (but not limited to): pressure management, voidage replacement, water and gas management, production and injection performance, reserves promotion and replacement, current RF, EURF, drilling and workover efficiency, Well-Up time, etc.","PeriodicalId":282370,"journal":{"name":"Day 2 Mon, October 14, 2019","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125642995","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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