Pub Date : 2019-11-18DOI: 10.3997/2214-4609.201903122
M. Pal, P. Saxena, M. Albertini, A. Kumar, P. Chenevière, P. Cordelier, C. Prinet
Summary A phased approach to screening and scaling up EOR trials for a highly complex offshore carbonate field will be presented. The phased approach taken is from screening to pilot and then continuing to a possible field implementation and is unique for the offshore field and its challenges. The cost effective means of executing the trials at different stages of the project are testament to the fact that EOR projects are possible even at low oil prices and in challenging offshore environments.
{"title":"Unlocking the Potential of a Giant Offshore Field through a Phased EOR Program and Pilot Implementation","authors":"M. Pal, P. Saxena, M. Albertini, A. Kumar, P. Chenevière, P. Cordelier, C. Prinet","doi":"10.3997/2214-4609.201903122","DOIUrl":"https://doi.org/10.3997/2214-4609.201903122","url":null,"abstract":"Summary A phased approach to screening and scaling up EOR trials for a highly complex offshore carbonate field will be presented. The phased approach taken is from screening to pilot and then continuing to a possible field implementation and is unique for the offshore field and its challenges. The cost effective means of executing the trials at different stages of the project are testament to the fact that EOR projects are possible even at low oil prices and in challenging offshore environments.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"134 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-11-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115303094","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}
Pub Date : 2019-11-18DOI: 10.3997/2214-4609.201903110
D. Guérillot, J. Bruyelle
Summary The characterization of lithofacies along wells is the first step before considering generating geological models. In this paper, a method to improve the well characterization in term of lithofacies is presented. This approach based on the relationship between capillary pressure and saturation associated with each lithofacies allows characterizing the lithofacies automatically along wells in transition zones. The saturation of fluids depends on the rock lithofacies, the fluid properties, the rock-fluid interactions, and must be calculated in order to satisfy the gravity-capillary equilibrium. From the well log data, the water saturation is assumed to be known. The aim of the method is to identify the capillary pressure curve that satisfies the calculated capillary pressure and the observed water saturation of the cells along the wells. The first step consists of calculating the pressure of each phase in the reservoir. From the pressure of each phase, the capillary pressure Pc is deduced. The lithofacies associated with the capillary pressure curve closest to the point [Sw, Pc] is assigned to the cell. An application on the Brugge Field is presented.
{"title":"Lithofacies Interpretation through Capillary Equilibrium Analysis in the Transition Zones","authors":"D. Guérillot, J. Bruyelle","doi":"10.3997/2214-4609.201903110","DOIUrl":"https://doi.org/10.3997/2214-4609.201903110","url":null,"abstract":"Summary The characterization of lithofacies along wells is the first step before considering generating geological models. In this paper, a method to improve the well characterization in term of lithofacies is presented. This approach based on the relationship between capillary pressure and saturation associated with each lithofacies allows characterizing the lithofacies automatically along wells in transition zones. The saturation of fluids depends on the rock lithofacies, the fluid properties, the rock-fluid interactions, and must be calculated in order to satisfy the gravity-capillary equilibrium. From the well log data, the water saturation is assumed to be known. The aim of the method is to identify the capillary pressure curve that satisfies the calculated capillary pressure and the observed water saturation of the cells along the wells. The first step consists of calculating the pressure of each phase in the reservoir. From the pressure of each phase, the capillary pressure Pc is deduced. The lithofacies associated with the capillary pressure curve closest to the point [Sw, Pc] is assigned to the cell. An application on the Brugge Field is presented.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-11-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123690792","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}
Pub Date : 2019-11-18DOI: 10.3997/2214-4609.201903124
M. Ghani, Nayef Alyafei, E. Elhafyan, O. Nawfal, H. Rabbani
Summary Multip[hase Flow in Porous Media Special Core Analysis Enhanced Oil Recovery Numerical Simulation
多孔介质多相流特殊岩心分析提高采收率数值模拟
{"title":"Capillary Impacts on Recovery: a Core-Scale Study to Predict Residual Oil Saturation for Altered Wettability Systems","authors":"M. Ghani, Nayef Alyafei, E. Elhafyan, O. Nawfal, H. Rabbani","doi":"10.3997/2214-4609.201903124","DOIUrl":"https://doi.org/10.3997/2214-4609.201903124","url":null,"abstract":"Summary Multip[hase Flow in Porous Media Special Core Analysis Enhanced Oil Recovery Numerical Simulation","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"82 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-11-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115724307","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}
Pub Date : 2019-11-18DOI: 10.3997/2214-4609.201903106
S. D. Hoop, D. Voskov, G. Bertotti
Summary Carbonate reservoirs host a major part of the world’s hydrocarbon reserves and over the past decade(s) have shown an increase in geothermal potential all over the world. However, naturally fractured carbonate reservoirs (NFR) contain a large uncertainty in their flow response and mechanical behavior due to the poor ability to predict the spatial distribution of discontinuity networks at reservoir-scale. In this work, we present a potential workflow for performing uncertainty quantification and data assimilation in fractured carbonate reservoirs. This workflow consists of a pre-processing step in which the original fracture network is cleaned and can be represented at the desired discretization accuracy. This method can then be used to transform a high-fidelity ensemble of models to some coarser representation. This coarser representation can be subsequently used to determine ensemble representatives. Finally, a history matching routine can be performed on each ensemble representative which characterizes the main flow patterns present in the NFR.
{"title":"Uncertainty Quantification and History Matching for Naturally Fractured Carbonate Reservoirs","authors":"S. D. Hoop, D. Voskov, G. Bertotti","doi":"10.3997/2214-4609.201903106","DOIUrl":"https://doi.org/10.3997/2214-4609.201903106","url":null,"abstract":"Summary Carbonate reservoirs host a major part of the world’s hydrocarbon reserves and over the past decade(s) have shown an increase in geothermal potential all over the world. However, naturally fractured carbonate reservoirs (NFR) contain a large uncertainty in their flow response and mechanical behavior due to the poor ability to predict the spatial distribution of discontinuity networks at reservoir-scale. In this work, we present a potential workflow for performing uncertainty quantification and data assimilation in fractured carbonate reservoirs. This workflow consists of a pre-processing step in which the original fracture network is cleaned and can be represented at the desired discretization accuracy. This method can then be used to transform a high-fidelity ensemble of models to some coarser representation. This coarser representation can be subsequently used to determine ensemble representatives. Finally, a history matching routine can be performed on each ensemble representative which characterizes the main flow patterns present in the NFR.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-11-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116935684","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}
Pub Date : 2019-11-18DOI: 10.3997/2214-4609.201903109
L. Bovet, G. Mueller, A. Vacheyrout
Summary The integration of horizontal well information is offering a unique dataset for structural calibration in Al-Shaheen field. New workflow to integrate seismic information using Depth Imaging technic show promising results as capturing geological heterogeneities in the overburden resulting in an improved structure. Better structural maps are of great interest for Al-Shaheen developpement: it ensures more realistic gelological model with less uncertainties. In particular, the identification of possible local structure that could be gas bearing.
{"title":"Structural Constraint with Integration of Horizontal Well Information and Advanced Seismic Imaging in Carbonate Environment","authors":"L. Bovet, G. Mueller, A. Vacheyrout","doi":"10.3997/2214-4609.201903109","DOIUrl":"https://doi.org/10.3997/2214-4609.201903109","url":null,"abstract":"Summary The integration of horizontal well information is offering a unique dataset for structural calibration in Al-Shaheen field. New workflow to integrate seismic information using Depth Imaging technic show promising results as capturing geological heterogeneities in the overburden resulting in an improved structure. Better structural maps are of great interest for Al-Shaheen developpement: it ensures more realistic gelological model with less uncertainties. In particular, the identification of possible local structure that could be gas bearing.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-11-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126461672","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}
Pub Date : 2019-11-18DOI: 10.3997/2214-4609.201903118
A. Vidyasagar, L. Patacchini, P. Panfili, F. Caresani, A. Cominelli, R. Gandham, K. Mukundakrishnan
Summary Simulation of carbonate fields presents challenges due to the underlying multi-scale heterogeneities and consequent stiff nature of the flow equations. This paper highlights the principles of a full-GPU (Graphics Processing Unit) reservoir simulator, currently approaching feature parity with traditional CPU-based codes. The approach exhibits fine-grained parallelism beyond that of CPU-based and hybrid CPU-GPU solutions; consequent performance improvements enable modeling of giant carbonate fields with limited computing resources. Additionally, large black-oil models are memory-bound, and GPU bandwidth has shown significant progress with every generational release of new hardware. Performance will keep improving without changes in the code base, which has not been observed with CPU codes in almost two decades. Computational performance of a full-GPU black-oil reservoir simulator is benchmarked against legacy and modern parallel CPU simulators, for two giant gas and oil carbonate reservoirs. Results for the gas reservoir indicate a ∼7.3x chip-to-chip speed improvement (one GPU vs. to 16 CPU cores), and ∼5.5x for the oil reservoir, both against the fastest reference simulator. These results suggest that full-GPU codes are ready to simulate complex carbonate models of commercial grade, with exceptional performance, which should encourage the industry to pursue research and development efforts geared towards this approach.
由于潜在的多尺度非均质性和随之而来的流动方程的刚性性质，碳酸盐岩油田的模拟面临挑战。本文重点介绍了全gpu(图形处理单元)水库模拟器的原理，该模拟器目前与传统的基于cpu的代码接近特征等值。该方法展示了超越基于cpu和混合CPU-GPU解决方案的细粒度并行性;由此带来的性能改进可以在有限的计算资源下对巨型碳酸盐岩油田进行建模。此外，大型黑油模型内存受限，GPU带宽随着新硬件的每一代发布都有显著进步。性能将在不改变代码库的情况下不断提高，这在近二十年的时间里没有在CPU代码中观察到。全gpu黑油油藏模拟器的计算性能与传统和现代并行CPU模拟器进行了基准测试，用于两个巨大的天然气和石油碳酸盐岩油藏。气藏的结果表明，芯片对芯片的速度提高了~ 7.3倍(1个GPU vs. 16个CPU内核)，油藏的速度提高了~ 5.5倍，两者都与最快的参考模拟器相比。这些结果表明，全gpu代码已经准备好模拟商业级复杂的碳酸盐模型，具有卓越的性能，这应该鼓励行业追求面向这种方法的研究和开发努力。
{"title":"Full-GPU Reservoir Simulation Delivers on its Promise for Giant Carbonate Fields","authors":"A. Vidyasagar, L. Patacchini, P. Panfili, F. Caresani, A. Cominelli, R. Gandham, K. Mukundakrishnan","doi":"10.3997/2214-4609.201903118","DOIUrl":"https://doi.org/10.3997/2214-4609.201903118","url":null,"abstract":"Summary Simulation of carbonate fields presents challenges due to the underlying multi-scale heterogeneities and consequent stiff nature of the flow equations. This paper highlights the principles of a full-GPU (Graphics Processing Unit) reservoir simulator, currently approaching feature parity with traditional CPU-based codes. The approach exhibits fine-grained parallelism beyond that of CPU-based and hybrid CPU-GPU solutions; consequent performance improvements enable modeling of giant carbonate fields with limited computing resources. Additionally, large black-oil models are memory-bound, and GPU bandwidth has shown significant progress with every generational release of new hardware. Performance will keep improving without changes in the code base, which has not been observed with CPU codes in almost two decades. Computational performance of a full-GPU black-oil reservoir simulator is benchmarked against legacy and modern parallel CPU simulators, for two giant gas and oil carbonate reservoirs. Results for the gas reservoir indicate a ∼7.3x chip-to-chip speed improvement (one GPU vs. to 16 CPU cores), and ∼5.5x for the oil reservoir, both against the fastest reference simulator. These results suggest that full-GPU codes are ready to simulate complex carbonate models of commercial grade, with exceptional performance, which should encourage the industry to pursue research and development efforts geared towards this approach.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"96 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-11-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122510355","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}
Pub Date : 2019-11-18DOI: 10.3997/2214-4609.201903115
Z. Jarrar, R. Al-Raoush, K. Alshibli, J. Hannun, Jongwon Jung
Summary Availability of natural hydrates and ongoing rise in demand for energy, motivated researchers to consider hydrates as a potential energy source. Prior to gas production operations from hydrate-bearing sediments, hydrate dissociation is required to release gas into sediments. To reliably predict natural hydrate reservoir gas production potential, a better understanding of hydrate dissociation kinetics is needed. Hydrate dissociation models assume the relationship between hydrate surface area and (hydrate volume)2/3 to be linear due to hydrate sphericity assumptions. This paper investigates the validity of the spherical hydrate assumption using in-situ three-dimensional (3D) imaging of Xenon (Xe) hydrate dissociation in porous media with dynamic 3D synchrotron microcomputed tomography (SMT). Xe hydrate was formed inside a high-pressure, low-temperature cell and then dissociated by depressurization. During dissociation, full 3D SMT scans were acquired continuously and reconstructed into 3D volume images. A combination of cementing, pore-filling, and surface coating pore-habits were observed in the specimen. It was shown that hydrate surface area can be estimated using a linear relationship with (hydrate volume)2/3 during hydrate dissociation in porous media based on direct observations and measurements from 3D SMT images.
{"title":"Hydrate Surface Area Measurements During Dissociation Using Dynamic 3D Synchrotron Computed Tomography","authors":"Z. Jarrar, R. Al-Raoush, K. Alshibli, J. Hannun, Jongwon Jung","doi":"10.3997/2214-4609.201903115","DOIUrl":"https://doi.org/10.3997/2214-4609.201903115","url":null,"abstract":"Summary Availability of natural hydrates and ongoing rise in demand for energy, motivated researchers to consider hydrates as a potential energy source. Prior to gas production operations from hydrate-bearing sediments, hydrate dissociation is required to release gas into sediments. To reliably predict natural hydrate reservoir gas production potential, a better understanding of hydrate dissociation kinetics is needed. Hydrate dissociation models assume the relationship between hydrate surface area and (hydrate volume)2/3 to be linear due to hydrate sphericity assumptions. This paper investigates the validity of the spherical hydrate assumption using in-situ three-dimensional (3D) imaging of Xenon (Xe) hydrate dissociation in porous media with dynamic 3D synchrotron microcomputed tomography (SMT). Xe hydrate was formed inside a high-pressure, low-temperature cell and then dissociated by depressurization. During dissociation, full 3D SMT scans were acquired continuously and reconstructed into 3D volume images. A combination of cementing, pore-filling, and surface coating pore-habits were observed in the specimen. It was shown that hydrate surface area can be estimated using a linear relationship with (hydrate volume)2/3 during hydrate dissociation in porous media based on direct observations and measurements from 3D SMT images.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"386 2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-11-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133028442","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}
Pub Date : 2019-11-18DOI: 10.3997/2214-4609.201903112
A. Shahin, M. Myers, L. Hathon
Summary Very often rock physics modeling and formation evaluation are treated as independent tasks. This is attributed to several causes: lack of communication between petrophysicists and seismic analysts (organizational silos), insistence on using simple linear or quasi-linear models in well log interpretation, and lack of core and fluid samples to provide calibrated rock matrix and fluid properties such as salinity, critical porosity, Archie’s parameters, etc. The proposed multiphysics modeling and inversion algorithm will make use of conventional well logs (sonic, density, and resistivity) to invert for pore-type, porosity, saturation, rock matrix properties, salinity, and other model parameters. The developed multiphysics rock models will assist petrophysicists and seismic analysts to identify and distinguish carbonate’s facies characteristics from well log and pre-stack seismic data.
{"title":"Deciphering Dual Porosity Carbonates Using Multiphysics Modeling and Inversion","authors":"A. Shahin, M. Myers, L. Hathon","doi":"10.3997/2214-4609.201903112","DOIUrl":"https://doi.org/10.3997/2214-4609.201903112","url":null,"abstract":"Summary Very often rock physics modeling and formation evaluation are treated as independent tasks. This is attributed to several causes: lack of communication between petrophysicists and seismic analysts (organizational silos), insistence on using simple linear or quasi-linear models in well log interpretation, and lack of core and fluid samples to provide calibrated rock matrix and fluid properties such as salinity, critical porosity, Archie’s parameters, etc. The proposed multiphysics modeling and inversion algorithm will make use of conventional well logs (sonic, density, and resistivity) to invert for pore-type, porosity, saturation, rock matrix properties, salinity, and other model parameters. The developed multiphysics rock models will assist petrophysicists and seismic analysts to identify and distinguish carbonate’s facies characteristics from well log and pre-stack seismic data.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"73 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-11-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114273509","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}
Pub Date : 2019-11-18DOI: 10.3997/2214-4609.201903113
V. Franzi, C. Robert, A. Shoeibi, R. Galimberti, E. Mahbou, B. Zupinov, B. Lambert, F. Bouasla, S. Hamdidouche, M. Kallel
Summary The giant Al Shaheen oil field, located within the Qatar Arch, exhibits variation in reservoir fluid properties, for example the oil API gravity ranges from 15° to 35°. The cause of the variability in oil density is believed to be due to multiple charges events ( E.Hoch et al, 2010 ), and the subtle bacterial alteration ( L.M.Wenger et al, 2002 ). Nowadays the field development is challenged to lower quality reservoirs units and in such condition a continuous information of hydrocarbon fluid quality is required. An example of application in a horizontal well drilled in the Mauddud Formation proves that the monitoring in near real-time of a series of molecular parameters enables the observations of oil quality variations along the well bore. In the future, the information supplied by the advanced mudlogging could evolve in a more detailed API gravity model, applicable to Al Shaheen field, provided by a sufficient number of downhole fluid samples. In any case the methodology, also thanks to its synergy and complementarity with LWD, offers a unique data set for geological interpretation and can give a fundamental contribution to the improvement of fluid sampling program and, ultimately, to a reduction of the costs for downhole sampling.
Al Shaheen大油田位于卡塔尔拱门内，其油藏流体性质变化很大，例如原油API度在15°到35°之间。油层密度变化的原因被认为是多重电荷事件(E.Hoch et al .， 2010)和微妙的细菌改变(L.M.Wenger et al .， 2002)。目前油田开发面临着低质量储层单元的挑战，在这种情况下，需要连续的油气流体质量信息。在Mauddud地层水平井中的应用实例证明，通过对一系列分子参数的近实时监测，可以观察到沿井筒的油质变化。在未来，先进的泥浆测井提供的信息可以发展为更详细的API重力模型，适用于Al Shaheen油田，由足够数量的井下流体样本提供。在任何情况下，由于该方法与随钻测井的协同作用和互补性，为地质解释提供了独特的数据集，可以为改进流体采样程序做出根本性贡献，并最终降低井下采样成本。
{"title":"Towards a Continuous Near-Real Time Reservoir Fluid Characterization by the Implementation of Advanced Mud Logging Technology","authors":"V. Franzi, C. Robert, A. Shoeibi, R. Galimberti, E. Mahbou, B. Zupinov, B. Lambert, F. Bouasla, S. Hamdidouche, M. Kallel","doi":"10.3997/2214-4609.201903113","DOIUrl":"https://doi.org/10.3997/2214-4609.201903113","url":null,"abstract":"Summary The giant Al Shaheen oil field, located within the Qatar Arch, exhibits variation in reservoir fluid properties, for example the oil API gravity ranges from 15° to 35°. The cause of the variability in oil density is believed to be due to multiple charges events ( E.Hoch et al, 2010 ), and the subtle bacterial alteration ( L.M.Wenger et al, 2002 ). Nowadays the field development is challenged to lower quality reservoirs units and in such condition a continuous information of hydrocarbon fluid quality is required. An example of application in a horizontal well drilled in the Mauddud Formation proves that the monitoring in near real-time of a series of molecular parameters enables the observations of oil quality variations along the well bore. In the future, the information supplied by the advanced mudlogging could evolve in a more detailed API gravity model, applicable to Al Shaheen field, provided by a sufficient number of downhole fluid samples. In any case the methodology, also thanks to its synergy and complementarity with LWD, offers a unique data set for geological interpretation and can give a fundamental contribution to the improvement of fluid sampling program and, ultimately, to a reduction of the costs for downhole sampling.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"37 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-11-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133883285","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}
Pub Date : 2019-11-18DOI: 10.3997/2214-4609.201903125
Fethi Elarouci, S. Smith, A. Mohamed Iguer
Summary An integrated approach was performed to determine the possible causes of permeability mismatch between cores, logs, wireline formation testers and production tests in this field. Based on logs and core data, the reservoir was subdivided into different layers and further refined using permeability indices from NMR logs. Formation testers with advance measurements were used to evaluate effective vertical and horizontal permeability of a single layer. The production testing covering several layers was used to fine-tune subzone permeability and subsequent flow units. The results from this study show that permeability given by CCA was somewhat misleading due to physical limitations from core plugging. The detailed core description and well-test data indicate that a significant portion of flow passes through high-permeability (vuggy) sections of the formation that cannot be measured by plugs. A formation tester was applied to check vertical and horizontal permeability in one productive zone.
{"title":"The Challenge of Carbonate Permeability Characterization: Off Shore Abu Dhabi Field Case Study","authors":"Fethi Elarouci, S. Smith, A. Mohamed Iguer","doi":"10.3997/2214-4609.201903125","DOIUrl":"https://doi.org/10.3997/2214-4609.201903125","url":null,"abstract":"Summary An integrated approach was performed to determine the possible causes of permeability mismatch between cores, logs, wireline formation testers and production tests in this field. Based on logs and core data, the reservoir was subdivided into different layers and further refined using permeability indices from NMR logs. Formation testers with advance measurements were used to evaluate effective vertical and horizontal permeability of a single layer. The production testing covering several layers was used to fine-tune subzone permeability and subsequent flow units. The results from this study show that permeability given by CCA was somewhat misleading due to physical limitations from core plugging. The detailed core description and well-test data indicate that a significant portion of flow passes through high-permeability (vuggy) sections of the formation that cannot be measured by plugs. A formation tester was applied to check vertical and horizontal permeability in one productive zone.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-11-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133486672","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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