Pub Date : 2019-11-18DOI: 10.3997/2214-4609.201903127
A. Alhammadi, A. AlMershed, H. Al-Khateeb, D. Tiwary, N. Kerrouche, R. Bouchou
Summary Far and near wellbore natural fracture systems characterization is key element for the successful exploitation of tight reservoirs, where one of the dominant aspects is permeability. Carbonate reservoirs fracture evaluation is a challenge in terms of type, density, aperture and extension. Borehole image logs, Stoneley permeability analysis, acoustic fracture ID and azimuthal shear-wave anisotropy evaluation from cross-dipole are key technologies in this context. They allow identification of individual fractures and provide information on fracture type, orientation, distribution (fracture density), aperture, permeability and extension. However, the meaning of features observed on image logs is a matter of interpretation at the borehole wall only. This introduces a degree of uncertainty, which may be greatly reduced by integrating other acquired measurements such as acoustic logs, which map the near borehole environment for fractures as well as their extension nature far away from the borehole. Therefore, integration of the two sources of information significantly enhances the benefits of both. While this principle is not new, technological advances in tool design and analysis software capabilities continuously expands the amount of detail that can be obtained.
{"title":"Far and Near Wellbore Fracture Characterization Using High Resolution Borehole Images and Acoustic Imaging","authors":"A. Alhammadi, A. AlMershed, H. Al-Khateeb, D. Tiwary, N. Kerrouche, R. Bouchou","doi":"10.3997/2214-4609.201903127","DOIUrl":"https://doi.org/10.3997/2214-4609.201903127","url":null,"abstract":"Summary Far and near wellbore natural fracture systems characterization is key element for the successful exploitation of tight reservoirs, where one of the dominant aspects is permeability. Carbonate reservoirs fracture evaluation is a challenge in terms of type, density, aperture and extension. Borehole image logs, Stoneley permeability analysis, acoustic fracture ID and azimuthal shear-wave anisotropy evaluation from cross-dipole are key technologies in this context. They allow identification of individual fractures and provide information on fracture type, orientation, distribution (fracture density), aperture, permeability and extension. However, the meaning of features observed on image logs is a matter of interpretation at the borehole wall only. This introduces a degree of uncertainty, which may be greatly reduced by integrating other acquired measurements such as acoustic logs, which map the near borehole environment for fractures as well as their extension nature far away from the borehole. Therefore, integration of the two sources of information significantly enhances the benefits of both. While this principle is not new, technological advances in tool design and analysis software capabilities continuously expands the amount of detail that can be obtained.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"54 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":"115435501","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: 10.3997/2214-4609.201903126
S. Al-jazzaf
Summary The complexity and heterogeneity of the thin, tight Mauddud carbonate in the Greater Burgan Field makes it challenging to characterize and develop this formation. In the study reported here, we have taken advantage of substantial advances in production data analysis and oil fingerprinting technology to conduct a more advanced reservoir analysis. The Mauddud carbonate reservoir is sandwiched between two massive clastic reservoirs, the Wara and the Burgan. The formation is mostly composed of calcarenitic limestone with intervals of 5–10 feet of good oil reservoir. Average porosity is 18% with low permeability ranging from 1 to 10 mD, characteristics which made this reservoir a candidate for horizontal drilling. However past production results have varied significantly among wells, a fact which previously raised the concern that perhaps the well paths of some lateral wells in this carbonate may be inadvertently tagging the adjacent, more permeable, clastic reservoirs. If that were the case, then production from the adjacent clastic reservoir could be augmenting the production from some of the wells intended to be completed solely in the carbonate. Considered in total, the results from previous development strategies for this reservoir did not meet expectations.
{"title":"Characterizing Flow from Thin Carbonate Formation Integration of Oil Finger Print and Dynamic Data","authors":"S. Al-jazzaf","doi":"10.3997/2214-4609.201903126","DOIUrl":"https://doi.org/10.3997/2214-4609.201903126","url":null,"abstract":"Summary The complexity and heterogeneity of the thin, tight Mauddud carbonate in the Greater Burgan Field makes it challenging to characterize and develop this formation. In the study reported here, we have taken advantage of substantial advances in production data analysis and oil fingerprinting technology to conduct a more advanced reservoir analysis. The Mauddud carbonate reservoir is sandwiched between two massive clastic reservoirs, the Wara and the Burgan. The formation is mostly composed of calcarenitic limestone with intervals of 5–10 feet of good oil reservoir. Average porosity is 18% with low permeability ranging from 1 to 10 mD, characteristics which made this reservoir a candidate for horizontal drilling. However past production results have varied significantly among wells, a fact which previously raised the concern that perhaps the well paths of some lateral wells in this carbonate may be inadvertently tagging the adjacent, more permeable, clastic reservoirs. If that were the case, then production from the adjacent clastic reservoir could be augmenting the production from some of the wells intended to be completed solely in the carbonate. Considered in total, the results from previous development strategies for this reservoir did not meet expectations.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"1 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":"130896909","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: 10.3997/2214-4609.201903114
C. Perrin, N. Sultana, E. Mahbou, M. Pal, B. Marir
Summary We present how a comprehensive geological study helped in the understanding the distribution of the heterogeneity in the example of a nodular facies. The result of an in-house workflow based on core CT-scan information provided quantification of the heterogeneities. These results are used to show that oil can still flow, even when logs indicate high water saturation values. The results anticipated by the method were confirmed by well tests.
{"title":"Quantification of Sublog Heterogeneities and Implication for Optimizing Well Injectivity - Example of a Carbonate Nodular Fabric","authors":"C. Perrin, N. Sultana, E. Mahbou, M. Pal, B. Marir","doi":"10.3997/2214-4609.201903114","DOIUrl":"https://doi.org/10.3997/2214-4609.201903114","url":null,"abstract":"Summary We present how a comprehensive geological study helped in the understanding the distribution of the heterogeneity in the example of a nodular facies. The result of an in-house workflow based on core CT-scan information provided quantification of the heterogeneities. These results are used to show that oil can still flow, even when logs indicate high water saturation values. The results anticipated by the method were confirmed by well tests.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"68 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":"114505902","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: 10.3997/2214-4609.201910004
W. Saleh, T. Sager, M. Altownsi
Summary The Garian reservoir is a low porosity, low permeability, locally fractured carbonate reservoir consisting mainly from limestones and dolomites. Log water saturation throughout the reservoir is highly uncertain and does not compare well with core water saturation. It is thought that the resistivity measurements conducted on few plugs cut from the first well drilled and used for evaluation are not adequate, and that the derived Archie parameters are somehow biased. It is necessary, therefore, that new resistivity measurements are acquired from a different well to calibrate and improve log water saturation. However, all fresh plugs cut from the newly drilled wells have been damaged and only plugs from a well drilled in 2008 are available. The main objective of this work is to check whether the plugs stored from the well drilled in 2008 are still fit for resistivity measurements (by comparing 2008 CCA data with the newly acquired ones), and if so, perform resistivity measurements at reservoir conditions, derive new Archie parameters and use it to see if log water saturation can be calibrated and/or improved.
{"title":"New Insights from 10-Years-Stored Plugs Improve Log Water Saturation Estimation in a Tight Carbonates in Libya","authors":"W. Saleh, T. Sager, M. Altownsi","doi":"10.3997/2214-4609.201910004","DOIUrl":"https://doi.org/10.3997/2214-4609.201910004","url":null,"abstract":"Summary The Garian reservoir is a low porosity, low permeability, locally fractured carbonate reservoir consisting mainly from limestones and dolomites. Log water saturation throughout the reservoir is highly uncertain and does not compare well with core water saturation. It is thought that the resistivity measurements conducted on few plugs cut from the first well drilled and used for evaluation are not adequate, and that the derived Archie parameters are somehow biased. It is necessary, therefore, that new resistivity measurements are acquired from a different well to calibrate and improve log water saturation. However, all fresh plugs cut from the newly drilled wells have been damaged and only plugs from a well drilled in 2008 are available. The main objective of this work is to check whether the plugs stored from the well drilled in 2008 are still fit for resistivity measurements (by comparing 2008 CCA data with the newly acquired ones), and if so, perform resistivity measurements at reservoir conditions, derive new Archie parameters and use it to see if log water saturation can be calibrated and/or improved.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"20 16 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":"116718545","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: 10.3997/2214-4609.201903117
S. Nardean, A. Abushaikha, M. Ferronato
Summary The need of a reliable solution to large numerical models poses an issue regarding the efficiency of the employed linear solver, both in terms of accuracy and computational cost. In this work, we present an analysis on the performance of two families of block preconditioners, properly designed to handle the linearized system of equations that arises from the discretization of flow problems in reservoirs by means of the Mimetic Finite Difference Method.
{"title":"A Block Preconditioning Framework for the Efficient Solution of Flow Simulations in Hydrocarbon Reservoirs","authors":"S. Nardean, A. Abushaikha, M. Ferronato","doi":"10.3997/2214-4609.201903117","DOIUrl":"https://doi.org/10.3997/2214-4609.201903117","url":null,"abstract":"Summary The need of a reliable solution to large numerical models poses an issue regarding the efficiency of the employed linear solver, both in terms of accuracy and computational cost. In this work, we present an analysis on the performance of two families of block preconditioners, properly designed to handle the linearized system of equations that arises from the discretization of flow problems in reservoirs by means of the Mimetic Finite Difference Method.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"119 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":"123473040","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: 10.3997/2214-4609.201903120
A. S. Abd, N. Zhang, A. Abushaikha
Summary Naturally fractured reservoirs (NFR’s) present complex physical flow conditions and form the vast majority of oil and gas reserves in the world, and exhibit complex flow regimes that prove to be challenging in reservoir modelling. In this work, we present the efficiency of utilizing a Mimetic Finite Difference based simulator for discrete fractures to predict hydrocarbon recovery when full tensor permeability is used. The results shed the light on the importance of mapping and realistically representing the highly heterogeneous porous media in the reservoir simulation using full tensor permeability. The orientation of the tensor will help accurately mimic the field conditions for oil flow. Moreover, this approach is powerful and can yield accurate results for hydrocarbon recovery, yet needs to be treated with care. The choice of the rotation axis and the angle for the full tensor permeability construction will greatly affect the flow in fractures and will result in early water breakthrough times in some cases.
{"title":"Modelling Full Tensor Permeability in Fractured Carbonates Using Advanced Discretization Schemes","authors":"A. S. Abd, N. Zhang, A. Abushaikha","doi":"10.3997/2214-4609.201903120","DOIUrl":"https://doi.org/10.3997/2214-4609.201903120","url":null,"abstract":"Summary Naturally fractured reservoirs (NFR’s) present complex physical flow conditions and form the vast majority of oil and gas reserves in the world, and exhibit complex flow regimes that prove to be challenging in reservoir modelling. In this work, we present the efficiency of utilizing a Mimetic Finite Difference based simulator for discrete fractures to predict hydrocarbon recovery when full tensor permeability is used. The results shed the light on the importance of mapping and realistically representing the highly heterogeneous porous media in the reservoir simulation using full tensor permeability. The orientation of the tensor will help accurately mimic the field conditions for oil flow. Moreover, this approach is powerful and can yield accurate results for hydrocarbon recovery, yet needs to be treated with care. The choice of the rotation axis and the angle for the full tensor permeability construction will greatly affect the flow in fractures and will result in early water breakthrough times in some cases.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"06 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":"129451621","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: 10.3997/2214-4609.201903119
L. Li, A. Abushaikha
Summary In this work, we develop an advancing parallel framework which is flexible for structured grids, unstructured grids, two point flux approximation (TPFA), multiple point flux approximation (MPFA) and full tensor permeability.
{"title":"Development of an Advancing Parallel Framework for Reservoir Simulation","authors":"L. Li, A. Abushaikha","doi":"10.3997/2214-4609.201903119","DOIUrl":"https://doi.org/10.3997/2214-4609.201903119","url":null,"abstract":"Summary In this work, we develop an advancing parallel framework which is flexible for structured grids, unstructured grids, two point flux approximation (TPFA), multiple point flux approximation (MPFA) and full tensor permeability.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"14 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":"116046361","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: 10.3997/2214-4609.201903116
J. Hannun, R. Al-Raoush, Z. Jarrar, K. Alshibli, Jongwon Jung
Summary Carbon sequestration in geological formations is in demand for many applications, especially energy production from hydrates. During gas production in a sandy hydrate reservoir, two phase flow and changes in confinement takes place. Nine fully saturated sand systems were scanned three times; before, during and after CO2 gas injection. The confinement pressure was altered, by placing a vertical spring that presses against the upper port of the sediment cylinder. 3D images were analyzed by direct visualization, followed by quantification and pore network analysis. Outcomes demonstrated that shape of sand particles affects how the unconsolidated media will impact the flow, in angular sediments with high confinement pressure, there is more friction between the grains, this results in no dislocations of sand, the fines clog the throats, and more formation damage is noted. In rounded grains with lower confinement pressure, sand grains dislocated; opening large pathways for gas flow; this resulted in lower formation damage. Measures done using pore networks, showed that because of micro-fractures, permeability of the system can increase during hydrate production. This is in contrast to the other systems, where throat sizes shrunk, decreasing the permeability; because of fines migration toward the throats and the small sand grains dislocations.
{"title":"Pore Networks to Characterize Formation Damage Due to Fines at Varied Confinement and Sand Shape","authors":"J. Hannun, R. Al-Raoush, Z. Jarrar, K. Alshibli, Jongwon Jung","doi":"10.3997/2214-4609.201903116","DOIUrl":"https://doi.org/10.3997/2214-4609.201903116","url":null,"abstract":"Summary Carbon sequestration in geological formations is in demand for many applications, especially energy production from hydrates. During gas production in a sandy hydrate reservoir, two phase flow and changes in confinement takes place. Nine fully saturated sand systems were scanned three times; before, during and after CO2 gas injection. The confinement pressure was altered, by placing a vertical spring that presses against the upper port of the sediment cylinder. 3D images were analyzed by direct visualization, followed by quantification and pore network analysis. Outcomes demonstrated that shape of sand particles affects how the unconsolidated media will impact the flow, in angular sediments with high confinement pressure, there is more friction between the grains, this results in no dislocations of sand, the fines clog the throats, and more formation damage is noted. In rounded grains with lower confinement pressure, sand grains dislocated; opening large pathways for gas flow; this resulted in lower formation damage. Measures done using pore networks, showed that because of micro-fractures, permeability of the system can increase during hydrate production. This is in contrast to the other systems, where throat sizes shrunk, decreasing the permeability; because of fines migration toward the throats and the small sand grains dislocations.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"25 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":"131646521","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: 10.3997/2214-4609.201903108
S. Finlay, A. Abu El Fotoh, C. Maeso
Summary Carbonate reservoirs commonly exhibit a variety of heterogeneities that can complicate ERD waterflood developments. One such heterogeneity that is commonly observed in carbonate reservoirs is the occurrence of diagenesis where varying degrees of cementation and dissolution can result in complex pore throat systems with varying proportions of primary and secondary porosities. The variability in pore throat systems can result in large variations in permeability and therefore have significant impact on the success of a waterflood development. Therefore characterizing the type of porosity and quantifying the types of porosity observed in the reservoir can lead to significant improvements in permeability prediction, reservoir characterisation and reservoir performance. Classical methods of porosity evaluation through traditional resistivity and neutron-density logs usually lack the vertical and azimuthal resolution to address such complexities in the internal rock fabric variability, and therefore accurate permeability predictions and reconciliation with production data remain elusive. In this case study we present the application of a revisited methodology for the characterisation and quantification of porosity types in heterogeneous reservoirs using borehole images, and whole core CT-Scans. The strength of the study is the iterative approach across multiple cored wells with advanced data acquisition, improving the confidence of propagation to uncored wells.
{"title":"An Image Is Still Worth a Thousand Words: Heterogeneity Analysis Using Electrical Images, CT-Scans and a Revisited Methodology","authors":"S. Finlay, A. Abu El Fotoh, C. Maeso","doi":"10.3997/2214-4609.201903108","DOIUrl":"https://doi.org/10.3997/2214-4609.201903108","url":null,"abstract":"Summary Carbonate reservoirs commonly exhibit a variety of heterogeneities that can complicate ERD waterflood developments. One such heterogeneity that is commonly observed in carbonate reservoirs is the occurrence of diagenesis where varying degrees of cementation and dissolution can result in complex pore throat systems with varying proportions of primary and secondary porosities. The variability in pore throat systems can result in large variations in permeability and therefore have significant impact on the success of a waterflood development. Therefore characterizing the type of porosity and quantifying the types of porosity observed in the reservoir can lead to significant improvements in permeability prediction, reservoir characterisation and reservoir performance. Classical methods of porosity evaluation through traditional resistivity and neutron-density logs usually lack the vertical and azimuthal resolution to address such complexities in the internal rock fabric variability, and therefore accurate permeability predictions and reconciliation with production data remain elusive. In this case study we present the application of a revisited methodology for the characterisation and quantification of porosity types in heterogeneous reservoirs using borehole images, and whole core CT-Scans. The strength of the study is the iterative approach across multiple cored wells with advanced data acquisition, improving the confidence of propagation to uncored wells.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"49 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":"133109748","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: 10.3997/2214-4609.201903123
P. Patil, M. Taha, O. M’Marki, M. Pal, A. Kumar, Q. Nguyen
Summary A complete laboratory plan is devised to identify the best surfactant formulation, that is, one that shows low adsorption, good aqueous stability at reservoir conditions, and strong foam stability with variations in foam quality, capillary number, water saturation, and oil saturation. We also evaluated surfactant or formulations for hybrid approach where one can create a foam to control conformance and also alter the wettability of the rock from oil-wet to water-wet to enhance foam transport by changing pore wettability to water-wet. The objective of this work is to generate a laboratory data to estimate parameters of a foam model which can then be used to simulate and predict foam performance in reservoir scale simulations. Such a predictive foam model then can be used to optimize injection strategy for implementing foam technology in the field. In this report we will present the initial phase of the experimental work used in identifying the suitable surfactant.
{"title":"Foam Assisted Conformance Control for Offshore Al-Shaheen Field","authors":"P. Patil, M. Taha, O. M’Marki, M. Pal, A. Kumar, Q. Nguyen","doi":"10.3997/2214-4609.201903123","DOIUrl":"https://doi.org/10.3997/2214-4609.201903123","url":null,"abstract":"Summary A complete laboratory plan is devised to identify the best surfactant formulation, that is, one that shows low adsorption, good aqueous stability at reservoir conditions, and strong foam stability with variations in foam quality, capillary number, water saturation, and oil saturation. We also evaluated surfactant or formulations for hybrid approach where one can create a foam to control conformance and also alter the wettability of the rock from oil-wet to water-wet to enhance foam transport by changing pore wettability to water-wet. The objective of this work is to generate a laboratory data to estimate parameters of a foam model which can then be used to simulate and predict foam performance in reservoir scale simulations. Such a predictive foam model then can be used to optimize injection strategy for implementing foam technology in the field. In this report we will present the initial phase of the experimental work used in identifying the suitable surfactant.","PeriodicalId":237705,"journal":{"name":"Third EAGE WIPIC Workshop: Reservoir Management in Carbonates","volume":"32 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":"132128782","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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