Identification of tidal channels fairways is key for predicting behavior of areas at higher risk to water breakthrough or otherwise have a significant impact on the development and monitoring of reservoir performance. However, tidal channels in carbonates are not often easily characterized using conventional seismic attributes. It is important to decipher the complexity of the carbonate tidal channel architecture with integrated multisource data and a variety of approaches. In this paper, petrological characteristics and petrographic analysis is conducted on well logs and validated carefully using core data. Then, the second step is to compare the carbonate channel systems with modern analogue in Bahama tidal flat and outcrop scales in Wadi Mi'Aidin (Northern Oman). Thereafter, the supervised probabilistic neural network (PNN) and linear regression method were undertaken to detect an additional channel distribution. The relationship of high porosity with low acoustic impedance appeared mostly in the channel facies which reflects good reservoir quality grainstone channels. Outside these channels, the rock is heavily mud filled by peritidal carbonates and characterized by a high acoustic impedance anomaly with low quality of porosity distribution. The new observation of PNN porosity volume revealed a lateral distribution of the Mishrif carbonate tidal channels in terms of paleocurrent direction and the connectivity. Additionally, the prior information from core data and the geological knowledge indicate a good consistency with classified lithology. These observations implied that Mishrif channels consist of a wide range of lithology and porotype fluctuations due to the impact of depositional environment. The work enables us to provide a new insight into the distribution of channel bodies, and petrophysical properties with quantification of their influence on dynamic reservoir behavior of the main producing reservoir. This work will not only provide an important guidance to the development and production of this case study, however also deliver an integrated work path for the similar geological and sedimentary environment in the nearby oil fields of Southern Iraq.
{"title":"Characterization of Channelized Systems in a Carbonate Platform Setting: A Case Study on the Late Cretaceous Reservoir from the Supergiant Oilfield, Iraq","authors":"A. Al-Ali, K. Stephen, Asghar Shams","doi":"10.2118/196618-ms","DOIUrl":"https://doi.org/10.2118/196618-ms","url":null,"abstract":"\u0000 Identification of tidal channels fairways is key for predicting behavior of areas at higher risk to water breakthrough or otherwise have a significant impact on the development and monitoring of reservoir performance. However, tidal channels in carbonates are not often easily characterized using conventional seismic attributes. It is important to decipher the complexity of the carbonate tidal channel architecture with integrated multisource data and a variety of approaches.\u0000 In this paper, petrological characteristics and petrographic analysis is conducted on well logs and validated carefully using core data. Then, the second step is to compare the carbonate channel systems with modern analogue in Bahama tidal flat and outcrop scales in Wadi Mi'Aidin (Northern Oman). Thereafter, the supervised probabilistic neural network (PNN) and linear regression method were undertaken to detect an additional channel distribution.\u0000 The relationship of high porosity with low acoustic impedance appeared mostly in the channel facies which reflects good reservoir quality grainstone channels. Outside these channels, the rock is heavily mud filled by peritidal carbonates and characterized by a high acoustic impedance anomaly with low quality of porosity distribution. The new observation of PNN porosity volume revealed a lateral distribution of the Mishrif carbonate tidal channels in terms of paleocurrent direction and the connectivity. Additionally, the prior information from core data and the geological knowledge indicate a good consistency with classified lithology. These observations implied that Mishrif channels consist of a wide range of lithology and porotype fluctuations due to the impact of depositional environment.\u0000 The work enables us to provide a new insight into the distribution of channel bodies, and petrophysical properties with quantification of their influence on dynamic reservoir behavior of the main producing reservoir. This work will not only provide an important guidance to the development and production of this case study, however also deliver an integrated work path for the similar geological and sedimentary environment in the nearby oil fields of Southern Iraq.","PeriodicalId":11098,"journal":{"name":"Day 2 Wed, September 18, 2019","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81023489","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}
As means of primary and secondary recovery, the fractured reservoirs with strong aquifer can be developed either by water injection or by utilizing the natural energy of the aquifer itself. High permeability contrast between fracture and matrix blocks and preferably mixed to oil-wet nature of the naturally fractured reservoirs makes waterflooding and primary methods of production mostly inefficient leaving vast amount of oil unrecovered in the oil-bearing matrix blocks. Due to the absence of a sufficient pressure gradient, wettability of the reservoir rock determines the rate of the displacing fluid invasion into the matrix blocks by capillary and gravity forces. Chemical Enhanced Oil Recovery (cEOR) mechanisms are aimed to intensify oil recovery by affecting these forces. Laboratory and field pilot tests showed the application of surfactant to be a promising cEOR agent for increasing oil recovery from the matrix blocks, both in water-wet and oil-wet fractured reservoirs. For the case studied in this paper, analysis of the surfactant application in the fractured reservoir required the solution of the following challenges: –Interpretation and reproduction of the EOR mechanisms by mathematical modelling–Adaptation and integration of the EOR effects into the full field model–Development of the proper technology for surfactant injection under the given reservoir conditions The aim of the paper is to present the discussions and the workflow for analyzing and identification of the surfactant application in the fractured reservoir with strong bottom driven aquifer. Introduction of the trapping number (accounting the capillary and Bond numbers) as a scaling parameter enabled to evaluate the combined effect of capillary, viscous and gravity forces on oil desaturation. To integrate the trapping number into commercial simulator, a special interface was developed within the scope of this work. The EOR effects of surfactant were evaluated on the single porosity numerical models representing a discretized matrix block. To upscale the specific recovery mechanism as a mass exchange term into full field dual porosity model a special coupling solution was introduced. A pseudo-capillary pressure is suggested as an intermediate function to translate the recovery mechanism from single to dual porosity model. The developed innovative technology proposes a special injection and production strategy for more effective areal sweep efficiency as well as alteration of injection water chemistry to drive the surfactant into target areas without high losses into the aquifer. This technology and the described workflow, both were employed for advanced estimation of surfactant EOR potential in a naturally fractured carbonate reservoir. The surfactant aided recovery mechanism based on transition from capillary to gravity dominated displacement showed enhanced effect on ultimate oil recovery from this reservoir.
{"title":"Evaluation of Surfactant Application to Increase Oil Recovery in Bottom Aquifer-Driven Naturally Fractured Reservoir","authors":"Samir Alakbarov, A. Behr","doi":"10.2118/196615-ms","DOIUrl":"https://doi.org/10.2118/196615-ms","url":null,"abstract":"\u0000 As means of primary and secondary recovery, the fractured reservoirs with strong aquifer can be developed either by water injection or by utilizing the natural energy of the aquifer itself. High permeability contrast between fracture and matrix blocks and preferably mixed to oil-wet nature of the naturally fractured reservoirs makes waterflooding and primary methods of production mostly inefficient leaving vast amount of oil unrecovered in the oil-bearing matrix blocks. Due to the absence of a sufficient pressure gradient, wettability of the reservoir rock determines the rate of the displacing fluid invasion into the matrix blocks by capillary and gravity forces. Chemical Enhanced Oil Recovery (cEOR) mechanisms are aimed to intensify oil recovery by affecting these forces. Laboratory and field pilot tests showed the application of surfactant to be a promising cEOR agent for increasing oil recovery from the matrix blocks, both in water-wet and oil-wet fractured reservoirs. For the case studied in this paper, analysis of the surfactant application in the fractured reservoir required the solution of the following challenges: –Interpretation and reproduction of the EOR mechanisms by mathematical modelling–Adaptation and integration of the EOR effects into the full field model–Development of the proper technology for surfactant injection under the given reservoir conditions\u0000 The aim of the paper is to present the discussions and the workflow for analyzing and identification of the surfactant application in the fractured reservoir with strong bottom driven aquifer.\u0000 Introduction of the trapping number (accounting the capillary and Bond numbers) as a scaling parameter enabled to evaluate the combined effect of capillary, viscous and gravity forces on oil desaturation. To integrate the trapping number into commercial simulator, a special interface was developed within the scope of this work. The EOR effects of surfactant were evaluated on the single porosity numerical models representing a discretized matrix block.\u0000 To upscale the specific recovery mechanism as a mass exchange term into full field dual porosity model a special coupling solution was introduced. A pseudo-capillary pressure is suggested as an intermediate function to translate the recovery mechanism from single to dual porosity model.\u0000 The developed innovative technology proposes a special injection and production strategy for more effective areal sweep efficiency as well as alteration of injection water chemistry to drive the surfactant into target areas without high losses into the aquifer.\u0000 This technology and the described workflow, both were employed for advanced estimation of surfactant EOR potential in a naturally fractured carbonate reservoir. The surfactant aided recovery mechanism based on transition from capillary to gravity dominated displacement showed enhanced effect on ultimate oil recovery from this reservoir.","PeriodicalId":11098,"journal":{"name":"Day 2 Wed, September 18, 2019","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90719050","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The identification of the fluid fill history is a necessity for the development strategy of any field, in particular in the Middle East where tectonic history is often reported to affect fluid distribution and contacts in many fields. The fluid fill concept for a low permeability carbonate field has been re-evaluated and modified from a tilted contact interpretation with imbibition of the deepest unit to a field-wide flat contact and primary drainage saturation distribution. The oil volumes in the reservoir under study are sensitive to minor changes in the structure and fluid fill due to the relatively low structural dip and low permeability transitional nature of the reservoir. The paper highlights the importance of removing preconceptions in data analysis and ensuring consistency on interpretations between different available data sources. It also demonstrates how data quality could completely change the fluid fill concept. The three main reservoir units of the Lower Shuaiba A, Lower Shuaiba B and Kharaib have been charged from two oil migration events. Structural changes post the first primary drainage are revealed by regional seismic images of the shallower horizons. Due to the rock low permeability, the water saturations are above irreducible value and the whole interval is in the "transition zone". Kharaib unit was believed to be imbibed by the aquifer after charge and was not developed. Three possible fluid fill scenarios were investigated: a) tilted contact due to structural changes post-charge, b) imbibition of the deeper interval, c) primary drainage with field-wide flat contact related to the second pulse of charge. Each scenario impacts the development of the three units positively or negatively. Water saturation logs vs. True Vertical Depth plots were the main diagnostic tool used to rule out fluid fill scenarios. The plots were used to recognise lateral changes of the saturation profile and investigate imbibition signatures. Production data were also used to cross check the expected fluid fill scenario. The resistivity tools’ types and mud resistivities were examined.
{"title":"Unlocking Development by Solving a Contacts Interpretation Mystery","authors":"S. Hadidi, M. Ferrero","doi":"10.2118/196617-ms","DOIUrl":"https://doi.org/10.2118/196617-ms","url":null,"abstract":"\u0000 The identification of the fluid fill history is a necessity for the development strategy of any field, in particular in the Middle East where tectonic history is often reported to affect fluid distribution and contacts in many fields. The fluid fill concept for a low permeability carbonate field has been re-evaluated and modified from a tilted contact interpretation with imbibition of the deepest unit to a field-wide flat contact and primary drainage saturation distribution. The oil volumes in the reservoir under study are sensitive to minor changes in the structure and fluid fill due to the relatively low structural dip and low permeability transitional nature of the reservoir. The paper highlights the importance of removing preconceptions in data analysis and ensuring consistency on interpretations between different available data sources. It also demonstrates how data quality could completely change the fluid fill concept.\u0000 The three main reservoir units of the Lower Shuaiba A, Lower Shuaiba B and Kharaib have been charged from two oil migration events. Structural changes post the first primary drainage are revealed by regional seismic images of the shallower horizons. Due to the rock low permeability, the water saturations are above irreducible value and the whole interval is in the \"transition zone\". Kharaib unit was believed to be imbibed by the aquifer after charge and was not developed. Three possible fluid fill scenarios were investigated: a) tilted contact due to structural changes post-charge, b) imbibition of the deeper interval, c) primary drainage with field-wide flat contact related to the second pulse of charge. Each scenario impacts the development of the three units positively or negatively. Water saturation logs vs. True Vertical Depth plots were the main diagnostic tool used to rule out fluid fill scenarios. The plots were used to recognise lateral changes of the saturation profile and investigate imbibition signatures. Production data were also used to cross check the expected fluid fill scenario. The resistivity tools’ types and mud resistivities were examined.","PeriodicalId":11098,"journal":{"name":"Day 2 Wed, September 18, 2019","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89831850","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}
While Image processing is still an area of research, standard workflows have emerged and are routinely used in Oil&Gas companies. However, while hardware capabilities have increased consequently, allowing large samples to be scanned with a high fidelity, permeability simulations are still limited to small samples unless having access to HPC. Direct simulations are known to be more flexible in terms of type of rocks, but limited in terms of sample size, while Pore Network Model based allow much larger sample sizes but less rock types. In this study, we will focus on the pore space analysis of a middle-eastern carbonate sample. The rock sample is 7.5 cm tall and has a diameter of 3.8 cm. It has been acquired at 3 different resolution: a microCT scan at 16μm, a microCT scan of a 10 mm of diameter subsample at 5 μm, and a 10 mm of diameter SEM section at 2μm. This study will propose a methodology to mix the different scales in order to get an accurate pore space analysis of the largest possible sample size. As micro porous regions are visible at every scale, bringing uncertainty to the segmentation step, the first part of our analysis will consist of determining the most accurate pore space at the three different resolutions. We will rely on image registration (2D to 3D and 3D to 3D) and image based upscaling methods, further validated by simulation results. Given the large numerical size of the samples, specific workflows involving large data 3D visualization and processing will be presented. Then, different measures will be conducted: porosity and connected porosity, absolute permeability with three different methods (Lattice Boltzmann, Finite Volume, Pore Network Modeling), relative permeability curves using a Pore Network Model simulator. A new pore network model generation applicable to highly concave pore spaces such as carbonates ones will also be introduced. A scalable method using automation will be presented, so that repeating the simulations on different samples of different space origins and size is easy. We will expose the results and limits of every method and will determine which size is bringing a convergence of the results. We will especially look at the convergence of direct based simulations and pore network model based ones, such that expanding the size prior to Pore Network Model generation can be reliable. In addition to the benchmark of the different simulation methods and their associated limits, the results will help us determining the representative elementary volume at different resolutions and the associated uncertainty depending on whether sub-resolution acquisitions are available or not.
{"title":"Digital Pore Space Study of a Middle-Eastern Carbonate Rock Sample","authors":"G. Tallec","doi":"10.2118/196653-ms","DOIUrl":"https://doi.org/10.2118/196653-ms","url":null,"abstract":"\u0000 \u0000 \u0000 While Image processing is still an area of research, standard workflows have emerged and are routinely used in Oil&Gas companies.\u0000 However, while hardware capabilities have increased consequently, allowing large samples to be scanned with a high fidelity, permeability simulations are still limited to small samples unless having access to HPC. Direct simulations are known to be more flexible in terms of type of rocks, but limited in terms of sample size, while Pore Network Model based allow much larger sample sizes but less rock types.\u0000 \u0000 \u0000 \u0000 In this study, we will focus on the pore space analysis of a middle-eastern carbonate sample. The rock sample is 7.5 cm tall and has a diameter of 3.8 cm.\u0000 It has been acquired at 3 different resolution: a microCT scan at 16μm, a microCT scan of a 10 mm of diameter subsample at 5 μm, and a 10 mm of diameter SEM section at 2μm.\u0000 This study will propose a methodology to mix the different scales in order to get an accurate pore space analysis of the largest possible sample size.\u0000 \u0000 \u0000 \u0000 As micro porous regions are visible at every scale, bringing uncertainty to the segmentation step, the first part of our analysis will consist of determining the most accurate pore space at the three different resolutions. We will rely on image registration (2D to 3D and 3D to 3D) and image based upscaling methods, further validated by simulation results.\u0000 Given the large numerical size of the samples, specific workflows involving large data 3D visualization and processing will be presented.\u0000 Then, different measures will be conducted: porosity and connected porosity, absolute permeability with three different methods (Lattice Boltzmann, Finite Volume, Pore Network Modeling), relative permeability curves using a Pore Network Model simulator. A new pore network model generation applicable to highly concave pore spaces such as carbonates ones will also be introduced.\u0000 \u0000 \u0000 \u0000 A scalable method using automation will be presented, so that repeating the simulations on different samples of different space origins and size is easy.\u0000 We will expose the results and limits of every method and will determine which size is bringing a convergence of the results. We will especially look at the convergence of direct based simulations and pore network model based ones, such that expanding the size prior to Pore Network Model generation can be reliable.\u0000 In addition to the benchmark of the different simulation methods and their associated limits, the results will help us determining the representative elementary volume at different resolutions and the associated uncertainty depending on whether sub-resolution acquisitions are available or not.\u0000","PeriodicalId":11098,"journal":{"name":"Day 2 Wed, September 18, 2019","volume":"116 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87766259","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}
Italo Luciani, S. Renna, Angelo Ortega, C. Catalani, Konstantinos Mastrogeorgiou, A. Cortese
3D model is a valuable tool in reservoir management, provided its representativeness of reservoir dynamics.Traditional History Match mainly focuses on reproducing reservoir behavior at well scale. A good match is not always representative of fluid movements in the reservoir. The proposed approach for 3D model validation combines and compares the results of integrated production analysis, in particular flow paths identification, with history matching by using streamlines technology. Streamlines speed up the comparison process especially in complex 3D models. The workflow is based on a massive Production Data Analysis (PDA) where geological and dynamic data are integrated to identify preferential paths followed by the different fluid phases during the producing life of the field. The main result is the Fluid Path Conceptual Model (FPCM) where aquifer and injected water movements are clearly identified. Once the flooded areas are detected, streamlines are traced on the history matched model in order to easily compare the simulated connections with hard information from PDA. Actions to improve the model representativeness are suggested and integrated in an iterative tuning process. This paper presents the results of the methodology applied on two complex fields with different injection strategies. FPCMs resulting from PDA provided a powerful boost to drive the history match and speed up the whole process. Priority was given in reproducing the identified preferential paths rather than to perfectly match well production data (which can be also affected by allocation uncertainties) by means of local unrealistic adjustments. Streamlines were run on Intersect simulation, proving to be a fast and powerful tool for the visualization and understanding of fluid movements in the 3D Model. Since streamlines are used as visualization tool and are traced on a corner point geometry grid using fluxes provided by reservoir simulation, the reliability of the simulation output is preserved. Once the model is representative of the real field behavior, it can be used as predictive tool in Reservoir Management to optimize the current injection strategy, promoting most efficient injectors.
{"title":"3D Model Validation in Reservoir Management Optimization Workflow","authors":"Italo Luciani, S. Renna, Angelo Ortega, C. Catalani, Konstantinos Mastrogeorgiou, A. Cortese","doi":"10.2118/196645-ms","DOIUrl":"https://doi.org/10.2118/196645-ms","url":null,"abstract":"\u0000 3D model is a valuable tool in reservoir management, provided its representativeness of reservoir dynamics.Traditional History Match mainly focuses on reproducing reservoir behavior at well scale. A good match is not always representative of fluid movements in the reservoir. The proposed approach for 3D model validation combines and compares the results of integrated production analysis, in particular flow paths identification, with history matching by using streamlines technology. Streamlines speed up the comparison process especially in complex 3D models.\u0000 The workflow is based on a massive Production Data Analysis (PDA) where geological and dynamic data are integrated to identify preferential paths followed by the different fluid phases during the producing life of the field. The main result is the Fluid Path Conceptual Model (FPCM) where aquifer and injected water movements are clearly identified. Once the flooded areas are detected, streamlines are traced on the history matched model in order to easily compare the simulated connections with hard information from PDA. Actions to improve the model representativeness are suggested and integrated in an iterative tuning process.\u0000 This paper presents the results of the methodology applied on two complex fields with different injection strategies. FPCMs resulting from PDA provided a powerful boost to drive the history match and speed up the whole process. Priority was given in reproducing the identified preferential paths rather than to perfectly match well production data (which can be also affected by allocation uncertainties) by means of local unrealistic adjustments.\u0000 Streamlines were run on Intersect simulation, proving to be a fast and powerful tool for the visualization and understanding of fluid movements in the 3D Model. Since streamlines are used as visualization tool and are traced on a corner point geometry grid using fluxes provided by reservoir simulation, the reliability of the simulation output is preserved.\u0000 Once the model is representative of the real field behavior, it can be used as predictive tool in Reservoir Management to optimize the current injection strategy, promoting most efficient injectors.","PeriodicalId":11098,"journal":{"name":"Day 2 Wed, September 18, 2019","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87210997","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. Saputelli, R. Celma, D. Boyd, H. Shebl, J. Gomes, Fahmi Bahrini, Alvaro Escorcia, Yogendra Pandey
Permeability and rock typing are two of the main outputs generated from the petrophysical domain and are particularly contributors to the highest degree of uncertainty during the history matching process in reservoir modeling, with the subsequent high impact in field development decisions. Detailed core analysis is the preferred main source of information to estimate permeability and to assign rock types; however, since there are generally more un-cored than cored wells, logs are the most frequently applied source of information to predict permeability and rock types in each data point of the reservoir model. The approach of this investigation is to apply data analytics and machine learning to move from the core domain to the log domain and to determine relationships to then generate properties for the three-dimensional reservoir model with proper simulation for history matching. All wells have a full set of logs (Gamma Ray, Resistivity, Density and Neutron) and few have routine core analysis (Permeability, Porosity and MICP). On a first pass, logs from selected wells are classified into Self Organizing Maps (SOM) without analytical supervision. Then, core data is used to define petrophysical groups (PG), followed by linking the PG's to NMR pore-size distribution analysis results into pre-determined standard pore geometry groups, in this step supervised PGs are generated from the log response constrained by the relationship between pore-throat geometry (MICP) and pose-size distribution (NMR). Permeability-porosity core relationships are reviewed by sorting and eliminating the outliers or inconsistent samples (damaged or chipped, fractures or with local features). After that, the supervised PGs are used to train and calibrate a supervised neural network (NN) and permeability and rock type's relationships can be captured at log scale. Using dimensionality reduction improves the neural network relationships and thus data population into the petrophysical wells. The result is a more robust model capable to capture over 80% of the core relationships and able to predict permeability and rock types while preserving the geological features of the reservoir. The application of this method makes possible to determine the relevance of core and log data sources to address rock typing and permeability prediction uncertainties. The applied workflows also show how to break the autocorrelation of variables and maximize the usage of logs. This work demonstrates that the introduced data-driven methods are useful for rock typing determination and address several of the challenges related to core to log properties derivation.
{"title":"Deriving Permeability and Reservoir Rock Typing Supported with Self-Organized Maps SOM and Artificial Neural Networks ANN - Optimal Workflow for Enabling Core-Log Integration","authors":"L. Saputelli, R. Celma, D. Boyd, H. Shebl, J. Gomes, Fahmi Bahrini, Alvaro Escorcia, Yogendra Pandey","doi":"10.2118/196704-ms","DOIUrl":"https://doi.org/10.2118/196704-ms","url":null,"abstract":"\u0000 Permeability and rock typing are two of the main outputs generated from the petrophysical domain and are particularly contributors to the highest degree of uncertainty during the history matching process in reservoir modeling, with the subsequent high impact in field development decisions. Detailed core analysis is the preferred main source of information to estimate permeability and to assign rock types; however, since there are generally more un-cored than cored wells, logs are the most frequently applied source of information to predict permeability and rock types in each data point of the reservoir model.\u0000 The approach of this investigation is to apply data analytics and machine learning to move from the core domain to the log domain and to determine relationships to then generate properties for the three-dimensional reservoir model with proper simulation for history matching. All wells have a full set of logs (Gamma Ray, Resistivity, Density and Neutron) and few have routine core analysis (Permeability, Porosity and MICP). On a first pass, logs from selected wells are classified into Self Organizing Maps (SOM) without analytical supervision. Then, core data is used to define petrophysical groups (PG), followed by linking the PG's to NMR pore-size distribution analysis results into pre-determined standard pore geometry groups, in this step supervised PGs are generated from the log response constrained by the relationship between pore-throat geometry (MICP) and pose-size distribution (NMR). Permeability-porosity core relationships are reviewed by sorting and eliminating the outliers or inconsistent samples (damaged or chipped, fractures or with local features). After that, the supervised PGs are used to train and calibrate a supervised neural network (NN) and permeability and rock type's relationships can be captured at log scale. Using dimensionality reduction improves the neural network relationships and thus data population into the petrophysical wells.\u0000 The result is a more robust model capable to capture over 80% of the core relationships and able to predict permeability and rock types while preserving the geological features of the reservoir. The application of this method makes possible to determine the relevance of core and log data sources to address rock typing and permeability prediction uncertainties. The applied workflows also show how to break the autocorrelation of variables and maximize the usage of logs.\u0000 This work demonstrates that the introduced data-driven methods are useful for rock typing determination and address several of the challenges related to core to log properties derivation.","PeriodicalId":11098,"journal":{"name":"Day 2 Wed, September 18, 2019","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89073958","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}
Most commercially available simulators use the trivial two-point flux approximation (TPFA) method for flux computation. However, the TPFA only gives consistent solutions when used for K-orthogonal grids. In general, multi-point flux approximation (MPFA) methods perform better under both heterogeneous and anisotropic conditions. The mimetic finite difference (MFD) method is designed to preserve properties on unstructured polyhedral grids, and its development for simulating full tensor permeabilities is also crucial step. This paper compares the performance, accuracy, and efficiency of these schemes for simulating complex synthetic and realistic hydrocarbon reservoirs.
{"title":"Comparing Advanced Discretization Methods for Complex Hydrocarbon Reservoirs","authors":"D. Hjeij, A. Abushaikha","doi":"10.2118/196727-ms","DOIUrl":"https://doi.org/10.2118/196727-ms","url":null,"abstract":"\u0000 Most commercially available simulators use the trivial two-point flux approximation (TPFA) method for flux computation. However, the TPFA only gives consistent solutions when used for K-orthogonal grids. In general, multi-point flux approximation (MPFA) methods perform better under both heterogeneous and anisotropic conditions. The mimetic finite difference (MFD) method is designed to preserve properties on unstructured polyhedral grids, and its development for simulating full tensor permeabilities is also crucial step. This paper compares the performance, accuracy, and efficiency of these schemes for simulating complex synthetic and realistic hydrocarbon reservoirs.","PeriodicalId":11098,"journal":{"name":"Day 2 Wed, September 18, 2019","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90871024","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}
Field presented here is located in offshore Abu Dhabi, consisting of multi-stacked reservoirs with different fluid and reservoir properties. In this paper, field development plan of one of reservoir has been presented which was initially planned to be developed with pattern water injection by more than 50 horizontal wells penetrating all the ten oil bearing layers from 9 well head towers. Reservoir consists of under-saturated oil with low gas-oil ratio and low bubble point. Initial 2 years of production was considered as Early Production Scheme (EPS period), during which significant amount of early production data consisting of downhole pressure measurement, time-lapse MDT, vertical interference data, PLT have been collected. Based on EPS data simulation model has been updated. Simulation fits well with the observed pressure gauge and time-lapse MDT data. Updated model gives good prediction for a year of blind test data (including saturation, MDT and porosity) collected from different wells several kilometers away from current development area reflecting a high level of confidence in areal and vertical connectivity representation. Considering other reservoir uncertainties different Development plans have been screened using updated model in order to improve recovery factor and economics. Based on development plan screening study, optimized development option has been chosen for Full Field Development.
{"title":"Agile Approach to Optimize Field Development Plan with Maximum Leverage of an EPS Phase Learnings in Offshore Abu Dhabi","authors":"Pawan Agrawal, Kamel Zahaf, A. Sinha, E. Draoui","doi":"10.2118/196728-ms","DOIUrl":"https://doi.org/10.2118/196728-ms","url":null,"abstract":"\u0000 Field presented here is located in offshore Abu Dhabi, consisting of multi-stacked reservoirs with different fluid and reservoir properties. In this paper, field development plan of one of reservoir has been presented which was initially planned to be developed with pattern water injection by more than 50 horizontal wells penetrating all the ten oil bearing layers from 9 well head towers. Reservoir consists of under-saturated oil with low gas-oil ratio and low bubble point.\u0000 Initial 2 years of production was considered as Early Production Scheme (EPS period), during which significant amount of early production data consisting of downhole pressure measurement, time-lapse MDT, vertical interference data, PLT have been collected. Based on EPS data simulation model has been updated. Simulation fits well with the observed pressure gauge and time-lapse MDT data. Updated model gives good prediction for a year of blind test data (including saturation, MDT and porosity) collected from different wells several kilometers away from current development area reflecting a high level of confidence in areal and vertical connectivity representation. Considering other reservoir uncertainties different Development plans have been screened using updated model in order to improve recovery factor and economics. Based on development plan screening study, optimized development option has been chosen for Full Field Development.","PeriodicalId":11098,"journal":{"name":"Day 2 Wed, September 18, 2019","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76706302","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}
Tatiana Faizova, M. Butorina, A. Goncharov, S. Nekhaev
Nowadays demand makes gas one of the desirable hydrocarbon sources of energy. However reservoirs size and quality of new discoveries or old preserved one are poor. This fact set the task for simulation of accurate prediction in order to evaluate economic reasonability of production. This study concerns the question of changes gas production profile at the gas-bearing carbonate formation due to presence of transition zone. The different ways of simulation models initialization are implemented. Then the changes of the total output are compared and analyzed. In addition the advantages of initialization by means of J-function over capillary pressure curve assignment for the carbonate formation with highly heterogeneous flowing properties are explained. All results are coupled to vertical flow performance of wells which were matched at the tests. The study shows that transition zone should be taken into account in simulation modeling of the gas-bearing no less than for the oil-bearing formations. Also the total gas production compared with and without the transition zone implementation due to its production is sensitive to presence any liquid. Accurate J-function matching at the core data provide better result for water breakthrough thus the performance of wells and finally the total production profile. The vertical flow performance curves adjustment and subsequent use for the simulation is the additional need which considered because in the case of the surface equipment restriction, such as the tubing head pressure limits, the pressure loss in the presence of gas and water mixture could be huge which cause early shutdown of the wells. It is shown that gas bearing is not the reason to neglect the importance of the capillary force and the presence of the transition zone which has essential impact on the total formation performance.
{"title":"Transition Zone Characterization for Simulation Models of Gas Bearing Carbonate Reservoir","authors":"Tatiana Faizova, M. Butorina, A. Goncharov, S. Nekhaev","doi":"10.2118/196671-ms","DOIUrl":"https://doi.org/10.2118/196671-ms","url":null,"abstract":"\u0000 Nowadays demand makes gas one of the desirable hydrocarbon sources of energy. However reservoirs size and quality of new discoveries or old preserved one are poor. This fact set the task for simulation of accurate prediction in order to evaluate economic reasonability of production.\u0000 This study concerns the question of changes gas production profile at the gas-bearing carbonate formation due to presence of transition zone. The different ways of simulation models initialization are implemented. Then the changes of the total output are compared and analyzed. In addition the advantages of initialization by means of J-function over capillary pressure curve assignment for the carbonate formation with highly heterogeneous flowing properties are explained. All results are coupled to vertical flow performance of wells which were matched at the tests.\u0000 The study shows that transition zone should be taken into account in simulation modeling of the gas-bearing no less than for the oil-bearing formations. Also the total gas production compared with and without the transition zone implementation due to its production is sensitive to presence any liquid. Accurate J-function matching at the core data provide better result for water breakthrough thus the performance of wells and finally the total production profile. The vertical flow performance curves adjustment and subsequent use for the simulation is the additional need which considered because in the case of the surface equipment restriction, such as the tubing head pressure limits, the pressure loss in the presence of gas and water mixture could be huge which cause early shutdown of the wells.\u0000 It is shown that gas bearing is not the reason to neglect the importance of the capillary force and the presence of the transition zone which has essential impact on the total formation performance.","PeriodicalId":11098,"journal":{"name":"Day 2 Wed, September 18, 2019","volume":"68 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77641544","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. Preux, I. Malinouskaya, Q. Nguyen, E. Flauraud, S. Ayache
In order to improve the oil recovery factor, many oil companies employ surfactant in injected water. On one hand, the injection of surfactant influences the interfacial tension and to a lesser extent, the mobility reduction factor. On the other hand, the efficiency of the surfactant depends strongly on the salinity and temperature conditions. In order to optimize the surfactant injection procedure, the salinity and temperature effects are commonly studied through series of laboratory experiments. However, these types of experiments are often long and expensive. Therefore, engineers use numerical simulations. The present study addresses a numerical model, which allows to take into account the modifications of the interfacial tension (IFT) and the mobility reduction factor due to the salinity and temperature variations during the surfactant injection. In this work, we propose a coupled numerical model based on five equations: i) two transport equations of water and oil phases modelized by the Darcy's law, ii) two transport equations for the surfactant and the salinity (the surfactant and the salinity are transported only in the water phase) iii) one energy conservation equation to take into account the thermal effect on surfactant flooding. The system of equations includes the salinity and the temperature impacts on the surfactant adsorption and thermal degradation, as well as the interfacial tension. Thus, this model allows improving the analysis of thermal corefloods or reservoir operations resulting from the surfactant injection. The coupled model is used to reproduce laboratory experiments based on corefloods. We analyze the interaction phenomena between the surfactant, salinity and temperature. Then, we demonstrate a competition between two phenomena: the thermal effect on the viscosity of water on one hand, and the effect of surfactant on the mobility of water on the other hand. This study highlights the efficiency of numerical simulations for the analysis and choice of the surfactant applied to the given reservoir and well conditions. Obviously, the knowledge of IFT and its dependence on surfactant concentration, salinity and temperature is not sufficient to understand all the physical mechanisms involved in a coreflood study. The phenomena are in fact extremely coupled, and the reservoir simulator coupling all these effects is found to be very helpful for engineers in order to take a good decision about the surfactant species to be used.
{"title":"Reservoir Simulation Model With Surfactant Flooding Including Salinity and Thermal Effect, Based on Laboratory Experiments","authors":"C. Preux, I. Malinouskaya, Q. Nguyen, E. Flauraud, S. Ayache","doi":"10.2118/196663-ms","DOIUrl":"https://doi.org/10.2118/196663-ms","url":null,"abstract":"In order to improve the oil recovery factor, many oil companies employ surfactant in injected water. On one hand, the injection of surfactant influences the interfacial tension and to a lesser extent, the mobility reduction factor. On the other hand, the efficiency of the surfactant depends strongly on the salinity and temperature conditions. In order to optimize the surfactant injection procedure, the salinity and temperature effects are commonly studied through series of laboratory experiments. However, these types of experiments are often long and expensive. Therefore, engineers use numerical simulations. The present study addresses a numerical model, which allows to take into account the modifications of the interfacial tension (IFT) and the mobility reduction factor due to the salinity and temperature variations during the surfactant injection. In this work, we propose a coupled numerical model based on five equations: i) two transport equations of water and oil phases modelized by the Darcy's law, ii) two transport equations for the surfactant and the salinity (the surfactant and the salinity are transported only in the water phase) iii) one energy conservation equation to take into account the thermal effect on surfactant flooding. The system of equations includes the salinity and the temperature impacts on the surfactant adsorption and thermal degradation, as well as the interfacial tension. Thus, this model allows improving the analysis of thermal corefloods or reservoir operations resulting from the surfactant injection. The coupled model is used to reproduce laboratory experiments based on corefloods. We analyze the interaction phenomena between the surfactant, salinity and temperature. Then, we demonstrate a competition between two phenomena: the thermal effect on the viscosity of water on one hand, and the effect of surfactant on the mobility of water on the other hand. This study highlights the efficiency of numerical simulations for the analysis and choice of the surfactant applied to the given reservoir and well conditions. Obviously, the knowledge of IFT and its dependence on surfactant concentration, salinity and temperature is not sufficient to understand all the physical mechanisms involved in a coreflood study. The phenomena are in fact extremely coupled, and the reservoir simulator coupling all these effects is found to be very helpful for engineers in order to take a good decision about the surfactant species to be used.","PeriodicalId":11098,"journal":{"name":"Day 2 Wed, September 18, 2019","volume":"106 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-09-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75729308","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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