Development wells are drilled for different purposes that varies based on the business needs. Some scenarios can be for flowing production, power water injector, gas, or to monitor the performance of a well. Coupled with the technology in wellbore drilling activity and the artifacts that are required for the workflow approval. Through evolving technology, the system captures every step of wellbore activity to address the business needs and streamline the approval process. Data fuels Industry Revolution (IR) 4.0 and effective data analytics is the prerequisite for successful implementation of digital enterprise applications. Well approval is an in-house developed system embedded in Petrel application for reservoir characterization geologists. It standardizes well approval documents across the organization. The geologists may generate multiple well approval documents in case a change in the plan has occurred. Different scenarios require geologists to replace the plan that reflects the well approval document. Planning is the main pillar in the process of Well Approval, and automating the planning part simplifies the well approval process. The system automates the generation of three critical documents. First, Integrated Requirements (IRs), which consists of logging and threshold values for each hole section generates the reservoir amplitude impedance and porosity maps, and finally allows the geologist to capture seismic maps from 3D geological models. Second, Prognosis geological horizons details. Third, Location Evaluation. The backbone of this system is that it is integrated with different back-end systems such as corporate database, Petrel, Openwork and Geolog. In addition, geologists are not required to select the offset wells. The offset wells algorithm designates the wells for geologies based on specific criteria that is built in the system such as reservoir type and dynamic log selection. The system tackles both environments 2D and 3D based on the giving parameters such as facie. The system is able to detect the environment and prepare the documents accordingly. Since the system is aligned with the business pattern for well approval process, it significantly improves the time required to create these documents from two to three (2-3) days to less than 1 hour (90%) and the data will be readily available through Real-Time Operations Center Knowledge System (also known as ROCKS) for further analysis and reporting.
{"title":"Streamlining and Automating Geological Requirements for Development Wells","authors":"Malak Abouhenidi, Reham Fadul, Faizuddin Tadamarry, Yassir Rahdi","doi":"10.2118/194892-MS","DOIUrl":"https://doi.org/10.2118/194892-MS","url":null,"abstract":"\u0000 Development wells are drilled for different purposes that varies based on the business needs. Some scenarios can be for flowing production, power water injector, gas, or to monitor the performance of a well. Coupled with the technology in wellbore drilling activity and the artifacts that are required for the workflow approval. Through evolving technology, the system captures every step of wellbore activity to address the business needs and streamline the approval process. Data fuels Industry Revolution (IR) 4.0 and effective data analytics is the prerequisite for successful implementation of digital enterprise applications.\u0000 Well approval is an in-house developed system embedded in Petrel application for reservoir characterization geologists. It standardizes well approval documents across the organization. The geologists may generate multiple well approval documents in case a change in the plan has occurred. Different scenarios require geologists to replace the plan that reflects the well approval document. Planning is the main pillar in the process of Well Approval, and automating the planning part simplifies the well approval process. The system automates the generation of three critical documents. First, Integrated Requirements (IRs), which consists of logging and threshold values for each hole section generates the reservoir amplitude impedance and porosity maps, and finally allows the geologist to capture seismic maps from 3D geological models. Second, Prognosis geological horizons details. Third, Location Evaluation. The backbone of this system is that it is integrated with different back-end systems such as corporate database, Petrel, Openwork and Geolog. In addition, geologists are not required to select the offset wells. The offset wells algorithm designates the wells for geologies based on specific criteria that is built in the system such as reservoir type and dynamic log selection. The system tackles both environments 2D and 3D based on the giving parameters such as facie. The system is able to detect the environment and prepare the documents accordingly.\u0000 Since the system is aligned with the business pattern for well approval process, it significantly improves the time required to create these documents from two to three (2-3) days to less than 1 hour (90%) and the data will be readily available through Real-Time Operations Center Knowledge System (also known as ROCKS) for further analysis and reporting.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75671258","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}
Probe permeameter (also known as Mini-permeameter) has been widely used in many field and laboratory applications where in-situ measurements and spatial distributions of permeability are needed. Mini-permeameter measurements have become popular techniques for collecting localized permeability measurements in both laboratory and field applications. It is designed to obtain fast, cheap, intensive and non-destructive permeability measurements and to describe the spatial arrangement of permeability. In this work, the effect of vertical and horizontal anisotropy on the probe permeameter measurements was investigated. A numerical simulation model for the rectangular system representing a porous rock sample was built based on finite difference discretization of steady-state flow of an incompressible single-phase fluid in a three-dimensional (3D) system. The seal and tip of the probe permeameter are represented by no-flow boundary and constant pressure boundary, respectively. All the sides of the sample are represented by a constant-pressure boundary in which the sample is exposed to the atmosphere. The investigation was conducted by examining different permeability anisotropy ratios. These include fully isotropic sample, different vertical anisotropy ratios in a horizontally-isotropic sample, different vertical anisotropy ratios at different horizontal anisotropy ratios. All these investigations are performed at a constant probe injection pressure of 50 psig at the injection tip. The results obtained showed the clear effect of anisotropy on the probe permeameter measurements and were expressed in dimensionless parameters. These dimensionless parameters include the ratio between the flow rate measurements at different directions for different vertical and horizontal anisotropy ratios. They also include the dimensionless pressure drop for the pressure drop measurements at different directions. From the plots of these dimensionless parameters, the permeability at different directions can be evaluated from a few steady-state flow rate and pressure drop measurements at different directions on a rectangular core sample. Therefore, a practical procedure for evaluating permeability anisotropy from probe permeameter measurements is also described.
{"title":"Effect of Permeability Anisotropy on Probe Permeameter Measurements","authors":"Khaled H. Al-Azani, H. Al-Yousef, Mohamed Mahmoud","doi":"10.2118/194769-MS","DOIUrl":"https://doi.org/10.2118/194769-MS","url":null,"abstract":"\u0000 Probe permeameter (also known as Mini-permeameter) has been widely used in many field and laboratory applications where in-situ measurements and spatial distributions of permeability are needed. Mini-permeameter measurements have become popular techniques for collecting localized permeability measurements in both laboratory and field applications. It is designed to obtain fast, cheap, intensive and non-destructive permeability measurements and to describe the spatial arrangement of permeability.\u0000 In this work, the effect of vertical and horizontal anisotropy on the probe permeameter measurements was investigated. A numerical simulation model for the rectangular system representing a porous rock sample was built based on finite difference discretization of steady-state flow of an incompressible single-phase fluid in a three-dimensional (3D) system. The seal and tip of the probe permeameter are represented by no-flow boundary and constant pressure boundary, respectively. All the sides of the sample are represented by a constant-pressure boundary in which the sample is exposed to the atmosphere. The investigation was conducted by examining different permeability anisotropy ratios. These include fully isotropic sample, different vertical anisotropy ratios in a horizontally-isotropic sample, different vertical anisotropy ratios at different horizontal anisotropy ratios. All these investigations are performed at a constant probe injection pressure of 50 psig at the injection tip.\u0000 The results obtained showed the clear effect of anisotropy on the probe permeameter measurements and were expressed in dimensionless parameters. These dimensionless parameters include the ratio between the flow rate measurements at different directions for different vertical and horizontal anisotropy ratios. They also include the dimensionless pressure drop for the pressure drop measurements at different directions. From the plots of these dimensionless parameters, the permeability at different directions can be evaluated from a few steady-state flow rate and pressure drop measurements at different directions on a rectangular core sample. Therefore, a practical procedure for evaluating permeability anisotropy from probe permeameter measurements is also described.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75706651","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}
Simplified semi-quantitative equations are used in 1D geomechanics workflows to predict the rock’s behavior during drilling and production. While such methods allow for getting a time- efficient solution, it does lose out on accuracy. In addition, by simplifying equations, we limit our ability to predict behavior of the borehole wall only i.e. near wellbore solutions. We lose the ability to predict full field behavior in response to drilling and production activities. For example, when constructing a field-wide drilling plan or a field development plan for a complex subsurface setting, a simplified approach may not be accurate enough and on the contrary, can be quite misleading. A 3D numerical solution on the other hand, honours subsurface features of a field and simulates for their effect on the stresses. It generates solutions which are more akin to reality. In this paper, this difference between a simplified semi-quantitative well-centric approach (1D) and a full field numerical solution (3D) has been presented and discussed. The subsurface setting considered in the study is quite complex – an amalgamation of high dipping beds with pinch outs and low angled faults in a thrust regime. Wellbore stability and fault stability models have been constructed using both a well-centric approach and a full field-wide 3D numerical solution. It is clearly observed that field-based approach provided us more accurate estimation of overburden stresses, variation of pore pressure across the field, impending changes in stress magnitudes and its rotation due to pinch-outs and formation dips. For example, due to variation in topography, the estimated well-centric overburden at the toe of deviated well at reservoir level is lower by 0.21gm/cc (~1.75ppg~0.9psi/ft) as compared to the 3D model. It is also observed that within the field itself stress regime changes from normal to strike slip laterally across the reservoir. In comparison to 1D model, considerable differences in stable mud weight window of upto 1.5ppg is observed in wells located close to faults. This is primarily due to effect of fault on stresses (both magnitude and azimuth). Stress states of 4 faults were assessed and all 4 faults are estimated to be critically stressed with elevated risk of damaging three wells cutting through. However, a simple 1D assessment of stress state of faults at wells cutting through them, shows them to be stable. By comparing the differences between 1D and 3D solutions, importance of 3D numerical modelling over 1D models is highlighted.
{"title":"Complex Settings Need Complex Equations – Comparison Between Numerical and Semi-Quantitative Geomechanical Solutions","authors":"Somessh Bahuguna, R. Talreja","doi":"10.2118/195034-MS","DOIUrl":"https://doi.org/10.2118/195034-MS","url":null,"abstract":"\u0000 Simplified semi-quantitative equations are used in 1D geomechanics workflows to predict the rock’s behavior during drilling and production. While such methods allow for getting a time- efficient solution, it does lose out on accuracy. In addition, by simplifying equations, we limit our ability to predict behavior of the borehole wall only i.e. near wellbore solutions. We lose the ability to predict full field behavior in response to drilling and production activities. For example, when constructing a field-wide drilling plan or a field development plan for a complex subsurface setting, a simplified approach may not be accurate enough and on the contrary, can be quite misleading. A 3D numerical solution on the other hand, honours subsurface features of a field and simulates for their effect on the stresses. It generates solutions which are more akin to reality.\u0000 In this paper, this difference between a simplified semi-quantitative well-centric approach (1D) and a full field numerical solution (3D) has been presented and discussed. The subsurface setting considered in the study is quite complex – an amalgamation of high dipping beds with pinch outs and low angled faults in a thrust regime. Wellbore stability and fault stability models have been constructed using both a well-centric approach and a full field-wide 3D numerical solution.\u0000 It is clearly observed that field-based approach provided us more accurate estimation of overburden stresses, variation of pore pressure across the field, impending changes in stress magnitudes and its rotation due to pinch-outs and formation dips. For example, due to variation in topography, the estimated well-centric overburden at the toe of deviated well at reservoir level is lower by 0.21gm/cc (~1.75ppg~0.9psi/ft) as compared to the 3D model. It is also observed that within the field itself stress regime changes from normal to strike slip laterally across the reservoir. In comparison to 1D model, considerable differences in stable mud weight window of upto 1.5ppg is observed in wells located close to faults. This is primarily due to effect of fault on stresses (both magnitude and azimuth). Stress states of 4 faults were assessed and all 4 faults are estimated to be critically stressed with elevated risk of damaging three wells cutting through. However, a simple 1D assessment of stress state of faults at wells cutting through them, shows them to be stable.\u0000 By comparing the differences between 1D and 3D solutions, importance of 3D numerical modelling over 1D models is highlighted.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77842060","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 tectonic setting of Saudi Arabia enriches the country with significant geothermal resources, such as those in Al-Lith and Jizan in the southwestern area. Recently, there has been interest to explore the geothermal potential to diversify the country's energy-mix, which is driven by the Kingdom's Vision 2030. One key challenge in geothermal systems is in their low efficiency compared to traditional hydrocarbon-fired plants. This inefficiency is related to the thermal flow behavior in the subsurface and to the energy conversion technology at the surface. In this study, we provide a workflow for feasibility assessment of geothermal reservoir development with potential application in Saudi Arabia. The proposed workflow is within the Design of Experiment (DoE) framework, which allows conducting numerous simulations with low computational cost. Computations are performed using a proxy modeling approach, which reflects a multidimensional response-surface emerging from the optimization problem. Two steps in the workflow were found to be critical. First, identify and select the most significant uncertainty parameters to focus the design. Second, address the nonlinearity of the problem by filling up any potential gaps within the response space. In this work, two-level folded Plackett-Burman design is used to identify and select the most significant parameters relative to the energy recovery and enthalpy production factors. Three-level Taguchi design is then applied to create a more rigorous proxy model. We used a space-filling technique to address lack of sampling and nonlinearity in the response surface. Monte Carlo simulations are performed, at the final stage, to generate probabilistic forecasts under uncertainties. The energy recovery factor and the enthalpy production behavior are found to be influenced by the volume of the reservoir, rock permeability and porosity, heterogeneity, well spacing, and fluid production rate. Our Monte Carlo simulations show that, at the Jizan's geothermal conditions, the energy recovery factor is within 12% to 24%, which is encouraging as they are above the typical recovery factor of 10%-17% worldwide.
{"title":"Optimization of Energy Recovery from Geothermal Reservoirs Undergoing Re-Injection: Conceptual Application in Saudi Arabia","authors":"R. Santoso, H. Hoteit, V. Vahrenkamp","doi":"10.2118/195155-MS","DOIUrl":"https://doi.org/10.2118/195155-MS","url":null,"abstract":"\u0000 The tectonic setting of Saudi Arabia enriches the country with significant geothermal resources, such as those in Al-Lith and Jizan in the southwestern area. Recently, there has been interest to explore the geothermal potential to diversify the country's energy-mix, which is driven by the Kingdom's Vision 2030. One key challenge in geothermal systems is in their low efficiency compared to traditional hydrocarbon-fired plants. This inefficiency is related to the thermal flow behavior in the subsurface and to the energy conversion technology at the surface. In this study, we provide a workflow for feasibility assessment of geothermal reservoir development with potential application in Saudi Arabia.\u0000 The proposed workflow is within the Design of Experiment (DoE) framework, which allows conducting numerous simulations with low computational cost. Computations are performed using a proxy modeling approach, which reflects a multidimensional response-surface emerging from the optimization problem. Two steps in the workflow were found to be critical. First, identify and select the most significant uncertainty parameters to focus the design. Second, address the nonlinearity of the problem by filling up any potential gaps within the response space. In this work, two-level folded Plackett-Burman design is used to identify and select the most significant parameters relative to the energy recovery and enthalpy production factors. Three-level Taguchi design is then applied to create a more rigorous proxy model. We used a space-filling technique to address lack of sampling and nonlinearity in the response surface. Monte Carlo simulations are performed, at the final stage, to generate probabilistic forecasts under uncertainties.\u0000 The energy recovery factor and the enthalpy production behavior are found to be influenced by the volume of the reservoir, rock permeability and porosity, heterogeneity, well spacing, and fluid production rate. Our Monte Carlo simulations show that, at the Jizan's geothermal conditions, the energy recovery factor is within 12% to 24%, which is encouraging as they are above the typical recovery factor of 10%-17% worldwide.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77984320","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}
M. T. Al-Murayri, H. Al-Mayyan, Mohammad Al-Ghnemi, M. Pitts, E. Dean, K. Wyatt, Josh French, E. Skeans
Sabriyah Lower Burgan (SALB) is a multi-billion-barrel reservoir located in north Kuwait with favorable fluid and rock properties, and a strong active aquifer. The presence of the aquifer is advantageous for primary development of the reservoir but presents a challenge for conventional application of chemical EOR (CEOR). SALB has passed multiple stages of a CEOR evaluation process (technical screening, laboratory formulation design, SWCT, pilot design, risk assessment, etc.), and is currently considered for a multi-well CEOR pilot. This study investigates the viability of using sacrificial wells in the management of the lateral aquifer present in the SALB Layered formation, which represents a sought after CEOR target. The objective of these sacrificial wells is to reduce the potential negative impacts of the existing aquifer on commercial CEOR deployment. The adopted approach involved using a history matched field model with EOR parameters calibrated to laboratory results for ASP and CO2 technologies. The multi-well field model was used to evaluate and compare different development scenarios to assess the impact of sacrificial wells. These scenarios were evaluated based on production performance and economics. It was observed that strong aquifer presence complicates both CO2 and ASP project implementation. Challenges due to the aquifer include loss of EOR agents into the water leg, difficulty in accounting for effective pore volume of the project and water encroachment. It is difficult for EOR project economics to compete with an effective aquifer primary development. Sacrificial wells can be used to reduce the strength of the aquifer, potentially improving the effectiveness of the EOR technology. Although the sacrificial wells are unlikely to be economic on their own, they can improve the overall economics of the project. The amount of recovered oil due to EOR deployment is an important parameter to evaluate the economic feasibility of using sacrificial wells. Many reservoirs around the world have strong aquifers, for which conventional reservoir engineering advice has been to avoid EOR application. This paper introduces a novel approach to deal with these strong aquifers by strategically placing wells that can reduce the aquifer's strength, thus making EOR deployment more favorable.
{"title":"Sabriyah Lower Burgan Field EOR Development Study: Use of Sacrificial Wells to Minimize Water Encroachment","authors":"M. T. Al-Murayri, H. Al-Mayyan, Mohammad Al-Ghnemi, M. Pitts, E. Dean, K. Wyatt, Josh French, E. Skeans","doi":"10.2118/194909-MS","DOIUrl":"https://doi.org/10.2118/194909-MS","url":null,"abstract":"\u0000 Sabriyah Lower Burgan (SALB) is a multi-billion-barrel reservoir located in north Kuwait with favorable fluid and rock properties, and a strong active aquifer. The presence of the aquifer is advantageous for primary development of the reservoir but presents a challenge for conventional application of chemical EOR (CEOR). SALB has passed multiple stages of a CEOR evaluation process (technical screening, laboratory formulation design, SWCT, pilot design, risk assessment, etc.), and is currently considered for a multi-well CEOR pilot. This study investigates the viability of using sacrificial wells in the management of the lateral aquifer present in the SALB Layered formation, which represents a sought after CEOR target. The objective of these sacrificial wells is to reduce the potential negative impacts of the existing aquifer on commercial CEOR deployment.\u0000 The adopted approach involved using a history matched field model with EOR parameters calibrated to laboratory results for ASP and CO2 technologies. The multi-well field model was used to evaluate and compare different development scenarios to assess the impact of sacrificial wells. These scenarios were evaluated based on production performance and economics.\u0000 It was observed that strong aquifer presence complicates both CO2 and ASP project implementation. Challenges due to the aquifer include loss of EOR agents into the water leg, difficulty in accounting for effective pore volume of the project and water encroachment. It is difficult for EOR project economics to compete with an effective aquifer primary development. Sacrificial wells can be used to reduce the strength of the aquifer, potentially improving the effectiveness of the EOR technology. Although the sacrificial wells are unlikely to be economic on their own, they can improve the overall economics of the project. The amount of recovered oil due to EOR deployment is an important parameter to evaluate the economic feasibility of using sacrificial wells.\u0000 Many reservoirs around the world have strong aquifers, for which conventional reservoir engineering advice has been to avoid EOR application. This paper introduces a novel approach to deal with these strong aquifers by strategically placing wells that can reduce the aquifer's strength, thus making EOR deployment more favorable.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73736604","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}
Yanhui Han, Chao Liu, Dung T. Phan, K. Alruwaili, Y. Abousleiman
An advanced wellbore stability analysis software product has been developed in-house at Aramco. This product offers three analysis modules: (1) the classical mechanical module (elastic); (2) the time-dependent analysis module (poroelasticity); and (3) the time-dependent analysis of naturally fractured rock module (dual-porosity and dual permeability poroelasticity). The stress and pressure analyses are integrated with four rock failure criteria (Mohr-Coulomb, Drucker-Prager, Modified Lade, and Hoek-Brown) to calculate critical mud densities. The basic mechanical module is similar to the wellbore stability module provided in the most-frequently-used drilling geomechanics software. What sets this product apart from the others is that no commercial drilling software to date has the time-dependent stress and pressure analyses modeled by this product's poroelastic and dual-porosity poroelastic modules, which can capture real-time phenomena introduced by the time-dependent fluid pore pressure perturbation and the wellbore time-dependent failures in tension and/or compression.
{"title":"Advanced Wellbore Stability Analysis for Drilling Naturally Fractured Rocks","authors":"Yanhui Han, Chao Liu, Dung T. Phan, K. Alruwaili, Y. Abousleiman","doi":"10.2118/195021-MS","DOIUrl":"https://doi.org/10.2118/195021-MS","url":null,"abstract":"\u0000 An advanced wellbore stability analysis software product has been developed in-house at Aramco. This product offers three analysis modules: (1) the classical mechanical module (elastic); (2) the time-dependent analysis module (poroelasticity); and (3) the time-dependent analysis of naturally fractured rock module (dual-porosity and dual permeability poroelasticity). The stress and pressure analyses are integrated with four rock failure criteria (Mohr-Coulomb, Drucker-Prager, Modified Lade, and Hoek-Brown) to calculate critical mud densities. The basic mechanical module is similar to the wellbore stability module provided in the most-frequently-used drilling geomechanics software. What sets this product apart from the others is that no commercial drilling software to date has the time-dependent stress and pressure analyses modeled by this product's poroelastic and dual-porosity poroelastic modules, which can capture real-time phenomena introduced by the time-dependent fluid pore pressure perturbation and the wellbore time-dependent failures in tension and/or compression.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73496300","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}
M. Khan, Sami A. Al-nuaim, Zeeshan Tariq, A. Abdulraheem
Well production rate is one of the most critical parameters for reservoir/production engineers to evaluate performance of the system. Given this importance, however, monitoring of production rates is not usually carried out in real time. Some cases flowmeters are used which are known to carry their own inherent uncertainties. The industry, thus, relies on the use of correlations to allocate production to wells. Over time, it has been realized that the generally used correlations are not effective enough due to multiple technical and economic issues. The focus of this work is to utilize machine learning (ML) algorithms to develop a correlation that can accurately predict oil rate in artificial gas lift wells. The reason for using these algorithms is to provide a solution that is simple, easy to use and universally applicable. Various intelligent algorithms are employed, namely; Artificial Neuro Fuzzy Inference Systems (ANFIS), and Support Vector Machines (SVM), along with the development of Artificial Neural Network providing a usable equation to be applied on any field, hence demystifying the black-box reputation of artificial intelligence. In addition, non-linear regression is also performed to compare the results with ML methods. Data cleansing and data-reduction were carried out on the dataset comprising of 1500 separator test points. This practice yielded in only the common wellhead parameters to be used as input for the model. All ML models were compared with the non-linear regression model and with previously derived empirical models to gauge the effectiveness of the work. The newly developed model using ANN shows that it can predict the flow-rate with 99% accuracy. This is an interesting outcome, as such accuracy has not been reported in literature usually. The results of this study show that the correlation developed using ANN outperforms all the current empirical correlations, moreover, it also performs multiple times better in comparison to previously developed AI models. In addition, this work provides a functional equation that can be used by anyone on their field data, thereby removing any ambiguities or confusion related to the concept of artificial intelligence expertise and software. This effort puts forth an industrial insight into the role of data-driven computational models for the production reconnaissance scheme, not only to validate the well tests but also as an effective tool to reduce qualms in production provisions.
{"title":"Machine Learning Application for Oil Rate Prediction in Artificial Gas Lift Wells","authors":"M. Khan, Sami A. Al-nuaim, Zeeshan Tariq, A. Abdulraheem","doi":"10.2118/194713-MS","DOIUrl":"https://doi.org/10.2118/194713-MS","url":null,"abstract":"\u0000 Well production rate is one of the most critical parameters for reservoir/production engineers to evaluate performance of the system. Given this importance, however, monitoring of production rates is not usually carried out in real time. Some cases flowmeters are used which are known to carry their own inherent uncertainties. The industry, thus, relies on the use of correlations to allocate production to wells. Over time, it has been realized that the generally used correlations are not effective enough due to multiple technical and economic issues.\u0000 The focus of this work is to utilize machine learning (ML) algorithms to develop a correlation that can accurately predict oil rate in artificial gas lift wells. The reason for using these algorithms is to provide a solution that is simple, easy to use and universally applicable. Various intelligent algorithms are employed, namely; Artificial Neuro Fuzzy Inference Systems (ANFIS), and Support Vector Machines (SVM), along with the development of Artificial Neural Network providing a usable equation to be applied on any field, hence demystifying the black-box reputation of artificial intelligence. In addition, non-linear regression is also performed to compare the results with ML methods.\u0000 Data cleansing and data-reduction were carried out on the dataset comprising of 1500 separator test points. This practice yielded in only the common wellhead parameters to be used as input for the model. All ML models were compared with the non-linear regression model and with previously derived empirical models to gauge the effectiveness of the work. The newly developed model using ANN shows that it can predict the flow-rate with 99% accuracy. This is an interesting outcome, as such accuracy has not been reported in literature usually.\u0000 The results of this study show that the correlation developed using ANN outperforms all the current empirical correlations, moreover, it also performs multiple times better in comparison to previously developed AI models. In addition, this work provides a functional equation that can be used by anyone on their field data, thereby removing any ambiguities or confusion related to the concept of artificial intelligence expertise and software. This effort puts forth an industrial insight into the role of data-driven computational models for the production reconnaissance scheme, not only to validate the well tests but also as an effective tool to reduce qualms in production provisions.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81702497","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}
Endurance Ighodalo, G. Hursán, J. Mccrossan, A. Belowi
Unconventional tight reservoir sands have low porosity and very low permeability (mostly less than 0.1mD) due to their fine grain size and poor grain sorting that is often exacerbated by extensive diagenetic effects such as cementation and compaction. Petrophysical evaluation in these formations is very challenging. Conventional downhole logs such as density, neutron, sonic, gamma ray and resistivity measurements provide limited information on pore size variations and often missed Key geological features especially at the early stages of reservoir development. Fluid characterization at the earliest possible stage is paramount to guide the development of these reservoirs where tight well spacing, stimulation (fracturing) and or horizontal well completion is usually required. The main objective of this paper is to show a process of fluid characterization in unconventional tight sand that guides reservoir stimulation. Porosity partitioning using nuclear magnetic resonance (NMR) logging data helps address these challenges in three distinct steps. First, the 1-dimensional (1D) NMR T2 spectrum quantifies the amount of bound and free fluids pore space and reveals reservoir quality with unique sensitivity. In this step, the NMR fluid substitution method was utilized to ensure consistency between NMR logs in oil-based mud (OBM) and water-based mud (WBM) systems. Second, the free fluids are further subdivided into hydrocarbon and water phases using a 2-dimensional (2D) NMR T1/T2 processing technique. Third, the hydrocarbon phase is subdivided again into liquid and gas phases where a gas flag is turned on whenever the NMR gas signal significantly exceeds measurement uncertainty. This enables detection of live hydrocarbons with high gas-oil ratio (GOR). This paper presents the integration of NMR analysis into petrophysical evaluation of an unconventional tight sand reservoir. The evaluation helped optimize the best interval for stimulation. Fluid sample acquired with formation tester correlated very well with NMR log-based fluid prediction. Integrated NMR analysis, including bound fluid vs. free fluid analysis and 2D NMR-based fluid characterization, including gas indicator flag, was applied to establish the presence and type of hydrocarbon in tight sands and select the best representative interval for stimulation. The continuous reservoir quality and fluid distribution profiles provided by these logs were beneficial for the geological understanding and complex formation testing operations in this challenging reservoir.
{"title":"Integrated NMR Fluid Characterization Guides Stimulation in Tight Sand Reservoirs","authors":"Endurance Ighodalo, G. Hursán, J. Mccrossan, A. Belowi","doi":"10.2118/195061-MS","DOIUrl":"https://doi.org/10.2118/195061-MS","url":null,"abstract":"\u0000 Unconventional tight reservoir sands have low porosity and very low permeability (mostly less than 0.1mD) due to their fine grain size and poor grain sorting that is often exacerbated by extensive diagenetic effects such as cementation and compaction. Petrophysical evaluation in these formations is very challenging. Conventional downhole logs such as density, neutron, sonic, gamma ray and resistivity measurements provide limited information on pore size variations and often missed Key geological features especially at the early stages of reservoir development. Fluid characterization at the earliest possible stage is paramount to guide the development of these reservoirs where tight well spacing, stimulation (fracturing) and or horizontal well completion is usually required. The main objective of this paper is to show a process of fluid characterization in unconventional tight sand that guides reservoir stimulation.\u0000 Porosity partitioning using nuclear magnetic resonance (NMR) logging data helps address these challenges in three distinct steps. First, the 1-dimensional (1D) NMR T2 spectrum quantifies the amount of bound and free fluids pore space and reveals reservoir quality with unique sensitivity. In this step, the NMR fluid substitution method was utilized to ensure consistency between NMR logs in oil-based mud (OBM) and water-based mud (WBM) systems. Second, the free fluids are further subdivided into hydrocarbon and water phases using a 2-dimensional (2D) NMR T1/T2 processing technique. Third, the hydrocarbon phase is subdivided again into liquid and gas phases where a gas flag is turned on whenever the NMR gas signal significantly exceeds measurement uncertainty. This enables detection of live hydrocarbons with high gas-oil ratio (GOR).\u0000 This paper presents the integration of NMR analysis into petrophysical evaluation of an unconventional tight sand reservoir. The evaluation helped optimize the best interval for stimulation. Fluid sample acquired with formation tester correlated very well with NMR log-based fluid prediction.\u0000 Integrated NMR analysis, including bound fluid vs. free fluid analysis and 2D NMR-based fluid characterization, including gas indicator flag, was applied to establish the presence and type of hydrocarbon in tight sands and select the best representative interval for stimulation. The continuous reservoir quality and fluid distribution profiles provided by these logs were beneficial for the geological understanding and complex formation testing operations in this challenging reservoir.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86902462","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}
E. Chevallier, S. Bouquet, N. Gland, F. Douarche, G. Batôt
In naturally fractured carbonate reservoirs, Gas Oil Gravity Drainage processes (GOGD) are successfully implemented but oil recovery is limited by a slow kinetics. However a gas EOR process represents a promising alternative to boost this oil production rate. Nevertheless the design of this process should address several technical challenges: the typically unfavorable wettability of the matrix (intermediate to strongly oil-wet), the densely connected fracture network and the high contrast of fracture-to-matrix permeability. We propose here the injection of a advanced EOR foam with reduced interfacial tension. The foam flow in the fracture creates an important viscous drive leading to a pressure gradient, which increases the oil recovery dynamics compared to GOGD. Besides, the reduced interfacial tension (IFT) between crude oil and aqueous phase allows the aqueous phase to enter the matrix despite the unfavorable wettability. In this paper, we demonstrate that a balance exist between IFT and foam strength performances to optimize the process. Three foam formulations are optimized with very different profiles in terms of IFT and foam performances. For their design, priority is given either to ultra-low IFT values (10-3mN/m) or to a strong foam with larger IFT (0.35mN/m) or to a balance between the two first formulations (0.03mN/m). Foams are evidenced as intrinsically less stable in ultra-low IFT conditions: apparent viscosity (in porous media) in contact with oil is respectively enhanced by a factor 40 when IFT rises from 10−3 to 10−1mN/m. Based on sandpack and coreflood experiments, we recommend an IFT in the order of 10−1 mN/mas a balance between the viscous drive in fracture and an efficient aqueous phase imbibition in the oil-wet matrix. Simulation work supports this experimental conclusion: the common target of IFT in the order of 10−3 mN/m determined by capillary desaturation curves in SP flooding can be adjusted to a higher IFT value, which can be deduced from the wettability of the reservoir. To ensure an accelerated oil recovery in naturally fractured carbonate reservoirs, we recommend the design of a low-IFT foam formulation with revised IFT performances compared to a classical Surfactant-Polymer process targeting residual oil. Indeed, the final process is likely more efficient if the target of IFT is defined by wettability requirements rather than residual oil desaturation. This article gives the target formulation parameters which arise from the mechanisms at play (viscous drive and imbibition in oil-wet matrix), and are realistically achieved with industrial surfactants.
{"title":"Advanced Eor Foam in Naturally Fractured Carbonates Reservoirs : Optimal Balance Between Foam and Interfacial Tension Properties","authors":"E. Chevallier, S. Bouquet, N. Gland, F. Douarche, G. Batôt","doi":"10.2118/194992-MS","DOIUrl":"https://doi.org/10.2118/194992-MS","url":null,"abstract":"\u0000 In naturally fractured carbonate reservoirs, Gas Oil Gravity Drainage processes (GOGD) are successfully implemented but oil recovery is limited by a slow kinetics. However a gas EOR process represents a promising alternative to boost this oil production rate. Nevertheless the design of this process should address several technical challenges: the typically unfavorable wettability of the matrix (intermediate to strongly oil-wet), the densely connected fracture network and the high contrast of fracture-to-matrix permeability.\u0000 We propose here the injection of a advanced EOR foam with reduced interfacial tension. The foam flow in the fracture creates an important viscous drive leading to a pressure gradient, which increases the oil recovery dynamics compared to GOGD. Besides, the reduced interfacial tension (IFT) between crude oil and aqueous phase allows the aqueous phase to enter the matrix despite the unfavorable wettability.\u0000 In this paper, we demonstrate that a balance exist between IFT and foam strength performances to optimize the process. Three foam formulations are optimized with very different profiles in terms of IFT and foam performances. For their design, priority is given either to ultra-low IFT values (10-3mN/m) or to a strong foam with larger IFT (0.35mN/m) or to a balance between the two first formulations (0.03mN/m). Foams are evidenced as intrinsically less stable in ultra-low IFT conditions: apparent viscosity (in porous media) in contact with oil is respectively enhanced by a factor 40 when IFT rises from 10−3 to 10−1mN/m. Based on sandpack and coreflood experiments, we recommend an IFT in the order of 10−1 mN/mas a balance between the viscous drive in fracture and an efficient aqueous phase imbibition in the oil-wet matrix. Simulation work supports this experimental conclusion: the common target of IFT in the order of 10−3 mN/m determined by capillary desaturation curves in SP flooding can be adjusted to a higher IFT value, which can be deduced from the wettability of the reservoir.\u0000 To ensure an accelerated oil recovery in naturally fractured carbonate reservoirs, we recommend the design of a low-IFT foam formulation with revised IFT performances compared to a classical Surfactant-Polymer process targeting residual oil. Indeed, the final process is likely more efficient if the target of IFT is defined by wettability requirements rather than residual oil desaturation. This article gives the target formulation parameters which arise from the mechanisms at play (viscous drive and imbibition in oil-wet matrix), and are realistically achieved with industrial surfactants.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91150226","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}
A. Sanyal, Sanjeev Kumar, Ahmed Abdullah Al Awadh, Sarah Al Samhan, Jassim Al Azmi, K. Sikdar, G. Sultan, Sourav Das
Zubair Formation is one of the key producers in North Kuwait; however, the reservoir complexity and hydrocarbon movement along with pressure depletion always poses challenge for determining the perforation and completion strategy to optimize the production. Zubair Formation is broadly divided into three parts e.g. upper, middle and lower, the upper and lower units are of utmost importance for the current study. An integrated approach was adopted utilizing the high-resolution borehole image outputs; which has not only helped in identifying thin bedded reservoir zones but also facilitated the understanding of detail reservoir geology and sand dispersion. Integrated formation evaluation and workover design is always the key to sustain the production and it becomes even more important when the reservoir is highly heterogeneous in nature and coupled with declining pressure trend. Therefore, an innovative methodology was necessary to address the uncertainties. High resolution borehole images were utilized to determine the sand count, which can detect even the thinnest reservoir layer in the formation. Heterogeneity analysis was also performed to understand the relative sorting of the different reservoir units; sorting has a direct relation with reservoir permeability and thus reservoir productivity. High resolution sedimentary analysis was performed to understand the detailed sedimentology using the borehole image derived dip data; cross bedding types were identified which provides fair idea about depositional energy condition along with depositional environment. All the high-resolution inputs were integrated with openhole logs and volumetric results, which led to a clear deterministic picture of the reservoir, based on which crucial decision was taken. This integrated approach was adopted in three deviated well sections in Zubair formation, which has facilitated in improving the well performance. Detail sedimentary analysis and cross bedding typing in multiwell helps in fine tuning the sand dispersion in the reservoir model; which in turn found to be helpful for deciding future well locations.
{"title":"Integrated Formation Evaluation Using High Resolution Sedimentary and Facies Analysis an Aid for Field Development: A Case Study from North Kuwait","authors":"A. Sanyal, Sanjeev Kumar, Ahmed Abdullah Al Awadh, Sarah Al Samhan, Jassim Al Azmi, K. Sikdar, G. Sultan, Sourav Das","doi":"10.2118/195043-MS","DOIUrl":"https://doi.org/10.2118/195043-MS","url":null,"abstract":"\u0000 Zubair Formation is one of the key producers in North Kuwait; however, the reservoir complexity and hydrocarbon movement along with pressure depletion always poses challenge for determining the perforation and completion strategy to optimize the production. Zubair Formation is broadly divided into three parts e.g. upper, middle and lower, the upper and lower units are of utmost importance for the current study. An integrated approach was adopted utilizing the high-resolution borehole image outputs; which has not only helped in identifying thin bedded reservoir zones but also facilitated the understanding of detail reservoir geology and sand dispersion.\u0000 Integrated formation evaluation and workover design is always the key to sustain the production and it becomes even more important when the reservoir is highly heterogeneous in nature and coupled with declining pressure trend. Therefore, an innovative methodology was necessary to address the uncertainties. High resolution borehole images were utilized to determine the sand count, which can detect even the thinnest reservoir layer in the formation. Heterogeneity analysis was also performed to understand the relative sorting of the different reservoir units; sorting has a direct relation with reservoir permeability and thus reservoir productivity. High resolution sedimentary analysis was performed to understand the detailed sedimentology using the borehole image derived dip data; cross bedding types were identified which provides fair idea about depositional energy condition along with depositional environment. All the high-resolution inputs were integrated with openhole logs and volumetric results, which led to a clear deterministic picture of the reservoir, based on which crucial decision was taken.\u0000 This integrated approach was adopted in three deviated well sections in Zubair formation, which has facilitated in improving the well performance. Detail sedimentary analysis and cross bedding typing in multiwell helps in fine tuning the sand dispersion in the reservoir model; which in turn found to be helpful for deciding future well locations.","PeriodicalId":11321,"journal":{"name":"Day 3 Wed, March 20, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89353185","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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