W. Fares, Maniesh Singh, M. Bazuhair, Parmanand Dhermeshwar Thakur, Mariam N. M. Al Baloushi, S. Al Arfi, Mohamed El Gohary, Salem El Abd, Ahmed S. Al Mesafri, N. Clegg, A. Walmsley, A. Aki
Drilling horizontal wells in mature fields undergoing enhanced oil recovery programs requires advanced high-resolution reservoir mapping to optimise well placement. Ultra-deep electromagnetic (EM) technology provides shallow and deep 1D and 3D inversion-based mapping in real-time and recorded data. All inversion results show uncertainty in the exact position of formation/fluid boundaries and inverted resistivity values. Understanding this uncertainty and deploying multiple inversions to mitigate it is essential for attaining high confidence in the quality of results. Multi-antenna, azimuthal EM LWD tools propagate EM fields in three dimensions with an ultra-deep depth of investigation (DOI). Robust inversion algorithms both one dimensional (1D) and three dimensional (3D) derive the position and resistivity of formations within the DOI from measurements induced by the propagated fields. This provides geologists with a clearer understanding of the surrounding geology. High confidence in these results, which are models that best represent the EM field is essential. It is vital to understand any uncertainty and where possible use independent verification. Pre-drill modelling provides understanding of the expected response in each formation. Offset data and independent LWD tools provide independent verification of results but have limited DOI's. An understanding of inversion uncertainty is essential to assess quality of the inversions and allow confident geosteering decisions to be made. Pre-drill modeling for a candidate field onshore Abu Dhabi demonstrated the capability of resolving multiple formation layers, with a DOI of more than 90ft. Uncertainty is therefore important as other LWD tools have limited DOI's and can only be used to verify results close to the wellbore. The field trail results exceeded pre-drill expectations, clearly identifying resistivity boundaries, consistent with offset logs. While drilling, the real-time ultra-deep EM tool provided high resolution mapping for precise geosteering within thin layers and mapped a varying water slumping contact 80 ft TVD above the wellbore. A simultaneous 3D EM inversion with 120 ft distance-to-boundary window also imaged the water-front and confirmed that no lateral variation existed in its orientation, it also defined the azimuth, dip and strike of a fault. Confidence in these results was essential as the real-time information helped in timely optimizing completion design to produce oil without water cut and extend the wells production life. Understanding boundary position and resistivity value uncertainty provided confidence in the quality of the results. Post-well these results aided in updating the static model with water flood areas, reservoir tops, faults and overall reservoir structure. The results of this experience provided optimized BHA selection and maximize the benefits of running ultra-deep EM mapping tool in mature fields for multiple purposes; deep reservoir fluid mapping, m
{"title":"Understanding Uncertainty in 1D and 3D Ultra-Deep Resistivity Inversions for Improved Geosteering and Geomapping in Complex Carbonate Reservoirs, Onshore Abu Dhabi","authors":"W. Fares, Maniesh Singh, M. Bazuhair, Parmanand Dhermeshwar Thakur, Mariam N. M. Al Baloushi, S. Al Arfi, Mohamed El Gohary, Salem El Abd, Ahmed S. Al Mesafri, N. Clegg, A. Walmsley, A. Aki","doi":"10.2118/210030-ms","DOIUrl":"https://doi.org/10.2118/210030-ms","url":null,"abstract":"\u0000 Drilling horizontal wells in mature fields undergoing enhanced oil recovery programs requires advanced high-resolution reservoir mapping to optimise well placement. Ultra-deep electromagnetic (EM) technology provides shallow and deep 1D and 3D inversion-based mapping in real-time and recorded data. All inversion results show uncertainty in the exact position of formation/fluid boundaries and inverted resistivity values. Understanding this uncertainty and deploying multiple inversions to mitigate it is essential for attaining high confidence in the quality of results.\u0000 Multi-antenna, azimuthal EM LWD tools propagate EM fields in three dimensions with an ultra-deep depth of investigation (DOI). Robust inversion algorithms both one dimensional (1D) and three dimensional (3D) derive the position and resistivity of formations within the DOI from measurements induced by the propagated fields. This provides geologists with a clearer understanding of the surrounding geology. High confidence in these results, which are models that best represent the EM field is essential. It is vital to understand any uncertainty and where possible use independent verification. Pre-drill modelling provides understanding of the expected response in each formation. Offset data and independent LWD tools provide independent verification of results but have limited DOI's. An understanding of inversion uncertainty is essential to assess quality of the inversions and allow confident geosteering decisions to be made.\u0000 Pre-drill modeling for a candidate field onshore Abu Dhabi demonstrated the capability of resolving multiple formation layers, with a DOI of more than 90ft. Uncertainty is therefore important as other LWD tools have limited DOI's and can only be used to verify results close to the wellbore. The field trail results exceeded pre-drill expectations, clearly identifying resistivity boundaries, consistent with offset logs. While drilling, the real-time ultra-deep EM tool provided high resolution mapping for precise geosteering within thin layers and mapped a varying water slumping contact 80 ft TVD above the wellbore. A simultaneous 3D EM inversion with 120 ft distance-to-boundary window also imaged the water-front and confirmed that no lateral variation existed in its orientation, it also defined the azimuth, dip and strike of a fault. Confidence in these results was essential as the real-time information helped in timely optimizing completion design to produce oil without water cut and extend the wells production life. Understanding boundary position and resistivity value uncertainty provided confidence in the quality of the results. Post-well these results aided in updating the static model with water flood areas, reservoir tops, faults and overall reservoir structure.\u0000 The results of this experience provided optimized BHA selection and maximize the benefits of running ultra-deep EM mapping tool in mature fields for multiple purposes; deep reservoir fluid mapping, m","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129235401","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}
This article will address two issues related to sand production in unconsolidated reservoirs. First, it will examine the relationship between formation compressibility (Cf), elasto-plastic hysteresis and the shear failure of the formation macroscopically (when the fluid and formation pressure together cannot support the overburden stress), as well as the methodology to predict this failure pressure. Second, it will explore the means to recognize which formations are more friable and likely to produce sand grains – microscopic shear failure. The two effects are only tangentially related but can occur simultaneously. Logs and petrophysical data should be methodolically used to qualitatively and quantitatively assess the sanding potential of a well or reservoir. The first method is evaluating the compressibility of formation rocks as they first demonstrate elasto-plasticity, then have catastrophic shear failure. The other method evaluates the sanding potential based on the friability of the formation. The most effective way to manage/mitigate catastrophic/macroscopic shear failure is to observe the dynamic behavior of the reservoir. By plotting the build-up permeability vs. skin-less FBHP, the failure pressure of the formation can be determined. Good operating practices then dictate that the well should not be flowed at pressures below the value plus a safety factor. The approach to managing potential sand grain failure (microscopic shear failure) is to design the completion (frac-pack, gravel pack, etc.) to collect the sand grains in the pack and screens, then perform periodic pump-in stimulation treatments to push the fines away from the screens/pack. Two examples each from the Gulf of Mexico and the Louisiana Gulf Coast will be presented to demonstrate the methodology for both macroscopic and microscopic shear failure. It should be noted that it is important to differentiate the cause of sand production/fines migration as one of the two (macro/micro) causes. This can be determined by tracking the accretion of skin due to fines. If this occurs coincident with a decrease in permeability or mobility thickness, it should be assumed that the cause is macroscopic shear failure. If the permeability remains constant as skin due to fines increases, it is due to microscopic shear failure. Technically, both mechanisms can occur simultaneously, but it is best to approach the issue conservatively and assume that any increase in skin due to fines that occurs with a decrease in mobility thickness is due to macroscopic shear failure. Applying the sanding potential systematically to formation evaluation can improve the completion design; predicting the macroscopic shear failure pressure of the formation contributes to better overall reservoir management.
{"title":"A Systematic Approach to Evaluate the Sanding Potential Caused by Formation Shear Failure in Unconsolidated Oil and Gas Reservoirs","authors":"Bryan Baptista, Chris L. Fair","doi":"10.2118/210013-ms","DOIUrl":"https://doi.org/10.2118/210013-ms","url":null,"abstract":"\u0000 This article will address two issues related to sand production in unconsolidated reservoirs. First, it will examine the relationship between formation compressibility (Cf), elasto-plastic hysteresis and the shear failure of the formation macroscopically (when the fluid and formation pressure together cannot support the overburden stress), as well as the methodology to predict this failure pressure. Second, it will explore the means to recognize which formations are more friable and likely to produce sand grains – microscopic shear failure. The two effects are only tangentially related but can occur simultaneously.\u0000 Logs and petrophysical data should be methodolically used to qualitatively and quantitatively assess the sanding potential of a well or reservoir. The first method is evaluating the compressibility of formation rocks as they first demonstrate elasto-plasticity, then have catastrophic shear failure. The other method evaluates the sanding potential based on the friability of the formation.\u0000 The most effective way to manage/mitigate catastrophic/macroscopic shear failure is to observe the dynamic behavior of the reservoir. By plotting the build-up permeability vs. skin-less FBHP, the failure pressure of the formation can be determined. Good operating practices then dictate that the well should not be flowed at pressures below the value plus a safety factor. The approach to managing potential sand grain failure (microscopic shear failure) is to design the completion (frac-pack, gravel pack, etc.) to collect the sand grains in the pack and screens, then perform periodic pump-in stimulation treatments to push the fines away from the screens/pack. Two examples each from the Gulf of Mexico and the Louisiana Gulf Coast will be presented to demonstrate the methodology for both macroscopic and microscopic shear failure.\u0000 It should be noted that it is important to differentiate the cause of sand production/fines migration as one of the two (macro/micro) causes. This can be determined by tracking the accretion of skin due to fines. If this occurs coincident with a decrease in permeability or mobility thickness, it should be assumed that the cause is macroscopic shear failure. If the permeability remains constant as skin due to fines increases, it is due to microscopic shear failure. Technically, both mechanisms can occur simultaneously, but it is best to approach the issue conservatively and assume that any increase in skin due to fines that occurs with a decrease in mobility thickness is due to macroscopic shear failure. Applying the sanding potential systematically to formation evaluation can improve the completion design; predicting the macroscopic shear failure pressure of the formation contributes to better overall reservoir management.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"468 ","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"120981324","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}
D. Abdrazakov, E. Eswein, Jakub Witek, D. Agee, Brian Bruce, M. Dorokhov, Dmytro Trokhymets, Stanislav Prokhorenko
An end-to-end workflow was developed for optimization of a carbonate stimulation treatment in a high-temperature environment. The workflow includes advanced core testing, treatment fluid and design considerations, and production simulations. A case history validated the workflow and production results. A well in central Ukraine was selected by an operator as a candidate well for a production stimulation feasibility study. The reservoir and well information were reviewed, and a reservoir model was built in an advanced matrix stimulation simulator. Core flow tests with 3D wormhole geometry visualization were used to calibrate the simulator's fluid-rock interaction parameters. Various skin and permeability profiles were subjected to iterations in the simulator with different fluids and treatment schedules. Optimum fluids were chosen according to the risk analysis, and key design objectives were considered based on the drilling records, mud type, workover history, and petrophysics. Analysis of the drilling history revealed the necessity of using special stimulation fluids for removing damage from the oil-based mud. Analysis of the well and reservoir conditions showed that the use of nonmodified, emulsified, and organic acids was not recommended. Instead, a single-phase retarded stimulation fluid was chosen as the main reactive agent. Use of chelates was declined due to higher cost-to-efficiency ratio in comparison with the single-phase retarded stimulation fluid. The core flow tests along with 3D wormhole geometry visualization allowed optimizing the treatment parameters with respect to wormholing efficiency. The core flow test data were used to calibrate the matrix stimulation simulator with representative fluid-rock interaction curves. Due to interval length and heterogeneity, the use of diverters was recommended to increase wellbore coverage during the treatment. A polymer-free viscoelastic surfactant-based diverter was selected to alter the injection profile. An optimum treatment schedule developed in the matrix simulator included cleanout by coiled tubing equipped with a high-velocity jet, a low-rate coiled tubing matrix treatment, and a high-rate bullhead treatment. The designed treatment was successfully pumped. The post-stimulation production showed a significant increase in productivity index, without issues in cleanup. Similar workflow stimulation treatments were deployed on five subsequent wells, which have also shown very positive production response. This work provides validation that a sound and rigorous engineering approach with advanced modeling and novel chemistry solutions can revive and significantly increase productivity of carbonate reservoirs. It was the first application of such a workflow and described stimulation fluid technology in Ukraine and Europe.
{"title":"Successful Application of an End-to-End Advanced Workflow for Reservoir Stimulation: Case Studies from a High-Temperature Gas Formation in Ukraine","authors":"D. Abdrazakov, E. Eswein, Jakub Witek, D. Agee, Brian Bruce, M. Dorokhov, Dmytro Trokhymets, Stanislav Prokhorenko","doi":"10.2118/209986-ms","DOIUrl":"https://doi.org/10.2118/209986-ms","url":null,"abstract":"\u0000 An end-to-end workflow was developed for optimization of a carbonate stimulation treatment in a high-temperature environment. The workflow includes advanced core testing, treatment fluid and design considerations, and production simulations. A case history validated the workflow and production results.\u0000 A well in central Ukraine was selected by an operator as a candidate well for a production stimulation feasibility study. The reservoir and well information were reviewed, and a reservoir model was built in an advanced matrix stimulation simulator. Core flow tests with 3D wormhole geometry visualization were used to calibrate the simulator's fluid-rock interaction parameters. Various skin and permeability profiles were subjected to iterations in the simulator with different fluids and treatment schedules. Optimum fluids were chosen according to the risk analysis, and key design objectives were considered based on the drilling records, mud type, workover history, and petrophysics.\u0000 Analysis of the drilling history revealed the necessity of using special stimulation fluids for removing damage from the oil-based mud. Analysis of the well and reservoir conditions showed that the use of nonmodified, emulsified, and organic acids was not recommended. Instead, a single-phase retarded stimulation fluid was chosen as the main reactive agent. Use of chelates was declined due to higher cost-to-efficiency ratio in comparison with the single-phase retarded stimulation fluid. The core flow tests along with 3D wormhole geometry visualization allowed optimizing the treatment parameters with respect to wormholing efficiency. The core flow test data were used to calibrate the matrix stimulation simulator with representative fluid-rock interaction curves. Due to interval length and heterogeneity, the use of diverters was recommended to increase wellbore coverage during the treatment. A polymer-free viscoelastic surfactant-based diverter was selected to alter the injection profile. An optimum treatment schedule developed in the matrix simulator included cleanout by coiled tubing equipped with a high-velocity jet, a low-rate coiled tubing matrix treatment, and a high-rate bullhead treatment. The designed treatment was successfully pumped. The post-stimulation production showed a significant increase in productivity index, without issues in cleanup. Similar workflow stimulation treatments were deployed on five subsequent wells, which have also shown very positive production response.\u0000 This work provides validation that a sound and rigorous engineering approach with advanced modeling and novel chemistry solutions can revive and significantly increase productivity of carbonate reservoirs. It was the first application of such a workflow and described stimulation fluid technology in Ukraine and Europe.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131714814","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. Jain, A. Morgenthal, M. Aman, M. Horton, S. Khan
A key component of well integrity is annular integrity. Much of the focus on this has been on establishing maximum and minimum pressure limits and designing envelopes under various well conditions encountered during well construction and subsequent production and injection operations. Many operators have established systems for operating wells within this design envelope to monitor for pressure excursions. However, abnormal annulus pressure behavior within the design envelope could be overlooked using a system that relies on limit monitoring and excursions. We propose a modeling workflow that combines novel deep learning techniques with statistical analysis to create online models which predict potential asset failures and alert on abnormal behavior such as abrupt pressure build up in producer and water injection wells’ A-Annulus. The model uses autoencoder architecture to learn the behavior of the wells during normal operating periods and generates alerts when it encounters new or abnormal behavior. The autoencoder architecture outputs a risk score aggregated over the residuals from all input features. Sequential Probability Ratio Test (SPRT) is performed on the risk score to determine abnormal regime during operation to raise alerts. These alerts can be used for root cause analysis based on the top contributors to the risk score. In our approach, we use feature thresholds as filters to determine normal operating periods for training the model. To simulate live conditions during model training, the historical time series data is divided into training and prediction windows. The model is trained on each training window and risk scores are created for the prediction window using a sliding window technique. To find the optimum model, a grid search is performed over a wide distribution of autoencoder and SPRT hyper-parameters. The models are scored based on recall, precision and lead time provided before a failure. We demonstrate this workflow using annulus pressure, downhole pressure, upstream choke pressure and upstream choke temperature as input to the model. The model does not require the physical properties of a well but uses historic well data lending itself to be applicable to already existing well stock. Next, we demonstrate using engineered features and synthesized data to efficiently train and score the models. During our experiments, we have explored several engineered features across multiple platforms and found that the correct set of engineered features can deliver a model that accurately alerts on asset abnormalities and potential failures. Our approach combines the strengths of deep learning techniques, statistical analytics and subject matter expertise to provide a framework that has demonstrated efficient scaling across multiple assets and sites and has potential application on a variety of oil and gas equipment.
{"title":"Creating an Auto-Encoder Based Predictive Maintenance Tool for Offshore Annulus Wells","authors":"A. Jain, A. Morgenthal, M. Aman, M. Horton, S. Khan","doi":"10.2118/210220-ms","DOIUrl":"https://doi.org/10.2118/210220-ms","url":null,"abstract":"\u0000 \u0000 \u0000 A key component of well integrity is annular integrity. Much of the focus on this has been on establishing maximum and minimum pressure limits and designing envelopes under various well conditions encountered during well construction and subsequent production and injection operations. Many operators have established systems for operating wells within this design envelope to monitor for pressure excursions. However, abnormal annulus pressure behavior within the design envelope could be overlooked using a system that relies on limit monitoring and excursions.\u0000 \u0000 \u0000 \u0000 We propose a modeling workflow that combines novel deep learning techniques with statistical analysis to create online models which predict potential asset failures and alert on abnormal behavior such as abrupt pressure build up in producer and water injection wells’ A-Annulus. The model uses autoencoder architecture to learn the behavior of the wells during normal operating periods and generates alerts when it encounters new or abnormal behavior.\u0000 The autoencoder architecture outputs a risk score aggregated over the residuals from all input features. Sequential Probability Ratio Test (SPRT) is performed on the risk score to determine abnormal regime during operation to raise alerts. These alerts can be used for root cause analysis based on the top contributors to the risk score. In our approach, we use feature thresholds as filters to determine normal operating periods for training the model. To simulate live conditions during model training, the historical time series data is divided into training and prediction windows. The model is trained on each training window and risk scores are created for the prediction window using a sliding window technique. To find the optimum model, a grid search is performed over a wide distribution of autoencoder and SPRT hyper-parameters. The models are scored based on recall, precision and lead time provided before a failure.\u0000 \u0000 \u0000 \u0000 We demonstrate this workflow using annulus pressure, downhole pressure, upstream choke pressure and upstream choke temperature as input to the model. The model does not require the physical properties of a well but uses historic well data lending itself to be applicable to already existing well stock. Next, we demonstrate using engineered features and synthesized data to efficiently train and score the models. During our experiments, we have explored several engineered features across multiple platforms and found that the correct set of engineered features can deliver a model that accurately alerts on asset abnormalities and potential failures.\u0000 \u0000 \u0000 \u0000 Our approach combines the strengths of deep learning techniques, statistical analytics and subject matter expertise to provide a framework that has demonstrated efficient scaling across multiple assets and sites and has potential application on a variety of oil and gas equipment.\u0000","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"21 6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126861171","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 DFIT-flowback test has shown some advantages in terms of running time and accuracy over typical injection tests such as DFITs specially in very low permeability formations. However, the success of the test depends largely on choosing an appropriate flowback rate to achieve acceptable results. The hidden assumption behind analysis is assuming uniform closure of fractures at the last step of the tests. Basically, the uniform closure is the only considered form of fracture closure in all the existing analyses for this test. Here, we show how adjusting flowback rates may change fracture closure mode and how to interpret field data accordingly. Often abnormality in the data acquired from pump-in/flowback tests have posed challenges in the widespread application of this test. Here, we use scaling analysis verified by numerical simulations to describe different situations may occur during this test and how to interpret abnormal data. Using scaling analysis does not require running complicated simulations and can provide quick solutions in field operations. Using this method can hopefully make DFIT-flowback more popular in the field.
{"title":"Selection of the Flowback Rate for DFIT-Flowback Test","authors":"Rui Wang, A. Dahi Taleghani","doi":"10.2118/210161-ms","DOIUrl":"https://doi.org/10.2118/210161-ms","url":null,"abstract":"\u0000 The DFIT-flowback test has shown some advantages in terms of running time and accuracy over typical injection tests such as DFITs specially in very low permeability formations. However, the success of the test depends largely on choosing an appropriate flowback rate to achieve acceptable results. The hidden assumption behind analysis is assuming uniform closure of fractures at the last step of the tests. Basically, the uniform closure is the only considered form of fracture closure in all the existing analyses for this test. Here, we show how adjusting flowback rates may change fracture closure mode and how to interpret field data accordingly. Often abnormality in the data acquired from pump-in/flowback tests have posed challenges in the widespread application of this test. Here, we use scaling analysis verified by numerical simulations to describe different situations may occur during this test and how to interpret abnormal data. Using scaling analysis does not require running complicated simulations and can provide quick solutions in field operations. Using this method can hopefully make DFIT-flowback more popular in the field.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126512424","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 success of large-scale geological storage of gases highly depends on the interfacial properties and gas adsorption capacity of the formation in question. To infer a clear understanding of the behavior of hydrogen (H2) and carbon dioxide (CO2) at conditions relevant to their storage, a systematic study relating pressure to the gas adsorption capacity of Jordanian shale formations is conducted. Additionally, the pendant drop method and the Axisymmetric Drop Shape Analysis technique are used to measure and evaluate brine-gas interfacial tension (IFT) as a function of pressure and salinity at 333 K. The wettability of Jordanian shale is also measured using the sessile drop method at different gas pressures and varying salinities. The results show that the adsorption capacity of shale is positively correlated with pressure. CO2 adsorption capacity is found to be orders of magnitude higher than that of H2 under similar conditions. Conversely, the measured CO2 diffusivity is an order of magnitude lower than the diffusivity of H2. The results also show that IFT increases with increasing salinity in both brine-gas systems and decreases with pressure, nevertheless, the reduction in IFT is much more evident in brine-CO2 systems. Additionally, the initially water-wet shale becomes highly CO2-wet at elevated pressures, while for H2, the shale remains water wet under all experimental conditions.
{"title":"Geological Storage of Carbon Dioxide and Hydrogen in Jordanian Shale Formations","authors":"H. Samara, Tatjana Von Ostrowski, P. Jaeger","doi":"10.2118/210202-ms","DOIUrl":"https://doi.org/10.2118/210202-ms","url":null,"abstract":"\u0000 The success of large-scale geological storage of gases highly depends on the interfacial properties and gas adsorption capacity of the formation in question. To infer a clear understanding of the behavior of hydrogen (H2) and carbon dioxide (CO2) at conditions relevant to their storage, a systematic study relating pressure to the gas adsorption capacity of Jordanian shale formations is conducted. Additionally, the pendant drop method and the Axisymmetric Drop Shape Analysis technique are used to measure and evaluate brine-gas interfacial tension (IFT) as a function of pressure and salinity at 333 K. The wettability of Jordanian shale is also measured using the sessile drop method at different gas pressures and varying salinities. The results show that the adsorption capacity of shale is positively correlated with pressure. CO2 adsorption capacity is found to be orders of magnitude higher than that of H2 under similar conditions. Conversely, the measured CO2 diffusivity is an order of magnitude lower than the diffusivity of H2. The results also show that IFT increases with increasing salinity in both brine-gas systems and decreases with pressure, nevertheless, the reduction in IFT is much more evident in brine-CO2 systems. Additionally, the initially water-wet shale becomes highly CO2-wet at elevated pressures, while for H2, the shale remains water wet under all experimental conditions.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128202261","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}
Traditional economic measures use chiefly net present value to compare on-going net revenue to plugging liabilities and other retirement liabilities, but operators onshore in the US plan to pay for plugging costs from cash flow. Liabilities have accumulated and continue to accumulate as operators defer plugging. At the same time, production declines, and cash flow tapers and becomes riskier. When retirement liabilities become significant compared to thinned cash flow, traditional yardsticks obscure the risk of ultimate insolvency. Future cash flow becomes insufficient to fund liabilities years before the present value flags the inversion. Recognizing the cash shortfall – which can occur surprisingly early when liabilities are allowed to accumulate – can fundamentally change the way the investment is viewed, valued, and managed. Planning, therefore, requires new economic yardsticks to characterize the nature of cash flows with large retirement obligations, what can be called "holdback" and its adjuncts. These yardsticks look differently at the timing and risk of asset retirement obligations, namely backward from the end of the projection. "Holdback" is analogous to payout but in reverse from the end of economic life. Related measures similarly use other conventional yardstick concepts in reverse to characterize the situation more fully and to help an operator avoid orphaning its abandonment liabilities to be paid by taxpayers.
{"title":"Economic Yardsticks for the End of Economic Life: Holdback and Its Adjuncts","authors":"D. Purvis","doi":"10.2118/210226-ms","DOIUrl":"https://doi.org/10.2118/210226-ms","url":null,"abstract":"\u0000 Traditional economic measures use chiefly net present value to compare on-going net revenue to plugging liabilities and other retirement liabilities, but operators onshore in the US plan to pay for plugging costs from cash flow. Liabilities have accumulated and continue to accumulate as operators defer plugging. At the same time, production declines, and cash flow tapers and becomes riskier.\u0000 When retirement liabilities become significant compared to thinned cash flow, traditional yardsticks obscure the risk of ultimate insolvency. Future cash flow becomes insufficient to fund liabilities years before the present value flags the inversion. Recognizing the cash shortfall – which can occur surprisingly early when liabilities are allowed to accumulate – can fundamentally change the way the investment is viewed, valued, and managed.\u0000 Planning, therefore, requires new economic yardsticks to characterize the nature of cash flows with large retirement obligations, what can be called \"holdback\" and its adjuncts. These yardsticks look differently at the timing and risk of asset retirement obligations, namely backward from the end of the projection. \"Holdback\" is analogous to payout but in reverse from the end of economic life. Related measures similarly use other conventional yardstick concepts in reverse to characterize the situation more fully and to help an operator avoid orphaning its abandonment liabilities to be paid by taxpayers.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114183405","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}
By using the continuum damage mechanics’ model and finite element numerical simulation technology, this paper studies natural fractures’ distribution within volcanic reservoir and presents numerical solution of contour of damage variable which represents distribution of natural fractures within target formations. Workflow of numerical calculation was proposed. These techniques were applied to investigate natural fractures distribution generated by tectonic movement within volcanic reservoir of an oilfield in west China. Quasi-brittle plastic damage model is used to simulate fractures generated by technical movement within volcanic formations given in this region. Initial-strain-method is used to simulate loading applied to target formation caused by tectonic movement instead of using boundary displacement loading. Different values of magnitude and orientations of principal strain components have been tested in order to find their proper values. Values of parameters of damage models are calibrated by matching numerical results of natural fractures’ distribution to those obtained by interpretation of seismic data. Principal results are: (1) in the upper Triassic Xiaoquangou formation reservoir and the lower Tiaohu formation reservoir, numerical solution of natural fractures’ distribution is consistent with those obtained from interpretation of seismic data. (2) The maximum value of damage variable of the upper Triassic Xiaoquangou formation is 0.2678, i.e., the degree of crushing is 26.78%. The width of the zone of damage localization is about 10 meters to 300 meter. The maximum value of damage variable in the lower Tiaohu formation is 0.2569, which is slightly less than that in the upper Xiaoquangou formation. (3) Within the target block, zones of natural fractures are mainly distributed in central-east part of the block. Therefore the planned new wells should be located in this part of the block. Zones of natural fractures in the west part of the target block are in the shape of narrow bands which are lack of connections, and thus this west side of the block is not a good place for new wells. This case study provides a best practice for identification of natural fractures within volcanic reservoir.
{"title":"Forward Modeling of Natural Fractures within Volcanic Reservoir by Using Continuum Damage Mechanics","authors":"Xinpu Shen","doi":"10.2118/210276-ms","DOIUrl":"https://doi.org/10.2118/210276-ms","url":null,"abstract":"\u0000 By using the continuum damage mechanics’ model and finite element numerical simulation technology, this paper studies natural fractures’ distribution within volcanic reservoir and presents numerical solution of contour of damage variable which represents distribution of natural fractures within target formations. Workflow of numerical calculation was proposed. These techniques were applied to investigate natural fractures distribution generated by tectonic movement within volcanic reservoir of an oilfield in west China. Quasi-brittle plastic damage model is used to simulate fractures generated by technical movement within volcanic formations given in this region. Initial-strain-method is used to simulate loading applied to target formation caused by tectonic movement instead of using boundary displacement loading. Different values of magnitude and orientations of principal strain components have been tested in order to find their proper values. Values of parameters of damage models are calibrated by matching numerical results of natural fractures’ distribution to those obtained by interpretation of seismic data. Principal results are: (1) in the upper Triassic Xiaoquangou formation reservoir and the lower Tiaohu formation reservoir, numerical solution of natural fractures’ distribution is consistent with those obtained from interpretation of seismic data. (2) The maximum value of damage variable of the upper Triassic Xiaoquangou formation is 0.2678, i.e., the degree of crushing is 26.78%. The width of the zone of damage localization is about 10 meters to 300 meter. The maximum value of damage variable in the lower Tiaohu formation is 0.2569, which is slightly less than that in the upper Xiaoquangou formation. (3) Within the target block, zones of natural fractures are mainly distributed in central-east part of the block. Therefore the planned new wells should be located in this part of the block. Zones of natural fractures in the west part of the target block are in the shape of narrow bands which are lack of connections, and thus this west side of the block is not a good place for new wells. This case study provides a best practice for identification of natural fractures within volcanic reservoir.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124031344","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In-well multiphase flow measurement continues to be a challenging task in the oil and gas industry. One promising technology to achieve this goal is the distributed acoustic sensing (DAS) system deployed downhole along a fiber. A DAS system is usually capable of measuring speed of sound (SoS) and, depending on the type of application and how the system is installed/configured, it may also measure flow velocity. In its current state, the DAS technology is still not fully explored in multiphase flow measurement for reasons including but not limited to the lack of flow algorithms and methodologies that can use measurements in a combinative and coherent approach. The current work introduces a game-changing methodology in applying the DAS and other sound measuring optical or electronic technologies to measure 3-phase flow. The 3-phase flow measurement methodology is based on the measurements of SoS at different locations along the well where the pressure is greater than the bubble-point pressure (P>Pb) at the first location and P
{"title":"Downhole Three-Phase Flow Measurement Using Sound Speed Measured by Local or Distributed Acoustic Sensing","authors":"Ö. H. Ünalmis","doi":"10.2118/210072-ms","DOIUrl":"https://doi.org/10.2118/210072-ms","url":null,"abstract":"\u0000 In-well multiphase flow measurement continues to be a challenging task in the oil and gas industry. One promising technology to achieve this goal is the distributed acoustic sensing (DAS) system deployed downhole along a fiber. A DAS system is usually capable of measuring speed of sound (SoS) and, depending on the type of application and how the system is installed/configured, it may also measure flow velocity. In its current state, the DAS technology is still not fully explored in multiphase flow measurement for reasons including but not limited to the lack of flow algorithms and methodologies that can use measurements in a combinative and coherent approach. The current work introduces a game-changing methodology in applying the DAS and other sound measuring optical or electronic technologies to measure 3-phase flow.\u0000 The 3-phase flow measurement methodology is based on the measurements of SoS at different locations along the well where the pressure is greater than the bubble-point pressure (P>Pb) at the first location and P<Pb at the second location. A bulk velocity measurement is also necessary at one of the locations, preferably at the second location. The minimum required measurements to resolve 3-phase flow rates are SoS at both locations (SoS1 and SoS2), pressure/temperature (P/T) values at both locations (P1, P2, T1, T2), and the bulk velocity measurement at the second location (V2). Using these measurements, phase flow rate calculations in a 3-phase flow are possible. A Lego-like approach may be used with various sensor technologies to obtain these required measurements which are then used in a consecutive manner in 2-phase and 3-phase solution domains obtained using Wood and Korteweg-Lamb equations.\u0000 The methodology is fully explained and the analytical solutions for 3-phase flow measurement is explicitly provided in a step-by-step approach. This approach provides significant advantages over the traditional methods. For example, SoS measurements along the well at multiple locations by using the same sensor technology or by combining different sensor technologies make this methodology highly flexible and applicable to custom-fit solutions. The method is independent of the sensor type as long as the sensors measure SoS, though the ideal systems that can adopt it easily and efficiently are DAS and optical flowmeters (OFMs). Additionally, a developing case history involving downhole OFMs installed in a North Sea field-wide application is discussed. The methodology may be implemented for a special case in which SoS is measured at the same location but at different times.\u0000 This new methodology in measuring downhole 3-phase flow furthers the understanding of downhole multiphase flow measurement. It can be implemented in existing wells with optical infrastructure by adding an appropriate topside optoelectronics system when needed at later phases of production.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121960921","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}
Wei Jian Yeap, Qi Zheng Lee, Anie Jelie, Nurfatin Adibah M Habib, Sulaiman Sidek, Zulkifli M Zin, Hazrina Abdul Rahman, Nicholas Foo Kwang Hui, Nik Zarina Suryana Nik Khansani, Khairul Nizam Idris, B. Madon, Mohd Najib Mustafa, Nur Baizura Zainal Abidin, Aleksandr Kovalov
Managing sand production has been a common problem and one of the most difficult challenges within the oil and gas industry. Various techniques are available to control sand production such as downhole sand screens. More than half of the wells in Malaysian fields are completed with downhole primary sand control or require sand management throughout their lifetime. To further aggravate the issue, most primary sand controls installed have suffered from failure after an extended period of production due to unacceptable high pressure drop in the near wellbore area which causes the screen to lose the ability to retain the formation sand particles. There are four (4) common mechanisms that can lead to the screen failure which include plugging, corrosion, erosion, and mechanical deformation. Erosion occurs when the formation particles hit the screen surface with high velocity or by continuous production through the screen openings. Operators are often compelled to rely on thru-tubing metallic sand screen to reactivate the idle wells back into production. However, most metallic sand screens suffer from sustainability issue due to excessive erosion especially for gas wells. Most operators have shifted their focus to maximize the screen lifetime against erosion, which consequently leads to the development of a novel sand screen design where an inventive coating consists of ceramic or hard metal amalgamation was applied by plasma spraying technique on the screen (i.e., outside surfaces facing the formation) to reinforce its resistance against severe erosive environment. An extensive development and verification program was conducted to select over 50 possible coating combinations, guarantee predefined slot size, assess corrosion resistance, and ascertain mechanical integrity of both the coating and screen. The technology has been considered and applied in Field A, offshore Borneo Island as remedial sand control due to its superior durability and resistance compared to metallic sand screen. Extensive technology hunting had been conducted by the operator to identify new erosion resistant thru-tubing sand screen for gas well application. As part of the overall project requirement, test facility was built by the Service Partners that consists of a flow loop testing designed to simulate accelerated erosive downhole condition with the combination of high flowrate and volume-controlled particle coalesced into an acceleration tube. The screens were tested for 60 hours at maximum velocity of 18 m/s during liquid erosion test and for 48 hours at maximum velocity of 80 m/s during gas erosion test. Rigorous analysis was conducted focusing on among others optical criteria, mass loss and sand retention tests (SRT) before and after the erosion test to verify the functionality and validate its performance prediction prior to the actual field application. Velocity calculation was also conducted using in-house and commercial software to adjudicate the design limit, to set
{"title":"Pioneering Application of Plasma Spray Coatings to Improve the Erosion Resistance of Rod Based Wedge Wire Screen","authors":"Wei Jian Yeap, Qi Zheng Lee, Anie Jelie, Nurfatin Adibah M Habib, Sulaiman Sidek, Zulkifli M Zin, Hazrina Abdul Rahman, Nicholas Foo Kwang Hui, Nik Zarina Suryana Nik Khansani, Khairul Nizam Idris, B. Madon, Mohd Najib Mustafa, Nur Baizura Zainal Abidin, Aleksandr Kovalov","doi":"10.2118/210377-ms","DOIUrl":"https://doi.org/10.2118/210377-ms","url":null,"abstract":"\u0000 Managing sand production has been a common problem and one of the most difficult challenges within the oil and gas industry. Various techniques are available to control sand production such as downhole sand screens. More than half of the wells in Malaysian fields are completed with downhole primary sand control or require sand management throughout their lifetime. To further aggravate the issue, most primary sand controls installed have suffered from failure after an extended period of production due to unacceptable high pressure drop in the near wellbore area which causes the screen to lose the ability to retain the formation sand particles. There are four (4) common mechanisms that can lead to the screen failure which include plugging, corrosion, erosion, and mechanical deformation. Erosion occurs when the formation particles hit the screen surface with high velocity or by continuous production through the screen openings. Operators are often compelled to rely on thru-tubing metallic sand screen to reactivate the idle wells back into production. However, most metallic sand screens suffer from sustainability issue due to excessive erosion especially for gas wells. Most operators have shifted their focus to maximize the screen lifetime against erosion, which consequently leads to the development of a novel sand screen design where an inventive coating consists of ceramic or hard metal amalgamation was applied by plasma spraying technique on the screen (i.e., outside surfaces facing the formation) to reinforce its resistance against severe erosive environment. An extensive development and verification program was conducted to select over 50 possible coating combinations, guarantee predefined slot size, assess corrosion resistance, and ascertain mechanical integrity of both the coating and screen. The technology has been considered and applied in Field A, offshore Borneo Island as remedial sand control due to its superior durability and resistance compared to metallic sand screen.\u0000 Extensive technology hunting had been conducted by the operator to identify new erosion resistant thru-tubing sand screen for gas well application. As part of the overall project requirement, test facility was built by the Service Partners that consists of a flow loop testing designed to simulate accelerated erosive downhole condition with the combination of high flowrate and volume-controlled particle coalesced into an acceleration tube. The screens were tested for 60 hours at maximum velocity of 18 m/s during liquid erosion test and for 48 hours at maximum velocity of 80 m/s during gas erosion test. Rigorous analysis was conducted focusing on among others optical criteria, mass loss and sand retention tests (SRT) before and after the erosion test to verify the functionality and validate its performance prediction prior to the actual field application. Velocity calculation was also conducted using in-house and commercial software to adjudicate the design limit, to set","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"134 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"117293649","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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