O. H. Khan, Samad Ali, M. A. Elfeel, S. Biniwale, R. Dandekar
Effective asset-level decision-making relies on a sound understanding of the complex sub-components of the hydrocarbon production system, their interactions, along with an overarching evaluation of the asset's economic performance under different operational strategies. This is especially true for the LNG upstream production system, from the reservoir to the LNG export facility, due to the complex constraints imposed by the gas processing and liquefaction plant. The evolution of the production characteristics over the asset lifetime poses a challenge to the continued and efficient operation of the LNG facility. To ensure a competitive landed LNG cost for the customer, the economics of the production system must be optimized, particularly the liquefaction costs which form the bulk of the operating expenditure of the LNG supply chain. Forecasting and optimizing the production of natural gas liquids helps improve the asset economics. The risks due to demand uncertainty must also be assessed when comparing development alternatives. This paper describes the application of a comprehensive field management framework that can create an integrated virtual asset by coupling reservoir, wells, network, facilities, and economics models and provides an advisory system for efficient asset management. In continuation of previously published work (Khan, Ali, Elfeel, Biniwale, & Dandekar, 2020), this paper focuses on the integration of a steady-state process simulation model that provides high-fidelity thermo-physical property prediction to represent the gas treatment and LNG plant operation. This is accomplished through the Python-enabled extensibility and generic capability of the field management system. This is demonstrated on a complex LNG asset that is fed by sour gas of varying compositions from multiple reservoirs. An asset wide economics model is also incorporated in the integrated model to assess the economic performance and viability of competing strategies. The impact of changes to the wells and production network system on LNG plant operation is analyzed along with the long-term evolution of the inlet stream specifications. The end-to-end integration enables component tracking throughout the flowing system over time which is useful for contractual and environmental compliance. Integrated economics captures costs at all levels and enables the comparison of development alternatives. Flexible integration of the dedicated domain models reveals interactions that can be otherwise overlooked. The ability of the integrated field management system to allow the modeling of the sub-systems at the ‘right’ level of fidelity makes the solution versatile and adaptable. In addition, the integration of economics enables the maximization of total asset value by improving decision making.
{"title":"Integrated Field Management System for LNG Assets: Maximizing Asset Value Through Representative End-To-End Modeling","authors":"O. H. Khan, Samad Ali, M. A. Elfeel, S. Biniwale, R. Dandekar","doi":"10.2118/205969-ms","DOIUrl":"https://doi.org/10.2118/205969-ms","url":null,"abstract":"\u0000 Effective asset-level decision-making relies on a sound understanding of the complex sub-components of the hydrocarbon production system, their interactions, along with an overarching evaluation of the asset's economic performance under different operational strategies. This is especially true for the LNG upstream production system, from the reservoir to the LNG export facility, due to the complex constraints imposed by the gas processing and liquefaction plant. The evolution of the production characteristics over the asset lifetime poses a challenge to the continued and efficient operation of the LNG facility. To ensure a competitive landed LNG cost for the customer, the economics of the production system must be optimized, particularly the liquefaction costs which form the bulk of the operating expenditure of the LNG supply chain. Forecasting and optimizing the production of natural gas liquids helps improve the asset economics. The risks due to demand uncertainty must also be assessed when comparing development alternatives.\u0000 This paper describes the application of a comprehensive field management framework that can create an integrated virtual asset by coupling reservoir, wells, network, facilities, and economics models and provides an advisory system for efficient asset management. In continuation of previously published work (Khan, Ali, Elfeel, Biniwale, & Dandekar, 2020), this paper focuses on the integration of a steady-state process simulation model that provides high-fidelity thermo-physical property prediction to represent the gas treatment and LNG plant operation. This is accomplished through the Python-enabled extensibility and generic capability of the field management system. This is demonstrated on a complex LNG asset that is fed by sour gas of varying compositions from multiple reservoirs. An asset wide economics model is also incorporated in the integrated model to assess the economic performance and viability of competing strategies.\u0000 The impact of changes to the wells and production network system on LNG plant operation is analyzed along with the long-term evolution of the inlet stream specifications. The end-to-end integration enables component tracking throughout the flowing system over time which is useful for contractual and environmental compliance. Integrated economics captures costs at all levels and enables the comparison of development alternatives.\u0000 Flexible integration of the dedicated domain models reveals interactions that can be otherwise overlooked. The ability of the integrated field management system to allow the modeling of the sub-systems at the ‘right’ level of fidelity makes the solution versatile and adaptable. In addition, the integration of economics enables the maximization of total asset value by improving decision making.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91350536","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}
With the advent of increased measurements and instrumentation in oil and gas upstream production infrastructure; in the wellbore, in subsea and on surface processing facilities, data integration from all sources can be used more effectively in producing consistent and robust production profiles. The proposed data integration methodology aims at identifying the sources of measurement and process errors and removing them from the system. This ensures quasi error-free data when driving critical applications such as well rate determination from virtual and multiphase meters, and production allocation schemes, to name few. Confidence in the data is further enhanced by quantifying the uncertainty of each measured and unmeasured variable. Advanced Data Validation and Reconciliation (DVR) methodology uses data redundancy to correct measurements. As more data is ingested in a modeling system the statistical aspect attached to each measurement becomes an important source of information to further improve its precision. DVR is an equation-based calculation process. It combines data redundancy and conservation laws to correct measurements and convert them into accurate and reliable information. The methodology is used in upstream oil & gas, refineries and gas plants, petrochemical plants as well as power plants including nuclear. DVR detects faulty sensors and identifies degradation of equipment performance. As such, it provides more robust inputs to operations, simulation, and automation processes. The DVR methodology is presented using field data from a producing offshore field. The discussion details the design and implementation of a DVR system to integrate all available field data from the wellbore and surface facilities. The integrated data in this end-to-end evaluation includes reservoir productivity parameters, downhole and wellhead measurements, tuned vertical lift models, artificial lift devices, fluid sample analysis and thermodynamic models, and top facility process measurements. The automated DVR iterative runs solve all conservation equations simultaneously when determining the production flowrates "true values" and their uncertainties. The DVR field application is successfully used in real-time to ensure data consistency across a number of production tasks including the continual surveillance of the critical components of the production facility, the evaluation and validation of well tests using multiphase flow metering, the virtual flow metering of each well, the modeling of fluid phase behavior in the well and in the multistage separation facility, and performing the back allocation from sales meters to individual wells.
{"title":"The Application of Data Validation and Reconciliation to Upstream Production Measurement Integration and Surveillance – Field Study","authors":"V. Bent, A. Amin, Timothy Jadot","doi":"10.2118/205934-ms","DOIUrl":"https://doi.org/10.2118/205934-ms","url":null,"abstract":"\u0000 With the advent of increased measurements and instrumentation in oil and gas upstream production infrastructure; in the wellbore, in subsea and on surface processing facilities, data integration from all sources can be used more effectively in producing consistent and robust production profiles. The proposed data integration methodology aims at identifying the sources of measurement and process errors and removing them from the system. This ensures quasi error-free data when driving critical applications such as well rate determination from virtual and multiphase meters, and production allocation schemes, to name few. Confidence in the data is further enhanced by quantifying the uncertainty of each measured and unmeasured variable.\u0000 Advanced Data Validation and Reconciliation (DVR) methodology uses data redundancy to correct measurements. As more data is ingested in a modeling system the statistical aspect attached to each measurement becomes an important source of information to further improve its precision. DVR is an equation-based calculation process. It combines data redundancy and conservation laws to correct measurements and convert them into accurate and reliable information. The methodology is used in upstream oil & gas, refineries and gas plants, petrochemical plants as well as power plants including nuclear. DVR detects faulty sensors and identifies degradation of equipment performance. As such, it provides more robust inputs to operations, simulation, and automation processes.\u0000 The DVR methodology is presented using field data from a producing offshore field. The discussion details the design and implementation of a DVR system to integrate all available field data from the wellbore and surface facilities. The integrated data in this end-to-end evaluation includes reservoir productivity parameters, downhole and wellhead measurements, tuned vertical lift models, artificial lift devices, fluid sample analysis and thermodynamic models, and top facility process measurements. The automated DVR iterative runs solve all conservation equations simultaneously when determining the production flowrates \"true values\" and their uncertainties. The DVR field application is successfully used in real-time to ensure data consistency across a number of production tasks including the continual surveillance of the critical components of the production facility, the evaluation and validation of well tests using multiphase flow metering, the virtual flow metering of each well, the modeling of fluid phase behavior in the well and in the multistage separation facility, and performing the back allocation from sales meters to individual wells.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88594624","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}
Hongfu Shi, Zhongbo Xu, H. Cai, Wenjun Zhang, Yunting Li
At present, the Bohai Oilfield has entered the late stage of high water cut, with a high degree of flooding and an average water cut of more than 80%. Horizontal wells were widely used in tapping the potentials of high water-cut oilfields with avoiding local water flooding, accurately develop enrichment of remaining oil, and improving initial productivity. Until 2020, there are more than 1,200 horizontal wells in the Bohai Oilfield, with daily production accounting for more than 40% of the entire oilfield. However, mainly continental deposits, strong heterogeneity, heavy oil, relatively large mobility ratio, long-term water flooding, and large liquid production have resulted in the obvious dominant channels in the formation, intensified ineffective water circulation, and low oil recovery. The application of horizontal wells faces huge challenges due to the serious water flooding and the prevalence of thief zones. Inflow Control Device (ICD) is becoming more and more prevalent in bottom water reservoirs as it can delay the water breakthrough and significantly improve the economic benefit of a project by producing more oil and less water. The strong microscopic heterogeneity along the horizontal water channeling outside the screen or water channeling along the annulus between the screen and ICD tubular is responsible for the short term even ineffective effect of conventional ICD. Based on the review of the conventional ICD application in the Q oilfield, a workflow is present to design and optimize hybrid ICD to increase the success probability of the validity period of water control.
{"title":"How to Block the Water Channels by High-Density Polyethylene Particles Supersaturated Filling Out-of-Screen and Inflow Control Device in Heterogeneous Sandstone Reservoir","authors":"Hongfu Shi, Zhongbo Xu, H. Cai, Wenjun Zhang, Yunting Li","doi":"10.2118/205952-ms","DOIUrl":"https://doi.org/10.2118/205952-ms","url":null,"abstract":"\u0000 At present, the Bohai Oilfield has entered the late stage of high water cut, with a high degree of flooding and an average water cut of more than 80%. Horizontal wells were widely used in tapping the potentials of high water-cut oilfields with avoiding local water flooding, accurately develop enrichment of remaining oil, and improving initial productivity. Until 2020, there are more than 1,200 horizontal wells in the Bohai Oilfield, with daily production accounting for more than 40% of the entire oilfield. However, mainly continental deposits, strong heterogeneity, heavy oil, relatively large mobility ratio, long-term water flooding, and large liquid production have resulted in the obvious dominant channels in the formation, intensified ineffective water circulation, and low oil recovery. The application of horizontal wells faces huge challenges due to the serious water flooding and the prevalence of thief zones.\u0000 Inflow Control Device (ICD) is becoming more and more prevalent in bottom water reservoirs as it can delay the water breakthrough and significantly improve the economic benefit of a project by producing more oil and less water. The strong microscopic heterogeneity along the horizontal water channeling outside the screen or water channeling along the annulus between the screen and ICD tubular is responsible for the short term even ineffective effect of conventional ICD. Based on the review of the conventional ICD application in the Q oilfield, a workflow is present to design and optimize hybrid ICD to increase the success probability of the validity period of water control.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90972022","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}
Recent papers on pre-frac tests have proposed fracture closure pressure interpretation methodologies that lead to an earlier, higher stress estimation than the ones estimated from well-established practices. These early time estimations based on the fracture compliance method lead the practitioner to utilize unrealistic permeability, stress, and fracture pressure models. This, in turn, has a severe impact on the modeled fracture geometries which hinders the hydraulic fracture optimization process. A multi-basin analysis of pre-frac tests from the North Sea, Europe, Russia, North Africa and South America is presented to support traditional closure estimation techniques. The validity of traditional minimum stress interpretation techniques will be reinforced through multiple case histories by comparing permeability estimates from the time required for the fracture to achieve closure during diagnostic injections, after-closure analysis, core, pressure build up and rate transient analysis. Results will be supported further by fiber optics and production logging tool (PLT) driven flow allocation, fracture geometry assessment through micro seismic and sonic anisotropy, and diagnostic injections numerical inversions.
{"title":"DFIT: An Interdisciplinary Validation of Fracture Closure Pressure Interpretation Across Multiple Basins","authors":"H. Buijs","doi":"10.2118/206239-ms","DOIUrl":"https://doi.org/10.2118/206239-ms","url":null,"abstract":"\u0000 Recent papers on pre-frac tests have proposed fracture closure pressure interpretation methodologies that lead to an earlier, higher stress estimation than the ones estimated from well-established practices. These early time estimations based on the fracture compliance method lead the practitioner to utilize unrealistic permeability, stress, and fracture pressure models. This, in turn, has a severe impact on the modeled fracture geometries which hinders the hydraulic fracture optimization process. A multi-basin analysis of pre-frac tests from the North Sea, Europe, Russia, North Africa and South America is presented to support traditional closure estimation techniques. The validity of traditional minimum stress interpretation techniques will be reinforced through multiple case histories by comparing permeability estimates from the time required for the fracture to achieve closure during diagnostic injections, after-closure analysis, core, pressure build up and rate transient analysis. Results will be supported further by fiber optics and production logging tool (PLT) driven flow allocation, fracture geometry assessment through micro seismic and sonic anisotropy, and diagnostic injections numerical inversions.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"21 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91554402","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Most lab-scale acidizing experiments are performed in core samples with 100% water saturation conditions and at pore pressures around 1100 psi. However, this is seldom the case on the field, where different saturation conditions exist with high temperature and pressure conditions. Carbon-di-Oxide (CO2), a by-product evolved during the acidizing process, is long thought to behave inertly during the acidizing process. Recent investigations reveal that the presence of CO2 dynamically changes the behavior of wormhole patterns and acid efficiency. A compositional simulation technique was adopted to understand the process thoroughly. A validated compositional numerical model capable of replicating acidizing experiments at the core-scale level, in fully aqueous environments described in published literature was utilized in this study. The numerical model was extended to a three-phase environment and applied at the field scale level to monitor and evaluate the impacts of evolved CO2 during the carbonate acidizing processes. Lessons learned from the lab-scale were tested at the field-scale scenario via a numerical model with radial coordinates. Contrary to popular belief, high pore pressures of 1,000 psi and above are not sufficient to keep all the evolved CO2 in solution. The presence of CO2 as a separate phase hinders acid efficiency. The reach or extent of the evolved CO2 is shown to exist only near the damage zone and seldom penetrates the reservoir matrix. Based on the field scale model's predictions, this study warrants conducting acidizing experiments at the laboratory level, at precisely similar pressure, temperature, and salinity conditions faced in the near-wellbore region, and urges the application of compositional modeling techniques to account for CO2 evolution, while studying and predicting matrix acidizing jobs.
{"title":"The Role of CO2 in Carbonate Acidizing at the Field Scale – A Multi-Phase Perspective","authors":"H. Kumar, Sajjaat Muhemmed, H. Nasr-El-Din","doi":"10.2118/206033-ms","DOIUrl":"https://doi.org/10.2118/206033-ms","url":null,"abstract":"\u0000 Most lab-scale acidizing experiments are performed in core samples with 100% water saturation conditions and at pore pressures around 1100 psi. However, this is seldom the case on the field, where different saturation conditions exist with high temperature and pressure conditions. Carbon-di-Oxide (CO2), a by-product evolved during the acidizing process, is long thought to behave inertly during the acidizing process. Recent investigations reveal that the presence of CO2 dynamically changes the behavior of wormhole patterns and acid efficiency.\u0000 A compositional simulation technique was adopted to understand the process thoroughly. A validated compositional numerical model capable of replicating acidizing experiments at the core-scale level, in fully aqueous environments described in published literature was utilized in this study. The numerical model was extended to a three-phase environment and applied at the field scale level to monitor and evaluate the impacts of evolved CO2 during the carbonate acidizing processes. Lessons learned from the lab-scale were tested at the field-scale scenario via a numerical model with radial coordinates.\u0000 Contrary to popular belief, high pore pressures of 1,000 psi and above are not sufficient to keep all the evolved CO2 in solution. The presence of CO2 as a separate phase hinders acid efficiency. The reach or extent of the evolved CO2 is shown to exist only near the damage zone and seldom penetrates the reservoir matrix. Based on the field scale model's predictions, this study warrants conducting acidizing experiments at the laboratory level, at precisely similar pressure, temperature, and salinity conditions faced in the near-wellbore region, and urges the application of compositional modeling techniques to account for CO2 evolution, while studying and predicting matrix acidizing jobs.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87519760","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 critical component of natural gas in organic-rich shales is adsorbed gas within organic matter. Quantification of adsorbed gas is essential for reliable estimates of gas-in-place in shale reservoirs. However, conventional high-pressure adsorption measurements for coal on the volumetric method are prone to error when applied to characterize sorption kinetics in shale-gas systems due to limited adsorption capacity and finer pores of shale matrix. An innovated laboratory apparatus and measurement procedures have been developed for accurate determination of the relatively small amount of adsorbed gas in the Marcellus shale sample. The custom-built volumetric apparatus is a differential unit composed of two identical single-sided units (one blank and one adsorption side) connected with a differential pressure transducer. The scale of the differential pressure transducer is ± 50 psi, a hundred-fold smaller than the absolute pressure transducer measuring to 5000 psi, leading to a significant increase in the accuracy of adsorption measurement. Methane adsorption isotherms on Marcellus shale are measured at 303, 313, 323 and 333 K with pressure up to 3000 psi. A fugacity-based Dubinin-Astakhov (D-A) isotherm is implemented to correct for the non-ideality and predict the temperature-dependence of supercritical gas sorption. The Marcellus shale studied displays generally linear correlations between adsorption capacity and pressure over the range of temperature and pressure investigated, indicating the presence of a solute gas component. It is noted that the condensed phase gas storage exists as the adsorbed gas on shale surface and dissolved gas in kerogen, where the solute gas amount is proportional to the partial pressure of that gas above the solution. To our best understanding, it is the first time to observe the contribution of dissolved gas to total gas storage. With adsorption potential being modeled by a temperature dependence expression, the D-A isotherm can successfully describe supercritical gas sorption for shale at multiple temperatures. Adsorption capacity remarkably decreases with temperature attributed to the isosteric heat of adsorption. Lastly, the wide applicability of the proposed fugacity-based D-A model is also tested for literature adsorption data on Woodford, Barnett, and Devonian shale. Overall, the fugacity-based D-A isotherm provides precise representations of the temperature-dependent gas adsorption on shales investigated in this work. The application of the proposed adsorption model allows predicting adsorption data at multiple temperatures based on the adsorption data collected at a single temperature. This study lays the foundation for accurate evaluation of gas storage in shale.
{"title":"Quantification of Temperature-Dependent Sorption Kinetics in Shale Gas Reservoirs: Experiment and Theory","authors":"Yun Yang, Shimin Liu","doi":"10.2118/205897-ms","DOIUrl":"https://doi.org/10.2118/205897-ms","url":null,"abstract":"\u0000 A critical component of natural gas in organic-rich shales is adsorbed gas within organic matter. Quantification of adsorbed gas is essential for reliable estimates of gas-in-place in shale reservoirs. However, conventional high-pressure adsorption measurements for coal on the volumetric method are prone to error when applied to characterize sorption kinetics in shale-gas systems due to limited adsorption capacity and finer pores of shale matrix. An innovated laboratory apparatus and measurement procedures have been developed for accurate determination of the relatively small amount of adsorbed gas in the Marcellus shale sample.\u0000 The custom-built volumetric apparatus is a differential unit composed of two identical single-sided units (one blank and one adsorption side) connected with a differential pressure transducer. The scale of the differential pressure transducer is ± 50 psi, a hundred-fold smaller than the absolute pressure transducer measuring to 5000 psi, leading to a significant increase in the accuracy of adsorption measurement. Methane adsorption isotherms on Marcellus shale are measured at 303, 313, 323 and 333 K with pressure up to 3000 psi. A fugacity-based Dubinin-Astakhov (D-A) isotherm is implemented to correct for the non-ideality and predict the temperature-dependence of supercritical gas sorption.\u0000 The Marcellus shale studied displays generally linear correlations between adsorption capacity and pressure over the range of temperature and pressure investigated, indicating the presence of a solute gas component. It is noted that the condensed phase gas storage exists as the adsorbed gas on shale surface and dissolved gas in kerogen, where the solute gas amount is proportional to the partial pressure of that gas above the solution. To our best understanding, it is the first time to observe the contribution of dissolved gas to total gas storage. With adsorption potential being modeled by a temperature dependence expression, the D-A isotherm can successfully describe supercritical gas sorption for shale at multiple temperatures. Adsorption capacity remarkably decreases with temperature attributed to the isosteric heat of adsorption. Lastly, the wide applicability of the proposed fugacity-based D-A model is also tested for literature adsorption data on Woodford, Barnett, and Devonian shale. Overall, the fugacity-based D-A isotherm provides precise representations of the temperature-dependent gas adsorption on shales investigated in this work. The application of the proposed adsorption model allows predicting adsorption data at multiple temperatures based on the adsorption data collected at a single temperature. This study lays the foundation for accurate evaluation of gas storage in shale.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75212814","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}
Acid fracturing is a preferred method of stimulating low permeability limestone formations throughout the world. The treatment consists of pumping alternating cycles of viscous pad and acid to promote differential etching, thereby creating a conductive acid-etched fracture. Acid-type, pad and acid volumes, and the injection rates in the designed pump schedule are based on treatment objectives, rock-types and in-situ conditions such as temperatures, in-situ stress, proximity to water-bearing layers, and others. During the acid fracturing treatment, the acid-rock interaction is often marked by signature pressure responses, that are a combined outcome of acid reaction kinetics, responses to changes in fluid viscosity and densities, fluid-frictional drop in narrow hydraulic fractures, and other such parameters. This paper focuses on interpretation of bottomhole pressures during acid fracturing treatment to separate these individual effects and determine the effectiveness of the treatment. Unlike propped fracturing treatments where most fracturing treatments result in net pressure gain, acid fracturing treatments seldom result in net pressure increase at the end of the treatment because the in-situ stresses are generally relieved during the rock-dissolution and fracture width creation process that results from acid-mineral reactions. Not only is the extent of stress relief evident from the difference in the start and the end of the treatment instantaneous shut-in pressures, the loss of stresses is also apparent during the treatment itself, especially in jobs where the treatment data is constantly monitored and evaluated in real-time. The study reveals that the changes in pressure responses with the onset of acid in the formation can be successfully used to determine the effectiveness of treatment design and can aid in carrying out informed changes during the treatment. Better understanding of these responses can also lead to more effective treatment designs for future jobs. The interpretation developed in the study can be applied to most of the acid fracturing treatments that are pumped worldwide.
{"title":"Pressure Interpretations in Acid Fracturing Treatments","authors":"V. Pandey","doi":"10.2118/205990-ms","DOIUrl":"https://doi.org/10.2118/205990-ms","url":null,"abstract":"\u0000 Acid fracturing is a preferred method of stimulating low permeability limestone formations throughout the world. The treatment consists of pumping alternating cycles of viscous pad and acid to promote differential etching, thereby creating a conductive acid-etched fracture.\u0000 Acid-type, pad and acid volumes, and the injection rates in the designed pump schedule are based on treatment objectives, rock-types and in-situ conditions such as temperatures, in-situ stress, proximity to water-bearing layers, and others. During the acid fracturing treatment, the acid-rock interaction is often marked by signature pressure responses, that are a combined outcome of acid reaction kinetics, responses to changes in fluid viscosity and densities, fluid-frictional drop in narrow hydraulic fractures, and other such parameters. This paper focuses on interpretation of bottomhole pressures during acid fracturing treatment to separate these individual effects and determine the effectiveness of the treatment.\u0000 Unlike propped fracturing treatments where most fracturing treatments result in net pressure gain, acid fracturing treatments seldom result in net pressure increase at the end of the treatment because the in-situ stresses are generally relieved during the rock-dissolution and fracture width creation process that results from acid-mineral reactions. Not only is the extent of stress relief evident from the difference in the start and the end of the treatment instantaneous shut-in pressures, the loss of stresses is also apparent during the treatment itself, especially in jobs where the treatment data is constantly monitored and evaluated in real-time. The study reveals that the changes in pressure responses with the onset of acid in the formation can be successfully used to determine the effectiveness of treatment design and can aid in carrying out informed changes during the treatment. Better understanding of these responses can also lead to more effective treatment designs for future jobs.\u0000 The interpretation developed in the study can be applied to most of the acid fracturing treatments that are pumped worldwide.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84850929","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}
Thitaree Lertliangchai, B. Dindoruk, Ligang Lu, Xi Yang
Dew point pressure (DPP) is a key variable that may be needed to predict the condensate to gas ratio behavior of a reservoir along with some production/completion related issues and calibrate/constrain the EOS models for integrated modeling. However, DPP is a challenging property in terms of its predictability. Recognizing the complexities, we present a state-of-the-art method for DPP prediction using advanced machine learning (ML) techniques. We compare the outcomes of our methodology with that of published empirical correlation-based approaches on two datasets with small sizes and different inputs. Our ML method noticeably outperforms the correlation-based predictors while also showing its flexibility and robustness even with small training datasets provided various classes of fluids are represented within the datasets. We have collected the condensate PVT data from public domain resources and GeoMark RFDBASE containing dew point pressure (the target variable), and the compositional data (mole percentage of each component), temperature, molecular weight (MW), MW and specific gravity (SG) of heptane plus as input variables. Using domain knowledge, before embarking the study, we have extensively checked the measurement quality and the outcomes using statistical techniques. We then apply advanced ML techniques to train predictive models with cross-validation to avoid overfitting the models to the small datasets. We compare our models against the best published DDP predictors with empirical correlation-based techniques. For fair comparisons, the correlation-based predictors are also trained using the underlying datasets. In order to improve the outcomes and using the generalized input data, pseudo-critical properties and artificial proxy features are also employed.
{"title":"A Comparative Analysis of the Prediction of Gas Condensate Dew Point Pressure Using Advanced Machine Learning Algorithms","authors":"Thitaree Lertliangchai, B. Dindoruk, Ligang Lu, Xi Yang","doi":"10.2118/205997-ms","DOIUrl":"https://doi.org/10.2118/205997-ms","url":null,"abstract":"\u0000 Dew point pressure (DPP) is a key variable that may be needed to predict the condensate to gas ratio behavior of a reservoir along with some production/completion related issues and calibrate/constrain the EOS models for integrated modeling. However, DPP is a challenging property in terms of its predictability. Recognizing the complexities, we present a state-of-the-art method for DPP prediction using advanced machine learning (ML) techniques. We compare the outcomes of our methodology with that of published empirical correlation-based approaches on two datasets with small sizes and different inputs. Our ML method noticeably outperforms the correlation-based predictors while also showing its flexibility and robustness even with small training datasets provided various classes of fluids are represented within the datasets. We have collected the condensate PVT data from public domain resources and GeoMark RFDBASE containing dew point pressure (the target variable), and the compositional data (mole percentage of each component), temperature, molecular weight (MW), MW and specific gravity (SG) of heptane plus as input variables. Using domain knowledge, before embarking the study, we have extensively checked the measurement quality and the outcomes using statistical techniques. We then apply advanced ML techniques to train predictive models with cross-validation to avoid overfitting the models to the small datasets. We compare our models against the best published DDP predictors with empirical correlation-based techniques. For fair comparisons, the correlation-based predictors are also trained using the underlying datasets. In order to improve the outcomes and using the generalized input data, pseudo-critical properties and artificial proxy features are also employed.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82543890","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 paper develops a mathematical model for rate transient analysis in multi-stage fractured horizontal wells with considering weak fluid supply. A new concept of additional skin factor is introduced in the proposed model to characterize the fluid supply. Then, the mathematical model are solved by using the perturbation transformation, point source integration method, Laplace transform, and numerical inversion, while the fracture flow equations are solved by fracture discretization and superposition principle. First, the flow regimes of multi-stage fractured horizontal wells with considering weak fluid supply are identified based on the rate transient behaviors, including wellbore storage and skin effect, bilinear flow, linear flow, pseudo-radial flow in the fractured zone, interface skin effect, pseudo-radial flow in the original zone, and boundary-dominated flow. The effect of additional interface skin makes the double logarithmic curve of production rate appear an abrupt "overlap". The results of the sensitivity study show that the abrupt "overlap" becomes more obvious with the increase of the fracture conductivity, fracture number, the stress sensitivity coefficient, especially the interface skin. Finally, the proposed mathematical model is used to perform a case study on the production data of actual tight-gas wells from the Ordos Basin. The interface skin factor, fracture half-length, fracture conductivity, and boundary radius are evaluated. Through the proposed model, the characteristics of weak fluid supply in tight gas reservoirs are fully understood.
{"title":"Mathematical Model for Rate Transient Analysis with Additional Interface Skin for Fractured Horizontal Well With Weak Fluid Supply","authors":"Jiali Zhang, X. Liao, Nai Cao","doi":"10.2118/206169-ms","DOIUrl":"https://doi.org/10.2118/206169-ms","url":null,"abstract":"This paper develops a mathematical model for rate transient analysis in multi-stage fractured horizontal wells with considering weak fluid supply. A new concept of additional skin factor is introduced in the proposed model to characterize the fluid supply. Then, the mathematical model are solved by using the perturbation transformation, point source integration method, Laplace transform, and numerical inversion, while the fracture flow equations are solved by fracture discretization and superposition principle. First, the flow regimes of multi-stage fractured horizontal wells with considering weak fluid supply are identified based on the rate transient behaviors, including wellbore storage and skin effect, bilinear flow, linear flow, pseudo-radial flow in the fractured zone, interface skin effect, pseudo-radial flow in the original zone, and boundary-dominated flow. The effect of additional interface skin makes the double logarithmic curve of production rate appear an abrupt \"overlap\". The results of the sensitivity study show that the abrupt \"overlap\" becomes more obvious with the increase of the fracture conductivity, fracture number, the stress sensitivity coefficient, especially the interface skin. Finally, the proposed mathematical model is used to perform a case study on the production data of actual tight-gas wells from the Ordos Basin. The interface skin factor, fracture half-length, fracture conductivity, and boundary radius are evaluated. Through the proposed model, the characteristics of weak fluid supply in tight gas reservoirs are fully understood.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82759157","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. Alsaeedi, M. Elabrashy, M. Alzeyoudi, M. Albadi, Sandeep Soni, Jose Isambertt, Deepak Tripathi
The concept of integrated modeling and digital transformation has grown within the oil and gas industry over the past decade and every such digital transformation has its own set of challenges from which significant learnings can be derived to enhance the knowledge base of the industry. This paper encompasses the successful achievement journey from the UAE's first end to end standardized workflow- based digital transformation in a giant gas producing asset, where several key challenges and learnings have been summarized that are originated from a unique project for a giant gas-condensate asset. The role and importance from multiple business stakeholders such as the planning, engineering, operations and performance teams was imperative to establish a collaborative working philosophy and a detailed specification document, the end-to-end solution, functional and non-functional requirements were captured and aligned with end-user needs. Firstly, a detailed offline phase along with focused efforts in understanding data-quality and establishing representative base-models, was key to enhance the benefit-realization of the integrated platform. Secondly, the online implementation helped in achieving significant process efficiency improvement as inbuilt data validation features significantly improved the confidence of the output. The diagnostic workflows replaced the conventional spreadsheet-based approach. The digital platform works as a common reference of "truth" for everyone across the organization. It helped to produce several the business KPIs to assist the engineers in emphasizing on the problem area, such as improved well test planning.
{"title":"UAE's First End to End Standardized Workflow-Based Digital Transformation in a Giant Gas Producing Asset - Lessons Learned and Way Forward","authors":"A. Alsaeedi, M. Elabrashy, M. Alzeyoudi, M. Albadi, Sandeep Soni, Jose Isambertt, Deepak Tripathi","doi":"10.2118/205851-ms","DOIUrl":"https://doi.org/10.2118/205851-ms","url":null,"abstract":"\u0000 The concept of integrated modeling and digital transformation has grown within the oil and gas industry over the past decade and every such digital transformation has its own set of challenges from which significant learnings can be derived to enhance the knowledge base of the industry. This paper encompasses the successful achievement journey from the UAE's first end to end standardized workflow- based digital transformation in a giant gas producing asset, where several key challenges and learnings have been summarized that are originated from a unique project for a giant gas-condensate asset.\u0000 The role and importance from multiple business stakeholders such as the planning, engineering, operations and performance teams was imperative to establish a collaborative working philosophy and a detailed specification document, the end-to-end solution, functional and non-functional requirements were captured and aligned with end-user needs.\u0000 Firstly, a detailed offline phase along with focused efforts in understanding data-quality and establishing representative base-models, was key to enhance the benefit-realization of the integrated platform. Secondly, the online implementation helped in achieving significant process efficiency improvement as inbuilt data validation features significantly improved the confidence of the output.\u0000 The diagnostic workflows replaced the conventional spreadsheet-based approach. The digital platform works as a common reference of \"truth\" for everyone across the organization. It helped to produce several the business KPIs to assist the engineers in emphasizing on the problem area, such as improved well test planning.","PeriodicalId":10928,"journal":{"name":"Day 2 Wed, September 22, 2021","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87829692","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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