This paper presented an integrated CO2 injection and sequestration modelling study performed on a depleted carbonate gas reservoir, which has been identified as one of potential CO2 sequestration site candidate in conjunction with nearby high CO2 gas fields development and commercialization effort to monetize the fields. 3D compositional modelling, geomechanical and geochemical assessment were conducted to strategize optimum subsurface CO2 injection and sequestration development concept for project execution. Available history matched black oil simulation model was converted into compositional model. Sensitivity analyses on optimum injection rate, number and types of injectors, solubility of CO2 in water, injection locations and impact of hysteresis to plume distribution were investigated. Different types of CO2 trapping mechanisms including hydrodynamic, residual/capillary, solubility and mineral trapping were studied in detailed. Coupled modelling study was performed on base case scenario to assess geomechnical and geochemical risks associated with CO2 injection and sequestration process before-, during- and post- CO2 injection operation to provide assurance for a safe and long-term CO2 sequestration in the field. Available history matched black oil model was successfully converted into compositional model, in which CO2 is treated and can be tracked as a separate component in the reservoir throughout the production and injection processes. Integrating all the results obtained from sensitivities analyses, the proposed optimum subsurface CO2 injection and sequestration development concept for the field is to inject up to 400 MMscf/D of CO2 rate via four injectors. CO2 injection rate is forecasted to sustain more than 3 years from injection start date before declining with time. In terms of CO2 storage capacity, constraining injection pressure up to initial reservoir pressure, maximum CO2 storage capacity is estimated ~65 Million tonnes. Nevertheless, considering maximum allowable CO2 injection pressure estimated from coupled modelling study and operational safety factor, the field is capable to accommodate a total of ~77 Million tonnes of CO2, whereby 73% of total CO2 injected will exists in mobile phase and trapped underneath caprock whilst the other 24% and 3% will be trapped as residual/capillary and dissolved in water respectively. Changes of minerals and porosity were observed from 3D geochemical modelling, however, changes are negligible due to the fact that geochemical reaction is a very slow process. This paper highlights and shares simulation results obtained from CO2 injection and sequestration studies performed on 3D compositional model to generate an optimum subsurface CO2 injection and sequestration development concept for project execution in future. Integration with geomechanical and geochemical modelling studies are crucial to assess site's capability to accommodate CO2 within the geological formation and provide assurance fo
{"title":"Integrated CO2 Modeling Studies to Assess CO2 Sequestration Prospect in a Depleted Carbonate Gas Reservoir, Malaysia","authors":"M. A. A Jalil, Sharidah M Amin, S. S. M Ali","doi":"10.2118/204810-ms","DOIUrl":"https://doi.org/10.2118/204810-ms","url":null,"abstract":"\u0000 This paper presented an integrated CO2 injection and sequestration modelling study performed on a depleted carbonate gas reservoir, which has been identified as one of potential CO2 sequestration site candidate in conjunction with nearby high CO2 gas fields development and commercialization effort to monetize the fields. 3D compositional modelling, geomechanical and geochemical assessment were conducted to strategize optimum subsurface CO2 injection and sequestration development concept for project execution.\u0000 Available history matched black oil simulation model was converted into compositional model. Sensitivity analyses on optimum injection rate, number and types of injectors, solubility of CO2 in water, injection locations and impact of hysteresis to plume distribution were investigated. Different types of CO2 trapping mechanisms including hydrodynamic, residual/capillary, solubility and mineral trapping were studied in detailed. Coupled modelling study was performed on base case scenario to assess geomechnical and geochemical risks associated with CO2 injection and sequestration process before-, during- and post- CO2 injection operation to provide assurance for a safe and long-term CO2 sequestration in the field.\u0000 Available history matched black oil model was successfully converted into compositional model, in which CO2 is treated and can be tracked as a separate component in the reservoir throughout the production and injection processes. Integrating all the results obtained from sensitivities analyses, the proposed optimum subsurface CO2 injection and sequestration development concept for the field is to inject up to 400 MMscf/D of CO2 rate via four injectors. CO2 injection rate is forecasted to sustain more than 3 years from injection start date before declining with time. In terms of CO2 storage capacity, constraining injection pressure up to initial reservoir pressure, maximum CO2 storage capacity is estimated ~65 Million tonnes. Nevertheless, considering maximum allowable CO2 injection pressure estimated from coupled modelling study and operational safety factor, the field is capable to accommodate a total of ~77 Million tonnes of CO2, whereby 73% of total CO2 injected will exists in mobile phase and trapped underneath caprock whilst the other 24% and 3% will be trapped as residual/capillary and dissolved in water respectively. Changes of minerals and porosity were observed from 3D geochemical modelling, however, changes are negligible due to the fact that geochemical reaction is a very slow process.\u0000 This paper highlights and shares simulation results obtained from CO2 injection and sequestration studies performed on 3D compositional model to generate an optimum subsurface CO2 injection and sequestration development concept for project execution in future. Integration with geomechanical and geochemical modelling studies are crucial to assess site's capability to accommodate CO2 within the geological formation and provide assurance fo","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78699692","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}
T. Jiang, Daiyu Zhou, Liming Lian, Yiming Wu, Zangyuan Wu, Kun Fan, Wei Zhou, W. Bian, Guangqiang Shao, J. Fan, Hong-Yang Yu, Xiyu Kuang, Lin Wu, Lan Huang, Xianan Deng, Kaiyu Wang
Different from other gas drive processes, phase behavior performs more significant roles in natural gas drive process. The main reason is that more severe mass transfer effect and similar phase solubility effect have been caused by multicomponent interaction. This paper provides a series of methods to study the phase behavior in natural gas drive process, aiming to reveal further mechanism and give technical supports to the on-site practice in T_D Reservoir with HTHP. Four key parameters of natural gas drive have been determined. Firstly, laboratory compounding method has been improved to obtain real components of formation fluids and actual injected gas at formation condition (140°C, 45MPa). Secondly, 19 sets of slim tube test has been carried to determine MMP (minimum miscible pressure) and the injected gas components ensuring miscibility. Thirdly, swelling test and laser method have been used to separately obtain the viscosity reduction degree and solid deposition effects. Finally, multiple contact test has been carried to describe the miscibility behavior. All the above have been applied in T_D Reservoir. Conclusions could be drawn from the results obtained by the methods above. Firstly, swelling capacity of crude oil could be enhanced by natural gas for the formation volume factor of crude oil in T_D Reservoir increased by 57% and the viscosity decreased by 83% after natural gas injection. Secondly, MMP of dry gas and crude oil in T_D Reservoir is 43.5MPa with a miscible displacement efficiency above 90% (>30% compared with immiscible displacement efficiency), and the content of N2+C1 should be controlled over 88%. Thirdly, results of 5 levels contact experiments shows that miscibility behavior of natural gas and oil from T_D Reservoir performs an evaporative-condensate composite miscible process in which the condensate miscible process takes the lead. Finally, obvious solid point has not been observed in natural gas drive process of crude oil from T_D Reservoir at the formation temperature, and the effect of solid deposition on the fluid flow in formation could be ignored because of trace amount of solid solution (<1mg/ml) and minute formation permeability damage (<8%). The achievements above have been applied in T_D Reservoir as one of the important technical means supporting over 350,000 tons increased production by natural gas drive. A systematic methods have been reorganized to research the phase behavior in natural gas drive process and half of these methods mentioned above get partially improvement. These physical simulation experiments have covered most mainly processes and the key parameters in reservoirs with HTHP and natural gas drive, including mass transfer, viscosity, expansion, volume coefficient, MMP, miscibility behavior and solid deposition. Every experiment gives a quantitative analysis which possesses satisfied practicability in field application.
{"title":"Research of Phase Behavior in Natural Gas Drive Process and Its Application in T_D Reservoir with HTHP","authors":"T. Jiang, Daiyu Zhou, Liming Lian, Yiming Wu, Zangyuan Wu, Kun Fan, Wei Zhou, W. Bian, Guangqiang Shao, J. Fan, Hong-Yang Yu, Xiyu Kuang, Lin Wu, Lan Huang, Xianan Deng, Kaiyu Wang","doi":"10.2118/204676-ms","DOIUrl":"https://doi.org/10.2118/204676-ms","url":null,"abstract":"\u0000 Different from other gas drive processes, phase behavior performs more significant roles in natural gas drive process. The main reason is that more severe mass transfer effect and similar phase solubility effect have been caused by multicomponent interaction. This paper provides a series of methods to study the phase behavior in natural gas drive process, aiming to reveal further mechanism and give technical supports to the on-site practice in T_D Reservoir with HTHP.\u0000 Four key parameters of natural gas drive have been determined. Firstly, laboratory compounding method has been improved to obtain real components of formation fluids and actual injected gas at formation condition (140°C, 45MPa). Secondly, 19 sets of slim tube test has been carried to determine MMP (minimum miscible pressure) and the injected gas components ensuring miscibility. Thirdly, swelling test and laser method have been used to separately obtain the viscosity reduction degree and solid deposition effects. Finally, multiple contact test has been carried to describe the miscibility behavior. All the above have been applied in T_D Reservoir.\u0000 Conclusions could be drawn from the results obtained by the methods above. Firstly, swelling capacity of crude oil could be enhanced by natural gas for the formation volume factor of crude oil in T_D Reservoir increased by 57% and the viscosity decreased by 83% after natural gas injection. Secondly, MMP of dry gas and crude oil in T_D Reservoir is 43.5MPa with a miscible displacement efficiency above 90% (>30% compared with immiscible displacement efficiency), and the content of N2+C1 should be controlled over 88%. Thirdly, results of 5 levels contact experiments shows that miscibility behavior of natural gas and oil from T_D Reservoir performs an evaporative-condensate composite miscible process in which the condensate miscible process takes the lead. Finally, obvious solid point has not been observed in natural gas drive process of crude oil from T_D Reservoir at the formation temperature, and the effect of solid deposition on the fluid flow in formation could be ignored because of trace amount of solid solution (<1mg/ml) and minute formation permeability damage (<8%). The achievements above have been applied in T_D Reservoir as one of the important technical means supporting over 350,000 tons increased production by natural gas drive.\u0000 A systematic methods have been reorganized to research the phase behavior in natural gas drive process and half of these methods mentioned above get partially improvement. These physical simulation experiments have covered most mainly processes and the key parameters in reservoirs with HTHP and natural gas drive, including mass transfer, viscosity, expansion, volume coefficient, MMP, miscibility behavior and solid deposition. Every experiment gives a quantitative analysis which possesses satisfied practicability in field application.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"45 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79119441","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}
Carbonate reservoir rocks are composed of complex pore structures and networks, forming a wide range of sedimentary facies. Considering this complexity, we present a novel approach for a better selection of coreflood composites. In this approach, reservoir plugs undergo a thorough filtration process by completing several lab tests before they get classified into reservoir rock types. Those tests include conventional core analysis (CCA), liquid permeability, plug computed tomography (CT), nuclear magnetic resonance (NMR), end-trim mercury injection capillary pressure (MICP), X-ray diffraction (XRD), thin-section analysis (TS), scanning electron microscopy (SEM), and drainage capillary pressure (Pc). We recommend starting with a large pool of plugs and narrowing down the selection as they complete different stages of the screening process. The CT scans help to exclude plugs exhibiting composite-like behavior or containing vugs and fractures that potentially influence coreflood results. After that, the plugs are categorized into separate groups representing the available reservoir rock types. Then, we look into each rock type and determine whether the selected plugs share similar pore-structures, rock texture, and mineral content. The end-trim MICP is usually helpful in clustering plugs having similar pore-throat size distributions. Nevertheless, it also poses a challenge because it may not represent the whole plug, especially for heterogeneous carbonates. In such a case, we recommend harnessing the NMR capabilities to verify the pore-size distribution. After pore-size distribution verification, plugs are further screened for textural and mineral similarity using the petrographic data (XRD, TS, and SEM). Finally, we evaluate the similarity of brine permeability (Kb), irreducible water saturation (Swir) from Pc, and effective oil permeability data at Swir (Koe, after wettability restoration for unpreserved plugs) before finalizing the composite selection. The paper demonstrates significant aspects of applying the proposed approach to carbonate reservoir rock samples. It integrates geology, petrophysics, and reservoir engineering elements when deciding the best possible composite for coreflood experiments. By practicing this workflow, we also observe considerable differences in rock types depending on the data source, suggesting that careful use of end-trim data for carbonates is advisable compared to more representative full-plug MICP and NMR test results. In addition, we generally observe that Kb and Koe are usually lower than the Klinkenberg permeability with a varying degree that is plug-specific, highlighting the benefit of incorporating these measurements as additional criteria in coreflood composite selection for carbonate reservoirs.
{"title":"A New Approach for Building Composite Cores for Corefloods in Complex Carbonate Rocks","authors":"Y. Cinar, Ahmed Zayer, Naseem Dawood, D. Krinis","doi":"10.2118/204655-ms","DOIUrl":"https://doi.org/10.2118/204655-ms","url":null,"abstract":"\u0000 Carbonate reservoir rocks are composed of complex pore structures and networks, forming a wide range of sedimentary facies. Considering this complexity, we present a novel approach for a better selection of coreflood composites. In this approach, reservoir plugs undergo a thorough filtration process by completing several lab tests before they get classified into reservoir rock types. Those tests include conventional core analysis (CCA), liquid permeability, plug computed tomography (CT), nuclear magnetic resonance (NMR), end-trim mercury injection capillary pressure (MICP), X-ray diffraction (XRD), thin-section analysis (TS), scanning electron microscopy (SEM), and drainage capillary pressure (Pc). We recommend starting with a large pool of plugs and narrowing down the selection as they complete different stages of the screening process. The CT scans help to exclude plugs exhibiting composite-like behavior or containing vugs and fractures that potentially influence coreflood results. After that, the plugs are categorized into separate groups representing the available reservoir rock types. Then, we look into each rock type and determine whether the selected plugs share similar pore-structures, rock texture, and mineral content. The end-trim MICP is usually helpful in clustering plugs having similar pore-throat size distributions. Nevertheless, it also poses a challenge because it may not represent the whole plug, especially for heterogeneous carbonates. In such a case, we recommend harnessing the NMR capabilities to verify the pore-size distribution. After pore-size distribution verification, plugs are further screened for textural and mineral similarity using the petrographic data (XRD, TS, and SEM). Finally, we evaluate the similarity of brine permeability (Kb), irreducible water saturation (Swir) from Pc, and effective oil permeability data at Swir (Koe, after wettability restoration for unpreserved plugs) before finalizing the composite selection.\u0000 The paper demonstrates significant aspects of applying the proposed approach to carbonate reservoir rock samples. It integrates geology, petrophysics, and reservoir engineering elements when deciding the best possible composite for coreflood experiments. By practicing this workflow, we also observe considerable differences in rock types depending on the data source, suggesting that careful use of end-trim data for carbonates is advisable compared to more representative full-plug MICP and NMR test results. In addition, we generally observe that Kb and Koe are usually lower than the Klinkenberg permeability with a varying degree that is plug-specific, highlighting the benefit of incorporating these measurements as additional criteria in coreflood composite selection for carbonate reservoirs.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87005610","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}
Brian Chin, Safdar Ali, A. Mathur, C. Barnes, W. V. Gonten
A big challenge in tight conventional and unconventional rock systems is the lack of representative reservoir deliverability models for movement of water, oil and gas through micro-pore and nano-pore networks. Relative permeability is a key input in modelling these rocks; but due to limitations in core analysis techniques, permeability has become a knob or tuning parameter in reservoir simulation. Current relative permeability measurements on conventional core samples rely on density contrast between oil/water or gas/water on CT (Computed Tomography) scans and recording of effluent volumes to determine relative fluid saturations during the core flooding process. However, tight rocks are characterized by low porosities (< 10 %) and ultra-low permeabilities (< 1 micro-Darcy), that make effective and relative permeability measurements very difficult, time-consuming, and prone to high errors associated with low pore volumes and flow rates. Nuclear Magnetic Resonance (NMR) measurements have been used extensively in the industry to measure fluid porosities, pore size characterization, wettability evaluation, etc. Core NMR scans can provide accurate quantification of pore fluids (oil, gas, water) even in very small quantities, using T2, T1T2 and D-T2 activation sequences. We have developed a novel process to perform experiments that measure effective and relative permeability values on both conventional and tight reservoirs at reservoir conditions while accurately monitoring fluid saturations and fluid fronts in a 12 MHz 3D gradient NMR spectrometer. The experimental process starts by acquiring Micro-CT scans of the cylindrical rock plugs to screen the samples for artifacts or microcracks that may affect permeability measurements. Once the samples are chosen, NMR T2 and T1T2 scans are performed to establish residual fluid saturations in the as-received state. If a liquid effective permeability test is required, the samples are then saturated with the given liquid through a combination of humidification, vacuum-assisted spontaneous imbibition, and saturation under pressure and temperature. After saturation, NMR scans are obtained to verify the volumes of the liquids and determine if the samples have achieved complete saturation. The sample is then loaded into a special core-flooding vessel that is invisible to the NMR spectrometer to minimize interference with the NMR signals from the fluids in the sample. The sample is brought up to reservoir stress and temperature, and the main flowing fluid is injected from one side of the sample while controlling the pressures on the other side of the sample with a back pressure regulator. The saturation front of the injected fluid is continuously monitored using 2D and 3D gradient NMR scans and the volumes of different fluids in the sample are measured using NMR T2 and T1T2 scans. The use of a 12 MHz NMR spectrometer provides very high SNR (signal-to-noise ratio); and clear distinction of water and hydrocarbon s
{"title":"Core Effective and Relative Permeability Measurements for Conventional and Unconventional Reservoirs by Saturation Monitoring in High Frequency 3d Gradient NMR","authors":"Brian Chin, Safdar Ali, A. Mathur, C. Barnes, W. V. Gonten","doi":"10.2118/204796-ms","DOIUrl":"https://doi.org/10.2118/204796-ms","url":null,"abstract":"\u0000 A big challenge in tight conventional and unconventional rock systems is the lack of representative reservoir deliverability models for movement of water, oil and gas through micro-pore and nano-pore networks. Relative permeability is a key input in modelling these rocks; but due to limitations in core analysis techniques, permeability has become a knob or tuning parameter in reservoir simulation. Current relative permeability measurements on conventional core samples rely on density contrast between oil/water or gas/water on CT (Computed Tomography) scans and recording of effluent volumes to determine relative fluid saturations during the core flooding process. However, tight rocks are characterized by low porosities (< 10 %) and ultra-low permeabilities (< 1 micro-Darcy), that make effective and relative permeability measurements very difficult, time-consuming, and prone to high errors associated with low pore volumes and flow rates.\u0000 Nuclear Magnetic Resonance (NMR) measurements have been used extensively in the industry to measure fluid porosities, pore size characterization, wettability evaluation, etc. Core NMR scans can provide accurate quantification of pore fluids (oil, gas, water) even in very small quantities, using T2, T1T2 and D-T2 activation sequences. We have developed a novel process to perform experiments that measure effective and relative permeability values on both conventional and tight reservoirs at reservoir conditions while accurately monitoring fluid saturations and fluid fronts in a 12 MHz 3D gradient NMR spectrometer.\u0000 The experimental process starts by acquiring Micro-CT scans of the cylindrical rock plugs to screen the samples for artifacts or microcracks that may affect permeability measurements. Once the samples are chosen, NMR T2 and T1T2 scans are performed to establish residual fluid saturations in the as-received state. If a liquid effective permeability test is required, the samples are then saturated with the given liquid through a combination of humidification, vacuum-assisted spontaneous imbibition, and saturation under pressure and temperature. After saturation, NMR scans are obtained to verify the volumes of the liquids and determine if the samples have achieved complete saturation. The sample is then loaded into a special core-flooding vessel that is invisible to the NMR spectrometer to minimize interference with the NMR signals from the fluids in the sample. The sample is brought up to reservoir stress and temperature, and the main flowing fluid is injected from one side of the sample while controlling the pressures on the other side of the sample with a back pressure regulator. The saturation front of the injected fluid is continuously monitored using 2D and 3D gradient NMR scans and the volumes of different fluids in the sample are measured using NMR T2 and T1T2 scans. The use of a 12 MHz NMR spectrometer provides very high SNR (signal-to-noise ratio); and clear distinction of water and hydrocarbon s","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83810494","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}
Horizontal drilling and multistage hydraulic fracturing applied in unconventional reservoirs over the past decade to create a large fracture surface area to improve the well productivity. The combination of reservoir quality with perforation cluster spacing and fracture staging are keys to successful hydraulic fracturing treatment for horizontal wells. The objective of this work is to build and calibrate a dynamic model by integrating geologic, hydraulic fracture, and reservoir modeling to optimize the number of clusters and other completion parameters for a horizontal well drilled in the source rock reservoir using simulation and analytical models. The methodology adopted in this study covers the integration of geological, petrophysical, and production data analysis to evaluate reservoir and completion qualities and quantify the heterogeneity and the perforation clusters number required within a frac stage. Assuming all perforation clusters are uniformly distributed within a stage. The hydraulic planer fracture attributes assumed and the surface production measurement together with the production profile were used to calibrate the reservoir model. The properties of the Stimulated Reservoir Volume "SRV" were defined after the final calibration using reservoir model including hydraulic fractures. The calibrated reservoir model was used to carry out sensitivity analyses for cluster spacing optimization and other completion parameters considering the surface and reservoir constraints. An optimum cluster spacing was observed based on the Estimated Ultimate Recovery "EUR" of the subject well by reservoir properties. The final results based on 70% of perforation clusters contribution to production observed from PLT log, and the results of this study were implemented. Afterwards, another study has been undertaken to increasing the stimulation effectiveness and maximizing the number of perforation clusters contributing to productivity as an area for improvement to engineering the completion design. The methodology adopted in this study identifies the most important parameters of completion affecting well productivity for specific unconventional reservoirs. This study will help to engineer completion design, improve cluster efficiency, reduce cost and increase well EUR for the development phase.
{"title":"Workflow to Optimize Cluster Spacing Design of Horizontal Multistage Fractured Well in Unconventional Source Rock","authors":"Rabah Mesdour, Moemen Abdelrahman, Abdulbari Alhayaf","doi":"10.2118/204891-ms","DOIUrl":"https://doi.org/10.2118/204891-ms","url":null,"abstract":"\u0000 Horizontal drilling and multistage hydraulic fracturing applied in unconventional reservoirs over the past decade to create a large fracture surface area to improve the well productivity. The combination of reservoir quality with perforation cluster spacing and fracture staging are keys to successful hydraulic fracturing treatment for horizontal wells. The objective of this work is to build and calibrate a dynamic model by integrating geologic, hydraulic fracture, and reservoir modeling to optimize the number of clusters and other completion parameters for a horizontal well drilled in the source rock reservoir using simulation and analytical models. The methodology adopted in this study covers the integration of geological, petrophysical, and production data analysis to evaluate reservoir and completion qualities and quantify the heterogeneity and the perforation clusters number required within a frac stage. Assuming all perforation clusters are uniformly distributed within a stage. The hydraulic planer fracture attributes assumed and the surface production measurement together with the production profile were used to calibrate the reservoir model.\u0000 The properties of the Stimulated Reservoir Volume \"SRV\" were defined after the final calibration using reservoir model including hydraulic fractures. The calibrated reservoir model was used to carry out sensitivity analyses for cluster spacing optimization and other completion parameters considering the surface and reservoir constraints. An optimum cluster spacing was observed based on the Estimated Ultimate Recovery \"EUR\" of the subject well by reservoir properties. The final results based on 70% of perforation clusters contribution to production observed from PLT log, and the results of this study were implemented. Afterwards, another study has been undertaken to increasing the stimulation effectiveness and maximizing the number of perforation clusters contributing to productivity as an area for improvement to engineering the completion design. The methodology adopted in this study identifies the most important parameters of completion affecting well productivity for specific unconventional reservoirs. This study will help to engineer completion design, improve cluster efficiency, reduce cost and increase well EUR for the development phase.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"100 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85795127","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}
Nitin Johri, N. Pandey, S. Kadam, S. Vermani, Shubham Agarwal, Debashis Gupta
Data monitoring in remote satellite field without any DOF platform is a challenging task but critical for ALS monitoring and optimization. In SRP wells the VFD data collection is important for analysis of downhole pump behavior and system health. SRP maintenance crew collects data from VFDs daily, but it is time consuming and can target only few wells in a day. The steps from requirement of dyna to final decision taken for ALS optimization are mobilizing team, permits approvals, download data, e-mail dynacards, dyna visualization, final decision. The problems with above process were: - Insufficient and discrete data for any post-failure analysis or ALS-optimization Minimal data to investigate the pre failure events The lack of real time monitoring was resulting in well downtime and associated production loss. The combination of IOT, Cloud Computing and Machine learning was implemented to shift from the reactive to proactive approach which helped in ALS Optimization and reduced production loss. The data was transmitted to a Cloud server and further it was transmitted to web-based app. Since thousands of Dynacards are generated in a day, hence it requires automated classification using computer driven pattern recognition techniques. The real time data is used for analysis involving basic statistic and Machine learning algorithms. The critical pump signatures were identified using machine learning libraries and email is generated for immediate action. Several informative dashboards were developed which provide quick analysis of ALS performance. The types of dashboard are as below Well Operational Status Dynacards Interpretation module SRP parameters visualization Machine Learning model calibration module Pump Performance Statistics After collection of enough data and creation of analytical dashboards on the three wells using domain knowledge the gained insights were used for ALS optimization. To keep the model in an evergreen high-confidence prediction state, inputs from domain experts are often required. After regular fine-tuning the prediction accuracy of the ML model increased to 80-85 %. In addition, system was made flexible so that a new algorithm can be deployed when required. Smart Alarms were generated involving statistic and Machine Learning by the system which gives alerts by e-mail if an abnormal behavior or erratic dynacards were identified. This helped in reduction of well downtime in some events which were treated instinctively before. The integration of domain knowledge and digitalization enables an engineer to take informed and effective decisions. The techniques discussed above can be implemented in marginal fields where DOF implementation is logistically and economically challenged. EDGE along with advanced analytics will gain more technological advances and can be used in other potential domains as well in near future.
{"title":"Satellite Fields Digitalization & ALS Optimization with EDGE & Advance Analytics Application","authors":"Nitin Johri, N. Pandey, S. Kadam, S. Vermani, Shubham Agarwal, Debashis Gupta","doi":"10.2118/204794-ms","DOIUrl":"https://doi.org/10.2118/204794-ms","url":null,"abstract":"\u0000 Data monitoring in remote satellite field without any DOF platform is a challenging task but critical for ALS monitoring and optimization. In SRP wells the VFD data collection is important for analysis of downhole pump behavior and system health. SRP maintenance crew collects data from VFDs daily, but it is time consuming and can target only few wells in a day. The steps from requirement of dyna to final decision taken for ALS optimization are mobilizing team, permits approvals, download data, e-mail dynacards, dyna visualization, final decision.\u0000 The problems with above process were: -\u0000 Insufficient and discrete data for any post-failure analysis or ALS-optimization Minimal data to investigate the pre failure events\u0000 The lack of real time monitoring was resulting in well downtime and associated production loss. The combination of IOT, Cloud Computing and Machine learning was implemented to shift from the reactive to proactive approach which helped in ALS Optimization and reduced production loss.\u0000 The data was transmitted to a Cloud server and further it was transmitted to web-based app. Since thousands of Dynacards are generated in a day, hence it requires automated classification using computer driven pattern recognition techniques. The real time data is used for analysis involving basic statistic and Machine learning algorithms. The critical pump signatures were identified using machine learning libraries and email is generated for immediate action. Several informative dashboards were developed which provide quick analysis of ALS performance. The types of dashboard are as below\u0000 Well Operational Status Dynacards Interpretation module SRP parameters visualization Machine Learning model calibration module Pump Performance Statistics\u0000 After collection of enough data and creation of analytical dashboards on the three wells using domain knowledge the gained insights were used for ALS optimization. To keep the model in an evergreen high-confidence prediction state, inputs from domain experts are often required. After regular fine-tuning the prediction accuracy of the ML model increased to 80-85 %. In addition, system was made flexible so that a new algorithm can be deployed when required. Smart Alarms were generated involving statistic and Machine Learning by the system which gives alerts by e-mail if an abnormal behavior or erratic dynacards were identified. This helped in reduction of well downtime in some events which were treated instinctively before.\u0000 The integration of domain knowledge and digitalization enables an engineer to take informed and effective decisions. The techniques discussed above can be implemented in marginal fields where DOF implementation is logistically and economically challenged. EDGE along with advanced analytics will gain more technological advances and can be used in other potential domains as well in near future.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83031529","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 objective of this paper is to showcase the successful and innovative troubleshooting data analysis techniques in one of the gas compression systems in upstream gas oil separation plants (GOSP-A). The gas compression system using gas compressors, dry gas seal systems and due point controls is used in almost all of upstream operation. These proven data analysis techniques were used to tackle major and chronic issues associated with gas compression system operation that lead to excessive flaring, mechanical seal failures, solidification, hydrate formation and off-specification products. Dry Gas mechanical seals are an important key element in gas compression and its lifetime represents a concern to the operation personnel. Most gas compression systems have a mechanical seal lifetime of 2 years which in some cases limit production, increase the potential of unnecessary flaring and increase OPEX significantly. In addition, solidification due to constant liquid carry over result in a wide range of undesirable results such as blockages that constrain production rates and result in safety concerns. In this paper, comprehensive data analysis of the potential root causes that aggravate undesired premature mechanical seal failure, material solidification, equipment damage and off-specification gas products will be discussed along with solutions to minimize expected impact. For example, improper product specification in some applications have been found to promote seal failures, corrosion, solidification and incur additional flaring which is both costly and environmentally undesirable. In addition, after extensive analysis improper operation practices during compressor startups, steady state operation and gas conditioning have been linked with premature compressor failures, product off spec and safety device failures. The field trial proved the effectiveness of the proposed innovative troubleshooting data analysis techniques in reinstating the gas compression unit in GOSP-A to its recommended design conditions, eliminated compressors and mechanical seal failures and avoided the off-specification products at the lowest operating cost. This innovative technique was based on deep and extensive process data analysis, evaluating operating and design data, reviewing international standards, benchmarking against other facilities, process simulation using Hysys, and finally the actual field trial.
{"title":"Troubleshooting Gas Compression Systems Using Data Analysis","authors":"A. Al-Aiderous","doi":"10.2118/204808-ms","DOIUrl":"https://doi.org/10.2118/204808-ms","url":null,"abstract":"\u0000 The objective of this paper is to showcase the successful and innovative troubleshooting data analysis techniques in one of the gas compression systems in upstream gas oil separation plants (GOSP-A). The gas compression system using gas compressors, dry gas seal systems and due point controls is used in almost all of upstream operation.\u0000 These proven data analysis techniques were used to tackle major and chronic issues associated with gas compression system operation that lead to excessive flaring, mechanical seal failures, solidification, hydrate formation and off-specification products. Dry Gas mechanical seals are an important key element in gas compression and its lifetime represents a concern to the operation personnel. Most gas compression systems have a mechanical seal lifetime of 2 years which in some cases limit production, increase the potential of unnecessary flaring and increase OPEX significantly. In addition, solidification due to constant liquid carry over result in a wide range of undesirable results such as blockages that constrain production rates and result in safety concerns.\u0000 In this paper, comprehensive data analysis of the potential root causes that aggravate undesired premature mechanical seal failure, material solidification, equipment damage and off-specification gas products will be discussed along with solutions to minimize expected impact. For example, improper product specification in some applications have been found to promote seal failures, corrosion, solidification and incur additional flaring which is both costly and environmentally undesirable. In addition, after extensive analysis improper operation practices during compressor startups, steady state operation and gas conditioning have been linked with premature compressor failures, product off spec and safety device failures.\u0000 The field trial proved the effectiveness of the proposed innovative troubleshooting data analysis techniques in reinstating the gas compression unit in GOSP-A to its recommended design conditions, eliminated compressors and mechanical seal failures and avoided the off-specification products at the lowest operating cost. This innovative technique was based on deep and extensive process data analysis, evaluating operating and design data, reviewing international standards, benchmarking against other facilities, process simulation using Hysys, and finally the actual field trial.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81866951","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}
Sobia Fatima, Hafiz Muhammad Azib Khan, Zeeshan Tariq, Mohammad Abdalla, M. Mahmoud
Carbon dioxide (CO2) sequestration is a technique to store CO2 into an underground formation. CO2 can cause a severe reaction with the underground formation and injection tubing inside the well. Successful CO2 storage into underground formations depends on many factors such as efficient sealing, no escaping from the storage, and minimum corrosion to injection tubing/casing. Therefore, proper planning involving thorough study and reaction kinetics of CO2 with the underground formation is indeed necessary for proper planning. The main aim and objective of this study are to investigate the effect of CO2 storage with different cap rocks such as tight carbonate and shale under simulated reservoir conditions. The samples were stored for different times such as 10, 20, and 120 days. The objectives of the study were achieved by carrying out extensive laboratory experiments before and after sequestration. The laboratory experiments included were rock compressive and tensile strength tests, petrophysical tests, and rock mechanical tests. The laboratory results were later used to investigate the reaction kinetics study of CO2 with the underground formation using CMG simulation software. The effect of injection rate, the point of injection, purity of the injection fluid, reservoir heterogeneity, reservoir depth, and minimum miscibility pressure was analyzed. In this simulation model, CO2 is injected for 25 years using CMG-GEM simulation software and then the fate of CO2 post injection is modeled for the next 225 years. The simulation results showed a notable effect on the mechanical strength and petrophysical parameters of the rock after sequestration, also the solubility of CO2 decreases with the increase in salinity and injection pressure. The results also showed that the storage of CO2 increases the petrophysical properties of porosity and permeability of the formation rock when the storage period is more than 20 days because of calcite precipitation and CO2 dissolution. A storage period of fewer than 20 days does not show any significant effect on the porosity and permeability of carbonate reservoir rock. A sensitivity analysis was carried out which showed that the rate of CO2 sequestration is sensitive to the mineral-water reaction kinetic constants. The sensitivity of CO2 sequestration to the rate constants decreases in magnitude respectively for different clay minerals. The new simulation model considers the effect of reaction kinetics and geomechanical parameters. The new model is capable of predicting the compatibility of CO2 sequestration for a particular field for a particular time.
{"title":"An Experimental and Simulation Study of CO2 Sequestration in an Underground Formations; Impact on Geomechanical and Petrophysical Properties","authors":"Sobia Fatima, Hafiz Muhammad Azib Khan, Zeeshan Tariq, Mohammad Abdalla, M. Mahmoud","doi":"10.2118/204726-ms","DOIUrl":"https://doi.org/10.2118/204726-ms","url":null,"abstract":"\u0000 Carbon dioxide (CO2) sequestration is a technique to store CO2 into an underground formation. CO2 can cause a severe reaction with the underground formation and injection tubing inside the well. Successful CO2 storage into underground formations depends on many factors such as efficient sealing, no escaping from the storage, and minimum corrosion to injection tubing/casing. Therefore, proper planning involving thorough study and reaction kinetics of CO2 with the underground formation is indeed necessary for proper planning.\u0000 The main aim and objective of this study are to investigate the effect of CO2 storage with different cap rocks such as tight carbonate and shale under simulated reservoir conditions. The samples were stored for different times such as 10, 20, and 120 days. The objectives of the study were achieved by carrying out extensive laboratory experiments before and after sequestration. The laboratory experiments included were rock compressive and tensile strength tests, petrophysical tests, and rock mechanical tests. The laboratory results were later used to investigate the reaction kinetics study of CO2 with the underground formation using CMG simulation software. The effect of injection rate, the point of injection, purity of the injection fluid, reservoir heterogeneity, reservoir depth, and minimum miscibility pressure was analyzed.\u0000 In this simulation model, CO2 is injected for 25 years using CMG-GEM simulation software and then the fate of CO2 post injection is modeled for the next 225 years. The simulation results showed a notable effect on the mechanical strength and petrophysical parameters of the rock after sequestration, also the solubility of CO2 decreases with the increase in salinity and injection pressure. The results also showed that the storage of CO2 increases the petrophysical properties of porosity and permeability of the formation rock when the storage period is more than 20 days because of calcite precipitation and CO2 dissolution. A storage period of fewer than 20 days does not show any significant effect on the porosity and permeability of carbonate reservoir rock. A sensitivity analysis was carried out which showed that the rate of CO2 sequestration is sensitive to the mineral-water reaction kinetic constants. The sensitivity of CO2 sequestration to the rate constants decreases in magnitude respectively for different clay minerals.\u0000 The new simulation model considers the effect of reaction kinetics and geomechanical parameters. The new model is capable of predicting the compatibility of CO2 sequestration for a particular field for a particular time.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"15 2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80425217","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}
P. Tiwari, P. Chidambaram, A. I. Azahree, Dr. Rabindra Das, P. A. Patil, Zoann Low, P. Chandran, R. Tewari, M. A. Abdul Hamid, M. Yaakub
CO2 sequestration is a process for eternity with a possibility of zero-degree failure. One of the key components of the CO2 Sequestration Project is to have a site-specific, risk-based and adaptive Monitoring, Measurement and Verification (MMV) plan. The storage site has been studied thoroughly and is understood to be inherently safe for CO2 sequestration. However, it is incumbent on operator to manage and minimize storage risks. MMV planning is critical along with geological site selection, transportation and storage process. Geological evaluation study of the storage site suggests the containment capacity of identified large depleted gas reservoirs as well as long term conformance due to thick interval. The fault-seal analysis and reservoir integrity study contemplate long-term security of the CO2 storage. An integrated 3D reservoir dynamic simulation model coupled with geomechanical and geochemical models were performed. This helps in understanding storage capacity, trapping mechanisms, reservoir integrity, plume migration path, and injectivity. To demonstrate that CO2 plume migration can be mapped from the seismic, a 4D Seismic feasibility study was carried out using well and fluid data. Gassmann fluid substitution was performed in carbonate reservoir at well, and seismic response of several combination of fluid saturation scenarios on synthetic gathers were analyzed. The CO2 dispersion study, which incorporate integration of subsurface, geomatic and metocean & environment data along with leakage character information, was carried out to understand the potential leakage pathway along existing wells and faults which enable to design a monitoring plan accordingly. The monitoring of wells & reservoir integrity, overburden integrity will be carried out by Fiber Optic System to be installed in injection wells. Significant difference in seismic amplitude observed at the reservoir top during 4D seismic feasibility study for varying CO2 saturation suggests that monitoring of CO2 plume migration from seismic is possible. CO2 plume front with as low as 25% saturation can be discriminated provided seismic data has high signal noise ratio (SNR). 3D DAS-VSP acquisition modeling results show that a subsurface coverage of approximately 3 km2 per well is achievable. Laboratory injectivity studies and three-way coupled modelling simulations established that three injection wells will be required to achieve the target injection rate. As planned injection wells are field centric and storage site area is large, DAS-VSP find limited coverage to monitor the CO2 plume front. Hence, surface seismic acquisition will be an integral component of full field monitoring and time-lapsed evaluations for integrated MMV planning to monitor CO2 plume migration. The integrated MMV planning is designed to ensure that injected CO2 in the reservoir is intact and safely stored for hundreds of years after injection. Field specific MMV technologies for CO2 plume migration with p
{"title":"Safeguarding CO2 Storage in a Depleted Offshore Gas Field with Adaptive Approach of Monitoring, Measurement and Verification MMV","authors":"P. Tiwari, P. Chidambaram, A. I. Azahree, Dr. Rabindra Das, P. A. Patil, Zoann Low, P. Chandran, R. Tewari, M. A. Abdul Hamid, M. Yaakub","doi":"10.2118/204590-ms","DOIUrl":"https://doi.org/10.2118/204590-ms","url":null,"abstract":"\u0000 CO2 sequestration is a process for eternity with a possibility of zero-degree failure. One of the key components of the CO2 Sequestration Project is to have a site-specific, risk-based and adaptive Monitoring, Measurement and Verification (MMV) plan. The storage site has been studied thoroughly and is understood to be inherently safe for CO2 sequestration. However, it is incumbent on operator to manage and minimize storage risks. MMV planning is critical along with geological site selection, transportation and storage process.\u0000 Geological evaluation study of the storage site suggests the containment capacity of identified large depleted gas reservoirs as well as long term conformance due to thick interval. The fault-seal analysis and reservoir integrity study contemplate long-term security of the CO2 storage. An integrated 3D reservoir dynamic simulation model coupled with geomechanical and geochemical models were performed. This helps in understanding storage capacity, trapping mechanisms, reservoir integrity, plume migration path, and injectivity. To demonstrate that CO2 plume migration can be mapped from the seismic, a 4D Seismic feasibility study was carried out using well and fluid data. Gassmann fluid substitution was performed in carbonate reservoir at well, and seismic response of several combination of fluid saturation scenarios on synthetic gathers were analyzed.\u0000 The CO2 dispersion study, which incorporate integration of subsurface, geomatic and metocean & environment data along with leakage character information, was carried out to understand the potential leakage pathway along existing wells and faults which enable to design a monitoring plan accordingly. The monitoring of wells & reservoir integrity, overburden integrity will be carried out by Fiber Optic System to be installed in injection wells. Significant difference in seismic amplitude observed at the reservoir top during 4D seismic feasibility study for varying CO2 saturation suggests that monitoring of CO2 plume migration from seismic is possible. CO2 plume front with as low as 25% saturation can be discriminated provided seismic data has high signal noise ratio (SNR).\u0000 3D DAS-VSP acquisition modeling results show that a subsurface coverage of approximately 3 km2 per well is achievable. Laboratory injectivity studies and three-way coupled modelling simulations established that three injection wells will be required to achieve the target injection rate. As planned injection wells are field centric and storage site area is large, DAS-VSP find limited coverage to monitor the CO2 plume front. Hence, surface seismic acquisition will be an integral component of full field monitoring and time-lapsed evaluations for integrated MMV planning to monitor CO2 plume migration. The integrated MMV planning is designed to ensure that injected CO2 in the reservoir is intact and safely stored for hundreds of years after injection. Field specific MMV technologies for CO2 plume migration with p","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"35 5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77961218","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}
Carlos Alejandro Terrones Brand, Miguel Alejandro Basso Mora, Rajeswary Kandasamy, Sergio Comarin, Felipe Rene Bustos Guevara, Beatriz Vega, Susana Pasaran
Mexico has set challenging oil and gas production to meet worldwide demand. In order to deliver promised oil production outputs in this challenging environment, the operator came up with efficient partnerships with key service providers to leverage resources and technical know-how whilst encouraging knowledge transfer and drilling project cost reduction. By working with various service companies, the operator creates a competitive environment where each strives to outperform the other. One such success case is in the "S" field, a heavy oil field producing via steam injection in the South of Mexico. Utilizing a creative design and execution methodology, the "S" project team succeeded to deliver improved project performance over the course of drilling the 14 wells in the campaign. The average well operational time was successfully reduced by 10%, hence maximizing the well construction index to 122 m/day and reducing overall well costs. The main strategy to optimize performance is to re-engineer solutions for profitability such as performing a study to replace OBM by WBM, designing a new wellhead system, collaborating with the rig contractor to reduce flat time activities, redesigning cement properties for losses mitigation, improvement of ROP by merging new technologies and local practices, among others. Complementary to this, the strategy is to prioritize realistic areas of improvement by the development and utilization of a new tool called Best of the Best (BoB), a methodology breaking down all well activities in order to measure its fastest time per well and then aiming to achieve that aggressive goal. Detailed follow up in the field allows to reduce operational times by allowing the wellsite team monitor and suggest new and improved ways of doing a routine task all of which result in lower costs per foot. Utilizing this BoB approach and stringent performance monitoring while drilling (pre-actual-post) activity analysis, allowed superior performance to be achieved. The project reached a 60% improvement on well times from the first well drilled to the best performing well. The best well was drilled in 8.68 days versus a field average of 18 days (217 m/day construction index). This generated 369,000 bbls of earlier oil production, 176 days ahead vs client expectations. Furthermore, in coordination with field staff, lessons learned were captured. But this is not enough since fast and effective communication is required, and the BoB methodology provides the solution to share optimization tricks quickly and effectively between crews, to continue well to well improvement and overall project and field level learning. Improved well delivery results is possible only by aligning the detailed planning and execution follow up in both the wellsite and a remote operations centre which monitored drilling activity in real time from town. This synergy and proactive communication system is also a key factor in the project delivery. This paper will present th
为了满足全球需求，墨西哥的石油和天然气产量具有挑战性。为了在这种充满挑战的环境中提供承诺的石油产量，作业者与主要服务提供商建立了有效的合作伙伴关系，以利用资源和技术诀窍，同时鼓励知识转移和降低钻井项目成本。通过与不同的服务公司合作，运营商创造了一个竞争环境，每个公司都在努力超越对方。“S”油田就是一个成功的例子，该油田位于墨西哥南部，是一个通过蒸汽注入生产的稠油油田。利用创新的设计和执行方法，“S”项目团队成功地提高了项目绩效，在整个项目中钻了14口井。平均井作业时间成功缩短了10%，从而将井建设指数最大化至122米/天，并降低了总体井成本。优化性能的主要策略是重新设计解决方案以提高盈利能力，例如进行研究以WBM取代OBM，设计新的井口系统，与钻机承包商合作减少平作业时间，重新设计水泥性能以减少损失，通过合并新技术和当地实践来提高ROP等等。与此相辅相成的是，该策略是通过开发和利用一种名为Best of the Best (BoB)的新工具来优先考虑实际的改进领域，这种方法可以分解所有井的活动，以测量每口井的最快时间，然后旨在实现这一激进的目标。现场的详细跟踪可以减少作业时间，让井场团队监控并建议新的和改进的方法来完成常规任务，所有这些都可以降低每英尺的成本。利用这种BoB方法和严格的钻井活动分析时的性能监测，可以实现卓越的性能。从第一口井到性能最佳的井，该项目的钻井时间缩短了60%。最好的一口井的钻井时间为8.68天，而油田的平均钻井时间为18天(施工指数为217米/天)。这使得原油产量提前了36.9万桶，比客户预期提前了176天。此外，与外地工作人员协调，吸取了经验教训。但这还不够，因为需要快速有效的沟通，BoB方法提供了解决方案，可以在工作人员之间快速有效地分享优化技巧，继续进行井与井之间的改进，以及整个项目和现场层面的学习。只有在井场和远程操作中心进行详细的规划和后续执行，并从城镇实时监控钻井活动，才能改善井的交付效果。这种协同和主动沟通系统也是项目交付的关键因素。本文将介绍在墨西哥首次应用“Best of Best”(BoB)方法的结果。这一成功的应用强化了这样一种理念:通过结合再工程实践，开发出更具创造性的井设计，并进行严格的性能监测;任何现场性能都可以得到改善，从而获得出色的结果。
{"title":"Leveraging a New Well Delivery Methodology for Stellar Drilling Results Steam Injection Project Case Study","authors":"Carlos Alejandro Terrones Brand, Miguel Alejandro Basso Mora, Rajeswary Kandasamy, Sergio Comarin, Felipe Rene Bustos Guevara, Beatriz Vega, Susana Pasaran","doi":"10.2118/204618-ms","DOIUrl":"https://doi.org/10.2118/204618-ms","url":null,"abstract":"\u0000 Mexico has set challenging oil and gas production to meet worldwide demand. In order to deliver promised oil production outputs in this challenging environment, the operator came up with efficient partnerships with key service providers to leverage resources and technical know-how whilst encouraging knowledge transfer and drilling project cost reduction. By working with various service companies, the operator creates a competitive environment where each strives to outperform the other. One such success case is in the \"S\" field, a heavy oil field producing via steam injection in the South of Mexico. Utilizing a creative design and execution methodology, the \"S\" project team succeeded to deliver improved project performance over the course of drilling the 14 wells in the campaign. The average well operational time was successfully reduced by 10%, hence maximizing the well construction index to 122 m/day and reducing overall well costs.\u0000 The main strategy to optimize performance is to re-engineer solutions for profitability such as performing a study to replace OBM by WBM, designing a new wellhead system, collaborating with the rig contractor to reduce flat time activities, redesigning cement properties for losses mitigation, improvement of ROP by merging new technologies and local practices, among others. Complementary to this, the strategy is to prioritize realistic areas of improvement by the development and utilization of a new tool called Best of the Best (BoB), a methodology breaking down all well activities in order to measure its fastest time per well and then aiming to achieve that aggressive goal. Detailed follow up in the field allows to reduce operational times by allowing the wellsite team monitor and suggest new and improved ways of doing a routine task all of which result in lower costs per foot. Utilizing this BoB approach and stringent performance monitoring while drilling (pre-actual-post) activity analysis, allowed superior performance to be achieved. The project reached a 60% improvement on well times from the first well drilled to the best performing well. The best well was drilled in 8.68 days versus a field average of 18 days (217 m/day construction index). This generated 369,000 bbls of earlier oil production, 176 days ahead vs client expectations.\u0000 Furthermore, in coordination with field staff, lessons learned were captured. But this is not enough since fast and effective communication is required, and the BoB methodology provides the solution to share optimization tricks quickly and effectively between crews, to continue well to well improvement and overall project and field level learning. Improved well delivery results is possible only by aligning the detailed planning and execution follow up in both the wellsite and a remote operations centre which monitored drilling activity in real time from town. This synergy and proactive communication system is also a key factor in the project delivery.\u0000 This paper will present th","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"81 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91512080","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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