Shehzad Ahmed, K. Elraies, A. Hanamertani, M. Hashmet, Siti Rohaida M. Shafian, Ivy Chai Ching Hsia
The application of CO2 foam has caught overwhelming attention for fracturing shales. In applications, high foam deterioration and insufficient viscosity at operating conditions are the major concerns associated with foam fracturing process. In this study, polymer-free CO2 foam possessing high stability has been presented through chemical screening and optimization under HPHT conditions. Initial screening was performed by conducting a series of foam stability experiments considering different commercial anionic surfactants, concentration, and foam stabilizer addition using FoamScan instrument. Foam rheology study was then performed by considering the similar investigated factors under fracturing conditions using HTHP foam rheometer. All the tested solutions were prepared in fixed brine salinity and HPAM polymers with different molecular weights were used in evaluation of the performance of the designed polymer-free foam in term of foam strength. In comparison with other types of surfactant, alpha olefin sulfonate (AOS) exhibited the best foam stability and viscosity at testing conditions. The optimum AOS concentration providing the best performance was found to be 5000 ppm and its combination with 5000 ppm of foam booster (betaine) further increased AOS foam longevity. An improved result on foam stability and viscosity was not obtained by increasing surfactant concentration. Results on foam rheology reveals that CO2 foam generated in the presence of different molecular weight classical HPAM polymers could not provide significant increment in foam viscosity under experimental conditions. It was observed that these types of polymer underwent degradation due to some unfavorable mechanisms which will be expected to negatively affect its performance during fracturing process. On the other hand, polymer-free CO2 foam was found to produce a higher stability and relatively equally high viscosity compared to polymer-stabilied CO2 foam without experiencing degradation at high pressure and temperature conditions. Therefore, based on this study, it is recommended to use polymer-free foam for fracturing shales application. The use of formulated polymer-free CO2 foam which has high stability and viscosity will lead to improved fracture cleanup, minimized formation damage and pore plugging, and efficient proppant placement which will ultimately enhance gas recovery from unconventional shales.
{"title":"Investigation of Carbon Dioxide Foam Performance Utilizing Different Additives for Fracturing Unconventional Shales","authors":"Shehzad Ahmed, K. Elraies, A. Hanamertani, M. Hashmet, Siti Rohaida M. Shafian, Ivy Chai Ching Hsia","doi":"10.2118/197964-ms","DOIUrl":"https://doi.org/10.2118/197964-ms","url":null,"abstract":"\u0000 The application of CO2 foam has caught overwhelming attention for fracturing shales. In applications, high foam deterioration and insufficient viscosity at operating conditions are the major concerns associated with foam fracturing process. In this study, polymer-free CO2 foam possessing high stability has been presented through chemical screening and optimization under HPHT conditions. Initial screening was performed by conducting a series of foam stability experiments considering different commercial anionic surfactants, concentration, and foam stabilizer addition using FoamScan instrument. Foam rheology study was then performed by considering the similar investigated factors under fracturing conditions using HTHP foam rheometer. All the tested solutions were prepared in fixed brine salinity and HPAM polymers with different molecular weights were used in evaluation of the performance of the designed polymer-free foam in term of foam strength. In comparison with other types of surfactant, alpha olefin sulfonate (AOS) exhibited the best foam stability and viscosity at testing conditions. The optimum AOS concentration providing the best performance was found to be 5000 ppm and its combination with 5000 ppm of foam booster (betaine) further increased AOS foam longevity. An improved result on foam stability and viscosity was not obtained by increasing surfactant concentration. Results on foam rheology reveals that CO2 foam generated in the presence of different molecular weight classical HPAM polymers could not provide significant increment in foam viscosity under experimental conditions. It was observed that these types of polymer underwent degradation due to some unfavorable mechanisms which will be expected to negatively affect its performance during fracturing process. On the other hand, polymer-free CO2 foam was found to produce a higher stability and relatively equally high viscosity compared to polymer-stabilied CO2 foam without experiencing degradation at high pressure and temperature conditions. Therefore, based on this study, it is recommended to use polymer-free foam for fracturing shales application. The use of formulated polymer-free CO2 foam which has high stability and viscosity will lead to improved fracture cleanup, minimized formation damage and pore plugging, and efficient proppant placement which will ultimately enhance gas recovery from unconventional shales.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84851475","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}
K. Deshpande, M. A. Celigueta, S. Latorre, E. Oñate, P. Naphade
Cuttings transport and hole-cleaning is a challenging issue associated with the efficiency of wellbore hydraulics and drilling operation. Traditional methods used to understand hole cleaning problems are based on field observations and extensive flow loop testing to formulate empirical correlations and mechanistic models. The focus of this study is to create digital twin utilizing advanced simulation techniques that provides better insight for cuttings transport and hole-cleaning. This study explores the use of Eulerian-Lagrangian based numerical techniques to estimate critical flow rate needed for efficient hole cleaning. Digital twin for the cuttings transport is formulated utilizing three dimensional Navier stokes equations employing combination of Eulerian and lagrangian approaches to model the drilling mud flow and cuttings interaction with the drilling mud, wellbore walls and between cuttings themselves. One of the important model to estimate the drag force on cuttings is modified for non-spherical cuttings shape coupled with non-newtonian Herschel Bulkley behavior of the drilling mud in this work. The influence of important parameters, such as fluid rheology, rotation of drill-string, and inclination of wellbore on the hole-cleaning process is investigated. Digital solutions are compared against the published data for Newtonian and non-Newtonian drilling fluids under different wellbore configurations. The advanced computational simulation involving novel drag force correlation and unique combination of numerical methods allowed to create digital twin for cuttings transport process accurately. The numerical strategy utilizing modified drag law showed a very good match with experimental results for straight vertical wellbore, the cuttings transport velocity estimated by digital solutions was within 5% difference of experimental results. Further upon validation, numerical results are successfully computed for drill -string rotation effects which clearly showed physics of cuttings transported efficiently with added energy due to rotation. The phenomenon of cuttings bed sliding in inclined and horizontal wellbores is also correctly simulated with the proposed drag law and numerical methods. The proposed methodology works without any issues with high concentration of cuttings and provides detailed insight into cuttings flow path and effect of various operational parameters on hole cleaning. Advanced computational simulations and modification of drag force law assisted in formulating digital twin that provided excellent insights in understanding effects of operational parameters for efficient hole cleaning.
{"title":"Digital Solutions Using Advanced Computational Techniques to Simulate Hole Cleaning","authors":"K. Deshpande, M. A. Celigueta, S. Latorre, E. Oñate, P. Naphade","doi":"10.2118/197864-ms","DOIUrl":"https://doi.org/10.2118/197864-ms","url":null,"abstract":"\u0000 Cuttings transport and hole-cleaning is a challenging issue associated with the efficiency of wellbore hydraulics and drilling operation. Traditional methods used to understand hole cleaning problems are based on field observations and extensive flow loop testing to formulate empirical correlations and mechanistic models. The focus of this study is to create digital twin utilizing advanced simulation techniques that provides better insight for cuttings transport and hole-cleaning. This study explores the use of Eulerian-Lagrangian based numerical techniques to estimate critical flow rate needed for efficient hole cleaning. Digital twin for the cuttings transport is formulated utilizing three dimensional Navier stokes equations employing combination of Eulerian and lagrangian approaches to model the drilling mud flow and cuttings interaction with the drilling mud, wellbore walls and between cuttings themselves. One of the important model to estimate the drag force on cuttings is modified for non-spherical cuttings shape coupled with non-newtonian Herschel Bulkley behavior of the drilling mud in this work. The influence of important parameters, such as fluid rheology, rotation of drill-string, and inclination of wellbore on the hole-cleaning process is investigated. Digital solutions are compared against the published data for Newtonian and non-Newtonian drilling fluids under different wellbore configurations. The advanced computational simulation involving novel drag force correlation and unique combination of numerical methods allowed to create digital twin for cuttings transport process accurately. The numerical strategy utilizing modified drag law showed a very good match with experimental results for straight vertical wellbore, the cuttings transport velocity estimated by digital solutions was within 5% difference of experimental results. Further upon validation, numerical results are successfully computed for drill -string rotation effects which clearly showed physics of cuttings transported efficiently with added energy due to rotation. The phenomenon of cuttings bed sliding in inclined and horizontal wellbores is also correctly simulated with the proposed drag law and numerical methods. The proposed methodology works without any issues with high concentration of cuttings and provides detailed insight into cuttings flow path and effect of various operational parameters on hole cleaning. Advanced computational simulations and modification of drag force law assisted in formulating digital twin that provided excellent insights in understanding effects of operational parameters for efficient hole cleaning.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90157972","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}
F. Hollaender, Y. Shumakov, Ozgur Karacali, B. Theuveny
Today many well test operations are performed in frontier environments targeting high potential oil and gas reservoirs or using high deliverability horizontal wells. Such highly productive wells cannot be dynamically evaluated to acquire representative reservoir data by small-scale flow tests. High flow rate well tests are introducing a set of unique challenges that need to be addressed at the design stage of the test, each requiring an appropriate surface well test spread, DST string as well as job operation procedures and equipment planning. Currently, well tests aiming at achieving very high flow rates are often designed and executed on a case-by-case basis, and there are no practical recommendations available that would summarise the well testing experience in such environments and guide the operator through the process to efficiently plan the well test operations. Well test operations are inherently challenging operations owing to the requirements for well control, accurate data acquisition, and the safe handling and disposal of produced fluids (hydrocarbons, completion brine, water, and solids), concerns are especially acute when considering high flow rates. Several past experiences have clearly shown limitations when trying to achieve high flow rates using conventional approaches and standard well test equipment. Concerns range from equipment failure and operational issues to poor interpretability of acquired data from those tests, increasing the total costs of such well tests or in extreme cases leading to severe HSE incidents. Enhancements in well testing equipment such as new generation well test separators equipped with high-range Coriolis mass flow meters or new generation burners, combined with fit-for-purpose well testing techniques make it possible to overcome these challenges. This paper will summarise the results and lessons learned from high flow rate well test operations performed around the globe on vertical and horizontal wells, in oil and gas reservoirs. The paper provides practical recommendations supported by a series of case studies from multiple oil and gas fields. The paper also describes a comprehensive list of challenges associated with high rate well test operations that can support successful operations design. Recipes for success are provided to ensure that safe operation can be performed in challenging environments.
{"title":"Well Testing to Full Potential: Lessons Learned and Best Practices for High Rate Wells","authors":"F. Hollaender, Y. Shumakov, Ozgur Karacali, B. Theuveny","doi":"10.2118/197754-ms","DOIUrl":"https://doi.org/10.2118/197754-ms","url":null,"abstract":"\u0000 Today many well test operations are performed in frontier environments targeting high potential oil and gas reservoirs or using high deliverability horizontal wells. Such highly productive wells cannot be dynamically evaluated to acquire representative reservoir data by small-scale flow tests.\u0000 High flow rate well tests are introducing a set of unique challenges that need to be addressed at the design stage of the test, each requiring an appropriate surface well test spread, DST string as well as job operation procedures and equipment planning. Currently, well tests aiming at achieving very high flow rates are often designed and executed on a case-by-case basis, and there are no practical recommendations available that would summarise the well testing experience in such environments and guide the operator through the process to efficiently plan the well test operations.\u0000 Well test operations are inherently challenging operations owing to the requirements for well control, accurate data acquisition, and the safe handling and disposal of produced fluids (hydrocarbons, completion brine, water, and solids), concerns are especially acute when considering high flow rates. Several past experiences have clearly shown limitations when trying to achieve high flow rates using conventional approaches and standard well test equipment.\u0000 Concerns range from equipment failure and operational issues to poor interpretability of acquired data from those tests, increasing the total costs of such well tests or in extreme cases leading to severe HSE incidents. Enhancements in well testing equipment such as new generation well test separators equipped with high-range Coriolis mass flow meters or new generation burners, combined with fit-for-purpose well testing techniques make it possible to overcome these challenges.\u0000 This paper will summarise the results and lessons learned from high flow rate well test operations performed around the globe on vertical and horizontal wells, in oil and gas reservoirs. The paper provides practical recommendations supported by a series of case studies from multiple oil and gas fields. The paper also describes a comprehensive list of challenges associated with high rate well test operations that can support successful operations design. Recipes for success are provided to ensure that safe operation can be performed in challenging environments.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"91 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78874854","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}
Abdulaziz Ellafi, H. Jabbari, M. B. Geri, Ethar H. K. Alkamil
In unconventional reservoirs, such as Bakken Fm, the stimulation application is the required method to develop and produce economically from this vast reserve. However, the production process is still only through primary depletion mechanism with low recovery factor in ranging of 3-5% due to sharp decline in oil production by depletion in natural fracture networks as well as unsuccessful implementation hydraulic fracturing design. This paper aims to investigate the application of HVFRs with surfactant in high TDS condition to enhance Bakken oil wells production performance using an integral methodology between 3D/2D Pseudo hydraulic fracturing simulator and numerical reservoir simulation. Four types of fracturing fluids as follows: Linear Gel, HVFR-A (mixed with freshwater), HVFR-B (mixed with produced water plus surfactant as additives), and HVFR-C (mixed with produced water) were tested using an integral approach. The workflow in this paper was started by modeling the optimal fracture half-length using 2D/PKN model based on the slurry volume per stage. As a next step, the optimum pump schedule was created using 3D Pseudo hydraulic fracturing simulator. Furthermore, the sensitivity analysis was performed on HVFR-B at different pump rate, final proppant concentration, and proppant size to investigate the proppant transport and production performance. Finally, reservoir simulation tool was utilized to investigate the changing in fracture parameters and evaluating the Bakken oil production. The results showed that HVFRs with surfactant is the optimum hydraulic fracture fluids that showed better performance in proppant transport, which responded by high fracture capability to improve oil production. The findings can be applied and compared to other unconventional shale plays, such as Eagle Ford and Permian Basin.
{"title":"Can HVFRs Increase the Oil Recovery in Hydraulic Fractures Applications?","authors":"Abdulaziz Ellafi, H. Jabbari, M. B. Geri, Ethar H. K. Alkamil","doi":"10.2118/197744-ms","DOIUrl":"https://doi.org/10.2118/197744-ms","url":null,"abstract":"\u0000 In unconventional reservoirs, such as Bakken Fm, the stimulation application is the required method to develop and produce economically from this vast reserve. However, the production process is still only through primary depletion mechanism with low recovery factor in ranging of 3-5% due to sharp decline in oil production by depletion in natural fracture networks as well as unsuccessful implementation hydraulic fracturing design. This paper aims to investigate the application of HVFRs with surfactant in high TDS condition to enhance Bakken oil wells production performance using an integral methodology between 3D/2D Pseudo hydraulic fracturing simulator and numerical reservoir simulation. Four types of fracturing fluids as follows: Linear Gel, HVFR-A (mixed with freshwater), HVFR-B (mixed with produced water plus surfactant as additives), and HVFR-C (mixed with produced water) were tested using an integral approach. The workflow in this paper was started by modeling the optimal fracture half-length using 2D/PKN model based on the slurry volume per stage. As a next step, the optimum pump schedule was created using 3D Pseudo hydraulic fracturing simulator. Furthermore, the sensitivity analysis was performed on HVFR-B at different pump rate, final proppant concentration, and proppant size to investigate the proppant transport and production performance. Finally, reservoir simulation tool was utilized to investigate the changing in fracture parameters and evaluating the Bakken oil production. The results showed that HVFRs with surfactant is the optimum hydraulic fracture fluids that showed better performance in proppant transport, which responded by high fracture capability to improve oil production. The findings can be applied and compared to other unconventional shale plays, such as Eagle Ford and Permian Basin.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84772478","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}
V. Saroj, F. Zadjali, S. Calvert, Ahmed Al Hattali, Mohamed Yousuf Said Al Rawahi, A. Hussain, Dawood Al Kharusi
This paper discusses the further development of Burhaan West Field, a complex multilayered onshore tight gas reservoir that is one of the largest in the Sultanate of Oman. After several years of production through vertical comingled fractured wells, the foreseen decline below production target triggered an integrated assessment of the field. After considering various subsurface development and surface evacuation options, an opportunity for further field development at minimum cost was identified and selected. The integrated assessment of the field for further development optimization included the following work-streams: Interdisciplinary data analysis to determine the critical elements of the recovery process.Building a range of integrated models capturing the subsurface complexity and diversity of rock properties.Optimized well type and spacing which focused on the advantages of infill drilling for improved aerial/vertical drainage.Phased development along with de-risking of the newly proposed areas.Decision based integrated production modelling to screen various evacuation options.Cost optimizationThe development of a Well Reservoir and Facility Management (WRFM) strategy. The proposed optimized field development enhances the field gas production capacity by 50%, while increasing ultimate recovery by 24%. This is achieved at low surface development cost, utilizing existing facilities, through infill drilling in the Core area and development of the Extension area. The conducted work highlighted the following key aspects of developing a tight gas reservoir: Integrated cross-discipline data analysis is required to identify the critical elements contributing to gas and condensate recovery processes. In the Burhaan Field, this has revealed the presence of key marginally resolvable to sub-seismic features that were not previously identified.Integrated Assessment (Integrated Production Modelling) enables for robust and quick evaluation of a variety of surface development options (e.g. evacuation routes and capacity) that is a key in achieving significant project cost optimization.Large gas field developments generally benefit from a phased development approach, where newly proposed areas can be de-risked while high confidence areas are being developed.A comprehensive WRFM plan is a key component of field development. This plan focuses on the activities required to address the field specific uncertainties and associated risks. It needs to be strictly implemented to ensure the delivery of promised volumes. This case study shares the insights on the challenges faced in developing multi-layered tight gas fields. It highlights how development decisions need to be governed by field specific characteristics that can be identified through multi-disciplinary integrated data analysis. The paper also provides an example of an effective Production Modelling workflow to screen through surface development options and demonstrates how focused data acquisition an
{"title":"Large Multilayered Tight Gas Condensate Field Development Optimization with Integrated Assessment of Subsurface Data and Surface Evacuation Options: A Case Study in the Sultanate of Oman","authors":"V. Saroj, F. Zadjali, S. Calvert, Ahmed Al Hattali, Mohamed Yousuf Said Al Rawahi, A. Hussain, Dawood Al Kharusi","doi":"10.2118/197277-ms","DOIUrl":"https://doi.org/10.2118/197277-ms","url":null,"abstract":"\u0000 This paper discusses the further development of Burhaan West Field, a complex multilayered onshore tight gas reservoir that is one of the largest in the Sultanate of Oman. After several years of production through vertical comingled fractured wells, the foreseen decline below production target triggered an integrated assessment of the field. After considering various subsurface development and surface evacuation options, an opportunity for further field development at minimum cost was identified and selected. The integrated assessment of the field for further development optimization included the following work-streams: Interdisciplinary data analysis to determine the critical elements of the recovery process.Building a range of integrated models capturing the subsurface complexity and diversity of rock properties.Optimized well type and spacing which focused on the advantages of infill drilling for improved aerial/vertical drainage.Phased development along with de-risking of the newly proposed areas.Decision based integrated production modelling to screen various evacuation options.Cost optimizationThe development of a Well Reservoir and Facility Management (WRFM) strategy.\u0000 The proposed optimized field development enhances the field gas production capacity by 50%, while increasing ultimate recovery by 24%. This is achieved at low surface development cost, utilizing existing facilities, through infill drilling in the Core area and development of the Extension area. The conducted work highlighted the following key aspects of developing a tight gas reservoir: Integrated cross-discipline data analysis is required to identify the critical elements contributing to gas and condensate recovery processes. In the Burhaan Field, this has revealed the presence of key marginally resolvable to sub-seismic features that were not previously identified.Integrated Assessment (Integrated Production Modelling) enables for robust and quick evaluation of a variety of surface development options (e.g. evacuation routes and capacity) that is a key in achieving significant project cost optimization.Large gas field developments generally benefit from a phased development approach, where newly proposed areas can be de-risked while high confidence areas are being developed.A comprehensive WRFM plan is a key component of field development. This plan focuses on the activities required to address the field specific uncertainties and associated risks. It needs to be strictly implemented to ensure the delivery of promised volumes.\u0000 This case study shares the insights on the challenges faced in developing multi-layered tight gas fields. It highlights how development decisions need to be governed by field specific characteristics that can be identified through multi-disciplinary integrated data analysis. The paper also provides an example of an effective Production Modelling workflow to screen through surface development options and demonstrates how focused data acquisition an","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"337 15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77415477","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}
Performance comparisons of different tier friction reducers (FRs) using field water samples from the Delaware and Midland basins within the Permian Basin are discussed. The objective is to correlate them with their respective water mineralogy to identify the primary components affecting FR effectiveness, allowing a proper FR selection based on individual elements and not just by total dissolved solids (TDS). Identifying critical minerals that affect the proper FR selection enables making an educated FR selection not based on TDS count alone, which could potentially reduce the amount of testing and unsuccessful field trials. To zero in on the primary elements within the water that affect friction reduction behavior, extensive testing was performed. Traditional and inductive couple plasma (ICP) water analyses were performed to determine mineralogy, and flow loop testing was performed to determine FR performance. Additionally, specific parameters (i.e., hydration time, maximum FR percentage, and stability) were measured and compared to the multiple tests to determine trends between FR performance and water mineralogy. Understanding how a flow loop apparatus works is discussed, which helps when interpreting friction reduction performance. This is a fundamental component for understanding the behavior of the FR during testing and how it affects performance in the field. Additionally, this paper can be used as a basic guide for flow loop interpretation, and it attempts to identify possible causes of varying FR behavior in the field versus laboratory testing.
{"title":"Selecting Friction Reducers Based on Variability in the Completion Water Mineralogy: Case Study, Permian Basin","authors":"Federico Zamar, Cinthia Mendoza, Faraaz Adil","doi":"10.2118/197667-ms","DOIUrl":"https://doi.org/10.2118/197667-ms","url":null,"abstract":"\u0000 Performance comparisons of different tier friction reducers (FRs) using field water samples from the Delaware and Midland basins within the Permian Basin are discussed. The objective is to correlate them with their respective water mineralogy to identify the primary components affecting FR effectiveness, allowing a proper FR selection based on individual elements and not just by total dissolved solids (TDS). Identifying critical minerals that affect the proper FR selection enables making an educated FR selection not based on TDS count alone, which could potentially reduce the amount of testing and unsuccessful field trials.\u0000 To zero in on the primary elements within the water that affect friction reduction behavior, extensive testing was performed. Traditional and inductive couple plasma (ICP) water analyses were performed to determine mineralogy, and flow loop testing was performed to determine FR performance. Additionally, specific parameters (i.e., hydration time, maximum FR percentage, and stability) were measured and compared to the multiple tests to determine trends between FR performance and water mineralogy.\u0000 Understanding how a flow loop apparatus works is discussed, which helps when interpreting friction reduction performance. This is a fundamental component for understanding the behavior of the FR during testing and how it affects performance in the field. Additionally, this paper can be used as a basic guide for flow loop interpretation, and it attempts to identify possible causes of varying FR behavior in the field versus laboratory testing.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77962042","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 new vision with new techniques of wells’ upper and lower completions have been applied successfully throughout a giant offshore multi-reservoir oilfield. Wells with long to very-long laterals have been completed successfully following a systematic strategy based applications and showed tremendous success. This paper will present the various techniques used completing wells in different reservoirs considering well-integrity and HSE regulations in order to achieve the maximum wells’ deliverability’s at their lowest costs throughout the well life. Many challenges were faced and overcame in order to reach the optimum completion that suits each well. A complete journey from reservoir simulation to well and network models, well performance to reservoir management studies, from geological models and interpretation to geo-science and seismic inputs, in addition to actual production data, all helped to achieve the over-all target. From the phase of design to the phase of implementation and beyond to the production phase, each piece of information yielded a certain potential that led to a certain completion design based on available data and expectations. This paper will discuss the new innovative upper and lower completion designs’ strategies along with the execution and performance from production engineering perspective in order to reach the maximum productivity for the life cycle from these long horizontal wells at the lowest possible cost. The extended lateral length in these wells warrants innovative designs in upper and lower completions, as the traditional completion designs no longer suite to address the challenges in these wells. The key well design and planning process involves designing the upper completion including suitable tubing size with the most effective and durable gas-lift system, and lower completion liner designs for different wells’ cases. Efficient initial strategies to start-up wells including some protocols with well-performance monitoring and reservoir surveillance. The paper will also address and discuss the challenges in long horizontal wells such as accessibility, production/injection conformance, and effective stimulations of these laterals. This paper will discuss and show many examples of the completed wells with different types of completions and a comparison of their performances after initial startup and during the back-flow period in addition to the extended performance during normal flowing conditions. Some LEL wells were logged and stimulated showing excellent results; these results will be shared in the paper. It is concluded that the LEL completion proved itself to be the future for lower completion to be widely used in the field. The novelty of such new applications were that they were designed in-house and applied on considerable number of long lateral wells showing excellent results that is changing the completion future strategy in the field and may be in the region or even worldwid
{"title":"Strategic Engineering Application for Long Lateral Wells","authors":"Ahmed Kiyoumi, Alaa Amin, Y. Ali, Rajes Sau","doi":"10.2118/197968-ms","DOIUrl":"https://doi.org/10.2118/197968-ms","url":null,"abstract":"\u0000 \u0000 \u0000 A new vision with new techniques of wells’ upper and lower completions have been applied successfully throughout a giant offshore multi-reservoir oilfield. Wells with long to very-long laterals have been completed successfully following a systematic strategy based applications and showed tremendous success. This paper will present the various techniques used completing wells in different reservoirs considering well-integrity and HSE regulations in order to achieve the maximum wells’ deliverability’s at their lowest costs throughout the well life. Many challenges were faced and overcame in order to reach the optimum completion that suits each well. A complete journey from reservoir simulation to well and network models, well performance to reservoir management studies, from geological models and interpretation to geo-science and seismic inputs, in addition to actual production data, all helped to achieve the over-all target. From the phase of design to the phase of implementation and beyond to the production phase, each piece of information yielded a certain potential that led to a certain completion design based on available data and expectations.\u0000 \u0000 \u0000 \u0000 This paper will discuss the new innovative upper and lower completion designs’ strategies along with the execution and performance from production engineering perspective in order to reach the maximum productivity for the life cycle from these long horizontal wells at the lowest possible cost. The extended lateral length in these wells warrants innovative designs in upper and lower completions, as the traditional completion designs no longer suite to address the challenges in these wells. The key well design and planning process involves designing the upper completion including suitable tubing size with the most effective and durable gas-lift system, and lower completion liner designs for different wells’ cases. Efficient initial strategies to start-up wells including some protocols with well-performance monitoring and reservoir surveillance. The paper will also address and discuss the challenges in long horizontal wells such as accessibility, production/injection conformance, and effective stimulations of these laterals.\u0000 \u0000 \u0000 \u0000 This paper will discuss and show many examples of the completed wells with different types of completions and a comparison of their performances after initial startup and during the back-flow period in addition to the extended performance during normal flowing conditions. Some LEL wells were logged and stimulated showing excellent results; these results will be shared in the paper. It is concluded that the LEL completion proved itself to be the future for lower completion to be widely used in the field.\u0000 \u0000 \u0000 \u0000 The novelty of such new applications were that they were designed in-house and applied on considerable number of long lateral wells showing excellent results that is changing the completion future strategy in the field and may be in the region or even worldwid","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78574782","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In this paper we will set out how we maximise the value created by the digital revolution through the use Systems Thinking and Agile techniques to establish a FEL 0-1 Digital Twin, we will then describe how we use a BIM approach to evolve this Digital Twin through the project lifecycle; fostering collaboration, breaking down siloes, creating and protecting value as we do so. Two case studies, one an offshore gas compression project and the other a normally unmanned wellhead installation, will be presented to demonstrate the application and effectiveness of this approach.
{"title":"Starting with the End in Mind: The Path to Realising Digital Value","authors":"D. McLachlan","doi":"10.2118/197366-ms","DOIUrl":"https://doi.org/10.2118/197366-ms","url":null,"abstract":"\u0000 In this paper we will set out how we maximise the value created by the digital revolution through the use Systems Thinking and Agile techniques to establish a FEL 0-1 Digital Twin, we will then describe how we use a BIM approach to evolve this Digital Twin through the project lifecycle; fostering collaboration, breaking down siloes, creating and protecting value as we do so. Two case studies, one an offshore gas compression project and the other a normally unmanned wellhead installation, will be presented to demonstrate the application and effectiveness of this approach.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78596389","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 digital transformation in the energy sector has specific features arising from the characteristics of the sector, the dimensions of the assets and the complexity of the technologies and processes utilized in the research, production, transformation, and transportation and sale of energy to the end-user. This paper describes the performance model developed in Eni to measure the success of the digital transformation programme. A top-down approach was developed for the three main sectors/areas impacted by the transformation i.e. the Industrial and Commercial sectors and the Support Functions area. The model is structured in 3 layers: Strategic Goals, Company Results and Business Lines / Assets Operational Performances. For each layer, different sets of KPIs have been identified to measure the contribution provided to the Company's targets both operational and economic, from the digital transformation programme. Those KPIs are also complemented with indicators to monitor the progress of the on-going initiatives/projects and of the Change Management programme. Some preliminary results and next steps are also discussed.
{"title":"A Distinctive Approach to Performance Measurement of a Digital Transformation Programme in an Energy Company","authors":"M. Talamonti, L. Siciliano","doi":"10.2118/197539-ms","DOIUrl":"https://doi.org/10.2118/197539-ms","url":null,"abstract":"\u0000 The digital transformation in the energy sector has specific features arising from the characteristics of the sector, the dimensions of the assets and the complexity of the technologies and processes utilized in the research, production, transformation, and transportation and sale of energy to the end-user.\u0000 This paper describes the performance model developed in Eni to measure the success of the digital transformation programme. A top-down approach was developed for the three main sectors/areas impacted by the transformation i.e. the Industrial and Commercial sectors and the Support Functions area.\u0000 The model is structured in 3 layers: Strategic Goals, Company Results and Business Lines / Assets Operational Performances. For each layer, different sets of KPIs have been identified to measure the contribution provided to the Company's targets both operational and economic, from the digital transformation programme. Those KPIs are also complemented with indicators to monitor the progress of the on-going initiatives/projects and of the Change Management programme. Some preliminary results and next steps are also discussed.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"193 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77300368","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}
Production of Oil, Gas and Petrochemical from production units is becoming very competitive every day. As products are sold in open market, production cost drives an organization's profitability. To keep a plant available for production as much as possible, Asset Performance Management (APM) or Asset Integrity Management (AIM)is the key. Risk based inspection (RBI) is a decision making tool that deals with integrity management of static equipment and piping through focus on prioritizing inspection based on the risk. Review of published guidelines for RBI such as API RP 580/581, ASME PCC3, DNV-RP-G101, EN 16991 etc., suggests that they provide either oversimplified or complex explanations which makes it difficult for beginners to grasp all the aspects that are critical for a successful RBI project. Therefore, this paper is aimed to provide and discuss the essential elements for effective RBI implementation project in a simplified way. RBI project can be divided into four major phases i.e project initiation and pre-requisites, workshops & trainings, RBI analysis phase and post RBI actions. Each of these stages is discussed with details in this paper. An overview of successful RBI program used within the industry and from the ADNOC LNG RBI implementation experience, is provided with details. Project management approach for RBI program implementation is conveyed by dividing project into different phases and highlighting the inputs/outputs and activities for each phase. Objectives, time and resources such as data and personnel required, software features that are essential, project planning and monitoring are provided. RBI program implemented efficiently in accordance with suggested plan, results in an overall optimization of inspection for static equipment/piping while maintaining their integrity as part of a broader APM or AIM strategy.
生产单位的石油、天然气和石化产品的竞争日益激烈。当产品在公开市场上销售时，生产成本驱动组织的盈利能力。为了使工厂尽可能多地用于生产，资产绩效管理(APM)或资产完整性管理(AIM)是关键。基于风险的检查(RBI)是一种决策工具，通过关注基于风险的检查优先级来处理静态设备和管道的完整性管理。回顾已发布的RBI指南，如API RP 580/581, ASME PCC3, DNV-RP-G101, EN 16991等，表明它们提供的解释要么过于简单，要么过于复杂，这使得初学者很难掌握成功RBI项目的所有关键方面。因此，本文旨在以一种简化的方式提供和讨论有效的RBI实施项目的基本要素。RBI项目可以分为四个主要阶段，即项目启动和先决条件，研讨会和培训，RBI分析阶段和后RBI行动。本文详细讨论了每一个阶段。详细介绍了行业内成功使用的RBI计划以及ADNOC LNG RBI实施经验。RBI计划实施的项目管理方法是通过将项目划分为不同的阶段并突出每个阶段的输入/输出和活动来传达的。提供目标、时间和资源，如所需的数据和人员、必要的软件特性、项目计划和监测。RBI计划按照建议的计划有效实施，使静态设备/管道的检查得到全面优化，同时保持其完整性，作为更广泛的APM或AIM战略的一部分。
{"title":"Implementing a Successful Risk Based Inspection Program","authors":"Asad Ali, H. Sabry","doi":"10.2118/197790-ms","DOIUrl":"https://doi.org/10.2118/197790-ms","url":null,"abstract":"\u0000 Production of Oil, Gas and Petrochemical from production units is becoming very competitive every day. As products are sold in open market, production cost drives an organization's profitability. To keep a plant available for production as much as possible, Asset Performance Management (APM) or Asset Integrity Management (AIM)is the key. Risk based inspection (RBI) is a decision making tool that deals with integrity management of static equipment and piping through focus on prioritizing inspection based on the risk.\u0000 Review of published guidelines for RBI such as API RP 580/581, ASME PCC3, DNV-RP-G101, EN 16991 etc., suggests that they provide either oversimplified or complex explanations which makes it difficult for beginners to grasp all the aspects that are critical for a successful RBI project. Therefore, this paper is aimed to provide and discuss the essential elements for effective RBI implementation project in a simplified way. RBI project can be divided into four major phases i.e project initiation and pre-requisites, workshops & trainings, RBI analysis phase and post RBI actions. Each of these stages is discussed with details in this paper.\u0000 An overview of successful RBI program used within the industry and from the ADNOC LNG RBI implementation experience, is provided with details. Project management approach for RBI program implementation is conveyed by dividing project into different phases and highlighting the inputs/outputs and activities for each phase. Objectives, time and resources such as data and personnel required, software features that are essential, project planning and monitoring are provided.\u0000 RBI program implemented efficiently in accordance with suggested plan, results in an overall optimization of inspection for static equipment/piping while maintaining their integrity as part of a broader APM or AIM strategy.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85711290","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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