Interwell tracers are powerful reservoir surveillance tools that provide direct reservoir flow paths and dynamics, which, when integrated with near real-time production optimization, can greatly improve recovery factor, and return on investment, the so-called "Advanced Tracers System" (ATS). Applying full field ATS is attractive for resource-holders, especially for those with large waterflood operations. However, to scale up ATS to cover large fields with potentially tens to hundreds of injectors and producers, the required unique tracer variations ("barcodes") and materials and associated analysis may increase rapidly. Here, we explore different tracer injection schemes that can acquire the most information while using reduced numbers of tracers, thereby controlling costs in field operations. We tested the designs of various modified tracer injection schemes with reservoir simulations. Numerical experiments were performed on synthetic fields with multiple injector and producer wells in waterflooding patterns. Two tracer injection schemes were considered: In Scheme 1, all injectors were injected with unique tracers representing the most information-rich case. In Scheme 2, some injectors were injected with the same tracers ("recycling" the same barcodes), and some injectors received no tracer injection ("null" barcodes). Production and tracer breakthrough data was collected for history matching after waterflooding simulations on the synthetic fields. The ensemble smoother with multiple data assimilation with tracers algorithm was used for history matching. We calculated the root-mean-square errors (RMSE) between the reference data and the history matched production simulation data. To improve the statistics, 20 independent testing reference synthetic fields were constructed by randomizing the number and locations of high permeability zones crossing different injectors and producers. In all cases, the history matching algorithms largely reduced the RMSE thereby enhancing reservoir characterization. Analyzing the statistical significance with p-values among testing cases, first, as expected, the data mismatch is highly significantly lower after history matching than before history matching (p < 0.001). Second, the data mismatch is even lower when history matching with tracers (both in Scheme 1 and 2) than without tracers (p < 0.05), demonstrating clearly that tracers can provide extra information for the reservoir dynamics. Finally, and most importantly, history matching with tracers in Scheme 1 or in Scheme 2 result in statistically the same data mismatch (p > 0.05), indicating the cost-saving "recycling" and "null" tracer barcodes can provide equally competent reservoir information. To the best of our knowledge, this is the first study that evaluated the history matching qualities deriving from different tracer injection schemes. We showed that through optimal designs of the tracer injections, we can acquire very similar information with redu
{"title":"Optimization of Tracer Injection Schemes for Improved History Matching","authors":"Hsieh Chen, Hooisweng Ow, M. Poitzsch","doi":"10.2118/206142-ms","DOIUrl":"https://doi.org/10.2118/206142-ms","url":null,"abstract":"\u0000 Interwell tracers are powerful reservoir surveillance tools that provide direct reservoir flow paths and dynamics, which, when integrated with near real-time production optimization, can greatly improve recovery factor, and return on investment, the so-called \"Advanced Tracers System\" (ATS). Applying full field ATS is attractive for resource-holders, especially for those with large waterflood operations. However, to scale up ATS to cover large fields with potentially tens to hundreds of injectors and producers, the required unique tracer variations (\"barcodes\") and materials and associated analysis may increase rapidly. Here, we explore different tracer injection schemes that can acquire the most information while using reduced numbers of tracers, thereby controlling costs in field operations.\u0000 We tested the designs of various modified tracer injection schemes with reservoir simulations. Numerical experiments were performed on synthetic fields with multiple injector and producer wells in waterflooding patterns. Two tracer injection schemes were considered: In Scheme 1, all injectors were injected with unique tracers representing the most information-rich case. In Scheme 2, some injectors were injected with the same tracers (\"recycling\" the same barcodes), and some injectors received no tracer injection (\"null\" barcodes). Production and tracer breakthrough data was collected for history matching after waterflooding simulations on the synthetic fields. The ensemble smoother with multiple data assimilation with tracers algorithm was used for history matching.\u0000 We calculated the root-mean-square errors (RMSE) between the reference data and the history matched production simulation data. To improve the statistics, 20 independent testing reference synthetic fields were constructed by randomizing the number and locations of high permeability zones crossing different injectors and producers. In all cases, the history matching algorithms largely reduced the RMSE thereby enhancing reservoir characterization. Analyzing the statistical significance with p-values among testing cases, first, as expected, the data mismatch is highly significantly lower after history matching than before history matching (p < 0.001). Second, the data mismatch is even lower when history matching with tracers (both in Scheme 1 and 2) than without tracers (p < 0.05), demonstrating clearly that tracers can provide extra information for the reservoir dynamics. Finally, and most importantly, history matching with tracers in Scheme 1 or in Scheme 2 result in statistically the same data mismatch (p > 0.05), indicating the cost-saving \"recycling\" and \"null\" tracer barcodes can provide equally competent reservoir information.\u0000 To the best of our knowledge, this is the first study that evaluated the history matching qualities deriving from different tracer injection schemes. We showed that through optimal designs of the tracer injections, we can acquire very similar information with redu","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77673432","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Carlsen, Braden Bowie, M. M. Dahouk, S. Mydland, C. H. Whitson, Ilina Yusra
We extend the numerically-assisted RTA workflow proposed by Bowie and Ewert (2020) to (a) all fluid systems and (b) finite conductivity fractures. The simple, fully-penetrating planar fracture model proposed is a useful numerical symmetry element model that provides the basis for the work presented in this paper. Results are given for simulated and field data. The linear flow parameter (LFP) is modified to include porosity (LFPꞌ=LFP√φ). The original (surface) oil in place (OOIP) is generalized to represent both reservoir oil and reservoir gas condensate systems, using a consistent initial total formation volume factor definition (Bti) representing the ratio of a reservoir HCPV containing surface oil in a reservoir oil phase, a reservoir gas phase, or both phases. With known (a) well geometry, (b) fluid initialization (PVT and water saturation), (c) relative permeability relations, and (d) bottomhole pressure (BHP) time variation (above and below saturation pressure), three fundamental relationships exist in terms of LFPꞌ and OOIP. Numerical reservoir simulation is used to define these relationships, providing the foundation for numerical RTA, namely that wells: (1) with the same value of LFPꞌ, the gas, oil and water surface rates will be identical during infinite-acting (IA) behavior; (2) with the same ratio LFPꞌ/OOIP, producing GOR and water cut behavior will be identical for all times, IA and boundary dominated (BD); and (3) with the same values of LFPꞌ and OOIP, rate performance of gas, oil, and water be identical for all times, IA and BD. These observations lead to an efficient, semi-automated process to perform rigorous RTA, assisted by a symmetry element numerical model. The numerical RTA workflow proposed by Bowie and Ewert solves the inherent problems associated with complex superposition and multiphase flow effects involving time and spatial changes in pressure, compositions and PVT properties, saturations, and complex phase mobilities. The numerical RTA workflow decouples multiphase flow data (PVT, initial saturations and relative permeabilities) from well geometry and petrophysical properties (L, xf, h, nf, φ, k), providing a rigorous yet efficient and semi-automated approach to define production performance for many wells. Contributions include a technical framework to perform numerical RTA for unconventional wells, irrespective of fluid type. A suite of key diagnostic plots associated with the workflow is provided, with synthetic and field examples used to illustrate the application of numerical simulation to perform rigorous RTA. Semi-analytical models, time, and spatial superposition (convolution), pseudopressure and pseudotime transforms are not required.
{"title":"Numerical RTA in Tight Unconventionals","authors":"M. Carlsen, Braden Bowie, M. M. Dahouk, S. Mydland, C. H. Whitson, Ilina Yusra","doi":"10.2118/205884-ms","DOIUrl":"https://doi.org/10.2118/205884-ms","url":null,"abstract":"\u0000 We extend the numerically-assisted RTA workflow proposed by Bowie and Ewert (2020) to (a) all fluid systems and (b) finite conductivity fractures. The simple, fully-penetrating planar fracture model proposed is a useful numerical symmetry element model that provides the basis for the work presented in this paper. Results are given for simulated and field data.\u0000 The linear flow parameter (LFP) is modified to include porosity (LFPꞌ=LFP√φ). The original (surface) oil in place (OOIP) is generalized to represent both reservoir oil and reservoir gas condensate systems, using a consistent initial total formation volume factor definition (Bti) representing the ratio of a reservoir HCPV containing surface oil in a reservoir oil phase, a reservoir gas phase, or both phases.\u0000 With known (a) well geometry, (b) fluid initialization (PVT and water saturation), (c) relative permeability relations, and (d) bottomhole pressure (BHP) time variation (above and below saturation pressure), three fundamental relationships exist in terms of LFPꞌ and OOIP. Numerical reservoir simulation is used to define these relationships, providing the foundation for numerical RTA, namely that wells: (1) with the same value of LFPꞌ, the gas, oil and water surface rates will be identical during infinite-acting (IA) behavior; (2) with the same ratio LFPꞌ/OOIP, producing GOR and water cut behavior will be identical for all times, IA and boundary dominated (BD); and (3) with the same values of LFPꞌ and OOIP, rate performance of gas, oil, and water be identical for all times, IA and BD. These observations lead to an efficient, semi-automated process to perform rigorous RTA, assisted by a symmetry element numerical model.\u0000 The numerical RTA workflow proposed by Bowie and Ewert solves the inherent problems associated with complex superposition and multiphase flow effects involving time and spatial changes in pressure, compositions and PVT properties, saturations, and complex phase mobilities.\u0000 The numerical RTA workflow decouples multiphase flow data (PVT, initial saturations and relative permeabilities) from well geometry and petrophysical properties (L, xf, h, nf, φ, k), providing a rigorous yet efficient and semi-automated approach to define production performance for many wells.\u0000 Contributions include a technical framework to perform numerical RTA for unconventional wells, irrespective of fluid type. A suite of key diagnostic plots associated with the workflow is provided, with synthetic and field examples used to illustrate the application of numerical simulation to perform rigorous RTA. Semi-analytical models, time, and spatial superposition (convolution), pseudopressure and pseudotime transforms are not required.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81919476","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. Schuman, Buddhabhushan Salunkhe, Ali Al Brahim, B. Bai
Preformed particle gels (PPGs), a type of hydrogel, have been widely applied to control the conformance of reservoirs owing to their robust gel chemistries. Traditional PPGs are polyacrylamide-based hydrogel compositions which can withstand neither higher temperatures nor high salinity conditions. There are many deep oilfield reservoirs worldwide which demand PPG products with a long term hydrolytic and thermal stability at the temperatures of higher than 120 °C. Current PPGs neither remain hydrated nor retain polymer integrity at these temperatures. A unique high temperature-resistant hydrogel composition (HT-PPG) was developed with exceptional thermal stability for greater than 18 months in North Sea formation temperature (~130 °C) and formation water environments. HT-PPG described herein can swell up to 30 times its initial volume in brines of different salinity for North Sea. The effects of salinity and temperature on swelling, swelling rate, and rheological behavior was studied. These HT-PPGs exhibit excellent strength with storage modulus (G’) of over 3,000 Pa at the swelling ratio of 10. Thermostability evaluations were performed in North Sea brines with variable salinity at temperatures of 130 °C and 150 °C and found to be stable for 18 months with no loss of molecular integrity at the higher temperature. Laboratory core flooding tests were conducted to test its plugging efficiency to fracture. HT-PPGs showed good plugging efficiency by reducing the permeability of open fracture and did not wash out during waterflooding. Overall, HT-PPG is a novel product with excellent hydrothermal stability that make it an ideal candidate for conformance problems associated with reservoirs of high temperature and salinity conditions.
{"title":"Development and Evaluation of Ultra-High Temperature Resistant Preformed Particle Gels for Conformance Control in North Sea Reservoirs","authors":"T. Schuman, Buddhabhushan Salunkhe, Ali Al Brahim, B. Bai","doi":"10.2118/206007-ms","DOIUrl":"https://doi.org/10.2118/206007-ms","url":null,"abstract":"\u0000 Preformed particle gels (PPGs), a type of hydrogel, have been widely applied to control the conformance of reservoirs owing to their robust gel chemistries. Traditional PPGs are polyacrylamide-based hydrogel compositions which can withstand neither higher temperatures nor high salinity conditions. There are many deep oilfield reservoirs worldwide which demand PPG products with a long term hydrolytic and thermal stability at the temperatures of higher than 120 °C. Current PPGs neither remain hydrated nor retain polymer integrity at these temperatures. A unique high temperature-resistant hydrogel composition (HT-PPG) was developed with exceptional thermal stability for greater than 18 months in North Sea formation temperature (~130 °C) and formation water environments. HT-PPG described herein can swell up to 30 times its initial volume in brines of different salinity for North Sea. The effects of salinity and temperature on swelling, swelling rate, and rheological behavior was studied. These HT-PPGs exhibit excellent strength with storage modulus (G’) of over 3,000 Pa at the swelling ratio of 10. Thermostability evaluations were performed in North Sea brines with variable salinity at temperatures of 130 °C and 150 °C and found to be stable for 18 months with no loss of molecular integrity at the higher temperature. Laboratory core flooding tests were conducted to test its plugging efficiency to fracture. HT-PPGs showed good plugging efficiency by reducing the permeability of open fracture and did not wash out during waterflooding. Overall, HT-PPG is a novel product with excellent hydrothermal stability that make it an ideal candidate for conformance problems associated with reservoirs of high temperature and salinity conditions.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76812574","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}
Jingfei Tang, B. Audrey, Jin-Taung Lin, X. Meng, Chao Yu, Taiji Wang, Andrew Fendt, Gayatri P. Kartoatmodjo
The field is located in a large gas producing basin in China and has prominent characteristics such as thin formation thickness, low permeability and poor reservoir connectivity. Horizontal drilling associated with multistage hydraulic fracturing has proven to be an effective technique to produce the hydrocarbon in this field. As the gas wells matures, the production rate starts to decline due to the decreasing of the bottom hole pressure which will prompt a liquid loading issue. A trending gas production loss is up to 150 mmscf in a year due to liquid loading issue alone, which is equivalent to $1.8MM revenue loss. An analytical decline rate showed that the field is declining 3.4% to 4.6% monthly due to the descending of the casing pressure, superimposed with low backflow ratio after hydraulic fracturing, which create a technical and economic challenge to produce effectively. In addition, the location between well pads are remote and far apart. This creates HSE challenge for personnel to go to the well pads, especially during icy road in the winter. Solid soap stick had been tried as a deliquifications method, unfortunately the result is unsustainable without frequent injection. It is also very much relying on human intervention. Due to that, an alternative liquid lift loading system is introduced in the field. An intelligent plunger lift has been piloted in 12 wells in the field to reduce the liquid loading issue in mid 2021. Apart from the apparent advantages of plunger lift such as mitigation of liquid fallback, zero input energy and low operating/maintenance cost, this system is not desirable to fully close well at downstroke process which comes up with increment of gas production comparing to traditional plunger lift system. One of the major advantages is the real time production data surveillance to enable remote operations based on its intelligence flow control system and downhole sensor.
{"title":"Intelligent Plunger Lift: Digital and Cost-Effective Solution to Unlock Gas Potential in a Large Tight Gas Field in China","authors":"Jingfei Tang, B. Audrey, Jin-Taung Lin, X. Meng, Chao Yu, Taiji Wang, Andrew Fendt, Gayatri P. Kartoatmodjo","doi":"10.2118/206123-ms","DOIUrl":"https://doi.org/10.2118/206123-ms","url":null,"abstract":"\u0000 The field is located in a large gas producing basin in China and has prominent characteristics such as thin formation thickness, low permeability and poor reservoir connectivity. Horizontal drilling associated with multistage hydraulic fracturing has proven to be an effective technique to produce the hydrocarbon in this field.\u0000 As the gas wells matures, the production rate starts to decline due to the decreasing of the bottom hole pressure which will prompt a liquid loading issue. A trending gas production loss is up to 150 mmscf in a year due to liquid loading issue alone, which is equivalent to $1.8MM revenue loss. An analytical decline rate showed that the field is declining 3.4% to 4.6% monthly due to the descending of the casing pressure, superimposed with low backflow ratio after hydraulic fracturing, which create a technical and economic challenge to produce effectively. In addition, the location between well pads are remote and far apart. This creates HSE challenge for personnel to go to the well pads, especially during icy road in the winter.\u0000 Solid soap stick had been tried as a deliquifications method, unfortunately the result is unsustainable without frequent injection. It is also very much relying on human intervention. Due to that, an alternative liquid lift loading system is introduced in the field. An intelligent plunger lift has been piloted in 12 wells in the field to reduce the liquid loading issue in mid 2021. Apart from the apparent advantages of plunger lift such as mitigation of liquid fallback, zero input energy and low operating/maintenance cost, this system is not desirable to fully close well at downstroke process which comes up with increment of gas production comparing to traditional plunger lift system. One of the major advantages is the real time production data surveillance to enable remote operations based on its intelligence flow control system and downhole sensor.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81347143","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}
Lost circulation problems may result in a significant downtime, a considerable reduction of the rate of penetration, or even well control problems. Despite advances in manufacturing lost circulation materials (LCMs), some formations, like heavily fractured carbonates, have complete losses during drilling. We develop smart LCMs using shape memory polymers (SMPs), and program them thermo-mechanically to satisfy size limitations imposed by bottomhole assemblies (BHA). Elevated downhole temperatures act as an external trigger to recover the permanent shape of LCMs, which could expand ten times larger than the temporary (programmed) dimensions for deployment. Smart LCMs are a combination of various material categories such as granular, fibrous (one-dimensional or 1-D) and planar (two-dimensional or 2-D) configurations that resume to the original shape after exposure to high temperatures. The LCMs form different structures such as flatted pellet, disc-shaped, spider-shaped, and spindled, which, respectively, presents grains, 1-D fibers, 2-D stars, and 2-D lattices after recovery. A combination of the above categories attempt to build three-dimensional (3-D) plugging capabilities across various sized fractures.
{"title":"Smart Lost Circulation Materials to Seal Large Fractures","authors":"M. Tabatabaei, A. Dahi Taleghani","doi":"10.2118/205873-ms","DOIUrl":"https://doi.org/10.2118/205873-ms","url":null,"abstract":"\u0000 Lost circulation problems may result in a significant downtime, a considerable reduction of the rate of penetration, or even well control problems. Despite advances in manufacturing lost circulation materials (LCMs), some formations, like heavily fractured carbonates, have complete losses during drilling. We develop smart LCMs using shape memory polymers (SMPs), and program them thermo-mechanically to satisfy size limitations imposed by bottomhole assemblies (BHA). Elevated downhole temperatures act as an external trigger to recover the permanent shape of LCMs, which could expand ten times larger than the temporary (programmed) dimensions for deployment. Smart LCMs are a combination of various material categories such as granular, fibrous (one-dimensional or 1-D) and planar (two-dimensional or 2-D) configurations that resume to the original shape after exposure to high temperatures. The LCMs form different structures such as flatted pellet, disc-shaped, spider-shaped, and spindled, which, respectively, presents grains, 1-D fibers, 2-D stars, and 2-D lattices after recovery. A combination of the above categories attempt to build three-dimensional (3-D) plugging capabilities across various sized fractures.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76341562","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 Petroleum Working Group (PWG) of the United Nations Economic Commission for Europe (UNECE) has developed the Petroleum Resource Specifications and Guidelines (PRSG) to facilitate the application of the United Nations Framework Classification for Resources (UNFC) for evaluating and classifying petroleum projects. The UNFC was developed by the Expert Group on Resource Management (EGRM) and covers all resource sectors such as minerals, petroleum, renewable energy, nuclear resources, injection projects, anthropogenic resources and groundwater. It has a unique three- dimensional structure to describe environmental, social and economic viability (E-axis), technical feasibility and maturity (F-axis) and degree of confidence in the resource estimates (G-axis). The UNFC is fully aligned to holistic and sustainable resource management called for by the 2030 Agenda for Sustainable Development (2030 Agenda). UNFC can be used by governments for integrated energy planning, companies for developing business models and the investors in decision making. Internationally, all classification systems and their application continue to evolve to incorporate the latest technical understanding and usage and societal, government and regulatory expectations. The PRSG incorporates key elements from current global petroleum classification systems. Furthermore, it provides a forward-thinking approach to including aspects of integrity and ethics. It expands on the unique differentiator of the UNFC to integrate social and environmental issues in the project evaluation. Several case studies have been carried out (in China, Kuwait, Mexico, Russia, and Uganda) using UNFC. Specifically, PRSG assists in identifying critical social and environmental issues to support their resolution and development sustainably. These issues may be unique to the country, location and projects and mapped using a risk matrix. This may support the development of a road map to resolve potential impediments to project sanction. The release of the PRSG comes at a time of global economic volatility on a national and international level due to the ongoing impact and management of COVID-19, petroleum supply and demand uncertainty and competing national and international interests. Sustainable energy is not only required for industries but for all other social development. It is essential for private sector development, productive capacity building and expansion of trade. It has strong linkages to climate action, health, education, water, food security and woman empowerment. Moreover, enduring complex system considerations in balancing the energy trilemma of reliable supply, affordability, equity, and social and environmental responsibility remain. These overarching conditions make it even more essential to ensure projects are evaluated in a competent, ethical and transparent manner. While considering all the risks, it is also critical to reinforce the positive contribution a natural resource utilizat
{"title":"Development of the Petroleum Resource Specifications and Guidelines PRSG – A Petroleum Classification System for the Energy Transition","authors":"Barbara Pribyl, S. Purewal, H. Tulsidas","doi":"10.2118/205847-ms","DOIUrl":"https://doi.org/10.2118/205847-ms","url":null,"abstract":"\u0000 The Petroleum Working Group (PWG) of the United Nations Economic Commission for Europe (UNECE) has developed the Petroleum Resource Specifications and Guidelines (PRSG) to facilitate the application of the United Nations Framework Classification for Resources (UNFC) for evaluating and classifying petroleum projects. The UNFC was developed by the Expert Group on Resource Management (EGRM) and covers all resource sectors such as minerals, petroleum, renewable energy, nuclear resources, injection projects, anthropogenic resources and groundwater. It has a unique three- dimensional structure to describe environmental, social and economic viability (E-axis), technical feasibility and maturity (F-axis) and degree of confidence in the resource estimates (G-axis). The UNFC is fully aligned to holistic and sustainable resource management called for by the 2030 Agenda for Sustainable Development (2030 Agenda). UNFC can be used by governments for integrated energy planning, companies for developing business models and the investors in decision making.\u0000 Internationally, all classification systems and their application continue to evolve to incorporate the latest technical understanding and usage and societal, government and regulatory expectations. The PRSG incorporates key elements from current global petroleum classification systems. Furthermore, it provides a forward-thinking approach to including aspects of integrity and ethics. It expands on the unique differentiator of the UNFC to integrate social and environmental issues in the project evaluation.\u0000 Several case studies have been carried out (in China, Kuwait, Mexico, Russia, and Uganda) using UNFC. Specifically, PRSG assists in identifying critical social and environmental issues to support their resolution and development sustainably. These issues may be unique to the country, location and projects and mapped using a risk matrix. This may support the development of a road map to resolve potential impediments to project sanction.\u0000 The release of the PRSG comes at a time of global economic volatility on a national and international level due to the ongoing impact and management of COVID-19, petroleum supply and demand uncertainty and competing national and international interests. Sustainable energy is not only required for industries but for all other social development. It is essential for private sector development, productive capacity building and expansion of trade. It has strong linkages to climate action, health, education, water, food security and woman empowerment. Moreover, enduring complex system considerations in balancing the energy trilemma of reliable supply, affordability, equity, and social and environmental responsibility remain. These overarching conditions make it even more essential to ensure projects are evaluated in a competent, ethical and transparent manner. While considering all the risks, it is also critical to reinforce the positive contribution a natural resource utilizat","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86124430","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}
Anjana Panchakarla, Tapan Kidambi, Ashish Sharma, E. Cazeneuve, R. Singh, A. Sv
Drilling wells in the remote northeastern part of India has always been a tremendous challenge owing to the subsurface complexity. This paper highlights the case of an exploratory well drilled in this region primarily targeting the main hydrocarbon bearing formations. The lithology characterized by mainly shale, siltstone and claystone sequences, are known to project high variance in terms of acoustic anisotropy. Additionally some mixed lithological sequences are also noted at particular depths and have been identified at posing potential problems during drilling operations. Several issues became apparent during the course of drilling the well, the main factor being consistently poor borehole condition. An added factor potentially exacerbating the progressively worsening borehole conditions was attributed to the significant tectonic activity in the area. To address and identify these issues and to pave the way for future operations in this region, a Deep Shear Wave Imaging analysis was commissioned to identify near and far wellbore geological features, in addition to addressing the geomechanical response of these formations. In this regard, acoustic based stress profiling and acoustic anisotropy analysis was carried out to estimate borehole stability for the drilled well section and provide insights for future drilling plans. Significant losses were observed while drilling the well, in addition to secondary problems including tight spots and hold ups and consequently the well had to be back reamed multiple times. Of particular note were the losses observed while transitioning between the main formations of interest. The former consisting relatively lower density claystone/siltstone formations and the latter, somewhat shalier interlayered with sandstones, displaying a generally higher density trend. This transition zone proved to be tricky while drilling, as a high density sandstone patch was encountered further impeding the drilling ROP. Overall, both formations were characterized by significantly low rock strength moduli with the exception of the sandstones projecting characteristically higher strengths. In light of these events, analysis of integrated geological, geomechanical and advanced borehole acoustic data analyses were used to identify the nature of the anisotropy, in terms of either stress induced, or caused by the presence of fractures in the vicinity of the borehole. The extensive analysis further identified sub-seismic features impeding drillability in these lithologies. Further, the holistic approach helped characterize the pressure regimes in different formations and in parallel, based on corroboration from available data, constrained stress magnitudes, indicating a transitional faulting regime. Variances in stress settings corresponded to the depths just above the transition zone, where significant variations were observed in shear wave azimuthal trends thereby indicating the presence of potential fracture clusters, some of wh
{"title":"Integration of Acoustics and Geomechanical Modelling for Subsurface Characterization in Tectonically Active Sedimentary Basins: A Case Study from Northeast India","authors":"Anjana Panchakarla, Tapan Kidambi, Ashish Sharma, E. Cazeneuve, R. Singh, A. Sv","doi":"10.2118/206229-ms","DOIUrl":"https://doi.org/10.2118/206229-ms","url":null,"abstract":"\u0000 Drilling wells in the remote northeastern part of India has always been a tremendous challenge owing to the subsurface complexity. This paper highlights the case of an exploratory well drilled in this region primarily targeting the main hydrocarbon bearing formations. The lithology characterized by mainly shale, siltstone and claystone sequences, are known to project high variance in terms of acoustic anisotropy. Additionally some mixed lithological sequences are also noted at particular depths and have been identified at posing potential problems during drilling operations.\u0000 Several issues became apparent during the course of drilling the well, the main factor being consistently poor borehole condition. An added factor potentially exacerbating the progressively worsening borehole conditions was attributed to the significant tectonic activity in the area. To address and identify these issues and to pave the way for future operations in this region, a Deep Shear Wave Imaging analysis was commissioned to identify near and far wellbore geological features, in addition to addressing the geomechanical response of these formations. In this regard, acoustic based stress profiling and acoustic anisotropy analysis was carried out to estimate borehole stability for the drilled well section and provide insights for future drilling plans.\u0000 Significant losses were observed while drilling the well, in addition to secondary problems including tight spots and hold ups and consequently the well had to be back reamed multiple times. Of particular note were the losses observed while transitioning between the main formations of interest. The former consisting relatively lower density claystone/siltstone formations and the latter, somewhat shalier interlayered with sandstones, displaying a generally higher density trend. This transition zone proved to be tricky while drilling, as a high density sandstone patch was encountered further impeding the drilling ROP. Overall, both formations were characterized by significantly low rock strength moduli with the exception of the sandstones projecting characteristically higher strengths. In light of these events, analysis of integrated geological, geomechanical and advanced borehole acoustic data analyses were used to identify the nature of the anisotropy, in terms of either stress induced, or caused by the presence of fractures in the vicinity of the borehole. The extensive analysis further identified sub-seismic features impeding drillability in these lithologies. Further, the holistic approach helped characterize the pressure regimes in different formations and in parallel, based on corroboration from available data, constrained stress magnitudes, indicating a transitional faulting regime. Variances in stress settings corresponded to the depths just above the transition zone, where significant variations were observed in shear wave azimuthal trends thereby indicating the presence of potential fracture clusters, some of wh","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82640984","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}
G. Chaves, H. Karami, D. D. Monteiro, Virgílio José Martins Ferreira
Flowrate is a valuable information for the oil and gas industry. High accuracy on flowrate estimation enhances production operations to control and manage the production. Recognized as a cost-efficient solution, the VFM (virtual flowmeter) is a mathematical-based technology designed to estimate the flowrates using available field instrumentation. The VFM approach developed in this work combines black-box simulations with mixed-integer linear programming (MILP) problem to obtain the flowrates dismissing the tuning process. The methodology included a set of multiphase flow correlations, and the MILP was developed to estimate the flowrate and designate the best fit model. We evaluated the proposed VFM against 649 well test data. The methodology presented 4.1% average percentage error (APE) for percentile 25% and 13.5% APE for percentile 50%. We developed a VFM technology to be used in scenarios with a lack of data, and we believe that our tuning-free method can contribute to the future of VFM technologies.
{"title":"Development of a Virtual Flowmeter as an Enhanced Alternative for Field Production Monitoring","authors":"G. Chaves, H. Karami, D. D. Monteiro, Virgílio José Martins Ferreira","doi":"10.2118/206259-ms","DOIUrl":"https://doi.org/10.2118/206259-ms","url":null,"abstract":"\u0000 Flowrate is a valuable information for the oil and gas industry. High accuracy on flowrate estimation enhances production operations to control and manage the production. Recognized as a cost-efficient solution, the VFM (virtual flowmeter) is a mathematical-based technology designed to estimate the flowrates using available field instrumentation. The VFM approach developed in this work combines black-box simulations with mixed-integer linear programming (MILP) problem to obtain the flowrates dismissing the tuning process. The methodology included a set of multiphase flow correlations, and the MILP was developed to estimate the flowrate and designate the best fit model. We evaluated the proposed VFM against 649 well test data. The methodology presented 4.1% average percentage error (APE) for percentile 25% and 13.5% APE for percentile 50%. We developed a VFM technology to be used in scenarios with a lack of data, and we believe that our tuning-free method can contribute to the future of VFM technologies.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87326802","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}
J. Griffin, D. J. Rojas, A. Al Shmakhy, P. Scranton
The hydraulic fracture treatment (HFT) and its effectiveness to enhance wellbore drainage directly correlate with each well’s overall production performance and underlining economics. This paper will discuss the potential of ultra high stage count Single Point Entry (SPE) sleeves and their ability to increase control over proppant placement and isolation during the HFT as a method for optimizing well performance, economics, and reduce non-uniformity between treatments and wells. To address the limitations of current completion methods, full ID single point entry systems have been developed for open hole and cemented applications. These systems provide unlimited frac stage count with lower frac tortuosity, provide increased control over proppant placement and well production, reduce or eliminate over- flush and formation damage, and achieve higher efficiency during and after frac stimulation than previous conventional plug-and-perf (PnP) and sleeve systems, thereby reducing costs. While the ball-and-seat completion technique revolutionized the efficiency of multi-stage single point entry fracturing, its vast array of limitations (primarily ID restrictions), limited stage count, and compatibility with cemented liners quickly sidelined it in place of PnP. PnP offers increased surface area contact through additional entry points compared to sleeve systems of the past and remains the accepted method for achieving zonal isolation and initiation during stimulation. However, the time intensive operations of PnP present challenges in maintaining efficiencies due to variability in wireline during deployment and coiled tubing during millouts. The increase in number of clusters per stage and number of stages per well achieved with PnP often results in higher stimulated rock volumes (SRV) however, due to the number of multiple clusters open simultaneously, this method gained a "pump-n-pray" reputation due to the uncertainty of cluster efficiency and its unpredictability. The lack of cluster control over the years has created a series of challenges in terms of parent-child well relationships and spacing, economical asset development, and loss of potential production. With over 4,000 stages fracture stimulated across US, Canada, and Asia, some wells containing 220 individual stages, this paper will address the differences in production in terms of bbl of oil equivalent (BOE) for direct and indirect offsets in trials, compare capital efficiency with spud to put on production (POP) timelines, demonstrate economical completion optimization for lower commodity pricing of oil, and carbon intensity reduction measures to lower greenhouse gas emissions.
{"title":"Application of Interventionless Single Point Entry Technology to Improve Proppant Placement Control and Well Production","authors":"J. Griffin, D. J. Rojas, A. Al Shmakhy, P. Scranton","doi":"10.2118/205865-ms","DOIUrl":"https://doi.org/10.2118/205865-ms","url":null,"abstract":"\u0000 The hydraulic fracture treatment (HFT) and its effectiveness to enhance wellbore drainage directly correlate with each well’s overall production performance and underlining economics. This paper will discuss the potential of ultra high stage count Single Point Entry (SPE) sleeves and their ability to increase control over proppant placement and isolation during the HFT as a method for optimizing well performance, economics, and reduce non-uniformity between treatments and wells.\u0000 To address the limitations of current completion methods, full ID single point entry systems have been developed for open hole and cemented applications. These systems provide unlimited frac stage count with lower frac tortuosity, provide increased control over proppant placement and well production, reduce or eliminate over- flush and formation damage, and achieve higher efficiency during and after frac stimulation than previous conventional plug-and-perf (PnP) and sleeve systems, thereby reducing costs.\u0000 While the ball-and-seat completion technique revolutionized the efficiency of multi-stage single point entry fracturing, its vast array of limitations (primarily ID restrictions), limited stage count, and compatibility with cemented liners quickly sidelined it in place of PnP. PnP offers increased surface area contact through additional entry points compared to sleeve systems of the past and remains the accepted method for achieving zonal isolation and initiation during stimulation. However, the time intensive operations of PnP present challenges in maintaining efficiencies due to variability in wireline during deployment and coiled tubing during millouts. The increase in number of clusters per stage and number of stages per well achieved with PnP often results in higher stimulated rock volumes (SRV) however, due to the number of multiple clusters open simultaneously, this method gained a \"pump-n-pray\" reputation due to the uncertainty of cluster efficiency and its unpredictability. The lack of cluster control over the years has created a series of challenges in terms of parent-child well relationships and spacing, economical asset development, and loss of potential production.\u0000 With over 4,000 stages fracture stimulated across US, Canada, and Asia, some wells containing 220 individual stages, this paper will address the differences in production in terms of bbl of oil equivalent (BOE) for direct and indirect offsets in trials, compare capital efficiency with spud to put on production (POP) timelines, demonstrate economical completion optimization for lower commodity pricing of oil, and carbon intensity reduction measures to lower greenhouse gas emissions.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86987535","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. Al-Turki, Obai Alnajjar, M. Baddourah, B. Moriwawon
The algorithms and workflows have been developed to couple efficient model parameterization with stochastic, global optimization using a Multi-Objective Genetic Algorithm (MOGA) for global history matching, and coupled with an advanced workflow for streamline sensitivity-based inversion for fine-tuning. During parameterization the low-rank subsets of most influencing reservoir parameters are identified and propagated to MOGA to perform the field-level history match. Data misfits between the field historical data and simulation data are calculated with multiple realizations of reservoir models that quantify and capture reservoir uncertainty. Each generation of the optimization algorithms reduces the data misfit relative to the previous iteration. This iterative process continues until a satisfactory field-level history match is reached or there are no further improvements. The fine-tuning process of well-connectivity calibration is then performed with a streamlined sensitivity-based inversion algorithm to locally update the model to reduce well-level mismatch. In this study, an application of the proposed algorithms and workflow is demonstrated for model calibration and history matching. The synthetic reservoir model used in this study is discretized into millions of grid cells with hundreds of producer and injector wells. It is designed to generate several decades of production and injection history to evaluate and demonstrate the workflow. In field-level history matching, reservoir rock properties (e.g., permeability, fault transmissibility, etc.) are parameterized to conduct the global match of pressure and production rates. Grid Connectivity Transform (GCT) was used and assessed to parameterize the reservoir properties. In addition, the convergence rate and history match quality of MOGA was assessed during the field (global) history matching. Also, the effectiveness of the streamline-based inversion was evaluated by quantifying the additional improvement in history matching quality per well. The developed parametrization and optimization algorithms and workflows revealed the unique features of each of the algorithms for model calibration and history matching. This integrated workflow has successfully defined and carried uncertainty throughout the history matching process. Following the successful field-level history match, the well-level history matching was conducted using streamline sensitivity-based inversion, which further improved the history match quality and conditioned the model to historical production and injection data. In general, the workflow results in enhanced history match quality in a shorter turnaround time. The geological realism of the model is retained for robust prediction and development planning.
{"title":"Compressed Dimension of Reservoir Models Uncertainty Parameters for Optimized Model Calibration and History Matching Process","authors":"A. Al-Turki, Obai Alnajjar, M. Baddourah, B. Moriwawon","doi":"10.2118/206066-ms","DOIUrl":"https://doi.org/10.2118/206066-ms","url":null,"abstract":"\u0000 The algorithms and workflows have been developed to couple efficient model parameterization with stochastic, global optimization using a Multi-Objective Genetic Algorithm (MOGA) for global history matching, and coupled with an advanced workflow for streamline sensitivity-based inversion for fine-tuning. During parameterization the low-rank subsets of most influencing reservoir parameters are identified and propagated to MOGA to perform the field-level history match. Data misfits between the field historical data and simulation data are calculated with multiple realizations of reservoir models that quantify and capture reservoir uncertainty. Each generation of the optimization algorithms reduces the data misfit relative to the previous iteration. This iterative process continues until a satisfactory field-level history match is reached or there are no further improvements. The fine-tuning process of well-connectivity calibration is then performed with a streamlined sensitivity-based inversion algorithm to locally update the model to reduce well-level mismatch.\u0000 In this study, an application of the proposed algorithms and workflow is demonstrated for model calibration and history matching. The synthetic reservoir model used in this study is discretized into millions of grid cells with hundreds of producer and injector wells. It is designed to generate several decades of production and injection history to evaluate and demonstrate the workflow. In field-level history matching, reservoir rock properties (e.g., permeability, fault transmissibility, etc.) are parameterized to conduct the global match of pressure and production rates. Grid Connectivity Transform (GCT) was used and assessed to parameterize the reservoir properties. In addition, the convergence rate and history match quality of MOGA was assessed during the field (global) history matching. Also, the effectiveness of the streamline-based inversion was evaluated by quantifying the additional improvement in history matching quality per well.\u0000 The developed parametrization and optimization algorithms and workflows revealed the unique features of each of the algorithms for model calibration and history matching. This integrated workflow has successfully defined and carried uncertainty throughout the history matching process. Following the successful field-level history match, the well-level history matching was conducted using streamline sensitivity-based inversion, which further improved the history match quality and conditioned the model to historical production and injection data. In general, the workflow results in enhanced history match quality in a shorter turnaround time. The geological realism of the model is retained for robust prediction and development planning.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"81 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76695082","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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