The problem of water production in carbonate reservoir is always a worldwide problem; meanwhile, in heavy oil reservoir with bottom water, rapid water breakthrough or high water cut is the development feature of this kind of reservoir; the problem of high water production in infill wells in old reservoir area is very common. Each of these three kinds of problems is difficult to be tackled for oilfield developers. When these three kinds of problems occur in a well, the difficulty of water shutoff can be imagined. Excessive water production will not only reduce the oil rate of wells, but also increase the cost of water treatment, and even lead to well shut in. Therefore, how to solve the problem of produced water from infill wells in old area of heavy oil reservoir with bottom water in carbonate rock will be the focus of this paper. This paper elaborates the application of continuous pack-off particles with ICD screen (CPI) technology in infill wells newly put into production in brown field of Liuhua, South China Sea. Liuhua oilfield is a biohermal limestone heavy oil reservoir with strong bottom water. At present, the recovery is only 11%, and the comprehensive water cut is as high as 96%. Excessive water production greatly reduces the hydrocarbon production of the oil well, which makes the production of the oilfield decrease rapidly. In order to delay the decline of oil production, Liuhua oilfield has adopted the mainstream water shutoff technology, including chemical and mechanical water shutoff methods. The application results show that the adaptability of mainstream water shutoff technology in Liuhua oilfield needs to be improved. Although CPI has achieved good water shutoff effect in the development and old wells in block 3 of Liuhua oilfield, there is no application case in the old area of Liuhua oilfield which has been developed for decades, so the application effect is still unclear. At present, the average water cut of new infill wells in the old area reaches 80% when commissioned and rises rapidly to more than 90% one month later. Considering that there is more remaining oil distribution in the old area of Liuhua oilfield and the obvious effect of CPI in block 3, it is decided to apply CPI in infill well X of old area for well completion. CPI is based on the ICD screen radial high-speed fluid containment and pack-off particles in the wellbore annulus to prevent fluid channeling axially, thus achieving well bore water shutoff and oil enhancement. As for the application in fractured reef limestone reservoir, the CPI not only has the function of wellbore water shutoff, but also fills the continuous pack-off particles into the natural fractures in the formation, so as to achieve dual water shutoff in wellbore and fractures, and further enhance the effect of water shutoff and oil enhancement. The target well X is located in the old area of Liuhua oilfield, which is a new infill well in the old area. This target well with three kinds of w
{"title":"An Innovated Water Shutoff Technology in Offshore Carbonate Reservoir","authors":"Yong Yang, Xiaodong Li, Changwei Sun, Yuanzhi Liu, Renkai Jiang, Bailin Pei, Wei Zhao","doi":"10.2118/204593-ms","DOIUrl":"https://doi.org/10.2118/204593-ms","url":null,"abstract":"\u0000 The problem of water production in carbonate reservoir is always a worldwide problem; meanwhile, in heavy oil reservoir with bottom water, rapid water breakthrough or high water cut is the development feature of this kind of reservoir; the problem of high water production in infill wells in old reservoir area is very common. Each of these three kinds of problems is difficult to be tackled for oilfield developers. When these three kinds of problems occur in a well, the difficulty of water shutoff can be imagined. Excessive water production will not only reduce the oil rate of wells, but also increase the cost of water treatment, and even lead to well shut in. Therefore, how to solve the problem of produced water from infill wells in old area of heavy oil reservoir with bottom water in carbonate rock will be the focus of this paper.\u0000 This paper elaborates the application of continuous pack-off particles with ICD screen (CPI) technology in infill wells newly put into production in brown field of Liuhua, South China Sea. Liuhua oilfield is a biohermal limestone heavy oil reservoir with strong bottom water. At present, the recovery is only 11%, and the comprehensive water cut is as high as 96%. Excessive water production greatly reduces the hydrocarbon production of the oil well, which makes the production of the oilfield decrease rapidly. In order to delay the decline of oil production, Liuhua oilfield has adopted the mainstream water shutoff technology, including chemical and mechanical water shutoff methods. The application results show that the adaptability of mainstream water shutoff technology in Liuhua oilfield needs to be improved. Although CPI has achieved good water shutoff effect in the development and old wells in block 3 of Liuhua oilfield, there is no application case in the old area of Liuhua oilfield which has been developed for decades, so the application effect is still unclear. At present, the average water cut of new infill wells in the old area reaches 80% when commissioned and rises rapidly to more than 90% one month later. Considering that there is more remaining oil distribution in the old area of Liuhua oilfield and the obvious effect of CPI in block 3, it is decided to apply CPI in infill well X of old area for well completion.\u0000 CPI is based on the ICD screen radial high-speed fluid containment and pack-off particles in the wellbore annulus to prevent fluid channeling axially, thus achieving well bore water shutoff and oil enhancement. As for the application in fractured reef limestone reservoir, the CPI not only has the function of wellbore water shutoff, but also fills the continuous pack-off particles into the natural fractures in the formation, so as to achieve dual water shutoff in wellbore and fractures, and further enhance the effect of water shutoff and oil enhancement.\u0000 The target well X is located in the old area of Liuhua oilfield, which is a new infill well in the old area. This target well with three kinds of w","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"54 5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84364722","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}
Muhamad Aizat B Kamaruddin, A. Ashqar, Muhammad Haniff Suhaimi, F. A. Salleh
Uncertainties in fluid typing and contacts within Sarawak Offshore brown field required a real time decision. To enhance reservoir fluid characterisation and confirm reservoir connectivity prior to well final total depth (TD). Fluid typing while drilling was selected to assure the completion strategy and ascertain the fluvial reservoir petrophysical interpretation. Benefiting from low invasion, Logging While Drilling (LWD) sampling fitted with state of ART advanced spectroscopy sensors were deployed. Pressures and samples were collected. The well was drilled using synthetic base mud. Conventional logging while drilling tool string in addition to sampling tool that is equipped with advanced sensor technology were deployed. While drilling real time formation evaluation allowed selecting the zones of interest, while fluid typing was confirmed using continually monitored fluids pump out via multiple advanced sensors, contamination, and reservoir fluid properties were assessed while pumping. Pressure and sampling were performed in drilling mode to minimise reservoir damage, and optimise rig time, additionally sampling while drilling was performed under circulation conditions. Pressures were collected first followed by sampling. High success in collecting pressure points with a reliable fluid gradient that indicated a virgin reservoir allowed the selection of best completion strategy without jeopardising reserves, and reduced rig time. Total of seven samples from 3 different reservoirs, four oil, and three formation water. High quality samples were collected. The dynamic formation evaluation supported by while drilling sampling confirmed the reservoir fluid type and successfully discovered 39ft of oil net pay. Reservoir was completed as an oil producer. The Optical spectroscopy measurements allowed in situ fluid typing for the quick decision making. The use of advanced optical sensors allowed the sample collection and gave initial assessment on reservoir fluids properties, as a result cost saving due to eliminating the need for additional Drill Stem Test (DST) run to confirm the fluid type. Sample and formation pressures has confirmed reservoir lateral continuity in the vicinity of the field. The reservoir developed as thick and blocky sandstone. Collected sample confirmed the low contamination levels. Continuous circulation mitigated sticking and potential well-control risks. This is the first time in surrounding area, advanced optical sensors are used to aid LWD sampling and to finalize the fluid identification. The innovative technology allowed the collection of low contamination. The real-time in-situ fluid analysis measurement allowed critical decisions to be made real time, consequently reducing rig downtime. Reliable analysis of fluid type identification removed the need for additional run/service like DST etc.
{"title":"Dynamic Formation Evaluation to Reduce Uncertainty and Confirm Completed Intervals in Brown Fields","authors":"Muhamad Aizat B Kamaruddin, A. Ashqar, Muhammad Haniff Suhaimi, F. A. Salleh","doi":"10.2118/204758-ms","DOIUrl":"https://doi.org/10.2118/204758-ms","url":null,"abstract":"\u0000 Uncertainties in fluid typing and contacts within Sarawak Offshore brown field required a real time decision. To enhance reservoir fluid characterisation and confirm reservoir connectivity prior to well final total depth (TD). Fluid typing while drilling was selected to assure the completion strategy and ascertain the fluvial reservoir petrophysical interpretation. Benefiting from low invasion, Logging While Drilling (LWD) sampling fitted with state of ART advanced spectroscopy sensors were deployed. Pressures and samples were collected.\u0000 The well was drilled using synthetic base mud. Conventional logging while drilling tool string in addition to sampling tool that is equipped with advanced sensor technology were deployed. While drilling real time formation evaluation allowed selecting the zones of interest, while fluid typing was confirmed using continually monitored fluids pump out via multiple advanced sensors, contamination, and reservoir fluid properties were assessed while pumping. Pressure and sampling were performed in drilling mode to minimise reservoir damage, and optimise rig time, additionally sampling while drilling was performed under circulation conditions. Pressures were collected first followed by sampling.\u0000 High success in collecting pressure points with a reliable fluid gradient that indicated a virgin reservoir allowed the selection of best completion strategy without jeopardising reserves, and reduced rig time. Total of seven samples from 3 different reservoirs, four oil, and three formation water. High quality samples were collected. The dynamic formation evaluation supported by while drilling sampling confirmed the reservoir fluid type and successfully discovered 39ft of oil net pay. Reservoir was completed as an oil producer. The Optical spectroscopy measurements allowed in situ fluid typing for the quick decision making. The use of advanced optical sensors allowed the sample collection and gave initial assessment on reservoir fluids properties, as a result cost saving due to eliminating the need for additional Drill Stem Test (DST) run to confirm the fluid type. Sample and formation pressures has confirmed reservoir lateral continuity in the vicinity of the field. The reservoir developed as thick and blocky sandstone. Collected sample confirmed the low contamination levels. Continuous circulation mitigated sticking and potential well-control risks.\u0000 This is the first time in surrounding area, advanced optical sensors are used to aid LWD sampling and to finalize the fluid identification. The innovative technology allowed the collection of low contamination. The real-time in-situ fluid analysis measurement allowed critical decisions to be made real time, consequently reducing rig downtime. Reliable analysis of fluid type identification removed the need for additional run/service like DST etc.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"80 3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83150363","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
D. Marum, A. Cartellieri, Edisa Shahini, Donata Scanavino
In the high risk Managed Pressure Drilling operations, increased certainty given by Mud Logging is a critical deliverable to guarantee a safe drilling environment even under challenging conditions and, to provide the first indications for reservoir evaluation. This paper describes a novel product application that successfully obtains advanced mud gas data from a Managed Pressure Drilling environment, proven in flow-loop and field applications (in Lower Saxony, Germany), by reducing service footprint as well as power consumption.
{"title":"A Novel and Sustainable Generation of Advanced Mud Gas Logging System for Managed Pressure Drilling Applications: An Explorative Well Deployment from North Germany","authors":"D. Marum, A. Cartellieri, Edisa Shahini, Donata Scanavino","doi":"10.2118/204887-ms","DOIUrl":"https://doi.org/10.2118/204887-ms","url":null,"abstract":"\u0000 \u0000 \u0000 In the high risk Managed Pressure Drilling operations, increased certainty given by Mud Logging is a critical deliverable to guarantee a safe drilling environment even under challenging conditions and, to provide the first indications for reservoir evaluation. This paper describes a novel product application that successfully obtains advanced mud gas data from a Managed Pressure Drilling environment, proven in flow-loop and field applications (in Lower Saxony, Germany), by reducing service footprint as well as power consumption.\u0000","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"44 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83266334","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. Aslanyan, A. Margarit, A. Popov, I. Zhdanov, E. Pakhomov, M. Garnyshev, D. Gulyaev, R. Farakhova
The paper shares a practical case of production analysis of mature field in Western Siberia with a large stock of wells (> 1,000) and ongoing waterflood project. The main production complications of this field are the thief water production, thief water injection and non-uniform vertical sweep profile. The objective of the study was to analyse the 30-year history of development using conventional production and surveillance data, identify the suspects of thief water production and thief water injection and check the uniformity of the vertical flow profile. Performing such an analysis on well-by-well basis is a big challenge and requires a systematic approach and substantial automation. The majority of conventional diagnostic metrics fail to identify the origin of production complications. The choice was made in favour of production analysis workflow based on PRIME metrics, which automatically generates numerous conventional production performance metrics (including the reallocated production maps and cross-sections) and additionally generates advanced metrics based on automated 3D micro-modelling. This allowed to zoom on the wells with potential complications and understand their production/recovery potential. The PRIME analysis has also helped to identify the wells and areas which potentially may hold recoverable reserves and may benefit from additional well and cross-well surveillance.
{"title":"Production Performance Analysis of Western Siberia Mature Waterflood with Prime Diagnostic Metrics","authors":"A. Aslanyan, A. Margarit, A. Popov, I. Zhdanov, E. Pakhomov, M. Garnyshev, D. Gulyaev, R. Farakhova","doi":"10.2118/204641-ms","DOIUrl":"https://doi.org/10.2118/204641-ms","url":null,"abstract":"\u0000 The paper shares a practical case of production analysis of mature field in Western Siberia with a large stock of wells (> 1,000) and ongoing waterflood project.\u0000 The main production complications of this field are the thief water production, thief water injection and non-uniform vertical sweep profile.\u0000 The objective of the study was to analyse the 30-year history of development using conventional production and surveillance data, identify the suspects of thief water production and thief water injection and check the uniformity of the vertical flow profile.\u0000 Performing such an analysis on well-by-well basis is a big challenge and requires a systematic approach and substantial automation.\u0000 The majority of conventional diagnostic metrics fail to identify the origin of production complications. The choice was made in favour of production analysis workflow based on PRIME metrics, which automatically generates numerous conventional production performance metrics (including the reallocated production maps and cross-sections) and additionally generates advanced metrics based on automated 3D micro-modelling.\u0000 This allowed to zoom on the wells with potential complications and understand their production/recovery potential.\u0000 The PRIME analysis has also helped to identify the wells and areas which potentially may hold recoverable reserves and may benefit from additional well and cross-well surveillance.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91252357","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}
R. Cornwall, Deepak Tripathi, Sandeep Soni, Jose Isambertt
Integrated model projects underscore an organizations ability to fully enhance efficiency and unlock production potential. This paper provides a change management framework for key knowledge areas of an IAM implementation, in a giant onshore field to ensure these projects maintain an organizational and operational continuity toward improving production surveillance and optimization. Benefits of linking subsurface performance to surface facilities delivered use cases possible through a well-defined organizational structure and vendor management techniques post deployment. Leveraging project implementation guidelines, working sessions for project sustainability captured all activities required to assure project continuity with maximum utilization. Processes for construction, calibration and network updates were outlined in the organizations new RACI and supported by well-defined quick reference user guides. Decision workflows for validation of pressure and rate data underpinned the value creation through the IAM. Knowledge sharing sessions were linked to a competency development plan for performance audits as IAM activities became routed in routine work. A guided on-site support with vendor as well as the establishment of a support portal ensured time-bound issue resolutions. A large IAM project implementation, involving stakeholders from multiple disciplines and teams, offers unique challenges such as resource-allocation, schedule-optimization, communication-mechanism-identification, change-management, project-document-configuration management, and vendor-management. The innovative user-reference-guide optimized time and enhanced efficiency of the engineers by more than 30%. Standardized process aligned to integrated reservoir management principles reduced the extent of variability in analyses, underscoring continuity of work. Improved data and model quality enhanced the unit's ability to support production evaluations in field operations. In the areas of cost-optimization and process improvements, the project has generated more than 10 value-cases. The project management approach discussed here facilitated the tasks of the newly formed production optimization team. Standardized engineering processes and well-defined tasks support major business objectives, such as well-health optimization, process-standardization, and talent-development. Clearly defined roles and accountabilities assisted the smooth transition and change-management, adopting a new way of working. For example, technical rate determination through the IAM is standardized. Support utilities established for the project are easily accessed with a version-control system for all engineers. In conclusion, the Production Optimization team's core ability to unlock hidden production potential has significantly improved. Integrated asset models are driving the decision-making process for field development and operation teams. This paper summarizes the lesson learnt over three years a
{"title":"Sustaining Momentum in an Integrated Field Model Utilizing an Efficient Project Management Approach - Challenges, Lessons Learnt and Solutions from a Supergiant Field Implementation","authors":"R. Cornwall, Deepak Tripathi, Sandeep Soni, Jose Isambertt","doi":"10.2118/204698-ms","DOIUrl":"https://doi.org/10.2118/204698-ms","url":null,"abstract":"\u0000 Integrated model projects underscore an organizations ability to fully enhance efficiency and unlock production potential. This paper provides a change management framework for key knowledge areas of an IAM implementation, in a giant onshore field to ensure these projects maintain an organizational and operational continuity toward improving production surveillance and optimization. Benefits of linking subsurface performance to surface facilities delivered use cases possible through a well-defined organizational structure and vendor management techniques post deployment.\u0000 Leveraging project implementation guidelines, working sessions for project sustainability captured all activities required to assure project continuity with maximum utilization. Processes for construction, calibration and network updates were outlined in the organizations new RACI and supported by well-defined quick reference user guides. Decision workflows for validation of pressure and rate data underpinned the value creation through the IAM.\u0000 Knowledge sharing sessions were linked to a competency development plan for performance audits as IAM activities became routed in routine work. A guided on-site support with vendor as well as the establishment of a support portal ensured time-bound issue resolutions.\u0000 A large IAM project implementation, involving stakeholders from multiple disciplines and teams, offers unique challenges such as resource-allocation, schedule-optimization, communication-mechanism-identification, change-management, project-document-configuration management, and vendor-management. The innovative user-reference-guide optimized time and enhanced efficiency of the engineers by more than 30%. Standardized process aligned to integrated reservoir management principles reduced the extent of variability in analyses, underscoring continuity of work. Improved data and model quality enhanced the unit's ability to support production evaluations in field operations. In the areas of cost-optimization and process improvements, the project has generated more than 10 value-cases.\u0000 The project management approach discussed here facilitated the tasks of the newly formed production optimization team. Standardized engineering processes and well-defined tasks support major business objectives, such as well-health optimization, process-standardization, and talent-development. Clearly defined roles and accountabilities assisted the smooth transition and change-management, adopting a new way of working. For example, technical rate determination through the IAM is standardized. Support utilities established for the project are easily accessed with a version-control system for all engineers.\u0000 In conclusion, the Production Optimization team's core ability to unlock hidden production potential has significantly improved.\u0000 Integrated asset models are driving the decision-making process for field development and operation teams. This paper summarizes the lesson learnt over three years a","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89770240","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}
Abdullah Alharith, Sulaiman Albassam, Thamer Al-Zahrani
Organic and inorganic deposits play a major issue and concern in the wellbore of oil wells. This paper discusses the utilization of a new and novel approach utilizing a thermochemical recipe that shows a successful impact on both organic and inorganic deposits, as an elimination agent, and functions as stimulation fluid to improve the permeability of the near wellbore formation. The new recipe consists of mixing nitrite salt with sulfamic acid in the wellbore at the target zone. The product of this reaction includes heat, acidic salt, and nitrogen gas. The heat of the reaction is enough to liquefy the organic deposits, and the acidic salt will tackle the carbonate scale in the tube and will increase the permeability of the near wellbore area. The nitrogen gas is an inert gas; it will not affect the reaction and will help to flow back the well after the treatment. The experimental work shows an increment in the temperature by 65 °C when mixing the two chemicals. The test was conducted at room conditions and the temperature reached around 90 °C. Adding another 65 °C to the wellbore temperature is enough to melt asphaltene and wax, the acidic salt tackles carbonate scale. As a result, the mixture works on eliminating both the organic and inorganic deposits. The permeability of the limestone sample shows an increment of 65% when treated by the mixture of the reaction recipe. The uniqueness of the new thermochemical recipe is the potential of performing three objectives at the same time; the heat of the reaction removes the organic deposits in the wellbore, the acidic salt tackles carbonate scale, and improves the permeability of the near wellbore zone.
{"title":"A Novel Approach for Near Wellbore Stimulation and Deposits Removal Utilizing Thermochemical Reaction","authors":"Abdullah Alharith, Sulaiman Albassam, Thamer Al-Zahrani","doi":"10.2118/204771-ms","DOIUrl":"https://doi.org/10.2118/204771-ms","url":null,"abstract":"\u0000 Organic and inorganic deposits play a major issue and concern in the wellbore of oil wells. This paper discusses the utilization of a new and novel approach utilizing a thermochemical recipe that shows a successful impact on both organic and inorganic deposits, as an elimination agent, and functions as stimulation fluid to improve the permeability of the near wellbore formation.\u0000 The new recipe consists of mixing nitrite salt with sulfamic acid in the wellbore at the target zone. The product of this reaction includes heat, acidic salt, and nitrogen gas. The heat of the reaction is enough to liquefy the organic deposits, and the acidic salt will tackle the carbonate scale in the tube and will increase the permeability of the near wellbore area. The nitrogen gas is an inert gas; it will not affect the reaction and will help to flow back the well after the treatment.\u0000 The experimental work shows an increment in the temperature by 65 °C when mixing the two chemicals. The test was conducted at room conditions and the temperature reached around 90 °C. Adding another 65 °C to the wellbore temperature is enough to melt asphaltene and wax, the acidic salt tackles carbonate scale. As a result, the mixture works on eliminating both the organic and inorganic deposits. The permeability of the limestone sample shows an increment of 65% when treated by the mixture of the reaction recipe.\u0000 The uniqueness of the new thermochemical recipe is the potential of performing three objectives at the same time; the heat of the reaction removes the organic deposits in the wellbore, the acidic salt tackles carbonate scale, and improves the permeability of the near wellbore zone.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88768538","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}
R. Santoso, Xupeng He, M. AlSinan, Ruben Figueroa Hernandez, H. Kwak, H. Hoteit
History matching is a critical step within the reservoir management process to synchronize the simulation model with the production data. The history-matched model can be used for planning optimum field development and performing optimization and uncertainty quantifications. We present a novel history matching workflow based on a Bayesian framework that accommodates subsurface uncertainties. Our workflow involves three different model resolutions within the Bayesian framework: 1) a coarse low-fidelity model to update the prior range, 2) a fine low-fidelity model to represent the high-fidelity model, and 3) a high-fidelity model to re-construct the real response. The low-fidelity model is constructed by a multivariate polynomial function, while the high-fidelity model is based on the reservoir simulation model. We firstly develop a coarse low-fidelity model using a two-level Design of Experiment (DoE), which aims to provide a better prior. We secondly use Latin Hypercube Sampling (LHS) to construct the fine low-fidelity model to be deployed in the Bayesian runs, where we use the Metropolis-Hastings algorithm. Finally, the posterior is fed into the high-fidelity model to evaluate the matching quality. This work demonstrates the importance of including uncertainties in history matching. Bayesian provides a robust framework to allow uncertainty quantification within the reservoir history matching. Under uniform prior, the convergence of the Bayesian is very sensitive to the parameter ranges. When the solution is far from the mean of the parameter ranges, the Bayesian introduces bios and deviates from the observed data. Our results show that updating the prior from the coarse low-fidelity model accelerates the Bayesian convergence and improves the matching convergence. Bayesian requires a huge number of runs to produce an accurate posterior. Running the high-fidelity model multiple times is expensive. Our workflow tackles this problem by deploying a fine low-fidelity model to represent the high-fidelity model in the main runs. This fine low-fidelity model is fast to run, while it honors the physics and accuracy of the high-fidelity model. We also use ANOVA sensitivity analysis to measure the importance of each parameter. The ranking gives awareness to the significant ones that may contribute to the matching accuracy. We demonstrate our workflow for a geothermal reservoir with static and operational uncertainties. Our workflow produces accurate matching of thermal recovery factor and produced-enthalpy rate with physically-consistent posteriors. We present a novel workflow to account for uncertainty in reservoir history matching involving multi-resolution interaction. The proposed method is generic and can be readily applied within existing history-matching workflows in reservoir simulation.
{"title":"Multi-Fidelity Bayesian Approach for History Matching in Reservoir Simulation","authors":"R. Santoso, Xupeng He, M. AlSinan, Ruben Figueroa Hernandez, H. Kwak, H. Hoteit","doi":"10.2118/204652-ms","DOIUrl":"https://doi.org/10.2118/204652-ms","url":null,"abstract":"\u0000 History matching is a critical step within the reservoir management process to synchronize the simulation model with the production data. The history-matched model can be used for planning optimum field development and performing optimization and uncertainty quantifications. We present a novel history matching workflow based on a Bayesian framework that accommodates subsurface uncertainties. Our workflow involves three different model resolutions within the Bayesian framework: 1) a coarse low-fidelity model to update the prior range, 2) a fine low-fidelity model to represent the high-fidelity model, and 3) a high-fidelity model to re-construct the real response. The low-fidelity model is constructed by a multivariate polynomial function, while the high-fidelity model is based on the reservoir simulation model. We firstly develop a coarse low-fidelity model using a two-level Design of Experiment (DoE), which aims to provide a better prior. We secondly use Latin Hypercube Sampling (LHS) to construct the fine low-fidelity model to be deployed in the Bayesian runs, where we use the Metropolis-Hastings algorithm. Finally, the posterior is fed into the high-fidelity model to evaluate the matching quality. This work demonstrates the importance of including uncertainties in history matching. Bayesian provides a robust framework to allow uncertainty quantification within the reservoir history matching. Under uniform prior, the convergence of the Bayesian is very sensitive to the parameter ranges. When the solution is far from the mean of the parameter ranges, the Bayesian introduces bios and deviates from the observed data. Our results show that updating the prior from the coarse low-fidelity model accelerates the Bayesian convergence and improves the matching convergence. Bayesian requires a huge number of runs to produce an accurate posterior. Running the high-fidelity model multiple times is expensive. Our workflow tackles this problem by deploying a fine low-fidelity model to represent the high-fidelity model in the main runs. This fine low-fidelity model is fast to run, while it honors the physics and accuracy of the high-fidelity model. We also use ANOVA sensitivity analysis to measure the importance of each parameter. The ranking gives awareness to the significant ones that may contribute to the matching accuracy. We demonstrate our workflow for a geothermal reservoir with static and operational uncertainties. Our workflow produces accurate matching of thermal recovery factor and produced-enthalpy rate with physically-consistent posteriors. We present a novel workflow to account for uncertainty in reservoir history matching involving multi-resolution interaction. The proposed method is generic and can be readily applied within existing history-matching workflows in reservoir simulation.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"78 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83887525","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}
Abdul Bari, Mohammad Rasheed Khan, M. S. Tanveer, Muhammad Hammad, Asad Mumtaz Adhami, S. Siddiqi, T. Zubair, Hamza Ali, M. Sarili, Anwar Ali, Saad bin Abrar, Shahnawaz Aziz
In today's dynamically challenging E&P industry, exploration activities demand for out-of-the-box measures to make the most out of the data available at hand. Instead of relying on time consuming and cost-intensive deliverability testing, there is a strong push to extract maximum possible information from time- and cost-efficient wireline formation testers in combination with other openhole logs to get critical reservoir insight. Consequently, driving efficiency in the appraisal process by reducing redundant expenditures linked with reservoir evaluation. Employing a data-driven approach, this paper addresses the need to build single-well analytical models that combines knowledge of core data, petrophysical evaluation and reservoir fluid properties. Resultantly, predictive analysis using cognitive processes to determine multilayer productivity for an exploratory well is achieved. Single Well Predictive Modeling (SWPM) workflow is developed for this case which utilizes plethora of formation evaluation information which traditionally resides across siloed disciplines. A tailor-made workflow has been implemented which goes beyond the conventional formation tester deliverables while incorporating PVT and numerical simulation methodologies. Stage one involved reservoir characterization utilizing Interval Pressure Transient Testing (IPTT) done through the mini-DST operation on wireline formation tester. Stage two concerns the use of analytical modeling to yield exact solution to an approximate problem whose end-product is an estimate of the Absolute Open Flow Potential (AOFP). Stage three involves utilizing fluid properties from downhole fluid samples and integrating with core, OH logs, and IPTT answer products to yield a calibrated SWPM model, which includes development of a 1D petrophysical model. Additionally, this stage produces a 3D simulation model to yield a reservoir production performance deliverable which considers variable rock typing through neural network analysis. Ultimately, stage four combines the preceding analysis to develop a wellbore production model which aids in optimizing completion strategies. The application of this data-driven and cognitive technique has helped the operator in evaluating the potential of the reservoir early-on to aid in the decision-making process for further investments. An exhaustive workflow is in place that can be adopted for informed reservoir deliverability modeling in case of early well-life evaluations.
{"title":"A Cognitive Data-Driven Single-Well Modeling Workflow for Reservoir Deliverability Predictions – Expanding the Wireline Formation Tester Application Envelope","authors":"Abdul Bari, Mohammad Rasheed Khan, M. S. Tanveer, Muhammad Hammad, Asad Mumtaz Adhami, S. Siddiqi, T. Zubair, Hamza Ali, M. Sarili, Anwar Ali, Saad bin Abrar, Shahnawaz Aziz","doi":"10.2118/204802-ms","DOIUrl":"https://doi.org/10.2118/204802-ms","url":null,"abstract":"\u0000 In today's dynamically challenging E&P industry, exploration activities demand for out-of-the-box measures to make the most out of the data available at hand. Instead of relying on time consuming and cost-intensive deliverability testing, there is a strong push to extract maximum possible information from time- and cost-efficient wireline formation testers in combination with other openhole logs to get critical reservoir insight. Consequently, driving efficiency in the appraisal process by reducing redundant expenditures linked with reservoir evaluation. Employing a data-driven approach, this paper addresses the need to build single-well analytical models that combines knowledge of core data, petrophysical evaluation and reservoir fluid properties. Resultantly, predictive analysis using cognitive processes to determine multilayer productivity for an exploratory well is achieved.\u0000 Single Well Predictive Modeling (SWPM) workflow is developed for this case which utilizes plethora of formation evaluation information which traditionally resides across siloed disciplines. A tailor-made workflow has been implemented which goes beyond the conventional formation tester deliverables while incorporating PVT and numerical simulation methodologies. Stage one involved reservoir characterization utilizing Interval Pressure Transient Testing (IPTT) done through the mini-DST operation on wireline formation tester. Stage two concerns the use of analytical modeling to yield exact solution to an approximate problem whose end-product is an estimate of the Absolute Open Flow Potential (AOFP). Stage three involves utilizing fluid properties from downhole fluid samples and integrating with core, OH logs, and IPTT answer products to yield a calibrated SWPM model, which includes development of a 1D petrophysical model. Additionally, this stage produces a 3D simulation model to yield a reservoir production performance deliverable which considers variable rock typing through neural network analysis. Ultimately, stage four combines the preceding analysis to develop a wellbore production model which aids in optimizing completion strategies.\u0000 The application of this data-driven and cognitive technique has helped the operator in evaluating the potential of the reservoir early-on to aid in the decision-making process for further investments. An exhaustive workflow is in place that can be adopted for informed reservoir deliverability modeling in case of early well-life evaluations.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"60 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84021381","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}
An operator working in Indian western land reservoirs, planned to develop a low-permeability, high potential reservoir with hydraulic fracturing. In the pilot project, production behavior of the initial wells was below expectation. As a diagnostic procedure few of the wells were attempted with memory coiled tubing-assisted production logging to record production log data and identify the root cause behind poor performance. Apart from the horizontal trajectory, major challenges associated with this approach included the low flow rate (150-200bbl) and expectation of frac fluid inside the wellbore due to inadequate cleaning. As a result, all the attempts for effective diagnosis were inconclusive. Moreover, absence of critical input such as individual stage frac evaluation demanded attention in order to optimize completion quality (CQ) and conclude effective fracturing and completion strategy prior to full field development planning. Addressing the challenges and with an aim to provide the critical inputs required for reservoir characterization and production optimization, a multi-spinner production logging tool with new innovative spinner design and multi-electrical and optical sensors were proposed on cased-hole tractor in order to resolve the complex flow profiles associated with the low flow rates and horizontal well trajectory. The newly configured spinners with innovative spinner design material lowered the spinner threshold from 2ft/min to 1ft/min for multipass logging in lab tests. It also optimized the magnetic field distribution to ensure less accretion of debris on the spinner (causing spinners to clog) without compromising measurement accuracy. With well production being 200 bbl at the time of logging, the multi-spinner survey with innovative spinner design clearly resolved the dynamic changes across the borehole during multi bean data acquisition. Overcoming the major interpretation challenge of isolating the dynamic changes in the wellbore due to borehole trajectory and due to fracturing stage, individual stage frac flow contributions were evaluated. Stage frac productivity correlated very well with the frac operation parameters, reservoir quality and completion quality. Apart from individual contributions, key findings such as activation of few frac stages at high drawdown pressures, increasing gas contribution from toe to heel and resolving presence of leftover frac fluid in the well, exceeded the expectations set by the client in terms of the objectives vs. results. This success clearly demonstrated that knowledge of downhole dynamics for horizontal trajectory is vital. This is not limited only to address the individual well requirement, but an integrated approach would help to optimize future wells through better understanding of reservoir productivity vs frac operation and completion quality (CQ).
{"title":"Innovative Spinner Design Aids in Flow Characterization and Production Optimization of a Multistage Frac Well","authors":"Gaurav Agrawal, Ajit Kumar, Rajvardhan Singh, Alekh Gupta, Puneet Kanwar Singh Kundi, P. Mukerji","doi":"10.2118/204894-ms","DOIUrl":"https://doi.org/10.2118/204894-ms","url":null,"abstract":"\u0000 An operator working in Indian western land reservoirs, planned to develop a low-permeability, high potential reservoir with hydraulic fracturing. In the pilot project, production behavior of the initial wells was below expectation. As a diagnostic procedure few of the wells were attempted with memory coiled tubing-assisted production logging to record production log data and identify the root cause behind poor performance. Apart from the horizontal trajectory, major challenges associated with this approach included the low flow rate (150-200bbl) and expectation of frac fluid inside the wellbore due to inadequate cleaning. As a result, all the attempts for effective diagnosis were inconclusive. Moreover, absence of critical input such as individual stage frac evaluation demanded attention in order to optimize completion quality (CQ) and conclude effective fracturing and completion strategy prior to full field development planning.\u0000 Addressing the challenges and with an aim to provide the critical inputs required for reservoir characterization and production optimization, a multi-spinner production logging tool with new innovative spinner design and multi-electrical and optical sensors were proposed on cased-hole tractor in order to resolve the complex flow profiles associated with the low flow rates and horizontal well trajectory.\u0000 The newly configured spinners with innovative spinner design material lowered the spinner threshold from 2ft/min to 1ft/min for multipass logging in lab tests. It also optimized the magnetic field distribution to ensure less accretion of debris on the spinner (causing spinners to clog) without compromising measurement accuracy.\u0000 With well production being 200 bbl at the time of logging, the multi-spinner survey with innovative spinner design clearly resolved the dynamic changes across the borehole during multi bean data acquisition. Overcoming the major interpretation challenge of isolating the dynamic changes in the wellbore due to borehole trajectory and due to fracturing stage, individual stage frac flow contributions were evaluated. Stage frac productivity correlated very well with the frac operation parameters, reservoir quality and completion quality. Apart from individual contributions, key findings such as activation of few frac stages at high drawdown pressures, increasing gas contribution from toe to heel and resolving presence of leftover frac fluid in the well, exceeded the expectations set by the client in terms of the objectives vs. results.\u0000 This success clearly demonstrated that knowledge of downhole dynamics for horizontal trajectory is vital. This is not limited only to address the individual well requirement, but an integrated approach would help to optimize future wells through better understanding of reservoir productivity vs frac operation and completion quality (CQ).","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81325553","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 foam coarsening process is significant to foam stability in porous media. This study provides, for the first time, direct visualization of the foam coarsening process in porous media under realistic reservoir conditions. Foam coarsening behavior in porous media has shown a similar linear increase in the average bubble area to that in an open system but differs in two stages. The average bubble area increases with a faster rate in stage 1 and then increases with a slower rate in stage 2 and stage 2 dominates the foam coarsening process. The transition between the two stages occurs as the inner bubbles disappear when the edge bubbles start feeling the effects of the walls. The foam at steady-state shows a bimodal size distribution with bubbles trapped in the pore bodies and pore throats. The effects of pore pressure (600-3200 psi) and temperature (22-100 °C) were studied. Foam coarsening dynamics are sensitive to pore pressure and temperature, where higher pore pressure and lower temperature are more favorable to maintain a stable foam. Finally, the coarsening rates of foams generated with different gas phases were compared. In contrast to N2 foam and gas CO2 foam, supercritical CO2 foam exhibits the slowest coarsening rate because of its ultralow interfacial tension.
{"title":"Capturing the Dynamics of Foam Coarsening in a HPHT Microfluidic System","authors":"Wei Yu, Xianmin Zhou, M. Kanj","doi":"10.2118/204695-ms","DOIUrl":"https://doi.org/10.2118/204695-ms","url":null,"abstract":"\u0000 The foam coarsening process is significant to foam stability in porous media. This study provides, for the first time, direct visualization of the foam coarsening process in porous media under realistic reservoir conditions. Foam coarsening behavior in porous media has shown a similar linear increase in the average bubble area to that in an open system but differs in two stages. The average bubble area increases with a faster rate in stage 1 and then increases with a slower rate in stage 2 and stage 2 dominates the foam coarsening process. The transition between the two stages occurs as the inner bubbles disappear when the edge bubbles start feeling the effects of the walls. The foam at steady-state shows a bimodal size distribution with bubbles trapped in the pore bodies and pore throats. The effects of pore pressure (600-3200 psi) and temperature (22-100 °C) were studied. Foam coarsening dynamics are sensitive to pore pressure and temperature, where higher pore pressure and lower temperature are more favorable to maintain a stable foam. Finally, the coarsening rates of foams generated with different gas phases were compared. In contrast to N2 foam and gas CO2 foam, supercritical CO2 foam exhibits the slowest coarsening rate because of its ultralow interfacial tension.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80680651","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：