CO2-foam enhanced oil recovery (EOR) has been considered a proven technology to mitigate adverse effects from CO2 front instabilities in highly heterogeneous reservoirs, such as viscous fingering, gravity segregation, and superior flow in high permeability streaks, leading to premature CO2 breakthrough. A highly stable CO2-foam is required to provide significant mobility control effect that stimulates flow diversion from high-permeability to low-permeability regions, hence improved sweep efficiency. CO2-foam EOR process can also be advanced for effective CO2 utilization and long-term CO2 sequestration in addition to improved oil production. However, harsh in-situ environments of hydrocarbon reservoirs greatly determine the performance of CO2-foam and the efficiency of the entire operations, leading to a need of foam formulation optimization in addition to technical development. As an innovative solution, hydrophobically modified polymer was employed to improve overall CO2-foam properties and CO2 mobility control performance inside porous media. A comprehensive evaluation on foaming properties (foamability and foam stability) and foam rheological behavior was performed under supercritical conditions to warrant the suitability of developed formulation as high-performance foaming agent. CO2-foam was generated using the primary foaming agent (alpha olefin sulfonate and betaine) in combination with different types of hydrophobically modified polymers, referred as to HMP, and conventional polymers (HPAMs) as foam stabilizers. The steady-state foam resistance established by each foam during dynamic flow tests was assessed under reservoir conditions to indicate the extent of mobility control effect for better sweep efficiency and the capability of the developed CO2-foam formulation of suppressing CO2 migration, hence improved storage efficiency. The formulation containing the selected HMP offered an acceptable foam generation ability compared to the formulations containing classical HPAM polymers. The presence of HMP with a higher degree of hydrophobes and lower molecular weight in surfactant-stabilized foam system was able to produce an improved flow resistance. These are attributed to the formation of organized and bridged polymer network triggered by hydrophobic association in the bulk and lamella interface hence providing steric forces at the interface that leads to substantial elasticity. Results from dynamic flow experiments revealed the superior performance of HMP stabilized CO2-foam in porous media in which its flow resistance was found to be 70% and 95% higher than that of polymer-free CO2-foam, and individual CO2, respectively. This research provides an alternative solution by promoting a relatively new foam formulation which is stabilized by hydrophobically modified water-soluble polymer. Besides offering better mobility control effect during EOR process, the application of developed CO2-foam formulation was also extended to CO2 trapping imp
{"title":"Improved CO2-Foam Properties and Flow Behavior by Hydrophobically Modified Polymers: Implications for Enhanced CO2 Storage and Oil Recovery","authors":"Shehzad Ahmed, A. Hanamertani, W. Alameri","doi":"10.2523/iptc-22628-ms","DOIUrl":"https://doi.org/10.2523/iptc-22628-ms","url":null,"abstract":"\u0000 CO2-foam enhanced oil recovery (EOR) has been considered a proven technology to mitigate adverse effects from CO2 front instabilities in highly heterogeneous reservoirs, such as viscous fingering, gravity segregation, and superior flow in high permeability streaks, leading to premature CO2 breakthrough. A highly stable CO2-foam is required to provide significant mobility control effect that stimulates flow diversion from high-permeability to low-permeability regions, hence improved sweep efficiency. CO2-foam EOR process can also be advanced for effective CO2 utilization and long-term CO2 sequestration in addition to improved oil production. However, harsh in-situ environments of hydrocarbon reservoirs greatly determine the performance of CO2-foam and the efficiency of the entire operations, leading to a need of foam formulation optimization in addition to technical development. As an innovative solution, hydrophobically modified polymer was employed to improve overall CO2-foam properties and CO2 mobility control performance inside porous media. A comprehensive evaluation on foaming properties (foamability and foam stability) and foam rheological behavior was performed under supercritical conditions to warrant the suitability of developed formulation as high-performance foaming agent. CO2-foam was generated using the primary foaming agent (alpha olefin sulfonate and betaine) in combination with different types of hydrophobically modified polymers, referred as to HMP, and conventional polymers (HPAMs) as foam stabilizers. The steady-state foam resistance established by each foam during dynamic flow tests was assessed under reservoir conditions to indicate the extent of mobility control effect for better sweep efficiency and the capability of the developed CO2-foam formulation of suppressing CO2 migration, hence improved storage efficiency. The formulation containing the selected HMP offered an acceptable foam generation ability compared to the formulations containing classical HPAM polymers. The presence of HMP with a higher degree of hydrophobes and lower molecular weight in surfactant-stabilized foam system was able to produce an improved flow resistance. These are attributed to the formation of organized and bridged polymer network triggered by hydrophobic association in the bulk and lamella interface hence providing steric forces at the interface that leads to substantial elasticity. Results from dynamic flow experiments revealed the superior performance of HMP stabilized CO2-foam in porous media in which its flow resistance was found to be 70% and 95% higher than that of polymer-free CO2-foam, and individual CO2, respectively. This research provides an alternative solution by promoting a relatively new foam formulation which is stabilized by hydrophobically modified water-soluble polymer. Besides offering better mobility control effect during EOR process, the application of developed CO2-foam formulation was also extended to CO2 trapping imp","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81244536","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}
S. Pooniwala, I. Brohi, A. Waheed, AbdulMuqtadir Khan, Zahaezuani Rafiq Hamidon
Post-fracturing cleanup and production revival in sub-hydrostatic wells can be challenging. The complexity is amplified in sub-hydrostatic multistage horizontal wells because, by the time the fracturing treatment is concluded, the gas phase of the energized fracturing fluids used during the initial stages of the fracturing treatment dissipates. In the subject sub-hydrostatic well, coiled tubing (CT) with a real-time telemetry system was utilized over a standard nitrogen lifting intervention utilizing conventional CT to revive a hydraulically fractured well due to its capabilities to enable real-time decisions using live bottom-hole data. Acid fracturing using an energized fluid treatment was conducted in the subject gas well completed with a multistage open-hole completion system using isolation packers and sleeves. As the subject well was sub-hydrostatic, it was decided to utilize the CT with real-time telemetry system to gain value from its associated downhole parameters during the cleanup phase to alleviate the chances of successfully lifting the well. The well was placed in an area with prolific offset producers; hence, there were high production expectations from this well. A review of the well indicated a decreasing trend of reservoir pressure from heel to toe of the lateral, possibly contributing to lower stresses and potential crossflow between stages. Hence, the diverter concentrations and volumes per stage and nitrogen rates were maximized for each new fracturing stage to attempt to create new fractures. Considering the challenges with the well, it was essential that the N2 lifting operation parameters should be optimized to enhance drawdown. It was decided to utilize CT with a real-time telemetry system to control drawdown parameters better and maximize the possibility of success. Real-time downhole pressure measurements were utilized to accurately identify the fluid gradient followed by real-time evaluation and monitoring of the well behavior during N2 lifting operations. The real-time downhole data collected enabled on-the-fly intervention optimization leading to transforming the well into an economic producer. The integrated post-treatment analysis workflow provided a robust insight into fracture treatment design and evaluation, reservoir imbibition perspective, openhole completion practices, and the importance of real-time telemetry for challenging interventions. The lessons learned that are presented in this paper could act as a guide to contribute to operational efficiency enhancements and cost savings in other projects.
{"title":"Adding a New Lease of Life to a Sub-Hydrostatic Hydraulically Fractured Gas Well Using Coiled Tubing with Real-Time Telemetry","authors":"S. Pooniwala, I. Brohi, A. Waheed, AbdulMuqtadir Khan, Zahaezuani Rafiq Hamidon","doi":"10.2523/iptc-22374-ms","DOIUrl":"https://doi.org/10.2523/iptc-22374-ms","url":null,"abstract":"\u0000 Post-fracturing cleanup and production revival in sub-hydrostatic wells can be challenging. The complexity is amplified in sub-hydrostatic multistage horizontal wells because, by the time the fracturing treatment is concluded, the gas phase of the energized fracturing fluids used during the initial stages of the fracturing treatment dissipates. In the subject sub-hydrostatic well, coiled tubing (CT) with a real-time telemetry system was utilized over a standard nitrogen lifting intervention utilizing conventional CT to revive a hydraulically fractured well due to its capabilities to enable real-time decisions using live bottom-hole data.\u0000 Acid fracturing using an energized fluid treatment was conducted in the subject gas well completed with a multistage open-hole completion system using isolation packers and sleeves. As the subject well was sub-hydrostatic, it was decided to utilize the CT with real-time telemetry system to gain value from its associated downhole parameters during the cleanup phase to alleviate the chances of successfully lifting the well.\u0000 The well was placed in an area with prolific offset producers; hence, there were high production expectations from this well. A review of the well indicated a decreasing trend of reservoir pressure from heel to toe of the lateral, possibly contributing to lower stresses and potential crossflow between stages. Hence, the diverter concentrations and volumes per stage and nitrogen rates were maximized for each new fracturing stage to attempt to create new fractures. Considering the challenges with the well, it was essential that the N2 lifting operation parameters should be optimized to enhance drawdown. It was decided to utilize CT with a real-time telemetry system to control drawdown parameters better and maximize the possibility of success. Real-time downhole pressure measurements were utilized to accurately identify the fluid gradient followed by real-time evaluation and monitoring of the well behavior during N2 lifting operations. The real-time downhole data collected enabled on-the-fly intervention optimization leading to transforming the well into an economic producer.\u0000 The integrated post-treatment analysis workflow provided a robust insight into fracture treatment design and evaluation, reservoir imbibition perspective, openhole completion practices, and the importance of real-time telemetry for challenging interventions. The lessons learned that are presented in this paper could act as a guide to contribute to operational efficiency enhancements and cost savings in other projects.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87118382","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}
Salman. F. Nofal, Fazeel Ahmad, Dr. Ahmad Shmakhy, Zohaib Ghous Channa, Arlen Sarsekov, Yassar Goraya Inayat, Sundos Ibrahim Alabed, Manal I. Albeshr, Ahmed Mohammed Al Seiari, W. Chehabi, T. Jørgensen, Kirstian Solhaug, R. Gill, Viljoen Duvenhage
Demonstrate technology effectiveness following improvements to system to increase robustness and refine operations following the initial Pilot Well deployed January 2016. The first Abu Dhabi Offshore well was deemed to be a success (reference SPE-183465-MS) despite deployment challenges during the lower completion phase. There was an opportunity to address these challenges for the second well, in the deployment of well -1 which from an operational perspective was textbook. In the search for an improvement to the Productivity index (PI), multi-lateral acid jetting technology was adopted as a more effective approach to typical drainage methods. With conventional stimulation techniques being limited in effectiveness and often leaving significant volumes of recoverable reserves out of reach, an alternative approach was required to create new connections within the reservoir. This technology effectively creates connections to layers previously separated by very tight, low permeability barriers to dramatically increase recovery factors across carbonate reservoirs. In a single multi-rate pumping sequence, needles were extended to create channels into the reservoir layers, using acid jetting technology to achieve vertical connectivity and improve production rates. Currently, up to 60 subs can be deployed in a signle well bore. With each sub capable of deploying 4 needles at 90 degrees perpendicular to the wellbore and up to 40 feet in length, multiple micro-laterals are created throughout the reservoir. During this case study, 10 sub-assemblies of the multi-lateral acid jetting technology system were installed, creating 40 micro-laterals, which significantly improved access to reserves. These laterals remain in the well, essentially leaving a permanently installed lower liner with full bore access to TD. Following successful adoption of this technology, the well has been producing for a year with positive results. Multi Rate test/PLT/Memory Gauge data all confirms a productivity index increase of 120%. This paper describes the process of candidate selection, completion design, operational challenges, deployment, post job analysis, system improvement and lessons learnt. Multilateral acid jetting technology has evolved and improved over recent years and the primary differentiators highlighted in this paper are as follows: The continuous enhancement of multi-lateral acid jetting technology is playing a key role in driving increased efficiency in field development planning. By reducing the total well requirement for the reservoir, whilst simultaneously increasing recoverable reserves, the technology is at the forefront of facilitating the future state of field development.
{"title":"Multi-Lateral Jetting Technology Results in a 150% Uplift in Production During a Second Offshore Application in Abu Dhabi Offshore Field","authors":"Salman. F. Nofal, Fazeel Ahmad, Dr. Ahmad Shmakhy, Zohaib Ghous Channa, Arlen Sarsekov, Yassar Goraya Inayat, Sundos Ibrahim Alabed, Manal I. Albeshr, Ahmed Mohammed Al Seiari, W. Chehabi, T. Jørgensen, Kirstian Solhaug, R. Gill, Viljoen Duvenhage","doi":"10.2523/iptc-21959-ea","DOIUrl":"https://doi.org/10.2523/iptc-21959-ea","url":null,"abstract":"\u0000 \u0000 \u0000 Demonstrate technology effectiveness following improvements to system to increase robustness and refine operations following the initial Pilot Well deployed January 2016.\u0000 The first Abu Dhabi Offshore well was deemed to be a success (reference SPE-183465-MS) despite deployment challenges during the lower completion phase. There was an opportunity to address these challenges for the second well, in the deployment of well -1 which from an operational perspective was textbook.\u0000 In the search for an improvement to the Productivity index (PI), multi-lateral acid jetting technology was adopted as a more effective approach to typical drainage methods. With conventional stimulation techniques being limited in effectiveness and often leaving significant volumes of recoverable reserves out of reach, an alternative approach was required to create new connections within the reservoir. This technology effectively creates connections to layers previously separated by very tight, low permeability barriers to dramatically increase recovery factors across carbonate reservoirs.\u0000 \u0000 \u0000 \u0000 In a single multi-rate pumping sequence, needles were extended to create channels into the reservoir layers, using acid jetting technology to achieve vertical connectivity and improve production rates.\u0000 Currently, up to 60 subs can be deployed in a signle well bore. With each sub capable of deploying 4 needles at 90 degrees perpendicular to the wellbore and up to 40 feet in length, multiple micro-laterals are created throughout the reservoir.\u0000 During this case study, 10 sub-assemblies of the multi-lateral acid jetting technology system were installed, creating 40 micro-laterals, which significantly improved access to reserves. These laterals remain in the well, essentially leaving a permanently installed lower liner with full bore access to TD.\u0000 \u0000 \u0000 \u0000 Following successful adoption of this technology, the well has been producing for a year with positive results. Multi Rate test/PLT/Memory Gauge data all confirms a productivity index increase of 120%.\u0000 This paper describes the process of candidate selection, completion design, operational challenges, deployment, post job analysis, system improvement and lessons learnt.\u0000 \u0000 \u0000 \u0000 Multilateral acid jetting technology has evolved and improved over recent years and the primary differentiators highlighted in this paper are as follows:\u0000 The continuous enhancement of multi-lateral acid jetting technology is playing a key role in driving increased efficiency in field development planning. By reducing the total well requirement for the reservoir, whilst simultaneously increasing recoverable reserves, the technology is at the forefront of facilitating the future state of field development.\u0000","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"48 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90223172","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}
C. Popeney, Kellen Harkness, Laura Copeland, Jesse Lee, Dmitry Usoltsev
The presence of extensive tight oil reserves in regions with scarce or intermittent supply of ground or surface freshwater resources underscores the importance of water reduction, reuse, and recycling strategies to ensure the sustainability of hydraulic fracturing. Currently, the advantages of using synthetic high viscosity friction reducers (HVFRs) does not extend to fluids composed of high salinity produced water or wastewater because these products cannot transport proppant effectively under such conditions. The use of a new fully synthetic polymer architecture bearing interchain association is described which provides a significant increase in brine tolerance and fluid rheology, giving rise to effective proppant transport and friction reduction in water salinity exceeding 200,000 TDS. Two variations of the polymer architecture are described: a product that operates effectively in fluid below 100,000 TDS such as seawater (SW-HVFR) and a second high brine product that works in all fluids up to and above 200,000 TDS (HB-HVFR). Proppant transport was studied dynamically using a slot flow apparatus, which demonstrated performance with the new system that exceeded guar and greatly exceeded other conventional HVFRs at equivalent polymer loadings. Slot flow results indicated consistent transport performance throughout the salinity range investigated by proper selection of SW-HVFR and HB-HVFR. Although high shear viscosity of the new polymers was inferior to that of guar, advanced rheological studiesindicated that the superior performance was due to enhanced viscosity and unusually high elasticity of the derived fluids within the relevant shear rate range between 1 and 100 s−1. In addition, anomalous dependence of viscosity on temperature is described, featuring a viscosity maximum above ambient temperature. This unusual rheology behavior was attributed to the associative polymer architecture of the new system. The new HVFRs exhibit effective friction reduction within their intended salinity ranges as well as good tolerance toward biocides and clay control agents. Furthermore, the operational salinity range of SW-HVFR can be extended up to 200,000 TDS in the presence of certain production enhancement aids due to a synergistic effect on the polymer dissolution rate. Lastly, bottle testing indicated that the polymers are effectively broken by common oxidative breakers, enabling their flowback. These results demonstrate the flexibility of the new HVFR system to make total fluids utilizing any water source, enabling sustainable fracturing in a variety of situations.
{"title":"Revamping Polymer Architecture for Optimized Fracturing Fluids in Fresh and Produced Water","authors":"C. Popeney, Kellen Harkness, Laura Copeland, Jesse Lee, Dmitry Usoltsev","doi":"10.2523/iptc-22434-ms","DOIUrl":"https://doi.org/10.2523/iptc-22434-ms","url":null,"abstract":"\u0000 The presence of extensive tight oil reserves in regions with scarce or intermittent supply of ground or surface freshwater resources underscores the importance of water reduction, reuse, and recycling strategies to ensure the sustainability of hydraulic fracturing. Currently, the advantages of using synthetic high viscosity friction reducers (HVFRs) does not extend to fluids composed of high salinity produced water or wastewater because these products cannot transport proppant effectively under such conditions. The use of a new fully synthetic polymer architecture bearing interchain association is described which provides a significant increase in brine tolerance and fluid rheology, giving rise to effective proppant transport and friction reduction in water salinity exceeding 200,000 TDS.\u0000 Two variations of the polymer architecture are described: a product that operates effectively in fluid below 100,000 TDS such as seawater (SW-HVFR) and a second high brine product that works in all fluids up to and above 200,000 TDS (HB-HVFR). Proppant transport was studied dynamically using a slot flow apparatus, which demonstrated performance with the new system that exceeded guar and greatly exceeded other conventional HVFRs at equivalent polymer loadings. Slot flow results indicated consistent transport performance throughout the salinity range investigated by proper selection of SW-HVFR and HB-HVFR.\u0000 Although high shear viscosity of the new polymers was inferior to that of guar, advanced rheological studiesindicated that the superior performance was due to enhanced viscosity and unusually high elasticity of the derived fluids within the relevant shear rate range between 1 and 100 s−1. In addition, anomalous dependence of viscosity on temperature is described, featuring a viscosity maximum above ambient temperature. This unusual rheology behavior was attributed to the associative polymer architecture of the new system.\u0000 The new HVFRs exhibit effective friction reduction within their intended salinity ranges as well as good tolerance toward biocides and clay control agents. Furthermore, the operational salinity range of SW-HVFR can be extended up to 200,000 TDS in the presence of certain production enhancement aids due to a synergistic effect on the polymer dissolution rate. Lastly, bottle testing indicated that the polymers are effectively broken by common oxidative breakers, enabling their flowback. These results demonstrate the flexibility of the new HVFR system to make total fluids utilizing any water source, enabling sustainable fracturing in a variety of situations.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"57 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84086602","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}
L. Dumitrache, Alistair Roy, Anastasia Bird, B. Goktas, C. Sorgi, Reginald Stanley, V. De Gennaro, E. Eswein, J. Abbott
The integration of data and discipline specific knowledge is a common challenge when attempting to optimize or accelerate an asset's recovery through hydraulic fracture stimulations. Any potential omission of data or understanding will increase uncertainty and a project's chance of failure. Therefore, when looking to optimize the production of a given asset, it is key to take a holistic approach that breaks down any technical and organisational barriers. This project couples the output of the different subsurface and stimulation disciplines to reduce the uncertainty associated with the production forecast of planned stimulation designs. The following paper presents the integrated approach for the Graben sector of UK's North Sea Clair oil field, largest oil field currently in Europe. Geophysicists, petrophysicists, and geologists generate a static model which is calibrated and validated by reservoir engineers through dynamic reservoir simulation. This model is used to identify the optimum exploitation scenario for a hydrocarbon reservoir and is assessed by the geomechanics engineer to deduce the subsurface stresses and strains to create a 3D mechanical earth model. The multidisciplinary validated representation is handed over to the stimulation engineer to implement various treatments, either performed or to be performed. Once these treatments are designed, the reservoir engineer produces a production forecast which is then fed back to all team members involved in the process, enabling an optimization loop. Considering that this is a multi-well (producers and injector) study, any inference is reflected by the analysis and the optimum hydraulic fracture design is chosen for implementation by an offshore stimulation vessel. Traditionally, for forecasting purposes, hydraulic fractures can be implemented using conventional reservoir simulation; however, these are very much approximated models of what the stimulation engineers are designing and implementing. Often, the reservoir, production, stimulation engineers can come up with individual forecasts that are obtained independently and omit basic information. A typical example is the way stresses might change due to stimulation and production and the possibility to account for them in an integrated way. The proposed workflow eliminates these shortcomings, and the asset team delivers a single forecast of the exact fracture design considering a fully consistent model of the subsurface, which is to be implemented by the stimulation vessel for the different wells.
{"title":"A Multidisciplinary Approach to Production Optimization through Hydraulic Fracturing Stimulation and Geomechanical Modelling in Clair Field","authors":"L. Dumitrache, Alistair Roy, Anastasia Bird, B. Goktas, C. Sorgi, Reginald Stanley, V. De Gennaro, E. Eswein, J. Abbott","doi":"10.2523/iptc-22293-ms","DOIUrl":"https://doi.org/10.2523/iptc-22293-ms","url":null,"abstract":"\u0000 The integration of data and discipline specific knowledge is a common challenge when attempting to optimize or accelerate an asset's recovery through hydraulic fracture stimulations. Any potential omission of data or understanding will increase uncertainty and a project's chance of failure. Therefore, when looking to optimize the production of a given asset, it is key to take a holistic approach that breaks down any technical and organisational barriers.\u0000 This project couples the output of the different subsurface and stimulation disciplines to reduce the uncertainty associated with the production forecast of planned stimulation designs. The following paper presents the integrated approach for the Graben sector of UK's North Sea Clair oil field, largest oil field currently in Europe.\u0000 Geophysicists, petrophysicists, and geologists generate a static model which is calibrated and validated by reservoir engineers through dynamic reservoir simulation. This model is used to identify the optimum exploitation scenario for a hydrocarbon reservoir and is assessed by the geomechanics engineer to deduce the subsurface stresses and strains to create a 3D mechanical earth model. The multidisciplinary validated representation is handed over to the stimulation engineer to implement various treatments, either performed or to be performed. Once these treatments are designed, the reservoir engineer produces a production forecast which is then fed back to all team members involved in the process, enabling an optimization loop. Considering that this is a multi-well (producers and injector) study, any inference is reflected by the analysis and the optimum hydraulic fracture design is chosen for implementation by an offshore stimulation vessel.\u0000 Traditionally, for forecasting purposes, hydraulic fractures can be implemented using conventional reservoir simulation; however, these are very much approximated models of what the stimulation engineers are designing and implementing. Often, the reservoir, production, stimulation engineers can come up with individual forecasts that are obtained independently and omit basic information. A typical example is the way stresses might change due to stimulation and production and the possibility to account for them in an integrated way. The proposed workflow eliminates these shortcomings, and the asset team delivers a single forecast of the exact fracture design considering a fully consistent model of the subsurface, which is to be implemented by the stimulation vessel for the different wells.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"02 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85910316","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}
Ahmed S. Rizk, Moussa Tembely, W. Alameri, E. Al-Shalabi
Increasing global oil demand, combined with limited new discoveries, compels oil companies to maximize the value of existing resources by employing enhanced oil recovery (EOR) techniques aimed at the remaining oil. Estimating residual oil saturation (Sor) in the reservoir after conventional recovery techniques, such as waterflooding is critical in screening the suitable EOR technique and in further field development and production prediction. The objective of this work is to provide an artificial intelligence (AI) workflow to assess Sor of carbonate rocks, which will aid in the development of a long-term strategy for efficient production in this fourth industrial age. In the present work, two-phase lattice Boltzmann method (LBM) simulation was used with the benefit of high parallelization schemes. After applying the CPU-based solver using LBM on thousands of carbonate rock digital images, an AI-based workflow was developed to estimate Sor. Different advanced tree-based regression models were tested. Relevant input features were extracted from complex carbonate micro-CT images including porosity, absolute permeability, pore size and pore-throat size distributions, as well as rock surface roughness distribution. These features were fed into the learning models as inputs; while the output used to train and test the models is based on the direct simulation results of Sor from the image dataset. The results showed that extracting the engineered features from images aided in building a physics-informed machine learning model (ML) capable of accurately predicting Sor of carbonate rocks from their dry images. Three ML models were trained and tested on more than 1000 data points, namely gradient boosting, random forest, and xgradient boosting. Even with such small number of data points, the three models yielded promising results. Gradient boosting algorithm showed the highest predictive capability among the three techniques, with an R2 of 0.71. Increasing the number of data points is expected to help the models capture wider ranges of rock properties, and consequently, result in an increase in the prediction capability of the models. To the best of our knowledge, this is the first study that leverages machine learning to estimating residual oil saturation in complex carbonate. This work will contribute to the development of a novel framework for estimating accurately and reliably residual oil saturation of heterogeneous rocks. As a result, this research will aid in providing decision-makers with a simple tool for screening the most suitable EOR technique for optimal asset use.
{"title":"Residual Oil Saturation Estimation from Carbonate Rock Images Based on Direct Simulation and Machine Learning","authors":"Ahmed S. Rizk, Moussa Tembely, W. Alameri, E. Al-Shalabi","doi":"10.2523/iptc-22096-ms","DOIUrl":"https://doi.org/10.2523/iptc-22096-ms","url":null,"abstract":"\u0000 Increasing global oil demand, combined with limited new discoveries, compels oil companies to maximize the value of existing resources by employing enhanced oil recovery (EOR) techniques aimed at the remaining oil. Estimating residual oil saturation (Sor) in the reservoir after conventional recovery techniques, such as waterflooding is critical in screening the suitable EOR technique and in further field development and production prediction. The objective of this work is to provide an artificial intelligence (AI) workflow to assess Sor of carbonate rocks, which will aid in the development of a long-term strategy for efficient production in this fourth industrial age. In the present work, two-phase lattice Boltzmann method (LBM) simulation was used with the benefit of high parallelization schemes. After applying the CPU-based solver using LBM on thousands of carbonate rock digital images, an AI-based workflow was developed to estimate Sor. Different advanced tree-based regression models were tested. Relevant input features were extracted from complex carbonate micro-CT images including porosity, absolute permeability, pore size and pore-throat size distributions, as well as rock surface roughness distribution. These features were fed into the learning models as inputs; while the output used to train and test the models is based on the direct simulation results of Sor from the image dataset.\u0000 The results showed that extracting the engineered features from images aided in building a physics-informed machine learning model (ML) capable of accurately predicting Sor of carbonate rocks from their dry images. Three ML models were trained and tested on more than 1000 data points, namely gradient boosting, random forest, and xgradient boosting. Even with such small number of data points, the three models yielded promising results. Gradient boosting algorithm showed the highest predictive capability among the three techniques, with an R2 of 0.71. Increasing the number of data points is expected to help the models capture wider ranges of rock properties, and consequently, result in an increase in the prediction capability of the models. To the best of our knowledge, this is the first study that leverages machine learning to estimating residual oil saturation in complex carbonate. This work will contribute to the development of a novel framework for estimating accurately and reliably residual oil saturation of heterogeneous rocks. As a result, this research will aid in providing decision-makers with a simple tool for screening the most suitable EOR technique for optimal asset use.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84872485","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}
Shairizal B. Badzri, Swee Fung Lim, Nordiana Jamil, A. H. Hassan
HSSE digitalisation and big data analytics in Oil and Gas industry present a multitude of challenges which includes the inconsistency of work processes in data management, questionable data integrity, high operating cost in managing digital systems, lack of visibility and the mindset shift of users. These challenges have led to the digital transformation journey in PETRONAS. Since PETRONAS embarked on the digitalisation and analytic transformation, numerous value creations have been recorded namely improved HSSE performance, compliance to internal and HSSE regulatory requirements, cost value realization and supporting the United Nations Sustainable Development Goals (UN SDGs). The objective of this paper is to provide strategy guidance in HSSE system digitalisation and data analytics enhancement. The inclusion of digitalisation as one of the focus areas in PETRONAS HSSE Strategy and its supporting blocks in realising the bigger digitalisation agenda can be emulated and/or referenced by industry peers who face similar challenges and are keen to embark on the transformation journey.
{"title":"Myhsse – Analytic Transformation of Health, Safety, Security and Environment HSSE in Making Prescriptive Possible Towards Zero Incident; Geared by End Users’ Pain Points","authors":"Shairizal B. Badzri, Swee Fung Lim, Nordiana Jamil, A. H. Hassan","doi":"10.2523/iptc-22572-ms","DOIUrl":"https://doi.org/10.2523/iptc-22572-ms","url":null,"abstract":"\u0000 HSSE digitalisation and big data analytics in Oil and Gas industry present a multitude of challenges which includes the inconsistency of work processes in data management, questionable data integrity, high operating cost in managing digital systems, lack of visibility and the mindset shift of users. These challenges have led to the digital transformation journey in PETRONAS.\u0000 Since PETRONAS embarked on the digitalisation and analytic transformation, numerous value creations have been recorded namely improved HSSE performance, compliance to internal and HSSE regulatory requirements, cost value realization and supporting the United Nations Sustainable Development Goals (UN SDGs).\u0000 The objective of this paper is to provide strategy guidance in HSSE system digitalisation and data analytics enhancement. The inclusion of digitalisation as one of the focus areas in PETRONAS HSSE Strategy and its supporting blocks in realising the bigger digitalisation agenda can be emulated and/or referenced by industry peers who face similar challenges and are keen to embark on the transformation journey.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91271914","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}
C. T. Law, Engku Ali Aminulhakim Engku M. Shukri, Sukhveender Singh Sukhdev Singh, Sarah, Suet Hoey Lim, A. Muhamad
The hunt for more data at lesser the cost is a never-ending quest in the world of seismic acquisition. The latest offered solution in that vein – multisource 3D marine acquisition Here, we present the first-ever penta source 3D Marine Acquisition to be adopted commercially in Malaysian waters, largest survey area of its kind to date ~ 6920 sqkm of data in total. This paper provides an overview of the execution and the outline of the challenges faced, and adaptations made to absolve it, in both acquiring and processing the penta source data. The results are compared with pre-existing legacy data, and with it, recommendations for better acquisition efficiency and processing results.
{"title":"Penta Source 3D Marine Acquisition in the Sarawak Basin, Malaysia","authors":"C. T. Law, Engku Ali Aminulhakim Engku M. Shukri, Sukhveender Singh Sukhdev Singh, Sarah, Suet Hoey Lim, A. Muhamad","doi":"10.2523/iptc-21887-ea","DOIUrl":"https://doi.org/10.2523/iptc-21887-ea","url":null,"abstract":"\u0000 \u0000 \u0000 The hunt for more data at lesser the cost is a never-ending quest in the world of seismic acquisition. The latest offered solution in that vein – multisource 3D marine acquisition Here, we present the first-ever penta source 3D Marine Acquisition to be adopted commercially in Malaysian waters, largest survey area of its kind to date ~ 6920 sqkm of data in total. This paper provides an overview of the execution and the outline of the challenges faced, and adaptations made to absolve it, in both acquiring and processing the penta source data. The results are compared with pre-existing legacy data, and with it, recommendations for better acquisition efficiency and processing results.\u0000","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"44 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88286712","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. Zharnikov, R. Ponomarenko, A. Nikitin, C. Ayadiuno
This paper presents the analysis of borehole acoustic logging response in anisotropic rocks under geomechanical stress. Several effects, which are relevant to the interpretation of sonic logs, are observed and discussed. First, it is shown that the crossover of flexural modes dispersion curves in stress-induced anisotropic formation do not necessarily occur. Second, it is demonstrated that the effects of the difference in orientation of principal stress and anisotropy axes directions, stress magnitudes, and degree of anisotropy on the flexural dispersions can compensate each other at least partially. Finally, the examples of measurable stress effects on the dispersion curves in anisotropic formations are presented. The implication of these observations for the formation stress evaluation from sonic logs in the case of anisotropic formation is that the stress estimation from sonic logs should focus not only on stress magnitudes, but also take into account formation anisotropy and stress orientation with respect to the borehole and anisotropy axes.
{"title":"Analysis of the Effect of Geomechanical Stress on the Acoustic Response of Anisotropic Rocks","authors":"T. Zharnikov, R. Ponomarenko, A. Nikitin, C. Ayadiuno","doi":"10.2523/iptc-22321-ea","DOIUrl":"https://doi.org/10.2523/iptc-22321-ea","url":null,"abstract":"\u0000 This paper presents the analysis of borehole acoustic logging response in anisotropic rocks under geomechanical stress. Several effects, which are relevant to the interpretation of sonic logs, are observed and discussed. First, it is shown that the crossover of flexural modes dispersion curves in stress-induced anisotropic formation do not necessarily occur. Second, it is demonstrated that the effects of the difference in orientation of principal stress and anisotropy axes directions, stress magnitudes, and degree of anisotropy on the flexural dispersions can compensate each other at least partially. Finally, the examples of measurable stress effects on the dispersion curves in anisotropic formations are presented. The implication of these observations for the formation stress evaluation from sonic logs in the case of anisotropic formation is that the stress estimation from sonic logs should focus not only on stress magnitudes, but also take into account formation anisotropy and stress orientation with respect to the borehole and anisotropy axes.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"67 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78328422","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}
Maryvi Martinez Santiago, Shamma Al Shehhi, Sukilesh Anbalagan, A. Shbair, F. Noordin, Dicky Trisnadi, Mustapha Adli, Krisna Surya
ADNOC has development and implemented a robust automated sector performance review (SPR) process using state-of-the-art analytics and business process management tool (Khan et al., 2019). In this paper, we will present the achieved results and the defined opportunities by implementing SPR across some targeted reservoirs during the previous last 2 years. With the necessity of having analysis at sector level, the main objective of this work is to conduct an integrated reservoir dynamic synthesis, identify all challenges and opportunities to come up with robust and practical action plan aiming for best reservoir management and ultimately obtain best oil recovery by sector. Applying Integrated Reservoir Management (IRM) Workflow on Giant Onshore Field, It was decided to start the project on one major Reservoir A (divided by 3 sectors) as a project pilot. First data were collected from operations database, data management in spreadsheets, simulation output format, maps and images. All data were organized into the automated SPR workflow through a web based Business Process Management (BPM) that provided mechanism for the user to load, validate and approve technical data. Setting the workflow to focusing on analyzing the reservoir performance at sector level, the data is illustrated in an integrated visualization environment including panels for the reservoir KPI, production plan compliance status and reservoir pressure maintenance, diagnostic plots, production and injection summary, etc., opening the possibility for the user to identify new opportunities and areas that needs further investigations. Few key enhancements are listed and were suggested to the solution as a next phase. Following a methodical SPR automated workflow these conclusion are drawn: Technical data can be approved with appropriate notification for task execution. Data processing cycles, visualization and performance analysis dashboard time frame was reduced. It was identify the underperforming areas into the sectors. The Opportunity Management proactive system was used to identify reservoir profitable opportunities through a centralized platform. Action plans include well and surface intervention. 20% of the activities were successfully implemented and provided significant added values. Implementation of the automated SPR workflows as part of Digital technologies is renovating the traditional work process into very effective and advanced analytics and has achieved excellence in reservoir management and reserves recovery.
{"title":"Achieving Reservoir Performance Excellence By Implementing Automated Sector Performance: Onshore Field Case Study","authors":"Maryvi Martinez Santiago, Shamma Al Shehhi, Sukilesh Anbalagan, A. Shbair, F. Noordin, Dicky Trisnadi, Mustapha Adli, Krisna Surya","doi":"10.2523/iptc-21990-ea","DOIUrl":"https://doi.org/10.2523/iptc-21990-ea","url":null,"abstract":"\u0000 ADNOC has development and implemented a robust automated sector performance review (SPR) process using state-of-the-art analytics and business process management tool (Khan et al., 2019). In this paper, we will present the achieved results and the defined opportunities by implementing SPR across some targeted reservoirs during the previous last 2 years.\u0000 With the necessity of having analysis at sector level, the main objective of this work is to conduct an integrated reservoir dynamic synthesis, identify all challenges and opportunities to come up with robust and practical action plan aiming for best reservoir management and ultimately obtain best oil recovery by sector.\u0000 Applying Integrated Reservoir Management (IRM) Workflow on Giant Onshore Field, It was decided to start the project on one major Reservoir A (divided by 3 sectors) as a project pilot.\u0000 First data were collected from operations database, data management in spreadsheets, simulation output format, maps and images. All data were organized into the automated SPR workflow through a web based Business Process Management (BPM) that provided mechanism for the user to load, validate and approve technical data.\u0000 Setting the workflow to focusing on analyzing the reservoir performance at sector level, the data is illustrated in an integrated visualization environment including panels for the reservoir KPI, production plan compliance status and reservoir pressure maintenance, diagnostic plots, production and injection summary, etc., opening the possibility for the user to identify new opportunities and areas that needs further investigations.\u0000 Few key enhancements are listed and were suggested to the solution as a next phase.\u0000 Following a methodical SPR automated workflow these conclusion are drawn:\u0000 Technical data can be approved with appropriate notification for task execution. Data processing cycles, visualization and performance analysis dashboard time frame was reduced. It was identify the underperforming areas into the sectors. The Opportunity Management proactive system was used to identify reservoir profitable opportunities through a centralized platform. Action plans include well and surface intervention. 20% of the activities were successfully implemented and provided significant added values.\u0000 Implementation of the automated SPR workflows as part of Digital technologies is renovating the traditional work process into very effective and advanced analytics and has achieved excellence in reservoir management and reserves recovery.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"28 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77901304","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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