Mohamed A. Awwad, Ahmed Marei Al Radhi, M. Panigrahy, Suraj Kumar Gopal
Cost optimization is a continuous process in any business to drive cost reduction, while maximizing business value. Currently, cost reduction is being adopted by Oil & Gas firms as a core strategy, in order to maximize the profit margin. With global economies facing recession and wide fluctuations in energy demands, it seems low costs is becoming the safety valve for Oil & Gas companies. The oil and gas industry is under tremendous revenue and costs pressures. The indication is that globally, the oil and gas industry has experienced a huge drop in revenue in recent past. Some exploration and production oil firms have either halted or slowed down their production operations. Companies that manage their costs effectively will gain a competitive advantage. The oil market has less maneuverability with oil cartels determining the international price of oil. Project Costs are the major cost drivers of the Life Cycle costing & so Cost optimization of all mega Oil & Gas Projects became necessitated. Mega Oil & Gas projects, especially at ADNOC Offshore locations, are complex, labor-intensive and located inside Arabian Sea. These workforces are mainly from south Asian countries and so offshore sites are often subjected to the constraints of insufficient labor. These projects face multiple challenges in project management like severe weather, geographical conditions, insufficient work spaces etc. in addition to labor forces. Cost reductions are accomplished through optimization of its strong and robust project management organization, management of uncertainties, high quality engineering, and implementation of value engineering during engineering, procurement, construction and commissioning (EPCC) phases and effective management of changes along with key Stakeholders expectations throughout the project life cycle. This paper is based on the authors’ real life experience in implementation of many complex and mega upstream Oil & Gas projects with ADNOC Offshore who is currently leading multiple projects at DAS & Zirku islands. The most workable methods in this regard are listed here below.
{"title":"Cost Optimization in Mega Oil & Gas Projects","authors":"Mohamed A. Awwad, Ahmed Marei Al Radhi, M. Panigrahy, Suraj Kumar Gopal","doi":"10.2118/207751-ms","DOIUrl":"https://doi.org/10.2118/207751-ms","url":null,"abstract":"\u0000 Cost optimization is a continuous process in any business to drive cost reduction, while maximizing business value. Currently, cost reduction is being adopted by Oil & Gas firms as a core strategy, in order to maximize the profit margin. With global economies facing recession and wide fluctuations in energy demands, it seems low costs is becoming the safety valve for Oil & Gas companies. The oil and gas industry is under tremendous revenue and costs pressures. The indication is that globally, the oil and gas industry has experienced a huge drop in revenue in recent past. Some exploration and production oil firms have either halted or slowed down their production operations. Companies that manage their costs effectively will gain a competitive advantage. The oil market has less maneuverability with oil cartels determining the international price of oil. Project Costs are the major cost drivers of the Life Cycle costing & so Cost optimization of all mega Oil & Gas Projects became necessitated. Mega Oil & Gas projects, especially at ADNOC Offshore locations, are complex, labor-intensive and located inside Arabian Sea. These workforces are mainly from south Asian countries and so offshore sites are often subjected to the constraints of insufficient labor. These projects face multiple challenges in project management like severe weather, geographical conditions, insufficient work spaces etc. in addition to labor forces.\u0000 Cost reductions are accomplished through optimization of its strong and robust project management organization, management of uncertainties, high quality engineering, and implementation of value engineering during engineering, procurement, construction and commissioning (EPCC) phases and effective management of changes along with key Stakeholders expectations throughout the project life cycle.\u0000 This paper is based on the authors’ real life experience in implementation of many complex and mega upstream Oil & Gas projects with ADNOC Offshore who is currently leading multiple projects at DAS & Zirku islands. The most workable methods in this regard are listed here below.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83486542","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}
Yogi Adi Guna, Michael A. Frank, Novianto Rochman, Thomas Herdian Abi Putra, M. Irvan, Alfatah Fitriansyah, Ibnu Kurniawan
An operator recorded 1100 psi of sustained casing pressure between a 9-5/8" casing and a 3.5" production tubing annulus seven days after the cementing operation was completed for the 3.5" production tubing. A production logging run was performed, and results indicated gas was flowing from a zone 86 feet below the 9-5/8" casing shoe. As per the operator's standard, such a situation suggests subsequent well completion operations cannot be processed and must be remediated. The most common solution for such situations is to perforate and squeeze to ensure zonal isolation in the zone from which the gas is flowing. Due to the slim tubing size this operation can be difficult, and there exists a high risk of leaving set cement inside the 3.5" tubing. Furthermore, drilling would require extensive time with a coil tubing unit and in the worst case could lead to the loss of the well. To provide a dependable barrier for long term well integrity, a novel approach consisting of epoxy resin was discussed. A highly ductile, solids-free resin was designed and tailored to seal off communication from the gas source to surface. The void space in the annulus was estimated to be less than 5 bbl. An equipment package was prepared to mix and pump the resin into the annulus. Resin was pumped through the wellhead casing valve using a hesitation squeeze technique with the maximum surface pressure limited to 3000 psi. Once all resin was pumped, the casing valve was closed to allow enough time for the resin to build compressive strength. The job was planned to be performed in multiple stages consisting of smaller volumes. The job was completed in two stages, and the annular pressure was reduced. On the first job, 1 bbl of resin was mixed and injected into the annulus. The pressure build up was decreased from 550 psi per day to 27 psi per day. To lower the annular pressure further, a second resin job was performed using 0.35 bbl resin volume, which further reduced the annular pressure build up to 25 psi within 3 days. No further stages were performed as this was considered a safe working pressure for the well owner. After 2 months no annular pressure was observed. The application of this tailored resin helped to improve the wells integrity under these circumstances in this high-pressure gas well. Epoxy resin with its solid-free nature and deep penetration capabilities helped to seal off a very tight flow path. This application of pumping resin through the wellhead to overcome annular gas pressure can be an option when the flow path is strictly limited, or downhole well intervention is very difficult and risky.
{"title":"Novel Application of Epoxy Resin to Eliminate Sustained Casing Pressure Without Costly Downhole Well Intervention - Case History from East Kalimantan, Indonesia","authors":"Yogi Adi Guna, Michael A. Frank, Novianto Rochman, Thomas Herdian Abi Putra, M. Irvan, Alfatah Fitriansyah, Ibnu Kurniawan","doi":"10.2118/207419-ms","DOIUrl":"https://doi.org/10.2118/207419-ms","url":null,"abstract":"\u0000 An operator recorded 1100 psi of sustained casing pressure between a 9-5/8\" casing and a 3.5\" production tubing annulus seven days after the cementing operation was completed for the 3.5\" production tubing. A production logging run was performed, and results indicated gas was flowing from a zone 86 feet below the 9-5/8\" casing shoe. As per the operator's standard, such a situation suggests subsequent well completion operations cannot be processed and must be remediated. The most common solution for such situations is to perforate and squeeze to ensure zonal isolation in the zone from which the gas is flowing. Due to the slim tubing size this operation can be difficult, and there exists a high risk of leaving set cement inside the 3.5\" tubing. Furthermore, drilling would require extensive time with a coil tubing unit and in the worst case could lead to the loss of the well.\u0000 To provide a dependable barrier for long term well integrity, a novel approach consisting of epoxy resin was discussed. A highly ductile, solids-free resin was designed and tailored to seal off communication from the gas source to surface. The void space in the annulus was estimated to be less than 5 bbl. An equipment package was prepared to mix and pump the resin into the annulus. Resin was pumped through the wellhead casing valve using a hesitation squeeze technique with the maximum surface pressure limited to 3000 psi. Once all resin was pumped, the casing valve was closed to allow enough time for the resin to build compressive strength.\u0000 The job was planned to be performed in multiple stages consisting of smaller volumes. The job was completed in two stages, and the annular pressure was reduced. On the first job, 1 bbl of resin was mixed and injected into the annulus. The pressure build up was decreased from 550 psi per day to 27 psi per day. To lower the annular pressure further, a second resin job was performed using 0.35 bbl resin volume, which further reduced the annular pressure build up to 25 psi within 3 days. No further stages were performed as this was considered a safe working pressure for the well owner. After 2 months no annular pressure was observed.\u0000 The application of this tailored resin helped to improve the wells integrity under these circumstances in this high-pressure gas well. Epoxy resin with its solid-free nature and deep penetration capabilities helped to seal off a very tight flow path. This application of pumping resin through the wellhead to overcome annular gas pressure can be an option when the flow path is strictly limited, or downhole well intervention is very difficult and risky.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82489133","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}
Erismar Rubio, M. Y. Alklih, N. Reddicharla, Abobaker Albelazi, Melike Dilsiz, Mohamed Ali Al-Attar, R. Davila, K. Khan
Automation and data-driven models have been proven to yield commercial success in several oil fields worldwide with reported technical advantages related to improved reservoir management. This paper demonstrates the implementation of an integrated workflow to enhance CO2 injection project performance in a giant onshore smart oil field in Abu Dhabi. Since commissioning, proactive evaluation of the reservoir management strategy is enabled via smart-exception-based surveillance routines that facilitate reservoir/pattern/well performance review and supporting the decision making process. Prolonging the production sustainability of each well is a key pillar of this work, which has been made more quantifiable using live-tracking of the produced CO2 content and corrosion indicators. The intensive computing technical tasks and data aggregation from different sources; such as well testing and real time production/injection measurements; are integrated in an automatic workflow in a single platform. Accordingly, real-time visualizations and dashboards are also generated automatically; to orchestrate information, models and multidisciplinary knowledge in a systematic and efficient manner; allowing engineers to focus on problematic wells and giving attention to opportunity generation in a timely manner. Complemented with numerical techniques and other decision support tools, the intelligent system data-driven model assist to obtain a reliable short-term forecast in a shorter time and help making quick decisions on day-to-day operational optimization aspects. These dashboards have allowed measuring the true well/pattern performance towards operational objectives and production targets. A complete set of KPI's has helped to identify well health-status, potential risks and thus mitigate them for short/long term recovery to obtain an optimum reservoir energy balance in daily bases. In case of unexpected well performance behaviors, the dashboards have provided data insights on the root causes of different well issues and thus remedial actions were proposed accordingly. Maintaining CO2 miscibility is also ensured by having the right pressure support around producers, taking proactive actions from continues evaluation of producer-injector connectivity/interdependency, improving injection/production schedule, validating/tuning streamline model based on surveillance insights, avoiding CO2 recycling, optimizing data acquisition plan with potential cost saving while taking preventive measures to minimize well/facility corrosion impact. In this work, best reservoir management practices have been implemented to create a value of 12% incremental oil recovery from the field. The applied methodology uses an integrated automation and data-driven modeling approach to tackle CO2 injection project management challenges in real-time.
{"title":"Integrated Automation and Data-Driven Workflow for CO2 Project Management – Case Study from a Smart Oil Field in the Middle-East","authors":"Erismar Rubio, M. Y. Alklih, N. Reddicharla, Abobaker Albelazi, Melike Dilsiz, Mohamed Ali Al-Attar, R. Davila, K. Khan","doi":"10.2118/207422-ms","DOIUrl":"https://doi.org/10.2118/207422-ms","url":null,"abstract":"\u0000 Automation and data-driven models have been proven to yield commercial success in several oil fields worldwide with reported technical advantages related to improved reservoir management. This paper demonstrates the implementation of an integrated workflow to enhance CO2 injection project performance in a giant onshore smart oil field in Abu Dhabi. Since commissioning, proactive evaluation of the reservoir management strategy is enabled via smart-exception-based surveillance routines that facilitate reservoir/pattern/well performance review and supporting the decision making process. Prolonging the production sustainability of each well is a key pillar of this work, which has been made more quantifiable using live-tracking of the produced CO2 content and corrosion indicators.\u0000 The intensive computing technical tasks and data aggregation from different sources; such as well testing and real time production/injection measurements; are integrated in an automatic workflow in a single platform. Accordingly, real-time visualizations and dashboards are also generated automatically; to orchestrate information, models and multidisciplinary knowledge in a systematic and efficient manner; allowing engineers to focus on problematic wells and giving attention to opportunity generation in a timely manner. Complemented with numerical techniques and other decision support tools, the intelligent system data-driven model assist to obtain a reliable short-term forecast in a shorter time and help making quick decisions on day-to-day operational optimization aspects.\u0000 These dashboards have allowed measuring the true well/pattern performance towards operational objectives and production targets. A complete set of KPI's has helped to identify well health-status, potential risks and thus mitigate them for short/long term recovery to obtain an optimum reservoir energy balance in daily bases. In case of unexpected well performance behaviors, the dashboards have provided data insights on the root causes of different well issues and thus remedial actions were proposed accordingly.\u0000 Maintaining CO2 miscibility is also ensured by having the right pressure support around producers, taking proactive actions from continues evaluation of producer-injector connectivity/interdependency, improving injection/production schedule, validating/tuning streamline model based on surveillance insights, avoiding CO2 recycling, optimizing data acquisition plan with potential cost saving while taking preventive measures to minimize well/facility corrosion impact.\u0000 In this work, best reservoir management practices have been implemented to create a value of 12% incremental oil recovery from the field. The applied methodology uses an integrated automation and data-driven modeling approach to tackle CO2 injection project management challenges in real-time.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84442149","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}
N. Razali, Ivy Ching Hsia Chai, A.A. a Manap, M. M. Mahamad Amir
The capability of commercial nanoparticles to perform as foam stabilizer were investigated at reservoir temperature of 96°C. Al2O3, Fe3O4, Co3O4, CuO, MgO, NiO, ZrO2, ZnO and SiO2 nanoparticles that were characterized using XRD, FTIR, FESEM-EDX, TEM and PSA, were blended in the in-house formulated surfactant named IVF respectively at a particular ratio. The test was performed with and without the presence of reservoir crude oil. Results showed that formulation with nanoparticles enhanced foam stability by having longer foam half-life than the IVF surfactant alone, especially in the absence of oil. Only SiO2 nanoparticles were observed to have improved the foam stability in both test conditions. The unique properties of SiO2 as a semi-metal oxide material may have contributed to the insensitivity of SiO2 nanoparticle towards crude oil which is known as a foam destabilizer. The physical barrier that was formed by SiO2 nanoparticles at the foam lamella were probably unaffected by the presence of crude oil, thus allowing the foams to maintain its stability. In thermal stability tests, we observed the instability of all nanoparticles in the IVF formulation at 96°C. Nanoparticles were observed to have separated and settled within 24 hours. Therefore, surface modification of nanoparticle was done to establish steric stabilization by grafting macro-molecule of polymer onto the surface of SiO2. This in-house developed polymer grafted silica nanoparticles are named ZPG nanoparticles. The ZPG nanoparticles passed the thermal stability test at 96°C for a duration of 3 months. In the foam wetness analysis, ZPG nanoparticles were observed to have produced more wet foams than IVF formulation alone, indicating that ZPG is suitable to be used as foam stabilizer for EOR process as it showed catalytic behaviour and thermally well-stable at reservoir temperature.
{"title":"Enhanced Foam Stability Using Nanoparticle in High Salinity High Temperature Condition for Eor Application","authors":"N. Razali, Ivy Ching Hsia Chai, A.A. a Manap, M. M. Mahamad Amir","doi":"10.2118/208196-ms","DOIUrl":"https://doi.org/10.2118/208196-ms","url":null,"abstract":"\u0000 The capability of commercial nanoparticles to perform as foam stabilizer were investigated at reservoir temperature of 96°C. Al2O3, Fe3O4, Co3O4, CuO, MgO, NiO, ZrO2, ZnO and SiO2 nanoparticles that were characterized using XRD, FTIR, FESEM-EDX, TEM and PSA, were blended in the in-house formulated surfactant named IVF respectively at a particular ratio. The test was performed with and without the presence of reservoir crude oil. Results showed that formulation with nanoparticles enhanced foam stability by having longer foam half-life than the IVF surfactant alone, especially in the absence of oil. Only SiO2 nanoparticles were observed to have improved the foam stability in both test conditions. The unique properties of SiO2 as a semi-metal oxide material may have contributed to the insensitivity of SiO2 nanoparticle towards crude oil which is known as a foam destabilizer. The physical barrier that was formed by SiO2 nanoparticles at the foam lamella were probably unaffected by the presence of crude oil, thus allowing the foams to maintain its stability. In thermal stability tests, we observed the instability of all nanoparticles in the IVF formulation at 96°C. Nanoparticles were observed to have separated and settled within 24 hours. Therefore, surface modification of nanoparticle was done to establish steric stabilization by grafting macro-molecule of polymer onto the surface of SiO2. This in-house developed polymer grafted silica nanoparticles are named ZPG nanoparticles. The ZPG nanoparticles passed the thermal stability test at 96°C for a duration of 3 months. In the foam wetness analysis, ZPG nanoparticles were observed to have produced more wet foams than IVF formulation alone, indicating that ZPG is suitable to be used as foam stabilizer for EOR process as it showed catalytic behaviour and thermally well-stable at reservoir temperature.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79765588","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}
Fa-yang Jin, Qi-hang Li, Yong Liu, W. Pu, C. Yuan, Xiaoman Yuan, Chuanjia Liu, Qing Chen, M. Varfolomeev, Kexing Li
The HD Oilfield, operated by PetroChina, is located in Tarim Basin. It is characterized by high temperature (112 ℃) and high salinity (291000 mg/L), and developed by wide spacing of wells (average 700 m). High vertical and areal heterogeneity lead to early water breakthrough and a poor water sweep efficiency. Effective conformance control is urgently needed, but harsh reservoir conditions, wide well spacing, and discontinuous interlayers pose great challenges for conformance treatments in this field. Because of wide well spacing and discontinuous interlayers, water channeling and crossflow in in-depth part of reservoir could still occur after conformance treatment. To prevent this, in-depth conformance improvement treatments with injecting large volumes of low-cost profile control agents were proposed. To achieve this goal, we designed delayed water-swelling, flexible gel particles that have high deformability and elasticity. Simultaneously, to meet the harsh reservoir conditions, gel particles were designed to have long-term tolerance to high temperature and high salinity. The first treatment was implemented in May 2016, and the total incremental oil by June 2019 was 17347 tons. The treatment validity is more than 36 months, and it keeps being effective. Until now, 9 treatments have been finished. The total incremental oil is 102100 tons until May 2020, and the increment is still going on. The input-output ratio for these 9 treatments is about 8.45, which indicates the treatments were an economic and technical success. In this paper, first we describe the design of gel particles and their properties evaluation by extensive experiments, including water-swelling ability, long-term tolerance to high temperature and high salinity, elasticity, tenacity, injectivity, selectivity, plugging ability, and scouring resistance, etc. Then, we present operation design and control in the field, which is especially important for the success of these treatments. Furthermore, according to production performance as well as the wellhead pressure drop curve, pressure curve of water injection, and water injectivity in injection well, treatment results are discussed in detail to evaluate if the treatment is successful or not. Finally, several important experiences with respect to how to do operation design and field control are summarized. This paper documents a successful case history of in-depth waterflood conformance improvement in wide spacing of wells. These successful field cases together with summarized experience will provide a detailed guide and an updated framework for conformance improvement treatment for operators. In addition, this paper presents an alternative agent, i.e., delayed water-swelling, flexible gel particles, for in-depth waterflood conformance improvement in high temperature and high salinity reservoirs.
{"title":"Successful Field Application of Delayed Water-Swelling, Flexible Gel Particles for In-Depth Waterflood Conformance Improvement in Wide Spacing of Wells with High Temperature and High Salinity","authors":"Fa-yang Jin, Qi-hang Li, Yong Liu, W. Pu, C. Yuan, Xiaoman Yuan, Chuanjia Liu, Qing Chen, M. Varfolomeev, Kexing Li","doi":"10.2118/207974-ms","DOIUrl":"https://doi.org/10.2118/207974-ms","url":null,"abstract":"\u0000 The HD Oilfield, operated by PetroChina, is located in Tarim Basin. It is characterized by high temperature (112 ℃) and high salinity (291000 mg/L), and developed by wide spacing of wells (average 700 m). High vertical and areal heterogeneity lead to early water breakthrough and a poor water sweep efficiency. Effective conformance control is urgently needed, but harsh reservoir conditions, wide well spacing, and discontinuous interlayers pose great challenges for conformance treatments in this field. Because of wide well spacing and discontinuous interlayers, water channeling and crossflow in in-depth part of reservoir could still occur after conformance treatment. To prevent this, in-depth conformance improvement treatments with injecting large volumes of low-cost profile control agents were proposed. To achieve this goal, we designed delayed water-swelling, flexible gel particles that have high deformability and elasticity. Simultaneously, to meet the harsh reservoir conditions, gel particles were designed to have long-term tolerance to high temperature and high salinity.\u0000 The first treatment was implemented in May 2016, and the total incremental oil by June 2019 was 17347 tons. The treatment validity is more than 36 months, and it keeps being effective. Until now, 9 treatments have been finished. The total incremental oil is 102100 tons until May 2020, and the increment is still going on. The input-output ratio for these 9 treatments is about 8.45, which indicates the treatments were an economic and technical success. In this paper, first we describe the design of gel particles and their properties evaluation by extensive experiments, including water-swelling ability, long-term tolerance to high temperature and high salinity, elasticity, tenacity, injectivity, selectivity, plugging ability, and scouring resistance, etc. Then, we present operation design and control in the field, which is especially important for the success of these treatments. Furthermore, according to production performance as well as the wellhead pressure drop curve, pressure curve of water injection, and water injectivity in injection well, treatment results are discussed in detail to evaluate if the treatment is successful or not. Finally, several important experiences with respect to how to do operation design and field control are summarized.\u0000 This paper documents a successful case history of in-depth waterflood conformance improvement in wide spacing of wells. These successful field cases together with summarized experience will provide a detailed guide and an updated framework for conformance improvement treatment for operators. In addition, this paper presents an alternative agent, i.e., delayed water-swelling, flexible gel particles, for in-depth waterflood conformance improvement in high temperature and high salinity reservoirs.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"99 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79256356","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}
Achraf Ourir, Jed Oukmal, B. Rondeleux, Zinyat Agharzayeva, Philippe Barrault
Analytical models, in particular Decline Curve Analysis (DCA) are widely used in the oil and gas industry. However, they are often solely based on production data from the declining wells and do not leverage the other data available in the field e.g. petrophysics at well, completion length, distance to contacts... This paper describes a workflow to quickly build hybrid models for reservoir production forecast based on a mix of classic reservoir methods and machine learning algorithms. This workflow is composed of three main steps applied on a well by well basis. First, we build an object called forecaster which contains the subject matter knowledge. This forecaster can represent parametric functions trained on the well itself or more complex models that learn from a larger data set (production and petrophysics data, synthesis properties). Secondly this forecaster is tested on a subset of production history to qualify it. Finally, the full data set is used to forecast the production profile. It has been applied to all fluids (oil, water, gas, liquid) and revealed particularly useful for fields with large number of wells and long history, as an alternative to classical simulations when grid models are too complex or difficult to history match. Two use cases from conventional and unconventional fields will be presented in which this workflow helped quickly generate robust forecast for existing wells (declining or non-declining) and new wells. This workflow brings the technology, structure and measurability of Data Science to Reservoir Engineering. It enables the application of the state of the art data science methods to solve concrete reservoir engineering problems. In addition, forecast results can be confronted to historical data using what we call "Blind Testing" which allows a quantification of the forecast uncertainty and avoid biases. Finally, the automated workflow has been used to generate a range of possible realizations and allows the quantification the uncertainty associated with the models.
{"title":"Hybrid Data Driven Approach for Reservoir Production Forecast","authors":"Achraf Ourir, Jed Oukmal, B. Rondeleux, Zinyat Agharzayeva, Philippe Barrault","doi":"10.2118/207425-ms","DOIUrl":"https://doi.org/10.2118/207425-ms","url":null,"abstract":"\u0000 Analytical models, in particular Decline Curve Analysis (DCA) are widely used in the oil and gas industry. However, they are often solely based on production data from the declining wells and do not leverage the other data available in the field e.g. petrophysics at well, completion length, distance to contacts... This paper describes a workflow to quickly build hybrid models for reservoir production forecast based on a mix of classic reservoir methods and machine learning algorithms. This workflow is composed of three main steps applied on a well by well basis. First, we build an object called forecaster which contains the subject matter knowledge. This forecaster can represent parametric functions trained on the well itself or more complex models that learn from a larger data set (production and petrophysics data, synthesis properties). Secondly this forecaster is tested on a subset of production history to qualify it. Finally, the full data set is used to forecast the production profile. It has been applied to all fluids (oil, water, gas, liquid) and revealed particularly useful for fields with large number of wells and long history, as an alternative to classical simulations when grid models are too complex or difficult to history match. Two use cases from conventional and unconventional fields will be presented in which this workflow helped quickly generate robust forecast for existing wells (declining or non-declining) and new wells.\u0000 This workflow brings the technology, structure and measurability of Data Science to Reservoir Engineering. It enables the application of the state of the art data science methods to solve concrete reservoir engineering problems. In addition, forecast results can be confronted to historical data using what we call \"Blind Testing\" which allows a quantification of the forecast uncertainty and avoid biases. Finally, the automated workflow has been used to generate a range of possible realizations and allows the quantification the uncertainty associated with the models.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77897715","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}
Sultan Ibrahim Al Shemaili, A. Fawzy, E. Assreti, M. El Maghraby, M. Moradi, Prabodh Chaube, Tawheed Mohammed
Several techniques have been applied to improve the water conformance of injection wells to eventually improve field oil recovery. Standalone Passive flow control devices or these devices combined with Sliding sleeves have been successful to improve the conformance in the wells, however, they may fail to provide the required performance in the reservoirs with complex/dynamic properties including propagating/dilating fractures or faults and may also require intervention. This is mainly because the continuously increasing contrast in the injectivity of a section with the feature compared to the rest of the well causes diverting a great portion of the injected fluid into the thief zone which ultimately creates short-circuit to the nearby producer wells. The new autonomous injection device overcomes this issue by selectively choking the injection of fluid into the growing fractures crossing the well. Once a predefined upper flowrate limit is reached at the zone, the valves autonomously close. Well A has been injecting water into reservoir B for several years. It has been recognised from the surveys that the well passes through two major faults and the other two features/fractures with huge uncertainty around their properties. The use of the autonomous valve was considered the best solution to control the water conformance in this well. The device initially operates as a normal passive outflow control valve, and if the injected flowrate flowing through the valve exceeds a designed limit, the device will automatically shut off. This provides the advantage of controlling the faults and fractures in case they were highly conductive as compared to other sections of the well and also once these zones are closed, the device enables the fluid to be distributed to other sections of the well, thereby improving the overall injection conformance. A comprehensive study was performed to change the existing dual completion to a single completion and determine the optimum completion design for delivering the targeted rate for the well while taking into account the huge uncertainty around the faults and features properties. The retrofitted completion including 9 joints with Autonomous valves and 5 joints with Bypass ICD valves were installed in the horizontal section of the well in six compartments separated with five swell packers. The completion was installed in mid-2020 and the well has been on the injection since September 2020. The well performance outcomes show that new completion has successfully delivered the target rate. Also, the data from a PLT survey performed in Feb 2021 shows that the valves have successfully minimised the outflow toward the faults and fractures. This allows achieving the optimised well performance autonomously as the impacts of thief zones on the injected fluid conformance is mitigated and a balanced-prescribed injection distribution is maintained. This paper presents the results from one of the early installations of the valves i
{"title":"The New Generation of Outflow Control Devices Autonomously Controlling the Conformance of Water Injection Well- A Case Study with ADNOC Onshore","authors":"Sultan Ibrahim Al Shemaili, A. Fawzy, E. Assreti, M. El Maghraby, M. Moradi, Prabodh Chaube, Tawheed Mohammed","doi":"10.2118/207647-ms","DOIUrl":"https://doi.org/10.2118/207647-ms","url":null,"abstract":"\u0000 Several techniques have been applied to improve the water conformance of injection wells to eventually improve field oil recovery. Standalone Passive flow control devices or these devices combined with Sliding sleeves have been successful to improve the conformance in the wells, however, they may fail to provide the required performance in the reservoirs with complex/dynamic properties including propagating/dilating fractures or faults and may also require intervention. This is mainly because the continuously increasing contrast in the injectivity of a section with the feature compared to the rest of the well causes diverting a great portion of the injected fluid into the thief zone which ultimately creates short-circuit to the nearby producer wells. The new autonomous injection device overcomes this issue by selectively choking the injection of fluid into the growing fractures crossing the well. Once a predefined upper flowrate limit is reached at the zone, the valves autonomously close.\u0000 Well A has been injecting water into reservoir B for several years. It has been recognised from the surveys that the well passes through two major faults and the other two features/fractures with huge uncertainty around their properties. The use of the autonomous valve was considered the best solution to control the water conformance in this well. The device initially operates as a normal passive outflow control valve, and if the injected flowrate flowing through the valve exceeds a designed limit, the device will automatically shut off. This provides the advantage of controlling the faults and fractures in case they were highly conductive as compared to other sections of the well and also once these zones are closed, the device enables the fluid to be distributed to other sections of the well, thereby improving the overall injection conformance.\u0000 A comprehensive study was performed to change the existing dual completion to a single completion and determine the optimum completion design for delivering the targeted rate for the well while taking into account the huge uncertainty around the faults and features properties. The retrofitted completion including 9 joints with Autonomous valves and 5 joints with Bypass ICD valves were installed in the horizontal section of the well in six compartments separated with five swell packers. The completion was installed in mid-2020 and the well has been on the injection since September 2020. The well performance outcomes show that new completion has successfully delivered the target rate. Also, the data from a PLT survey performed in Feb 2021 shows that the valves have successfully minimised the outflow toward the faults and fractures. This allows achieving the optimised well performance autonomously as the impacts of thief zones on the injected fluid conformance is mitigated and a balanced-prescribed injection distribution is maintained.\u0000 This paper presents the results from one of the early installations of the valves i","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"29 11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83281655","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 Fourth Industrial Revolution (4.0) in Oil & Gas Industry creates a dynamic landscape where Operational Excellence (OE) strives for stability, quality, and efficiency while continuing to serve an increasingly demanding customer. Operational excellence is a journey, not a sole destination. Abu Dhabi National Oil Company (ADNOC) Onshore, one of the South East Fields, oil production capacity was constrained due to the limitation of associated gas handling capacity of the compressors. Gas flow towards the compressor was not steady due to natural flowing wells non-steady behavior and this disturbance cannot be removed from the system. The situation was quite complicated. In order to produce oil, associated gas must be handled to avoid flaring. It was more than a challenge to increase the compressors effective capacity without any hardware modification. Since flaring is not permitted in ADNOC and running of huge capacity standby compressor was not economically viable, therefore, Field Operations by lateral thinking transformed this challenging situation into an opportunity and enhanced compressor effective capacity by expanding its operating envelope to handle additional gas. One innovative solution proposed by Field Operations was to expand the pressure-operating envelope of the machine to withstand high pressures without tripping. The idea was to increase the machine throughput by elevating the machine high-pressure trip set point along with Pressure Safety Valve (PSV) set point elevation. This submission shares success story of an oil field Operations in house efforts to enhance the gas injection compressor effective capacity by 600 MSCFD which subsequently increased the oil production capacity by 1700 bopd or 0.62 million barrels oil per year by Operational Excellence. Operational Excellence played its role with a value improvement objective. Rather than replacing successful practices and programs, Operational Excellence knitted them into a larger, fully integrated tapestry woven to increase value produced within the overall business strategy which is very evident in this scenario. This case study is blend of Operations Excellence and innovation representing Management support to employee to solve complex problems. Such support is always beneficial for the company and employee. Management of change process for followed to study, analyze and implement the idea.
{"title":"Enhancing Gas Injection Compressors Performance by Lateral Thinking Resulting in 0.62 Million Barrels Oil Per Year Additional Production Capacity at Zero Cost","authors":"M. Arif, Abdulla Mohammed Al Jneibi","doi":"10.2118/208186-ms","DOIUrl":"https://doi.org/10.2118/208186-ms","url":null,"abstract":"\u0000 The Fourth Industrial Revolution (4.0) in Oil & Gas Industry creates a dynamic landscape where Operational Excellence (OE) strives for stability, quality, and efficiency while continuing to serve an increasingly demanding customer. Operational excellence is a journey, not a sole destination.\u0000 Abu Dhabi National Oil Company (ADNOC) Onshore, one of the South East Fields, oil production capacity was constrained due to the limitation of associated gas handling capacity of the compressors. Gas flow towards the compressor was not steady due to natural flowing wells non-steady behavior and this disturbance cannot be removed from the system. The situation was quite complicated. In order to produce oil, associated gas must be handled to avoid flaring. It was more than a challenge to increase the compressors effective capacity without any hardware modification.\u0000 Since flaring is not permitted in ADNOC and running of huge capacity standby compressor was not economically viable, therefore, Field Operations by lateral thinking transformed this challenging situation into an opportunity and enhanced compressor effective capacity by expanding its operating envelope to handle additional gas.\u0000 One innovative solution proposed by Field Operations was to expand the pressure-operating envelope of the machine to withstand high pressures without tripping. The idea was to increase the machine throughput by elevating the machine high-pressure trip set point along with Pressure Safety Valve (PSV) set point elevation.\u0000 This submission shares success story of an oil field Operations in house efforts to enhance the gas injection compressor effective capacity by 600 MSCFD which subsequently increased the oil production capacity by 1700 bopd or 0.62 million barrels oil per year by Operational Excellence.\u0000 Operational Excellence played its role with a value improvement objective. Rather than replacing successful practices and programs, Operational Excellence knitted them into a larger, fully integrated tapestry woven to increase value produced within the overall business strategy which is very evident in this scenario.\u0000 This case study is blend of Operations Excellence and innovation representing Management support to employee to solve complex problems. Such support is always beneficial for the company and employee. Management of change process for followed to study, analyze and implement the idea.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88232512","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}
I. Maffeis, A. D. de Angelis, Riccardo Guernelli, E. Croce, Luigi Romano
During production from sour gas reservoirs, precipitation of elemental sulfur can take place in production tubing, resulting in plugging of the well and stop of production. Injection in tubing of products devoted to dissolving sulfur can be an efficient solution for plug removal and production restoring. Traditionally, organic solvents (like toluene) are employed for solid sulfur dissolution. In the present work, experimental investigations have been performed on a particular innovative liquid product designed as active phase for wellbore injection or near wellbore applications. The analyses about the behavior of the considered product were conducted at HP-HT conditions. For this purpose, PVT laboratory equipment was employed, being able to reproduce the conditions of interest for the formation of elemental sulfur plug in well. An important preliminary optimization phase on the experimental setup was necessary to assure the correct management of studied liquid substance and solid sulfur. Integration of main outcomes with other kind of analyses allowed to depict a complete representation of the behavior: microscopy analysis of the liquid phase and high-resolution tomography of solid sulfur before and after the interaction were employed. A key point of the experimental characterization is the reproduction of significant involved phenomena. A preliminary effort was necessary for reproducing the realistic crystal form expected during the precipitation of solid sulfur in well. The dissolution efficiency of the liquid product is evaluated by observing its physical interaction with sulfur in a HP-HT cell. Particular attention was paid to correctly handling employed substances at the considered pressure and temperature conditions. A detailed description of the optimized equipment used in laboratory is provided. Several dissolution tests have been conducted at different temperature and pressure conditions, aiming to observe the dependence of the dissolution efficiency on the thermodynamic parameters. A visual qualitative analysis was performed on both the liquid product and the solid plug, before and after the interaction in cell. This allowed to deepen the comprehension of the dynamics of sulfur dissolution, which takes place not only from the top face of the plug, but also from preferential paths (fractures) present inside the plug itself. The presence of sulfur crystals dispersed in the liquid product after sampling from the cell is also evident at the end of the tests. The studied novel sulfur-dissolving liquid active phase is a candidate for remedial job injection at well in case of plugging due to solid elemental sulfur precipitation. The analyses here presented allowed to characterize the dissolution potential of this product. An optimized workflow was designed, including different kind of experimental disciplines.
{"title":"Experimental Methods for the Evaluation of the Efficiency of an Innovative Sulfur-Dissolving Product in HP-HT Conditions","authors":"I. Maffeis, A. D. de Angelis, Riccardo Guernelli, E. Croce, Luigi Romano","doi":"10.2118/207845-ms","DOIUrl":"https://doi.org/10.2118/207845-ms","url":null,"abstract":"\u0000 During production from sour gas reservoirs, precipitation of elemental sulfur can take place in production tubing, resulting in plugging of the well and stop of production. Injection in tubing of products devoted to dissolving sulfur can be an efficient solution for plug removal and production restoring.\u0000 Traditionally, organic solvents (like toluene) are employed for solid sulfur dissolution. In the present work, experimental investigations have been performed on a particular innovative liquid product designed as active phase for wellbore injection or near wellbore applications.\u0000 The analyses about the behavior of the considered product were conducted at HP-HT conditions. For this purpose, PVT laboratory equipment was employed, being able to reproduce the conditions of interest for the formation of elemental sulfur plug in well. An important preliminary optimization phase on the experimental setup was necessary to assure the correct management of studied liquid substance and solid sulfur.\u0000 Integration of main outcomes with other kind of analyses allowed to depict a complete representation of the behavior: microscopy analysis of the liquid phase and high-resolution tomography of solid sulfur before and after the interaction were employed.\u0000 A key point of the experimental characterization is the reproduction of significant involved phenomena. A preliminary effort was necessary for reproducing the realistic crystal form expected during the precipitation of solid sulfur in well.\u0000 The dissolution efficiency of the liquid product is evaluated by observing its physical interaction with sulfur in a HP-HT cell. Particular attention was paid to correctly handling employed substances at the considered pressure and temperature conditions. A detailed description of the optimized equipment used in laboratory is provided.\u0000 Several dissolution tests have been conducted at different temperature and pressure conditions, aiming to observe the dependence of the dissolution efficiency on the thermodynamic parameters.\u0000 A visual qualitative analysis was performed on both the liquid product and the solid plug, before and after the interaction in cell. This allowed to deepen the comprehension of the dynamics of sulfur dissolution, which takes place not only from the top face of the plug, but also from preferential paths (fractures) present inside the plug itself. The presence of sulfur crystals dispersed in the liquid product after sampling from the cell is also evident at the end of the tests.\u0000 The studied novel sulfur-dissolving liquid active phase is a candidate for remedial job injection at well in case of plugging due to solid elemental sulfur precipitation. The analyses here presented allowed to characterize the dissolution potential of this product. An optimized workflow was designed, including different kind of experimental disciplines.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75844849","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}
Alexey Vasilievich Timonov, R. Khabibullin, N. S. Gurbatov, A. R. Shabonas, Alexey Vladimirovich Zhuchkov
Geosteering is an important area and its quality determines the efficiency of formation drilling by horizontal wells, which directly affects the project NPV. This paper presents the automated geosteering optimization platform which is based on live well data. The platform implements online corrections of the geological model and forecasts well performance from the target reservoir. The system prepares recommendations of the best reservoir production interval and the direction for horizontal well placements based on reservoir performance analytics. This paper describes the stages of developing a comprehensive system using machine-learning methods, which allows multivariate calculations to refine and predict the geological model. Based on the calculations, a search for the optimal location of a horizontal well to maximize production is carried out. The approach realized in the work takes into account many factors (some specific features of geological structure, history of field development, wells interference, etc.) and can offer optimum horizontal well placement options without performing full-scale or sector hydrodynamic simulation. Machine learning methods (based on decision trees and neural networks) and target function optimization methods are used for geological model refinement and forecasting as well as for selection of optimum interval of well placement. As the result of researches we have developed the complex system including modules of data verification and preprocessing, automatic inter-well correlation, optimization and target interval selection. The system was tested while drilling hydrocarbons in the Western Siberian fields, where the developed approach showed efficiency.
{"title":"Automated Geosteering Optimization Using Machine Learning","authors":"Alexey Vasilievich Timonov, R. Khabibullin, N. S. Gurbatov, A. R. Shabonas, Alexey Vladimirovich Zhuchkov","doi":"10.2118/207364-ms","DOIUrl":"https://doi.org/10.2118/207364-ms","url":null,"abstract":"\u0000 Geosteering is an important area and its quality determines the efficiency of formation drilling by horizontal wells, which directly affects the project NPV.\u0000 This paper presents the automated geosteering optimization platform which is based on live well data. The platform implements online corrections of the geological model and forecasts well performance from the target reservoir. The system prepares recommendations of the best reservoir production interval and the direction for horizontal well placements based on reservoir performance analytics.\u0000 This paper describes the stages of developing a comprehensive system using machine-learning methods, which allows multivariate calculations to refine and predict the geological model. Based on the calculations, a search for the optimal location of a horizontal well to maximize production is carried out.\u0000 The approach realized in the work takes into account many factors (some specific features of geological structure, history of field development, wells interference, etc.) and can offer optimum horizontal well placement options without performing full-scale or sector hydrodynamic simulation.\u0000 Machine learning methods (based on decision trees and neural networks) and target function optimization methods are used for geological model refinement and forecasting as well as for selection of optimum interval of well placement.\u0000 As the result of researches we have developed the complex system including modules of data verification and preprocessing, automatic inter-well correlation, optimization and target interval selection.\u0000 The system was tested while drilling hydrocarbons in the Western Siberian fields, where the developed approach showed efficiency.","PeriodicalId":11069,"journal":{"name":"Day 2 Tue, November 16, 2021","volume":"116 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76024115","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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