Zonal isolation is significant for safety operation of the well. Failure to keep wellbore integrity can lead to sustained annulus pressure (SAP), and gas migration (GM), which may cause long non-productive time. Losing zonal isolation can cause severe environmental issue, which is irreversible and detrimental. However, cement sheath is exposed to temperature and pressure changes from the beginning of the drilling process to the whole life of the well. These cyclic changes can lead to fatigue failure of the cement. The objective of this study is to investigate the fatigue failure that caused by cyclic changing of temperature and pressure during life of the well. The scope of the study is based on the laboratory fatigue failure cases in previous literatures. Instead of using mechanical failure models, support vector machine (SVM) model is used to predict the fatigue failure of the cement sheath. The data is gathered from six papers of One-Petro, which includes 325 laboratory cement fatigue failure cases. The model has fourteen inputs. Seven cement related factors were selected, which include cement type, additive material, Uniaxial Confining Strength (UCS), curing temperature, curing pressure, curing age, and Young's modulus. Seven experimental related factors, which include highest inner pressure, loading increment rate, frequency of loading, experimental temperature, confining pressure, existence of outer confining part, and cycles to reach failure. The SVM model is implemented by Python. We investigated 240 combinations of input groups and selected the best performance SVM model. The classification result is zero for no fatigue failure, and one for failure. The accuracy for the SVM model is 72.7%, which shows that SVM can be an acceptable model for cement fatigue prediction. The SVM model we proposed is more applicable for real implementation. Because we used real wellbore geometry data (thick wall geometry). Although the data were based on laboratory result, the SVM model provides a helpful method in predicting cement-sheath-failure. This study provides a data based method to predict cement fatigue failure under cyclic changing pressure and temperature. The result will be instructive for the cement design and wellbore operation optimization.
{"title":"Cement Sheath Fatigue Failure Prediction by Support Vector Machine Based Model","authors":"Danzhu Zheng, E. Ozbayoglu, S. Miska, Yaxin Liu","doi":"10.2118/211880-ms","DOIUrl":"https://doi.org/10.2118/211880-ms","url":null,"abstract":"\u0000 Zonal isolation is significant for safety operation of the well. Failure to keep wellbore integrity can lead to sustained annulus pressure (SAP), and gas migration (GM), which may cause long non-productive time. Losing zonal isolation can cause severe environmental issue, which is irreversible and detrimental. However, cement sheath is exposed to temperature and pressure changes from the beginning of the drilling process to the whole life of the well. These cyclic changes can lead to fatigue failure of the cement. The objective of this study is to investigate the fatigue failure that caused by cyclic changing of temperature and pressure during life of the well. The scope of the study is based on the laboratory fatigue failure cases in previous literatures. Instead of using mechanical failure models, support vector machine (SVM) model is used to predict the fatigue failure of the cement sheath.\u0000 The data is gathered from six papers of One-Petro, which includes 325 laboratory cement fatigue failure cases. The model has fourteen inputs. Seven cement related factors were selected, which include cement type, additive material, Uniaxial Confining Strength (UCS), curing temperature, curing pressure, curing age, and Young's modulus. Seven experimental related factors, which include highest inner pressure, loading increment rate, frequency of loading, experimental temperature, confining pressure, existence of outer confining part, and cycles to reach failure. The SVM model is implemented by Python. We investigated 240 combinations of input groups and selected the best performance SVM model. The classification result is zero for no fatigue failure, and one for failure.\u0000 The accuracy for the SVM model is 72.7%, which shows that SVM can be an acceptable model for cement fatigue prediction. The SVM model we proposed is more applicable for real implementation. Because we used real wellbore geometry data (thick wall geometry). Although the data were based on laboratory result, the SVM model provides a helpful method in predicting cement-sheath-failure.\u0000 This study provides a data based method to predict cement fatigue failure under cyclic changing pressure and temperature. The result will be instructive for the cement design and wellbore operation optimization.","PeriodicalId":407915,"journal":{"name":"Day 2 Wed, October 19, 2022","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122009728","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}
Laura Perkins, R. Tyree, Michael Ondash, Lauren Kreutzman
This paper outlines solutions for problems encountered due to scale deposits in Marcellus Shale wells, including approaches taken to remediate scale buildup. As wells in the Marcellus Shale produce over time, scale deposits in tubing form and have proven to be difficult to treat. These scale restrictions can cause well performance issues which limit options for artificial lift. Through sampling and lab analysis, the primary types of scale found are calcium carbonate and iron sulfide. After several years of evaluation, plunger lift equipment was unable to be installed in 25-30% of prospective wells due to scale buildup greater than tubing drift or 1.90″ in 2.375″ J-55 tubing. Calcium carbonate and iron sulfide scale tend to become very hard when they deposit on tubing walls and, as a result, they do not broach or scrape away easily. Throughout this remediation process, several types of broaches were trialed with minimal success. The most effective method for scale remediation was found to be hydrochloric acid (HCl), however, HCl introduces safety and operational concerns. From an operational perspective, the hydrostatic pressure exerted by a column of acid in the tubing can be difficult for an older well to unload. Volume and pressure calculations help prevent reservoir damage by not killing the well and corrosion inhibitors added to hydrochloric acid reduce risk of tubular degradation. The reaction between calcium carbonate and iron sulfide with HCl can produce an elevated amount of CO2 and H2S, respectively which are not present in normal operations. Additional safety measures taken in these operationally induced sour conditions are detailed in this paper. Through engineering efforts, along with computational fluid dynamics and field trials, several iterations of acid plungers designed specifically for scale remediation have been developed and successfully implemented. The role of the acid plunger is to provide temporary liquid holdup of the acid while simultaneously gauging the tubing walls as the acid column leaks by. The liquid holdup from the acid plunger provides sufficient contact time between the acid and scale buildup, especially in the vertical section of the well. The development of this process has resulted in the successful remediation of 62 wells to date. This includes using variations of this technique to free downhole tools stuck in scale. Additionally, there has not been reoccurring scaling deposits detected that would impede plunger lift operations. Further research for this project included trialing a corrosion-resistant stainless-steel slickline containing large amounts of nickel. This line, in conjunction with acid, provides additional versatility and more efficient means of scale removal. Future methods of scale remediation involve utilizing synthetic "green" acids and large volume lateral acid batches
{"title":"Scale Remediation in the Marcellus Shale: Calcium Carbonate and Iron Sulfide","authors":"Laura Perkins, R. Tyree, Michael Ondash, Lauren Kreutzman","doi":"10.2118/211870-ms","DOIUrl":"https://doi.org/10.2118/211870-ms","url":null,"abstract":"\u0000 This paper outlines solutions for problems encountered due to scale deposits in Marcellus Shale wells, including approaches taken to remediate scale buildup. As wells in the Marcellus Shale produce over time, scale deposits in tubing form and have proven to be difficult to treat. These scale restrictions can cause well performance issues which limit options for artificial lift. Through sampling and lab analysis, the primary types of scale found are calcium carbonate and iron sulfide. After several years of evaluation, plunger lift equipment was unable to be installed in 25-30% of prospective wells due to scale buildup greater than tubing drift or 1.90″ in 2.375″ J-55 tubing.\u0000 Calcium carbonate and iron sulfide scale tend to become very hard when they deposit on tubing walls and, as a result, they do not broach or scrape away easily. Throughout this remediation process, several types of broaches were trialed with minimal success. The most effective method for scale remediation was found to be hydrochloric acid (HCl), however, HCl introduces safety and operational concerns. From an operational perspective, the hydrostatic pressure exerted by a column of acid in the tubing can be difficult for an older well to unload. Volume and pressure calculations help prevent reservoir damage by not killing the well and corrosion inhibitors added to hydrochloric acid reduce risk of tubular degradation. The reaction between calcium carbonate and iron sulfide with HCl can produce an elevated amount of CO2 and H2S, respectively which are not present in normal operations. Additional safety measures taken in these operationally induced sour conditions are detailed in this paper.\u0000 Through engineering efforts, along with computational fluid dynamics and field trials, several iterations of acid plungers designed specifically for scale remediation have been developed and successfully implemented. The role of the acid plunger is to provide temporary liquid holdup of the acid while simultaneously gauging the tubing walls as the acid column leaks by. The liquid holdup from the acid plunger provides sufficient contact time between the acid and scale buildup, especially in the vertical section of the well. The development of this process has resulted in the successful remediation of 62 wells to date. This includes using variations of this technique to free downhole tools stuck in scale. Additionally, there has not been reoccurring scaling deposits detected that would impede plunger lift operations.\u0000 Further research for this project included trialing a corrosion-resistant stainless-steel slickline containing large amounts of nickel. This line, in conjunction with acid, provides additional versatility and more efficient means of scale removal. Future methods of scale remediation involve utilizing synthetic \"green\" acids and large volume lateral acid batches","PeriodicalId":407915,"journal":{"name":"Day 2 Wed, October 19, 2022","volume":"101 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133989389","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}
Determining frictional pressure losses along a wellbore annulus is the key to estimation of the wellbore equivalent circulating density. Flow-loop experiments are often used at smaller scales of flow to measure the frictional pressure losses. However, a complete set of scaling equations between the measured pressure drop in a flow loop device and the one occurring in the wellbore has not been reported in the literature. This study applies dimensional analysis to make such connection while accounting for drill pipe rotation, eccentricity, and cuttings load in the annular flow of power-law drilling fluids. Simultaneous application of geometric, kinematic, dynamic, and rheological similarities allows for developing direct relations between the operational and flow quantities at the laboratory and wellbore scales of flow. For this purpose, the pertinent dimensionless groups are identified and set equal between the two flow scales. Results indicate that scaling the two-phase flow of drilling fluid and cuttings entails nine (9) dimensionless groups. The obtained scaling equations provide the required volumetric rate of fluid and particles, the inner pipe rotation speed, as well as the fluid rheology and other design parameters of the flow-loop device to establish the full similitude with the corresponding wellbore hydraulics. In particular, the Reynolds number of cuttings necessitates introducing a constraint on the rheology of fluid to be used in the laboratory flow loop. Once all scaling requirements of the considered similitude are applied, the pressure gradient along the wellbore annulus can be obtained directly in terms of the measured pressure drop in the laboratory flow loop.
{"title":"Scaling Equations for Benchtop Laboratory Simulator of Wellbore Hydraulics","authors":"Mohammed Nabil Alarfaj, Wei Zhang, A. Mehrabian","doi":"10.2118/211886-ms","DOIUrl":"https://doi.org/10.2118/211886-ms","url":null,"abstract":"\u0000 Determining frictional pressure losses along a wellbore annulus is the key to estimation of the wellbore equivalent circulating density. Flow-loop experiments are often used at smaller scales of flow to measure the frictional pressure losses. However, a complete set of scaling equations between the measured pressure drop in a flow loop device and the one occurring in the wellbore has not been reported in the literature.\u0000 This study applies dimensional analysis to make such connection while accounting for drill pipe rotation, eccentricity, and cuttings load in the annular flow of power-law drilling fluids. Simultaneous application of geometric, kinematic, dynamic, and rheological similarities allows for developing direct relations between the operational and flow quantities at the laboratory and wellbore scales of flow. For this purpose, the pertinent dimensionless groups are identified and set equal between the two flow scales.\u0000 Results indicate that scaling the two-phase flow of drilling fluid and cuttings entails nine (9) dimensionless groups. The obtained scaling equations provide the required volumetric rate of fluid and particles, the inner pipe rotation speed, as well as the fluid rheology and other design parameters of the flow-loop device to establish the full similitude with the corresponding wellbore hydraulics. In particular, the Reynolds number of cuttings necessitates introducing a constraint on the rheology of fluid to be used in the laboratory flow loop. Once all scaling requirements of the considered similitude are applied, the pressure gradient along the wellbore annulus can be obtained directly in terms of the measured pressure drop in the laboratory flow loop.","PeriodicalId":407915,"journal":{"name":"Day 2 Wed, October 19, 2022","volume":"87 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115057401","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In wells with relatively high levels of iron, the use of polyacrylamide friction reducers (FR) used for hydraulic fracturing can result in poor performance due to negative chemical interactions. Hazra, et.al. (URTeC 2487 July 2020) documented a problem with the chemical reaction of FR and iron (ferrous and ferric) during hydraulic fracturing. This chemical reaction can create an accumulation of a semi-solid mass referred to as "gummy bears" due to their rubbery texture (figure 1). These gummy bears can form in surface and subsurface equipment and inhibit well production. In addition to the formation of gummy bears, the performance of FR is significantly impaired when reacting with iron (figure 2). Pyrite (FeS2) is a common mineral found in source rock. Ferrous iron (Fe2+) can be released by oxidative dissolution of pyrite minerals. In reservoirs with high concentrations of pyrite, iron can be released by dissolving reservoir rock during acid spearheading. Acid spearheading is a common industry practice during hydraulic fracturing operations. The process involves pumping a small quantity of acid pre-frac to dissolve rock material around the wellbore, cleaning up perforations, and reducing near wellbore entry friction. The focus of the acid spearhead is to lower breakdown pressures and improve injectivity during hydraulic fracturing. The problem that Hazra (2020) described was on a Woodford Shale project in Oklahoma. The Woodford is known to contain significant quantities of pyrite (observed at around 2%). One solution proposed was to eliminate the use of acid during the hydraulic fracturing operation. The potential downside was higher near wellbore frictions that would need to be addressed by higher hydraulic horsepower (HHP) and FR volumes. Figure 1 Effect of Fe2+ and Fe3+ on friction reduction properties of polyacrylamide friction reducer Figure courtesy of Downhole Chemical Solutions Figure 2 Gummy Bears Photo courtesy of Downhole Chemical Solutions The process of explosive perforating can create high near wellbore friction due to the perforation tunnel crushing that occurs during the perforation process. The acid spearhead is pumped to clean up this crushed zone and improve perforation tunnel performance. A new system of perforating was described by Albert (SPE 199274-MS 2019) that incorporated propellant and explosives perforating to eliminate the perforation tunnel crushed zone and reduce near wellbore friction. This paper will describe a Barnett Shale project that utilized this new composite perforating method to eliminate the use of acid.
{"title":"Better Perforations Help Solve the Gummy Bears Problem","authors":"L. Albert, Gavin McQueen, D. Weida, Clint Shaw","doi":"10.2118/211891-ms","DOIUrl":"https://doi.org/10.2118/211891-ms","url":null,"abstract":"\u0000 In wells with relatively high levels of iron, the use of polyacrylamide friction reducers (FR) used for hydraulic fracturing can result in poor performance due to negative chemical interactions. Hazra, et.al. (URTeC 2487 July 2020) documented a problem with the chemical reaction of FR and iron (ferrous and ferric) during hydraulic fracturing. This chemical reaction can create an accumulation of a semi-solid mass referred to as \"gummy bears\" due to their rubbery texture (figure 1). These gummy bears can form in surface and subsurface equipment and inhibit well production. In addition to the formation of gummy bears, the performance of FR is significantly impaired when reacting with iron (figure 2).\u0000 Pyrite (FeS2) is a common mineral found in source rock. Ferrous iron (Fe2+) can be released by oxidative dissolution of pyrite minerals. In reservoirs with high concentrations of pyrite, iron can be released by dissolving reservoir rock during acid spearheading. Acid spearheading is a common industry practice during hydraulic fracturing operations. The process involves pumping a small quantity of acid pre-frac to dissolve rock material around the wellbore, cleaning up perforations, and reducing near wellbore entry friction. The focus of the acid spearhead is to lower breakdown pressures and improve injectivity during hydraulic fracturing. The problem that Hazra (2020) described was on a Woodford Shale project in Oklahoma. The Woodford is known to contain significant quantities of pyrite (observed at around 2%). One solution proposed was to eliminate the use of acid during the hydraulic fracturing operation. The potential downside was higher near wellbore frictions that would need to be addressed by higher hydraulic horsepower (HHP) and FR volumes.\u0000 Figure 1 Effect of Fe2+ and Fe3+ on friction reduction properties of polyacrylamide friction reducer Figure courtesy of Downhole Chemical Solutions Figure 2 Gummy Bears Photo courtesy of Downhole Chemical Solutions\u0000 The process of explosive perforating can create high near wellbore friction due to the perforation tunnel crushing that occurs during the perforation process. The acid spearhead is pumped to clean up this crushed zone and improve perforation tunnel performance. A new system of perforating was described by Albert (SPE 199274-MS 2019) that incorporated propellant and explosives perforating to eliminate the perforation tunnel crushed zone and reduce near wellbore friction. This paper will describe a Barnett Shale project that utilized this new composite perforating method to eliminate the use of acid.","PeriodicalId":407915,"journal":{"name":"Day 2 Wed, October 19, 2022","volume":"38 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114229414","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In production of natural gas, often liquids (water and condensate) tend to collect in the production tubing of a typical gas well. Additionally, with horizontal wells stretching thousands of feet the liquids including flow back liquids get trapped in low laying sections and in the toe and heel of the tubing. When the gas flow velocity drops below critical velocity as result of drop in natural pressure, the liquids cannot escape the tubing and finally blocks the gas flow. In typical tight formations the wells natural pressure drops quickly, sometime in just months after start-up. As result the well will shut in or behave erratically with surging and slugging as result. Present methods using plungers, velocity strings, gas lift or ESP's are sometimes inefficient or need low back pressure to work which require blow down tanks, venting or flaring. Multiphase pumping has taken giant leaps since it was first introduced to the industry in the mid 1990s. The technology has received recognition in supporting oil and gas production from declining assets as well as being a tool to support and enhance the effectiveness of artificial lift systems of different types. Today more than thousand pumps are installed in onshore conventional as well as shale and tight formations, in steam assisted heavy oil production, topsides on platforms and subsea in deep water plays all over the world. From limited size pumps with a few hundred HP to large units with way over thousand HP, now some are in parallel operation to boost an entire oil field. Multiphase pumping has shown to provide great benefits to the operator as a tool for boosting and enhancing recovery from low-pressure reservoirs, minimizing topside facilities and comply with ESG considerations as well as significantly extending and accelerating oil and gas recovery. (Ref 4) Boosting with multiphase pumps is an efficient tool for continuous plateau production and for transporting the untreated or comingled well flow from the production pad to the process facility. The hydrocarbon production returns are essentially determined by the efficiency and capacity of the artificial lift system. When a surface installed multiphase pump is lowering the tubing and annulus gas pressure, it is possible to make the down-hole pumps, plungers or gas lift work under best possible conditions and thereby improving performance and reliability, which enhance production and the ultimate recovery from the formation.
{"title":"Liquid Unloading with Multiphase Pumping","authors":"Sven Olson","doi":"10.2118/211875-ms","DOIUrl":"https://doi.org/10.2118/211875-ms","url":null,"abstract":"\u0000 In production of natural gas, often liquids (water and condensate) tend to collect in the production tubing of a typical gas well. Additionally, with horizontal wells stretching thousands of feet the liquids including flow back liquids get trapped in low laying sections and in the toe and heel of the tubing. When the gas flow velocity drops below critical velocity as result of drop in natural pressure, the liquids cannot escape the tubing and finally blocks the gas flow. In typical tight formations the wells natural pressure drops quickly, sometime in just months after start-up. As result the well will shut in or behave erratically with surging and slugging as result. Present methods using plungers, velocity strings, gas lift or ESP's are sometimes inefficient or need low back pressure to work which require blow down tanks, venting or flaring.\u0000 Multiphase pumping has taken giant leaps since it was first introduced to the industry in the mid 1990s. The technology has received recognition in supporting oil and gas production from declining assets as well as being a tool to support and enhance the effectiveness of artificial lift systems of different types. Today more than thousand pumps are installed in onshore conventional as well as shale and tight formations, in steam assisted heavy oil production, topsides on platforms and subsea in deep water plays all over the world. From limited size pumps with a few hundred HP to large units with way over thousand HP, now some are in parallel operation to boost an entire oil field. Multiphase pumping has shown to provide great benefits to the operator as a tool for boosting and enhancing recovery from low-pressure reservoirs, minimizing topside facilities and comply with ESG considerations as well as significantly extending and accelerating oil and gas recovery. (Ref 4)\u0000 Boosting with multiphase pumps is an efficient tool for continuous plateau production and for transporting the untreated or comingled well flow from the production pad to the process facility. The hydrocarbon production returns are essentially determined by the efficiency and capacity of the artificial lift system. When a surface installed multiphase pump is lowering the tubing and annulus gas pressure, it is possible to make the down-hole pumps, plungers or gas lift work under best possible conditions and thereby improving performance and reliability, which enhance production and the ultimate recovery from the formation.","PeriodicalId":407915,"journal":{"name":"Day 2 Wed, October 19, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129295167","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}
Guoxiang Liu, Xiongjun Wu, V. Vasylkivska, C. Shih, G. Bromhal
The quick and accurate evaluation of reservoir behaviors and responses is essential to achieve successful field development and operations. An emerging technology for field development, physics informed advanced artificial intelligence/machine learning (AI/ML) benefits from both physics-based principles and AI/ML's learning capabilities. The capacitance and resistance model (CRM) method, based on the material balance principle, can provide rapid insights for optimal operations. Its flexible time-window selection and testing capability are especially useful for operation planning and development. Advanced AI/ML models developed for virtual learning environment (VLE) can be coupled to extend and enhance the capability for reservoir evolution evaluation. The objective of this study is to synergize the CRM with the VLE to provide a comprehensive toolset for field operations and reservoir management. The proposed approach has an organic integration of the CRM with the VLE; after completing a rapid reservoir study, the CRM first performs rapid forecasting of the well responses and inter-well connectivity for any given injection situation. The forecasted results from the CRM are then supplied as the inputs to the VLE, which utilizes its ML models to predict the corresponding three-dimensional distributions of key reservoir parameters such as detailed pressure transient and fluid movement for the entire field. This information, together with the field data streams, can be used for decision-making by providing a holistic view of the field operations and reservoir management regarding the injection and production enhancement in a real-time fashion. A simulated reservoir test case based on the SACROC CO2 flooding dataset from West Texas was used to demonstrate the concept and workflow. The test case has shown that the CRM can accurately capture the variations of the production rates and bottom-hole pressures with injection and production plan changes. The responses obtained from the CRM enable the VLE to correctly predict the three-dimensional distributions of the pressure and fluid saturation. The joint force from the CRM and the VLE enable them to capture the effects due to the injection and production changes in the field. Capable of tuning the injection plan, production design, and optimizing reservoir response, this integrated toolset can also assist field design with optimal well location selection/placement as extended benefits. As demonstrated with the preliminary results from above, a comprehensive and integrated toolset that couples the physics with the AI/ML can provide dynamic and real-time decision support for field operations and optimization for de-risked operation support, enhance oil recovery, and CO2 storage/monitoring design. Successful development of such a toolset makes it possible to integrate what-if scenarios and multiple-realizations to the workflow for static and dynamic uncertainty quantification. The toolset shows value and po
{"title":"Operations Coupled Virtual Learning for Reservoir Evaluation and Performance Analysis","authors":"Guoxiang Liu, Xiongjun Wu, V. Vasylkivska, C. Shih, G. Bromhal","doi":"10.2118/211883-ms","DOIUrl":"https://doi.org/10.2118/211883-ms","url":null,"abstract":"The quick and accurate evaluation of reservoir behaviors and responses is essential to achieve successful field development and operations. An emerging technology for field development, physics informed advanced artificial intelligence/machine learning (AI/ML) benefits from both physics-based principles and AI/ML's learning capabilities. The capacitance and resistance model (CRM) method, based on the material balance principle, can provide rapid insights for optimal operations. Its flexible time-window selection and testing capability are especially useful for operation planning and development. Advanced AI/ML models developed for virtual learning environment (VLE) can be coupled to extend and enhance the capability for reservoir evolution evaluation. The objective of this study is to synergize the CRM with the VLE to provide a comprehensive toolset for field operations and reservoir management.\u0000 The proposed approach has an organic integration of the CRM with the VLE; after completing a rapid reservoir study, the CRM first performs rapid forecasting of the well responses and inter-well connectivity for any given injection situation. The forecasted results from the CRM are then supplied as the inputs to the VLE, which utilizes its ML models to predict the corresponding three-dimensional distributions of key reservoir parameters such as detailed pressure transient and fluid movement for the entire field. This information, together with the field data streams, can be used for decision-making by providing a holistic view of the field operations and reservoir management regarding the injection and production enhancement in a real-time fashion.\u0000 A simulated reservoir test case based on the SACROC CO2 flooding dataset from West Texas was used to demonstrate the concept and workflow. The test case has shown that the CRM can accurately capture the variations of the production rates and bottom-hole pressures with injection and production plan changes. The responses obtained from the CRM enable the VLE to correctly predict the three-dimensional distributions of the pressure and fluid saturation. The joint force from the CRM and the VLE enable them to capture the effects due to the injection and production changes in the field. Capable of tuning the injection plan, production design, and optimizing reservoir response, this integrated toolset can also assist field design with optimal well location selection/placement as extended benefits.\u0000 As demonstrated with the preliminary results from above, a comprehensive and integrated toolset that couples the physics with the AI/ML can provide dynamic and real-time decision support for field operations and optimization for de-risked operation support, enhance oil recovery, and CO2 storage/monitoring design. Successful development of such a toolset makes it possible to integrate what-if scenarios and multiple-realizations to the workflow for static and dynamic uncertainty quantification. The toolset shows value and po","PeriodicalId":407915,"journal":{"name":"Day 2 Wed, October 19, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130446068","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In unconventional reservoirs, a novel polyacrylamide called high viscosity friction reducer was utilized throughout the previous decade to transport proppant. The product's advantages included freshwater use reduction, a more than 30 percent reduction in chemical use, and a decrease in the footprint of equipment such as trucks and tanks. Nonetheless, high TDS could limit the effectiveness of HVFR in providing better hydraulic fracturing treatments. This study investigates the impact of Utica's high TDS on HVFR using a flow loop test. The study investigates the consequences of the following four factors. The effect of TDS using DI water, 10% and 30% of the Utica-produced water concentration. Two pipe sizes (i.e., 1/2 and 3/4) are applied to determine the pipe's loop size. The effect of HVFR concentration on friction reduction utilizing three HVFR concentrations (i.e., 0.5, 1, and 2 gpt). The impact of temperature on HVFR and friction reduction using room temperature of 21°C and reservoir temperature of 65.5°C. The results demonstrate that HVFR provided a significant friction reduction utilizing DI water and at high TDS concentrations where friction reduction exceeds 67% using 10% or 30% of the Utica-produced water concentration. In addition, the result indicated that HVFR was strongly affected by a temperature of 65.5 °C (150 °F), where the friction reduction was around 40%, compared to a room temperature of 21 °C (70 °F), where the friction reduction is almost 70%. Furthermore, the outcomes showed that HVFR prepared with fresh water showed a significant friction reduction at low HVFR concentrations of 0.5 and 1 gpt, where the friction reduction was approximately 60 and 70%, respectively. Increasing the HVFR concentrations to 2 gpt did not improve the friction reduction compared to 1 gpt, where the friction reduction was around 66%. This work provides a comprehensive understanding of the effect of Utica Shale produced water, fluid concentration, and temperature on the performance of HVFR as fracture fluids by evaluating the friction reduction across a flow loop test.
{"title":"The Impact of High TDS of Utica Shale on High Viscosity Friction Reducer Performance: Experimental Study","authors":"Ghith Biheri, Khaled Elmaleh, Ashrf Amoura, Abdulmohsin Imqam","doi":"10.2118/211865-ms","DOIUrl":"https://doi.org/10.2118/211865-ms","url":null,"abstract":"\u0000 In unconventional reservoirs, a novel polyacrylamide called high viscosity friction reducer was utilized throughout the previous decade to transport proppant. The product's advantages included freshwater use reduction, a more than 30 percent reduction in chemical use, and a decrease in the footprint of equipment such as trucks and tanks. Nonetheless, high TDS could limit the effectiveness of HVFR in providing better hydraulic fracturing treatments. This study investigates the impact of Utica's high TDS on HVFR using a flow loop test.\u0000 The study investigates the consequences of the following four factors. The effect of TDS using DI water, 10% and 30% of the Utica-produced water concentration. Two pipe sizes (i.e., 1/2 and 3/4) are applied to determine the pipe's loop size. The effect of HVFR concentration on friction reduction utilizing three HVFR concentrations (i.e., 0.5, 1, and 2 gpt). The impact of temperature on HVFR and friction reduction using room temperature of 21°C and reservoir temperature of 65.5°C.\u0000 The results demonstrate that HVFR provided a significant friction reduction utilizing DI water and at high TDS concentrations where friction reduction exceeds 67% using 10% or 30% of the Utica-produced water concentration. In addition, the result indicated that HVFR was strongly affected by a temperature of 65.5 °C (150 °F), where the friction reduction was around 40%, compared to a room temperature of 21 °C (70 °F), where the friction reduction is almost 70%. Furthermore, the outcomes showed that HVFR prepared with fresh water showed a significant friction reduction at low HVFR concentrations of 0.5 and 1 gpt, where the friction reduction was approximately 60 and 70%, respectively. Increasing the HVFR concentrations to 2 gpt did not improve the friction reduction compared to 1 gpt, where the friction reduction was around 66%.\u0000 This work provides a comprehensive understanding of the effect of Utica Shale produced water, fluid concentration, and temperature on the performance of HVFR as fracture fluids by evaluating the friction reduction across a flow loop test.","PeriodicalId":407915,"journal":{"name":"Day 2 Wed, October 19, 2022","volume":"2011 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123778132","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}
Increased interest in correlating rheological properties to the prediction of proppant transport and/or friction reduction performance produces sporadic and isolated experimental evidence. Obtaining accurate results specifically for viscosity, proposedly representative of proppant transport and friction reduction, is challenging and therefore, extrapolating polymer melt rheology to dilute polymer solutions is problematic particularly when applying linear viscoelastic theory. This paper presents a simultaneous, multivariable research approach illustrating how viscoelastic results and hypotheses for anionic, cationic, and amphoteric friction reducers in various brines provide insight into the limitations of constricted variable and experimental range methodology. Establishing a relevant application window for viscoelastic friction reducers is complicated. Guar gum linear gels are viscous in nature and more approachable than synthetic friction reducers when manipulated for rheological experimentation and field application extrapolation. However, crosslinking of guar gum linear gels results in a viscoelastic fluid of greater complexity, thus even the simplest of linear gels must be subjected to a variety of unique bench tests differentiated by and specific to individual service companies’ field application requirements. Friction reducers’ crossover of storage and loss moduli are dependent upon how the reducers were dispersed and hydrated with respect to brine characters, times, and mixing energies. Furthermore, correlating rheological measurements developed for the melt state may not appropriately adapt to the friction reducer application's dilute polymer state. Response surfaces were generated for various anionic, cationic, and amphoteric friction reducers with testing variables including brine type, loading, mixing rpm, mixing duration, shear rate, linear shear strain, responses of viscosity, and moduli with corresponding cross over results. Excellent regression was obtained from these complex, interactive response surfaces, revealing the breadth of variability obtained from complex experimentation and validating that studies using simplistic procedures provide limited and potentially biased performance conclusions. When relating rheology to friction reduction and proppant transport, whether in the lab or the field, and understanding the complexities of polymer absolute dispersion, dissolution, and kinetics indicate that, with respect to performance prediction, limited knowledge is gained from simple polymer make down regimens. This work offers a guideline for assimilating comprehensive studies of complex versus oversimplified, limited scope rheological measurement research and analyses.
{"title":"A Critical Survey of the Rheological Properties Used to Predict Friction Reducer Performance","authors":"C. Aften, Yaser Asgari, Sharon E. Warren","doi":"10.2118/211874-ms","DOIUrl":"https://doi.org/10.2118/211874-ms","url":null,"abstract":"\u0000 Increased interest in correlating rheological properties to the prediction of proppant transport and/or friction reduction performance produces sporadic and isolated experimental evidence. Obtaining accurate results specifically for viscosity, proposedly representative of proppant transport and friction reduction, is challenging and therefore, extrapolating polymer melt rheology to dilute polymer solutions is problematic particularly when applying linear viscoelastic theory. This paper presents a simultaneous, multivariable research approach illustrating how viscoelastic results and hypotheses for anionic, cationic, and amphoteric friction reducers in various brines provide insight into the limitations of constricted variable and experimental range methodology.\u0000 Establishing a relevant application window for viscoelastic friction reducers is complicated. Guar gum linear gels are viscous in nature and more approachable than synthetic friction reducers when manipulated for rheological experimentation and field application extrapolation. However, crosslinking of guar gum linear gels results in a viscoelastic fluid of greater complexity, thus even the simplest of linear gels must be subjected to a variety of unique bench tests differentiated by and specific to individual service companies’ field application requirements. Friction reducers’ crossover of storage and loss moduli are dependent upon how the reducers were dispersed and hydrated with respect to brine characters, times, and mixing energies. Furthermore, correlating rheological measurements developed for the melt state may not appropriately adapt to the friction reducer application's dilute polymer state.\u0000 Response surfaces were generated for various anionic, cationic, and amphoteric friction reducers with testing variables including brine type, loading, mixing rpm, mixing duration, shear rate, linear shear strain, responses of viscosity, and moduli with corresponding cross over results. Excellent regression was obtained from these complex, interactive response surfaces, revealing the breadth of variability obtained from complex experimentation and validating that studies using simplistic procedures provide limited and potentially biased performance conclusions.\u0000 When relating rheology to friction reduction and proppant transport, whether in the lab or the field, and understanding the complexities of polymer absolute dispersion, dissolution, and kinetics indicate that, with respect to performance prediction, limited knowledge is gained from simple polymer make down regimens. This work offers a guideline for assimilating comprehensive studies of complex versus oversimplified, limited scope rheological measurement research and analyses.","PeriodicalId":407915,"journal":{"name":"Day 2 Wed, October 19, 2022","volume":"30 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125502353","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
J. Winegarden, T. Thomas, M. Solomon, D. Townsend, O. Algadi
The depth of the Utica formation poses many challenges during drilling operations. In Belmont, Jefferson, and Monroe counties of Ohio, lateral sections are often drilled with mud weights from 13.5 to 15.5 lb/gal. To support these mud weights, the various loss and flow zones encountered above the pay zone must be isolated by a deep intermediate casing. This paper describes the process of optimizing a cement slurry that is light enough to be circulated to surface in a single stage but also has additional properties to ensure that the potential corrosive formations are properly isolated and the casing has long-term protection from damage. The process compares the properties of four cement slurries in the 12-to-12.5lb/gal density range. Conventional tests were performed on each slurry (thickening time, free fluid, fluid loss, and compressive strength). Linear expansion tests determined whether the slurries would be capable of providing a long-term seal, against both formation and casing, to mitigate gas migration and annular pressure buildup. In addition, the team performed initial permeability tests for each slurry. Single-stage jobs were executed using three of the four newly formulated slurries, and this paper presents the success of those jobs as well.
{"title":"Optimization of Lead Cement Slurry for Use on Utica Deep Intermediate Casing Strings","authors":"J. Winegarden, T. Thomas, M. Solomon, D. Townsend, O. Algadi","doi":"10.2118/211878-ms","DOIUrl":"https://doi.org/10.2118/211878-ms","url":null,"abstract":"\u0000 The depth of the Utica formation poses many challenges during drilling operations. In Belmont, Jefferson, and Monroe counties of Ohio, lateral sections are often drilled with mud weights from 13.5 to 15.5 lb/gal. To support these mud weights, the various loss and flow zones encountered above the pay zone must be isolated by a deep intermediate casing. This paper describes the process of optimizing a cement slurry that is light enough to be circulated to surface in a single stage but also has additional properties to ensure that the potential corrosive formations are properly isolated and the casing has long-term protection from damage.\u0000 The process compares the properties of four cement slurries in the 12-to-12.5lb/gal density range. Conventional tests were performed on each slurry (thickening time, free fluid, fluid loss, and compressive strength). Linear expansion tests determined whether the slurries would be capable of providing a long-term seal, against both formation and casing, to mitigate gas migration and annular pressure buildup. In addition, the team performed initial permeability tests for each slurry. Single-stage jobs were executed using three of the four newly formulated slurries, and this paper presents the success of those jobs as well.","PeriodicalId":407915,"journal":{"name":"Day 2 Wed, October 19, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130302478","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}
Khalid Elwegaa, O. Kolawole, Saleh Ahmed, O. Tomomewo
Hydrocarbon recovery from conventional reservoirs is currently at a declining rate, thus, the petroleum industry needs to find ways to economically produce hydrocarbon from mature and marginal oilfields in conventional reservoirs. Non-conventional well technology can enable the oil industry to do so. This study investigated how a novel non-conventional well technology coupled with a geomechanical approach can potentially improve hydrocarbon recovery from mature fields. Here, we utilized data from Brown field XX located in North Africa, and it is composed of distinct geological formations. One of the formations, "Upper Gir," is an ideal candidate for the application of the non-conventional well technology. We used a reservoir simulator (SURE) to create a dynamic model by incorporating geomechanical tools from a static model previously built using Petrel software. SURE was used to model five simulation scenarios, with each scenario featuring a different well type. The scenarios simulated are the base case, do-nothing, vertical wells, horizontal wells, and multi-lateral wells. The model developed in this study forecasted 25 years of oil production for each simulation scenario and analyzed the results. The results of our numerical simulation study revealed that for 25 years, the multilateral wells produced +0.9% and +0.5% more hydrocarbon than the conventional wells and the horizontal wells, respectively. We also observed a reduction in the average water-cut from 25% to 20% (achieved in the conventional-well scenario) and from 23% to 20% (achieved in the horizontal-well scenario). Our proposed non-conventional well technology has shown promising potentials to improve hydrocarbon recovery, stabilize reservoir pressure, economic returns, and eliminate the risk of water conning in mature fields.
常规油藏的油气采收率目前呈下降趋势，因此，石油工业需要寻找从常规油藏的成熟和边缘油田中经济地开采油气的方法。非常规井技术可以使石油行业实现这一目标。该研究探讨了一种新的非常规井技术与地质力学方法相结合，如何潜在地提高成熟油田的油气采收率。在这里，我们利用了位于北非的Brown field XX的数据，它由不同的地质构造组成。其中一层“Upper Gir”是应用非常规井技术的理想选择。我们使用油藏模拟器(SURE)，结合地质力学工具，从之前使用Petrel软件建立的静态模型中创建动态模型。使用SURE对5种模拟场景进行建模，每种场景都有不同的井类型。模拟的场景包括基本情况、无操作、直井、水平井和多分支井。本研究开发的模型预测了每种模拟情景下25年的石油产量，并对结果进行了分析。数值模拟研究结果表明，在25年的时间里，分支井的油气产量分别比常规井和水平井高出0.9%和0.5%。我们还观察到，平均含水率从25%降低到20%(在常规井方案中实现)，从23%降低到20%(在水平井方案中实现)。我们提出的非常规井技术在提高油气采收率、稳定油藏压力、提高经济效益和消除成熟油田水窜风险方面显示出良好的潜力。
{"title":"A Non-Conventional Well Technology Approach to Improve Hydrocarbon Recovery from a Mature Field: Brown Field Case Study","authors":"Khalid Elwegaa, O. Kolawole, Saleh Ahmed, O. Tomomewo","doi":"10.2118/211881-ms","DOIUrl":"https://doi.org/10.2118/211881-ms","url":null,"abstract":"\u0000 Hydrocarbon recovery from conventional reservoirs is currently at a declining rate, thus, the petroleum industry needs to find ways to economically produce hydrocarbon from mature and marginal oilfields in conventional reservoirs. Non-conventional well technology can enable the oil industry to do so. This study investigated how a novel non-conventional well technology coupled with a geomechanical approach can potentially improve hydrocarbon recovery from mature fields. Here, we utilized data from Brown field XX located in North Africa, and it is composed of distinct geological formations. One of the formations, \"Upper Gir,\" is an ideal candidate for the application of the non-conventional well technology. We used a reservoir simulator (SURE) to create a dynamic model by incorporating geomechanical tools from a static model previously built using Petrel software. SURE was used to model five simulation scenarios, with each scenario featuring a different well type. The scenarios simulated are the base case, do-nothing, vertical wells, horizontal wells, and multi-lateral wells. The model developed in this study forecasted 25 years of oil production for each simulation scenario and analyzed the results. The results of our numerical simulation study revealed that for 25 years, the multilateral wells produced +0.9% and +0.5% more hydrocarbon than the conventional wells and the horizontal wells, respectively. We also observed a reduction in the average water-cut from 25% to 20% (achieved in the conventional-well scenario) and from 23% to 20% (achieved in the horizontal-well scenario). Our proposed non-conventional well technology has shown promising potentials to improve hydrocarbon recovery, stabilize reservoir pressure, economic returns, and eliminate the risk of water conning in mature fields.","PeriodicalId":407915,"journal":{"name":"Day 2 Wed, October 19, 2022","volume":"65 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124312961","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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