Yuewei Pan, Guoxin Li, Wei Ma, W. J. Lee, Yulong Yang
Over the past several decades, Arps decline curve analysis (DCA) has proved to be effective and efficient for production forecasts and EUR estimates due to its simplicity and applicability. However, as multi-stage hydraulically-fractured horizontal wells have unlocked the economic potential of unconventional reservoirs, forecasting future production accurately using Arps decline models becomes more challenging because of the complicated fluid flow mechanisms characterizing stimulated multi-layered ultra-low permeability porous media. Many field studies indicate unreliable forecasts and limitations in multi-layered field applications in particular. This paper presents a Mittag-Leffler (ML) function decline model which enhances the reliability of forecasts for multi-layered unconventional oil reservoirs by honoring anomalous diffusion physics for each layer. Many traditional decline curve models fail to honor the sub- or super-diffusion phenomenon under the paradigm of anomalous diffusion. The general form of our proposed two-factor ML function consolidates anomalous diffusion and classical diffusion into a single model, specifically including Arps hyperbolic, harmonic, exponential decline models and the stretched exponential decline model (SEPD) as special cases. Comparisons show that the ML model falls between the predictions of Arps and SEPD models in which the estimates are consistently either "overly optimistic" or "too conservative." For a multi-fractured horizontal well, the fracture height partially penetrating different layers leads to a layer-wise flow pattern which is reflected and captured in the production profile by curve-fitting the corresponding ML function parameters. We provide a workflow to guarantee consistency when applying the approach to each layer in field cases. We applied the workflow to one synthetic case using embedded discrete fracture modeling (EDFM) and to two field cases. We used hindcasting to demonstrate efficacy of the model by matching early-to-middle time production histories, forecasting future production, and comparing forecasted performance to hidden histories as well as to the corresponding EURs. The comparisons demonstrate the validity and reliability of the proposed ML function decline curve model for multi-layered unconventional oil reservoirs. Overall, this study shows that the novel ML-function DCA model is a robust alternative to forecast production and EUR in multi-layered unconventional oil reservoirs. The workflow presented was validated using one synthetic case and two actual field cases. This method further provides unique insight into multi-fractured horizontal well production profile characterization and facilitates well-spacing optimization, thereby improving reservoir development in layered unconventional reservoirs.
{"title":"A Novel Mittag-Leffler Function Decline Model for Production Forecasting in Multi-Layered Unconventional Oil Reservoirs","authors":"Yuewei Pan, Guoxin Li, Wei Ma, W. J. Lee, Yulong Yang","doi":"10.2118/210335-ms","DOIUrl":"https://doi.org/10.2118/210335-ms","url":null,"abstract":"\u0000 Over the past several decades, Arps decline curve analysis (DCA) has proved to be effective and efficient for production forecasts and EUR estimates due to its simplicity and applicability. However, as multi-stage hydraulically-fractured horizontal wells have unlocked the economic potential of unconventional reservoirs, forecasting future production accurately using Arps decline models becomes more challenging because of the complicated fluid flow mechanisms characterizing stimulated multi-layered ultra-low permeability porous media. Many field studies indicate unreliable forecasts and limitations in multi-layered field applications in particular. This paper presents a Mittag-Leffler (ML) function decline model which enhances the reliability of forecasts for multi-layered unconventional oil reservoirs by honoring anomalous diffusion physics for each layer.\u0000 Many traditional decline curve models fail to honor the sub- or super-diffusion phenomenon under the paradigm of anomalous diffusion. The general form of our proposed two-factor ML function consolidates anomalous diffusion and classical diffusion into a single model, specifically including Arps hyperbolic, harmonic, exponential decline models and the stretched exponential decline model (SEPD) as special cases. Comparisons show that the ML model falls between the predictions of Arps and SEPD models in which the estimates are consistently either \"overly optimistic\" or \"too conservative.\" For a multi-fractured horizontal well, the fracture height partially penetrating different layers leads to a layer-wise flow pattern which is reflected and captured in the production profile by curve-fitting the corresponding ML function parameters. We provide a workflow to guarantee consistency when applying the approach to each layer in field cases. We applied the workflow to one synthetic case using embedded discrete fracture modeling (EDFM) and to two field cases. We used hindcasting to demonstrate efficacy of the model by matching early-to-middle time production histories, forecasting future production, and comparing forecasted performance to hidden histories as well as to the corresponding EURs. The comparisons demonstrate the validity and reliability of the proposed ML function decline curve model for multi-layered unconventional oil reservoirs.\u0000 Overall, this study shows that the novel ML-function DCA model is a robust alternative to forecast production and EUR in multi-layered unconventional oil reservoirs. The workflow presented was validated using one synthetic case and two actual field cases. This method further provides unique insight into multi-fractured horizontal well production profile characterization and facilitates well-spacing optimization, thereby improving reservoir development in layered unconventional reservoirs.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"112 6","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132462660","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. Hincapie, Ante Borovina, T. Clemens, Markus Lüftenegger, E. Hoffmann, J. Wegner, Louis-Georgian Oprescu, Muhammad Tahir
Displacing viscous oil by water leads to poor displacement efficiency owing to the high mobility ratio and viscous fingering. Polymer injection increases oil recovery by reducing viscous fingering and improving sweep efficiency. We are showing how Alkali-Polymer (AP) flooding is substantially improving production of reactive viscous oil from a Romanian oil field. IFT measurements, coreflood and micro-model experiments were used to understand and optimize the physico-chemical processes leading to incremental oil recovery. Extensive IFT measurements were performed at different alkali and AP concentrations. In addition, phase behavior tests were done. Furthermore, micro-model experiments were used to elucidate effects at the pore-scale and as screening tool for which chemicals to use. Single and two-phase coreflood experiments helped defining the displacement efficiency on a core scale. Various sequences and concentrations of alkali and polymers were injected to reduce costs and maximize incremental recovery of the reactive viscous oil. IFT measurements showed that saponification (110 μmol/g saponifiable acids) at the oil-alkali solution interface is very effectively reducing the IFT. With time, the IFT is increasing owing to diffusion of the generated soaps away from the interface. Phase experiments confirmed that emulsions are formed initially. Micro-models revealed that injection of polymers or alkali only leads to limited incremental oil recovery over waterflooding. For alkali injection, oil is emulsified due to in-situ saponification at the edges of viscous fingers. AP injection after waterflooding is very effective. The emulsified oil at the edges of the viscous fingers is effectively dragged by the viscous fluid substantially increasing recovery. Corefloods confirmed the findings of the micromodels. In addition, the effect of di-valent cations for the selection of the polymer concentration was investigated. Water softening leads to significantly higher viscosity of the AP slug than non-softened brine. Reducing the polymer concentration to obtain the same viscosity as the polymer solution containing divalent cations resulted in similar displacement efficiency. Hence, significant cost savings can be realized for the field conditions, for which AP injection is planned after polymer injection. The results show that alkali solutions lead to initial low IFT of reactive viscous oil owing to soap generation at the oil-alkali solution interface increasing with time due to diffusion. Injecting alkali solutions into reactive viscous oil is not effective to reduce remaining oil saturation, a limited amount of oil is mobilized at the edges of viscous fingers. AP flooding of reactive viscous oil is substantially increasing incremental oil recovery. The reason is the effective dragging of the mobilized oil with the viscous fluid and associated exposure of additional oil to the alkali solutions. Furthermore, the economics of AP flooding projects can be
{"title":"Alkali Polymer Flooding of Viscous Reactive Oil","authors":"R. Hincapie, Ante Borovina, T. Clemens, Markus Lüftenegger, E. Hoffmann, J. Wegner, Louis-Georgian Oprescu, Muhammad Tahir","doi":"10.2118/210240-ms","DOIUrl":"https://doi.org/10.2118/210240-ms","url":null,"abstract":"\u0000 Displacing viscous oil by water leads to poor displacement efficiency owing to the high mobility ratio and viscous fingering. Polymer injection increases oil recovery by reducing viscous fingering and improving sweep efficiency. We are showing how Alkali-Polymer (AP) flooding is substantially improving production of reactive viscous oil from a Romanian oil field. IFT measurements, coreflood and micro-model experiments were used to understand and optimize the physico-chemical processes leading to incremental oil recovery.\u0000 Extensive IFT measurements were performed at different alkali and AP concentrations. In addition, phase behavior tests were done. Furthermore, micro-model experiments were used to elucidate effects at the pore-scale and as screening tool for which chemicals to use. Single and two-phase coreflood experiments helped defining the displacement efficiency on a core scale. Various sequences and concentrations of alkali and polymers were injected to reduce costs and maximize incremental recovery of the reactive viscous oil.\u0000 IFT measurements showed that saponification (110 μmol/g saponifiable acids) at the oil-alkali solution interface is very effectively reducing the IFT. With time, the IFT is increasing owing to diffusion of the generated soaps away from the interface. Phase experiments confirmed that emulsions are formed initially. Micro-models revealed that injection of polymers or alkali only leads to limited incremental oil recovery over waterflooding. For alkali injection, oil is emulsified due to in-situ saponification at the edges of viscous fingers. AP injection after waterflooding is very effective. The emulsified oil at the edges of the viscous fingers is effectively dragged by the viscous fluid substantially increasing recovery. Corefloods confirmed the findings of the micromodels. In addition, the effect of di-valent cations for the selection of the polymer concentration was investigated. Water softening leads to significantly higher viscosity of the AP slug than non-softened brine. Reducing the polymer concentration to obtain the same viscosity as the polymer solution containing divalent cations resulted in similar displacement efficiency. Hence, significant cost savings can be realized for the field conditions, for which AP injection is planned after polymer injection.\u0000 The results show that alkali solutions lead to initial low IFT of reactive viscous oil owing to soap generation at the oil-alkali solution interface increasing with time due to diffusion. Injecting alkali solutions into reactive viscous oil is not effective to reduce remaining oil saturation, a limited amount of oil is mobilized at the edges of viscous fingers. AP flooding of reactive viscous oil is substantially increasing incremental oil recovery. The reason is the effective dragging of the mobilized oil with the viscous fluid and associated exposure of additional oil to the alkali solutions. Furthermore, the economics of AP flooding projects can be ","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"48 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130239286","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. Poort, J. van der Waa, T. Mannucci, P. Shoeibi Omrani
Production optimization of oil, gas and geothermal wells suffering from unstable multiphase flow phenomena such as slugging is a challenging task due to their complexity and unpredictable dynamics. In this work, reinforcement learning which is a novel machine learning based control method was applied to find optimum well control strategies to maximize cumulative production while minimizing the negative impact of slugging on the system integrity, allowing for economical, safe, and reliable operation of wells and flowlines. Actor-critic reinforcement learning agents were trained to find the optimal settings for production valve opening and gas lift pressure in order to minimize slugging and maximize oil production. These agents were trained on a data-driven proxy models of two oil wells with different responses to the control actions. Use of such proxy models allowed for faster modelling of the environment while still accurately representing the system’s physical relations. In addition, to further increase the speed of optimization convergence, a policy transfer schem was developed in which a pre-trained agent on a different well was applied and finetuned on a new well. The reinforcement learning agents successfully managed to learn control strategies that improved oil production by up to 17% and reduced slugging effects by 6% when compared to baseline control settings. In addition, using policy transfer, agents converged up to 63% faster than when trained from a random initialization.
{"title":"An Optimum Well Control Using Reinforcement Learning and Policy Transfer; Application to Production Optimization and Slugging Minimization","authors":"J. Poort, J. van der Waa, T. Mannucci, P. Shoeibi Omrani","doi":"10.2118/210277-ms","DOIUrl":"https://doi.org/10.2118/210277-ms","url":null,"abstract":"\u0000 Production optimization of oil, gas and geothermal wells suffering from unstable multiphase flow phenomena such as slugging is a challenging task due to their complexity and unpredictable dynamics. In this work, reinforcement learning which is a novel machine learning based control method was applied to find optimum well control strategies to maximize cumulative production while minimizing the negative impact of slugging on the system integrity, allowing for economical, safe, and reliable operation of wells and flowlines. Actor-critic reinforcement learning agents were trained to find the optimal settings for production valve opening and gas lift pressure in order to minimize slugging and maximize oil production. These agents were trained on a data-driven proxy models of two oil wells with different responses to the control actions. Use of such proxy models allowed for faster modelling of the environment while still accurately representing the system’s physical relations. In addition, to further increase the speed of optimization convergence, a policy transfer schem was developed in which a pre-trained agent on a different well was applied and finetuned on a new well. The reinforcement learning agents successfully managed to learn control strategies that improved oil production by up to 17% and reduced slugging effects by 6% when compared to baseline control settings. In addition, using policy transfer, agents converged up to 63% faster than when trained from a random initialization.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"51 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125430813","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Batarseh, Saad Al Mutairi, Muhammad Alqahtani, Wiam Assiri, Damian SanRoman Alerigi, Scott Marshal
This paper presents the first field descaling deployment in the industry and a successful case study utilizing high power laser technology. The innovative technology was able to descale blocked flowlines without affecting the substrate integrity. The technology is safe, efficient, and cost-effective, providing a long-term solution, and extending the life span of the flowlines, casing, tubing, and others. High power laser technology has been tested and proven to effectively penetrate and remove materials in all types of rocks regardless of the strength and composition. This includes accumulations and deposits of iron sulfide, calcium carbonate, asphaltene, and others. The success of over two decades of intensive research has led to the development of the first high power laser field system. The design of the system is enclosed, providing safe and environmentally friendly operation; it consists of a laser energy-generator, nitrogen tank, vacuum truck and the tool. The function of the tool is to control the size and the shape of the beam that focuses on the targeted materials. The descaling process is done by utilizing the power of a laser to melt, spall or vaporize the materials. All the debris and materials removed are captured in a vacuum truck providing a clean operation. The technology was deployed in two flowline sections with different scale deposits. The first sample had an ankylosed scale covering the pipe's transversal area. The second sample combined scale with fresh hydrocarbons. The key parameters used for the deployment are volume of the scale removed, time, cost, and reusability of the pipe. The successful field deployment demonstrated that the technology could fully remove scale from the carbon steel flowlines without damaging the substrate. The removal rate reached as high as 18 inch per minute (IPM). The main factor affecting speed is the scale's thickness and vacuum efficiency. The analysis of the inner surface of the flowline showed the walls were clear of scale and maintained their original integrity. The descaled flowline could potentially be reused immediately after completing the process High power laser descaling technology is an innovative alternative to current descaling methods, which rely on chemical or mechanical means to remove the scale. The precise control of the beam allows targeting the scale without affecting the flowline's integrity. The technology is cost-effective, environmentally friendly, extends the lifespan of flowlines, dispenses with replacements, decreases downtime, reduces manpower, and eliminates waste. It is a key contributor to attaining net-zero and sustainable operations.
{"title":"First Industrial Flowlines Descaling Field Deployment Utilizing High Power Laser Technology","authors":"S. Batarseh, Saad Al Mutairi, Muhammad Alqahtani, Wiam Assiri, Damian SanRoman Alerigi, Scott Marshal","doi":"10.2118/209972-ms","DOIUrl":"https://doi.org/10.2118/209972-ms","url":null,"abstract":"\u0000 This paper presents the first field descaling deployment in the industry and a successful case study utilizing high power laser technology. The innovative technology was able to descale blocked flowlines without affecting the substrate integrity. The technology is safe, efficient, and cost-effective, providing a long-term solution, and extending the life span of the flowlines, casing, tubing, and others.\u0000 High power laser technology has been tested and proven to effectively penetrate and remove materials in all types of rocks regardless of the strength and composition. This includes accumulations and deposits of iron sulfide, calcium carbonate, asphaltene, and others. The success of over two decades of intensive research has led to the development of the first high power laser field system. The design of the system is enclosed, providing safe and environmentally friendly operation; it consists of a laser energy-generator, nitrogen tank, vacuum truck and the tool. The function of the tool is to control the size and the shape of the beam that focuses on the targeted materials. The descaling process is done by utilizing the power of a laser to melt, spall or vaporize the materials. All the debris and materials removed are captured in a vacuum truck providing a clean operation.\u0000 The technology was deployed in two flowline sections with different scale deposits. The first sample had an ankylosed scale covering the pipe's transversal area. The second sample combined scale with fresh hydrocarbons. The key parameters used for the deployment are volume of the scale removed, time, cost, and reusability of the pipe. The successful field deployment demonstrated that the technology could fully remove scale from the carbon steel flowlines without damaging the substrate. The removal rate reached as high as 18 inch per minute (IPM). The main factor affecting speed is the scale's thickness and vacuum efficiency. The analysis of the inner surface of the flowline showed the walls were clear of scale and maintained their original integrity. The descaled flowline could potentially be reused immediately after completing the process\u0000 High power laser descaling technology is an innovative alternative to current descaling methods, which rely on chemical or mechanical means to remove the scale. The precise control of the beam allows targeting the scale without affecting the flowline's integrity. The technology is cost-effective, environmentally friendly, extends the lifespan of flowlines, dispenses with replacements, decreases downtime, reduces manpower, and eliminates waste. It is a key contributor to attaining net-zero and sustainable operations.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"38 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133213826","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}
Xupeng He, Zhen Zhang, M. AlSinan, Yiteng Li, H. Kwak, H. Hoteit
Despite recent advancements in computational methods, it is still challenging to properly model fracture properties, such as relative permeability and hydraulic aperture, at the field scale. The challenge is in determining the most representative fracture properties, concluded from multi-scale data. In this study, we demonstrate how to capture fracture properties at the field scale from core-scale and pore-scale data through multi-scale uncertainty quantification, and assess how pore-scale processes can significantly impact the recovery factor. There are three components within our workflow: 1) performing high-resolution Navier-Stokes (NS) simulation at pore-scale to obtain hydraulic aperture of discrete single fractures, 2) embedding pore-scale parameters into core-scale for predicting field-scale objective, such as recovery factor, and 3) performing Monte Carlo simulations to determine the relationship effect of the pore-scale parameters to the field scale responding. At pore-scale, we start with four parameters that characterize the fractures: mean aperture, relative roughness, tortuosity, and the ratio of minimum to mean apertures. We then construct hydraulic aperture surrogates using an Artificial Neural Network (ANN). At the field scale, we deploy Long Short-Term Memory (LSTM) to capture the recovery factor at field-scale. The final results are the time-varying recovery factor and its sensitivity analysis. Monte Carlo simulation is performed on the final surrogate to produce the recovery factor value for various time-step. The result is beneficial for risk assessment and decision-making during the development of fractured reservoirs. Our method is the first to quantitatively estimate multi-scale parameters’ effect on recovery factors in two-phase flow in fractured media. This method also shows how we accommodate and deal with multi-scale parameters.
{"title":"Uncertainty and Sensitivity Analysis of Multi-Phase Flow in Fractured Rocks: A Pore-To-Field Scale Investigation","authors":"Xupeng He, Zhen Zhang, M. AlSinan, Yiteng Li, H. Kwak, H. Hoteit","doi":"10.2118/210131-ms","DOIUrl":"https://doi.org/10.2118/210131-ms","url":null,"abstract":"\u0000 Despite recent advancements in computational methods, it is still challenging to properly model fracture properties, such as relative permeability and hydraulic aperture, at the field scale. The challenge is in determining the most representative fracture properties, concluded from multi-scale data. In this study, we demonstrate how to capture fracture properties at the field scale from core-scale and pore-scale data through multi-scale uncertainty quantification, and assess how pore-scale processes can significantly impact the recovery factor. There are three components within our workflow: 1) performing high-resolution Navier-Stokes (NS) simulation at pore-scale to obtain hydraulic aperture of discrete single fractures, 2) embedding pore-scale parameters into core-scale for predicting field-scale objective, such as recovery factor, and 3) performing Monte Carlo simulations to determine the relationship effect of the pore-scale parameters to the field scale responding. At pore-scale, we start with four parameters that characterize the fractures: mean aperture, relative roughness, tortuosity, and the ratio of minimum to mean apertures. We then construct hydraulic aperture surrogates using an Artificial Neural Network (ANN). At the field scale, we deploy Long Short-Term Memory (LSTM) to capture the recovery factor at field-scale. The final results are the time-varying recovery factor and its sensitivity analysis. Monte Carlo simulation is performed on the final surrogate to produce the recovery factor value for various time-step. The result is beneficial for risk assessment and decision-making during the development of fractured reservoirs. Our method is the first to quantitatively estimate multi-scale parameters’ effect on recovery factors in two-phase flow in fractured media. This method also shows how we accommodate and deal with multi-scale parameters.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133265872","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}
Natural gas can be used to generate either blue or grey hydrogen depending on whether or not the carbon dioxide byproduct is captured and stored. When captured, the carbon dioxide (CO2) produced from a steam methane reforming (SMR) or partial oxidation (POX) process can be injected into the same natural gas reservoir for enhanced gas recovery (EGR) while simultaneously storing CO2. The objective of this work is the effective integration of these three major processes – blue hydrogen generation, carbon dioxide capture and storage, and enhanced natural gas production. Surface processes include separation of methane from CO2 and other inorganic and organic components in the produced natural gas. Produced CO2 will be injected back into the reservoir, and other components would be managed in ways standard to produced natural gas processing. An SMR or POX process followed by a shift reaction one will generate hydrogen and CO2 followed by separation of the hydrogen and CO2. To avoid a need for post combustion capture, continuous operation can use produced hydrogen to energize the SMR process. Integration of natural gas reservoir production, blue hydrogen generation, and CO2 injection back into the same reservoir leads to a process termed enhanced gas recovery and blue hydrogen (EGRBH). To optimize the reservoir management, analytical and numerical simulation models that address physical mechanisms such as CO2 diffusion, advection, and CO2 solubility in connate water provide guidelines on placement of injection and production wells, on their geometry (vertical or horizontal) and completion interval locations, and on well operating conditions. Displacing methane with CO2 is a miscible process with favorable mobility ratio, and simulations show that the methane recovery factor at CO2 breakthrough depends on both molecular diffusion and dispersivity related to reservoir heterogeneity. Continued production at constant methane rate enables additional blue hydrogen generation while increasing CO2 flow through the reservoir under declining average reservoir pressure. Injection of additional CO2 captured from other stationary point sources can achieve enhanced CO2 storage (ECS) up to a limit pressure less than the original reservoir pressure. The EGRBH process produces blue hydrogen at a price competitive with gasoline or diesel for transportation applications. When used for power generation, blue hydrogen decarbonizes natural gas fired generation at lower cost than can be achieved with post combustion capture from standard natural gas power plants. Blue hydrogen is also less than half the cost of so-called green hydrogen produced via electrolysis using electricity generated with renewable energy. This appears to be an ideal approach for developing and producing new natural gas discoveries.
{"title":"Coupled Enhanced Natural Gas Recovery and Blue Hydrogen (EGRBH) Generation","authors":"D. Hatzignatiou, C. Ehlig-Economides","doi":"10.2118/210356-ms","DOIUrl":"https://doi.org/10.2118/210356-ms","url":null,"abstract":"\u0000 Natural gas can be used to generate either blue or grey hydrogen depending on whether or not the carbon dioxide byproduct is captured and stored. When captured, the carbon dioxide (CO2) produced from a steam methane reforming (SMR) or partial oxidation (POX) process can be injected into the same natural gas reservoir for enhanced gas recovery (EGR) while simultaneously storing CO2. The objective of this work is the effective integration of these three major processes – blue hydrogen generation, carbon dioxide capture and storage, and enhanced natural gas production.\u0000 Surface processes include separation of methane from CO2 and other inorganic and organic components in the produced natural gas. Produced CO2 will be injected back into the reservoir, and other components would be managed in ways standard to produced natural gas processing. An SMR or POX process followed by a shift reaction one will generate hydrogen and CO2 followed by separation of the hydrogen and CO2. To avoid a need for post combustion capture, continuous operation can use produced hydrogen to energize the SMR process. Integration of natural gas reservoir production, blue hydrogen generation, and CO2 injection back into the same reservoir leads to a process termed enhanced gas recovery and blue hydrogen (EGRBH). To optimize the reservoir management, analytical and numerical simulation models that address physical mechanisms such as CO2 diffusion, advection, and CO2 solubility in connate water provide guidelines on placement of injection and production wells, on their geometry (vertical or horizontal) and completion interval locations, and on well operating conditions.\u0000 Displacing methane with CO2 is a miscible process with favorable mobility ratio, and simulations show that the methane recovery factor at CO2 breakthrough depends on both molecular diffusion and dispersivity related to reservoir heterogeneity. Continued production at constant methane rate enables additional blue hydrogen generation while increasing CO2 flow through the reservoir under declining average reservoir pressure. Injection of additional CO2 captured from other stationary point sources can achieve enhanced CO2 storage (ECS) up to a limit pressure less than the original reservoir pressure.\u0000 The EGRBH process produces blue hydrogen at a price competitive with gasoline or diesel for transportation applications. When used for power generation, blue hydrogen decarbonizes natural gas fired generation at lower cost than can be achieved with post combustion capture from standard natural gas power plants. Blue hydrogen is also less than half the cost of so-called green hydrogen produced via electrolysis using electricity generated with renewable energy. This appears to be an ideal approach for developing and producing new natural gas discoveries.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131767295","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 primary role of offshore solids handling is to properly remove and dispose of produced solids, without interruption or shutdown. Most sand management papers focus on the separation component only (i.e., wellhead desander, jetting system, or produced water desander). However, 80% of the capital expenditure (CAPEX) is attributed to separating devices, and 80% of the operating expenditure (OPEX) in sand handling operations involves dewatering, transport, and disposal (D-T-D). The present work outlines questions to ask during facility design and provides guidelines, calculations, and examples on each of the sand handling steps to be implemented after separation. Sand handling is not a waste-stream treatment exercise but a critical flow assurance issue. Following all five steps of Facilities Sand Management (FSM) will maximize hydrocarbon production and minimize the operating costs.
{"title":"What to do with Produced Solids After Separation: Dewatering, Transport, and Disposal","authors":"C. Rawlins","doi":"10.2118/210003-ms","DOIUrl":"https://doi.org/10.2118/210003-ms","url":null,"abstract":"\u0000 The primary role of offshore solids handling is to properly remove and dispose of produced solids, without interruption or shutdown. Most sand management papers focus on the separation component only (i.e., wellhead desander, jetting system, or produced water desander). However, 80% of the capital expenditure (CAPEX) is attributed to separating devices, and 80% of the operating expenditure (OPEX) in sand handling operations involves dewatering, transport, and disposal (D-T-D). The present work outlines questions to ask during facility design and provides guidelines, calculations, and examples on each of the sand handling steps to be implemented after separation. Sand handling is not a waste-stream treatment exercise but a critical flow assurance issue. Following all five steps of Facilities Sand Management (FSM) will maximize hydrocarbon production and minimize the operating costs.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"56 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134477305","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 high-temperature sandstone reservoirs especially at temperatures above 450°F, the rapid reaction of the acid treatment fluid and the secondary/tertiary reactions with the clays lead to formation damage. Moreover, at these high temperatures, the HCl/HF based acid systems are extremely corrosive to the wellbore tubers and downhole equipment's. This paper presents the next generation acid system that utilizes non-corrosive fluids to generate HF acid for high temperature sandstone stimulation. The non-corrosive deep-penetrating acid is a neutral, non-reactive treatment fluid at the surface and only when it is injected in the formation, it generates HF at a controlled rate in situ under temperature and time. The in-situ generated HF at a controlled rate allows for deep penetration of the acid in the formation. A series of solubility testing in HPHT reactor was first conducted to understand the chemical reactions that generate the acid as a function of temperature, concentration of acid generating components, and time, and to identify the optimum composition that maximize the dissolving of quartz and minimize the potential precipitation from reaction with clay minerals. Coreflow testing was then conducted at 475°F using 1.5″ in diameter and 6″ in length Berea sandstone cores to evaluate the performance of the new acid system for sandstone stimulation. Solubility testing showed that the new acid system has high dissolving power for calcite and silica and potential to minimize precipitations when reacted with clays. In Coreflow testing, the non-corrosive deep penetrating acid is effective to stimulate sandstone and provides remarkable permeability improvement by at least 60% at 475°F. Because of the in-situ controlled generation of HF, it penetrates deeper in the formation and minimizes the potential for precipitations. The non-corrosive deep-penetrating fluid system provides the industry with an effective solution to deeply stimulate sandstone reservoirs unlocking the full potential especially at temperatures above 450°F, and a safe non-corrosive fluid for wellbore tubulars and equipment. Moreover, the new fluid technology would eliminate the need for acid tanks on site, reduce transportation difficulties, and eliminates HSE concerns and acid exposure to personnel in the field.
{"title":"Next Generation Acid System — Deep-Penetrating Non-Corrosive Fluid for High Temperature Sandstone Stimulation","authors":"Ahmed S. Zakaria, H. Hudson","doi":"10.2118/210381-ms","DOIUrl":"https://doi.org/10.2118/210381-ms","url":null,"abstract":"\u0000 In high-temperature sandstone reservoirs especially at temperatures above 450°F, the rapid reaction of the acid treatment fluid and the secondary/tertiary reactions with the clays lead to formation damage. Moreover, at these high temperatures, the HCl/HF based acid systems are extremely corrosive to the wellbore tubers and downhole equipment's. This paper presents the next generation acid system that utilizes non-corrosive fluids to generate HF acid for high temperature sandstone stimulation.\u0000 The non-corrosive deep-penetrating acid is a neutral, non-reactive treatment fluid at the surface and only when it is injected in the formation, it generates HF at a controlled rate in situ under temperature and time. The in-situ generated HF at a controlled rate allows for deep penetration of the acid in the formation. A series of solubility testing in HPHT reactor was first conducted to understand the chemical reactions that generate the acid as a function of temperature, concentration of acid generating components, and time, and to identify the optimum composition that maximize the dissolving of quartz and minimize the potential precipitation from reaction with clay minerals. Coreflow testing was then conducted at 475°F using 1.5″ in diameter and 6″ in length Berea sandstone cores to evaluate the performance of the new acid system for sandstone stimulation.\u0000 Solubility testing showed that the new acid system has high dissolving power for calcite and silica and potential to minimize precipitations when reacted with clays. In Coreflow testing, the non-corrosive deep penetrating acid is effective to stimulate sandstone and provides remarkable permeability improvement by at least 60% at 475°F. Because of the in-situ controlled generation of HF, it penetrates deeper in the formation and minimizes the potential for precipitations.\u0000 The non-corrosive deep-penetrating fluid system provides the industry with an effective solution to deeply stimulate sandstone reservoirs unlocking the full potential especially at temperatures above 450°F, and a safe non-corrosive fluid for wellbore tubulars and equipment. Moreover, the new fluid technology would eliminate the need for acid tanks on site, reduce transportation difficulties, and eliminates HSE concerns and acid exposure to personnel in the field.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"109 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130317117","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
C. Keith, Xindan Wang, Yin Zhang, A. Dandekar, S. Ning
Since August 2018, a polymer flooding field pilot has been underway in an unconsolidated heavy oil reservoir on the Alaska North Slope (ANS). Previously, a reservoir simulation model was constructed and calibrated to predict the oil recovery of the field test; it demonstrated that polymer flooding is technically feasible to significantly improve oil recovery from heavy oil reservoirs on the Alaska North Slope. However, the economic performance of the pilot, critical to determining its success, has not been investigated, which is another key metric used in assessing the overall performance of the field pilot. Therefore, this study focuses on evaluating the project's economic performance by integrating the calibrated simulation model with an economic model. The investigation results demonstrate that the project value remains profitable for all polymer flood scenarios at conservative economic parameters. Thus, the use of polymer flooding over waterflooding is attractive. However, the predicted value changes meaningfully between the scenarios, emphasizing that a simulation model should be taken as a "living forecast". Subsequently, an economic sensitivity analysis is conducted to provide recommendations for continued operation of the ongoing field pilot and future polymer flood designs. The results indicate that a higher polymer concentration can be injected due to the development of fractures in the pilot reservoir. The throughput rate should remain high without exceeding operating constraints. A calculated point-forward polymer utilization parameter indicates a decreasing efficiency of the polymer flood at later times in the pattern life. Future projects will benefit from starting polymer injection earlier in the pattern life. A pattern with tighter horizontal well spacing will observe a greater incremental benefit from polymer flooding. This case study provides important insight for the broader discussion of polymer flood design from the economic perspective. It illustrates how expectations for performance may change as additional data is collected. It also formalizes the concept of "point-forward utilization" to evaluate the incremental efficiency of additional chemical injection.
{"title":"Economic Evaluation of Polymer Flood Field Test in Heavy Oil Reservoir on Alaska North Slope","authors":"C. Keith, Xindan Wang, Yin Zhang, A. Dandekar, S. Ning","doi":"10.2118/210000-ms","DOIUrl":"https://doi.org/10.2118/210000-ms","url":null,"abstract":"\u0000 Since August 2018, a polymer flooding field pilot has been underway in an unconsolidated heavy oil reservoir on the Alaska North Slope (ANS). Previously, a reservoir simulation model was constructed and calibrated to predict the oil recovery of the field test; it demonstrated that polymer flooding is technically feasible to significantly improve oil recovery from heavy oil reservoirs on the Alaska North Slope. However, the economic performance of the pilot, critical to determining its success, has not been investigated, which is another key metric used in assessing the overall performance of the field pilot. Therefore, this study focuses on evaluating the project's economic performance by integrating the calibrated simulation model with an economic model. The investigation results demonstrate that the project value remains profitable for all polymer flood scenarios at conservative economic parameters. Thus, the use of polymer flooding over waterflooding is attractive. However, the predicted value changes meaningfully between the scenarios, emphasizing that a simulation model should be taken as a \"living forecast\". Subsequently, an economic sensitivity analysis is conducted to provide recommendations for continued operation of the ongoing field pilot and future polymer flood designs. The results indicate that a higher polymer concentration can be injected due to the development of fractures in the pilot reservoir. The throughput rate should remain high without exceeding operating constraints. A calculated point-forward polymer utilization parameter indicates a decreasing efficiency of the polymer flood at later times in the pattern life. Future projects will benefit from starting polymer injection earlier in the pattern life. A pattern with tighter horizontal well spacing will observe a greater incremental benefit from polymer flooding. This case study provides important insight for the broader discussion of polymer flood design from the economic perspective. It illustrates how expectations for performance may change as additional data is collected. It also formalizes the concept of \"point-forward utilization\" to evaluate the incremental efficiency of additional chemical injection.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"16 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114394367","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}
Mohamed Adel Gabry, I. Eltaleb, M. Soliman, S. Farouq Ali
The Diagnostic Fracture Injection Test (DFIT) is widely used to get the fracture closure pressure, reservoir permeability, and reservoir pressure. Conventional methods for analyzing DFIT are based on the assumption of a vertical well but fail for horizontal wells drilled in ultra-low permeability reservoirs with potential multiple closures. There is still a significant debate about the rigorousness and validity of these techniques due to the complexity of the hydraulic fracture opening and closure process and assumptions of conventional fracture detection methods. In this study, a new signal processing approach was proposed by M.Y. Soliman, U. Ebru, F. Siddiqi, A.Rezaei, and I. Eltaleb (2019) and (2020) was extended to use the continuous wavelet transform to identify the closure time and pressure. The new method was applied to synthetic and actual field data. The synthetic data were produced using commercial fracture simulators based on fracture propagation and closure simulation principles with predefined fracture closure. To determine this closure instant, we decompose the pressure fall-off signal as the output of the fracture system into multiple levels with different frequencies using the continuous wavelet transform. This "short wavy" function is stretched or compressed and placed at many positions along the signal to be analyzed. The wavelet is then multiplied term-by-term by the signal, and each product yields a wavelet coefficient value. The signal energy is observed during the fracture closure process (pressure fall-off) and the fracture closure event is identified when the signal energy stabilizes to a minimum level. Because of the uncertainty of the real field fracture closure, a predefined simple synthetic fracture simulation with known fracture closure was used to validate the new methodology. The new continuous wavelet transform technique showed clear success without any prior assumptions or the need for additional reservoir data. The new methodology is also extended to actual field cases and showed the same success as conventional classical methods.
诊断性裂缝注入试验(DFIT)被广泛用于测量裂缝闭合压力、储层渗透率和储层压力。传统的DFIT分析方法是基于直井的假设，但不适用于可能多次闭井的超低渗透油藏中的水平井。由于水力裂缝开启和关闭过程的复杂性以及传统裂缝检测方法的假设，这些技术的严谨性和有效性仍然存在很大的争议。在本研究中，M.Y. Soliman, U. Ebru, F. Siddiqi, a . rezaei和I. Eltaleb(2019)提出了一种新的信号处理方法，并扩展了(2020)使用连续小波变换来识别关闭时间和压力。将新方法应用于综合资料和实际现场资料。基于裂缝扩展和闭合模拟原理，使用商用裂缝模拟器生成合成数据，并预置裂缝闭合。为了确定该闭合时刻，我们利用连续小波变换将作为裂缝系统输出的压力下降信号分解成不同频率的多级信号。这个“短波”函数被拉伸或压缩，并放置在待分析信号的许多位置。然后将小波逐项与信号相乘，每个乘积产生一个小波系数值。在裂缝闭合过程(压力下降)中观察信号能量，当信号能量稳定到最低水平时识别裂缝闭合事件。由于实际现场裂缝闭合的不确定性，采用预先定义的、已知裂缝闭合的简单合成裂缝模拟来验证新方法。新的连续小波变换技术在没有任何预先假设或需要额外油藏数据的情况下取得了明显的成功。新方法也被推广到实际的现场案例中，并取得了与传统经典方法相同的成功。
{"title":"Novel Method to Detect Fracture Closure Event Using Continuous Wavelet Transform","authors":"Mohamed Adel Gabry, I. Eltaleb, M. Soliman, S. Farouq Ali","doi":"10.2118/210267-ms","DOIUrl":"https://doi.org/10.2118/210267-ms","url":null,"abstract":"\u0000 The Diagnostic Fracture Injection Test (DFIT) is widely used to get the fracture closure pressure, reservoir permeability, and reservoir pressure. Conventional methods for analyzing DFIT are based on the assumption of a vertical well but fail for horizontal wells drilled in ultra-low permeability reservoirs with potential multiple closures. There is still a significant debate about the rigorousness and validity of these techniques due to the complexity of the hydraulic fracture opening and closure process and assumptions of conventional fracture detection methods.\u0000 In this study, a new signal processing approach was proposed by M.Y. Soliman, U. Ebru, F. Siddiqi, A.Rezaei, and I. Eltaleb (2019) and (2020) was extended to use the continuous wavelet transform to identify the closure time and pressure. The new method was applied to synthetic and actual field data. The synthetic data were produced using commercial fracture simulators based on fracture propagation and closure simulation principles with predefined fracture closure. To determine this closure instant, we decompose the pressure fall-off signal as the output of the fracture system into multiple levels with different frequencies using the continuous wavelet transform. This \"short wavy\" function is stretched or compressed and placed at many positions along the signal to be analyzed. The wavelet is then multiplied term-by-term by the signal, and each product yields a wavelet coefficient value. The signal energy is observed during the fracture closure process (pressure fall-off) and the fracture closure event is identified when the signal energy stabilizes to a minimum level.\u0000 Because of the uncertainty of the real field fracture closure, a predefined simple synthetic fracture simulation with known fracture closure was used to validate the new methodology. The new continuous wavelet transform technique showed clear success without any prior assumptions or the need for additional reservoir data. The new methodology is also extended to actual field cases and showed the same success as conventional classical methods.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"4 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114458128","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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