Polymer transport and retention affect oil recovery and economic feasibility of EOR processes. Most studies on polymer transport have focused on sandstones with permeabilities (k) higher than 200 mD. A limited number of studies were conducted in carbonates with k less than 100 mD and very few in the presence of residual oil. In this work, transport of four polymers with different molecular weights (MW) and functional groups are studied in Edwards Yellow outcrop cores (k<50 mD) with and without residual oil saturation (Sor). The retention of polymers was estimated by both the material balance method and the double-bank method. The polymer concentration was measured by both the total organic carbon (TOC) analyzer and the capillary tube rheology. Partially hydrolyzed acrylamide (HPAM) polymers exhibited high retention (> 150 μg/g), inaccessible pore volume (IPV) greater than 7%, and high residual resistance factor (>9). A sulfonated polyacrylamide (AN132), showed low retentions (< 20 μg/g) and low IPV. The residual resistance factor (RRF) of AN132 in the water-saturated rock was less than 2, indicating little blocking of pore throats in these tight rocks. The retention and RRF of the AN132 polymer increased in the presence of residual oil saturation due to partial blocking of the smaller pore throats available for polymer propagation in an oil-wet core.
{"title":"Transport of Polymers in Low Permeability Carbonate Rocks","authors":"Haofeng Song, P. Ghosh, K. Mohanty","doi":"10.2118/206024-ms","DOIUrl":"https://doi.org/10.2118/206024-ms","url":null,"abstract":"\u0000 Polymer transport and retention affect oil recovery and economic feasibility of EOR processes. Most studies on polymer transport have focused on sandstones with permeabilities (k) higher than 200 mD. A limited number of studies were conducted in carbonates with k less than 100 mD and very few in the presence of residual oil. In this work, transport of four polymers with different molecular weights (MW) and functional groups are studied in Edwards Yellow outcrop cores (k<50 mD) with and without residual oil saturation (Sor). The retention of polymers was estimated by both the material balance method and the double-bank method. The polymer concentration was measured by both the total organic carbon (TOC) analyzer and the capillary tube rheology. Partially hydrolyzed acrylamide (HPAM) polymers exhibited high retention (> 150 μg/g), inaccessible pore volume (IPV) greater than 7%, and high residual resistance factor (>9). A sulfonated polyacrylamide (AN132), showed low retentions (< 20 μg/g) and low IPV. The residual resistance factor (RRF) of AN132 in the water-saturated rock was less than 2, indicating little blocking of pore throats in these tight rocks. The retention and RRF of the AN132 polymer increased in the presence of residual oil saturation due to partial blocking of the smaller pore throats available for polymer propagation in an oil-wet core.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"84 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78934018","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}
Do we analyze on why can even the most reliable turbomachinery are getting failure and stopped? In some cases, it's all about bad installation or design literally. This paper explores the challenges one site had with repeated failure of lube oil fin fan coolers coupling which caused the unit availability of more than 3 months. It outlines the troubleshooting attempts made to remedy this issue, its root cause, and the resulting solution. This issue occurred at a site with a train configuration of motor driven centrifugal compressors. The plant lube oil system has been configured with 3 trains. Each train has been configured with Main electric motor + Vorecon Gearbox + Low Pressure centrifugal compressor + High Pressure centrifugal compressor. Lube oil system of the train has been configured as 2 lube oil coolers and 2 working oil coolers. Lube oil coolers are having fins with air cooler type. Air is supplied by fin fans and each train has 2 lube oil cooler fans and 2 working oil cooler fans. In total site has 3 trains x 4 fin fans so it has 12 fin fan cooler fans. All cooler fans are driven by electric motor which is coupled with gearbox and gear box is connected with cooler fan. During normal operation of working oil cooler fan A- stopped rotation suddenly from normal operation. During investigation, motor shaft was found running freely. No movement was seen on cooler fan. Coupling between motor to gearbox was inspected. Coupling is shear plate coupling. Its spacer flexible element were found broken into several pieces. Further investigation revealed that motor coupling hub was moving free axially back and forth due to clearance between motor shaft to coupling hub internal diameter. Motor side Coupling hub bolt hole was found with loss of material and ovality in shape. Hub locking Allen screw was found in damaged condition. Missing materials were noted and broken shear plate materials were found around coupling guard area. While site team was conducting the investigation on the unit A, similar incident occurred in next unit and other 3 units with 2 days difference between them. During detailed investigation it has been noted that all motor to gear box coupling are shear plates and shear plates were broken. Coupling hub was found loose and coupling hub locking screw was found broken or partial damage.
{"title":"Case Study: Consecutive Failure of Lube Oil Cooler Fans Coupling","authors":"A. Manikandan, Zeeshan Anwar","doi":"10.2118/206120-ms","DOIUrl":"https://doi.org/10.2118/206120-ms","url":null,"abstract":"\u0000 Do we analyze on why can even the most reliable turbomachinery are getting failure and stopped? In some cases, it's all about bad installation or design literally. This paper explores the challenges one site had with repeated failure of lube oil fin fan coolers coupling which caused the unit availability of more than 3 months. It outlines the troubleshooting attempts made to remedy this issue, its root cause, and the resulting solution.\u0000 This issue occurred at a site with a train configuration of motor driven centrifugal compressors. The plant lube oil system has been configured with 3 trains. Each train has been configured with Main electric motor + Vorecon Gearbox + Low Pressure centrifugal compressor + High Pressure centrifugal compressor. Lube oil system of the train has been configured as 2 lube oil coolers and 2 working oil coolers. Lube oil coolers are having fins with air cooler type. Air is supplied by fin fans and each train has 2 lube oil cooler fans and 2 working oil cooler fans. In total site has 3 trains x 4 fin fans so it has 12 fin fan cooler fans. All cooler fans are driven by electric motor which is coupled with gearbox and gear box is connected with cooler fan.\u0000 During normal operation of working oil cooler fan A- stopped rotation suddenly from normal operation. During investigation, motor shaft was found running freely. No movement was seen on cooler fan. Coupling between motor to gearbox was inspected. Coupling is shear plate coupling. Its spacer flexible element were found broken into several pieces. Further investigation revealed that motor coupling hub was moving free axially back and forth due to clearance between motor shaft to coupling hub internal diameter. Motor side Coupling hub bolt hole was found with loss of material and ovality in shape. Hub locking Allen screw was found in damaged condition. Missing materials were noted and broken shear plate materials were found around coupling guard area.\u0000 While site team was conducting the investigation on the unit A, similar incident occurred in next unit and other 3 units with 2 days difference between them.\u0000 During detailed investigation it has been noted that all motor to gear box coupling are shear plates and shear plates were broken. Coupling hub was found loose and coupling hub locking screw was found broken or partial damage.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72675385","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A previous study by the authors on synthetic fractal-fracture networks showed that lacunarity, a parameter that quantifies scale-dependent clustering in patterns, can be used as a proxy for connectivity and also, is an indicator of fluid flow in such model networks. In this research, we apply the concepts thus developed to the study of fractured reservoir analogs and seek solutions to more practical problems faced by modelers in the oil and gas industry. A set of seven nested fracture networks from the Devonian Sandstone of Hornelen Basin, Norway that have the same fractal-dimension but are mapped at different scales and resolutions is considered. We compare these seven natural fracture maps in terms of their lacunarity and connectivity values to test whether the former is a reasonable indicator of the latter. Additionally, these maps are also flow simulated by implementing a fracture continuum model and using a streamline simulator, TRACE3D. The values of lacunarity, connectivity and fluid recovery thus obtained are pairwise correlated with one another to look for possible relationships. The results indicate that while fracture maps that have the same fractal dimension show almost similar connectivity values, there exist subtle differences such that both the connectivity and clustering values change systematically with the scale at which the fracture networks are mapped. It is further noted that there appears to be a very good correlation between clustering, connectivity, and fluid recovery values for these fracture networks that belong to the same fractal system. The overall results indicate that while the fractal dimension is an important parameter for characterizing a specific type of fracture network geometry, it is the lacunarity or scale-dependent clustering attribute that controls connectivity in fracture maps and hence the flow properties. This research may prove helpful in quickly evaluating connectivity of fracture networks based on the lacunarity parameter. This parameter can therefore, be used for calibrating Discrete Fracture Network (DFN) models with respect to connectivity of reservoir analogs and can possibly replace the fractal dimension which is more commonly used in software that model DFNs. Additionally, while lacunarity has been mostly used for understanding network geometry in terms of clustering, we, for the first time, show how this may be directly used for understanding the potential flow behavior of fracture networks.
{"title":"Clustering, Connectivity and Flow in Naturally Fractured Reservoir Analogs","authors":"A. Sahu, A. Roy","doi":"10.2118/206009-ms","DOIUrl":"https://doi.org/10.2118/206009-ms","url":null,"abstract":"\u0000 A previous study by the authors on synthetic fractal-fracture networks showed that lacunarity, a parameter that quantifies scale-dependent clustering in patterns, can be used as a proxy for connectivity and also, is an indicator of fluid flow in such model networks. In this research, we apply the concepts thus developed to the study of fractured reservoir analogs and seek solutions to more practical problems faced by modelers in the oil and gas industry. A set of seven nested fracture networks from the Devonian Sandstone of Hornelen Basin, Norway that have the same fractal-dimension but are mapped at different scales and resolutions is considered. We compare these seven natural fracture maps in terms of their lacunarity and connectivity values to test whether the former is a reasonable indicator of the latter. Additionally, these maps are also flow simulated by implementing a fracture continuum model and using a streamline simulator, TRACE3D. The values of lacunarity, connectivity and fluid recovery thus obtained are pairwise correlated with one another to look for possible relationships. The results indicate that while fracture maps that have the same fractal dimension show almost similar connectivity values, there exist subtle differences such that both the connectivity and clustering values change systematically with the scale at which the fracture networks are mapped. It is further noted that there appears to be a very good correlation between clustering, connectivity, and fluid recovery values for these fracture networks that belong to the same fractal system. The overall results indicate that while the fractal dimension is an important parameter for characterizing a specific type of fracture network geometry, it is the lacunarity or scale-dependent clustering attribute that controls connectivity in fracture maps and hence the flow properties. This research may prove helpful in quickly evaluating connectivity of fracture networks based on the lacunarity parameter. This parameter can therefore, be used for calibrating Discrete Fracture Network (DFN) models with respect to connectivity of reservoir analogs and can possibly replace the fractal dimension which is more commonly used in software that model DFNs. Additionally, while lacunarity has been mostly used for understanding network geometry in terms of clustering, we, for the first time, show how this may be directly used for understanding the potential flow behavior of fracture networks.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87209489","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 mechanical properties of hydrocarbon reservoirs significantly depend on the elastic properties of the fluids occupying the pore space in the rock frame. Accurate data and models for the mechanical properties of fluid mixtures in a petroleum reservoir containing supercritical CO2 should be available at the same reservoir conditions for reliable design of well-completion, maximizing reservoir productivity, and minimizing risk in drilling operations. This work investigates the change in the bulk modulus of the higher hydrocarbon fluid (decane C10H22) after the injection with supercritical CO2 at reservoir conditions. The isothermal bulk modulus βT of liquids under pressure, simply defined as the first-order derivative of pressure with respect to volume, is determined in this study from the derivative of pressure with respect to density. The density data were obtained from experimental measurements of mixtures of supercritical CO2 + C10H22 for a range of CO2 mole fractions from 0 to 0.73, at temperatures from 40 to 137 °C and pressures up to 12000 psi. The isothermal derivative coefficients of the pressure as a function of density are reported for each CO2 concentration measured in this work. Common fluid-substitution models, including the Gassmann model, which is only valid for the isothermal regime, have limited predictive power because most fluids are treated as simple fluids, with their mechanical properties only characterized by their densities. However, under different environments, such as when supercritical CO2 is injected into the geological formation, the fluid phase and its mechanical properties can vary dramatically. At high pressure, the density of CO2 can equal to that of the hydrocarbon phase ρ(CO2)/ρ(C10H22) ≈ 1, while the bulk modulus of CO2 remains as low as only βT(CO2)/βT(C10H22) ≈ 7 %. Excessive decrease in the bulk modulus can easily cause subsidence, although the pore pressure and the fluid mixture density remain unchanged, even at pressures up to 4000 psi.
{"title":"Bulk Modulus of Hydrocarbon Fluids After Injection with Supercritical CO2 at Reservoir Conditions","authors":"Mohamed E. Kandil","doi":"10.2118/206277-ms","DOIUrl":"https://doi.org/10.2118/206277-ms","url":null,"abstract":"\u0000 The mechanical properties of hydrocarbon reservoirs significantly depend on the elastic properties of the fluids occupying the pore space in the rock frame. Accurate data and models for the mechanical properties of fluid mixtures in a petroleum reservoir containing supercritical CO2 should be available at the same reservoir conditions for reliable design of well-completion, maximizing reservoir productivity, and minimizing risk in drilling operations. This work investigates the change in the bulk modulus of the higher hydrocarbon fluid (decane C10H22) after the injection with supercritical CO2 at reservoir conditions. The isothermal bulk modulus βT of liquids under pressure, simply defined as the first-order derivative of pressure with respect to volume, is determined in this study from the derivative of pressure with respect to density. The density data were obtained from experimental measurements of mixtures of supercritical CO2 + C10H22 for a range of CO2 mole fractions from 0 to 0.73, at temperatures from 40 to 137 °C and pressures up to 12000 psi. The isothermal derivative coefficients of the pressure as a function of density are reported for each CO2 concentration measured in this work. Common fluid-substitution models, including the Gassmann model, which is only valid for the isothermal regime, have limited predictive power because most fluids are treated as simple fluids, with their mechanical properties only characterized by their densities. However, under different environments, such as when supercritical CO2 is injected into the geological formation, the fluid phase and its mechanical properties can vary dramatically. At high pressure, the density of CO2 can equal to that of the hydrocarbon phase ρ(CO2)/ρ(C10H22) ≈ 1, while the bulk modulus of CO2 remains as low as only βT(CO2)/βT(C10H22) ≈ 7 %. Excessive decrease in the bulk modulus can easily cause subsidence, although the pore pressure and the fluid mixture density remain unchanged, even at pressures up to 4000 psi.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"75 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91074157","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}
M. Vu, Aurélien Bouhours, Julien Bouhours, R. Bouchair, A. Bois, A. Badalamenti
Ensuring wells’ cement mechanical integrity (CMI) is of paramount importance for the success of a thermal project. Failed cement sheaths can lead to loss of production, environmental pollutions, or even to well abandonment. Over time, CMI software applications have been developed to design wells that do not leak. However, their efficiency depends not only on if their equations are verified, but also on how the models are validated versus wells’ downhole conditions. Unfortunately, most CMI tool designers have focused on only verifying if the models are mathematically correct, checking what is the time required for a simulation, and improving how are the simulations reported to the user. Typically, little time is dedicated on validating that the correct model is used for the specific well. This foresight has led to non-predictive CMI tools, which do not allow optimizing well designs. The authors have been involved for more than 15 years in developing and validating CMI models. They have shown the importance of simulating the cement hydration to evaluate the state of stress in the cement after it has set. They also have highlighted how the plastic behavior of the cement design can lead to opening micro-annuli at the cement-sheath's interfaces. Recently the authors have started theoretical work in the area of the cement integrity of high and ultra-high temperature wells and how these temperatures, either naturally occurring or induced, could affect the cement's mechanical integrity. The work has focused on modeling the increase in pore pressures, the opening of micro-annuli at the cement sheath's boundaries, and the phase changes which take place in the cement when it is heated to high temperature values. To date this work showed that heating cement up to 250°C can result in pore pressures larger than 100 MPa unless if the pore pressures can be released. This work has also identified three mechanisms that can lead to such release of pore pressures: 1) During cement hydration, due to the water consumption by the chemical reactions, 2) When a micro-annulus opens due to the large pore pressures, therefore allowing venting the pressures to the surface or to a downhole reservoir, and 3) When a change of phase occurs in the cement when heated to more than 110°C, as this leads to the creation of additional porosity in the cement. All this means that the cement sheath should not be simulated as a closed system, but rather as an open thermo-hydro-chemo-mechanics. How these features impact CMI has never been studied before even if they can explain why some cement designs lead to tight cement sheath and other to leaking ones. This paper highlights the work that has been done and when these conditions should be considered, and if it is feasible to design cement sheaths that do not fail, even at very high temperatures.
{"title":"Advanced Cement Mechanical Integrity for Thermal Wells","authors":"M. Vu, Aurélien Bouhours, Julien Bouhours, R. Bouchair, A. Bois, A. Badalamenti","doi":"10.2118/206144-ms","DOIUrl":"https://doi.org/10.2118/206144-ms","url":null,"abstract":"\u0000 Ensuring wells’ cement mechanical integrity (CMI) is of paramount importance for the success of a thermal project. Failed cement sheaths can lead to loss of production, environmental pollutions, or even to well abandonment. Over time, CMI software applications have been developed to design wells that do not leak. However, their efficiency depends not only on if their equations are verified, but also on how the models are validated versus wells’ downhole conditions. Unfortunately, most CMI tool designers have focused on only verifying if the models are mathematically correct, checking what is the time required for a simulation, and improving how are the simulations reported to the user. Typically, little time is dedicated on validating that the correct model is used for the specific well. This foresight has led to non-predictive CMI tools, which do not allow optimizing well designs.\u0000 The authors have been involved for more than 15 years in developing and validating CMI models. They have shown the importance of simulating the cement hydration to evaluate the state of stress in the cement after it has set. They also have highlighted how the plastic behavior of the cement design can lead to opening micro-annuli at the cement-sheath's interfaces. Recently the authors have started theoretical work in the area of the cement integrity of high and ultra-high temperature wells and how these temperatures, either naturally occurring or induced, could affect the cement's mechanical integrity. The work has focused on modeling the increase in pore pressures, the opening of micro-annuli at the cement sheath's boundaries, and the phase changes which take place in the cement when it is heated to high temperature values. To date this work showed that heating cement up to 250°C can result in pore pressures larger than 100 MPa unless if the pore pressures can be released. This work has also identified three mechanisms that can lead to such release of pore pressures: 1) During cement hydration, due to the water consumption by the chemical reactions, 2) When a micro-annulus opens due to the large pore pressures, therefore allowing venting the pressures to the surface or to a downhole reservoir, and 3) When a change of phase occurs in the cement when heated to more than 110°C, as this leads to the creation of additional porosity in the cement. All this means that the cement sheath should not be simulated as a closed system, but rather as an open thermo-hydro-chemo-mechanics. How these features impact CMI has never been studied before even if they can explain why some cement designs lead to tight cement sheath and other to leaking ones. This paper highlights the work that has been done and when these conditions should be considered, and if it is feasible to design cement sheaths that do not fail, even at very high temperatures.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85866256","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}
Tarik Abdelfattah, E. Nasir, Junjie Yang, J. Bynum, A. Klebanov, Danish Tarar, G. Loxton, Stephanie Cook, C. Mascagnini
Unconventional reservoir development is a multidisciplinary challenge due to complicated physical system, including but not limited to complicated flow mechanism, multiple porosity system, heterogeneous subsurface rock and minerals, well interference, and fluid-rock interaction. With enough well data, physics-based models can be supplemented with data driven methods to describe a reservoir system and accurately predict well performance. This study uses a data driven approach to tackle the field development problem in the Eagle Ford Shale. A large amount of data spanning major oil and gas disciplines was collected and interrogated from around 300 wells in the area of interest. The data driven workflow consists of: Descriptive model to regress on existing wells with the selected well features and provide insight on feature importance, Predictive model to forecast well performance, and Subject matter expert driven prescriptive model to optimize future well design for well economics improvement. To evaluate initial well economics, 365 consecutive days of production oil per CAPEX dollar spent (bbl/$) was setup as the objective function. After a careful model selection, Random Forest (RF) shows the best accuracy with the given dataset, and Differential Evolution (DE) was used for optimization. Using recursive feature elimination (RFE), the final master dataset was reduced to 50 parameters to feed into the machine learning model. After hyperparameter tuning, reasonable regression accuracy was achieved by the Random Forest algorithm, where correlation coefficient (R2) for the training and test dataset was 0.83, and mean absolute error percentage (MAEP) was less than 20%. The model also reveals that the well performance is highly dependent on a good combination of variables spanning geology, drilling, completions, production and reservoir. Completion year has one of the highest feature importance, indicating the improvement of operation and design efficiency and the fluctuation of service cost. Moreover, lateral rate of penetration (ROP) was always amongst the top two important parameters most likely because it impacts the drilling cost significantly. With subject matter experts’ (SME) input, optimization using the regression model was performed in an iterative manner with the chosen parameters and using reasonable upper and lower bounds. Compared to the best existing wells in the vicinity, the optimized well design shows a potential improvement on bbl/$ by approximately 38%. This paper introduces an integrated data driven solution to optimize unconventional development strategy. Comparing to conventional analytical and numerical methods, machine learning model is able to handle large multidimensional dataset and provide actionable recommendations with a much faster turnaround. In the course of field development, the model accuracy can be dynamically improved by including more data collected from new wells.
{"title":"Data Driven Workflow to Optimize Eagle Ford Unconventional Asset Development Plan Based on Multidisciplinary Data","authors":"Tarik Abdelfattah, E. Nasir, Junjie Yang, J. Bynum, A. Klebanov, Danish Tarar, G. Loxton, Stephanie Cook, C. Mascagnini","doi":"10.2118/206276-ms","DOIUrl":"https://doi.org/10.2118/206276-ms","url":null,"abstract":"\u0000 Unconventional reservoir development is a multidisciplinary challenge due to complicated physical system, including but not limited to complicated flow mechanism, multiple porosity system, heterogeneous subsurface rock and minerals, well interference, and fluid-rock interaction. With enough well data, physics-based models can be supplemented with data driven methods to describe a reservoir system and accurately predict well performance. This study uses a data driven approach to tackle the field development problem in the Eagle Ford Shale.\u0000 A large amount of data spanning major oil and gas disciplines was collected and interrogated from around 300 wells in the area of interest. The data driven workflow consists of:\u0000 Descriptive model to regress on existing wells with the selected well features and provide insight on feature importance, Predictive model to forecast well performance, and Subject matter expert driven prescriptive model to optimize future well design for well economics improvement.\u0000 To evaluate initial well economics, 365 consecutive days of production oil per CAPEX dollar spent (bbl/$) was setup as the objective function. After a careful model selection, Random Forest (RF) shows the best accuracy with the given dataset, and Differential Evolution (DE) was used for optimization.\u0000 Using recursive feature elimination (RFE), the final master dataset was reduced to 50 parameters to feed into the machine learning model. After hyperparameter tuning, reasonable regression accuracy was achieved by the Random Forest algorithm, where correlation coefficient (R2) for the training and test dataset was 0.83, and mean absolute error percentage (MAEP) was less than 20%. The model also reveals that the well performance is highly dependent on a good combination of variables spanning geology, drilling, completions, production and reservoir. Completion year has one of the highest feature importance, indicating the improvement of operation and design efficiency and the fluctuation of service cost. Moreover, lateral rate of penetration (ROP) was always amongst the top two important parameters most likely because it impacts the drilling cost significantly. With subject matter experts’ (SME) input, optimization using the regression model was performed in an iterative manner with the chosen parameters and using reasonable upper and lower bounds. Compared to the best existing wells in the vicinity, the optimized well design shows a potential improvement on bbl/$ by approximately 38%.\u0000 This paper introduces an integrated data driven solution to optimize unconventional development strategy. Comparing to conventional analytical and numerical methods, machine learning model is able to handle large multidimensional dataset and provide actionable recommendations with a much faster turnaround. In the course of field development, the model accuracy can be dynamically improved by including more data collected from new wells.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81599878","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}
Vivek Shankar, Shekhar Sunit, A. Brown, Abhishek Kumar Gupta
The paper describes the in-situ polymer sampling in Mangala which helped explain the performance of a large polymer flood in Mangala field in India. The Mangala field contains medium-gravity viscous crude oil. Notably, it is the largest polymer flood in India and 34% of the STOIIP has been produced in 11 years of production. Mangala was put on full field polymer flood in 2015, six years after the start of field production on water flood in 2009. Polymer flood added 93 million barrels above the anticipated water flood recovery in 6 years. Reservoir simulation models could replicate the initial Mangala polymer flood performance. However, the performance of the lower layers of Mangala (FM-3 and FM-4) continued to progressively deviate from modeling estimates. Equally importantly, the prediction of polymer breakthrough deviated significantly from modeling estimates. After 6 years and 0.7 pore volumes of polymer injection, it is apparent that field performance is equivalent to only 50-60% of the viscosity of the polymer injected at the surface. To better understand and quantify the nature and extent of polymer degradation it is necessary to gather representative down hole samples of polymer which has stayed in the reservoir conditions for a considerable length of time. Accelerated ageing studies in the lab showed HPAM can lose viscosity and precipitate after prolonged exposure to Mangala reservoir conditions with an increase in the degree of hydrolysis as the primary reason for the degradation. The concept of transfer function based on first order kinetics was used to extrapolate the laboratory results to Mangala reservoir temperatures. To test the hypothesis, a multi-disciplinary team implemented a plan to gather a representative polymer sample from the reservoir. The polymer sample had been in the reservoir for nearly 120 days and was captured in low shear and anaerobic conditions to minimize shear and oxidative degradation. The sample was tested for degree of hydrolysis by NMR method. The results confirmed that the level of hydrolysis of the injected HPAM did increase in the reservoir leading to lower viscosity and reduced lower amide concentration. Preliminary simulation studies using the concept of viscosity half-life were used to mimic the polymer degradation with time in the reservoir. The method is quite a simplistic representation of the thermal degradation, but it significantly improved the model's water cut predictions for lower layers and the full field polymer breakthrough predictions. The impact of polymer precipitation in the reservoir on the permeability is under study and it will drive the next phase of more detailed modeling.
{"title":"Mangala Polymer Flood Performance: Connecting the Dots Through in Situ Polymer Sampling","authors":"Vivek Shankar, Shekhar Sunit, A. Brown, Abhishek Kumar Gupta","doi":"10.2118/206146-ms","DOIUrl":"https://doi.org/10.2118/206146-ms","url":null,"abstract":"\u0000 The paper describes the in-situ polymer sampling in Mangala which helped explain the performance of a large polymer flood in Mangala field in India.\u0000 The Mangala field contains medium-gravity viscous crude oil. Notably, it is the largest polymer flood in India and 34% of the STOIIP has been produced in 11 years of production. Mangala was put on full field polymer flood in 2015, six years after the start of field production on water flood in 2009. Polymer flood added 93 million barrels above the anticipated water flood recovery in 6 years. Reservoir simulation models could replicate the initial Mangala polymer flood performance. However, the performance of the lower layers of Mangala (FM-3 and FM-4) continued to progressively deviate from modeling estimates. Equally importantly, the prediction of polymer breakthrough deviated significantly from modeling estimates.\u0000 After 6 years and 0.7 pore volumes of polymer injection, it is apparent that field performance is equivalent to only 50-60% of the viscosity of the polymer injected at the surface. To better understand and quantify the nature and extent of polymer degradation it is necessary to gather representative down hole samples of polymer which has stayed in the reservoir conditions for a considerable length of time. Accelerated ageing studies in the lab showed HPAM can lose viscosity and precipitate after prolonged exposure to Mangala reservoir conditions with an increase in the degree of hydrolysis as the primary reason for the degradation. The concept of transfer function based on first order kinetics was used to extrapolate the laboratory results to Mangala reservoir temperatures. To test the hypothesis, a multi-disciplinary team implemented a plan to gather a representative polymer sample from the reservoir. The polymer sample had been in the reservoir for nearly 120 days and was captured in low shear and anaerobic conditions to minimize shear and oxidative degradation.\u0000 The sample was tested for degree of hydrolysis by NMR method. The results confirmed that the level of hydrolysis of the injected HPAM did increase in the reservoir leading to lower viscosity and reduced lower amide concentration. Preliminary simulation studies using the concept of viscosity half-life were used to mimic the polymer degradation with time in the reservoir. The method is quite a simplistic representation of the thermal degradation, but it significantly improved the model's water cut predictions for lower layers and the full field polymer breakthrough predictions. The impact of polymer precipitation in the reservoir on the permeability is under study and it will drive the next phase of more detailed modeling.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"os-31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87217178","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}
Infill completions have been explored by many operators in the last few years as a strategy to increase ultimate recovery from unconventional shale oil reservoirs. The stimulation of infill wells often causes pressure increases, known as fracture-driven interactions (FDIs), in nearby wells. Studies have generally focused on the propagation of fractures from infill wells and pressure changes in treatment wells rather than observation wells. Meanwhile, studies regarding the pressure response in the observation (parent) wells are mainly limited to field observations and conjecture. In this study, we provide a partialcorrective to this gap in the research.We model the pressure fluctuations in parent wells induced by fracking infill wells and provide insight into how field operators can use the pressure data from nearby wells to identify different forms of FDI, including fracture hit (frac-hit) and fracture shadowing. First,we model the trajectory of a fracture propagating from an infill well using the extended finite element methods (XFEM). This method allows us to incorporatethe possible intersection of fractures independent of the mesh gridding. Subsequently, we calculate the pressure response from the frac-hit and stress shadowing using a coupled geomechanics and multi-phase fluid flow model. Through numerical examples, we assess different scenarios that might arise because of the interactions between new fractures and old depleted fractures based on the corresponding pressure behavior in the parent wells. Typically, a large increase in bottomhole pressure over a short period is interpreted as a potential indication of a fracture hit. However, we show that a slower increase in bottomhole pressure may also imply a fracture hit, especially if gas repressurization was performed before the infill well was fracked. Ultimately, we find that well storage may buffer the sudden increase in pressure due to the frac-hit. We conclude by summarizing the different FDIs through their pressure footprints.
{"title":"Toward Controllable Infill Completions Using Frac-Driven Interactions FDI Data","authors":"Yuzhe Cai, A. Dahi Taleghani","doi":"10.2118/206306-ms","DOIUrl":"https://doi.org/10.2118/206306-ms","url":null,"abstract":"\u0000 Infill completions have been explored by many operators in the last few years as a strategy to increase ultimate recovery from unconventional shale oil reservoirs. The stimulation of infill wells often causes pressure increases, known as fracture-driven interactions (FDIs), in nearby wells. Studies have generally focused on the propagation of fractures from infill wells and pressure changes in treatment wells rather than observation wells. Meanwhile, studies regarding the pressure response in the observation (parent) wells are mainly limited to field observations and conjecture. In this study, we provide a partialcorrective to this gap in the research.We model the pressure fluctuations in parent wells induced by fracking infill wells and provide insight into how field operators can use the pressure data from nearby wells to identify different forms of FDI, including fracture hit (frac-hit) and fracture shadowing. First,we model the trajectory of a fracture propagating from an infill well using the extended finite element methods (XFEM). This method allows us to incorporatethe possible intersection of fractures independent of the mesh gridding. Subsequently, we calculate the pressure response from the frac-hit and stress shadowing using a coupled geomechanics and multi-phase fluid flow model. Through numerical examples, we assess different scenarios that might arise because of the interactions between new fractures and old depleted fractures based on the corresponding pressure behavior in the parent wells. Typically, a large increase in bottomhole pressure over a short period is interpreted as a potential indication of a fracture hit. However, we show that a slower increase in bottomhole pressure may also imply a fracture hit, especially if gas repressurization was performed before the infill well was fracked. Ultimately, we find that well storage may buffer the sudden increase in pressure due to the frac-hit. We conclude by summarizing the different FDIs through their pressure footprints.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87316484","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}
This paper studies the effect of trapped, emulsified oil on the requirement for the geometrical Roof snap-off for foam generation in a porous medium. We extend an existing hydrodynamic pore-level model to describe the liquid accumulation in an appropriately-sized pore in the presence of oil. The effect of oil is simulated by adjusting the pore shape to be asymmetrical as observed in microfluidic experiments with residual oil. We alter the boundary and initial conditions of the problem to test various scenarios. Specifically, four cases are presented. The liquid accumulation is presented when the amount of wetting liquid volume connected to the pore is altered through changing the boundary conditions (cases 1 and 2). Moreover, the effect of drier surrounding medium and/or drier pores is also tested by increasing either the capillary pressure surrounding the pore or the capillary pressure of the pore itself (cases 3 and 4). We find that the presence of residual oil affects the liquid accumulation times when there is no external liquid pressure gradient applied. Additionally, residual oil presence makes the Roof snap-off criterion for liquid accumulation stricter. To augment our pore-level study, we use a statistical pore network to observe the effect of the microscopic changes observed in our pore-level model macroscopically. Our results indicate that a stricter Roof snap-off criterion leads to fewer germination sites for lamellae generation. Our pore network analysis computes the generation rate constant to be as much as four times larger in the absence of oil than in its presence. Results suggest that changes to the shape of pore constrictions by emulsified oil reduce the effectiveness of foam generation.
{"title":"Foam Generation in the Presence of Residual Oil in Porous Media","authors":"M. Almajid, A. Kovscek","doi":"10.2118/206031-ms","DOIUrl":"https://doi.org/10.2118/206031-ms","url":null,"abstract":"\u0000 This paper studies the effect of trapped, emulsified oil on the requirement for the geometrical Roof snap-off for foam generation in a porous medium. We extend an existing hydrodynamic pore-level model to describe the liquid accumulation in an appropriately-sized pore in the presence of oil. The effect of oil is simulated by adjusting the pore shape to be asymmetrical as observed in microfluidic experiments with residual oil. We alter the boundary and initial conditions of the problem to test various scenarios. Specifically, four cases are presented. The liquid accumulation is presented when the amount of wetting liquid volume connected to the pore is altered through changing the boundary conditions (cases 1 and 2). Moreover, the effect of drier surrounding medium and/or drier pores is also tested by increasing either the capillary pressure surrounding the pore or the capillary pressure of the pore itself (cases 3 and 4). We find that the presence of residual oil affects the liquid accumulation times when there is no external liquid pressure gradient applied. Additionally, residual oil presence makes the Roof snap-off criterion for liquid accumulation stricter. To augment our pore-level study, we use a statistical pore network to observe the effect of the microscopic changes observed in our pore-level model macroscopically. Our results indicate that a stricter Roof snap-off criterion leads to fewer germination sites for lamellae generation. Our pore network analysis computes the generation rate constant to be as much as four times larger in the absence of oil than in its presence. Results suggest that changes to the shape of pore constrictions by emulsified oil reduce the effectiveness of foam generation.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80679695","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}
Improved oil recovery in carbonate rocks through modified injection brine has been investigated extensively in recent years. Examples include low salinity waterflooding and surfactant injection for the purpose of residual oil reduction. Polymer addition to injection water for improvement of sweep efficiency enjoys field success. The effect of low salinity waterflooding is often marginal and it may even decrease recovery compared to seawater flooding. Polymer and surfactant injection are often effective (except at very high salinities and temperatures) but concentrations in the range of 5000 to 10000 ppm may make the processes expensive. We have recently suggested the idea of ultra-low concentration of surfactants at 100 ppm to decrease residual oil saturation from increased brine-oil interfacial elasticity. In this work, we investigate the synergistic effects of polymer injection for sweep efficiency and the surfactant for interfacial elasticity modification. The combined formulation achieves both sweep efficiency and residual oil reduction. A series of coreflood tests is performed on a carbonate rock using three crude oils and various injection brines: seawater and formation water with added surfactant and polymer. Both the surfactant and polymer are found to improve recovery at breakthrough via increase in oil-brine interfacial elasticity and injection brine viscosification, respectively. The synergy of surfactant and polymer mixed with seawater leads to higher viscosity and higher oil recovery. The overall oil recovery is found to be a strong function of oil-brine interfacial viscoelasticity with and without the surfactant and polymer in sea water and connate water injection.
{"title":"Synergy of Polymer for Mobility Control and Surfactant for Interface Elasticity Increase in Improved Oil Recovery","authors":"Taniya Kar, A. Firoozabadi","doi":"10.2118/206164-ms","DOIUrl":"https://doi.org/10.2118/206164-ms","url":null,"abstract":"\u0000 Improved oil recovery in carbonate rocks through modified injection brine has been investigated extensively in recent years. Examples include low salinity waterflooding and surfactant injection for the purpose of residual oil reduction. Polymer addition to injection water for improvement of sweep efficiency enjoys field success. The effect of low salinity waterflooding is often marginal and it may even decrease recovery compared to seawater flooding. Polymer and surfactant injection are often effective (except at very high salinities and temperatures) but concentrations in the range of 5000 to 10000 ppm may make the processes expensive. We have recently suggested the idea of ultra-low concentration of surfactants at 100 ppm to decrease residual oil saturation from increased brine-oil interfacial elasticity. In this work, we investigate the synergistic effects of polymer injection for sweep efficiency and the surfactant for interfacial elasticity modification. The combined formulation achieves both sweep efficiency and residual oil reduction. A series of coreflood tests is performed on a carbonate rock using three crude oils and various injection brines: seawater and formation water with added surfactant and polymer. Both the surfactant and polymer are found to improve recovery at breakthrough via increase in oil-brine interfacial elasticity and injection brine viscosification, respectively. The synergy of surfactant and polymer mixed with seawater leads to higher viscosity and higher oil recovery. The overall oil recovery is found to be a strong function of oil-brine interfacial viscoelasticity with and without the surfactant and polymer in sea water and connate water injection.","PeriodicalId":10896,"journal":{"name":"Day 1 Tue, September 21, 2021","volume":"88 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81097783","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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