Proper lateral and vertical well spacing is extremely critical to efficiently develop unconventional reservoirs. Much research has focused on lateral well spacing, but little on vertical spacing, which is important and challenging for those stacked-bench plays like Permian Basin. Following the previously successful single well study (SPE 189855), we have performed a seven-well case study by applying the latest complex fracture modeling and reservoir simulation technologies. Those seven wells are located at the same section but also are vertically placed in 4 different zones in the Wolfcamp formation. With the latest modeling technologies, we first built a 3-D geological and geomechanical model, and full wellbore fracturing propagation model for those seven wells, and then calibrated the model with multi-stage fracturing pumping history of each well. The resulting model was then converted into an unstructured grid-based reservoir simulation model, which was then calibrated with production history. Based upon the understandings on the local geomechanical characterization, as well as confidence on the capacity of those models from our previous study, we conducted experiments in fracturing modeling to study the impact by different completion design parameters on fracture propagation, including cluster spacing, frac-fluid viscosity, cluster pumping rate, and fluid and proppant intensities. With the statistical distributions of fracture length and height from different completion designs, we then optimized the completion design, studied lateral and vertical well spacings, further investigated frac-hit possibility assisted by Monte Carlo simulation, and estimated stimulated reservoir volume. The modeling results show: (1) both the length and height of those fractures initiated from perforation clusters are in log-normal distributions depending on completion designs, which provide crucial insights to well interference and furthermore on well spacing; (2) the hydraulic fracture length, height, and network complexity mainly depend on discrete fracture network (DFN), stress and its anisotropy, and frac-fluid viscosity; (3) the key completion design parameters, which impact the fracture length and height distributions, include cluster spacing, clusters per stage, the fluid and proppant intensities, and fluid viscosity and proppant concentration; (4) the implication of frac-hit probability on well spacing and completion design on the well spacing decision and furthermore on recovery and value. Therefore, we can reasonably model complicated fracturing propagation and well performance with the latest modeling technologies, and optimize both lateral and vertical well spacings, and the corresponding completion designs. The application of those technologies could help operators save significant time and money on well completion and spacing piloting projects, and thus speed up field development decision. In addition to the detailed modeling process, techniqu
{"title":"Optimize Completion Design and Well Spacing with the Latest Complex Fracture Modeling & Reservoir Simulation Technologies – A Permian Basin Case Study with Seven Wells","authors":"Hongjie Xiong, Songxia Liu, Feng Feng, Shuai Liu, Kaimin Yue","doi":"10.2118/194367-MS","DOIUrl":"https://doi.org/10.2118/194367-MS","url":null,"abstract":"\u0000 Proper lateral and vertical well spacing is extremely critical to efficiently develop unconventional reservoirs. Much research has focused on lateral well spacing, but little on vertical spacing, which is important and challenging for those stacked-bench plays like Permian Basin. Following the previously successful single well study (SPE 189855), we have performed a seven-well case study by applying the latest complex fracture modeling and reservoir simulation technologies. Those seven wells are located at the same section but also are vertically placed in 4 different zones in the Wolfcamp formation.\u0000 With the latest modeling technologies, we first built a 3-D geological and geomechanical model, and full wellbore fracturing propagation model for those seven wells, and then calibrated the model with multi-stage fracturing pumping history of each well. The resulting model was then converted into an unstructured grid-based reservoir simulation model, which was then calibrated with production history.\u0000 Based upon the understandings on the local geomechanical characterization, as well as confidence on the capacity of those models from our previous study, we conducted experiments in fracturing modeling to study the impact by different completion design parameters on fracture propagation, including cluster spacing, frac-fluid viscosity, cluster pumping rate, and fluid and proppant intensities. With the statistical distributions of fracture length and height from different completion designs, we then optimized the completion design, studied lateral and vertical well spacings, further investigated frac-hit possibility assisted by Monte Carlo simulation, and estimated stimulated reservoir volume.\u0000 The modeling results show: (1) both the length and height of those fractures initiated from perforation clusters are in log-normal distributions depending on completion designs, which provide crucial insights to well interference and furthermore on well spacing; (2) the hydraulic fracture length, height, and network complexity mainly depend on discrete fracture network (DFN), stress and its anisotropy, and frac-fluid viscosity; (3) the key completion design parameters, which impact the fracture length and height distributions, include cluster spacing, clusters per stage, the fluid and proppant intensities, and fluid viscosity and proppant concentration; (4) the implication of frac-hit probability on well spacing and completion design on the well spacing decision and furthermore on recovery and value.\u0000 Therefore, we can reasonably model complicated fracturing propagation and well performance with the latest modeling technologies, and optimize both lateral and vertical well spacings, and the corresponding completion designs. The application of those technologies could help operators save significant time and money on well completion and spacing piloting projects, and thus speed up field development decision.\u0000 In addition to the detailed modeling process, techniqu","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133138695","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 use of high viscosity friction reducers (HVFR) as alternatives to guar-based fluids to improve proppant transport and lessen formation damage has increased rapidly. While several product options are available, the criteria for selection of a product has focused on viscosity at 300 RPM (511s-1) that meets or exceeds that of linear gel fluids. However, there has been limited data available on what the target viscosity should be, how it influences the fluid's ability to transport sand, and the potential for damage to proppant conductivity. This study presents methodology used to screen HVFR's and results on product performance, which identified a need for alternative specifications to viscosity to achieve maximum performance. The proppant transport capacity in dynamic conditions was evaluated for twenty commercially available friction reducers and HVFR's in field waters which could have up to 20,000 TDS. A slot flow apparatus was used to mimic fluid flow through a fracture under different shear and flow rate conditions. Viscosity and elasticity measurements were also obtained using an advanced rotational rheometer. For comparison, linear gel and crosslinked guar fluid were also evaluated. While viscosity at 300 RPM (511s-1) and more recently high viscosity at lower shear rates, have been used for selection of HVFR's, these parameters alone do not indicate proppant carrying capacity. The authors did not find a correlation between higher viscosity and better proppant transport, rather they propose that too high a viscosity can negatively impact transport. The results provided insight into the effect of flow rate on proppant transport, with some HVFR's that exhibited higher viscosities at low shear, losing their transport capacity at the same low shear. Elasticity testing of those same products suggested that HVFR's have a critical elasticity range at which they will provide optimal performance. Polymer residuals were also evaluated on proppant post-test and compared to traditional linear gels and crosslinked fluids. Results suggested potential for damage if HVFR's are used without breakers. Different viscosity targets should be set when selecting a HVFR and coupled with other testing criteria such as elasticity and dynamic proppant transport. This paper provides insight into the need for development of standardized test criteria for HVFR selection. Further testing and screening of HVFR's will help increase the understanding of key factors influencing sand transport and their effect on proppant pack conductivity.
{"title":"Can Proppant Transport be Negatively Affected by Too Much Viscosity?","authors":"Tanhee Galindo","doi":"10.2118/194317-MS","DOIUrl":"https://doi.org/10.2118/194317-MS","url":null,"abstract":"\u0000 The use of high viscosity friction reducers (HVFR) as alternatives to guar-based fluids to improve proppant transport and lessen formation damage has increased rapidly. While several product options are available, the criteria for selection of a product has focused on viscosity at 300 RPM (511s-1) that meets or exceeds that of linear gel fluids. However, there has been limited data available on what the target viscosity should be, how it influences the fluid's ability to transport sand, and the potential for damage to proppant conductivity. This study presents methodology used to screen HVFR's and results on product performance, which identified a need for alternative specifications to viscosity to achieve maximum performance.\u0000 The proppant transport capacity in dynamic conditions was evaluated for twenty commercially available friction reducers and HVFR's in field waters which could have up to 20,000 TDS. A slot flow apparatus was used to mimic fluid flow through a fracture under different shear and flow rate conditions. Viscosity and elasticity measurements were also obtained using an advanced rotational rheometer. For comparison, linear gel and crosslinked guar fluid were also evaluated.\u0000 While viscosity at 300 RPM (511s-1) and more recently high viscosity at lower shear rates, have been used for selection of HVFR's, these parameters alone do not indicate proppant carrying capacity. The authors did not find a correlation between higher viscosity and better proppant transport, rather they propose that too high a viscosity can negatively impact transport. The results provided insight into the effect of flow rate on proppant transport, with some HVFR's that exhibited higher viscosities at low shear, losing their transport capacity at the same low shear. Elasticity testing of those same products suggested that HVFR's have a critical elasticity range at which they will provide optimal performance. Polymer residuals were also evaluated on proppant post-test and compared to traditional linear gels and crosslinked fluids. Results suggested potential for damage if HVFR's are used without breakers. Different viscosity targets should be set when selecting a HVFR and coupled with other testing criteria such as elasticity and dynamic proppant transport.\u0000 This paper provides insight into the need for development of standardized test criteria for HVFR selection. Further testing and screening of HVFR's will help increase the understanding of key factors influencing sand transport and their effect on proppant pack conductivity.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"61 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131435987","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}
Micro-proppants use in hydraulic fracturing has had a significant impact on production and has led to a reduction of treating pressure and thus enhancement of the overall hydraulic fracturing treatment. A number of mechanisms have been proposed to explain the success of micro-proppants. However, the role of these proppants on increasing the conductivity of secondary natural fractures and fracture network development has not been well demonstrated. The objective of this paper is to explore and clarify the potential mechanisms involved in the success of micro-proppants. We study the transport and deposition of micro-proppants in propagating facture networks using an advanced simulator "GeoFrac-3D" that can consider irregular fracture geometries and intersection angles not limited to 90 degrees, thereby capturing realistic flow and proppant transport pathways and deposition sites. The method is 3D and fully couples fluid pressure to stresses and allows for dynamic modeling of 3D fracture propagation. Robust multiple 3D fracture propagation is considered using the displacement discontinuity method for the rock deformation and the finite element method for the fracture fluid flow. The pressure dependent leak-off of the fracturing fluid into the rock matrix/natural fracture system is considered. The proppant transport and deposition within the fracture is modeled by treating the mixture of fluid and proppant particles as slurry. The simulation results show that proppant transport into secondary fractures, and relatively less settling are the major factors in micro-proppant effectiveness. Proppant settling velocities and thus proppant distribution is affected by fluid velocity, micro-proppant size, fluid rheology, fracture aperture, hydraulic and natural fracture interaction and near wellbore tortuosity. The results demonstrates that the micro-proppants being smaller size particles have strong potential for the effective uniform proppant placement into the complex fractured unconventional reservoirs; hence, to increase their conductivity for the oil and gas in-flow. Additionally, as the micro-proppant can enter into the tight natural or secondary fractures, it will reduce pressure dependent leak-off of the fracturing fluid into the surrounding formation, which will result in reduction in treating pressure.
{"title":"The Role of Micro-Proppants in Conductive Fracture Network Development","authors":"Dharmendra Kumar, R. A. González, A. Ghassemi","doi":"10.2118/194340-MS","DOIUrl":"https://doi.org/10.2118/194340-MS","url":null,"abstract":"\u0000 Micro-proppants use in hydraulic fracturing has had a significant impact on production and has led to a reduction of treating pressure and thus enhancement of the overall hydraulic fracturing treatment. A number of mechanisms have been proposed to explain the success of micro-proppants. However, the role of these proppants on increasing the conductivity of secondary natural fractures and fracture network development has not been well demonstrated. The objective of this paper is to explore and clarify the potential mechanisms involved in the success of micro-proppants. We study the transport and deposition of micro-proppants in propagating facture networks using an advanced simulator \"GeoFrac-3D\" that can consider irregular fracture geometries and intersection angles not limited to 90 degrees, thereby capturing realistic flow and proppant transport pathways and deposition sites. The method is 3D and fully couples fluid pressure to stresses and allows for dynamic modeling of 3D fracture propagation. Robust multiple 3D fracture propagation is considered using the displacement discontinuity method for the rock deformation and the finite element method for the fracture fluid flow. The pressure dependent leak-off of the fracturing fluid into the rock matrix/natural fracture system is considered. The proppant transport and deposition within the fracture is modeled by treating the mixture of fluid and proppant particles as slurry. The simulation results show that proppant transport into secondary fractures, and relatively less settling are the major factors in micro-proppant effectiveness. Proppant settling velocities and thus proppant distribution is affected by fluid velocity, micro-proppant size, fluid rheology, fracture aperture, hydraulic and natural fracture interaction and near wellbore tortuosity. The results demonstrates that the micro-proppants being smaller size particles have strong potential for the effective uniform proppant placement into the complex fractured unconventional reservoirs; hence, to increase their conductivity for the oil and gas in-flow. Additionally, as the micro-proppant can enter into the tight natural or secondary fractures, it will reduce pressure dependent leak-off of the fracturing fluid into the surrounding formation, which will result in reduction in treating pressure.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"40 12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129920046","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}
One of the most significant components of hydraulic fracturing modeling is the prediction of proppant transport in both the wellbore and fractures, as the resulting conductivity has a great impact on post treatment production. In multistage horizontal well treatments, the distribution of proppant between multiple perforation clusters has a substantial impact on treatment behaviors and results. If the proppant is not evenly distributed between the perforation clusters, the perforated intervals will not be equally stimulated. Only a few studies evaluating proppant transport in horizontal wellbores are found in the literature. This paper aims to investigate the parameters that have a large influence on the proppant settling in the wellbore and distribution of the proppants between perforation clusters, as well as providing insight into post-treatment flowback behaviors. The approach to this work uses a model of a horizontal wellbore with three perforation clusters at shot densities of 4 SPF with 90-degree phasing. Fresh water was used as a carrier fluid to transport the proppant in the horizontal pipe. Two different types of proppants, sand and ultra-light-weight ceramic, of varying mesh sizes were used. Two design parameters, injection rate and proppant concentration, have been varied throughout the experimental tests. The results from this work demonstrate that proppant settling velocity in the wellbore is different for each type of proppant. These differences are mainly due to the changes in the proppant concentration as well as the changes in the size and shape of proppant particles. The uneven proppant distribution between perforation clusters was mostly observed in cases where the density of proppnat was relatively high and at low flow rates. However, at high flow rates, the toe cluster received the largest amount of proppant. This occurs because the high flow rates near the first and second clusters prevent the proppant particles from turning into the perforation tunnels. The ultra-light weight ceramic shows the most even distribution between the perforation clusters since the density difference between the carrier fluid and the proppant particle is relatively low. The most significant finding is that the low viscosity fluid (fresh water) is not an effective transport system for larger particles with relatively high densities. The results obtained from this study can be used to improve the understanding of good practices of fracture stimulation flushing, as well as proppant distribution/deposition throughout the horizontal pipe during the fracture stimulation treatment and during flowback processes.
{"title":"Proppant Transport and Behavior in Horizontal Wellbores Using Low Viscosity Fluids","authors":"Faraj A. Ahmad, J. Miskimins","doi":"10.2118/194379-MS","DOIUrl":"https://doi.org/10.2118/194379-MS","url":null,"abstract":"\u0000 One of the most significant components of hydraulic fracturing modeling is the prediction of proppant transport in both the wellbore and fractures, as the resulting conductivity has a great impact on post treatment production. In multistage horizontal well treatments, the distribution of proppant between multiple perforation clusters has a substantial impact on treatment behaviors and results. If the proppant is not evenly distributed between the perforation clusters, the perforated intervals will not be equally stimulated. Only a few studies evaluating proppant transport in horizontal wellbores are found in the literature. This paper aims to investigate the parameters that have a large influence on the proppant settling in the wellbore and distribution of the proppants between perforation clusters, as well as providing insight into post-treatment flowback behaviors.\u0000 The approach to this work uses a model of a horizontal wellbore with three perforation clusters at shot densities of 4 SPF with 90-degree phasing. Fresh water was used as a carrier fluid to transport the proppant in the horizontal pipe. Two different types of proppants, sand and ultra-light-weight ceramic, of varying mesh sizes were used. Two design parameters, injection rate and proppant concentration, have been varied throughout the experimental tests.\u0000 The results from this work demonstrate that proppant settling velocity in the wellbore is different for each type of proppant. These differences are mainly due to the changes in the proppant concentration as well as the changes in the size and shape of proppant particles. The uneven proppant distribution between perforation clusters was mostly observed in cases where the density of proppnat was relatively high and at low flow rates. However, at high flow rates, the toe cluster received the largest amount of proppant. This occurs because the high flow rates near the first and second clusters prevent the proppant particles from turning into the perforation tunnels. The ultra-light weight ceramic shows the most even distribution between the perforation clusters since the density difference between the carrier fluid and the proppant particle is relatively low. The most significant finding is that the low viscosity fluid (fresh water) is not an effective transport system for larger particles with relatively high densities.\u0000 The results obtained from this study can be used to improve the understanding of good practices of fracture stimulation flushing, as well as proppant distribution/deposition throughout the horizontal pipe during the fracture stimulation treatment and during flowback processes.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130175881","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. I. Mohamed, M. Salah, Y. Coskuner, M. Ibrahim, C. Pieprzica, E. Ozkan
Diagnostic fracture injection test (DFIT) has become a valuable tool to quantify reservoir properties and hydraulic fracture characteristics. The pressure decline response of DFIT test reflects the process of fracture closure and the flow capacity of the reservoir. Previous literature provided simplifying assumptions to analysis the DFIT. However, operating companies often face challenges in the DFIT data interpretation due to several complex factors that result in non-ideal DFIT behavior and inconsistent results that lead to significant incorrect estimation of reservoir properties and fracturing parameters, including interaction with natural fractures, heterogeneous rock properties, variable storage, etc. The objective of this paper is to investigate the non-ideal DFIT behavior and factors that affect DFIT data and interpretations. The paper explained the flow regimes observed before closure and after closure during DFIT under complex reservoir conditions of natural fracture activation and fracture tip extension for reliable estimation of reservoir properties and fracture characteristic from actual field DFIT data. The overall fall-off period is analyzed using pressure transient analysis diagnostic plots and leak-off modeling. The transient pressure during the fall-off period is highly affected by the residual leak-off and continuing after flow that could disturb formation flow regimes during the test, affecting the ability to get correct pore pressure or formation permeability. The paper explains the various mechanisms affecting the pressure transient behavior during DFIT and adapts the wellbore and leak-off process to be able to observe reservoir response and get more realistic fracture characteristics and reservoir properties.
{"title":"Investigation of Non-Ideal Diagnostic Fracture Injection Tests Behavior in Unconventional Reservoirs","authors":"M. I. Mohamed, M. Salah, Y. Coskuner, M. Ibrahim, C. Pieprzica, E. Ozkan","doi":"10.2118/194332-MS","DOIUrl":"https://doi.org/10.2118/194332-MS","url":null,"abstract":"\u0000 Diagnostic fracture injection test (DFIT) has become a valuable tool to quantify reservoir properties and hydraulic fracture characteristics. The pressure decline response of DFIT test reflects the process of fracture closure and the flow capacity of the reservoir. Previous literature provided simplifying assumptions to analysis the DFIT. However, operating companies often face challenges in the DFIT data interpretation due to several complex factors that result in non-ideal DFIT behavior and inconsistent results that lead to significant incorrect estimation of reservoir properties and fracturing parameters, including interaction with natural fractures, heterogeneous rock properties, variable storage, etc.\u0000 The objective of this paper is to investigate the non-ideal DFIT behavior and factors that affect DFIT data and interpretations. The paper explained the flow regimes observed before closure and after closure during DFIT under complex reservoir conditions of natural fracture activation and fracture tip extension for reliable estimation of reservoir properties and fracture characteristic from actual field DFIT data. The overall fall-off period is analyzed using pressure transient analysis diagnostic plots and leak-off modeling. The transient pressure during the fall-off period is highly affected by the residual leak-off and continuing after flow that could disturb formation flow regimes during the test, affecting the ability to get correct pore pressure or formation permeability.\u0000 The paper explains the various mechanisms affecting the pressure transient behavior during DFIT and adapts the wellbore and leak-off process to be able to observe reservoir response and get more realistic fracture characteristics and reservoir properties.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"105 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116276117","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}
Karn Agarwal, Justin Kegel, B. Ballard, E. Lolon, M. Mayerhofer, L. Weijers, H. Melcher, Sarah Compton, P. Turner
As the Powder River Basin (PRB) development continues and more wells are drilled, identifying best completion practices is critical to economic success. This operator has completed several Turner horizontal wells drilled at 10,300-11,000 ft TVD using crosslinked gel with encouraging results. Although reservoir quality varies in the basin, the Turner interval is more than 30 ft thick in the area of interest (AOI) in Campbell County, Wyoming. In this area, production history matched permeability ranges from 0.005 to 0.1 mD, with pore pressure gradient from 0.55 to 0.64 psi/ft. Fracture modeling and production history matching/sensitivities were performed on a few horizontal wells. This paper discusses the results of this modeling and history matching, and it summarizes the evolution of Turner Formation fracture treatment designs, that were done by one operator to maximize the return on investment. The operator collected core data, open hole logs, and Diagnostic Fracture Injection Test (DFIT) data. The objectives of this study were to: a) determine reservoir parameters from DFIT, b) estimate fracture height growth, fracture half-length, and conductivity for Turner crosslinked gel fracs, c) determine the most appropriate perforation cluster or fracture spacing, as well as treatment rate, fluid/proppant loading, and proppant types/sizes based on the expected long-term production performance, d) compare the estimated production of cemented sleeve vs. plug-and-perf completions, and e) perform multivariate analysis of public production and completion data to compare with the detailed physical modeling. The results presented in this paper show well-performance predictions as a function of sleeve/perforation cluster spacing, treatment size, proppant type, mesh size, and pump rate. Implications for implementation of a certain treatment and completion design are discussed in detail.
{"title":"Evolving Completion Designs to Optimize Well Productivity from a Low Permeability Oil Sandstone Turner Reservoir in the Powder River Basin—One Operator's Experience","authors":"Karn Agarwal, Justin Kegel, B. Ballard, E. Lolon, M. Mayerhofer, L. Weijers, H. Melcher, Sarah Compton, P. Turner","doi":"10.2118/194350-ms","DOIUrl":"https://doi.org/10.2118/194350-ms","url":null,"abstract":"\u0000 As the Powder River Basin (PRB) development continues and more wells are drilled, identifying best completion practices is critical to economic success. This operator has completed several Turner horizontal wells drilled at 10,300-11,000 ft TVD using crosslinked gel with encouraging results. Although reservoir quality varies in the basin, the Turner interval is more than 30 ft thick in the area of interest (AOI) in Campbell County, Wyoming. In this area, production history matched permeability ranges from 0.005 to 0.1 mD, with pore pressure gradient from 0.55 to 0.64 psi/ft. Fracture modeling and production history matching/sensitivities were performed on a few horizontal wells. This paper discusses the results of this modeling and history matching, and it summarizes the evolution of Turner Formation fracture treatment designs, that were done by one operator to maximize the return on investment.\u0000 The operator collected core data, open hole logs, and Diagnostic Fracture Injection Test (DFIT) data. The objectives of this study were to: a) determine reservoir parameters from DFIT, b) estimate fracture height growth, fracture half-length, and conductivity for Turner crosslinked gel fracs, c) determine the most appropriate perforation cluster or fracture spacing, as well as treatment rate, fluid/proppant loading, and proppant types/sizes based on the expected long-term production performance, d) compare the estimated production of cemented sleeve vs. plug-and-perf completions, and e) perform multivariate analysis of public production and completion data to compare with the detailed physical modeling.\u0000 The results presented in this paper show well-performance predictions as a function of sleeve/perforation cluster spacing, treatment size, proppant type, mesh size, and pump rate. Implications for implementation of a certain treatment and completion design are discussed in detail.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"101 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133938738","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}
Junjing Zhang, D. Cramer, Jamie McEwen, M. White, K. Bjornen
Hydraulic fracturing treatments in shale infill wells are often impacted by existing parent well depletion and asymmetrical fracture growth. These phenomena can result in excessive load water production, deposition of proppant and deformation of casing in the parent well, and unbalanced stimulation of infill wells. This study determines the effectiveness of particulate materials for mitigating the above negative outcomes by bridging near the extremities of dominant fracture wings, i.e., far field diverting agents. Fracture propagation was modeled to characterize the width profile at fracture extremities in a depleted stress environment. A slotted-disk device was used to evaluate and optimize particulate blends for bridging slots representative of width near the fracture tip. Rheological tests replicating the downhole environment were used to formulate a system for transporting the diverting materials. Statistical analysis of 511 fracture hits at 30 parent wells was performed on key treatment indicators by the category of diverter type and post-hit parent well condition. Production trends of the influenced wells were compared to area-specific type curves and offset wells without diverter trials. Based on the simulation and testing results, two types of high-graded far field diverter systems were field tested in a shale play: dissolvable, extremely fine particulate mixed with 100 mesh sand, and mixtures of nominal 325 mesh silica flour and 100 mesh sand. Proppant dust collected at the fracturing site was also evaluated for replacing commercial silica flour. High-graded blends of the above diverting systems demonstrated superior frac-hit and productivity metrics as compared to the base case of not applying far field diverters. The silica flour and 100 mesh sand mixture performed on par with the significantly more expensive blend of dissolvable fine particulate and 100 mesh sand. Guar borate crosslinked gel was an effective carrying fluid for transporting diverting materials to the fracture extremities. Statistical analysis of fracture hit events shows that the application of far field diverters did not reduce the magnitude of pressure buildups during fracture hits; however, it significantly increases the post-hit pressure falloff rate at the parent wells. Based on the area-specific type curves, pumping far field diverters increased the P50 EUR by about 6% compared with the base cases of not applying diverters. For all the wells impacted by far field diverters, the infill wells saw larger benefits with an increment of P50 EUR by about 7% compared with the parent wells.
{"title":"Utilization of Far Field Diverters to Mitigate Parent and Infill Well Fracture Interaction in Shale Formations","authors":"Junjing Zhang, D. Cramer, Jamie McEwen, M. White, K. Bjornen","doi":"10.2118/194329-MS","DOIUrl":"https://doi.org/10.2118/194329-MS","url":null,"abstract":"\u0000 Hydraulic fracturing treatments in shale infill wells are often impacted by existing parent well depletion and asymmetrical fracture growth. These phenomena can result in excessive load water production, deposition of proppant and deformation of casing in the parent well, and unbalanced stimulation of infill wells. This study determines the effectiveness of particulate materials for mitigating the above negative outcomes by bridging near the extremities of dominant fracture wings, i.e., far field diverting agents.\u0000 Fracture propagation was modeled to characterize the width profile at fracture extremities in a depleted stress environment. A slotted-disk device was used to evaluate and optimize particulate blends for bridging slots representative of width near the fracture tip. Rheological tests replicating the downhole environment were used to formulate a system for transporting the diverting materials. Statistical analysis of 511 fracture hits at 30 parent wells was performed on key treatment indicators by the category of diverter type and post-hit parent well condition. Production trends of the influenced wells were compared to area-specific type curves and offset wells without diverter trials.\u0000 Based on the simulation and testing results, two types of high-graded far field diverter systems were field tested in a shale play: dissolvable, extremely fine particulate mixed with 100 mesh sand, and mixtures of nominal 325 mesh silica flour and 100 mesh sand. Proppant dust collected at the fracturing site was also evaluated for replacing commercial silica flour. High-graded blends of the above diverting systems demonstrated superior frac-hit and productivity metrics as compared to the base case of not applying far field diverters. The silica flour and 100 mesh sand mixture performed on par with the significantly more expensive blend of dissolvable fine particulate and 100 mesh sand. Guar borate crosslinked gel was an effective carrying fluid for transporting diverting materials to the fracture extremities.\u0000 Statistical analysis of fracture hit events shows that the application of far field diverters did not reduce the magnitude of pressure buildups during fracture hits; however, it significantly increases the post-hit pressure falloff rate at the parent wells. Based on the area-specific type curves, pumping far field diverters increased the P50 EUR by about 6% compared with the base cases of not applying diverters. For all the wells impacted by far field diverters, the infill wells saw larger benefits with an increment of P50 EUR by about 7% compared with the parent wells.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125118537","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}
Operators working with multiple stacked-pay reservoirs are challenged to optimize economic returns through their completion designs - not only in regards to horizontal well spacing, but also with vertical well spacing. Many of the popular Texas and New Mexico Wolfcamp formation sections exceed 1,000 feet in thickness and contain multiple hydrocarbon-rich benches. These benches and associated strata are complex mixtures of heterogenic geological factors such as weak/strong structural interfaces between facies, open/healed natural fractures, unpredictable fluid and pressure regimes, along with other lithological variables. Companies wrestle with the optimization of maximum hydrocarbon recovery within ever-present economic constraints when developing reservoir targeting strategies. This case study used multiple solid, oil-soluble tracers (OSTs) as an aid in reservoir characterization to determine optimal landing zones in the two unique Wolfcamp formations. This was accomplished by monitoring OST recovery data produced from grouping frac stages and reservoir zones over a 435 sampling day period. The two wells in this case study were intentionally drilled highly toe-up in order to cross all the potentially productive areas in two separate Wolfcamp benches; all stages were completed with the same stimulation design. The dynamics of the OST recovery provided insight into the variability of reservoir productivity within the Wolfcamp. Particular layers in the two wells exhibited initially high but transient OST recoveries, while other zones produced OSTs longer and more consistently. Using granular level tracer data in conjunction with other geoscience information, the operator was able to identify the formation layers having the highest potential for optimal production economics. This new methodology not only provided single-well placement optimization, but also important insights for future completions.
{"title":"Wellbore Placement Optimization Using Particulate Oil-Soluble Tracers","authors":"Marcus Jones, J. Larue","doi":"10.2118/194356-MS","DOIUrl":"https://doi.org/10.2118/194356-MS","url":null,"abstract":"\u0000 Operators working with multiple stacked-pay reservoirs are challenged to optimize economic returns through their completion designs - not only in regards to horizontal well spacing, but also with vertical well spacing. Many of the popular Texas and New Mexico Wolfcamp formation sections exceed 1,000 feet in thickness and contain multiple hydrocarbon-rich benches. These benches and associated strata are complex mixtures of heterogenic geological factors such as weak/strong structural interfaces between facies, open/healed natural fractures, unpredictable fluid and pressure regimes, along with other lithological variables. Companies wrestle with the optimization of maximum hydrocarbon recovery within ever-present economic constraints when developing reservoir targeting strategies.\u0000 This case study used multiple solid, oil-soluble tracers (OSTs) as an aid in reservoir characterization to determine optimal landing zones in the two unique Wolfcamp formations. This was accomplished by monitoring OST recovery data produced from grouping frac stages and reservoir zones over a 435 sampling day period. The two wells in this case study were intentionally drilled highly toe-up in order to cross all the potentially productive areas in two separate Wolfcamp benches; all stages were completed with the same stimulation design.\u0000 The dynamics of the OST recovery provided insight into the variability of reservoir productivity within the Wolfcamp. Particular layers in the two wells exhibited initially high but transient OST recoveries, while other zones produced OSTs longer and more consistently. Using granular level tracer data in conjunction with other geoscience information, the operator was able to identify the formation layers having the highest potential for optimal production economics. This new methodology not only provided single-well placement optimization, but also important insights for future completions.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"201 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115815502","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 presents an analysis of the interactions between stimulation design and two important geomechanical effects: the variation of least principal stress (Shmin) between lithological layers and the stress shadow effect that arises from simultaneously propagating adjacent hydraulic fractures. To demonstrate these interactions, hydraulic fracture propagation is modeled with a 5-layer geomechanical model representing an actual case study. The model consists of a profile of Shmin measurements made within, below and above the producing interval. The stress variations between layers leads to an overall upward fracture propagation and proppant largely above the producing interval. This is due to interactions between the pressure distribution within the fracture and the stress contrast in the multiple layers. A sensitivity study is done to investigate the complex 3-D couplings between geomechanical constraints and well completion design parameters such as landing zone, cluster spacing, perforation diameter, flow rate and proppant concentration. The simulation results demonstrate the importance of a well characterized stress stratigraphy for prediction of hydraulic fracture characteristics and optimization of operational parameters.
{"title":"Integrated Analysis of the Coupling Between Geomechanics and Operational Parameters to Optimize Hydraulic Fracture Propagation and Proppant Distribution","authors":"Ankush Singh, Shaochuan Xu, M. Zoback, M. McClure","doi":"10.2118/194323-MS","DOIUrl":"https://doi.org/10.2118/194323-MS","url":null,"abstract":"\u0000 This paper presents an analysis of the interactions between stimulation design and two important geomechanical effects: the variation of least principal stress (Shmin) between lithological layers and the stress shadow effect that arises from simultaneously propagating adjacent hydraulic fractures. To demonstrate these interactions, hydraulic fracture propagation is modeled with a 5-layer geomechanical model representing an actual case study. The model consists of a profile of Shmin measurements made within, below and above the producing interval. The stress variations between layers leads to an overall upward fracture propagation and proppant largely above the producing interval. This is due to interactions between the pressure distribution within the fracture and the stress contrast in the multiple layers. A sensitivity study is done to investigate the complex 3-D couplings between geomechanical constraints and well completion design parameters such as landing zone, cluster spacing, perforation diameter, flow rate and proppant concentration. The simulation results demonstrate the importance of a well characterized stress stratigraphy for prediction of hydraulic fracture characteristics and optimization of operational parameters.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"120 29","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131746120","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}
Heel-dominated treatment distribution among multiple perforation clusters is frequently observed in plug-and-perf stages, causing small propped surface areas, suboptimal production, and unexpected frac-hits. A multi-fracture simulator with a novel wellbore fluid and proppant transport model is applied to quantify treatment distribution among multiple perforation clusters in a plug-and-perf operation. A simulation Base Case is set up based on a field treatment design with four clusters. Simulation results show that the two toe-side clusters screened out early in the treatment and the two heel-side clusters were dominant. The simulated proppant placement is consistent with DAS observations. The impact of different perforating strategies and pumping schedules on final treatment distribution is investigated. Two criteria are defined that quantify the proppant distribution and fracture area: the Weighted Average (WA) and Standard Deviation (SD) of the final fluid and proppant distribution, as well as the Hydraulic and Propped Surface Area (HSA and PSA) of the created fractures. An optimum plug-and-perf design is defined as one that minimizes the SD of the treatment distribution among perforation clusters and maximizes the PSA. Both perforating strategy and pumping schedule are found to affect the final treatment distribution significantly, and uniform treatment distribution is shown to create more PSA. Fewer perforations-per-cluster were found to promote uniform fluid and proppant placement. Other helpful strategies include reducing the number of perforations near the heel, using small, lightweight proppant and so on. The stress shadow effect is accounted for using the Displacement Discontinuity Method (DDM) and was found to play a smaller role than perforation friction and proppant inertia in most cases. An automated process is developed to optimize plug-and-perf completion design with multiple decision variables using a Genetic Algorithm. Thirteen parameters are optimized simultaneously. The optimal design solution creates an almost even treatment distribution and more than doubled the PSA compared to the Base Case. The multi-fracture model presented in this paper provides a way to quantify fluid and proppant distribution for any perforating strategy and pumping schedule and provides more insights of the physics relevant to plug-and-perf treatment distribution. The perforation and pumping schedule recommendations presented in this paper provide directional guidance to design a fracturing job of balanced treatment distribution and large propped surface area.
{"title":"Optimization of Plug-and-Perf Completions for Balanced Treatment Distribution and Improved Reservoir Contact","authors":"S. S. Yi, Chu-Hsiang Wu, M. Sharma","doi":"10.2118/194360-MS","DOIUrl":"https://doi.org/10.2118/194360-MS","url":null,"abstract":"\u0000 Heel-dominated treatment distribution among multiple perforation clusters is frequently observed in plug-and-perf stages, causing small propped surface areas, suboptimal production, and unexpected frac-hits.\u0000 A multi-fracture simulator with a novel wellbore fluid and proppant transport model is applied to quantify treatment distribution among multiple perforation clusters in a plug-and-perf operation. A simulation Base Case is set up based on a field treatment design with four clusters. Simulation results show that the two toe-side clusters screened out early in the treatment and the two heel-side clusters were dominant. The simulated proppant placement is consistent with DAS observations.\u0000 The impact of different perforating strategies and pumping schedules on final treatment distribution is investigated. Two criteria are defined that quantify the proppant distribution and fracture area: the Weighted Average (WA) and Standard Deviation (SD) of the final fluid and proppant distribution, as well as the Hydraulic and Propped Surface Area (HSA and PSA) of the created fractures. An optimum plug-and-perf design is defined as one that minimizes the SD of the treatment distribution among perforation clusters and maximizes the PSA.\u0000 Both perforating strategy and pumping schedule are found to affect the final treatment distribution significantly, and uniform treatment distribution is shown to create more PSA. Fewer perforations-per-cluster were found to promote uniform fluid and proppant placement. Other helpful strategies include reducing the number of perforations near the heel, using small, lightweight proppant and so on. The stress shadow effect is accounted for using the Displacement Discontinuity Method (DDM) and was found to play a smaller role than perforation friction and proppant inertia in most cases.\u0000 An automated process is developed to optimize plug-and-perf completion design with multiple decision variables using a Genetic Algorithm. Thirteen parameters are optimized simultaneously. The optimal design solution creates an almost even treatment distribution and more than doubled the PSA compared to the Base Case.\u0000 The multi-fracture model presented in this paper provides a way to quantify fluid and proppant distribution for any perforating strategy and pumping schedule and provides more insights of the physics relevant to plug-and-perf treatment distribution. The perforation and pumping schedule recommendations presented in this paper provide directional guidance to design a fracturing job of balanced treatment distribution and large propped surface area.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"59 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130619065","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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