P. Seth, Ripudaman Manchanda, Shuang Zheng, Deepen P. Gala, M. Sharma
In conventional reservoirs, pressure communication between wells is ascribed to hydraulic diffusion through the rock matrix. In this work we show that in unconventional (low-permeability) reservoirs, pressure communication due to matrix diffusion is insignificant, and pressure changes observed in an offset monitor well during stimulation of a nearby well are primarily due to poroelastic effects. We quantify the pressure transient response observed through external downhole gauges in monitor wells, when an adjacent well is fractured. Our goal is to model this poroelastic response and obtain important reservoir mechanical and flow properties, as well as hydraulic fracture geometry. A fully-coupled, 3-D, poroelastic, compositional, reservoir-fracturing simulator was used to simulate dynamic fracture propagation from a treatment well and compute the resulting pressure changes at one or more monitor wells. The pressure transient response is shown to depend on the reservoir fluid and formation properties (permeability, Biot's coefficient, stress anisotropy) and reservoir mechanical properties (Young's modulus). The impacts of hydraulic diffusivity versus poroelastic pressure response are compared. Type curves are presented that allow the pressure transient response to be interpreted for any general reservoir and well configuration. These type curves can be used to obtain reservoir mechanical and flow properties and the geometry of the propagating fracture. We show that modeling the fracture as a discrete discontinuity (as opposed to high permeability grid- blocks) is essential to obtain good agreement with field pressure observations. The pressure observed in the monitor well first decreases and then increases over time as the growing fracture interacts poroelastically with the monitor well. It is shown that this pressure transient signature is dominated by poroelastic effects for most unconventional reservoirs. The poroelastic response depends on the reservoir fluid type (gas, oil) and the mechanical properties of the reservoir. To simplify the quantitative interpretation of the pressure transient response we have developed type curves that allow us to determine the rock elastic and flow properties and the evolving geometry of the propagating fracture. If multiple monitor wells are utilized, the relative communication between different vertically separated reservoirs and the effects of the altered stresses in the reservoir induced by prior production / depletion can clearly be observed. We present, for the first time, general type curves for interpreting the pressure transient response of monitoring wells when an adjacent well is being fractured. Our representation of the propagating hydraulic fracture as an explicit discontinuity in a poroelastic medium is crucial to capture the poroelastic response observed. The impacts of reservoir heterogeneity (layering), fracture geometry, reservoir mechanical properties, hydraulic diffusivity and prior dep
{"title":"Poroelastic Pressure Transient Analysis: A New Method for Interpretation of Pressure Communication Between Wells During Hydraulic Fracturing","authors":"P. Seth, Ripudaman Manchanda, Shuang Zheng, Deepen P. Gala, M. Sharma","doi":"10.2118/194358-MS","DOIUrl":"https://doi.org/10.2118/194358-MS","url":null,"abstract":"\u0000 In conventional reservoirs, pressure communication between wells is ascribed to hydraulic diffusion through the rock matrix. In this work we show that in unconventional (low-permeability) reservoirs, pressure communication due to matrix diffusion is insignificant, and pressure changes observed in an offset monitor well during stimulation of a nearby well are primarily due to poroelastic effects. We quantify the pressure transient response observed through external downhole gauges in monitor wells, when an adjacent well is fractured. Our goal is to model this poroelastic response and obtain important reservoir mechanical and flow properties, as well as hydraulic fracture geometry.\u0000 A fully-coupled, 3-D, poroelastic, compositional, reservoir-fracturing simulator was used to simulate dynamic fracture propagation from a treatment well and compute the resulting pressure changes at one or more monitor wells. The pressure transient response is shown to depend on the reservoir fluid and formation properties (permeability, Biot's coefficient, stress anisotropy) and reservoir mechanical properties (Young's modulus). The impacts of hydraulic diffusivity versus poroelastic pressure response are compared. Type curves are presented that allow the pressure transient response to be interpreted for any general reservoir and well configuration. These type curves can be used to obtain reservoir mechanical and flow properties and the geometry of the propagating fracture.\u0000 We show that modeling the fracture as a discrete discontinuity (as opposed to high permeability grid- blocks) is essential to obtain good agreement with field pressure observations. The pressure observed in the monitor well first decreases and then increases over time as the growing fracture interacts poroelastically with the monitor well. It is shown that this pressure transient signature is dominated by poroelastic effects for most unconventional reservoirs. The poroelastic response depends on the reservoir fluid type (gas, oil) and the mechanical properties of the reservoir. To simplify the quantitative interpretation of the pressure transient response we have developed type curves that allow us to determine the rock elastic and flow properties and the evolving geometry of the propagating fracture. If multiple monitor wells are utilized, the relative communication between different vertically separated reservoirs and the effects of the altered stresses in the reservoir induced by prior production / depletion can clearly be observed.\u0000 We present, for the first time, general type curves for interpreting the pressure transient response of monitoring wells when an adjacent well is being fractured. Our representation of the propagating hydraulic fracture as an explicit discontinuity in a poroelastic medium is crucial to capture the poroelastic response observed. The impacts of reservoir heterogeneity (layering), fracture geometry, reservoir mechanical properties, hydraulic diffusivity and prior dep","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"102 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":"116645579","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}
It is a well-established principle that rock properties affect fracture geometry. This paper investigates the relationships between fracture responses observed during completion operations and rock properties that are obtained during the drilling of a well. It will also attempt to quantify the benefits of designing completions based on these rock properties. Four pairs of wells adjacent to one another are included the study. Each pair of wells includes one well with a completion design based on the operator's baseline guidelines, and one well with the perforation depths and stage boundaries selected from rock strength information derived from drilling data. The fracture treatment pressure responses are correlated to the rock properties, and the two completion methodologies are compared to determine whether there is an operational or production benefit to this completion methodology. The results of the study show a clear and distinctive difference between treatment responses in wells whose completions are based upon drilling-derived rock properties, and those that did not. The most striking of these differences is that instantaneous shut-in pressures were higher in wells where completion stages and perforation depths were selected based on rock properties, without corresponding increases in average treatment pressures. This is likely an indication of improved fracture containment (higher net pressures) which would be expected with an equitable fluid distribution among perforation clusters. Further to this, the analysis allowed for the identification of rock parameters associated with increased risk of excessive height growth which is independent of the completion methodology used. Production comparisons will be included to support the findings. The result of this work is a clear path forward to improving future wells by understanding how rock properties and completion design are related to fracture height growth. This allows for a re-evaluation of future drilling targets and the modification of treatment designs to maintain the maximum amount of fracture energy within the target zone. It will also help to provide further evidence that completions can be improved through the optimized placements of stage boundaries and perforation clusters. This paper will present a new analytical workflow that combines the use of drilling-derived rock properties and fracture treatment responses to gain important insights and drive future decisions for both the drilling and completion processes.
{"title":"Improving Hydraulic Fracturing Performance and Interpreting Fracture Geometry Based on Drilling Measurements","authors":"R. Downie, D. Daves","doi":"10.2118/194357-MS","DOIUrl":"https://doi.org/10.2118/194357-MS","url":null,"abstract":"\u0000 It is a well-established principle that rock properties affect fracture geometry. This paper investigates the relationships between fracture responses observed during completion operations and rock properties that are obtained during the drilling of a well. It will also attempt to quantify the benefits of designing completions based on these rock properties.\u0000 Four pairs of wells adjacent to one another are included the study. Each pair of wells includes one well with a completion design based on the operator's baseline guidelines, and one well with the perforation depths and stage boundaries selected from rock strength information derived from drilling data. The fracture treatment pressure responses are correlated to the rock properties, and the two completion methodologies are compared to determine whether there is an operational or production benefit to this completion methodology.\u0000 The results of the study show a clear and distinctive difference between treatment responses in wells whose completions are based upon drilling-derived rock properties, and those that did not. The most striking of these differences is that instantaneous shut-in pressures were higher in wells where completion stages and perforation depths were selected based on rock properties, without corresponding increases in average treatment pressures. This is likely an indication of improved fracture containment (higher net pressures) which would be expected with an equitable fluid distribution among perforation clusters. Further to this, the analysis allowed for the identification of rock parameters associated with increased risk of excessive height growth which is independent of the completion methodology used. Production comparisons will be included to support the findings.\u0000 The result of this work is a clear path forward to improving future wells by understanding how rock properties and completion design are related to fracture height growth. This allows for a re-evaluation of future drilling targets and the modification of treatment designs to maintain the maximum amount of fracture energy within the target zone. It will also help to provide further evidence that completions can be improved through the optimized placements of stage boundaries and perforation clusters.\u0000 This paper will present a new analytical workflow that combines the use of drilling-derived rock properties and fracture treatment responses to gain important insights and drive future decisions for both the drilling and completion 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":"130858693","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}
During hydraulic fracturing treatments, proppants often settle near-wellbore in low viscosity fracturing fluids (e.g., slick water) and leave a large fractured surface unpropped. Poor placement of proppant could lead to a loss of fracture conductivity and undermine the productivity of shale wells. In addition, lots of microfractures are too narrow to accommodate commercial proppants and would close during production. In this study, a hydro-thermal reaction is proposed to generate hydroxyapatite crystals on calcite-rich shale surface to act as in-situ proppants to improve fracture conductivity. First, batch experiments were conducted in both low salinity frac water and seawater brine. Crystals were generated in both low and high salinity (and hard) brines. The crystals grew to several hundred microns and tended to form along calcite-rich layers, according to SEM image analysis. The hardness data showed that properly designed formulations could avoid the shale softening effect. Second, reactive flow experiments were performed to evaluate fracture conductivity change after chemical treatment. A typical 3-10 times increase in post fracture conductivity was observed for both reservoir and outcrop shale samples.
{"title":"Generation of In-Situ Proppant through Hydro-Thermal Reactions","authors":"Songyang Tong, Chammi Miller, K. Mohanty","doi":"10.2118/194320-MS","DOIUrl":"https://doi.org/10.2118/194320-MS","url":null,"abstract":"\u0000 During hydraulic fracturing treatments, proppants often settle near-wellbore in low viscosity fracturing fluids (e.g., slick water) and leave a large fractured surface unpropped. Poor placement of proppant could lead to a loss of fracture conductivity and undermine the productivity of shale wells. In addition, lots of microfractures are too narrow to accommodate commercial proppants and would close during production. In this study, a hydro-thermal reaction is proposed to generate hydroxyapatite crystals on calcite-rich shale surface to act as in-situ proppants to improve fracture conductivity. First, batch experiments were conducted in both low salinity frac water and seawater brine. Crystals were generated in both low and high salinity (and hard) brines. The crystals grew to several hundred microns and tended to form along calcite-rich layers, according to SEM image analysis. The hardness data showed that properly designed formulations could avoid the shale softening effect. Second, reactive flow experiments were performed to evaluate fracture conductivity change after chemical treatment. A typical 3-10 times increase in post fracture conductivity was observed for both reservoir and outcrop shale samples.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"23 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":"122073243","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}
Shale hydrocarbon production has become an increasingly important part of global oil and gas supply during the past decade. The life of projects in unconventional plays, such as shale oil and gas, tight oil and gas, coal bed methane etc., heavily depends on the Estimated Ultimate Recovery (EUR). However, the correlation to predict EUR in conventional plays becomes invalid for unconventional plays, which significantly affects the economics of relevant unconventional projects. The objective of this paper is to investigate the correlations between EUR and petrophysics/engineering/production parameters by data regression and interpolation analysis via big data mining from Eagle Ford. Furthermore, a 4-D interpolated EUR database and EUR prediction models are established based on the relevant regression and interpolation results. This study not only helps us understand the physics behind EUR prediction in unconventional plays, but also facilitates determining the viability of projects in unconventional formations from a big data perspective. In this study, petrophysics/engineering/production data from 4067 wells in Eagle Ford is summarized for analysis. Firstly, a sensitivity analysis is carried out to determine the most sensitive petrophysics and engineering controlling factors. In particular, the physics behind the EUR predictions is discussed in details. Following it, the 2-D nonlinear regression and the multivariate linear regression are applied to evaluate the relationship between EUR and engineering/production data. In addition, a 4-D interpolated EUR database is established to predict EUR based on the petrophysics parameters. The applied nonlinear multivariate interpolation methodology is the Triangulated Irregular Network based Nearest Interpolation Method (3-D). Finally, the 4-D interpolated EUR database are applied to several wells in the Eagle Ford to test its accuracy, confidence and reliability. Based on the sensitivity analysis results, Vitrinite Reflectance Equivalent (VRE), Total Organic Carbon (TOC) and Resource Density (porosity, hydrocarbon saturation and gross formation thickness) are the most sensitive and important parameters in Eagle Ford shale formation. Based on the data-mining results, effective lateral length has a positive monotonic relation with EUR; EUR increases with more proppant weight and higher true vertical depth. Frac stage and perf per cluster do not have a strong correlation with EUR. In addition, azimuth has a vague relation with EUR while drilling along the North-South orientation is the safest approach in Eagle Ford Shale. The physics behind the correlations is analyzed and discussed in detail. Finally, several DCA EURs of wells from Eagle Ford are used to test the established 4-D interpolated EUR database, and the study results show that the relative errors in EUR predictions are within 30%, indicating that the methodology in this study has great potentials for unlocking more reserves economically in shale
{"title":"A Big Data Study: Correlations Between EUR and Petrophysics/Engineering/Production Parameters in Shale Formations by Data Regression and Interpolation Analysis","authors":"Yu Liang, Lulu Liao, Ye Guo","doi":"10.2118/194381-MS","DOIUrl":"https://doi.org/10.2118/194381-MS","url":null,"abstract":"\u0000 Shale hydrocarbon production has become an increasingly important part of global oil and gas supply during the past decade. The life of projects in unconventional plays, such as shale oil and gas, tight oil and gas, coal bed methane etc., heavily depends on the Estimated Ultimate Recovery (EUR). However, the correlation to predict EUR in conventional plays becomes invalid for unconventional plays, which significantly affects the economics of relevant unconventional projects. The objective of this paper is to investigate the correlations between EUR and petrophysics/engineering/production parameters by data regression and interpolation analysis via big data mining from Eagle Ford. Furthermore, a 4-D interpolated EUR database and EUR prediction models are established based on the relevant regression and interpolation results. This study not only helps us understand the physics behind EUR prediction in unconventional plays, but also facilitates determining the viability of projects in unconventional formations from a big data perspective.\u0000 In this study, petrophysics/engineering/production data from 4067 wells in Eagle Ford is summarized for analysis. Firstly, a sensitivity analysis is carried out to determine the most sensitive petrophysics and engineering controlling factors. In particular, the physics behind the EUR predictions is discussed in details. Following it, the 2-D nonlinear regression and the multivariate linear regression are applied to evaluate the relationship between EUR and engineering/production data. In addition, a 4-D interpolated EUR database is established to predict EUR based on the petrophysics parameters. The applied nonlinear multivariate interpolation methodology is the Triangulated Irregular Network based Nearest Interpolation Method (3-D). Finally, the 4-D interpolated EUR database are applied to several wells in the Eagle Ford to test its accuracy, confidence and reliability.\u0000 Based on the sensitivity analysis results, Vitrinite Reflectance Equivalent (VRE), Total Organic Carbon (TOC) and Resource Density (porosity, hydrocarbon saturation and gross formation thickness) are the most sensitive and important parameters in Eagle Ford shale formation. Based on the data-mining results, effective lateral length has a positive monotonic relation with EUR; EUR increases with more proppant weight and higher true vertical depth. Frac stage and perf per cluster do not have a strong correlation with EUR. In addition, azimuth has a vague relation with EUR while drilling along the North-South orientation is the safest approach in Eagle Ford Shale. The physics behind the correlations is analyzed and discussed in detail. Finally, several DCA EURs of wells from Eagle Ford are used to test the established 4-D interpolated EUR database, and the study results show that the relative errors in EUR predictions are within 30%, indicating that the methodology in this study has great potentials for unlocking more reserves economically in shale","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"8 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":"130705990","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In the Midland Basin, infill wells have high potential of experiencing well-to-well fracture interference or "frac hits". Rock stress alteration around parent wells affect child fracture interactions thus impacting completion effectiveness, well productivity, and well spacing. Endeavor Energy Resources (EER) had a unique opportunity to study parent (hereafter referred to as primary) and child (hereafter referred as infill or active well) interactions and the effects of producing vertical wells on fracture behavior. Two active horizontal wells cross both developed and undeveloped acreage where half of each well is an infill between existing horizontals and the other half is in undeveloped acreage with two existing vertical wells. Operation-driven fracture fluid movement was analyzed by monitoring the treating pressure of the two active wells being completed; and the pressure response of nine shut-in offset horizontals, and ten vertical wells. The measurements and analysis establish a base case to which future fracture- interference monitoring techniques will be compared and later mitigation and intervention. Primary horizontal wells offsetting two infill wells were monitored with wellhead pressure sensors and ESP downhole pressure sensors. Two vertical observation wells (VOW) between the new infill wells were fitted with wellhead wireless pressure sensors and bottomhole pressure gauges. During this area's original development in 2016, vertical wells located hundreds to thousands of feet from the active fraccing well experienced frac interaction. To measure the severity of the invasive fluid movement, wellhead sensors were installed on vertical wells one-half mile, one mile, and one- and-a-half miles away from the active wells. Water and oil tracers were used in the two active infill wells to study fracture fluid movement in conjunction with pressure data. In the unexploited section, the observation horizontal wells’ pressure responses were examined for fracture shadowing (inter-well poro-elastic response) stress shadowing (intra-well dynamic active fracture interactions (DAFI) (Daneshy, 2018), and fracture-to-fracture connections both temporary and long term. As fracture operations approached a primary vertical well (depleted zones), frac fluid was distributed vertically among multiple horizons through perforations in the existing well and laterally into horizontal primary wells. The three laterally closest primary wells, completed in three different intervals, had similar strong pressure responses to a common active stage suggesting a geologic cause. As for the vertical observation wells, fluid incursion was observed over 8400 feet away. The vertical wells between the two horizontal active infills had a 200 ft. to 400 ft. radius of pressure disturbance as the frac stages approached their locations. Fracture stages within the 200 ft. to 400 ft. radius caused direct hits while stages outside this radius caused mild pressure increases identified
在米德兰盆地，充填井发生井间裂缝干扰或“裂缝冲击”的可能性很大。母井周围的岩石应力变化会影响子裂缝的相互作用，从而影响完井效率、井产能和井距。Endeavor Energy Resources (EER)有一个独特的机会来研究母井(以下称为主井)和子井(以下称为填充井或活动井)的相互作用，以及生产直井对裂缝行为的影响。两个活跃的水平井穿过已开发区域和未开发区域，其中每口井的一半是在现有水平段之间的填充，另一半是在未开发区域，有两个现有的直井。通过监测两口正在完井的处理压力，分析了作业驱动的压裂液运动;9口关井邻井水平井和10口直井的压力响应。这些测量和分析为将来的裂缝干扰监测技术以及后续的缓解和干预奠定了基础。利用井口压力传感器和ESP井下压力传感器对相邻两口充填井的主水平井进行监测。新填充井之间的两口垂直观测井(VOW)安装了井口无线压力传感器和井底压力计。在2016年该地区最初的开发过程中，距离主动跟踪井数百至数千英尺的直井经历了压裂相互作用。为了测量侵入性流体运动的严重程度，井口传感器被安装在距离活动井1.5英里、1英里和1.5英里的直井上。水示踪剂和油示踪剂被用于两口活跃的填充井中，结合压力数据研究压裂液的运动。在未开发段，对观察水平井的压力响应进行了裂缝阴影(井间孔隙弹性响应)、应力阴影(井内动态主动裂缝相互作用(DAFI)) (Daneshy, 2018)以及裂缝间的临时和长期连接。当压裂作业接近主直井(枯竭区)时，压裂液通过现有井的射孔垂直分布在多个层位，并横向分布到水平主井中。在三个不同的井段完成的三口横向距离最近的主井，在一个共同的活动阶段有相似的强烈压力响应，这表明有地质原因。在垂直观察井中，在8400英尺处观察到流体侵入。在两个水平活动充填体之间的直井，当压裂段接近它们的位置时，压力扰动半径为200英尺至400英尺。在200 ~ 400英尺半径范围内的压裂段会产生直接冲击，而在此半径之外的压裂段会产生轻微的压力增加，即裂缝阴影。Midland盆地的遗留油田通常由生产(HBP)持有。因此，水平开发可能围绕现有的直井进行。许多公司面临的另一种情况是，在初级油田水平开发后，将土地重新开发成未开发的油田。通过分享这个案例研究，作者希望其他面临这些共同问题的运营商能够利用这些学习。忽视潜在裂缝干扰和水力连接的重要性可能导致裂缝无效，降低增产储层体积(SRV)，或井共用SRV。最终，这意味着资源采收率降低，这可能发生在主井和填充井中，也可能同时发生。
{"title":"Evaluating the Impact of Frac Communication Between Parent, Child, and Vertical Wells in the Midland Basin Lower Spraberry and Wolfcamp Reservoirs","authors":"R. Scherz, M. Rainbolt, Y. Pradhan, Wei Tian","doi":"10.2118/194349-MS","DOIUrl":"https://doi.org/10.2118/194349-MS","url":null,"abstract":"\u0000 In the Midland Basin, infill wells have high potential of experiencing well-to-well fracture interference or \"frac hits\". Rock stress alteration around parent wells affect child fracture interactions thus impacting completion effectiveness, well productivity, and well spacing. Endeavor Energy Resources (EER) had a unique opportunity to study parent (hereafter referred to as primary) and child (hereafter referred as infill or active well) interactions and the effects of producing vertical wells on fracture behavior. Two active horizontal wells cross both developed and undeveloped acreage where half of each well is an infill between existing horizontals and the other half is in undeveloped acreage with two existing vertical wells. Operation-driven fracture fluid movement was analyzed by monitoring the treating pressure of the two active wells being completed; and the pressure response of nine shut-in offset horizontals, and ten vertical wells. The measurements and analysis establish a base case to which future fracture- interference monitoring techniques will be compared and later mitigation and intervention.\u0000 Primary horizontal wells offsetting two infill wells were monitored with wellhead pressure sensors and ESP downhole pressure sensors. Two vertical observation wells (VOW) between the new infill wells were fitted with wellhead wireless pressure sensors and bottomhole pressure gauges. During this area's original development in 2016, vertical wells located hundreds to thousands of feet from the active fraccing well experienced frac interaction. To measure the severity of the invasive fluid movement, wellhead sensors were installed on vertical wells one-half mile, one mile, and one- and-a-half miles away from the active wells. Water and oil tracers were used in the two active infill wells to study fracture fluid movement in conjunction with pressure data.\u0000 In the unexploited section, the observation horizontal wells’ pressure responses were examined for fracture shadowing (inter-well poro-elastic response) stress shadowing (intra-well dynamic active fracture interactions (DAFI) (Daneshy, 2018), and fracture-to-fracture connections both temporary and long term. As fracture operations approached a primary vertical well (depleted zones), frac fluid was distributed vertically among multiple horizons through perforations in the existing well and laterally into horizontal primary wells. The three laterally closest primary wells, completed in three different intervals, had similar strong pressure responses to a common active stage suggesting a geologic cause. As for the vertical observation wells, fluid incursion was observed over 8400 feet away. The vertical wells between the two horizontal active infills had a 200 ft. to 400 ft. radius of pressure disturbance as the frac stages approached their locations. Fracture stages within the 200 ft. to 400 ft. radius caused direct hits while stages outside this radius caused mild pressure increases identified","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"39 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":"121805106","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 novel DFIT simulator comprising a 3D hydraulic fracturing model seamlessly coupled within one software with reservoir flow and geomechanical modeling is described and used to numerically analyze DFITs in unconventional reservoirs. This workflow involves history matching treatment or injection pressures (fracture propagation) and shut-in (fracture closure) pressures consistent with 3D growth of hydraulic fractures in the presence of pressure dependent leak-off. These are the same fundamental processes which characterize Dynamic Stimulated Reservoir Volume or DSRV growth (Sen et al., 2018, Min et al., 2018) and DFITs can therefore be used to get a better early prognosis on the potential of DSRV growth in a tight reservoir. This modular DFIT simulator iteratively couples a finite-difference reservoir simulation with a finite- element geomechanical modeling within one software and can therefore maintain important consistencies between fracture opening, propagation, closure and the stress dependent leak-off and permeability evolution inside the induced dynamic SRV. Both DFIT injection and closure processes are numerically modeled - and depending on which model parameters we choose to fix and which we perturb, we can preemptively estimate the potential for a successful stimulation and its possible dimensions. This estimate can be obtained at the early stages of a field /section development, before embarking on major drilling and completion campaigns, even in the absence of substantial production data. And it provides guidance for optimizing major fracturing design and well spacing. This approach is not reliant or bound by the assumptions underlying widely-used analytical DFIT analyzing methods, and is therefore more flexible and better captures the physics of stimulation in unconventional reservoirs. An early understanding of the key geomechanical metrics defining unconventional reservoir enhancement (DSRV effectiveness) allows us to build a directional relationship between fracturing parameters and post-fracture production without the need for an extended record of production trends. This speeds up the continuous learning and adaptive process of completion optimization involving pumped volumes, cluster spacing and well landing zones.
{"title":"Numerical Simulation of DFITs Within a Coupled Reservoir Flow and Geomechanical Simulator - Insights Into Completions Optimization","authors":"L. Ji, V. Sen, K. Min, R. Sullivan","doi":"10.2118/194352-MS","DOIUrl":"https://doi.org/10.2118/194352-MS","url":null,"abstract":"\u0000 A novel DFIT simulator comprising a 3D hydraulic fracturing model seamlessly coupled within one software with reservoir flow and geomechanical modeling is described and used to numerically analyze DFITs in unconventional reservoirs. This workflow involves history matching treatment or injection pressures (fracture propagation) and shut-in (fracture closure) pressures consistent with 3D growth of hydraulic fractures in the presence of pressure dependent leak-off. These are the same fundamental processes which characterize Dynamic Stimulated Reservoir Volume or DSRV growth (Sen et al., 2018, Min et al., 2018) and DFITs can therefore be used to get a better early prognosis on the potential of DSRV growth in a tight reservoir.\u0000 This modular DFIT simulator iteratively couples a finite-difference reservoir simulation with a finite- element geomechanical modeling within one software and can therefore maintain important consistencies between fracture opening, propagation, closure and the stress dependent leak-off and permeability evolution inside the induced dynamic SRV. Both DFIT injection and closure processes are numerically modeled - and depending on which model parameters we choose to fix and which we perturb, we can preemptively estimate the potential for a successful stimulation and its possible dimensions.\u0000 This estimate can be obtained at the early stages of a field /section development, before embarking on major drilling and completion campaigns, even in the absence of substantial production data. And it provides guidance for optimizing major fracturing design and well spacing.\u0000 This approach is not reliant or bound by the assumptions underlying widely-used analytical DFIT analyzing methods, and is therefore more flexible and better captures the physics of stimulation in unconventional reservoirs. An early understanding of the key geomechanical metrics defining unconventional reservoir enhancement (DSRV effectiveness) allows us to build a directional relationship between fracturing parameters and post-fracture production without the need for an extended record of production trends. This speeds up the continuous learning and adaptive process of completion optimization involving pumped volumes, cluster spacing and well landing zones.","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":"129550991","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}
Fan Zhang, I. Saputra, S. Parsegov, Imad A. Adel, D. Schechter
Field observations and laboratory experiments have proven the possibility of production enhancement of shale oil wells through surfactant addition into completion fluid and perhaps, surfactant injection for EOR. This study numerically upscaled laboratory data for multi-stage hydraulic fracturing treatment and injection process proposed for the Wolfcamp formation. A combination of rock mechanic and reservoir numerical modeling was used to approximate the field-scale performance of both techniques. Novel completion fluid formulations and optimum surfactant injection schemes were designed, based on actual completion and production data. Surfactant-Assisted Spontaneous Imbibition (SASI) experiments data for two surfactants investigated on the core-scale were upscaled to model production response of a hydraulically fractured well in Upton County, Texas, with realistic fracture geometry and conductivity. Core plugs were saturated and aged with their corresponding oil to restore the original oil saturation. Contact angle, interfacial tension (IFT), and zeta-potential were measured to investigate the role of capillary pressure for surfactant tests. We use a dual-porosity compositional model to determine the surfactant transport and adsorption. With the proposed methodology, we show that lateral heterogeneity may limit both hydraulic fracture propagation and uniform distribution of EOR fluids, which cannot be ignored for the sake of simplicity. The primary production mechanism of aqueous phase surfactant EOR is wettability alteration and the reduction of IFT. Laboratory-scale SASI experimental results revealed that 2 gpt of surfactant solutions recovered up to 30% of the original oil in place (OOIP), whereas water alone recovered 10%. Capillary pressure and relative permeability curves were generated by scaling group analysis and history-matching the results of imbibition experiments on CT-generated core-scale model. On the next step, these curves were applied to surfactant completion and injection simulation models. The field-scale model was achieved from history-matching actual well production data. We tested different soak times, injection pressure, and number of cycles in surfactant injection simulations to provide an optimum design for this scheme. Simulation results indicated that surfactant injection has further potential for higher recovery factor in addition to the incremental Estimated Ultimate Recovery (EUR) observed with application of surfactant as a completion fluid alone. Also, we investigated water-injection after primary depletion (water without surfactant) to provide another possible method for unconventional liquid reservoirs (ULR). Instead of referring to Huff-n-Puff which implies gas injection, in this manuscript we use the terminology Multi-Cycle Surfactant-Assisted Spontaneous Imbibition (MC-SASI) to describe surfactant Huff-n-Puff for EOR. This paper provides a complete workflow on SASI-EOR that has been evaluated in laborato
{"title":"Experimental and Numerical Studies of EOR for the Wolfcamp Formation by Surfactant Enriched Completion Fluids and Multi-Cycle Surfactant Injection","authors":"Fan Zhang, I. Saputra, S. Parsegov, Imad A. Adel, D. Schechter","doi":"10.2118/194325-MS","DOIUrl":"https://doi.org/10.2118/194325-MS","url":null,"abstract":"\u0000 Field observations and laboratory experiments have proven the possibility of production enhancement of shale oil wells through surfactant addition into completion fluid and perhaps, surfactant injection for EOR. This study numerically upscaled laboratory data for multi-stage hydraulic fracturing treatment and injection process proposed for the Wolfcamp formation. A combination of rock mechanic and reservoir numerical modeling was used to approximate the field-scale performance of both techniques. Novel completion fluid formulations and optimum surfactant injection schemes were designed, based on actual completion and production data.\u0000 Surfactant-Assisted Spontaneous Imbibition (SASI) experiments data for two surfactants investigated on the core-scale were upscaled to model production response of a hydraulically fractured well in Upton County, Texas, with realistic fracture geometry and conductivity. Core plugs were saturated and aged with their corresponding oil to restore the original oil saturation. Contact angle, interfacial tension (IFT), and zeta-potential were measured to investigate the role of capillary pressure for surfactant tests. We use a dual-porosity compositional model to determine the surfactant transport and adsorption.\u0000 With the proposed methodology, we show that lateral heterogeneity may limit both hydraulic fracture propagation and uniform distribution of EOR fluids, which cannot be ignored for the sake of simplicity. The primary production mechanism of aqueous phase surfactant EOR is wettability alteration and the reduction of IFT. Laboratory-scale SASI experimental results revealed that 2 gpt of surfactant solutions recovered up to 30% of the original oil in place (OOIP), whereas water alone recovered 10%. Capillary pressure and relative permeability curves were generated by scaling group analysis and history-matching the results of imbibition experiments on CT-generated core-scale model. On the next step, these curves were applied to surfactant completion and injection simulation models.\u0000 The field-scale model was achieved from history-matching actual well production data. We tested different soak times, injection pressure, and number of cycles in surfactant injection simulations to provide an optimum design for this scheme. Simulation results indicated that surfactant injection has further potential for higher recovery factor in addition to the incremental Estimated Ultimate Recovery (EUR) observed with application of surfactant as a completion fluid alone. Also, we investigated water-injection after primary depletion (water without surfactant) to provide another possible method for unconventional liquid reservoirs (ULR). Instead of referring to Huff-n-Puff which implies gas injection, in this manuscript we use the terminology Multi-Cycle Surfactant-Assisted Spontaneous Imbibition (MC-SASI) to describe surfactant Huff-n-Puff for EOR.\u0000 This paper provides a complete workflow on SASI-EOR that has been evaluated in laborato","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"90 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":"117288087","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}
T. Moussa, H. Dehghanpour, Yingkun Fu, Obinna Ezulike
Hydraulic fracturing combined with horizontal drilling is the key to unlocking vast unconventional reservoirs. However, understanding the relationship between fracturing/completion-design parameters and the process efficiency remains challenging. The objectives of this paper are 1) to estimate initial fracture volume and its variations during the production by using flowback data and 2) to investigate the existence of correlations between completion-design parameters and induced fracture volume process optimization. We analyze flowback data and completion-design parameters of 16 shale-gas completed in the Eagle Ford Formation. First, we estimate ultimate water recovery and initial fracture volume by using harmonic-decline model, and fracture volume loss during flowback by using a new iterative approach that accounts for fracture-porosity changes with time. Then, we conduct a multivariate analysis to develop empirical correlations of completions-design parameters with initial fracture volume and fracture characteristic-closure rate (FCR). The results show that harmonic-decline model could be used to estimate initial fracture volume with an average absolute percentage error (AAPE) of 7%. The correlations developed between initial fracture volume and completion-design parameters show that the proppant concentration has the most significant effect on fracture volume, followed by gross perforated interval (GPI) and shut-in time, respectively. Total vertical depth (TVD) and fluid injection rate have insignificant effects. The results indicate that increasing choke size during early flowback leads to a relatively-sharp decrease in fracture volume, while changing choke size during late flowback has negligible effects. The proposed correlation between FCR and completion-design parameters demonstrates the significant effect of proppant concentration on fracture closure during flowback, while GPI and TVD have negligible effects.
{"title":"Dynamic Fracture Volume Estimation using Flowback Data Analysis and its Correlation to Completion-Design Parameters","authors":"T. Moussa, H. Dehghanpour, Yingkun Fu, Obinna Ezulike","doi":"10.2118/194322-MS","DOIUrl":"https://doi.org/10.2118/194322-MS","url":null,"abstract":"\u0000 Hydraulic fracturing combined with horizontal drilling is the key to unlocking vast unconventional reservoirs. However, understanding the relationship between fracturing/completion-design parameters and the process efficiency remains challenging. The objectives of this paper are 1) to estimate initial fracture volume and its variations during the production by using flowback data and 2) to investigate the existence of correlations between completion-design parameters and induced fracture volume process optimization. We analyze flowback data and completion-design parameters of 16 shale-gas completed in the Eagle Ford Formation. First, we estimate ultimate water recovery and initial fracture volume by using harmonic-decline model, and fracture volume loss during flowback by using a new iterative approach that accounts for fracture-porosity changes with time. Then, we conduct a multivariate analysis to develop empirical correlations of completions-design parameters with initial fracture volume and fracture characteristic-closure rate (FCR).\u0000 The results show that harmonic-decline model could be used to estimate initial fracture volume with an average absolute percentage error (AAPE) of 7%. The correlations developed between initial fracture volume and completion-design parameters show that the proppant concentration has the most significant effect on fracture volume, followed by gross perforated interval (GPI) and shut-in time, respectively. Total vertical depth (TVD) and fluid injection rate have insignificant effects. The results indicate that increasing choke size during early flowback leads to a relatively-sharp decrease in fracture volume, while changing choke size during late flowback has negligible effects. The proposed correlation between FCR and completion-design parameters demonstrates the significant effect of proppant concentration on fracture closure during flowback, while GPI and TVD have negligible effects.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"29 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":"124564231","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
R. Gondalia, Rajeev Kumar, U. Nand, A. Bandyopadhyay, S. Narayan, Krishna Bordeori, Mukund Murari Singh, Arpit Shah, Santanu Das, Dasari Papa Rao, Moulali Shaik
The Mandapeta-Malleswaram field in India comprises Triassic-Jurassic age sands found at 4000m– 4500m depth, where reservoir pressure ranges 6,000 psi to 9,500psi with static temperature up to 340°F. This tectonically active basin with strike slip stress regime causes a heterogeneous distribution of in-situ stress which complicates the design and execution of effective hydraulic fracturing treatments. Previous attempts at fracturing from 2013 to 2017 were not successful and geomechanics inputs were different from actual values. This paper describes the lifecycle of a production enhancement project, from construction of a geomechanics-enabled mechanical earth model (MEM) to the successful design and execution of fracturing jobs on nine wells increasing proppant placement by 250% compared to previous hydraulic fracturing campaign and achieving 730% incremental gain in gas production compared to pre- fracturing production. Challenges like fracture modeling in tectonically stressed formations, issues of proppant admittance, and complicated fracture plane growth in highly deviated wells (>65°) were overcome by Geomechanical modeling. The modeling incorporated advanced 3D anisotropy measurements, providing better estimation of Young's modulus, Poisson's ratio, and horizontal stresses, resulting in realistic estimation of closure and breakdown pressure. Fault effects were modeled and taken into consideration for perforation depth selection and estimation of pumping pressure with model update based on extensive Minifrac injections and analysis. This study describes the results of injection tests (step rate, pump in-flowback, and calibration injection tests) carried out in the field addressing specific challenges in each well. Pre frac diagnostic injection and decline analysis was used to calibrate the MEM and tailor the design for every well. Proper job preparation for well completions and extensive stability testing involving a borate-based fluid system has reduced the screen out risk and enabled successful fracture placement. Effective pressure management on the job eliminated the problem with frequent screen outs and led to successful execution of all nine jobs while increasing the average job size from 30 t to ~150 t of proppant per stage. From this project, a practical guide to address issues of multiple complexities occurring simultaneously in a reservoir, such as the presence of tectonic stress, fracture misalignment, fissure mitigation, and high tortuosity was developed for future application in tectonically complex fields.
{"title":"Solving the Hydraulic Fracturing Puzzle in the HPHT KG Basin of India with Geomechanics-Enabled Design and Execution","authors":"R. Gondalia, Rajeev Kumar, U. Nand, A. Bandyopadhyay, S. Narayan, Krishna Bordeori, Mukund Murari Singh, Arpit Shah, Santanu Das, Dasari Papa Rao, Moulali Shaik","doi":"10.2118/194315-MS","DOIUrl":"https://doi.org/10.2118/194315-MS","url":null,"abstract":"\u0000 The Mandapeta-Malleswaram field in India comprises Triassic-Jurassic age sands found at 4000m– 4500m depth, where reservoir pressure ranges 6,000 psi to 9,500psi with static temperature up to 340°F. This tectonically active basin with strike slip stress regime causes a heterogeneous distribution of in-situ stress which complicates the design and execution of effective hydraulic fracturing treatments. Previous attempts at fracturing from 2013 to 2017 were not successful and geomechanics inputs were different from actual values. This paper describes the lifecycle of a production enhancement project, from construction of a geomechanics-enabled mechanical earth model (MEM) to the successful design and execution of fracturing jobs on nine wells increasing proppant placement by 250% compared to previous hydraulic fracturing campaign and achieving 730% incremental gain in gas production compared to pre- fracturing production.\u0000 Challenges like fracture modeling in tectonically stressed formations, issues of proppant admittance, and complicated fracture plane growth in highly deviated wells (>65°) were overcome by Geomechanical modeling. The modeling incorporated advanced 3D anisotropy measurements, providing better estimation of Young's modulus, Poisson's ratio, and horizontal stresses, resulting in realistic estimation of closure and breakdown pressure. Fault effects were modeled and taken into consideration for perforation depth selection and estimation of pumping pressure with model update based on extensive Minifrac injections and analysis.\u0000 This study describes the results of injection tests (step rate, pump in-flowback, and calibration injection tests) carried out in the field addressing specific challenges in each well. Pre frac diagnostic injection and decline analysis was used to calibrate the MEM and tailor the design for every well. Proper job preparation for well completions and extensive stability testing involving a borate-based fluid system has reduced the screen out risk and enabled successful fracture placement. Effective pressure management on the job eliminated the problem with frequent screen outs and led to successful execution of all nine jobs while increasing the average job size from 30 t to ~150 t of proppant per stage.\u0000 From this project, a practical guide to address issues of multiple complexities occurring simultaneously in a reservoir, such as the presence of tectonic stress, fracture misalignment, fissure mitigation, and high tortuosity was developed for future application in tectonically complex fields.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"135 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":"127390087","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}
Knowledge of fracture entry pressures or the formation face pressures during Acid Fracturing treatments can help in evaluating the effectiveness of the stimulation treatment in dynamic mode and can also enable and improve real-time decisions during the execution of treatment. In this paper, details of the methods and tools employed to generate formation face pressures in real-time mode with the help of live bottomhole pressure data, is discussed in detail. The majority of the horizontal wells considered for this study were drilled and completed in the North Sea with permanent bottomhole pressure gauges that enabled constant monitoring of well pressures. The tool in discussion uses the combination of treatment data such as surface pressure, fluid density, injection rates, type of fluid, wellbore description, gauge depth, and wellbore deviation, along with bottomhole pressures to generate formation face pressures just outside the casing at active perforation depth. The tool carries out the calculations as the treatment is being pumped thus providing a dynamic array of several important parameters and can also evaluate the treatment after it has been executed. Acid fracturing treatments combine the basic principles of hydraulic fracturing and acid reaction kinetics to stimulate acid soluble formations. It is customary to start the treatment with a high viscosity pad to generate a fracture geometry and follow it up with acid to react with the walls of the fracture and etch it differentially. The non-uniform etching action of the acid creates an uneven surface on fracture walls that provides the requisite fracture conductivity which is key to enhancing the well performance. The effectiveness of a treatment schedule can be ascertained by determining and analyzing the pressure behavior during the injection process. Several acid fracture treatments were analyzed using the tool and led to important conclusions related to fracture propagation modes, acid exposure times and effectiveness of given acid types. The results had a direct influence on modification of treatment designs and pump schedules to optimize treatment outcomes. The knowledge of formation face pressures is critical to the success of hydraulic fracturing treatments, especially in multi-stage and multiple perforation cluster type horizontal well completions. The tool developed in the study helps generate information that predicts pressures at fracture entry in real-time mode.
{"title":"Real Time Analysis of Formation Face Pressures in Acid Fracturing Treatments","authors":"V. Pandey, R. Burton, K. Capps","doi":"10.2118/194351-MS","DOIUrl":"https://doi.org/10.2118/194351-MS","url":null,"abstract":"\u0000 \u0000 \u0000 Knowledge of fracture entry pressures or the formation face pressures during Acid Fracturing treatments can help in evaluating the effectiveness of the stimulation treatment in dynamic mode and can also enable and improve real-time decisions during the execution of treatment. In this paper, details of the methods and tools employed to generate formation face pressures in real-time mode with the help of live bottomhole pressure data, is discussed in detail.\u0000 \u0000 \u0000 \u0000 The majority of the horizontal wells considered for this study were drilled and completed in the North Sea with permanent bottomhole pressure gauges that enabled constant monitoring of well pressures. The tool in discussion uses the combination of treatment data such as surface pressure, fluid density, injection rates, type of fluid, wellbore description, gauge depth, and wellbore deviation, along with bottomhole pressures to generate formation face pressures just outside the casing at active perforation depth. The tool carries out the calculations as the treatment is being pumped thus providing a dynamic array of several important parameters and can also evaluate the treatment after it has been executed.\u0000 \u0000 \u0000 \u0000 Acid fracturing treatments combine the basic principles of hydraulic fracturing and acid reaction kinetics to stimulate acid soluble formations. It is customary to start the treatment with a high viscosity pad to generate a fracture geometry and follow it up with acid to react with the walls of the fracture and etch it differentially. The non-uniform etching action of the acid creates an uneven surface on fracture walls that provides the requisite fracture conductivity which is key to enhancing the well performance. The effectiveness of a treatment schedule can be ascertained by determining and analyzing the pressure behavior during the injection process. Several acid fracture treatments were analyzed using the tool and led to important conclusions related to fracture propagation modes, acid exposure times and effectiveness of given acid types. The results had a direct influence on modification of treatment designs and pump schedules to optimize treatment outcomes.\u0000 \u0000 \u0000 \u0000 The knowledge of formation face pressures is critical to the success of hydraulic fracturing treatments, especially in multi-stage and multiple perforation cluster type horizontal well completions. The tool developed in the study helps generate information that predicts pressures at fracture entry in real-time mode.\u0000","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"193 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":"114992673","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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