Gongsheng Li, Nobuo Morita, D. Zhu, E. Kerr, Andrew Johnson, Katie Ross, E. Estrada, R. Scofield
Offset monitor wells experience stress, strain and pressure changes due to far-field fracture propagation. The pressure interference as hydraulic fractures propagate and intersect the casing directly results in a casing inner volume change and monitor well surface pressure change. The pressure behavior has been analyzed by a patented method, Sealed Wellbore Pressure Monitoring (SWPM), and it is an effective means to detect frac hits. To extend the understanding of this pressure behavior for wider applications, we proposed a methodology of simulating the casing response and corresponding pressure change of the offset well during hydraulic fracturing. The objective is to investigate the strain/pressure response along the monitor well casing for different scenarios of fracture intersection. In this study, an analytical model for computing the stress/strain in a casing-cement-formation system was developed based on the well-known solution of stress in a thick wall cylinder. The integrated numerical model consists of a fracture propagation model, a 3D geo-mechanical model, and a transient fluid flow model. Prior to analyzing the monitoring well pressure response, fracture propagation is modeled using a commercial software to give information of fracture geometry and fracture net pressure. The 3D fluid flow model and the geo-mechanical model of fractured rock and monitor well casing were established with finite-element method. With the input parameter of fracture geometry and net pressure distribution from the fracture propagation model, the integrated model can be used to solve the total stress-displacement behavior within the simulation domain. Using this approach, the volume change of the monitor well casing, and the corresponding surface pressure behavior can be estimated. The simulated strains along the monitor well casing of a radial fracture show the numerical simulation results agree well with the existing analytical solution. When a fracture crosses the monitor well, the standard surface pressure behavior is: (A) pressure increases due to fracture intersection; (B) pressure increase slows down as fracture tip travels some distance away from the casing; (C) pressure declines after the treatment well is shut-in. The first pressure increase is caused by casing radius reduction while the pressure fall-off is greatly affected by the far-field leakoff coefficient and permeability. The simulated results, and also the published data indicate that the typical pressure response for a single fracture hitting is on the order of 1 psi. When multiple fractures intersect the casing, a higher surface pressure increase is observed compared to single fracture case due to higher net pressure, and longer impacted section along the casing. Combined with the interpretation of DAS, this approach can identify the number and locations of the fractures that intersect the far field monitor well.
{"title":"Integrated 3D Numerical Modelling of Pressure Behavior and Casing Response at Offset Monitor Well During Fracturing","authors":"Gongsheng Li, Nobuo Morita, D. Zhu, E. Kerr, Andrew Johnson, Katie Ross, E. Estrada, R. Scofield","doi":"10.2118/212316-ms","DOIUrl":"https://doi.org/10.2118/212316-ms","url":null,"abstract":"\u0000 Offset monitor wells experience stress, strain and pressure changes due to far-field fracture propagation. The pressure interference as hydraulic fractures propagate and intersect the casing directly results in a casing inner volume change and monitor well surface pressure change. The pressure behavior has been analyzed by a patented method, Sealed Wellbore Pressure Monitoring (SWPM), and it is an effective means to detect frac hits. To extend the understanding of this pressure behavior for wider applications, we proposed a methodology of simulating the casing response and corresponding pressure change of the offset well during hydraulic fracturing. The objective is to investigate the strain/pressure response along the monitor well casing for different scenarios of fracture intersection.\u0000 In this study, an analytical model for computing the stress/strain in a casing-cement-formation system was developed based on the well-known solution of stress in a thick wall cylinder. The integrated numerical model consists of a fracture propagation model, a 3D geo-mechanical model, and a transient fluid flow model. Prior to analyzing the monitoring well pressure response, fracture propagation is modeled using a commercial software to give information of fracture geometry and fracture net pressure. The 3D fluid flow model and the geo-mechanical model of fractured rock and monitor well casing were established with finite-element method. With the input parameter of fracture geometry and net pressure distribution from the fracture propagation model, the integrated model can be used to solve the total stress-displacement behavior within the simulation domain. Using this approach, the volume change of the monitor well casing, and the corresponding surface pressure behavior can be estimated. The simulated strains along the monitor well casing of a radial fracture show the numerical simulation results agree well with the existing analytical solution.\u0000 When a fracture crosses the monitor well, the standard surface pressure behavior is: (A) pressure increases due to fracture intersection; (B) pressure increase slows down as fracture tip travels some distance away from the casing; (C) pressure declines after the treatment well is shut-in. The first pressure increase is caused by casing radius reduction while the pressure fall-off is greatly affected by the far-field leakoff coefficient and permeability. The simulated results, and also the published data indicate that the typical pressure response for a single fracture hitting is on the order of 1 psi. When multiple fractures intersect the casing, a higher surface pressure increase is observed compared to single fracture case due to higher net pressure, and longer impacted section along the casing. Combined with the interpretation of DAS, this approach can identify the number and locations of the fractures that intersect the far field monitor well.","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115266223","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}
Mohsen Ahmadian, M. Haddad, Liangze Cui, A. Kleinhammes, P. Doyle, Jeffrey Chen, Trevor Pugh, Q. Liu, Yuehua Wu, Darwin Mohajeri
In collaboration with the Advanced Energy Consortium, our team has previously demonstrated that the placement of electrically active proppants (EAPs) in a hydraulic fracture surveyed by electromagnetic (EM) methods can enhance the imaging of the stimulated reservoir volumes during hydraulic fracturing. That work culminated in constructing a well-characterized EAP-filled fracture anomaly at the Devine field pilot site (DFPS). In subsequent laboratory studies, we observed that the electrical conductivity of our EAP correlates with changes in pressure, salinity, and flow. Thus, we postulated that the EAP could be used as an in-situ sensor for the remote monitoring of these changes in previously EAP-filled fractures. This paper presents our latest field data from the DFPS to demonstrate such correlations at an intermediate pilot scale. We conducted surface-based EM surveys during freshwater (200 ppm) and saltwater (2,500 ppm) slug injections while running surfaced-based EM surveys. Simultaneously, we measured the following: 1) bottomhole pressure and salinity in five monitoring wells; 2) injection rate using high-precision data loggers; 3) distributed acoustic sensors in four monitoring wells; and 4) tiltmeter data on the survey area. We demonstrated that injections into an EAP-filled fracture could be successfully coupled with real-time electric field measurements on the surface, leading to remote monitoring of dynamic changes within the EAP-filled fracture. Furthermore, by comparing the electrical field traces with the bottomhole pressure, flow rate, and salinity, we concluded that the observed electric field in our study is influenced by fracture dilation and flow rate. Salinity effect was observed when saltwater was injected. EM simulations solely based on assumptions of fracture conductivity changes during injection did not reproduce all of the measured electric field magnitudes. Preliminary estimates showed that including streaming potential in our geophysical model may be needed to reduce the simulation mismatch. The methods developed and demonstrated during this study will lead to a better understanding of the extent of fracture networks, formation stress states, fluid leakoff and invasion, characterizations of engineered fracture systems, and other applications where monitoring subsurface flow tracking is deemed important.
通过与Advanced Energy Consortium的合作，我们的团队之前已经证明，通过电磁(EM)方法在水力裂缝中放置电活性支撑剂(EAPs)可以增强水力压裂过程中被压裂油藏体积的成像。这项工作最终在Devine油田试验点(DFPS)建立了一个具有良好特征的eap填充裂缝异常。在随后的实验室研究中，我们观察到EAP的电导率与压力、盐度和流量的变化有关。因此，我们假设EAP可以用作原位传感器，用于远程监测先前填充EAP的裂缝的这些变化。本文介绍了DFPS的最新现场数据，以在中间中试规模上证明这种相关性。在注入淡水(200ppm)和盐水(2500ppm)段塞流期间，我们进行了地面电磁测量。同时，对5口监测井进行了井底压力和矿化度测量;2)注入速率采用高精度数据记录仪;3) 4口监测井分布声传感器;4)测区倾斜仪数据。我们证明，注入eap充填的裂缝可以成功地与地面的实时电场测量相结合，从而远程监测eap充填裂缝内的动态变化。此外，通过将电场轨迹与井底压力、流速和矿化度进行比较，我们得出结论，研究中观察到的电场受到裂缝扩张和流速的影响。注入盐水后观察到盐度效应。仅基于注入过程中裂缝导电性变化的假设进行的电磁模拟并不能再现所有测量到的电场强度。初步估计表明，可能需要在我们的地球物理模型中包括流势，以减少模拟不匹配。在这项研究中开发和演示的方法将有助于更好地了解裂缝网络的范围、地层应力状态、流体泄漏和侵入、工程裂缝系统的特征，以及其他监测地下流动跟踪的重要应用。
{"title":"Real-Time Monitoring of Fracture Dynamics with a Contrast Agent-Assisted Electromagnetic Method","authors":"Mohsen Ahmadian, M. Haddad, Liangze Cui, A. Kleinhammes, P. Doyle, Jeffrey Chen, Trevor Pugh, Q. Liu, Yuehua Wu, Darwin Mohajeri","doi":"10.2118/212376-ms","DOIUrl":"https://doi.org/10.2118/212376-ms","url":null,"abstract":"\u0000 In collaboration with the Advanced Energy Consortium, our team has previously demonstrated that the placement of electrically active proppants (EAPs) in a hydraulic fracture surveyed by electromagnetic (EM) methods can enhance the imaging of the stimulated reservoir volumes during hydraulic fracturing. That work culminated in constructing a well-characterized EAP-filled fracture anomaly at the Devine field pilot site (DFPS). In subsequent laboratory studies, we observed that the electrical conductivity of our EAP correlates with changes in pressure, salinity, and flow. Thus, we postulated that the EAP could be used as an in-situ sensor for the remote monitoring of these changes in previously EAP-filled fractures. This paper presents our latest field data from the DFPS to demonstrate such correlations at an intermediate pilot scale.\u0000 We conducted surface-based EM surveys during freshwater (200 ppm) and saltwater (2,500 ppm) slug injections while running surfaced-based EM surveys. Simultaneously, we measured the following: 1) bottomhole pressure and salinity in five monitoring wells; 2) injection rate using high-precision data loggers; 3) distributed acoustic sensors in four monitoring wells; and 4) tiltmeter data on the survey area.\u0000 We demonstrated that injections into an EAP-filled fracture could be successfully coupled with real-time electric field measurements on the surface, leading to remote monitoring of dynamic changes within the EAP-filled fracture. Furthermore, by comparing the electrical field traces with the bottomhole pressure, flow rate, and salinity, we concluded that the observed electric field in our study is influenced by fracture dilation and flow rate. Salinity effect was observed when saltwater was injected. EM simulations solely based on assumptions of fracture conductivity changes during injection did not reproduce all of the measured electric field magnitudes. Preliminary estimates showed that including streaming potential in our geophysical model may be needed to reduce the simulation mismatch.\u0000 The methods developed and demonstrated during this study will lead to a better understanding of the extent of fracture networks, formation stress states, fluid leakoff and invasion, characterizations of engineered fracture systems, and other applications where monitoring subsurface flow tracking is deemed important.","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"19 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126900551","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 efficiencies observed in simul-frac operations are commonly associated with a singular, four-plus well pad containing an even number of wells. These efficiencies yield significant savings and reduction in overall completion time, expedite first-production and substantially reduce the time in which offset wells are shut in during frac operations. The introduction of remote simul-frac operations in the Delaware Basin, proven by Matador Resources Company in their Stateline asset, has removed this operational single-pad limitation by connecting adjacent multi-well pads and opening the opportunity to capitalize on ‘traditional’ simul-frac efficiencies on multiple pads simultaneously. Simul-frac is the use of a singular frac crew to simultaneously stimulate two separate wells. In most cases, the frac crew is equipped with an increase in hydraulic horsepower to be able to achieve rates ranging from 120 – 160 barrels per minute. The backside equipment in a Simul-Frac operation remains relatively unchanged, with the crew still utilizing only one blender. In earliest trials, wells completed via simul-frac operations were on the same pad and potentially receiving an uneven split of the fracturing slurry. By splitting the flow on the low- and high-pressure side of the frac, Matador and Universal Pressure Pumping were able to evenly meter the flow of slurry to two separate banks of pumps on location. One bank led to a zipper manifold on the same location that directed flow accordingly. The other bank directed flow along a 1,500′ high-pressure flanged-pipe frac line to an adjacent location to stimulate its "partner" well. Remote, satellite-communicating pressure gauges were used to monitor pressures on the adjacent pad. Matador has reported savings of up to ~7.5% of total completion spend per well and increased completed lateral footage per day by upwards of 50% on four well simul-fracs. Six of eleven batched wells in the Stateline asset were selected as a pilot location in Q4 of 2021 for remote simul-frac operations. Two three-well pads, Pad A and Pad B, were to be connected via high-pressure frac line and simultaneously stimulated. A Universal frac spread capable of 160 bpm was rigged up on Pad A and successfully stimulated wells on both Pad A and Pad B, via a high-pressure remote frac line throughout the job. The remote frac operations were a success; 6 wells, 407 stages, and over 73,000 lateral feet were completed in just under 33 days. In addition to the ~7.5% total completion spend per well savings, Matador was able to reduce total completion time by roughly 20 days, which brought forward production on the 11 well batch by 20 days and simultaneously reduced shut-in time of 16 offset wells. Successful remote simul-frac operations have enabled Matador to revisit a much wider variety of planned pads as candidates for simul-frac activity. After successful implementation in Q4 2021, Matador was able to increase its 2022 simul-frac activity by 91% due
{"title":"Simul-Frac Candidate Wells Identified in the Delaware Basin via Remote Operations","authors":"Matador Completions Team, Jesse Street","doi":"10.2118/212333-ms","DOIUrl":"https://doi.org/10.2118/212333-ms","url":null,"abstract":"\u0000 The efficiencies observed in simul-frac operations are commonly associated with a singular, four-plus well pad containing an even number of wells. These efficiencies yield significant savings and reduction in overall completion time, expedite first-production and substantially reduce the time in which offset wells are shut in during frac operations. The introduction of remote simul-frac operations in the Delaware Basin, proven by Matador Resources Company in their Stateline asset, has removed this operational single-pad limitation by connecting adjacent multi-well pads and opening the opportunity to capitalize on ‘traditional’ simul-frac efficiencies on multiple pads simultaneously.\u0000 Simul-frac is the use of a singular frac crew to simultaneously stimulate two separate wells. In most cases, the frac crew is equipped with an increase in hydraulic horsepower to be able to achieve rates ranging from 120 – 160 barrels per minute. The backside equipment in a Simul-Frac operation remains relatively unchanged, with the crew still utilizing only one blender. In earliest trials, wells completed via simul-frac operations were on the same pad and potentially receiving an uneven split of the fracturing slurry. By splitting the flow on the low- and high-pressure side of the frac, Matador and Universal Pressure Pumping were able to evenly meter the flow of slurry to two separate banks of pumps on location. One bank led to a zipper manifold on the same location that directed flow accordingly. The other bank directed flow along a 1,500′ high-pressure flanged-pipe frac line to an adjacent location to stimulate its \"partner\" well. Remote, satellite-communicating pressure gauges were used to monitor pressures on the adjacent pad.\u0000 Matador has reported savings of up to ~7.5% of total completion spend per well and increased completed lateral footage per day by upwards of 50% on four well simul-fracs. Six of eleven batched wells in the Stateline asset were selected as a pilot location in Q4 of 2021 for remote simul-frac operations. Two three-well pads, Pad A and Pad B, were to be connected via high-pressure frac line and simultaneously stimulated. A Universal frac spread capable of 160 bpm was rigged up on Pad A and successfully stimulated wells on both Pad A and Pad B, via a high-pressure remote frac line throughout the job. The remote frac operations were a success; 6 wells, 407 stages, and over 73,000 lateral feet were completed in just under 33 days. In addition to the ~7.5% total completion spend per well savings, Matador was able to reduce total completion time by roughly 20 days, which brought forward production on the 11 well batch by 20 days and simultaneously reduced shut-in time of 16 offset wells.\u0000 Successful remote simul-frac operations have enabled Matador to revisit a much wider variety of planned pads as candidates for simul-frac activity. After successful implementation in Q4 2021, Matador was able to increase its 2022 simul-frac activity by 91% due","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"226 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134003143","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. McClure, Magdalene Albrecht, Carl Bernet, C. Cipolla, Kenneth Etcheverry, G. Fowler, A. Fuhr, Amin Gherabati, Michelle Johnston, P. Kaufman, Mason Mackay, Michael G. McKimmy, Carlos Miranda, Claudia Molina, Christopher Ponners, D. Ratcliff, Janz Rondon, Ankush Singh, Rohit Sinha, Anthony Sung, Jian Xu, J. Yeo, Rob Zinselmeyer
This paper presents results from a collaborative industry study involving ten high-quality pad-scale datasets from the Delaware Basin, Midland Basin, Bakken, and Montney. The study had three primary goals: (a) compare/contrast observations between each dataset, (b) identify general strategies that can be used to mitigate parent/child impacts, and (c) provide concrete recommendations to optimize fracture design and well placement. For each dataset, an integrated hydraulic fracturing and reservoir simulation model was constructed and history matched to the observations. The models were calibrated to production data and pressure measurements, as well as to diagnostics such as: distributed acoustic sensing (DAS), microseismic, downhole imaging, chemical tracers, geochemical production allocations, and pressure observations from offset wells. History matching was performed by varying formation properties and model inputs to ensure consistency with the observations. Once the models were calibrated, the same set of approximately 120 sensitivity analysis simulations was performed on each model. Finally, an automated algorithm was used to quantitatively optimize fracture design and well placement to maximize economic performance. At each step in the process, the results were analyzed to identify the similarities and differences between the datasets and to explain why. The results show how differences in stratigraphy, well configuration, fracture design, and formation properties drive differences in parent/child phenomena. Optimal strategies to mitigate challenges depend on these site-specific conditions. Negative impacts from parent/child interactions cannot be entirely avoided. There is no strategy that can prevent the most important cause of child well underperformance – that wells are attempting to produce hydrocarbons from rock that has already been significantly depleted by parent well production. However, strategic design choices and quantitative economic optimization can significantly improve net present value and return on investment.
{"title":"Results from a Collaborative Industry Study on Parent/Child Interactions: Bakken, Permian Basin, and Montney","authors":"M. McClure, Magdalene Albrecht, Carl Bernet, C. Cipolla, Kenneth Etcheverry, G. Fowler, A. Fuhr, Amin Gherabati, Michelle Johnston, P. Kaufman, Mason Mackay, Michael G. McKimmy, Carlos Miranda, Claudia Molina, Christopher Ponners, D. Ratcliff, Janz Rondon, Ankush Singh, Rohit Sinha, Anthony Sung, Jian Xu, J. Yeo, Rob Zinselmeyer","doi":"10.2118/212321-ms","DOIUrl":"https://doi.org/10.2118/212321-ms","url":null,"abstract":"\u0000 This paper presents results from a collaborative industry study involving ten high-quality pad-scale datasets from the Delaware Basin, Midland Basin, Bakken, and Montney. The study had three primary goals: (a) compare/contrast observations between each dataset, (b) identify general strategies that can be used to mitigate parent/child impacts, and (c) provide concrete recommendations to optimize fracture design and well placement. For each dataset, an integrated hydraulic fracturing and reservoir simulation model was constructed and history matched to the observations. The models were calibrated to production data and pressure measurements, as well as to diagnostics such as: distributed acoustic sensing (DAS), microseismic, downhole imaging, chemical tracers, geochemical production allocations, and pressure observations from offset wells. History matching was performed by varying formation properties and model inputs to ensure consistency with the observations. Once the models were calibrated, the same set of approximately 120 sensitivity analysis simulations was performed on each model. Finally, an automated algorithm was used to quantitatively optimize fracture design and well placement to maximize economic performance. At each step in the process, the results were analyzed to identify the similarities and differences between the datasets and to explain why. The results show how differences in stratigraphy, well configuration, fracture design, and formation properties drive differences in parent/child phenomena. Optimal strategies to mitigate challenges depend on these site-specific conditions. Negative impacts from parent/child interactions cannot be entirely avoided. There is no strategy that can prevent the most important cause of child well underperformance – that wells are attempting to produce hydrocarbons from rock that has already been significantly depleted by parent well production. However, strategic design choices and quantitative economic optimization can significantly improve net present value and return on investment.","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"72 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133410637","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 Haynesville organic shale has just under 3600 wells, completed before mid-2016, with cluster spacings over 50 feet. This wide spacing resulted in many wells having missed or bypassed reserve recovery due to inefficient completions. Understandably these wells would be prime candidates for refracturing. Refracs have the advantage of lower up-front capital cost, fewer operational issues that rely on functioning supply chains, and significantly lower carbon footprint than new wells that need to be drilled prior to completion. However, a frequent concern is that refracs in the Haynesville cannot compete with new well economics. We looked at both public and operator refrac data to identify the criteria that makes a good Haynesville refrac candidate. We offer case studies to show the economic performance of 45 Haynesville liner refracs using actual post refrac decline data and current well costs. Both the economic value of the post refrac production is included along with the economic value of protecting infill wells from asymmetric fractures. An analysis of the completion design for a typical Haynesville refrac is also provided to demonstrate that significant upside remains for improvement if "best practices" are applied. These include Extreme Limited Entry (XLE), zero-degree top perforations per cluster, larger diameter expandable liners, and microproppant in the prepad. In our data set, the typical Haynesville refrac completion has very low pressure drops (520 psi pre-erosion) across the perforations. With average treating pressures of 9500 psi there is limited room for higher pressure drops due to a 10,500-psi surface pressure limit. And so, the available delta pressure for treatment is limited to +/- 500 psi when a 2500 to 3000 psi pressure drop is recommended to maximize cluster efficiency (Hausveit 2020). With the author’s recommended practices, over 2500 psi of excess friction losses can be avoided, providing adequate margin to achieve the recommended pressure drop. With increased cluster efficiency, increased recovery factors should follow. While Haynesville refracs have successfully increased estimated ultimate recovery (EUR), when "best practices" are followed, the economic returns should be highly competitive with new-well completion economics. If the refracs had the 60% average cluster efficiency values from several studies done on poorly diverted treatments (Weddle 2018 and Miller 2011) the total NPV10 for a P50 refrac is equivalent to the new well NPV10 values.
{"title":"The Economics of Refracturing in the Haynesville","authors":"R. Barba, M. Villarreal","doi":"10.2118/212371-ms","DOIUrl":"https://doi.org/10.2118/212371-ms","url":null,"abstract":"\u0000 The Haynesville organic shale has just under 3600 wells, completed before mid-2016, with cluster spacings over 50 feet. This wide spacing resulted in many wells having missed or bypassed reserve recovery due to inefficient completions. Understandably these wells would be prime candidates for refracturing. Refracs have the advantage of lower up-front capital cost, fewer operational issues that rely on functioning supply chains, and significantly lower carbon footprint than new wells that need to be drilled prior to completion. However, a frequent concern is that refracs in the Haynesville cannot compete with new well economics. We looked at both public and operator refrac data to identify the criteria that makes a good Haynesville refrac candidate. We offer case studies to show the economic performance of 45 Haynesville liner refracs using actual post refrac decline data and current well costs. Both the economic value of the post refrac production is included along with the economic value of protecting infill wells from asymmetric fractures. An analysis of the completion design for a typical Haynesville refrac is also provided to demonstrate that significant upside remains for improvement if \"best practices\" are applied. These include Extreme Limited Entry (XLE), zero-degree top perforations per cluster, larger diameter expandable liners, and microproppant in the prepad.\u0000 In our data set, the typical Haynesville refrac completion has very low pressure drops (520 psi pre-erosion) across the perforations. With average treating pressures of 9500 psi there is limited room for higher pressure drops due to a 10,500-psi surface pressure limit. And so, the available delta pressure for treatment is limited to +/- 500 psi when a 2500 to 3000 psi pressure drop is recommended to maximize cluster efficiency (Hausveit 2020). With the author’s recommended practices, over 2500 psi of excess friction losses can be avoided, providing adequate margin to achieve the recommended pressure drop. With increased cluster efficiency, increased recovery factors should follow. While Haynesville refracs have successfully increased estimated ultimate recovery (EUR), when \"best practices\" are followed, the economic returns should be highly competitive with new-well completion economics. If the refracs had the 60% average cluster efficiency values from several studies done on poorly diverted treatments (Weddle 2018 and Miller 2011) the total NPV10 for a P50 refrac is equivalent to the new well NPV10 values.","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"10 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124250842","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}
Fracture diagnostic on a cluster scale of multi-stage hydraulic fracturing wells remains challenging but essential to determine the quality of the stimulation operation and the completion strategies for future wells. Since the stimulation fluid is injected at a different temperature compared to the original geothermal, the considerably modified and highly heterogeneous thermal profile after stimulation presents significant potential to serve for fracture diagnostic purposes. In this work, a model to analyze the temperature signal associated with the shut-in period after hydraulic fracturing is presented, along with the pilot testing of two datasets. The model extends the scope of traditional thermal injection profiling algorithm with fracture diagnostic functions. During the development process, we incorporate the existing warmback model of conventional wells in analyzing shut-in temperature data with a newly developed stimulated region thermal model. Two main outputs of the model, the injection fluid intake and the fracture propagation extent, are estimated and tested. The model is then automated and thoroughly implemented in the software package. The primary applications of this work are injection fluid intake and fracture propagation extent of each perforation cluster in fractured wells. The spatial resolution of the injection profiling and fracture growth can reach the sub-meter scale (same as the distributed temperature sensing spatial resolution). Compared to the conventional radial warmback model, the temperature signals from the fractured well show a much faster warming trend while taking relatively larger amounts of injection fluid. This behavior can be attributed to the additional heat loss to the unstimulated region and larger contact area between clusters. On the other hand, leak-off fluids create a cooler stimulated region around the fracture plane, which makes the warmback trend slower compared to the linear flow regime model. The model developed in this study considers both behaviors to simulate the actual datasets. The inverse model estimates the fracture propagation extent in both the stimulated region as well as the fracture plane. Both estimations can jointly infer the leak-off extent of an individual cluster. As a pilot project, this model is tested on warmback temperature data from two datasets. The injection profiling results using the model are consistent with profiles obtained from other data sources, while the estimated fracture propagation extents of individual clusters present different types of fracture geometry (symmetrical, asymmetrical, double peaks, etc.). Quantitative injection profiling and fracture propagation extent estimations of an individual cluster using warmback analysis have been proven viable and reliable in this field study. It could be the first quantitative warmback analysis applied to fracture wells in the industry.
{"title":"Field Applications of Quantitative Fracture Diagnostic From Distributed Temperature Warmback Analysis","authors":"Y. Mao, C. Godefroy, M. Gysen","doi":"10.2118/212380-ms","DOIUrl":"https://doi.org/10.2118/212380-ms","url":null,"abstract":"\u0000 Fracture diagnostic on a cluster scale of multi-stage hydraulic fracturing wells remains challenging but essential to determine the quality of the stimulation operation and the completion strategies for future wells. Since the stimulation fluid is injected at a different temperature compared to the original geothermal, the considerably modified and highly heterogeneous thermal profile after stimulation presents significant potential to serve for fracture diagnostic purposes. In this work, a model to analyze the temperature signal associated with the shut-in period after hydraulic fracturing is presented, along with the pilot testing of two datasets.\u0000 The model extends the scope of traditional thermal injection profiling algorithm with fracture diagnostic functions. During the development process, we incorporate the existing warmback model of conventional wells in analyzing shut-in temperature data with a newly developed stimulated region thermal model. Two main outputs of the model, the injection fluid intake and the fracture propagation extent, are estimated and tested. The model is then automated and thoroughly implemented in the software package.\u0000 The primary applications of this work are injection fluid intake and fracture propagation extent of each perforation cluster in fractured wells. The spatial resolution of the injection profiling and fracture growth can reach the sub-meter scale (same as the distributed temperature sensing spatial resolution). Compared to the conventional radial warmback model, the temperature signals from the fractured well show a much faster warming trend while taking relatively larger amounts of injection fluid. This behavior can be attributed to the additional heat loss to the unstimulated region and larger contact area between clusters. On the other hand, leak-off fluids create a cooler stimulated region around the fracture plane, which makes the warmback trend slower compared to the linear flow regime model. The model developed in this study considers both behaviors to simulate the actual datasets.\u0000 The inverse model estimates the fracture propagation extent in both the stimulated region as well as the fracture plane. Both estimations can jointly infer the leak-off extent of an individual cluster. As a pilot project, this model is tested on warmback temperature data from two datasets. The injection profiling results using the model are consistent with profiles obtained from other data sources, while the estimated fracture propagation extents of individual clusters present different types of fracture geometry (symmetrical, asymmetrical, double peaks, etc.).\u0000 Quantitative injection profiling and fracture propagation extent estimations of an individual cluster using warmback analysis have been proven viable and reliable in this field study. It could be the first quantitative warmback analysis applied to fracture wells in the industry.","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128914959","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}
Ningning Li, Matt Slowinski, Don Koenig, B. Weaver, Naomi Valenzuela, Curtis Searle, Adrian Reece, Sabrina Sullivan, Jack Rosenthal
The operator has successfully drilled and completed more than fifty horizontal oil wells in the subnormally pressured Gallup Sandstone (Mancos Formation) within the San Juan Basin, New Mexico. All the wells were fracture stimulated using 70% quality Nitrogen (N2) foam with 20/40 sand. N2 fracs are uncommon in modern completions but provide numerous benefits for operations in the San Juan Basin. Benefits of N2 foam fracs include reduced water usage, less proppant settling (improved carrying capacity of proppant), and less parent/child interference. The N2 fluid is high-viscosity and promotes higher height/length growth with improved fracture width relative to low viscosity completion fluids. These properties of N2 foam fluids help prevent damage to parent wells and result in an ideal fracture geometry. This paper discusses methodologies employed by the operator resulting in significant improvements to well results. Methods include a) fracture design/modeling optimization with N2, b) parent and child well management, c) strategies for mitigating fracture-driven interactions, and d) a presentation of well results. The paper compares the completion parameters used in newly drilled wells versus legacy wells and contemporary offset completions to provide context to well results. Additionally, pressure management is utilized during flowback and production of both parent and child wells, resulting in improvements in oil productivity, load recovery, and minimal proppant returns during flowback. Pressure management incorporates both wellhead choke management and gas injection volume management as methods to maintain reservoir pressure in the short and long term. The combination of N2 foam hydraulic fracs, pressure management during flowback, and production optimization has led to significant improvements in horizontal Gallup sandstone well production. Incremental improvements have been made to all aspects of the completion, flowback, and production processes. Nitrogen foam fracturing is an understudied completion design that has had limited deployment in oil reservoirs across the oil industry. Strong production results from Gallup Sandstone N2 completions suggest that the technology is worth further consideration and study. This methodology could provide insights for other operators with similar reservoir conditions.
{"title":"Nitrogen Foam Fracturing in the Oil Window of the San Juan Basin: A Multi- Disciplined Approach Contributes to Significant Well Results","authors":"Ningning Li, Matt Slowinski, Don Koenig, B. Weaver, Naomi Valenzuela, Curtis Searle, Adrian Reece, Sabrina Sullivan, Jack Rosenthal","doi":"10.2118/212343-ms","DOIUrl":"https://doi.org/10.2118/212343-ms","url":null,"abstract":"\u0000 The operator has successfully drilled and completed more than fifty horizontal oil wells in the subnormally pressured Gallup Sandstone (Mancos Formation) within the San Juan Basin, New Mexico. All the wells were fracture stimulated using 70% quality Nitrogen (N2) foam with 20/40 sand. N2 fracs are uncommon in modern completions but provide numerous benefits for operations in the San Juan Basin. Benefits of N2 foam fracs include reduced water usage, less proppant settling (improved carrying capacity of proppant), and less parent/child interference. The N2 fluid is high-viscosity and promotes higher height/length growth with improved fracture width relative to low viscosity completion fluids. These properties of N2 foam fluids help prevent damage to parent wells and result in an ideal fracture geometry.\u0000 This paper discusses methodologies employed by the operator resulting in significant improvements to well results. Methods include a) fracture design/modeling optimization with N2, b) parent and child well management, c) strategies for mitigating fracture-driven interactions, and d) a presentation of well results. The paper compares the completion parameters used in newly drilled wells versus legacy wells and contemporary offset completions to provide context to well results. Additionally, pressure management is utilized during flowback and production of both parent and child wells, resulting in improvements in oil productivity, load recovery, and minimal proppant returns during flowback. Pressure management incorporates both wellhead choke management and gas injection volume management as methods to maintain reservoir pressure in the short and long term.\u0000 The combination of N2 foam hydraulic fracs, pressure management during flowback, and production optimization has led to significant improvements in horizontal Gallup sandstone well production. Incremental improvements have been made to all aspects of the completion, flowback, and production processes. Nitrogen foam fracturing is an understudied completion design that has had limited deployment in oil reservoirs across the oil industry. Strong production results from Gallup Sandstone N2 completions suggest that the technology is worth further consideration and study. This methodology could provide insights for other operators with similar reservoir conditions.","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121293169","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}
F. Salazar, N. Vasconez, Pedro Artola, Dorian Jaramillo, Diego Cueva, D. Cuenca, Bernardo Coronel, Mauricio Unapanta
A fracturing campaign in mature fields in Ecuador demonstrated the advantages of hydraulic fracturing to optimize production and maximize the extraction of the remaining reserves. Good design practices were key to the success of the fracturing campaign in MDC and Inchi fields. Initially, a comprehensive process of characterization was carried out to select the candidates for hydraulic fracturing in the Napo U and T formations to perform an initial fracturing campaign, studying among other characteristics, reservoir permeability, skin, pore pressure, remaining oil saturation, porosity, geomechanical properties, and completion integrity. A small group of wells was selected for hydraulic fracturing using the channel fracturing technique. The second phase consisted of optimizing the fracture design by improving the fracture geometry and conductivity, as well as the application proppant flowback control. Improved fracture geometry and proppant flowback prevention were identified as key elements for the success of the fracturing campaign in these mature fields. Fracturing channel technique was implemented to generate higher fracture conductivity in a low reservoir pressure environment by creating a highly conductive fracture that reduce the drawdown pressure during production. Because of successful implementation, the channel fracturing technique became the preferred completion method in the field for wells requiring stimulation. Twenty five hydraulic fracturing treatments were performed from 2018 to 2022, all demonstrating outstanding production results. The implementation of hydraulic fracturing increased the volume of recoverable reserves by 20%. Operationally, the application of channel fracturing allowed performing more aggressive pump schedules without the risk of screenout, achieving fracture conductivities in the order of 90,000 md-ft and skin values of –2 and –3.5. The learning curve and the results obtained in these fields are important sources of information for implementing hydraulic fracturing in mature fields to increase production and reduce risk.
{"title":"Hydraulic Fracturing Value Boosting Through Operational Innovation and Data Analytics, MDC and Inchi Fields Case Study","authors":"F. Salazar, N. Vasconez, Pedro Artola, Dorian Jaramillo, Diego Cueva, D. Cuenca, Bernardo Coronel, Mauricio Unapanta","doi":"10.2118/212372-ms","DOIUrl":"https://doi.org/10.2118/212372-ms","url":null,"abstract":"\u0000 A fracturing campaign in mature fields in Ecuador demonstrated the advantages of hydraulic fracturing to optimize production and maximize the extraction of the remaining reserves. Good design practices were key to the success of the fracturing campaign in MDC and Inchi fields.\u0000 Initially, a comprehensive process of characterization was carried out to select the candidates for hydraulic fracturing in the Napo U and T formations to perform an initial fracturing campaign, studying among other characteristics, reservoir permeability, skin, pore pressure, remaining oil saturation, porosity, geomechanical properties, and completion integrity. A small group of wells was selected for hydraulic fracturing using the channel fracturing technique. The second phase consisted of optimizing the fracture design by improving the fracture geometry and conductivity, as well as the application proppant flowback control. Improved fracture geometry and proppant flowback prevention were identified as key elements for the success of the fracturing campaign in these mature fields.\u0000 Fracturing channel technique was implemented to generate higher fracture conductivity in a low reservoir pressure environment by creating a highly conductive fracture that reduce the drawdown pressure during production. Because of successful implementation, the channel fracturing technique became the preferred completion method in the field for wells requiring stimulation. Twenty five hydraulic fracturing treatments were performed from 2018 to 2022, all demonstrating outstanding production results. The implementation of hydraulic fracturing increased the volume of recoverable reserves by 20%. Operationally, the application of channel fracturing allowed performing more aggressive pump schedules without the risk of screenout, achieving fracture conductivities in the order of 90,000 md-ft and skin values of –2 and –3.5.\u0000 The learning curve and the results obtained in these fields are important sources of information for implementing hydraulic fracturing in mature fields to increase production and reduce risk.","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"16 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115789687","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Maxwell, R. Brito, G. Ritter, J. Sinclair, A. Leavitt, Faye Liu, Jana Bachleda
This study integrates microseismic hydraulic fracture mapping with geochemical production profiling to understand the interaction between mechanical stratigraphy, fracture geometry, and effective drainage for wells landed in different benches of the STACK play in Oklahoma. Microseismic monitoring was used to map the extents of the hydraulic fracture system contacted during stimulation, while high resolution geochemical analysis or ‘fingerprinting’ was used to assess how different formations in the reservoir were draining. Microseismicity showed that hydraulic fracture growth from an Upper Meramec well rapidly cover the entire Meramec interval with some growth downward into the Woodford. Conversely, microseismicity initiating from a Woodford well clustered in that layer and grew upward into the Lower Meramec with time. Geochemical profiling closely matched the microseismic depth distributions for the associated well landing zones. Similar to the microseismic hydraulic heights from both Upper and Lower Meramec wells consistently produced from the entire Meramec, with additional recovery from the Woodford. Woodford landed wells produced Woodford oil with some production also coming from the Lower Meramec, also consistent with the microseismic depths. These production profiling trends were found to be very consistent across multiple sets of wells drilled into the same target formations. Integrating mapping of hydraulic fracture growth with geochemical assessment of the effective drainage within the hydraulically contacted zones provides unique insights into the reservoir contact and drainage. Understanding the mechanical stratigraphic controls on hydraulic fracture height growth relative to the reservoir drainage is key to informed decisions on wine-rack configurations for optimal reservoir drainage.
{"title":"Evaluation of Effective Drainage Height through Integration of Microseismic and Geochemical Depth Profiling of Produced Hydrocarbons","authors":"S. Maxwell, R. Brito, G. Ritter, J. Sinclair, A. Leavitt, Faye Liu, Jana Bachleda","doi":"10.2118/212314-ms","DOIUrl":"https://doi.org/10.2118/212314-ms","url":null,"abstract":"\u0000 This study integrates microseismic hydraulic fracture mapping with geochemical production profiling to understand the interaction between mechanical stratigraphy, fracture geometry, and effective drainage for wells landed in different benches of the STACK play in Oklahoma. Microseismic monitoring was used to map the extents of the hydraulic fracture system contacted during stimulation, while high resolution geochemical analysis or ‘fingerprinting’ was used to assess how different formations in the reservoir were draining. Microseismicity showed that hydraulic fracture growth from an Upper Meramec well rapidly cover the entire Meramec interval with some growth downward into the Woodford. Conversely, microseismicity initiating from a Woodford well clustered in that layer and grew upward into the Lower Meramec with time. Geochemical profiling closely matched the microseismic depth distributions for the associated well landing zones. Similar to the microseismic hydraulic heights from both Upper and Lower Meramec wells consistently produced from the entire Meramec, with additional recovery from the Woodford. Woodford landed wells produced Woodford oil with some production also coming from the Lower Meramec, also consistent with the microseismic depths. These production profiling trends were found to be very consistent across multiple sets of wells drilled into the same target formations. Integrating mapping of hydraulic fracture growth with geochemical assessment of the effective drainage within the hydraulically contacted zones provides unique insights into the reservoir contact and drainage. Understanding the mechanical stratigraphic controls on hydraulic fracture height growth relative to the reservoir drainage is key to informed decisions on wine-rack configurations for optimal reservoir drainage.","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121416191","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 a bullhead refrac treatment, an Eagle Ford operator utilized active acoustic pulses to measure diverter effectiveness while continuously pumping. The goal was to determine if the fluid point of entry along the lateral would change after the diverter material seated on the perforations. The bullhead refrac treatment consisted of 52 sand ramps with planned diverter drops after each ramp. Active acoustic pulses were taken at the end of every sand ramp to identify if fluid point of entry was changing along the wellbore as a result of the diverter material. The acoustic pulses and return signals were captured with a hydrophone sensor for optimal signal quality. The return signal comes from the first encountered, lowest impedance point and represents fluid point of entry in the well. Subsequently, forward acoustic modeling was conducted to simulate acoustic responses from different fracture sizes and their corresponding acoustic signatures. Over 300 acoustic pulses were taken throughout the refrac treatment. Analysis of all the acoustic return signals indicated that a dominant fracture system was created or previously existed around the heel segment of the lateral and the fluid point of entry did not change throughout the duration of the refrac, indicating diverter was not effective. This paper will show that the use of acoustics gives an operator real-time ground truth about the location of the fluid point of entry and will allow them to make changes to optimize the refrac operation during a stage.
{"title":"A Bullhead Refrac Application - Using Active Acoustic Pulses to Measure Diverter Effectiveness","authors":"Steven Bourgoyne, David Murray","doi":"10.2118/212369-ms","DOIUrl":"https://doi.org/10.2118/212369-ms","url":null,"abstract":"\u0000 During a bullhead refrac treatment, an Eagle Ford operator utilized active acoustic pulses to measure diverter effectiveness while continuously pumping. The goal was to determine if the fluid point of entry along the lateral would change after the diverter material seated on the perforations.\u0000 The bullhead refrac treatment consisted of 52 sand ramps with planned diverter drops after each ramp. Active acoustic pulses were taken at the end of every sand ramp to identify if fluid point of entry was changing along the wellbore as a result of the diverter material. The acoustic pulses and return signals were captured with a hydrophone sensor for optimal signal quality. The return signal comes from the first encountered, lowest impedance point and represents fluid point of entry in the well. Subsequently, forward acoustic modeling was conducted to simulate acoustic responses from different fracture sizes and their corresponding acoustic signatures.\u0000 Over 300 acoustic pulses were taken throughout the refrac treatment. Analysis of all the acoustic return signals indicated that a dominant fracture system was created or previously existed around the heel segment of the lateral and the fluid point of entry did not change throughout the duration of the refrac, indicating diverter was not effective. This paper will show that the use of acoustics gives an operator real-time ground truth about the location of the fluid point of entry and will allow them to make changes to optimize the refrac operation during a stage.","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129707202","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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