{"title":"Cracking Canisp: Deep void evolution during ancient earthquakes","authors":"","doi":"10.1144/geosci2019-003","DOIUrl":"https://doi.org/10.1144/geosci2019-003","url":null,"abstract":"","PeriodicalId":10957,"journal":{"name":"Day 1 Tue, February 05, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86898669","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}
{"title":"Eruptions and ships","authors":"","doi":"10.1144/geosci2019-002","DOIUrl":"https://doi.org/10.1144/geosci2019-002","url":null,"abstract":"","PeriodicalId":10957,"journal":{"name":"Day 1 Tue, February 05, 2019","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88694339","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}
{"title":"Distant Thunder: Romance of the Fossiles","authors":"","doi":"10.1144/geosci2019-006","DOIUrl":"https://doi.org/10.1144/geosci2019-006","url":null,"abstract":"","PeriodicalId":10957,"journal":{"name":"Day 1 Tue, February 05, 2019","volume":"632 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73319560","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}
{"title":"Southwest Britain inspires through the ages","authors":"","doi":"10.1144/geosci2019-005","DOIUrl":"https://doi.org/10.1144/geosci2019-005","url":null,"abstract":"","PeriodicalId":10957,"journal":{"name":"Day 1 Tue, February 05, 2019","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81170923","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}
Coring adjacent to a hydraulically fractured horizontal well in Eagle Ford shale by Conoco-Phillips has revealed several closely spaced parallel hydraulic fractures (separated only by few inches) propagating in the direction perpendicular to the wellbore axis. The number of observed hydraulic fractures greatly exceed the number of clusters according to the recent paper titled "Sampling a Stimulated Rock Volume: An Eagle Ford Example". The observed behavior is contrary to the conventional practice of hydraulic fracture modeling where often a single fracture from each perforation cluster. This assumption stems from a simplified concept of the stress shadow that inhibit the growth of multiple parallel fractures under very tight spacing. In this study we show that correct modeling can in fact capture the field observed fracture clusters or swarms of closely-spaced fractures. Numerical model based on displacement discontinuity method is used to simulate non-planar hydraulic fracture propagation. Fracture deformation, fluid flow and perforation friction are fully coupled. Fracture propagation from a single cluster consisting of 20 perforations under 1800 phasing spanning 5 ft is considered. The effect of controlling parameters such as far-field stress contrast, perforation properties, and fracture toughness on multiple hydraulic fracture growth from a cluster of perforations is studied. The results show that closely spaced fracture clusters or swarms can occur for a certain range of conditions and operational parameters. The in-situ stress contrast, perforations conditions, and injection rates exert a significant influence. Under the right conditions, closely-spaced fractures can extend to distances exceeding tens of feet from the wellbore. Early termination and/or coalescence of closely spaced fractures can also occur. To our knowledge, our modeling results are the only ones that can explain the data from the Conoco-Phillips field observations regarding the occurrence of fracture swarms. The resuts show that the assumption of a single fracture per cluster does not hold true under all conditions. Moreover, such assumption would significantly underestimate stimulated rock volume near the wellbore. Finally, our results capture the injection pressure data which can be used as a diagnostic tool to infer the perforation effectiveness (i.e., the number of perforations that are in contact with fluid flow).
{"title":"Simulation and Analysis of Fracture Swarms Observed in the Eagle Ford Field Experiment","authors":"V. Sesetty, A. Ghassemi","doi":"10.2118/194328-MS","DOIUrl":"https://doi.org/10.2118/194328-MS","url":null,"abstract":"\u0000 Coring adjacent to a hydraulically fractured horizontal well in Eagle Ford shale by Conoco-Phillips has revealed several closely spaced parallel hydraulic fractures (separated only by few inches) propagating in the direction perpendicular to the wellbore axis. The number of observed hydraulic fractures greatly exceed the number of clusters according to the recent paper titled \"Sampling a Stimulated Rock Volume: An Eagle Ford Example\". The observed behavior is contrary to the conventional practice of hydraulic fracture modeling where often a single fracture from each perforation cluster. This assumption stems from a simplified concept of the stress shadow that inhibit the growth of multiple parallel fractures under very tight spacing. In this study we show that correct modeling can in fact capture the field observed fracture clusters or swarms of closely-spaced fractures.\u0000 Numerical model based on displacement discontinuity method is used to simulate non-planar hydraulic fracture propagation. Fracture deformation, fluid flow and perforation friction are fully coupled. Fracture propagation from a single cluster consisting of 20 perforations under 1800 phasing spanning 5 ft is considered. The effect of controlling parameters such as far-field stress contrast, perforation properties, and fracture toughness on multiple hydraulic fracture growth from a cluster of perforations is studied.\u0000 The results show that closely spaced fracture clusters or swarms can occur for a certain range of conditions and operational parameters. The in-situ stress contrast, perforations conditions, and injection rates exert a significant influence. Under the right conditions, closely-spaced fractures can extend to distances exceeding tens of feet from the wellbore. Early termination and/or coalescence of closely spaced fractures can also occur.\u0000 To our knowledge, our modeling results are the only ones that can explain the data from the Conoco-Phillips field observations regarding the occurrence of fracture swarms. The resuts show that the assumption of a single fracture per cluster does not hold true under all conditions. Moreover, such assumption would significantly underestimate stimulated rock volume near the wellbore. Finally, our results capture the injection pressure data which can be used as a diagnostic tool to infer the perforation effectiveness (i.e., the number of perforations that are in contact with fluid flow).","PeriodicalId":10957,"journal":{"name":"Day 1 Tue, February 05, 2019","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75179242","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}
Cyrille Defeu, Ryan Williams, Dan Shan, Joel Martin, D. Cannon, Kyle Clifton, Chad Lollar
Unconventional plays across the US are often made of stacked pays, typically ranging from a few hundred to thousands of feet thick. These stacked pay intervals are generally segregated into different formations as dictated by differences in geology, mineralogy, rock fabric, and fluid type. This proves to be a challenge because many stacked/staggered horizontal wells are required to provide effective coverage of the reservoir. Selecting the right landing location can become even more challenging in an environment with existing producing wells in adjacent formations because pressure depletion and its associated effects on fracture propagation necessitate consideration of vertical spacing and time. In this study, we outline an integrated approach that addresses a four-dimensional horizontal well placement challenge in the Midland basin's Wolfcamp A formation using advanced hydraulic fracture modeling to calibrate hydraulic fracture geometries and history match five producing wells in both Lower Spraberry and Wolfcamp B. The optimal landing location within the Wolfcamp A was determined based on an assessment of reservoir quality, rock mechanics, unique structural features, and depletion effects. These data were then combined to form a 4D geomodel that enabled a completion optimization study via modeling of the resulting complex hydraulic fracture geometry and subsequent hydrocarbon production. This integrated workflow, using a wide array of high-quality datasets and the input of experts from multiple disciplines, yielded a comprehensive assessment and clear recommendations for this challenging partially depleted stacked pay interval. Although this study is specific to the Midland basin's Lower Spraberry and Wolfcamp A and B formations, many sections of the workflow apply to other basins and their unique strata.
{"title":"Case Study of a Landing Location Optimization within a Depleted Stacked Reservoir in the Midland Basin","authors":"Cyrille Defeu, Ryan Williams, Dan Shan, Joel Martin, D. Cannon, Kyle Clifton, Chad Lollar","doi":"10.2118/194353-ms","DOIUrl":"https://doi.org/10.2118/194353-ms","url":null,"abstract":"\u0000 Unconventional plays across the US are often made of stacked pays, typically ranging from a few hundred to thousands of feet thick. These stacked pay intervals are generally segregated into different formations as dictated by differences in geology, mineralogy, rock fabric, and fluid type. This proves to be a challenge because many stacked/staggered horizontal wells are required to provide effective coverage of the reservoir. Selecting the right landing location can become even more challenging in an environment with existing producing wells in adjacent formations because pressure depletion and its associated effects on fracture propagation necessitate consideration of vertical spacing and time.\u0000 In this study, we outline an integrated approach that addresses a four-dimensional horizontal well placement challenge in the Midland basin's Wolfcamp A formation using advanced hydraulic fracture modeling to calibrate hydraulic fracture geometries and history match five producing wells in both Lower Spraberry and Wolfcamp B.\u0000 The optimal landing location within the Wolfcamp A was determined based on an assessment of reservoir quality, rock mechanics, unique structural features, and depletion effects. These data were then combined to form a 4D geomodel that enabled a completion optimization study via modeling of the resulting complex hydraulic fracture geometry and subsequent hydrocarbon production.\u0000 This integrated workflow, using a wide array of high-quality datasets and the input of experts from multiple disciplines, yielded a comprehensive assessment and clear recommendations for this challenging partially depleted stacked pay interval. Although this study is specific to the Midland basin's Lower Spraberry and Wolfcamp A and B formations, many sections of the workflow apply to other basins and their unique strata.","PeriodicalId":10957,"journal":{"name":"Day 1 Tue, February 05, 2019","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84849909","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}
Taregh Soleiman Asl, A. Habibi, Obinna Ezulike, Maryam Eghbalvala, H. Dehghanpour
We analyzed flowback and post-flowback production data from a horizontal well in the Montney Formation, which was fractured with water containing a microemulsion additive. This well was shut-in for 7 months after 5 months of post-flowback production. Oil and gas rates were significantly increased after the shut-in (700% increase), suggesting a reduction in matrix-fracture damage. We performed imbibition oil-recovery tests to evaluate the imbibition of the ME solution into the oil-saturated core plugs. The results show that the microemulsion solution can spontaneously imbibe into the oil-saturated core plugs leading to the final oil recovery factor of 24% of the original oil in place, compared with the tap water case with only 2% oil recovery factor. Combined analyses of the field and laboratory results suggest that imbibition of the fracturing water containing the ME solution during the extended shut-in period leads to 1) reduction of water blockage near the fracture face and 2) counter-current production of oil. These two effects can explain the enhanced production rate of oil and gas after the shut-in period.
{"title":"The Role of Microemulsion and Shut-in on Well Performance: From Field Scale to Laboratory Scale","authors":"Taregh Soleiman Asl, A. Habibi, Obinna Ezulike, Maryam Eghbalvala, H. Dehghanpour","doi":"10.2118/194363-MS","DOIUrl":"https://doi.org/10.2118/194363-MS","url":null,"abstract":"\u0000 We analyzed flowback and post-flowback production data from a horizontal well in the Montney Formation, which was fractured with water containing a microemulsion additive. This well was shut-in for 7 months after 5 months of post-flowback production. Oil and gas rates were significantly increased after the shut-in (700% increase), suggesting a reduction in matrix-fracture damage. We performed imbibition oil-recovery tests to evaluate the imbibition of the ME solution into the oil-saturated core plugs. The results show that the microemulsion solution can spontaneously imbibe into the oil-saturated core plugs leading to the final oil recovery factor of 24% of the original oil in place, compared with the tap water case with only 2% oil recovery factor. Combined analyses of the field and laboratory results suggest that imbibition of the fracturing water containing the ME solution during the extended shut-in period leads to 1) reduction of water blockage near the fracture face and 2) counter-current production of oil. These two effects can explain the enhanced production rate of oil and gas after the shut-in period.","PeriodicalId":10957,"journal":{"name":"Day 1 Tue, February 05, 2019","volume":"792 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78862359","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}
Creating sufficient and sustained fracture conductivity contributes directly to the success of acid fracturing treatments. The permeability and mineralogy distributions of formation rocks play significant roles in creating non-uniformly etched surfaces that can withstand high closure stress. Previous studies showed that depending on the properties of formation rock and acidizing conditions (acid selection, formation temperature, injection rate and contact time), a wide range of etching patterns (roughness, uniform, channeling) could be created that can dictate the resultant fracture conductivity. Insoluble minerals and their distribution can completely change the outcomes of acid fracturing treatments. However, most experimental studies use homogeneous rock samples such as Indiana limestones that do not represent the highly-heterogeneous features of carbonate rocks. This work studies the effect of heterogeneity, and more importantly, the distribution of insoluble rock, on acid fracture conductivity. In this research, we conducted acid fracturing experiments using both homogeneous Indiana limestone samples and heterogeneous carbonate rock samples. The Indiana limestone tests served as a baseline. The highly-heterogeneous carbonate rock samples contain several types of insoluble minerals such as quartz and various types of clays along sealed natural fractures. These minerals are distributed in the form of streaks correlated against the flow direction, or as smaller nodules. After acidizing the rock samples, these minerals acted as pillars that significantly reduced conductivity decline rate at high closure stresses. Both X-ray diffraction (XRD) and X-ray fluorescence (XRF) tests were done to pinpoint the type and location of different minerals on the fracture surfaces. A surface profilometer was also used to correlate conductivity as a function of mineralogy distribution by comparing the surface scans from after the acidizing test to the scans after the conductivity test. Theoretical models considering geostatistical correlation parameters were used to match and understand the experimental results. Results of this study showed that insoluble minerals with higher mechanical properties were not crushed at high closure stress, resulting in a less steep conductivity decline with increasing closure stress. If the acid etching creates enough conductivity, the rock sample can sustain a higher closure stress with a much lower decline rate compared with Indiana limestone samples. Fracture surfaces with insoluble mineral streaks correlated against the flow direction offer the benefit of being able to maintain conductivity at high closure stress, but not necessarily high initial conductivity. Using a fracture conductivity model with correlation length, we matched the fracture conductivity behavior for the heterogeneous samples. Fracture surfaces with mineral streaks correlated with the flow direction could increase acid fracturing conductivity significant
{"title":"Effects of Heterogeneity in Mineralogy Distribution on Acid Fracturing Efficiency","authors":"Xiao Jin, D. Zhu, A. Hill, D. McDuff","doi":"10.2118/194377-MS","DOIUrl":"https://doi.org/10.2118/194377-MS","url":null,"abstract":"\u0000 Creating sufficient and sustained fracture conductivity contributes directly to the success of acid fracturing treatments. The permeability and mineralogy distributions of formation rocks play significant roles in creating non-uniformly etched surfaces that can withstand high closure stress. Previous studies showed that depending on the properties of formation rock and acidizing conditions (acid selection, formation temperature, injection rate and contact time), a wide range of etching patterns (roughness, uniform, channeling) could be created that can dictate the resultant fracture conductivity. Insoluble minerals and their distribution can completely change the outcomes of acid fracturing treatments. However, most experimental studies use homogeneous rock samples such as Indiana limestones that do not represent the highly-heterogeneous features of carbonate rocks. This work studies the effect of heterogeneity, and more importantly, the distribution of insoluble rock, on acid fracture conductivity.\u0000 In this research, we conducted acid fracturing experiments using both homogeneous Indiana limestone samples and heterogeneous carbonate rock samples. The Indiana limestone tests served as a baseline. The highly-heterogeneous carbonate rock samples contain several types of insoluble minerals such as quartz and various types of clays along sealed natural fractures. These minerals are distributed in the form of streaks correlated against the flow direction, or as smaller nodules. After acidizing the rock samples, these minerals acted as pillars that significantly reduced conductivity decline rate at high closure stresses. Both X-ray diffraction (XRD) and X-ray fluorescence (XRF) tests were done to pinpoint the type and location of different minerals on the fracture surfaces. A surface profilometer was also used to correlate conductivity as a function of mineralogy distribution by comparing the surface scans from after the acidizing test to the scans after the conductivity test. Theoretical models considering geostatistical correlation parameters were used to match and understand the experimental results.\u0000 Results of this study showed that insoluble minerals with higher mechanical properties were not crushed at high closure stress, resulting in a less steep conductivity decline with increasing closure stress. If the acid etching creates enough conductivity, the rock sample can sustain a higher closure stress with a much lower decline rate compared with Indiana limestone samples. Fracture surfaces with insoluble mineral streaks correlated against the flow direction offer the benefit of being able to maintain conductivity at high closure stress, but not necessarily high initial conductivity. Using a fracture conductivity model with correlation length, we matched the fracture conductivity behavior for the heterogeneous samples. Fracture surfaces with mineral streaks correlated with the flow direction could increase acid fracturing conductivity significant","PeriodicalId":10957,"journal":{"name":"Day 1 Tue, February 05, 2019","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78872457","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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