J. Ely, Jon Harper, Esteban N. Nieto, Dimitrios Kousparis, Andrew Kousparis, Curt Crumrine
The Northern extension of the "COMBO" Barnett Shale is located primarily in Montague, Cooke, and Clay counties in the North Texas region. This play is unique in that the shale in the area is very rich in total organic content (TOC) and contains a relatively high concentration of carbonates throughout. This extension is primarily inside the the oil window of the Barnett, rather than predominately within the more gas-rich region, which dominates the rest of the shale's development throughout North Texas (See Figure 1). Some of the earliest technological enhancements in oil production from shale occurred in the COMBO Barnett play, prior to the expanse and relative boom of the Eagle ford shale, and many other successful unconventional oil shale plays throughout the industry, both domestic and international. The Barnett in this area is typically quite thick, with sections from 300-700 feet. In some cases, naturally occurring fractures are fairly evident and can be identified through the use of image logging, prior to the completion phase of a well. Some areas may exhibit limited natural fractures, but have very brittle rock. Vertical completions were dominate during the early development of the Barnett, constituting a vast majority of oil and gas wells in production within the region. In fact, measureable time in production for the wells in the area indicated that properly completed vertical wells had respectable economics, which were later, at times, enhanced with horizontal drilling and multi-stage frac completions and re-completions.
{"title":"Nine Plus Years of Production Show Value of Proper Design in Oil Window of Barnett Shale","authors":"J. Ely, Jon Harper, Esteban N. Nieto, Dimitrios Kousparis, Andrew Kousparis, Curt Crumrine","doi":"10.2118/194365-MS","DOIUrl":"https://doi.org/10.2118/194365-MS","url":null,"abstract":"\u0000 The Northern extension of the \"COMBO\" Barnett Shale is located primarily in Montague, Cooke, and Clay counties in the North Texas region. This play is unique in that the shale in the area is very rich in total organic content (TOC) and contains a relatively high concentration of carbonates throughout. This extension is primarily inside the the oil window of the Barnett, rather than predominately within the more gas-rich region, which dominates the rest of the shale's development throughout North Texas (See Figure 1). Some of the earliest technological enhancements in oil production from shale occurred in the COMBO Barnett play, prior to the expanse and relative boom of the Eagle ford shale, and many other successful unconventional oil shale plays throughout the industry, both domestic and international. The Barnett in this area is typically quite thick, with sections from 300-700 feet. In some cases, naturally occurring fractures are fairly evident and can be identified through the use of image logging, prior to the completion phase of a well. Some areas may exhibit limited natural fractures, but have very brittle rock. Vertical completions were dominate during the early development of the Barnett, constituting a vast majority of oil and gas wells in production within the region. In fact, measureable time in production for the wells in the area indicated that properly completed vertical wells had respectable economics, which were later, at times, enhanced with horizontal drilling and multi-stage frac completions and re-completions.","PeriodicalId":10957,"journal":{"name":"Day 1 Tue, February 05, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80354861","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":null,"pages":null},"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":null,"pages":null},"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}
Estimating reservoir flow capacity is crucial for production estimation, hydraulic fracturing design and field development. Laboratory experiments can be used to measure the permeability of rock samples, but the results may not be representative at a field scale because of reservoir heterogeneity and pre-existing natural fracture systems. Diagnostic Fracture Injection Tests (DFIT) have now become standard practice to estimate formation pore pressure and formation permeability. However, in low permeability reservoirs, after-closure radial flow is often absent and this can cast significant uncertainties in interpreting DFIT data. In addition, the established methods for analyzing DFIT data make two oversimplified assumptions: (1) Carter's leak-off and, (2) Constant fracture compliance (or stiffness) during fracture closure. However, both assumptions are violated during fracture closure and this is why G-function based models and subsequent related works can lead to an incorrect interpretation and are not capable of consistently fitting both before and after closure data coherently (Wang and Sharma 2017). Moreover, current after-closure analysis relies on classic well-test solutions with constant injection rate. In reality, a "constant injection rate" does not equal "constant leak-off rate into the formation", because over 90% of the injected fluid stays inside the fracture at the end of pumping, instead of leaking into formation. The variable leak-off rate clearly violates the constant rate boundary condition used in existing well-test solutions. In this study, we extend our previous work and derive time-convolution solutions to pressure transient behavior of a closing fracture with infinite and finite fracture conductivity. We show that G-function and the square root of time models are only special cases of our general solutions. In addition, we found that after-closure linear flow and bilinear flow analysis can only be used to infer pore pressure reliably, but fail to estimate other parameters correctly. Most importantly, we present a new approach to history match the entire duration of DFIT data to estimate formation flow capacity, even without knowing closure stress and the roughness properties of the fracture surface. Our approach adds tremendous value to DFIT interpretation and uncertainty analysis, especially in unconventional reservoirs where the absence of after-closure radial flow is the norm. Two representative field cases are also presented and discussed.
储层流量估算对于产量估算、水力压裂设计和油田开发至关重要。实验室实验可以用来测量岩石样品的渗透率，但由于储层的非均质性和已有的天然裂缝系统，结果可能在现场规模上不具有代表性。诊断性裂缝注入测试(DFIT)现在已经成为估计地层孔隙压力和地层渗透率的标准方法。然而，在低渗透油藏中，关闭后的径向流动往往不存在，这给DFIT数据的解释带来了很大的不确定性。此外，现有的分析DFIT数据的方法有两个过于简化的假设:(1)Carter泄漏;(2)裂缝闭合过程中的裂缝柔顺度(或刚度)恒定。然而，在裂缝闭合过程中，这两个假设都被违反了，这就是为什么基于g函数的模型和随后的相关工作可能导致错误的解释，并且无法一致地拟合闭合前后的数据(Wang and Sharma 2017)。此外，目前的闭井后分析依赖于恒定注入速率的经典试井方案。实际上，“恒定注入速率”并不等于“恒定漏入地层速率”，因为在泵注结束时，超过90%的注入流体留在裂缝内，而不是泄漏到地层中。可变泄漏率显然违反了现有试井方案中使用的恒定速率边界条件。在这项研究中，我们扩展了之前的工作，并推导了具有无限和有限裂缝导流能力的闭合裂缝的压力瞬态行为的时间卷积解。我们证明了g函数和时间的平方根模型只是通解的特殊情况。此外，我们发现闭合后线性流动和双线性流动分析只能可靠地推断孔隙压力，而不能正确估计其他参数。最重要的是，我们提出了一种新的方法，可以在不知道闭合应力和裂缝表面粗糙度的情况下，对DFIT数据的整个持续时间进行历史匹配，以估计地层流动能力。我们的方法为DFIT解释和不确定性分析增加了巨大的价值，特别是在非常规油藏中，关闭后径向流是常态。提出并讨论了两个有代表性的现场案例。
{"title":"A Novel Approach for Estimating Formation Permeability and Revisit After-Closure Analysis from DFIT","authors":"HanYi Wang, M. Sharma","doi":"10.2118/194344-MS","DOIUrl":"https://doi.org/10.2118/194344-MS","url":null,"abstract":"\u0000 Estimating reservoir flow capacity is crucial for production estimation, hydraulic fracturing design and field development. Laboratory experiments can be used to measure the permeability of rock samples, but the results may not be representative at a field scale because of reservoir heterogeneity and pre-existing natural fracture systems. Diagnostic Fracture Injection Tests (DFIT) have now become standard practice to estimate formation pore pressure and formation permeability. However, in low permeability reservoirs, after-closure radial flow is often absent and this can cast significant uncertainties in interpreting DFIT data. In addition, the established methods for analyzing DFIT data make two oversimplified assumptions: (1) Carter's leak-off and, (2) Constant fracture compliance (or stiffness) during fracture closure. However, both assumptions are violated during fracture closure and this is why G-function based models and subsequent related works can lead to an incorrect interpretation and are not capable of consistently fitting both before and after closure data coherently (Wang and Sharma 2017). Moreover, current after-closure analysis relies on classic well-test solutions with constant injection rate. In reality, a \"constant injection rate\" does not equal \"constant leak-off rate into the formation\", because over 90% of the injected fluid stays inside the fracture at the end of pumping, instead of leaking into formation. The variable leak-off rate clearly violates the constant rate boundary condition used in existing well-test solutions.\u0000 In this study, we extend our previous work and derive time-convolution solutions to pressure transient behavior of a closing fracture with infinite and finite fracture conductivity. We show that G-function and the square root of time models are only special cases of our general solutions. In addition, we found that after-closure linear flow and bilinear flow analysis can only be used to infer pore pressure reliably, but fail to estimate other parameters correctly. Most importantly, we present a new approach to history match the entire duration of DFIT data to estimate formation flow capacity, even without knowing closure stress and the roughness properties of the fracture surface. Our approach adds tremendous value to DFIT interpretation and uncertainty analysis, especially in unconventional reservoirs where the absence of after-closure radial flow is the norm. Two representative field cases are also presented and discussed.","PeriodicalId":10957,"journal":{"name":"Day 1 Tue, February 05, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78812635","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. Hickey, Oscar Vasquez, S. Treviño, J. Oberle, Drew J. Jones
Controlled Source Electromagnetics (CSEM) is used to monitor and image a three well zipper frac operation. We examine the interaction between the completions operation and a fault zone at reservoir depth. Using two grounded dipole transmitter lines and 350 receiver locations, 27 frac stages were monitored in the Anadarko basin for three horizontal wells. Our broadband signal is transmitted before the start of the frac stage, during the frac stage, and after the frac stage is completed. This allows us to establish a baseline image prior to the start of the frac stage and to generate a response throughout the frac. The electromagnetic data collected provides a direct measurement of the conductivity change in the subsurface caused by the hydraulic fracturing process and from this we infer fluid movement. This case study presents the effects of a fault at reservoir depths that is intersected by the three wells and examines the possible effects of formation heterogeneities on frac fluid migration. Images produced by our CSEM method illustrate the lateral extent of the fluid, fracture azimuth, and identify reservoir heterogeneities. In addition, unlike microseismic, the CSEM method records signal generated from fluid flow in natural fractures as well as those fractures created by hydraulic pressure. As a result, CSEM allows us to infer fluid propagation and location to gauge frac behavior near and away from the fault where the fault zone is seen possibly acting as a sink and barrier. CSEM monitoring of a frac operation not only serves as a tool for monitoring and fracture diagnostic, it can also be used to identify geologic controls that can affect reservoir stimulation.
{"title":"Using Land Controlled Source Electromagnetics to Identify the Effects of Geologic Controls During a Zipper Frac Operation - A Case Study from the Anadarko Basin","authors":"M. Hickey, Oscar Vasquez, S. Treviño, J. Oberle, Drew J. Jones","doi":"10.2118/194313-MS","DOIUrl":"https://doi.org/10.2118/194313-MS","url":null,"abstract":"\u0000 Controlled Source Electromagnetics (CSEM) is used to monitor and image a three well zipper frac operation. We examine the interaction between the completions operation and a fault zone at reservoir depth.\u0000 Using two grounded dipole transmitter lines and 350 receiver locations, 27 frac stages were monitored in the Anadarko basin for three horizontal wells. Our broadband signal is transmitted before the start of the frac stage, during the frac stage, and after the frac stage is completed. This allows us to establish a baseline image prior to the start of the frac stage and to generate a response throughout the frac. The electromagnetic data collected provides a direct measurement of the conductivity change in the subsurface caused by the hydraulic fracturing process and from this we infer fluid movement.\u0000 This case study presents the effects of a fault at reservoir depths that is intersected by the three wells and examines the possible effects of formation heterogeneities on frac fluid migration. Images produced by our CSEM method illustrate the lateral extent of the fluid, fracture azimuth, and identify reservoir heterogeneities. In addition, unlike microseismic, the CSEM method records signal generated from fluid flow in natural fractures as well as those fractures created by hydraulic pressure. As a result, CSEM allows us to infer fluid propagation and location to gauge frac behavior near and away from the fault where the fault zone is seen possibly acting as a sink and barrier. CSEM monitoring of a frac operation not only serves as a tool for monitoring and fracture diagnostic, it can also be used to identify geologic controls that can affect reservoir stimulation.","PeriodicalId":10957,"journal":{"name":"Day 1 Tue, February 05, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81134459","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}
Understanding the effect of natural fractures on the propagation of a hydraulic fracture has challenged the fracturing community for a very long time. Nearly all previous investigations address the problem with the assumption that the natural and hydraulic fractures are all vertical and basically two-dimensional. While it is realistic to assume that the hydraulic fractures are vertical, the natural fractures have random orientations, and many of them are not in a vertical plane. This paper offers a first look at the 3D interactions between a vertical hydraulic fracture and randomly oriented natural fractures. It computes the stresses acting on the natural fractures induced by the three in-situ principal stresses plus an actively growing hydraulic fracture. It shows that as the inclination of the natural fracture with respect to the vertical plane increases, the chances of its activation by a hydraulic fracture diminishes, with a horizontal natural fracture having a very low chance of activation. Natural fractures are divided into three general groups; open, closed unbonded, and closed bonded. Activation of each of these general groups are reviewed separately and factors that control the process are identified and discussed. Paper shows that when an advancing hydraulic fracture intersects an open natural fracture, the initial result is local fracture arrest. Next, the hydraulic fracture grows three-dimensionally around the natural fracture and joins it from the opposite side. Continuous three-dimensional growth of the hydraulic fracture increases the fluid pressure inside the open natural fracture and can cause initiation of a branch fracture from one or more of its extremities. The net result is creation of a main fracture together with a set of smaller and very narrow offset branch fractures. An unbonded closed natural fracture has no tensile strength and can open when exposed to a tensile normal stress acting on its face. Intersection of these types of natural fractures by a hydraulic fracture can have one or more of three different consequences; crossing through, limited natural fracture opening in mixed mode (tensile plus shear) and extension, or creation of offset parallel branches. The conditions leading to each of these are identified and discussed. Bonded closed natural fractures can activate if the magnitude of the tensile stress induced on its face by the advancing hydraulic fracture causes the normal stress on its face to exceed its bond strength. In this situation the activation of the natural fracture will be in mixed more (tensile plus shear). However, under most actual situations hydraulic fractures are more likely to cross through them. The important parameters controlling activation of natural fractures are their inclination angle with respect to the hydraulic fracture and the three in-situ principal stresses, the magnitude of fluid pressure inside the fracture relative to the difference between the two horizontal princip
{"title":"Three-Dimensional Analysis of Interactions Between Hydraulic and Natural Fractures","authors":"A. Daneshy","doi":"10.2118/194335-MS","DOIUrl":"https://doi.org/10.2118/194335-MS","url":null,"abstract":"\u0000 Understanding the effect of natural fractures on the propagation of a hydraulic fracture has challenged the fracturing community for a very long time. Nearly all previous investigations address the problem with the assumption that the natural and hydraulic fractures are all vertical and basically two-dimensional. While it is realistic to assume that the hydraulic fractures are vertical, the natural fractures have random orientations, and many of them are not in a vertical plane.\u0000 This paper offers a first look at the 3D interactions between a vertical hydraulic fracture and randomly oriented natural fractures. It computes the stresses acting on the natural fractures induced by the three in-situ principal stresses plus an actively growing hydraulic fracture. It shows that as the inclination of the natural fracture with respect to the vertical plane increases, the chances of its activation by a hydraulic fracture diminishes, with a horizontal natural fracture having a very low chance of activation.\u0000 Natural fractures are divided into three general groups; open, closed unbonded, and closed bonded. Activation of each of these general groups are reviewed separately and factors that control the process are identified and discussed.\u0000 Paper shows that when an advancing hydraulic fracture intersects an open natural fracture, the initial result is local fracture arrest. Next, the hydraulic fracture grows three-dimensionally around the natural fracture and joins it from the opposite side. Continuous three-dimensional growth of the hydraulic fracture increases the fluid pressure inside the open natural fracture and can cause initiation of a branch fracture from one or more of its extremities. The net result is creation of a main fracture together with a set of smaller and very narrow offset branch fractures.\u0000 An unbonded closed natural fracture has no tensile strength and can open when exposed to a tensile normal stress acting on its face. Intersection of these types of natural fractures by a hydraulic fracture can have one or more of three different consequences; crossing through, limited natural fracture opening in mixed mode (tensile plus shear) and extension, or creation of offset parallel branches. The conditions leading to each of these are identified and discussed.\u0000 Bonded closed natural fractures can activate if the magnitude of the tensile stress induced on its face by the advancing hydraulic fracture causes the normal stress on its face to exceed its bond strength. In this situation the activation of the natural fracture will be in mixed more (tensile plus shear). However, under most actual situations hydraulic fractures are more likely to cross through them.\u0000 The important parameters controlling activation of natural fractures are their inclination angle with respect to the hydraulic fracture and the three in-situ principal stresses, the magnitude of fluid pressure inside the fracture relative to the difference between the two horizontal princip","PeriodicalId":10957,"journal":{"name":"Day 1 Tue, February 05, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79361109","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}
L. Weijers, C. Wright, M. Mayerhofer, M. Pearson, L. Griffin, P. Weddle
Hydraulic fracturing has been a part of oil & gas development in North America for seven decades. Hydraulic fracturing was first conducted in 1947. Commercial operations began in 1949. After over twenty years fracturing took a large step up in the late-1970s with its application to tight gas sand formations. The game changer that brought discussion of hydraulic fracturing to dinner tables, bars and sidelines of soccer games is the recent advances that enable commercial extraction of natural gas and oil directly from shale source rocks. Since the start of shale fracturing in the early-1990s, fracturing technology and the pressure pumping industry's efficiency in delivering fracturing services have changed almost beyond recognition. The result has been the world-changing Shale Revolution. Through researching industry databases, the authors have compiled an industry-wide review of North American hydraulic fracturing activity dating back to the first work done in the late 1940s. Yearly stage count in the 1950s through the early 1990s was 10,000 – 30,000 stages/year, while recent peak levels show a step change in activity aproaching 500,000 stages/year (Fig. 1). While the North American industry's fracturing horsepower grew about 10-fold between 2000 and 2018, yearly frac stage count grew 20-fold in North America and proppant mass pumped grew 40-fold. The authors show how the industry achieved a step-change in reducing service delivery cost through innovation and efficiency, allowing sustained economic development of unconventional resources at decreasing breakeven production costs. Technological changes, as assisted by a better understanding through frac diagnostics, integrated modeling and statistical analysis have enabled the large cost reduction to commercially produce a barrel of oil. As a result, shale frac designs have focused on higher intensity completions with tighter stage and cluster spacing, improved diversion through extreme limited entry perforation design and simultaneous and zipper frac'ing, increasing proppant mass per well, utilizing next-generation frac fluids to increase produced water recycling and using cheaper lower-quality proppant. At the same time, the environmental footprint of oil & gas production has been shrinking and will continue to do so as operational changes continue to make our industry a better neighbor, for example through faster well construction utilizing fewer pad locations, development of quiet fleets, greener frac chemistry, frac focus disclosure, etc. Together, oil and gas operators and their service providers have used technology & innovation to improve efficiencies and increase the overall daily pump time per frac crew. However, there is plenty of room for further improvements in technology and efficiency. We believe this is the first industry database of its kind covering hydraulic fracturing activity in the United States, going back to the 1940s. We hope this paper provides a unique perspective of
{"title":"Trends in the North American Frac Industry: Invention through the Shale Revolution","authors":"L. Weijers, C. Wright, M. Mayerhofer, M. Pearson, L. Griffin, P. Weddle","doi":"10.2118/194345-MS","DOIUrl":"https://doi.org/10.2118/194345-MS","url":null,"abstract":"\u0000 Hydraulic fracturing has been a part of oil & gas development in North America for seven decades. Hydraulic fracturing was first conducted in 1947. Commercial operations began in 1949. After over twenty years fracturing took a large step up in the late-1970s with its application to tight gas sand formations. The game changer that brought discussion of hydraulic fracturing to dinner tables, bars and sidelines of soccer games is the recent advances that enable commercial extraction of natural gas and oil directly from shale source rocks. Since the start of shale fracturing in the early-1990s, fracturing technology and the pressure pumping industry's efficiency in delivering fracturing services have changed almost beyond recognition. The result has been the world-changing Shale Revolution.\u0000 Through researching industry databases, the authors have compiled an industry-wide review of North American hydraulic fracturing activity dating back to the first work done in the late 1940s. Yearly stage count in the 1950s through the early 1990s was 10,000 – 30,000 stages/year, while recent peak levels show a step change in activity aproaching 500,000 stages/year (Fig. 1). While the North American industry's fracturing horsepower grew about 10-fold between 2000 and 2018, yearly frac stage count grew 20-fold in North America and proppant mass pumped grew 40-fold.\u0000 The authors show how the industry achieved a step-change in reducing service delivery cost through innovation and efficiency, allowing sustained economic development of unconventional resources at decreasing breakeven production costs. Technological changes, as assisted by a better understanding through frac diagnostics, integrated modeling and statistical analysis have enabled the large cost reduction to commercially produce a barrel of oil. As a result, shale frac designs have focused on higher intensity completions with tighter stage and cluster spacing, improved diversion through extreme limited entry perforation design and simultaneous and zipper frac'ing, increasing proppant mass per well, utilizing next-generation frac fluids to increase produced water recycling and using cheaper lower-quality proppant. At the same time, the environmental footprint of oil & gas production has been shrinking and will continue to do so as operational changes continue to make our industry a better neighbor, for example through faster well construction utilizing fewer pad locations, development of quiet fleets, greener frac chemistry, frac focus disclosure, etc. Together, oil and gas operators and their service providers have used technology & innovation to improve efficiencies and increase the overall daily pump time per frac crew. However, there is plenty of room for further improvements in technology and efficiency.\u0000 We believe this is the first industry database of its kind covering hydraulic fracturing activity in the United States, going back to the 1940s. We hope this paper provides a unique perspective of ","PeriodicalId":10957,"journal":{"name":"Day 1 Tue, February 05, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78750329","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. Lorwongngam, C. Cipolla, C. Gradl, Jose Gil Cidoncha, Bruce Davis
To effectively drain hydrocarbon from unconventional plays, operators have been optimizing their drilling spacing unit (DSU) well spacing for many years. This paper presents a continuous improvement of Bakken well spacing using trial pads with smaller spacing and multidisciplinary data gathering to understand the most effective spacing between wells. The operator's standard well spacing between Middle Bakken (MB) wells in the East Nesson (EN) area [Alger Field] ranges from 500 to 700 ft. To understand the optimum spacing between wells in this area, the operator trialed well spacing of 500 ft between like formations. The spacing between Middle Bakken and Three Forks wells was 250 ft. Data gathered during the spacing trial included microseismic, microseismic depletion delineation (MDD), radioactive (RA) tracers, chemical tracers, image logs, pressure measurements during completion/flowback/early-time production, and diagnostic fracture injection tests (DFITs). The data was used to calibrate advanced hydraulic fracture models and guide next-generation reservoir simulation history matching to characterize multiwell production behavior. The MDD in the parent well provided data to "map" drainage patterns, showing that drainage was limited to the MB formation. However, microseismic showed that hydraulic fracture height extended from the Three Forks second bench (TF2) up through the Three Forks first bench (TF1), Middle Bakken, and into the overlying Lodgepole (LP)—connecting the entire Bakken petroleum system. The microseismic also showed asymmetric fracture growth toward the parent well in the DSU, but the asymmetry diminished as completions progressed away from the parent well. In addition to the MB-TF connectivity indicated from the microseismic, RA tracers pumped from a TF2 well were detected in a Middle Bakken well. The implied transport of proppant from a lower TF completion to the MB increases the likelihood of production communication between formations. Chemical tracers (oil and water) pumped during hydraulic fracturing operations were found from one end of the pad to another (over 2,500 ft) regardless of formation; another confirmation of hydraulic communication between Middle Bakken and Three Forks wells. The hydraulic fracture model was calibrated using microseismic data and used for subsequent reservoir simulation history matching. The workflow consisted of modeling the parent well hydraulic fractures and history matching production, performing geomechanical modeling to determine the effects of parent well depletion on 3D stress state for hydraulic fracture modeling of the infill wells, and production history matching of the entire pad. The modeling showed significant fracture-to-fracture communication and well-to-well interference. The operator quickly used these learnings to optimize well spacing across the area to maximize DSU value.
{"title":"Multidisciplinary Data Gathering to Characterize Hydraulic Fracture Performance and Evaluate Well Spacing in the Bakken","authors":"A. Lorwongngam, C. Cipolla, C. Gradl, Jose Gil Cidoncha, Bruce Davis","doi":"10.2118/194321-MS","DOIUrl":"https://doi.org/10.2118/194321-MS","url":null,"abstract":"\u0000 To effectively drain hydrocarbon from unconventional plays, operators have been optimizing their drilling spacing unit (DSU) well spacing for many years. This paper presents a continuous improvement of Bakken well spacing using trial pads with smaller spacing and multidisciplinary data gathering to understand the most effective spacing between wells.\u0000 The operator's standard well spacing between Middle Bakken (MB) wells in the East Nesson (EN) area [Alger Field] ranges from 500 to 700 ft. To understand the optimum spacing between wells in this area, the operator trialed well spacing of 500 ft between like formations. The spacing between Middle Bakken and Three Forks wells was 250 ft. Data gathered during the spacing trial included microseismic, microseismic depletion delineation (MDD), radioactive (RA) tracers, chemical tracers, image logs, pressure measurements during completion/flowback/early-time production, and diagnostic fracture injection tests (DFITs). The data was used to calibrate advanced hydraulic fracture models and guide next-generation reservoir simulation history matching to characterize multiwell production behavior.\u0000 The MDD in the parent well provided data to \"map\" drainage patterns, showing that drainage was limited to the MB formation. However, microseismic showed that hydraulic fracture height extended from the Three Forks second bench (TF2) up through the Three Forks first bench (TF1), Middle Bakken, and into the overlying Lodgepole (LP)—connecting the entire Bakken petroleum system. The microseismic also showed asymmetric fracture growth toward the parent well in the DSU, but the asymmetry diminished as completions progressed away from the parent well. In addition to the MB-TF connectivity indicated from the microseismic, RA tracers pumped from a TF2 well were detected in a Middle Bakken well. The implied transport of proppant from a lower TF completion to the MB increases the likelihood of production communication between formations. Chemical tracers (oil and water) pumped during hydraulic fracturing operations were found from one end of the pad to another (over 2,500 ft) regardless of formation; another confirmation of hydraulic communication between Middle Bakken and Three Forks wells.\u0000 The hydraulic fracture model was calibrated using microseismic data and used for subsequent reservoir simulation history matching. The workflow consisted of modeling the parent well hydraulic fractures and history matching production, performing geomechanical modeling to determine the effects of parent well depletion on 3D stress state for hydraulic fracture modeling of the infill wells, and production history matching of the entire pad. The modeling showed significant fracture-to-fracture communication and well-to-well interference. The operator quickly used these learnings to optimize well spacing across the area to maximize DSU value.","PeriodicalId":10957,"journal":{"name":"Day 1 Tue, February 05, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81872517","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}
Currently, the closure stress is often predicted using the conventional tangent method (i.e., G-function) or the variable compliance method. Both methods use several restrictive assumptions such as a single planar fracture. However, the hydraulic fracture often intersects rock fabric features such as bedding planes and/or natural fractures causing the pressure transient behavior to become drastically different compared to that of a single planar hydraulic fracture. Closure of the intersected natural fractures might precede that of the created HF which impacts the interpretation of the pressure derivate plots and also the closure stress. In this paper we present and use an advanced fracture diagnostic model that can help recognize the signatures of rock fabric features and their impact on estimation of the closure stress. An example field data is used to illustrate the potential impact on closure stress. The new DFIT model consists of a fully coupled 3D hydraulic fracture simulator with the ability to handle the opening, propagation, and closure of natural factures so that the pre- and post-closure stress/deformation of both the hydraulic and natural fractures can be captured. Fracture propagation, HF-NF interaction, fracture intersection, and DFIT model are integrated into one simulator to provide a more realistic view of HF propagation and fracture diagnostics in naturally fractured reservoirs. The current model is developed without any major assumptions concerning the fluid flow, fracture deformation, and propagation path. Rock/fracture deformation is calculated using a boundary element formulation whereas the transport processes are solved using finite elements method. Our results indicate that natural fractures affect the pre- and post- shut-in response of the hydraulic fracture in a number of ways. For example, the fracture propagation path, the pumping pressure profile, and interfering with the post shut-in pressure response. These factors, indeed, impact the estimation of the minimum horizontal stress which is a key parameter obtained from DFIT. Moreover, our results show how the normal stiffness of the fracture surface asperities can impact the minimum stress estimation. Closure of natural fractures is reflected in the slope of the pressure derivative and G-function plots so that correct interpretation of these signatures is essential to accurate extraction of the Shmin. Closure of natural fractures is often viewed as a pressure depdendent leakoff mechanism that is reflected on the Gdp/dG curve. The closure behavior of HF-NF sets is, however, not explicitly modeled in the context of pressure transient analysis. Therefore, it is our objective to study the closure behavior of HF-NF sets using a 3D coupled simulator. This novel model is applied to actual field data to illustrate the potential impact on closure stress and to shed light on the subject of fracture diagnostics in naturally fractured reservoirs. Our results indicate that the
{"title":"DFIT Considering Complex Interactions of Hydraulic and Natural Fractures","authors":"A. Kamali, A. Ghassemi","doi":"10.2118/194348-MS","DOIUrl":"https://doi.org/10.2118/194348-MS","url":null,"abstract":"\u0000 Currently, the closure stress is often predicted using the conventional tangent method (i.e., G-function) or the variable compliance method. Both methods use several restrictive assumptions such as a single planar fracture. However, the hydraulic fracture often intersects rock fabric features such as bedding planes and/or natural fractures causing the pressure transient behavior to become drastically different compared to that of a single planar hydraulic fracture. Closure of the intersected natural fractures might precede that of the created HF which impacts the interpretation of the pressure derivate plots and also the closure stress. In this paper we present and use an advanced fracture diagnostic model that can help recognize the signatures of rock fabric features and their impact on estimation of the closure stress. An example field data is used to illustrate the potential impact on closure stress.\u0000 The new DFIT model consists of a fully coupled 3D hydraulic fracture simulator with the ability to handle the opening, propagation, and closure of natural factures so that the pre- and post-closure stress/deformation of both the hydraulic and natural fractures can be captured. Fracture propagation, HF-NF interaction, fracture intersection, and DFIT model are integrated into one simulator to provide a more realistic view of HF propagation and fracture diagnostics in naturally fractured reservoirs. The current model is developed without any major assumptions concerning the fluid flow, fracture deformation, and propagation path. Rock/fracture deformation is calculated using a boundary element formulation whereas the transport processes are solved using finite elements method.\u0000 Our results indicate that natural fractures affect the pre- and post- shut-in response of the hydraulic fracture in a number of ways. For example, the fracture propagation path, the pumping pressure profile, and interfering with the post shut-in pressure response. These factors, indeed, impact the estimation of the minimum horizontal stress which is a key parameter obtained from DFIT. Moreover, our results show how the normal stiffness of the fracture surface asperities can impact the minimum stress estimation. Closure of natural fractures is reflected in the slope of the pressure derivative and G-function plots so that correct interpretation of these signatures is essential to accurate extraction of the Shmin.\u0000 Closure of natural fractures is often viewed as a pressure depdendent leakoff mechanism that is reflected on the Gdp/dG curve. The closure behavior of HF-NF sets is, however, not explicitly modeled in the context of pressure transient analysis. Therefore, it is our objective to study the closure behavior of HF-NF sets using a 3D coupled simulator. This novel model is applied to actual field data to illustrate the potential impact on closure stress and to shed light on the subject of fracture diagnostics in naturally fractured reservoirs. Our results indicate that the","PeriodicalId":10957,"journal":{"name":"Day 1 Tue, February 05, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77422327","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}
Hydraulic fracturing as a means to stimulate production has become an effective way to extract oil and gas from low-porosity, low-permeability, hydrocarbon-bearing formations. The technology used in support of hydraulic fracturing is evolving at a fast rate, which has enabled operators worldwide to achieve improved recovery in increasingly complex well environments. The well designs and completion strategies associated with hydraulic fracturing come with a unique set of challenges. During well construction, the long lateral sections of extended-reach wells may require the production (or intermediate) casing to be rotated and pushed through build sections of relatively high curvature (greater than 10° per 100 feet or 30 meters); furthermore, some operators rotate the casing during cementing to improve cement quality. This rotation can subject the casing connections in the build section to a high number of rotating-bending load cycles. This cyclic loading can result in high stresses in the thread roots of the casing connections, which may lead to localized yielding of the material and potential structural failure. The hydraulic fracturing process itself subjects the production casing to rapid increases in internal pressure to high magnitudes, which will result in cyclic pressure loading for wells with multiple stages. Given these considerations, casing connections that are used in hydraulically fractured wells can be subjected to significant cyclic loading before the well is produced, and this loading may have an impact on the overall casing connection sealing and structural capacity in subsequent well operations. In 2015 the American Petroleum Institute (API) published the first edition of Recommended Practice 100-1, Hydraulic Fracturing – Well Integrity and Fracture Containment, to provide the industry with guidelines and considerations for hydraulically fractured well designs, including recommendations on casing string design. This document does not include specific criteria for how to assess the performance of equipment. Since current connection evaluation protocols such as API RP 5C5 and ISO/PAS 12835 do not target the types of loading that are commonly observed in hydraulically fractured wells, connections that are evaluated under these protocols may not be suitable for hydraulic fracturing. Due to the critical role that casing connections play in well integrity, various industry stakeholders (operators and connection manufacturers) discussed the concept of creating an application-specific method to evaluate casing connection performance in hydraulically fractured wells. In 2016 the API established a committee of industry experts under Work Item (WI) 3081 to develop this new evaluation protocol for casing connections used in hydraulically fractured wells. This protocol will provide users with a means to evaluate casing connection performance under a consistent method of discrete test program elements developed to replicate the cyclic rot
水力压裂作为一种增产手段，已成为从低孔低渗含油气地层中提取油气的有效途径。用于支持水力压裂的技术正在快速发展，这使得世界各地的运营商能够在日益复杂的井环境中实现更高的采收率。与水力压裂相关的井设计和完井策略面临着一系列独特的挑战。在造井过程中，大位移井的长水平段可能需要旋转生产(或中间)套管，并将其推入曲率相对较大的造井段(每100英尺或30米大于10°);此外，一些作业者在固井过程中旋转套管以提高固井质量。这种旋转可以使构建段的套管连接承受大量的旋转弯曲载荷循环。这种循环载荷会导致套管连接处的螺纹根部产生高应力，这可能导致材料的局部屈服和潜在的结构破坏。水力压裂过程本身会使生产套管内压力快速增加到很高的量级，这将导致多级井的循环压力加载。考虑到这些因素，在水力压裂井中使用的套管连接在生产之前可能会受到显著的循环载荷，这种载荷可能会影响后续井作业中套管连接的整体密封性和结构能力。2015年，美国石油协会(API)发布了第一版推荐实施细则100-1《水力压裂—井完整性和裂缝遏制》，为行业提供了水力压裂井设计的指南和考虑因素，包括套管柱设计的建议。本文件不包括如何评估设备性能的具体标准。由于目前的连接评估协议，如API RP 5C5和ISO/PAS 12835，并没有针对水力压裂井中常见的载荷类型，因此根据这些协议进行评估的连接可能不适合水力压裂。由于套管连接在井的完整性中起着至关重要的作用，各个行业的利益相关者(运营商和连接制造商)都在讨论创建一种特定于应用的方法来评估水力压裂井中套管连接性能的概念。2016年，美国石油协会在工作项目(WI) 3081下成立了一个行业专家委员会，为水力压裂井中使用的套管接头制定新的评估方案。该方案将为用户提供一种在离散测试程序元素的一致方法下评估套管连接性能的方法，该测试程序元素可以复制造井过程中的循环旋转弯曲载荷和多级水力压裂的压力循环。与之前的协议不同，该协议将不遵循传统的规定性方法，而是允许最终用户自定义由代表其应用程序的各种元素组成的测试程序。一旦发布，该协议将被称为API技术报告(TR) 5SF，《多裂缝水平井套管连接性能评价指南》。本文将总结API TR 5SF的开发，以及为复制水力压裂井的独特载荷而创建的各种测试程序元素，并提供可以从各种测试程序元素中衍生出的定制测试程序示例。
{"title":"Developing an Evaluation Method for Casing Connections used in Hydraulically Fractured Wells","authors":"K. Hamilton, P. Pattillo","doi":"10.2118/194369-MS","DOIUrl":"https://doi.org/10.2118/194369-MS","url":null,"abstract":"\u0000 Hydraulic fracturing as a means to stimulate production has become an effective way to extract oil and gas from low-porosity, low-permeability, hydrocarbon-bearing formations. The technology used in support of hydraulic fracturing is evolving at a fast rate, which has enabled operators worldwide to achieve improved recovery in increasingly complex well environments.\u0000 The well designs and completion strategies associated with hydraulic fracturing come with a unique set of challenges. During well construction, the long lateral sections of extended-reach wells may require the production (or intermediate) casing to be rotated and pushed through build sections of relatively high curvature (greater than 10° per 100 feet or 30 meters); furthermore, some operators rotate the casing during cementing to improve cement quality. This rotation can subject the casing connections in the build section to a high number of rotating-bending load cycles. This cyclic loading can result in high stresses in the thread roots of the casing connections, which may lead to localized yielding of the material and potential structural failure. The hydraulic fracturing process itself subjects the production casing to rapid increases in internal pressure to high magnitudes, which will result in cyclic pressure loading for wells with multiple stages. Given these considerations, casing connections that are used in hydraulically fractured wells can be subjected to significant cyclic loading before the well is produced, and this loading may have an impact on the overall casing connection sealing and structural capacity in subsequent well operations.\u0000 In 2015 the American Petroleum Institute (API) published the first edition of Recommended Practice 100-1, Hydraulic Fracturing – Well Integrity and Fracture Containment, to provide the industry with guidelines and considerations for hydraulically fractured well designs, including recommendations on casing string design. This document does not include specific criteria for how to assess the performance of equipment. Since current connection evaluation protocols such as API RP 5C5 and ISO/PAS 12835 do not target the types of loading that are commonly observed in hydraulically fractured wells, connections that are evaluated under these protocols may not be suitable for hydraulic fracturing. Due to the critical role that casing connections play in well integrity, various industry stakeholders (operators and connection manufacturers) discussed the concept of creating an application-specific method to evaluate casing connection performance in hydraulically fractured wells.\u0000 In 2016 the API established a committee of industry experts under Work Item (WI) 3081 to develop this new evaluation protocol for casing connections used in hydraulically fractured wells. This protocol will provide users with a means to evaluate casing connection performance under a consistent method of discrete test program elements developed to replicate the cyclic rot","PeriodicalId":10957,"journal":{"name":"Day 1 Tue, February 05, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84636225","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：