The performance and completion efficiency of horizontal multistage hydraulically fractured wells stimulated using the plug-and-perf technique are affected by the uniformity of the multiple perforation cluster treatment. Depending on reservoir heterogeneity, perforation design, and pumping schedule, uneven distribution of fluid and proppant among fractures connected to different perforation clusters can be defined by wellbore proppant transport hydrodynamics, fracture propagation mechanics, or a complex interplay of both. A modeling case study exploring strategies to mitigate nonuniformity of cluster stimulation is presented. Approaches to perforation and treatment optimization are chosen based on consideration of reservoir properties and their heterogeneity. A numerical model coupling a recently developed wellbore flow simulator and an advanced fracture simulator enables comprehensive simulations including both realistic fracture and wellbore modeling for complex perforation designs, treatment schedules, and distributions of reservoir inhomogeneities. The wellbore simulator considers proppant transport and settling, fluid rheology, perforation erosion, rate- and concentration-dependent pressure drop, and variable efficiency of proppant transport to perforations. The fracture simulator models fracture growth, fluid flow, proppant transport inside fractures, and interaction between fracture branches due to stress shadow effect. The interaction between hydraulic and pre-existing natural fractures plays a critical role during fracturing treatments in formations with pre-existing discrete fracture network (DFN). The model considers the effect of formation heterogeneity on fracture propagation, arrest of hydraulic fractures, crossing and opening of natural fractures depending on their properties, fluid viscosity, rate, and stress conditions. Several approaches for optimization of proppant distribution are suggested for cases showing nonperfect proppant transport efficiency caused by high proppant grain inertia. Tapered perforation designs enable achieving more even proppant distribution. However, perforation distribution among clusters providing best stimulation uniformity is sensitive to uncertainties in characterization and heterogeneity of reservoir and discrete fracture network properties. A combination of tapered perforation design and the suppression of inertial effects by increasing carrier fluid viscosity is more robust with respect to reservoir properties variation.
{"title":"Modeling Case Study: Optimizing Multicluster Stimulation Uniformity in Horizontal Wells","authors":"O. Kresse, K. Sinkov, B. Hobbs","doi":"10.2118/212318-ms","DOIUrl":"https://doi.org/10.2118/212318-ms","url":null,"abstract":"\u0000 The performance and completion efficiency of horizontal multistage hydraulically fractured wells stimulated using the plug-and-perf technique are affected by the uniformity of the multiple perforation cluster treatment. Depending on reservoir heterogeneity, perforation design, and pumping schedule, uneven distribution of fluid and proppant among fractures connected to different perforation clusters can be defined by wellbore proppant transport hydrodynamics, fracture propagation mechanics, or a complex interplay of both. A modeling case study exploring strategies to mitigate nonuniformity of cluster stimulation is presented. Approaches to perforation and treatment optimization are chosen based on consideration of reservoir properties and their heterogeneity. A numerical model coupling a recently developed wellbore flow simulator and an advanced fracture simulator enables comprehensive simulations including both realistic fracture and wellbore modeling for complex perforation designs, treatment schedules, and distributions of reservoir inhomogeneities. The wellbore simulator considers proppant transport and settling, fluid rheology, perforation erosion, rate- and concentration-dependent pressure drop, and variable efficiency of proppant transport to perforations. The fracture simulator models fracture growth, fluid flow, proppant transport inside fractures, and interaction between fracture branches due to stress shadow effect. The interaction between hydraulic and pre-existing natural fractures plays a critical role during fracturing treatments in formations with pre-existing discrete fracture network (DFN). The model considers the effect of formation heterogeneity on fracture propagation, arrest of hydraulic fractures, crossing and opening of natural fractures depending on their properties, fluid viscosity, rate, and stress conditions. Several approaches for optimization of proppant distribution are suggested for cases showing nonperfect proppant transport efficiency caused by high proppant grain inertia. Tapered perforation designs enable achieving more even proppant distribution. However, perforation distribution among clusters providing best stimulation uniformity is sensitive to uncertainties in characterization and heterogeneity of reservoir and discrete fracture network properties. A combination of tapered perforation design and the suppression of inertial effects by increasing carrier fluid viscosity is more robust with respect to reservoir properties variation.","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"15 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":"125474256","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}
Michael Kraynek, J. Miskimins, A. Eustes, D. Joshi, Mark Balderston
Re-fracturing is a common technique to ensure the maximum recovery from low-permeability, unconventional reservoirs. Generally in such reservoir systems, optimal gains are made from treating new areas of the reservoir that were unstimulated during the initial completion. To be successful under such circumstances, diversion away from depleted sections of the wellbore is critical. This paper discusses laboratory testing and subsequent finite element modeling (FEM) of full-length expandable casing patches deployed in several refracturing treatments in the Denver-Julesburg Basin, Colorado. Short sections of casing patches were deployed in 4.5′, 13.5# casing. These sections included unanchored and anchored patch components. One type of each section (anchored and unanchored) was then perforated with a full-size perforating gun, 4 shot each section, 90° phasing. The perforating took place at the Edgar Mine Testing Facility in Idaho Springs, Colorado. Both the anchored and unanchored, perforated and unperforated, patch/casing sections were then push/pull-tested to determine friction factors and the impacts of the perforating on the patch/casing interface. These results were then incorporated into FEM modeling to determine the ability of the full-size, field-deployed patch to remain stationary and the impact such would have on perforation alignment during treatment conditions. Both the push/pull tests and the subsequent FEM modeling suggest that the full-length casing patch exhibits only a minimal shift during the application of the forces associated with the hydraulic fracturing process. Some miss-alignment of perforations may occur but not to the level that they negatively impact the treatment success. These results align with the field trials which indicate positive re-fracturing treatment results. This unique project tested the viability of full-length casing patches in the refracturing process and incorporated laboratory testing of the casing-casing patch interfaces under both perforated and unperforated into FEM modeling, with comparison to field results. This process provides a full cycle analysis of the re-fracturing process using this diversion technique.
{"title":"Please Fill in Your Manuscript Title. Impacts of Perforating and Hydraulic Re-Fracturing on Expandable Casing Patches","authors":"Michael Kraynek, J. Miskimins, A. Eustes, D. Joshi, Mark Balderston","doi":"10.2118/212332-ms","DOIUrl":"https://doi.org/10.2118/212332-ms","url":null,"abstract":"\u0000 Re-fracturing is a common technique to ensure the maximum recovery from low-permeability, unconventional reservoirs. Generally in such reservoir systems, optimal gains are made from treating new areas of the reservoir that were unstimulated during the initial completion. To be successful under such circumstances, diversion away from depleted sections of the wellbore is critical. This paper discusses laboratory testing and subsequent finite element modeling (FEM) of full-length expandable casing patches deployed in several refracturing treatments in the Denver-Julesburg Basin, Colorado.\u0000 Short sections of casing patches were deployed in 4.5′, 13.5# casing. These sections included unanchored and anchored patch components. One type of each section (anchored and unanchored) was then perforated with a full-size perforating gun, 4 shot each section, 90° phasing. The perforating took place at the Edgar Mine Testing Facility in Idaho Springs, Colorado. Both the anchored and unanchored, perforated and unperforated, patch/casing sections were then push/pull-tested to determine friction factors and the impacts of the perforating on the patch/casing interface. These results were then incorporated into FEM modeling to determine the ability of the full-size, field-deployed patch to remain stationary and the impact such would have on perforation alignment during treatment conditions.\u0000 Both the push/pull tests and the subsequent FEM modeling suggest that the full-length casing patch exhibits only a minimal shift during the application of the forces associated with the hydraulic fracturing process. Some miss-alignment of perforations may occur but not to the level that they negatively impact the treatment success. These results align with the field trials which indicate positive re-fracturing treatment results. This unique project tested the viability of full-length casing patches in the refracturing process and incorporated laboratory testing of the casing-casing patch interfaces under both perforated and unperforated into FEM modeling, with comparison to field results. This process provides a full cycle analysis of the re-fracturing process using this diversion technique.","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":"130992038","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}
Anton Reshetnikov, Anna Nazarova, Scott Taylor, J. Haffener, D. Langton, A. Biholar, Sloan Anderson
A novel diagnostic processing technique called Conductive Fracture Imaging (CFI) measures hydraulic and conductive fractures using microseismic events as a source. The method was applied to three datasets located in onshore unconventional formations in the United States. CFI results were in all cases first delivered independent of any external diagnostic data and only subsequently compared to multiple diagnostics such as microseismic, fiber cross-well strain (CWS), 3D seismic, and recovered core under supervision of Devon Energy’s Subsurface Team. The comparison reveals a reasonable agreement of the CFI results with cross-well strain for both height and transverse conductive fracture growth. CFI was able to image fractures out 1 mile from the observation lateral, with fractures imaged in areas of no microseismic activity. Furthermore, CFI successfully quantified the height growth of fractures aligned with the pre-existing faults and how natural structures influence conductivity fracture distribution. CFI reveals a valid relationship with cored & interpreted conductive, hydraulic, and natural fractures. The method provides dynamic images showing fracture morphology from the near-wellbore into the far-field reservoir. Complimentary analytics of relationships between CFI and reservoir properties, limited entry perforation designs, stress shadowing, and depletion effects may generate significant new observations and key learnings to industry as this technique is more broadly adopted.
{"title":"Observations, Learnings, and Validation of Conductive Fracture Imaging","authors":"Anton Reshetnikov, Anna Nazarova, Scott Taylor, J. Haffener, D. Langton, A. Biholar, Sloan Anderson","doi":"10.2118/212374-ms","DOIUrl":"https://doi.org/10.2118/212374-ms","url":null,"abstract":"\u0000 A novel diagnostic processing technique called Conductive Fracture Imaging (CFI) measures hydraulic and conductive fractures using microseismic events as a source. The method was applied to three datasets located in onshore unconventional formations in the United States. CFI results were in all cases first delivered independent of any external diagnostic data and only subsequently compared to multiple diagnostics such as microseismic, fiber cross-well strain (CWS), 3D seismic, and recovered core under supervision of Devon Energy’s Subsurface Team.\u0000 The comparison reveals a reasonable agreement of the CFI results with cross-well strain for both height and transverse conductive fracture growth. CFI was able to image fractures out 1 mile from the observation lateral, with fractures imaged in areas of no microseismic activity. Furthermore, CFI successfully quantified the height growth of fractures aligned with the pre-existing faults and how natural structures influence conductivity fracture distribution.\u0000 CFI reveals a valid relationship with cored & interpreted conductive, hydraulic, and natural fractures. The method provides dynamic images showing fracture morphology from the near-wellbore into the far-field reservoir. Complimentary analytics of relationships between CFI and reservoir properties, limited entry perforation designs, stress shadowing, and depletion effects may generate significant new observations and key learnings to industry as this technique is more broadly adopted.","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"35 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":"117257985","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}
Pressure losses from pipe and perforation friction control the relation between wellhead pressure and pressure at the mouth (entrance) of hydraulic fractures. Because both pipe and perforation friction are proportional to flow rate squared, standard step-down tests that rely on the steady pressure response at a set of injection rates cannot uniquely determine pipe and perforation friction. We introduce a novel method to resolve this nonuniqueness by analyzing the water hammer response, measured by high-rate pressure sensors at the wellhead, following abrupt rate steps during shut-in following a stimulation treatment. Constraints on perforation friction permit quantification of the number of active perforations connecting to fractures and hence perforation cluster efficiency. Our method requires a shut-in procedure with abrupt drops in injection rate to produce water hammer oscillations (tube waves propagating between the wellhead and current stage). The rate drop is accompanied by a drop in wellhead pressure as a tube wave propagates away from the wellhead, decelerating the fluid behind it. Pipe friction attenuates this wave, such that the local flow rate remains higher at depth than near the wellhead. This expands the fluid, causing additional depressurization at the wellhead until the arrival of the reflected wave from the stage. The Darcy-Weisbach pipe friction factor is determined from the depressurization rate. At high background flow rates, the reflected wave amplitude is controlled by perforation friction with minimal sensitivity to fracture properties. The claims above are substantiated by numerical simulations of tube wave propagation and reflection from perforation clusters connected to hydraulic fractures. We then present two case studies in which the method is applied data from hydraulic fracturing treatments in two stages in different wells targeting the Wolfcamp and Bone Spring Formations, Permian Basin. The inferred pipe friction factor is 2×10−3, an order of magnitude smaller than for turbulent water flow, but consistent with the use of friction reducers and pumping company pressure loss tables. The measured perforation friction is higher than predictions based on a standard formula involving fluid density, discharge coefficient, entry hole diameter, and design number of holes. This suggests not all clusters connect to fractures; the inferred cluster efficiency is 67% (Case-A, Wolfcamp) and 84% (Case-B, Bone Spring). This work extends simulation and inversion capabilities utilizing wellhead data to nonlinear problems involving tube wave interactions with hydraulic fractures and perforations. The ability to independently constrain pipe and perforation friction resolves nonuniqueness of step rate tests. Rapid inversion enables us to deliver real-time measurements of perforation cluster efficiency, pipe and perforation friction that complement traditional fracture diagnostics. Combined with acoustic pulsing to quantify near-well
管柱压力损失和射孔摩擦控制着井口压力与水力裂缝口(口)压力的关系。由于管柱和射孔摩擦力都与流量的平方成正比，因此依赖于一组注入速率下的稳定压力响应的标准降压测试无法唯一地确定管柱和射孔摩擦力。我们引入了一种新的方法来解决这种非唯一性，通过分析井口高速率压力传感器测量的水锤响应，在增产处理后关井期间出现突然的速率变化。射孔摩擦的限制可以量化连接裂缝的活动射孔数量，从而量化射孔簇的效率。我们的方法需要一个关井过程，注入速度突然下降，产生水锤振荡(管波在井口和当前级之间传播)。当管波从井口传播出去时，速率的下降伴随着井口压力的下降，从而使其后面的流体减速。管道摩擦减弱了这种波，因此在深度处的局部流速仍然高于井口附近。这会使流体膨胀，在井口造成额外的降压，直到来自该级的反射波到达。Darcy-Weisbach管的摩擦系数由降压速率决定。在高背景流速下，反射波振幅由射孔摩擦控制，对裂缝特性的敏感性最小。上述观点得到了水力裂缝射孔簇中管波传播和反射的数值模拟的证实。然后，我们介绍了两个案例研究，其中该方法应用于二叠纪盆地Wolfcamp和Bone Spring地层不同井的两个阶段水力压裂处理数据。推断的管道摩擦系数为2×10−3，比湍流水流小一个数量级，但与摩擦减速器的使用和泵送公司的压力损失表一致。测量到的射孔摩擦比基于流体密度、流量系数、入孔直径和设计孔数的标准公式预测的要高。这表明并非所有簇都与骨折有关;推断集群效率为67% (Case-A, Wolfcamp)和84% (Case-B, Bone Spring)。这项工作将利用井口数据的模拟和反演能力扩展到涉及管波与水力裂缝和射孔相互作用的非线性问题。独立约束管柱和射孔摩擦的能力解决了阶跃速率测试的非唯一性问题。快速反演使我们能够提供射孔簇效率、管柱和射孔摩擦的实时测量，补充了传统的裂缝诊断。该方法结合声脉冲来量化井附近的流动阻力，为模拟处理过程中监测井与裂缝之间的关键连接提供了一种无创、经济有效的方法。该方法可用于诊断和治疗诸如簇间流体分布不均匀等问题。
{"title":"Constraints on Pipe Friction and Perforation Cluster Efficiency from Water Hammer Analysis","authors":"E. Dunham, Junwei Zhang, D. Moos","doi":"10.2118/212337-ms","DOIUrl":"https://doi.org/10.2118/212337-ms","url":null,"abstract":"\u0000 Pressure losses from pipe and perforation friction control the relation between wellhead pressure and pressure at the mouth (entrance) of hydraulic fractures. Because both pipe and perforation friction are proportional to flow rate squared, standard step-down tests that rely on the steady pressure response at a set of injection rates cannot uniquely determine pipe and perforation friction. We introduce a novel method to resolve this nonuniqueness by analyzing the water hammer response, measured by high-rate pressure sensors at the wellhead, following abrupt rate steps during shut-in following a stimulation treatment. Constraints on perforation friction permit quantification of the number of active perforations connecting to fractures and hence perforation cluster efficiency.\u0000 Our method requires a shut-in procedure with abrupt drops in injection rate to produce water hammer oscillations (tube waves propagating between the wellhead and current stage). The rate drop is accompanied by a drop in wellhead pressure as a tube wave propagates away from the wellhead, decelerating the fluid behind it. Pipe friction attenuates this wave, such that the local flow rate remains higher at depth than near the wellhead. This expands the fluid, causing additional depressurization at the wellhead until the arrival of the reflected wave from the stage. The Darcy-Weisbach pipe friction factor is determined from the depressurization rate. At high background flow rates, the reflected wave amplitude is controlled by perforation friction with minimal sensitivity to fracture properties.\u0000 The claims above are substantiated by numerical simulations of tube wave propagation and reflection from perforation clusters connected to hydraulic fractures. We then present two case studies in which the method is applied data from hydraulic fracturing treatments in two stages in different wells targeting the Wolfcamp and Bone Spring Formations, Permian Basin. The inferred pipe friction factor is 2×10−3, an order of magnitude smaller than for turbulent water flow, but consistent with the use of friction reducers and pumping company pressure loss tables. The measured perforation friction is higher than predictions based on a standard formula involving fluid density, discharge coefficient, entry hole diameter, and design number of holes. This suggests not all clusters connect to fractures; the inferred cluster efficiency is 67% (Case-A, Wolfcamp) and 84% (Case-B, Bone Spring).\u0000 This work extends simulation and inversion capabilities utilizing wellhead data to nonlinear problems involving tube wave interactions with hydraulic fractures and perforations. The ability to independently constrain pipe and perforation friction resolves nonuniqueness of step rate tests. Rapid inversion enables us to deliver real-time measurements of perforation cluster efficiency, pipe and perforation friction that complement traditional fracture diagnostics. Combined with acoustic pulsing to quantify near-well","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"35 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":"127240825","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, Karn Agarwal, E. Lolon, DK Fontana, M. Mayerhofer, Cyrille Defeu, K. Haustveit, J. Haffener
Creating a reliable, calibrated frac model used to be a long and expensive task in frac optimization. Today, with the proliferation of fracture diagnostics to calibrate models, simple frac dimensions can be calculated from indirect measurements on most North American shale fracs. Through the US Shale Revolution, fracturing operations have increasingly focused on pumping efficiencies. "Factory mode" operations today often allow little time for what used to be a lengthy optimization process of estimating fracture dimension sensitivity to job design changes for well placement selection and optimization of production economics. While some new fracture diagnostics have been designed to do measurements without interfering with frac operations, the calibrated models that harness these measurements remain cumbersome. We have developed a practical engineering tool that can extend the use of direct measurements to all shale horizontal well frac jobs. Unlike complex models that require lots of inputs and that are only routinely run on a few stages in a limited fraction of all North American shale wells, this Back-of-the-Envelope (BoE) model can be run effectively on every horizontal well stage. To date, it has been run on almost a quarter million stages. The BoE model provides two main advantages: (1) utilization of average basin diagnostic feedback and model calibration for more realistic results, and (2) augmenting more complex models on a much larger scale through a simpler workflow. The BoE model incorporates key fundamental processes in elliptical-shaped hydraulic fracture growth, including conservation of mass; limited entry-driven cluster distribution into simultaneously growing equal-sized multiple fractures; and Sneddon width profile with calibrated coupling over the fracture height. The physical model is further constrained by assuming a fixed half-length-to-height ratio from direct observation of hydraulic fracture growth. The BoE fracture model can be described with a few different rock mechanical fracture design and treatment parameters and ISIP measurements at the end of each fracture treatment stage. A key feature of the BoE model is that direct measurements are directly incorporated as an inherent calibration step. The model is anchored to basin closure stress measurements from DFITs and calibrated with past fracture geometry measurements, for example from Volume-to-First-Response data provided through Sealed Wellbore Pressure Monitoring (SWPM), or from other direct fracture diagnostics. In our paper, we present the results of this simple model and compare it with more complex fracture modeling efforts and fracture diagnostic results in a few major US shale basins.
{"title":"A Back-Of-The-Envelope Model to Estimate Dimensions for Every Shale Frac","authors":"L. Weijers, Karn Agarwal, E. Lolon, DK Fontana, M. Mayerhofer, Cyrille Defeu, K. Haustveit, J. Haffener","doi":"10.2118/212339-ms","DOIUrl":"https://doi.org/10.2118/212339-ms","url":null,"abstract":"\u0000 Creating a reliable, calibrated frac model used to be a long and expensive task in frac optimization. Today, with the proliferation of fracture diagnostics to calibrate models, simple frac dimensions can be calculated from indirect measurements on most North American shale fracs.\u0000 Through the US Shale Revolution, fracturing operations have increasingly focused on pumping efficiencies. \"Factory mode\" operations today often allow little time for what used to be a lengthy optimization process of estimating fracture dimension sensitivity to job design changes for well placement selection and optimization of production economics. While some new fracture diagnostics have been designed to do measurements without interfering with frac operations, the calibrated models that harness these measurements remain cumbersome.\u0000 We have developed a practical engineering tool that can extend the use of direct measurements to all shale horizontal well frac jobs. Unlike complex models that require lots of inputs and that are only routinely run on a few stages in a limited fraction of all North American shale wells, this Back-of-the-Envelope (BoE) model can be run effectively on every horizontal well stage. To date, it has been run on almost a quarter million stages. The BoE model provides two main advantages: (1) utilization of average basin diagnostic feedback and model calibration for more realistic results, and (2) augmenting more complex models on a much larger scale through a simpler workflow.\u0000 The BoE model incorporates key fundamental processes in elliptical-shaped hydraulic fracture growth, including conservation of mass; limited entry-driven cluster distribution into simultaneously growing equal-sized multiple fractures; and Sneddon width profile with calibrated coupling over the fracture height. The physical model is further constrained by assuming a fixed half-length-to-height ratio from direct observation of hydraulic fracture growth.\u0000 The BoE fracture model can be described with a few different rock mechanical fracture design and treatment parameters and ISIP measurements at the end of each fracture treatment stage. A key feature of the BoE model is that direct measurements are directly incorporated as an inherent calibration step. The model is anchored to basin closure stress measurements from DFITs and calibrated with past fracture geometry measurements, for example from Volume-to-First-Response data provided through Sealed Wellbore Pressure Monitoring (SWPM), or from other direct fracture diagnostics.\u0000 In our paper, we present the results of this simple model and compare it with more complex fracture modeling efforts and fracture diagnostic results in a few major US shale basins.","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"99 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":"121563194","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. Al Kalbani, Ali Al Ghaithi, S. Al Kindi, A. Christiawan, R. Yuyan
High permeability hydraulic fracturing in Nimr cluster of oil fields within the Sultanate of Oman has been gaining momentum in recent years. This is despite of the inherent resistance towards deferring producing wells for a typically long intervention such as hydraulic fracturing. In part, that is due to the required pre fracturing preparation which ranges from removing low grade existing completion, removal of artificial lift pumps, installing fracturing completion, and finally post fracturing recompletion. This is in addition to damage presented by less-than-optimal fracturing fluids which may impair well productivity, especially in cases where oil is of moderate to high viscosity. Hence hydraulic fracturing of high permeability formations within Nimr fields dictated an optimal candidate selection process. This paper presents well-defined candidate selection criteria derived from regression modelling, in addition to design related optimizations such as the utilization of reduced gel loading designs and enhancing oxidizing breaker concentration for better cleanup and flowback. As part of the study within this paper, fracturing water injectors presented a less risky endeavor due to a shorter turnaround time from pre to post fracturing. It also presented an opportunity to enhance sweep efficiency in fields where water injectors are underperforming. Injector wells within the Nimr cluster of fields generally target high permeability formations (10-200 mD), however due to the quality of injected water and the degree of self-scaling due to temperature and pressure changes, skin build up is common. Hence the introduction of fracturing presented an efficient technique to bypass damage and generate larger conductive effective wellbore radii. This paper describes the restoration of several poorly performing producer and injectors that were treated between 2021 and 2022 using hydraulic fracturing. Injection results as well as post fracturing sweep efficiencies were compared to those prior to fracturing. These wells were also assessed in perspective of their injection patterns where results have shown substantial pressure support to nearby wells without fast-tracking water breakthrough. This resulted in the revival of some producer wells that were previously closed in due to poor aquifer pressure support.
{"title":"Enhancing Productivity and Injectivity in the Sultanate of Oman's Nimr Cluster Using Hydraulic Fracturing; Challenging The Status Quo in High Permeability Fracturing","authors":"M. Al Kalbani, Ali Al Ghaithi, S. Al Kindi, A. Christiawan, R. Yuyan","doi":"10.2118/212327-ms","DOIUrl":"https://doi.org/10.2118/212327-ms","url":null,"abstract":"\u0000 High permeability hydraulic fracturing in Nimr cluster of oil fields within the Sultanate of Oman has been gaining momentum in recent years. This is despite of the inherent resistance towards deferring producing wells for a typically long intervention such as hydraulic fracturing. In part, that is due to the required pre fracturing preparation which ranges from removing low grade existing completion, removal of artificial lift pumps, installing fracturing completion, and finally post fracturing recompletion. This is in addition to damage presented by less-than-optimal fracturing fluids which may impair well productivity, especially in cases where oil is of moderate to high viscosity.\u0000 Hence hydraulic fracturing of high permeability formations within Nimr fields dictated an optimal candidate selection process. This paper presents well-defined candidate selection criteria derived from regression modelling, in addition to design related optimizations such as the utilization of reduced gel loading designs and enhancing oxidizing breaker concentration for better cleanup and flowback.\u0000 As part of the study within this paper, fracturing water injectors presented a less risky endeavor due to a shorter turnaround time from pre to post fracturing. It also presented an opportunity to enhance sweep efficiency in fields where water injectors are underperforming.\u0000 Injector wells within the Nimr cluster of fields generally target high permeability formations (10-200 mD), however due to the quality of injected water and the degree of self-scaling due to temperature and pressure changes, skin build up is common. Hence the introduction of fracturing presented an efficient technique to bypass damage and generate larger conductive effective wellbore radii.\u0000 This paper describes the restoration of several poorly performing producer and injectors that were treated between 2021 and 2022 using hydraulic fracturing. Injection results as well as post fracturing sweep efficiencies were compared to those prior to fracturing. These wells were also assessed in perspective of their injection patterns where results have shown substantial pressure support to nearby wells without fast-tracking water breakthrough. This resulted in the revival of some producer wells that were previously closed in due to poor aquifer pressure support.","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"152 10","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131747038","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}
Downhole imaging technology has been widely utilized in recent years to help diagnose proppant distribution during hydraulic fracturing operations. Abrasion leading to entry hole enlargement provides strong evidence of proppant placement into individual perforations, and treatment volume can be inferred by measuring the magnitude of this erosion. Results from individual perforations are easily aggregated to cluster and stage level to provide information on overall treatment distribution. Two different technologies have been deployed for this purpose – an array of downhole video cameras able to capture a full 360 view of the borehole and, more recently, multi-transducer ultrasonic instruments. These services have been considered competitors, and arguments for and against both technologies have included their relative measurement resolutions and how this impacts result accuracy, along with sensitivity to ‘stick and slip’ effects on toolstring motion. Both technologies are also affected to differing degrees by the well fluid and the presence of diverters and proppant in perforations. The recent introduction of a toolstring able to simultaneously acquire images from both sensor types affords the opportunity to objectively compare results acquired under identical conditions and establish their merits and limitations. The paper considers the underlying physical principles of each of the measurements and reviews in detail the real world results from North American wells that have been logged using both technologies. The aim of the paper is to provide a more complete understanding of the technologies involved, and how they can be viewed as complementary rather than competitive when they are run simultaneously, allowing potential users to make fully informed decisions on when, why and how to deploy them. We will also demonstrate how the information derived from simultaneous application is of greater value than that derived from the individual technologies in isolation, and how this can be applied to further enhance completion design and frac execution for unconventional wells.
{"title":"Combined Video and Ultrasonic Measurements for Fracture Diagnostics – Greater Than the Sum of the Parts","authors":"T. Tymons, Glyn Roberts, D. Troup","doi":"10.2118/212322-ms","DOIUrl":"https://doi.org/10.2118/212322-ms","url":null,"abstract":"\u0000 Downhole imaging technology has been widely utilized in recent years to help diagnose proppant distribution during hydraulic fracturing operations. Abrasion leading to entry hole enlargement provides strong evidence of proppant placement into individual perforations, and treatment volume can be inferred by measuring the magnitude of this erosion. Results from individual perforations are easily aggregated to cluster and stage level to provide information on overall treatment distribution.\u0000 Two different technologies have been deployed for this purpose – an array of downhole video cameras able to capture a full 360 view of the borehole and, more recently, multi-transducer ultrasonic instruments. These services have been considered competitors, and arguments for and against both technologies have included their relative measurement resolutions and how this impacts result accuracy, along with sensitivity to ‘stick and slip’ effects on toolstring motion. Both technologies are also affected to differing degrees by the well fluid and the presence of diverters and proppant in perforations. The recent introduction of a toolstring able to simultaneously acquire images from both sensor types affords the opportunity to objectively compare results acquired under identical conditions and establish their merits and limitations.\u0000 The paper considers the underlying physical principles of each of the measurements and reviews in detail the real world results from North American wells that have been logged using both technologies.\u0000 The aim of the paper is to provide a more complete understanding of the technologies involved, and how they can be viewed as complementary rather than competitive when they are run simultaneously, allowing potential users to make fully informed decisions on when, why and how to deploy them. We will also demonstrate how the information derived from simultaneous application is of greater value than that derived from the individual technologies in isolation, and how this can be applied to further enhance completion design and frac execution for unconventional wells.","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"132 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":"116624970","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. Rylance, H. Kogsboll, C. Cipolla, C. Montgomery, M. B. Smith, W. D. Norman, K. Olson, C. Pearson
The focus on unconventional technology and operations, has been relentless during the last 15 - 20 years, while conventional operations have continued to tick along delivering their effective solutions globally. However, with unconventional operations dominating, it is inevitable that we run the risk of a fading knowledge base regarding the valuable contributions and hard lessons that have been learned with conventional techniques such as Tip Screen Out (TSO). This paper will present a global update on the development and application and continued success of this very specialised technique. The paper will describe the original development of the TSO process, design, deployment, refinement, and its broader application. A suite of case histories will demonstrate that every major operator in every major basin worldwide has successfully applied this technique to enhance production, where its use was both applicable and conditions made it possible. From highly specialised applications in North Sea chalks, to field developments in higher and medium permeability in Alaska and Siberia. From utilisation as an enabling solution in gas-condensates of South America, Middle East, and South-East Asia; and additionally, with the development of the Frac-Pack technique, delivery of a key sand-control completion method, crucial to GoM, Brazil and Global soft-rock oil production delivery. The paper will describe a range of requirements behind each consideration of deployment of the TSO technique, as well as specific in-situ characteristics that are required to support such application. It will describe the nuances of fracture design, material utilisation and adjustments that may be required to ensure effective delivery. The paper will also outline examples where the TSO process was the difference between success and failure. Finally, the paper will also cover some of the surveillance approaches utilised allowing a direct confirmation of the TSO process. All the extensive supporting evidence for this application will show how invaluable this technique has been to the Oil & Gas industry. In summary the paper will demonstrate the value which this technique has delivered in all its varied forms of application. It will enshrine the knowledge and lessons learned over 40 years of application and ensure that any short-term technical direction does not run the risk of disregarding the previously hard- won experiences of previous decades. Enshrined as an option in conventional fracturing techniques, the TSO process demonstrates the longevity that is associated with fundamentally sound engineering.
在过去的15 - 20年里，非常规技术和作业一直是人们关注的焦点，而传统作业则继续在全球范围内提供有效的解决方案。然而，随着非常规作业的主导地位，我们不可避免地会面临知识库衰退的风险，这些知识库涉及到传统技术(如Tip Screen Out (TSO))的宝贵贡献和惨痛教训。本文将介绍这一非常专业的技术的发展和应用以及持续成功的全球最新情况。本文将描述TSO过程的原始发展、设计、部署、改进及其更广泛的应用。一系列的历史案例将证明，世界上每个主要盆地的每个主要运营商都成功地应用了该技术来提高产量，在这些地区，该技术既适用，条件也允许。从北海白垩的高度专业化应用，到阿拉斯加和西伯利亚的高渗透率和中渗透率的现场开发。作为南美、中东和东南亚天然气凝析油的有利解决方案;此外，随着fracpack技术的发展，提供了一种关键的防砂完井方法，对墨西哥湾、巴西和全球的软岩油生产交付至关重要。本文将描述每种TSO技术部署考虑背后的一系列要求，以及支持此类应用所需的特定原位特征。它将描述裂缝设计、材料利用和调整的细微差别，以确保有效交付。本文还将概述一些例子，说明TSO过程是成功与失败的区别。最后，本文还将介绍一些用于直接确认TSO过程的监测方法。所有支持该应用的大量证据都表明，该技术对石油和天然气行业来说是多么宝贵。总之，本文将展示该技术在其所有不同形式的应用中所提供的价值。它将把过去40年的应用所获得的知识和教训铭记在心，并确保任何短期的技术指导都不会冒着忽视过去几十年来之不易的经验的风险。作为常规压裂技术的一种选择，TSO工艺证明了与基础良好的工程相关的寿命。
{"title":"Tip Screen Out Fracturing Delivering Optimum Performance in Conventional Applications for 40 years: Case Histories and Lessons Learned","authors":"M. Rylance, H. Kogsboll, C. Cipolla, C. Montgomery, M. B. Smith, W. D. Norman, K. Olson, C. Pearson","doi":"10.2118/212365-ms","DOIUrl":"https://doi.org/10.2118/212365-ms","url":null,"abstract":"\u0000 The focus on unconventional technology and operations, has been relentless during the last 15 - 20 years, while conventional operations have continued to tick along delivering their effective solutions globally. However, with unconventional operations dominating, it is inevitable that we run the risk of a fading knowledge base regarding the valuable contributions and hard lessons that have been learned with conventional techniques such as Tip Screen Out (TSO). This paper will present a global update on the development and application and continued success of this very specialised technique.\u0000 The paper will describe the original development of the TSO process, design, deployment, refinement, and its broader application. A suite of case histories will demonstrate that every major operator in every major basin worldwide has successfully applied this technique to enhance production, where its use was both applicable and conditions made it possible. From highly specialised applications in North Sea chalks, to field developments in higher and medium permeability in Alaska and Siberia. From utilisation as an enabling solution in gas-condensates of South America, Middle East, and South-East Asia; and additionally, with the development of the Frac-Pack technique, delivery of a key sand-control completion method, crucial to GoM, Brazil and Global soft-rock oil production delivery.\u0000 The paper will describe a range of requirements behind each consideration of deployment of the TSO technique, as well as specific in-situ characteristics that are required to support such application. It will describe the nuances of fracture design, material utilisation and adjustments that may be required to ensure effective delivery. The paper will also outline examples where the TSO process was the difference between success and failure. Finally, the paper will also cover some of the surveillance approaches utilised allowing a direct confirmation of the TSO process. All the extensive supporting evidence for this application will show how invaluable this technique has been to the Oil & Gas industry.\u0000 In summary the paper will demonstrate the value which this technique has delivered in all its varied forms of application. It will enshrine the knowledge and lessons learned over 40 years of application and ensure that any short-term technical direction does not run the risk of disregarding the previously hard- won experiences of previous decades. Enshrined as an option in conventional fracturing techniques, the TSO process demonstrates the longevity that is associated with fundamentally sound engineering.","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"354 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":"132617004","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This case study looked to identify a perforation design and a perforation charge that measurably increases Perforation Efficiency (PE) and reduces PE variability from stage to stage. Achieving these goals allows for more economic fracture surface area generation as well as more informed decisions toward frac design and full field development. Primarily relying on industry-standard pre-fracture Step-Down Tests (SDT) to estimate number of perforation holes open, a variety of strategies and technologies were tested by altering perforation friction, orientation, entry hole diameter (EHD), perforations per cluster (PPC), and charge type. The trial was performed across multiple horizons in the Delaware Basin, consisting of over 4,500 stages from 193 wells across 13 horizons from the 1st Bone Spring Sand to the Wolfcamp C in Lea and Eddy Counties, New Mexico. With the legacy perforation strategy and technology, the operator historically achieved a probability 50 (P50) using the cumulative distribution function (CDF) of 47% of perforations open pre-fracture. Utilizing eXtreme Limited Entry (XLE), 0 degree-oriented perforating, larger EHD, single perforation clusters, and a shaped charge which increases the reservoir contact area, the operator was able to increase the CDF P50 to 93% of perforations open pre-fracture. This straightforward trial allowed the operator to meaningfully reduce the cost of operations while type curves were met or exceeded. Contributing to the success of this field trial was a clear and restricted design of the experiment in combination with a special shale-optimized perforating charge designed for greater near wellbore reservoir contact area.
本案例研究旨在确定能够显著提高射孔效率(PE)并减少不同压裂段PE变化的射孔设计和射孔装药。实现这些目标可以更经济地产生裂缝表面积，并在压裂设计和全油田开发方面做出更明智的决策。主要依靠行业标准的压裂前降压测试(SDT)来估计已打开的射孔孔数，通过改变射孔摩擦、射孔方位、入孔直径(EHD)、每簇射孔数(PPC)和装药类型，测试了各种策略和技术。该试验在Delaware盆地的多个层位进行，包括从第1 Bone Spring Sand到新墨西哥州Lea和Eddy县的Wolfcamp C的13个层位的193口井的4500多个阶段。利用传统的射孔策略和技术，作业者利用累积分布函数(CDF)实现了50%的概率(P50)，即47%的射孔在压裂前打开。利用极限有限射孔(XLE)、0度定向射孔、更大的EHD、单个射孔簇以及增加储层接触面积的聚能装药，作业者能够将CDF P50提高到93%的压裂前射孔。这项简单的试验使作业者在满足或超过类型曲线的情况下显著降低了作业成本。现场试验的成功得益于实验设计的清晰和限制，以及一种特殊的页岩优化射孔药，该射孔药设计用于更大的近井油藏接触面积。
{"title":"Optimization of Perforation Efficiency in the Delaware Basin Through XLE Perforating and Innovative Perforating Charge; A Case Study","authors":"Phil Churchwell, B. McQueen, Paul M. Weddle","doi":"10.2118/212345-ms","DOIUrl":"https://doi.org/10.2118/212345-ms","url":null,"abstract":"\u0000 This case study looked to identify a perforation design and a perforation charge that measurably increases Perforation Efficiency (PE) and reduces PE variability from stage to stage. Achieving these goals allows for more economic fracture surface area generation as well as more informed decisions toward frac design and full field development.\u0000 Primarily relying on industry-standard pre-fracture Step-Down Tests (SDT) to estimate number of perforation holes open, a variety of strategies and technologies were tested by altering perforation friction, orientation, entry hole diameter (EHD), perforations per cluster (PPC), and charge type. The trial was performed across multiple horizons in the Delaware Basin, consisting of over 4,500 stages from 193 wells across 13 horizons from the 1st Bone Spring Sand to the Wolfcamp C in Lea and Eddy Counties, New Mexico.\u0000 With the legacy perforation strategy and technology, the operator historically achieved a probability 50 (P50) using the cumulative distribution function (CDF) of 47% of perforations open pre-fracture. Utilizing eXtreme Limited Entry (XLE), 0 degree-oriented perforating, larger EHD, single perforation clusters, and a shaped charge which increases the reservoir contact area, the operator was able to increase the CDF P50 to 93% of perforations open pre-fracture.\u0000 This straightforward trial allowed the operator to meaningfully reduce the cost of operations while type curves were met or exceeded. Contributing to the success of this field trial was a clear and restricted design of the experiment in combination with a special shale-optimized perforating charge designed for greater near wellbore reservoir contact area.","PeriodicalId":402242,"journal":{"name":"Day 2 Wed, February 01, 2023","volume":"79 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":"125002188","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}
D. Al-Muhanna, Zamzam Ahmed Abdul-Samad, Aliah Al-Qallaf, E. Fidan, Mansour Al-Awadhi, Y. Al-salali, Mohamed Abdel-Basset
The first ever CO2 foam fracturing new technology in Kuwait Oil Company (KOC) history was executed flawlessly in late 2021. Three treatments were executed. Co2 Foam Fracturing proved its significant added value of improving productivity in deep depleted tight carbonate Jurassic reservoirs, enhance flow back, reduce water consumption and carbon emission, and enable early production plus improving operation efficiency and cost saving. The stimulation operation has proven to be a huge success for all multidisciplinary teams involved as preliminary results showed over 50-70% production increase compared to offset wells. The main challenges of acid fracturing stimulation in depleted reservoirs are the need for extended formation cleanup to flow back the injected fluids via prolonging Nitrogen lift that add higher operational costs and intervention operations. Therefore, energetic high foam efficiency frac fluid becomes essential to assist flowback and retrieve pumped frac fluids from reservoir. To tackle these challenges, Carbon Dioxide CO2 is pumped in liquid phase as energetic fluid together with normal frac fluids. Due to CO2 liquid nature, high foam efficiency can be reached (40 – 50%) at much lower friction losses. So, it enables achieving pumping frac at high rates and high foam efficiency. The main benefits of CO2 Foam frac are better fracture cleanup due to expansion of the stored compressed gas in the liquid CO2, fluid loss control that is provided by foam, minimized fracture conductivity damage, and the increase in hydrostatic pressure while pumping that translates to lower surface pressures during injection. The selected pilot well is in depleted deep tight carbonate reservoir area of North Kuwait Jurassic gas fields. The executed acid fracturing operation required close planning starting from Q1-2021. Many challenges faced from logistical issues, lack of infrastructure and CO2 resources for the multi-faceted operation due to COVID-19 pandemic limitations. These challenges were tackled ahead with the integration of technical and operations teams to bridge the knowledge gap and to enable executing the operation safely. The pilot well's net incremental production gain is estimated at 50-70% compared to offset wells, with improved flowback and formation cleanup with less well intervention. The resulting time and cost savings as well as the incremental well productivity and better operation efficiency confirmed high perspectives for the implemented foam acid fracturing approach. Another two CO2 Foam acid fracturing wells were executed with good results too. This paper will demonstrate the value of CO2 foam fracturing in depleted reservoir and KOC experience post first application and its plans to expand CO2 Foam Fracturing application across KOC different fields.
{"title":"First Ever in Kuwait, Successful Application of CO2 Foam Acid Fracturing Enables Paradigm Shift in Stimulation Strategy of Kuwait Jurassic Depleted Reservoirs","authors":"D. Al-Muhanna, Zamzam Ahmed Abdul-Samad, Aliah Al-Qallaf, E. Fidan, Mansour Al-Awadhi, Y. Al-salali, Mohamed Abdel-Basset","doi":"10.2118/212361-ms","DOIUrl":"https://doi.org/10.2118/212361-ms","url":null,"abstract":"\u0000 The first ever CO2 foam fracturing new technology in Kuwait Oil Company (KOC) history was executed flawlessly in late 2021. Three treatments were executed. Co2 Foam Fracturing proved its significant added value of improving productivity in deep depleted tight carbonate Jurassic reservoirs, enhance flow back, reduce water consumption and carbon emission, and enable early production plus improving operation efficiency and cost saving. The stimulation operation has proven to be a huge success for all multidisciplinary teams involved as preliminary results showed over 50-70% production increase compared to offset wells.\u0000 The main challenges of acid fracturing stimulation in depleted reservoirs are the need for extended formation cleanup to flow back the injected fluids via prolonging Nitrogen lift that add higher operational costs and intervention operations. Therefore, energetic high foam efficiency frac fluid becomes essential to assist flowback and retrieve pumped frac fluids from reservoir. To tackle these challenges, Carbon Dioxide CO2 is pumped in liquid phase as energetic fluid together with normal frac fluids. Due to CO2 liquid nature, high foam efficiency can be reached (40 – 50%) at much lower friction losses. So, it enables achieving pumping frac at high rates and high foam efficiency. The main benefits of CO2 Foam frac are better fracture cleanup due to expansion of the stored compressed gas in the liquid CO2, fluid loss control that is provided by foam, minimized fracture conductivity damage, and the increase in hydrostatic pressure while pumping that translates to lower surface pressures during injection.\u0000 The selected pilot well is in depleted deep tight carbonate reservoir area of North Kuwait Jurassic gas fields. The executed acid fracturing operation required close planning starting from Q1-2021. Many challenges faced from logistical issues, lack of infrastructure and CO2 resources for the multi-faceted operation due to COVID-19 pandemic limitations. These challenges were tackled ahead with the integration of technical and operations teams to bridge the knowledge gap and to enable executing the operation safely.\u0000 The pilot well's net incremental production gain is estimated at 50-70% compared to offset wells, with improved flowback and formation cleanup with less well intervention. The resulting time and cost savings as well as the incremental well productivity and better operation efficiency confirmed high perspectives for the implemented foam acid fracturing approach. Another two CO2 Foam acid fracturing wells were executed with good results too.\u0000 This paper will demonstrate the value of CO2 foam fracturing in depleted reservoir and KOC experience post first application and its plans to expand CO2 Foam Fracturing application across KOC different fields.","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":"130864761","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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