Day 2 Wed, February 02, 2022最新文献

{"title":"Isip or Fracture Extension Pressure?","authors":"R. Barree","doi":"10.2118/209170-ms","DOIUrl":"https://doi.org/10.2118/209170-ms","url":null,"abstract":"\u0000 The term \"ISIP\", meaning instantaneous shut-in pressure, is often used to represent the fracture extension pressure (FEP), and to determine the reported fracture extension gradient. In vertical wells, with minimal near-well friction, this equivalence was often acceptable. In horizontal wells, the difference between an \"instantaneous\" ISIP and FEP can exceed 1000 psi. Misinterpretation of the FEP and fracture extension gradient can lead to critical misunderstandings regarding fracture orientation and geometry. This paper explains the difference between ISIP, as often misinterpreted, and fracture extension pressure (FEP) and presents a proven method for determining the correct FEP, extension gradient, and near-well frictional pressure.","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"186 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131888416","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Optimizing Longitudinal Fracture Design for Horizontal Well Completions in Laminated Sandstone Reservoirs","authors":"Junjing Zhang, N. Zwarich, R. Burton, P. Carman, E. Davis, M. Nozaki, B. Buck, Adam M. Lewis, B. Wendt","doi":"10.2118/209158-ms","DOIUrl":"https://doi.org/10.2118/209158-ms","url":null,"abstract":"\u0000 Horizontal wells with multi-stage longitudinal fractures have been widely used to develop low-to-moderate permeability sandstone formations in enhanced oil recovery schemes. A long-held misconception exists that high fracture conductivity is not essential to well productivity for longitudinal fractures in openhole completions because the pressure drop through the fracture is small due to the geometry. This study provides workflows to optimize longitudinal fracture design for horizontal well completions on the North Slope of Alaska and presents practical considerations that challenge this misconception.\u0000 Mechanical properties of core samples across the reservoir interval were evaluated by hardness-based strength calculators and tri-axial compression tests. Based on the rock strength profile, candidate intervals were selected for fracture conductivity measurements. Both summer (low salinity) and winter (high salinity) seawater based fracturing fluids were injected through the propped fracture cell containing both sandstone and mudstone lithologies. Numerical fracture models were built and matched to bottomhole pressures acquired during project appraisal well stimulations. Proppant concentration distribution along the fracture was generated for different design scenarios by varying proppant volume, proppant size, pump schedule, etc. The impact of various design scenarios on well production was also investigated.\u0000 Full alignment between the fracture plane and the wellbore results in the highest productivity for fractured horizontal wells with openhole completions. However, calculations demonstrate that even a few degrees of misalignment between horizontal well orientation and the maximum horizontal principal stress results in fracture deviation from the open hole. Due to flow along the fracture and convergence from the fracture to the wellbore, fracture conductivity dominates the pressure drop and completion skin factor for this geometry. Since actual fracture conductivities in wells on the North Slope of Alaska are not infinite, it is therefore inappropriate to use \"infinitely-acting\" fracture assumptions as has often been used historically for longitudinally fractured horizontal wells with openhole completions. Fracture conductivity tests show severe conductivity loss due to gel residue as well as mudstone and seawater interactions. Realistic discount factors for fracture conductivities in the targeted shallow sandstone-mudstone formations were developed for subsequent reservoir studies. Modeling results suggest that larger job sizes and bigger proppant are needed to achieve desirable skin factors and well inflow performance when the fracture becomes misaligned from the wellbore.","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"141 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131787194","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"New Casing Friction Model for Slickwater: Field Data Validation, Application, and Optimization for Hydraulic Fracturing","authors":"Nabijan Nizamidin, Amos Kim, Kristen Belcourt, Magdiel Angeles, Do Hoon Kim, Gojko Matovic, Eric Lege","doi":"10.2118/209133-ms","DOIUrl":"https://doi.org/10.2118/209133-ms","url":null,"abstract":"\u0000 During hydraulic fracturing, reliable characterization and modeling of friction pressures in casing as a function of flow rate, friction reducer (FR) type, FR dosage, and casing ID is critical to optimizing frac designs. However, measuring bottomhole pressures during hydraulic fracturing is challenging and often, casing friction pressure estimates are made with wellhead pressures along with step-down tests. These estimations can be inaccurate due to difficulties associated with decoupling casing friction pressures from perforation and near-wellbore pressure drops. A novel casing friction pressure model for FR is presented in this study and validated with field data.\u0000 The new multivariable friction model is based on lab FR rheology measurements and pipe velocity profile derivation of FR fluids. Step-down tests were implemented with 6 different FRs at various dosage rates to obtain friction pressures for a range of conditions. The friction pressures were estimated along the lateral of the well using innovative bottomhole gauges installed at two distinct locations on the casing string and were compared to our model to validate the accuracy.\u0000 Casing friction pressures between the wellhead gauge and the two BHGs were measured during various stages of a frac job. Six FRs were tested at concentrations ranging from 0.4-1 gpt at flow rates of 10 to 100 bpm. For each of these conditions, friction pressure data were collected for flow through various IDs in the 3-string casing design. With lab measured rheological properties and field data, the casing friction pressure model was successfully calibrated for each FR. The validated casing friction model was utilized with step-down tests to calibrate perforation friction pressure equation utilizing the kinetic energy erosion model and near-wellbore friction pressure equation. The three calibrated equations for friction components along with ISIP successfully estimated wellhead pressures during pumping for an entire stage as well as stages from toe to heel of 2-mile lateral. Some significant findings discovered from this study: less severe mechanical degradation effects observed in the field compared to lab flow loop measurements, casing friction pressure reductions plateau around 1-1.5 gpt of FR, and high-viscosity friction reducers typically possess higher casing friction pressures due to its higher viscosity.\u0000 The novelty of this study is the newly developed casing friction model for frac fluids with FRs. The model results in three main benefits. First, it allows for accurate estimation of FR performance in terms of casing friction pressures to optimize FR selection and dosages. Second, more precise estimation of casing friction pressures allows for evaluation of perforation and near-wellbore friction pressures as well as net pressures during pumping from just wellhead pressures coupled with a step-down test. Third, technical and economic feasibility studies can be performed to evaluate changes in lateral l","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"42 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114939686","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Estimating Fracture Containment in Layered Formations Using 3D Fracture Growth Assumptions","authors":"V. Pandey, R. Vamegh","doi":"10.2118/209151-ms","DOIUrl":"https://doi.org/10.2118/209151-ms","url":null,"abstract":"\u0000 Fracture growth in layered formations where the stresses and rock mechanical properties change frequently with depth is of great interest to researchers, especially when estimating the vertical growth of fractures in hydraulic fracturing treatments. The influence of formation stresses on fracture growth has been well documented and supported by numerous case histories, but the height-growth limitations resulting from intersection and crossing of various interfaces by the fracture continues to be investigated. This paper describes a model and a method to predict potential locations where a horizontal fracture can develop and limit the vertical growth of the fracture.\u0000 Most height growth predictions using traditional pseudo-3D (P3D) models result in planar fractures of widths that vary depending on the stresses and mechanical property of the layers that the fracture crosses. As evinced from the literature and laboratory experiments, the propagating cracks may have a three-dimensional (3D) characteristic given the observed combination of deviation (kinking) and out-of-plane displacements that can hinder the vertical growth. Multiple flaws leading to a 3D crack can be approximated as a two-dimensional (2D) model by considering it as a mixed boundary value triple pressurized-crack problem. In this paper, such representations are first used to obtain discrete stress intensity factors (SIF) at specific locations, and then, are superimposed on routine SIFs to include the influence of real-world 3D cracks on vertical growth estimation.\u0000 Fracture width profiles across several layers were generated using a modified equilibrium height growth model and were key to identifying the regions where complex growth in layered formations could potentially exist. These predictions resemble the analog for 3D fractures and given the fact that a portion of the treatment was injected at pressures that exceeded the overburden, alludes to the presence of a horizontal fracture component. Micro-seismic survey from the treatment shows vertical growth containment at the location where minimal width is projected. Three cases histories where these observations were made are also presented in the paper along with pertinent theory and explanations.\u0000 The model developed in the study is helpful in predicting potential locations where a horizontal fracture can develop and limit the vertical growth or even curtail the extension of the main fracture. The method developed in the study requires discrete layered formation and fluid properties such as stresses, rock moduli, SIFs, leakoff, and fracturing fluid rheology, as the only inputs, and hence can be applied to a variety of examples worldwide.","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131021859","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Modeling Proppant Transport in Casing and Perforations Based on Proppant Transport Surface Tests","authors":"J. Kollé, Alan Mueller, S. Baumgartner, D. Cuthill","doi":"10.2118/209178-ms","DOIUrl":"https://doi.org/10.2118/209178-ms","url":null,"abstract":"\u0000 The results of a series of proppant transport surface tests (PTSTs) were used in conjunction with Eulerian multiphase-computational fluid dynamics (EMP-CFD) modeling to develop an engineering model of proppant distribution. The PTSTs were carried out to evaluate proppant placement through perforated casing. In these tests, sand slurry was pumped at realistically high flow rates through perforated casing and the distribution of sand and slurry from each perforation cluster was observed. The tests show that gravitational settling in horizontal casing, proppant slip past perforations and the visco-elastic properties of slickwater fluids strongly affect the distribution of proppant from the heel to the toe of the completion.\u0000 The EMP-CFD modeling was used to estimate the gravitational settling of sand in fully-developed turbulent slurry flow in horizontal casing as a function of casing velocity. A survey of 36 calculations was carried out to generate tables of sand concentration in a cross section through the casing as a function of flow rate and particle size. A single-phase CFD analysis showed how sand exiting each perforation is taken from a limited ingestion area which is proportional to the ratio of flow through the perforation to total flow in the casing. A detailed EMP-CFD analysis of flow through single perforations showed how sand slips past the perforation. The results of 28 EMP-CFD calculations provided slip factors as a function of particle size, casing flow velocity, and perforation flow velocity in straight and angled perforations. The EMP-CFD settling tables and a parameterization of the slip factors were integrated into an engineering model. The model predicts the distribution of slurry and sand through each perforation based on the proppant size, perforation phase angle, and pump rate.\u0000 The engineering model was used to predict the sand distributions observed in the PTSTs. The PTSTs were conducted with a range of sand sizes and with low-viscosity friction reducing polymer (FR) additives, while the EMP-CFD analysis assumed water. A weight factor is introduced in the settling model to account for the increased dispersion of sand in water with low viscosity FR and to match the observed sand distributions in the PTSTs. The observed slip of 100 Mesh and 40/70 Mesh sand is consistent with the EMP-CFD calculations in water.\u0000 The model reflects the PTST observations that fine sand is distributed relatively uniformly throughout the length of a perforated completion while coarser sand tends to slip past the heel perforations and concentrate on the bottom towards the toe of the completion.","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129386285","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Did We Break New Rock? Utilizing Diagnostics to Differentiate New Fracture Creation vs Old Fracture Reactivation: A Meramec and Wolfcamp Study","authors":"J. Haffener, K. Haustveit, T. Ingle","doi":"10.2118/209123-ms","DOIUrl":"https://doi.org/10.2118/209123-ms","url":null,"abstract":"\u0000 Microseismic and cross-well strain are both high-end diagnostic tools that provide insight into hydraulic fracture geometry and stimulation effectiveness. However, both datasets have limitations: for example, microseismic can over or underestimate the true fracture geometry, while cross-well strain is restricted to describing a portion of the fracture geometry it is situated to measure. Furthermore, both datasets can show not only the creation of new hydraulic fractures but also the reactivation of previously created hydraulic fractures. The focus of this study is two projects in which both cross-well strain and microseismic were integrated to characterize the geometry of new hydraulic fractures and understand the interaction with pre-existing fractures during well stimulation.\u0000 The first project is a multi-well development in the Meramec formation of the Anadarko Basin. The second project is the Hydraulic Fracturing Test Site 2 (HFTS2) in the Wolfcamp formation of the Delaware Basin. Both projects collected low-frequency DAS using permanent fibers in offset wells and were monitored with borehole microseismic arrays during stimulations. Organizing the data relative to distance from the active stage and time since stage start, i.e., spatiotemporally, was a key step in understanding what the diagnostics measured during stimulation.\u0000 Both projects tell a similar story, where wells have extensive interactions with previously created fractures originating from both parent wells and recently completed child wells. This interaction manifests as a quicker arrival and muted strain response in cross-well strain and a more rapid and linear move-out of the triggering front over time in the microseismic. We interpret these signatures to be showing re-dilation of pre-existing fractures. Also visible in the diagnostics are arrivals with slower growth, generating microseismicity with a parabolic move-out of the triggering front over time, and typical strain response with heart-shaped tensional front leading the arrival. This signature is interpreted to be new hydraulic fracture creation and growth. Once this reactivation mechanism is understood for a basin, it can also be noted and described using lower-cost techniques, such as sealed-wellbore pressure monitoring (SWPM).\u0000 The main motivation for most microseismic and cross-well strain studies is understanding hydraulic fracture geometry; however, interactions with failed media and analysis of either datatype in isolation can cause misinterpretations far from reality. Understanding the range of possible mechanisms measured by these advanced diagnostics is key not just in accurately characterizing fracture geometry but also in understanding the impact of failed media on hydraulic fracture growth. Once understood, these observations can also be used as a baseline to measure success or failure of mitigation trials.","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125822366","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Perforation Cluster Efficiency of Cemented Plug and Perf Limited Entry Completions. Insights from Logging Based Diagnostics","authors":"D. Witt, Jessica Barhaug, Maarten Propper, Wei Jiang, Jeff Jeff Jia, R. Hawkes","doi":"10.2118/209130-ms","DOIUrl":"https://doi.org/10.2118/209130-ms","url":null,"abstract":"\u0000 It is now well established that production from horizontal wells with multi-stage hydraulic fracture stimulations performed through plug and perf completions is highly variable along the length of the wellbore. In addition to the elements of the completion design, such as fluid and proppant volume, injection rate, stage length, and the number and spacing of perforation clusters, subsurface conditions influence the performance of individual stimulated perforation clusters, intervals, and wells. Information about completion efficiency can be obtained using conventional well log measurements for fracture fluid mapping. Contemporary logging conveyance methods make this information gathering practical for modern horizontal wellbores. A log-based Perforation Cluster Efficiency (PCE) computational method will be presented.\u0000 These conventional open-hole logging measurements reveal insights into the Near-Wellbore Region (NWR), including annular cement density, and can be used to anticipate fracture behavior. Integrating well log measurements with Fiber Optic (FO) diagnostics provides insight into the performance of each perforation cluster and the factors controlling frac construction. This paper illustrates recent observations about PCE using traditional well log measurements with new conveyance methods and summarizes the results for several cemented plug and perforated completed Niobrara and Codell wells within the DJ basin. A comparison to interpreted FO DAS data is included, illustrating a good agreement for PCE.","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121072015","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Execution and Learnings from the First Two Surface Tests Replicating Unconventional Fracturing and Proppant Transport","authors":"P. Snider, S. Baumgartner, M. Mayerhofer, Matt Woltz","doi":"10.2118/209141-ms","DOIUrl":"https://doi.org/10.2118/209141-ms","url":null,"abstract":"\u0000 This is believed to be the world's first two attempts, both successful, to replicate multi-cluster hydraulic fracturing at surface to better understand not only proppant transport and placement by cluster, but a host of other items of interest such as perforation erosion. With due recognition and compliments to all the good theoretical studies conducted and published by the academic community, it seemed that actual physical tests could be a valuable contribution to the industry activity. Both 8 cluster (6 shots per cluster) and 13 cluster (3 shots per cluster) tests were completed at 90 BPM injection rates at approximately 1,500 psi initial differential pressures. Both tests were conducted in 5.5\" 23#, P-110 casing, with assembly lengths of 191 feet and 216 feet respectively. Water, Water plus Friction Reducer, 100 mesh sand and 40/70 mesh sand were utilized on these highly instrumented tests with each cluster having its own individual tank to capture fluids and proppants as they exited the perforation clusters. Perforation hole size changes, fluid level data, and proppant masses were captured after each test along with all the frac fleet data and pressure gauge data at each cluster. How the tests were safely and successfully executed will also be discussed. These tests led to subsequent tests with 15 perforation clusters with different charge designs and perforation orientations in a project with a larger number of operators participating. Predictive software based on computational fluid dynamics was also developed as an outcome of the project learnings and actual physical measurements. The key benefit of these tests is that all the data was physically measured and not subject to interpretation, therefore providing solid data for subsequent model calibration and predictions. Validity and shortfalls in the standardly used orifice flow equations was also the subject of the studies and will be discussed. Learnings about perforation erosion and impacts of different proppant sources as well as fluid velocities occurred.","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"32 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130952310","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Empirical Meets Analytical-Novel Case Study Quantifies Fracture Stress Shadowing and Net Pressure Using Bottom Hole Pressure and Optical Fiber","authors":"K. Haustveit, Brendan Elliott, Jon Roberts","doi":"10.2118/209128-ms","DOIUrl":"https://doi.org/10.2118/209128-ms","url":null,"abstract":"\u0000 The Anadarko Basin is located within a strike-slip faulting regime (SHMax>Sv>Shmin) which results in large, planar fracture geometries created during the hydraulic stimulation of low permeability formations. The Meramec formation is dominated by siltstones as part of a series of prograding, stacked clinoforms. The geomechanical properties and the regional stress regime are first order drivers in controlling fracture growth rates, size, and ultimately the drainage area. Net pressure and stress shadowing play a significant role in the design of cluster spacing, proppant selection, fluid selection, and resulting fracture geometry. This paper will review an operator’s case study designed to quantify stress shadowing and fracture net pressure using multiple bottomhole pressure gauges (BHPGs) in a horizontal, multi-stage stimulation in the Meramec formation of the Anadarko Basin.\u0000 The case study will review the measurements taken from two permanently installed BHPGs placed along a horizontal wellbore during a hydraulic stimulation. The first BHPG is located at the toe of a horizontal wellbore being stimulated and is in communication with hydraulic fractures created during the first stage; the second BHPG is located near the heel of the same well being stimulated. The BHPG at the toe of the well is used to measure the poroelastic pressure responses generated as stages are completed uphole from the first stage. Optical fiber is analyzed to evaluate Near Wellbore (NWB) and far-field fracture interactions. The measurements have been integrated into a fracture simulator to calibrate the far-field stress during hydraulic fracture growth.\u0000 Measured stress shadowing in this pilot allowed the authors to develop an equation that can be solved to estimate net pressure. The results are aligned with measurements obtained from DFITs in the area. Historically, net pressure and stress shadow values have been difficult to measure with high confidence due to various pressure losses between the wellhead and formation. Net pressure is a key for optimal cluster spacing design, and a critical matching parameter for hydraulic stimulation models, small errors in net pressure matches can have significant impacts in the resulting simulated fracture geometry. This paper will detail the integration of empirical data to advance an analytical model that quantifies net pressure and poroelastic stress transfer from a hydraulic fracture.","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"14 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130725108","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Processes of Screenout Development and Avoidance","authors":"R. Barree","doi":"10.2118/209125-ms","DOIUrl":"https://doi.org/10.2118/209125-ms","url":null,"abstract":"\u0000 In SPE 18955, published in 1989, a strong case was made suggesting that observed rapid increases in treating pressure were not caused by fracture \"tip screenouts\". These conclusions were further supported by extensive laboratory studies of proppant bridging in slot-flow geometries. These studies showed that conventional \"bridging criteria\" predicting slot widths of 3-6 particle diameters would cause permanent proppant bridging or packing, were invalid. These results were published in SPE 67298 in 2001. Yet, more than 30 years after the first cited publication the terms \"tip screenout\" and \"tip screenout design\" are still in common usage. This paper presents a physics-based description of the mechanisms that cause actual wellbore screenout and the associated rapid pressure rise, and easy to apply methods to prevent or avoid developing screenouts while pumping.\u0000 Field cases and numerical simulation studies will be presented to show that screenouts occur in the very near-wellbore region, particularly at the borehole sand-face. The proximity to the wellbore allows changes to be made to pump rate and other parameters, without the need to adjust fluid composition, stability, or prepad/pad volumes in future stages. A numerical simulator has been used to simulate observed screenout conditions, predict their occurrence, and demonstrate that screenout progression can be halted or controlled. The paper presents the underlying physical processes that control screenouts and explains why the proposed (and field tested) avoidance protocols work.\u0000 The numerical formulation presented in the paper models screenout development and shows how to avert progression of the associated treating pressure rise. The method has been tested and verified in the field, and examples are provided. The work shows conclusively that screenouts occur at the wellbore surface or entry to the fracture intersections with the borehole, and not in the body or tip (perimeter) of the propagating fracture.\u0000 The information presented in the paper invalidates decades of conventional fracture design theory including pad volume requirements based on fluid efficiency, design of fracturing fluid rheological stability at bottomhole temperature for the duration of pumping time, methods for proppant concentration scheduling (ramping), and virtually all conventional \"design\" practices.","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130577338","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}