Day 2 Wed, February 06, 2019最新文献

{"title":"Got Diversion? Real Time Analysis to Identify Success or Failure","authors":"Michael Trumble, M. Sinkey, Jeremy Meehleib","doi":"10.2118/194336-MS","DOIUrl":"https://doi.org/10.2118/194336-MS","url":null,"abstract":"\u0000 Successful diversion is traditionally identified as a sudden treating pressure increase upon the diverter material reaching the perforations. However, the real value is derived from sustaining that diversion for subsequent proppant placement. The charting overlay approach focuses on that sustained diversion. With validation from fiber optic data, the overlay method has a proven track record of real-time diagnostics, eliminating the need for time-consuming, resource intensive high cost evaluations. That real-time application allows treatments to be confidently optimized while pumping, increasing stimulation effectiveness and operational efficiencies.\u0000 Through the process of overlaying treating pressures before and after diversion, the effectiveness of the diverter can be qualified and adjustments made for subsequent diverter drops. The charting overlay method, which consists of plotting early time treatment data on top of later treatment data, provides better accuracy and a more thorough analysis than the traditional method of evaluating pressure increase, or ‘hit’ pressure, when diverter arrives on formation. When compared to fiber optic data utilizing a dynamic acoustic sensing (DAS) tool, the charting overlay method indicated successful diversion every time the DAS data showed diversion from cluster to cluster. The comparison with the DAS data further proved that the charting overlays can be used for real-time diversion analysis.\u0000 This method is useful to those who are using diverting agents to create more efficient stimulation. Through the use of the charting overlay technique, diversion strategies can be adjusted real-time to improve the diversion and increase cluster efficiency.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"395 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124240232","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":"The World's First Offshore Multilateral Well Completed with Multistage Proppant Fracturing: A Case Study from Offshore Black Sea","authors":"A. Tomlins, J. Conrad, Bogdan Bocaneala","doi":"10.2118/194324-MS","DOIUrl":"https://doi.org/10.2118/194324-MS","url":null,"abstract":"\u0000 The paper aims to present the successful execution of the first offshore multilateral well completed for multistage high-pressure proppant stimulation - in the Black Sea, offshore Romania. The paper describes the drivers that lead the operator to trial a multilateral well as well as cover the considerations made in selecting, defining and executing the final completion solution with a review of the lessons learned.\u0000 With only one platform slot left and a significant undrained area of reservoir the operator had to maximise the hydrocarbon recovery through a single well which, due to pressure to increase the operator's daily production, had to be finalised in just one year. Building on field experience gained since 2008 in drilling and completing for multistage proppant stimulation a detailed screening and evaluation of multilateral completion technologies was performed. The focus was on developing a concept that would minimise risks during execution while meeting cost and lead time objectives, which necessitated customising the chosen TAML Level 3 completion design and installation methodology.\u0000 To maximise rig-time efficiency the well was executed in two phases: 1) drilling and lower completion installation of both branches with a drilling rig and 2) stimulation and upper completion installation with the platform's workover rig. With six stages in each lateral the high-pressure stimulation was executed by a converted supply vessel in four sailings, necessary to reload materials. To meet the delivery schedule, ensure simplicity and utilise operator experience the completion was realised with no dedicated multilateral hardware, rather, through the effective use of standard multistage stimulation open hole completion equipment and appropriately engineered bent joints to exit the main bore.\u0000 With initial production rates higher than anticipated, the multilateral well completed in this manner has proven to be considerably more economic than drilling two horizontal wells with equivalent reservoir coverage. The success of this well serves as a proof of concept and provides increased confidence in delivering reliable, cost effective multilateral wells even under tight time constraints and in areas and/or operators with no history of multilateral well completions","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"42 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134525232","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":"Simplification and Simulation of Fracture Network Using Fast Marching Method and Spectral Clustering for Embedded Discrete Fracture Model","authors":"Xu Xue, A. Rey, Pierre Muron, G. Dufour, X. Wen","doi":"10.2118/194368-MS","DOIUrl":"https://doi.org/10.2118/194368-MS","url":null,"abstract":"\u0000 Embedded Discrete-Fracture Model (EDFM) is designed to accurately represent realistic hydraulic fracture network (HFN) and provide efficient performance predictions by honoring the fracture topology. Due to the complexity of HFN, the EDFM grid may be computationally inefficient, particularly for field-scale applications with millions of fracture cells. This paper aims at incorporating the Fast Marching Method (FMM) and spectral clustering for fast HFN analysis, simplification and simulation under the framework of EDFM.\u0000 HFNs are first generated using a commercial hydraulic fracture simulator. The FMM is used to solve the pressure front propagation using the fracture graph and subsequently the ‘diffusive time of flight’, well and completion index are calculated. The results are used as pre-conditions to split the fracture graph into connected components, which are subsequently partitioned using spectral clustering. The resulting clusters are used for fracture simplification resulting in a significantly lower number of fracture elements for flow simulation. To demonstrate the feasibility of the workflow, we use the Multi-Well Pad pilot model, which is characterized by a complex HFN and a high-resolution matrix system. We investigate the relationship between matrix resolution (characterized by the matrix-fracture size of the reservoir cells) and the ratio of oil and gas production on the field. Our investigation provides an alternative approach to explain the very large Gas Oil Ratio (GOR) reported for this type of reservoirs. The required levels of refinement to correctly represent the observed GOR presents an opportunity to test the efficiency and accuracy of our proposed workflow for HFN simplification. We use the results of the FMM applied to the high-resolution models to find an optimal spectral fracture clustering. The results show that the proposed workflow can achieve massive fracture cells aggregation (with only 1% of the original fracture cell number) while maintaining the accuracy.\u0000 This is the first study for analysis, simplification, and simulation of HFN for EDFM using a field scale model. The main contributions are: (i) honor the topology of complex HFNs in EDFM and is able to represent the complex physics observed in the oil and gas shale reservoirs, (ii) HFNs diagnosis without simulation, and (iii) massive fracture aggregation with an error below 5 percent, and speed-up higher than 16 times of the fine scale model.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"55 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133944264","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":"Wavelet Analysis of DFIT Data to Identify Fracture Closure Parameters","authors":"E. Unal, F. Siddiqui, M. Soliman, B. Dindoruk","doi":"10.2118/194326-MS","DOIUrl":"https://doi.org/10.2118/194326-MS","url":null,"abstract":"\u0000 Due to the shift from conventional reservoirs towards unconventional, ultra-low permeability reservoirs in the last decade, Diagnostic Fracture Injection Test (DFIT) has become one of the dominant and economically practical pressure transient tests. It is crucial to analyze and interpret DFIT data correctly to obtain essential fracture design and reservoir parameters. This study presents the application of wavelet analysis to DFIT falloff pressure data to determine fracture closure pressure and time, to ultimately improve the overall efficiency of hydraulic fracturing designs.\u0000 In this study, DFIT pressure is treated as a non-stationary signal and analyzed by one of the signal processing techniques which is wavelet transformation. The purpose of signal analysis is to extract relevant information from a signal by transforming it. Firstly, the signal is transformed into wavelet domain by Discrete Wavelet Transformation (DWT) to calculate high-frequency wavelet coefficients (details), then change-point detection technique is applied to distinguish major changes within the coefficients trend to determine fracture closure pressure and time.\u0000 DFIT pressure decline data from different wells were analyzed by wavelet transformation. Detail coefficient demonstrates different patterns depending on the formation analyzed and near wellbore activities. This is expected because wavelet analysis is sensitive to any physical changes within the system. From the amplitude changes of the coefficients, wavelet tool demonstrates the fracture closure as a continuing process.\u0000 Because wavelet is sensitive to changes in the system, it detects the fracture closure unambiguously by amplitude change, as compared to slope changes in other conventional methodologies. A comparison with some of the most commonly used diagnostic techniques, conventional log-log diagnostic plot, square root time, G-function and its derivative analysis are also provided in this study.\u0000 There have been several publications discussing various techniques analyzing DFIT pressure decline in unconventional formations and yet there is relatively high uncertainty in before-closure-analysis. However, this methodology is more sensitive to fundamental changes in the system, so application in detecting closure pressure and time decreases the uncertainty compared to other conventional tangential methodologies.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131063074","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":"Close Encounters in the 3rd Dimension: Using Diagnostic Fracture Injection Tests DFITs from the Alberta Duvernay Shale Formation to Quantify Simultaneous Horizontal- & Vertical-Plane Hydraulic Fracture Growth","authors":"A. K. Nicholson, R. Hawkes, R. Bachman","doi":"10.2118/194316-MS","DOIUrl":"https://doi.org/10.2118/194316-MS","url":null,"abstract":"This paper will benefit engineers and geoscientists interested in creating representative hydraulic fracture simulation models and optimizing commercial-scale fracture treatments. The paper focuses on the emerging Duvernay shale formation in Alberta, Canada. Well fracturing pressures are often significantly higher than the Overburden (OB, lithostatic) pressure. Pressures above OB likely create horizontal (hz) bedding plane fracture components since sedimentary rocks are almost always weaker along bedding planes. Most fracture design simulators do not account for the simultaneous existence of multi-plane fractures (Figure 1). Therefore, scaled treatment designs for optimizing fluids, proppant schedules and production performance may be flawed. A key question is: What proportion of the overall fracture volume do horizontal-plane features take? The answer can be sought using the Pressure Transient Analysis (PTA) workflow for Diagnostic Fracture Injection Tests (DFITs) described by Bachman et al (2012, 2015) combined with simple PKN and GDK fracture models to represent the hz and vertical plane fracture components.\u0000 DFIT analysis techniques and interpretation are hotly debated topics of late. The authors believe a portion of the gap in the understanding of how hydraulic fractures behave is a result of assuming fracture components are fully, or dominantly, vertical. Analysts often interpret high fracturing pressures as tortuosity or near-well friction. However, during the fall-off period after pumping a DFIT, pressures above OB can persist for up to 20 minutes after pump shut-down. Analysis of these tests often exhibit early-time radial flow signatures which are coincident with the OB gradient of ~22kPa/m (1psi/ft) also indicative of hz plane fractures. In Nicholson et al 2017 four field DFIT examples were presented showing strong evidence of hz plane fractures in various depths and formations found in the Western Canadian Sedimentary Basin.\u0000 In the current paper DFIT PTA analysis is applied to two West Shale Basin Duvernay datasets. A physical model is presented (Figure 1) that incorporates the in-situ stress regime, rock fabric, and pore pressure and that allows history matching of DFIT leak-off and closure behavior for fractures above OB pressure. Simple calculations are provided to estimate the volume and dimensions of these same components for a small volume, single viscosity, no-proppant injection DFIT. This unique approach provides a valuable calibration point for building more advanced simulation models.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131334938","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":"Effect of Shear Slippage on the Interaction of Hydraulic Fractures with Natural Fractures","authors":"Shivam Agrawal, Kaustubh Shrivastava, M. Sharma","doi":"10.2118/194361-MS","DOIUrl":"https://doi.org/10.2118/194361-MS","url":null,"abstract":"\u0000 Micro-seismic data suggest that complex fracture networks are formed frequently in unconventional reservoirs due to the interaction of hydraulic fractures (HF) with natural fractures (NF). Understanding this interaction is critical for optimizing fracturing design. It is generally accepted that under certain conditions, a propagating HF can cause remote shear failure of a NF before intersecting with it. This fact is not accounted for in the development of the existing fracture interaction criteria. The goal of this study is to account for these dynamic interactions and present new criteria that define the conditions under which a HF will cross, kink, branch, or turn along a NF.\u0000 We have used our peridynamics-based poroelastic fracturing simulator in this study, which solves for rock displacements and fluid pressure in a fully coupled and implicit manner. Shear failure of the NF is modeled using a Mohr-Coulomb failure criterion. The frictional force on the NF surface is modeled implicitly. The stress distribution around the HF is monitored as the NF approaches it. Considering the effects of shear failure, different propagation behavior such as turning, and crossing are characterized as a function of in-situ stress ratio, angle of approach, NF characteristics, and matrix permeability. It should be noted that the peridynamics model used in this study does not require a crossing criterion as an input, rather it can predict the interaction behavior based on local poroelastic stresses.\u0000 The model is validated against the analytical crossing criteria derived using Linear Elastic Fracture Mechanics (LEFM) by ignoring remote shear slippage prior to intersection and poroelasticity in our model. Recent experimental observations that show an increase in approach angle before intersection of a HF with a NF are also used to test the model. Remote shear failure of the NF before intersection results in relaxation of the stresses locally. This in turn leads to the HF bending towards the NF. Though these effects are found to be important in low permeability rocks (100 nD), they are more pronounced in high permeability rocks (10 mD). In high permeability rocks, poroelastic effects are much more significant, leading to greater stress relaxation and thus a near-orthogonal modified approach angle. When stress relaxation due to remote shear slippage of the NF is considered, the HF is more likely to turn along the NF. For low angles of approach and low stress ratios (1.0-1.1 for low permeability rocks and 1.0-1.2 for high permeability rocks), the poroelastic crossing criteria derived in this study are considerably different from those derived using LEFM. However, for near-orthogonal angles of approach or high stress ratios, the crossing criteria do not change much.\u0000 The poroelastic crossing criteria derived here can serve as direct inputs for discrete fracture network models simulating the growth of complex fracture networks (Shrivastava and Sharma, 2018). The results","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121623252","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":"CounterProp, Finally Adding the Correct Proppant in the Proper Size and Proper Sequence in Slick Water Treatments","authors":"J. Ely, Jon Harper, Esteban N. Nieto, M. Semmelbeck","doi":"10.2118/194370-MS","DOIUrl":"https://doi.org/10.2118/194370-MS","url":null,"abstract":"\u0000 As long as Stokes law or low viscosity Newtonian fluids have been available, common knowledge within the industry has been that whenever these fluids are utilized during the hydraulic fracturing process, very rapid settling of any conventional proppant occurs. Over the years, there have been occasional jobs pumped where the larger sized proppant was the initial proppant pumped, followed by the smaller meshed sand, ceramic or bauxite materials. Little attention was paid to this differing sort of treatment, due to the belief in piston like displacement of proppant regardless of fluid type. Commonly curable resin-coated sand was always pumped in the very last slurry stage of a fracturing treatment, in the common hopes of controlling any potential sand production from the near wellbore area when operations were concluded and flow back operations were initiated to bring the well on line. In reality, with typical over flush volumes, any resin-coated sand pumped during a slick water treatment will travel far away from the wellbore.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"28 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132204238","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":"Permian Basin Production Performance Comparison Over Time and the Parent-Child Well Study","authors":"Tao Xu, Wei Zheng, J. Baihly, P. Dwivedi, Dan Shan, Randy Utech, Grant Miller","doi":"10.2118/194310-MS","DOIUrl":"https://doi.org/10.2118/194310-MS","url":null,"abstract":"\u0000 More operators are increasing their activity level in shale oil plays as the commodity price has stabilized. Activity has been at a fever pitch in the Permian Basin where over half of the North American land rigs drilling for oil are located. Operators realize that well performance varies both positively and negatively along reservoir quality and completion design changes as well as the drilling time of infill wells. Previous studies included investigation of the average type curve for gas wells located in core areas of various unconventional plays across the US. The Permian Basin is predominantly an oil-rich basin with multiple benches; the challenge associated with discerning which bench a well was landed in makes it difficult to compare completions. This paper seeks to generate decline trends for wells drilled in the Wolfbone and Wolfberry sequences of the Permian Basin while also examining the changes in completion evolution and parent/child relationships. A similar workflow from previous studies was also applied to generate the decline curves for wells by bench and producing year.\u0000 First, the horizontal wells were categorized based on which formation the laterals were landed in. Then, the moving window approach was used to identify the parent and child wells in each major formation. Based on this information, the production performance and completion between the parent and child wells were compared by bench and completion time.\u0000 In this paper, we investigated the change in decline rate by applying the ratio of best 1-month production (B1) and the best 12 consecutive months (B12) production rate with relation to parent and child well spacing across respective formation layers. We also examined the completion factors in combination with the child/infill well production performance to determine the production improvement and degradation causes, thereby providing a reference for child/infill well design.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"308 3","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114097093","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":"Power Law Correlation for Slickwater Proppant Dune Height","authors":"Msalli Alotaibi, J. Miskimins","doi":"10.2118/194309-MS","DOIUrl":"https://doi.org/10.2118/194309-MS","url":null,"abstract":"\u0000 Poor proppant transport in slickwater is an industry challenge in the hydraulic fracturing of unconventional reservoirs. Part of this challenge is the difficulty in estimating the settled proppant dune height inside induced fractures. An experimental study was conducted and used to develop lab-based correlations that can predict slickwater proppant dune height as a function of certain key parameters.\u0000 A slot flow apparatus was designed and used to conduct more than 70 experiments to obtain the data necessary for the correlation development. The designed fracture slot has a rough surface and is 23.25 inches high and 0.2 inch wide. White sand was tested over a wide range of field representative values for slurry velocity and proppant size and concentration.\u0000 Power law correlations were developed for slickwater proppant dune height based on slurry velocity, proppant size, and concentration. The slurry velocity refers to the initially slurry velocity before proppant starts to settle inside the induced fracture. The overall correlation was developed by experimentally studying the effect of each parameter on the dune height and then combining them all in one correlation based on their respective relationships. The developed correlation covers proppant sizes ranging from 100 to 20/40 mesh and concentrations ranging from 0.25 to 2.80 ppg. The developed correlation showed high prediction accuracy relative to obtained lab data with an average error value of less than 0.6% relative to lab data. The developed correlation was further evaluated for its accuracy relative to lab data and the previously published correlation by Wang et al. (2003).\u0000 The developed correlation is the first of its type to be based on experimental data while using rough surface slot walls. Roughness is proven to have a considerable effect on proppant settling which makes this correlation more representative for field applications. Also, compared to the well-known correlation by Wang et al. (2003), this correlation covers a wider range of proppant sizes, concentrations, and slurry velocities.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121720430","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":"Understanding Frac Fluid Distribution of an Individual Frac Stage from Chemical Tracer Flowback Data","authors":"Wei Tian, A. Darnley, Teddy Mohle, K. Johns, D. Christopher","doi":"10.2118/194362-MS","DOIUrl":"https://doi.org/10.2118/194362-MS","url":null,"abstract":"\u0000 A data set is presented which involves pumping multiple, unique chemical tracers into a single ‘Wolfcamp B’ fracture stage. The goal of this tracer test is to shed light on the flowback characteristics of individually tagged fluid & sand segments by adding another layer of granularity to a typical tracer flowback report. The added intra-stage level detail can provide insights into fracture behavior when stimulating shale reservoirs by looking at individual fluid segment tracer recoveries. This data set could aid in the interpretation of:\u0000 Identifying fluid segments placed outside of the P-SRV (Propped Stimulated Reservoir Volume) Fracture Complexity\u0000 A total of 12 water phase tracers and 12 oil phase tracers were injected sequentially from \"Pad\" to \"Flush\". After pumping the pad stage, unique tracers were used to tag the \"Proppant Laden Fluid\" from the 0.2 ppa 100 mesh sand stage to the 2 ppa 40/70 mesh sand stage, before going to flush. The flush volume was not traced. Upon flowback, produced fluids were analyzed for the concentration of each tracer within the produced fluid samples. The first goal was to determine whether any traced fluid would be placed within \"unpropped\" SRV. The second goal was to determine the order of load fluid returns, to verify the \"first-in, last-out\" phenomenon, and to ascertain any degree of fluid mixing, which could be an indication of increased fracture complexity.\u0000 The results illustrate the average tracer concentration and arrival time of each traced fluid segment, which was then used to characterize the fracture stage. All tracers were detected in the produced fluid samples, indicating that no traced segment was placed outside of the propped fracture network. The results also indicate that significant tracer mixing occured within the fracture network, a potential indicator of fracture complexity. All individually traced segments flowed back simultaneously, albeit at varying tracer concentrations. The residence time calculation for each tracer showed that frac fluid injected into the later proppant segments generally flowed back faster than the earlier segments. No obvious piston-like displacement of frac fluid was observed from the tracer data.","PeriodicalId":103693,"journal":{"name":"Day 2 Wed, February 06, 2019","volume":"os-12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-01-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127763732","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}