Day 4 Thu, June 14, 2018最新文献

{"title":"Acid Jetting on Carbonate Rocks: A Computational Fluid Dynamics Study at Laboratory Scale","authors":"Vanessa Ndonhong, D. Zhu, A. Hill","doi":"10.2118/190849-MS","DOIUrl":"https://doi.org/10.2118/190849-MS","url":null,"abstract":"\u0000 Acid jetting is a well stimulation method for carbonate reservoirs, with observed positive production enhancement in some extended-reach horizontal wells. It is a process in which a reactive chemical solution is injected at a high rate at specific entry points via relatively smaller nozzles. The flow out of the nozzles is designed to be a fully turbulent jet which impinges on the porous surface of the rock, leading to a dissolution structure. That dissolution structure is of great interest as it determines the quality of the well stimulation job, which correlates directly to the well productivity. This work is the second step in the overall project about a comprehensive study of acid jetting as a successful stimulation method for carbonate formations. The first step was an experimental study performed using a linear core-flood setup including a jetting nozzle. The objective was to understand the mechanism of acid jetting on carbonate cores and identify the important parameters in the experimental outcome. The current study aims at describing acid jetting from a mathematical standpoint, while using experimental results as model validation and improvement tools. Previously published acid jetting laboratory experiments results revealed the recurring creation of a large dissolution structure at the impingement location in the shape of a cavity and, depending on injection conditions, the propagation of wormholes through the core.\u0000 A core-scale computational fluid dynamics model has been developed to simulate cavity and wormhole growth in acid jetting. It is a three-dimensional model which alternates between the two fundamental aspects of the overall acid jetting process. Firstly, it models the fluid mechanics of the turbulent jet exiting the nozzle and continuously impinging on the porous media transient surface. The jet fluid dynamics are implemented using a 3D transient finite volume numerical solver using Large Eddy Simulations (LES) with the Smagorinsky-Lilly sub-grid model to solve the Navier-Stokes and continuity equations. The results of this simulation include a velocity and pressure distribution at the porous media surface. Secondly, it models an irreversible chemical reaction with dissolution and transport at the impingement location between the fluid and the rock matrix. The reactive transport is modeled using the conventional kinetics of the dissolution of calcite by hydrochloric acid. This two-step model successfully replicates experimental results and observations for the cavity growth. It can then be coupled with a wormhole growth model to represent the entire experimental acid jetting outcome.\u0000 The modeling and computational tool for acid jetting developed in this paper will build the understanding for the upscaling and integrated dynamic modeling of an acid jetting stimulation job in the field. It will thus lead to the establishment of a standard for predicting and improving field applications of acid jetting.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"184 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123069680","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":"Replacing Mud Pulse Telemetry with an Electromagnetic System","authors":"Iain Lunney, John Thompson, J. Wilkes, Matthew Chong, I. Whyte, P. Peytchev, Elike Mawuli, P. Goel, J. Burns","doi":"10.2118/190766-MS","DOIUrl":"https://doi.org/10.2118/190766-MS","url":null,"abstract":"\u0000 In the budgeting of all major development projects, there is always a desire to capture the financial and operational opportunities of all new and existing technologies; however, this can be difficult if not proven to be viable in advance of the development campaign commencing. This leads to great difficulty in fully capturing potential savings in future financial planning. In a cost-sensitive market, a leading East Africa exploration and production operator recognized an opportunity to trial new technologies in the exploration and appraisal campaign phase in order to reduce well cost and risk, which could be directly translated to the development campaign feasibility model. A flat-time analysis was performed on historical data to benchmark the connection performance against relevant proxies. From this analysis, it was determined that there was room for improvement from both technology and existing practices. To improve the connection time on a technology basis, offset field resistivity data were modelled to determine the feasibility of the formations drilled to efficiently propagate a bi-directional electromagnetic signal. Once the modelled feasibility was deemed acceptable to deploy from a risk perspective, a systematic field-trial plan was developed to deliver proof of concept, which was followed by the second element, running the system to reduce connection time. After two successful proof-of-concept runs, the electromagnetic system facilitated a material reduction in connection time, which could then be applied to the development project economics. Whilst primarily focusing on technology-oriented connection improvements, there was also a systematic performance improvement from the human element on the rig floor owing to the performance initiative. The secondary benefit of successfully implementing the electromagnetic telemetry system was the increased data rate and the ability to transmit annular pressure data while the pumps were off, which provides valuable data to understand wellbore hydraulic behavior during pumps-off events. With conventional mud-pulse telemetry systems, the critical path is impeded to obtain these measurements, where annular pressure data is streamed to surface after the surface event (e.g., LOT / FIT, connection ballooning check, etc.). During these field trials, the downhole equipment complexity run in conjunction with the electromagnetic telemetry transitioned from basic gamma ray and pressure measurements to a quad-combo LWD string run in conjunction with a rotary steerable system.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"31 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116985960","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":"Oil Recovery Analyses and Formation Water Investigations for High Salinity-Low Salinity Water Flooding in Sandstone Reservoirs","authors":"Hasan N. Al-Saedi, Ariel Williams, R. Flori, P. Brady, Soura K. Al-Jaberi","doi":"10.2118/190845-MS","DOIUrl":"https://doi.org/10.2118/190845-MS","url":null,"abstract":"\u0000 Recently, we investigated the effect of Ca2+ in the formation water and its potential on low salinity (LS) water flooding (Al-Saedi et al. 2018). In this paper, we pursue to quantify the influence of formation water containing Ca2+ and Mg2+ on LS EOR. Berean sandstone cores were sequentially flooded with high salinity HS water and LS water at 90°C. During injecting brines, samples of the effluent were analyzed for pH. Oil recovery experiments with a double Ca2+ and Mg2+ concentration showed a lower LS water effect, meaning that the cores became more water-wet; however, the LS water effect was much greater when the amount of Ca2+ and Mg2+ in the HS water was decreased by half.\u0000 The results of this work isolate and relate oil recovery with the most effective factors that control LS water chemical mechanisms.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"127 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125046517","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":"NanoSurfactant: A Novel Nanoparticle-Based EOR Approach","authors":"Afnan Mashat, A. Abdel-Fattah, A. Gizzatov","doi":"10.2118/190861-MS","DOIUrl":"https://doi.org/10.2118/190861-MS","url":null,"abstract":"\u0000 This paper describes a nanoparticle-based approach for stabilizing the low-cost petroleum sulfonate surfactants in high salinity and temperature water to enable their utility in EOR applications in typical carbonate reservoirs. The paper presents and discusses experimental results on the phase behavior of three of such NanoSurfactant formulations and their interfacial tensions (IFT) with crude oil, in order to evaluate their ability to mobilize oil during EOR operations. The three NanoSurfactant formulations were prepared through a one-step nano-emulsification process involving high salinity water, 5 wt% petroleum sulfonate solution and a low-dose of three different 4 wt% co-surfactant solutions. The resulting formulations had a 0.2 wt% of total active ingredients. One of the three formulations was persistently stable, colloidally and chemically, in high salinity water (~ 56,000 ppm) at high temperature (100 °C) for more than six months, while the other two showed signs of instability after about four months. Interfacial tensions between crude oil and NanoSurfactant solutions, measured using a spinning drop interfacial tensiometer at 90 °C, was in the 10−2 to 10−3 mN/m range and substantially lower than that with high salinity water alone or solutions of corresponding co-surfactants of similar concentrations. Phase behavior, investigated by monitoring the clarity and UV absorbance changes in a system of crude oil atop of the NanoSurfactant formulation at 100 °C without mechanical mixing, showed enhanced formation of homogeneous oil-in-water emulsions at 100 °C without the aid of any mixing. Our results demonstrate the ability of NanoSurfactants to mobilize oil under typical carbonate reservoir conditions. Their colloidal nature gives them advantages over conventional micellar surfactants by allowing them to migrate deeper in the reservoir due to size exclusion and chromatographic effects. The simple method utilized in making NanoSurfactants opens the door for better utilization of numerous low-cost, yet salinity- and temperature-intolerant chemicals in typical carbonate oil reservoir applications.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"14 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134449575","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":"Evaluation and Optimisation of Smart Water Injection for Fractured Reservoir","authors":"M. Akbar, N. Agenet, A. Kamp, O. Gosselin","doi":"10.2118/190854-MS","DOIUrl":"https://doi.org/10.2118/190854-MS","url":null,"abstract":"\u0000 Smart water injection or low-salinity water flooding is an enhanced oil recovery technique for fractured reservoirs. The mechanism of low-salinity water flooding is performed by altering the wettability of rock towards water-wetness.\u0000 This study presents an evaluation of low-salinity water flooding based on a brown field fractured reservoir properties by using explicit simulation of spontaneous imbibition at a fine scale (single and multiple matrix block level), and assessing the validity of dual-medium simulation models, which will be further used to perform modelling at the full field scale.\u0000 Some reservoir parameters were varied within plausible range to quantify their impact on the recovery mechanism. To mitigate the biases of dual-medium models, upscaling and pseudoisation techniques were applied to match the behaviour of explicit fine-scale single-porosity model. A particular emphasis on the modelling of salt diffusion is made through one-dimension model.\u0000 It was found that, whereas pressure diffusion is rather well represented by the usual matrix-fracture exchange coefficient formalism, the underlying assumption of pseudo-steady state seems to be inappropriate for salt diffusion phenomenon.\u0000 When salt diffusion is the main driver for low salinity water imbibition, for example at the early times of a switch from high salinity to low salinity, it appears that the salt diffusion process occurs in a transient regime that cannot be properly represented by the pseudo-steady state regime assumption.\u0000 This has an impact on the modelled incremental recovery and consequently on the low salinity flooding efficiency evaluation.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"189 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116332447","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":"Successful Application of an Integrated Workflow for Seismic Reservoir Characterisation: From Thin Sections to Seismic Scale","authors":"R. L. Tagliamonte, G. Carrasquero, M. Fervari, C. Tarchiani","doi":"10.2118/190771-MS","DOIUrl":"https://doi.org/10.2118/190771-MS","url":null,"abstract":"\u0000 This paper describes a new integrated workflow that successfully bridges the gap between different measurement scales to characterise a clastic reservoir. This workflow combines thin sections, well logs and elastic curves (Vp, Vs and Rho or any combination of these) to generate a petro-elastic log facies classification that is not only calibrated to core data, but at the same time constitutes a shared key input for seismic inversion classification and reservoir modelling.\u0000 The application of this workflow is deemed crucial whenever seismic attributes are required to be used as a driver for properties distribution within a geological model. Given the inherent constraint of the seismic resolution, the recommended logfacies model has to honour a robust petrophysical reservoir characterisation (porosity, permeability) while assuring the maximum discrimination within the elastic inversion space (e.g. P-Impedance vs. Vp/Vs ratio) with a minimum number of classes.\u0000 In this paper, we outline a framework for building an integrated log facies model that includes the following steps: first, a facies model is defined at the scale of thin sections by means of a clustering technique. This represents the reference for a core-supported facies classification that in turn is linked to the sedimentological facies. A porosity-permeability relationship is analysed as it represents a common petrophysical domain for both facies models: thin sections and core data. The \"poro-perm\" relations are preserved when moving to log scale, where a petro-elastic log facies model is generated with a small number of classes. Secondly, Formation Evaluation (FE) is carried out to provide a simple, general and robust petrophysical model paramount not only for reservoir characterisation but also to be used as input for a dedicated Rock Physics Model (RPM), which links petrophysics and seismic velocities. FE and RPM are tuned one to the other until optimised. Thereafter, in order to generate classes that are not affected by hydrocarbon effects, fluid replacement modelling is performed to produce synthetic elastic curves in brine condition, that are input - together with porosity and volumes of minerals - to the facies classification. The procedure iterates until a few log facies are simultaneously discriminated in the petrophysical (e.g. Porosity vs. Permeability), petro-elastic (e.g. Porosity vs. Vp/Vs ratio) and in the elastic space of seismic inversion (e.g. P-Impedance vs. Vp/Vs ratio). Finally, once the log facies classes are defined at the well log scale, we use a dedicated technique to scale-up the petro-elastic log facies to the seismic domain, together with the petrophysical and the elastic curves. While the log facies are the hard data for geological modelling and support for petrophysical properties distribution, the corresponding upscaled log facies curves are used to populate the template for seismic elastic attributes classification to facies probabilities.\u0000 The successfu","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"114 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116460859","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":"Calculation of Relative Permeability Using Well Test Data in Gas-Condensate Reservoirs","authors":"I. Abdulwahab, M. Jamiolahmady, T. Whittle","doi":"10.2118/190878-MS","DOIUrl":"https://doi.org/10.2118/190878-MS","url":null,"abstract":"\u0000 Analysing well test data from gas-condensate reservoirs can be challenging, particularly when pressure drops below the dew point and condensate forms near the well. Usually, a single-phase pseudo-pressure approach is used to analyse the corresponding pressure transient well test data in combination with a composite reservoir model, but this approach has its shortcomings. A two-phase pseudo-pressure approach has been shown to give better results, but it requires relative permeability (kr) data which are not readily available.\u0000 The paper demonstrates the reliability of calculating a pressure versus radius profile from pressure versus time build up data from tests on wells in gas-condensate reservoirs. The calculation is based on the probe radius concept originally proposed for single-phase systems. It also evaluates the possibility of obtaining, analytically, kr data affected by pressure and velocity in single-rate and multi-rate tests. The calculation is based on Darcy's law using the pressure derivative with respect to distance obtained from the pressure versus radius profile. The theory of these calculations is verified by comparing the results with the output from a numerical simulator based on a single-layer single-well radial reservoir model. A simple binary rich gas condensate fluid was used in the numerical simulation.\u0000 The results demonstrate that the pressure versus radius profile using probe radius theory reasonably matches the corresponding pressure versus radius profile output from the numerical simulation. This also shows that the method can reliably predict the condensate bank radius. At first, the analytical approach used to calculate kr, as a function of radius, resulted in oscillations due to the nature of derivative calculation involved. The source of the kr noise was treated following two separate approaches that can be used depending on the level of noise versus ease of use. The calculated kr versus radius data showed good agreement with the corresponding grid block kr versus radius data predicted by the simulator for various rock types and flow rates.\u0000 The method described in this paper provides a practical tool to estimate kr data that can be used to calculate two-phase pseudo pressure and hence potentially improve the analysis of gas-condensate test data affected by condensate banking and velocity. The derived kr data may also have other applications.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"85 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134409960","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":"A Composite Transient Model for Multi-Fractured Horizontal Well in Tight Gas Reservoirs Based on Multi-Factor Effect","authors":"Cao Lina, Lu Lize, Xiaoping Li, Wang Hehua, He Wei, Deng Yong, Xu Bing, Jiang Liping","doi":"10.2118/190873-MS","DOIUrl":"https://doi.org/10.2118/190873-MS","url":null,"abstract":"\u0000 In low-permeability tight reservoirs, the natural gas transient flow is affected by multi-factor including stress-sensitivity, threshold pressure gradient, or both. This paper aims to synthetically study transient pressure response as well as transient rate behavior of a multi-fractured horizontal well in tight gas reservoirs. With the new mathematics model, the flow characteristics coupled with such multi-factor can be described.\u0000 The new composite seepage model of a line-sink incorporating both stress-sensitive permeability and threshold pressure gradient was established. Employing fractures discretization and superposition principle yielded the final model of a multi-fractured horizontal well. The model was semi-analytically solved by Pedrosa's transformation, perturbation theory, and integration transformation method. Not only pressure transient analysis, but also rate transient analysis are separately performed with relevant parameters.\u0000 A total of six flow periods can be divided according to the same standard of time stages for pressure type curves and rate type curves. It is found that stress-sensitivity results in upward tendencies in both of pressure and rate derivative curves reflecting larger pressure drop during intermediate and late flow regimes; threshold pressure gradient leads to more difficult fluid flow acting a steeper upwarping on pressure curve and downwarping on production rate curve. Finally the variation trend of the corresponding curve will be more apparent under the combined impact of stress-sensitivity and threshold pressure gradient. The research of this paper can provide some insights into well dynamic forecasting during exploiting such reservoirs, and contribute to establish the theoretical basic for transient analysis efficiently.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"29 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130265696","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":"Biopolymer Injection in Offshore Single-Well Test","authors":"J. Beeder, Anita Skarstad, D. Prasad, A. Todosijević, E. Mahler, C. Fleck, F. Lehr","doi":"10.2118/190758-MS","DOIUrl":"https://doi.org/10.2118/190758-MS","url":null,"abstract":"\u0000 A single well biopolymer injection test has been performed to investigate the stability of the biopolymer Schizophyllan under reservoir conditions. Laboratory tests of the Schizophyllan biopolymer prior to field test did show microbial degradation, and an environmentally qualified biocide was selected to be injected together with the biopolymer.\u0000 The objective of this paper is to focus on the microbial aspects of using biopolymers for EOR (Enhanced Oil Recovery) by performing an extensive microbial analysis program of injected and produced water samples both prior to and after injection of the biopolymer into the reservoir.\u0000 Multiple samples at different stages during the field test were collected using sterile and anaerobic methods to investigate any change in microbial community and evaluate any microbial degradation of the biopolymer.\u0000 Analyses show that the biopolymer was not biodegraded during the shut-in period due to presence of biocide. However, microbes able to degrade the biopolymer Schizophyllan were present and could have biodegraded the biopolymer in the absence of active biocide. The microbial community changed in the area affected by biopolymer injection during the field test.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"70 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127369938","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":"Selecting a Horizontal Well Candidate in the Black Sea for Refracturing with Flow Diverting Technology","authors":"P. Janiczek, Ivan Makar, B. Reilly, M. Lahman, Bartlomiej Kolasa, R. Day","doi":"10.2118/190839-MS","DOIUrl":"https://doi.org/10.2118/190839-MS","url":null,"abstract":"\u0000 This paper identifies restimulation opportunities in existing multistage completed horizontal wells with plans for a customized refracturing solution applying breakthrough stimulation and diversion processes to increase oil production in a tight carbonate formation, offshore Black Sea. Because operators are shifting strategy in a low oil price environment from new well drilling toward well interventions, refracturing is gaining more focus, particularly for tight and less conventional reservoirs. Many potential candidates also have suboptimal completions for refracturing, so the challenge for operators is selecting the best candidates and designing a refracturing treatment for improved well performance in these complex situations. This paper describes the well screening and selection process for the restimulation of existing horizontal wells with multistage openhole completions.\u0000 During Phase 1 of the project, pilot candidates were ranked using a weighted average score of specific decision criteria for evaluating the refracturing potential. The goal of the screening process was to identify wellbores with the most bypassed reserves and to determine the root cause. Top candidates demonstrated bypassed reserve potential because of large completion spacing and lower average permeability than was originally estimated. The design process emphasized identifying areas where incremental oil could be accessed by substantially increasing total exposed conductive surface area and placing new fractures between existing using novel approaches to refracturing incorporating flow diverting technology. The application of an engineered pressure-managed design approach optimized proppant cycles, and flow diverting refracturing methods were a fundamental component in recognizing that the restimulation pilot was realistic, achievable, and justified economically. By dynamically managing and adapting proppant schedules, diverter volume fractions, and total materials pumped over time, new induced fracture surface areas can be reliably created in the most economic manner.\u0000 Phase 2 consisted of executing the refracturing operation on the selected pilot well, which had been originally hydraulically fractured in 2009. A repressurization procedure of the reservoir was performed before the main treatment to equalize pressure depletion along the lateral and ultimately enhance the coverage of newly fractured zones along the wellbore. The refracturing treatment on the pilot well consisted of four proppant cycles with application of engineered pressure management to improve fracture initiations and flow distribution. A degradable particulate diverter technology was used as primary isolation of each fracturing cycle.\u0000 Restimulation results of the pilot well demonstrated technical and production success, with huge potential to implement this technology during the next phase of field revitalization (Phase 3). This pilot project has proved that the combination of a well selection pro","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"16 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127429114","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}