Day 2 Wed, August 15, 2018最新文献

{"title":"Integrated Methodology for Laboratory Evaluation of Shale Plays Cuttings","authors":"P. AngélicaMaríaCarreño, T MariadelRosarioPérez, N. Marfisi, J. J. Gómez, C EdgarRicardoPérez","doi":"10.2118/191812-MS","DOIUrl":"https://doi.org/10.2118/191812-MS","url":null,"abstract":"\u0000 This current paper is intended to show the implemented methodology for integrated mineralogical, geochemical, petrophysical characterization of Shale Plays from the analysis of well cuttings at the Colombian Petroleum Institute (ICP).\u0000 The implemented methodology starts with taking drilling cuttings (Wet Trench samples) during the drilling of exploratory wells in areas of interest for production of Shale Oil & Gas in diferents Colombian basins. Then fragments are selected (picking) with stereoscopic magnifiers. Observed proportions and lithology in the Formation Evaluation Log (FEL) for a given range should be consistent.\u0000 Subsequently, the textural and compositional macroscopic description of each sample using Hydrochloric Acid (HCL) to identify carbonates is performed. This description takes into account the degree of effervescence and solid waste analysis. Finally, the percentages of every lithotype present per interval are defined, and this way samples are selected for evaluation.\u0000 The evaluation of texture and composition of samples was performed by conventional Petrography of relative abundance of elements by means of Scanning Electron Microscopy (SEM). The mineralogical evaluation of samples is performed by X-ray Diffraction (XRD).\u0000 Furthermore, geochemical analysis of TOC and pyrolysis are performed in some fragments of the selected samples. Other tests include: Mercury Injection Capillary Pressure analysis (MICP), helium porosity, nanoindentation technique. These analyzes are made to determine mechanical properties of the rock. The integrated analysis of these techniques provides information to the mineralogical, geochemical and petrophysical characterization of rocks from a shale plays.\u0000 This allows defining areas of interest for hydraulic fracturing and production in a UnConventional Reservoirs. The methodology was validated with results obtained from core samples from well Iwana-1 drilled by Ecopetrol in unconventional reservoirs in Middle Magdalena Valley Basin (MMVB). This fact provided competitive advantage to Ecopetrol in exploration and exploitation of Shale Plays. This mineralogical, geochemical and petrophysical characterization laboratory methodology for Shale Plays from well cuttings was used during 2014 at the ICP to characterize 880 ft at El Tablazo Formation in well Casabe K1, 850 ft at La Luna formation in well Golosa 1 and 5,900 ft at Gala 1K at the same formation. This methodology allowed shortening the laboratory analysis time from 120 to 60 days with respect to laboratory tests on a core of 800 ft","PeriodicalId":265203,"journal":{"name":"Day 2 Wed, August 15, 2018","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129072568","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":"Application of The Technique MPD Using Automated Systems for Non-Conventional Wells Drilling with Narrow Operating Window in the Neuquén Basin","authors":"Ismael A Ruiz, R. Padilla, Alexis Pagani","doi":"10.2118/191818-MS","DOIUrl":"https://doi.org/10.2118/191818-MS","url":null,"abstract":"\u0000 For many years it has conducting the drilling of unconventional wells looking for optimize the operation looking for reduce risks and operational problems, additionally increasing the staff security in the complex operations of the Neuquén Basin. New technologies applied to extremely demanding scenarios contribute to reach these goals, and the MPD technique together with automated pressure control systems are a sample of these applications.\u0000 Despite the remarkable progress in the drilling of unconventional wells, through the application of UBD and MPD techniques it is observed that with the use of manual equipment continue to have operational problems, which are often associated to difficulty to maintain a proper annular pressure profile for a very narrow operating window and complex geology, which in most cases is due to human factors added to operating conditions of the equipment. As a result of this improper handling of the pressure profile while drilling or during the control of an influx, there are problems of severe admissions, collapses, trapping and presence of cross flows, generating excessive NPT and in some cases the loss of the well with the associated costs that this entail.\u0000 The content of this document will show the results of the drilling operation of horizontal wells in the Fortin De Piedra field, where is drilling by applying the MPD technique with automated systems and will demonstrate the difference with wells where techniques MPD or UBD were used with manual or semi-Automated equipment.\u0000 This article is considered of interest to those involved in drilling wells in shale gas areas with complex geology and narrow operating windows, especially Neuquén Basin, particularly for design and drilling engineers wishing to evaluate other technologies to apply to optimize drilling operations.","PeriodicalId":265203,"journal":{"name":"Day 2 Wed, August 15, 2018","volume":"49 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134328532","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":"Application of Multi-Functionalized Surfactant to Enhance Hydrocarbon Production in Tight Oil & Gas Formations Yields Successful Results","authors":"H. Quintero, Robert Hawkes, M. Mattucci, S. Sessarego, Bill O’Neil, Kewei Zhang","doi":"10.2118/191845-MS","DOIUrl":"https://doi.org/10.2118/191845-MS","url":null,"abstract":"\u0000 Oil and gas shale hydraulic fracturing designs for new wells drilled typically call for water volumes as high as 50,000 m3 (314,000 bbls). The cleanup of these massive water volumes during flowback must be efficient and minimize fluid invasion into the matrix. Once the saturation of the invaded water zone is reduced to the lowest possible level during flowback (cleanup operations), hydrocarbons can flow freely into the wellbore. However, the flowback behavior in unconventional reservoirs is quite different than in conventional reservoirs where soakback and slowback techniques are implemented. It is not uncommon for these wells to be shut in or for weeks or even months following the hydraulic fracturing treatment. Chemical and surfactant flowback enhancers such as microemulsions and nano-surfactants are additives typically used in hydraulic fracturing to assist in flowback design and improve load fluid recovery as they minimize fracture face damage due to water blockage.\u0000 In this paper, we describe the successful field application of a multi-functionalized surfactant (MFS) that significantly outperformed common surfactant chemistry when applied to mixed-wettability shale core samples in laboratory Amott cell tests. The results from the laboratory testing were reflected in field trials: the relative permeability to hydrocarbon was increased and production was enhanced.","PeriodicalId":265203,"journal":{"name":"Day 2 Wed, August 15, 2018","volume":"37 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123402321","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":"Completion Diagnostics Learnings from Shale Development Projects","authors":"C. Ramos, R. Woodroof, Mark N. Warren","doi":"10.2118/191837-MS","DOIUrl":"https://doi.org/10.2118/191837-MS","url":null,"abstract":"\u0000 Accelerating the learning curve in the development of the Vaca Muerta utilizing lessons learned in North American unconventional resource plays is the focus of this paper. Reducing completion costs while maintaining high productivity has become a key objective in the current low-price environment. Completion diagnostics have been demonstrated to optimize stimulation and completion parameters that have shaped successful field developments.\u0000 The paper reviews stimulation diagnostic data from wells completed in the Tuscaloosa Marine Shale, Eagle Ford, Wolfcamp and Niobrara shale formations. Case histories are presented in which proppant and fluid tracers were successfully employed in completion optimization processes. In the examples presented, diagnostic results were used to assess the stimulation of high productivity intervals within a target zone, evaluate various completion methods, and optimize stage and cluster spacing. The diagnostic data were compared with post-frac production rates in an effort to correlate completion changes with well performance. Results presented compare first, engineered perforations versus conventional geometrically spaced perforations to drive up effectiveness in cluster stimulation. Second, new chemistries, such as nanosurfactant, versus conventional chemistries to cut either completion cost or prove their profitability. Third, employing an effective choke management strategy to improve well productivity. Last, as in any stacked pay, determining fracture height growth in order to optimize well density, well spacing, field development and ultimately the recovery of the natural resources.\u0000 Completion effectiveness is shown to be improved by landing laterals in high productivity target intervals, increasing proppant coverage across the lateral by utilizing the most effective completion methods, optimizing cluster spacing and decreasing the number of stages to reduce completion costs while achieving comparable production rates. Cluster treatment efficiency (CTE), in particular, has become a critical metric when optimizing hydraulic fracturing treatment designs based on current and future well densities. It can be used to rationalize well performance as well as to identify possible candidates for a refrac program.\u0000 Using completion diagnostics, successful completion techniques were identified that led to production enhancements and cost reductions in prolific plays such as the Tuscaloosa Marine Shale, Eagle Ford, Wolfcamp and Niobrara.","PeriodicalId":265203,"journal":{"name":"Day 2 Wed, August 15, 2018","volume":"194 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124336276","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 of Matrix-Fracture Transfer with Non-Uniform Block Distributions in Unconventional Low-Permeability Fractured Reservoirs","authors":"D. Ding","doi":"10.2118/191811-MS","DOIUrl":"https://doi.org/10.2118/191811-MS","url":null,"abstract":"\u0000 Unconventional tight-oil and shale-gas reservoirs are usually naturally fractured, and developing this kind of reservoirs requires stimulation via hydraulic fracturing to create conductive fluid flow paths via open fracture networks for practical exploitation. The presence of the multi-scale fracture network, including hydraulic fractures, stimulated and non-stimulated natural fractures, and micro-fractures, increases the complexity of the reservoir simulation. The matrix block sizes are not uniform, and they can vary in a very wide range, from several tens of centimeters to several tens of meters. In such a reservoir, the matrix provides most of the pore volume for storage, but makes few contributions to the global flow, while the fracture supplies the flow, however, with negligible contributions to reservoir porosity. The hydrocarbon is mainly produced from matrix-fracture interaction. So, it is essential to model accurately the matrix-fracture transfers with a reservoir simulator.\u0000 For the fluid flow simulation in tight-oil and shale-gas reservoirs, dual-porosity models are widely used. In a dual-porosity model, fractures are homogenized, and a shape factor, based on the homogenized matrix block size, is applied to model the matrix-fracture transfer. However, in real cases, the discrete fracture networks are very complex and non-uniformly distributed. One cannot determine an equivalent matrix block to compute the shape factor. So, a dual-porosity model is not accurate for the simulation of tight-oil and shale-gas reservoirs due to the presence of complex multi-scale fracture networks.\u0000 In this paper, we will study the MINC (Multiple Interacting Continua) method for the flow modeling in fractured reservoirs. MINC is usually considered as an improvement of the dual-porosity model. However, a standard MINC approach, using transmissibilities derived from the MINC proximity function, cannot always handle correctly the matrix-fracture transfers when the matrix block sizes are not uniformly distributed. To overcome this insufficiency, we present some new approaches for the MINC subdivision and the transmissibility computations. Several examples are presented to show that using the new approaches improves significantly the dual-porosity model and the standard MINC method for non-uniform block size distributions.","PeriodicalId":265203,"journal":{"name":"Day 2 Wed, August 15, 2018","volume":"23 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116936983","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":"Determining Optimal Well Spacing in the Marcellus Shale: A Case Study Using an Integrated Workflow","authors":"P. Pankaj, P. Shukla, P. Kavousi, T. Carr","doi":"10.2118/191862-MS","DOIUrl":"https://doi.org/10.2118/191862-MS","url":null,"abstract":"\u0000 Naturally fractured reservoirs such as the Marcellus shale require an integrated reservoir modeling approach to determine well spacing and well-to-well interference. The Marcellus Shale Energy and Environment Laboratory (MSEEL) is a joint project between universities, companies, and government to develop and test new completion technologies and acquire a robust understanding of the Marcellus shale. The study presented in this paper aims to reveal an approach to determine reservoir depletion with time through coupled geological modeling and geomechanical evaluation followed by completion and well performance history matching for a multiwell pad in the Marcellus shale.\u0000 The geomechanical model was prepared with interpreted vertical log data. A discrete natural fracture (DFN) model was created and used to determine the complexity of hydraulic fracture geometry simulated through complex fracture models on a two well pad. The microseismic data obtained during the hydraulic fracture simulations served as a constraining parameter for the hydraulic fracture footprint in these wells. Sensitivity to the DFN is realized by parametric variations of DFN properties to achieve a calibrated fracture geometry. Reservoir simulation and history matching the well production data confirmed the subsurface production response to the hydraulic fractures. Well spacing sensitivity was done to reveal the optimum distance that the wells need to be spaced to maximize recovery and number of wells per section.\u0000 Hydraulic fracture geometry was found to be a result of the calibration parameters, such as horizontal stress anisotropy, fracturing fluid leakoff, and the DFN. The availability of microseismic data and production history matching through integrated numerical simulation are therefore critical elements to bring unique representation of the subsurface reaction to the injected fracturing fluid. This approach can therefore be consistently applied to evaluate well spacing and interference in time for the subsequent wells completed in the Marcellus. With the current completion design and pumping treatments, the optimal well spacing of 990 ft was determined between the wells in this study. However, wells to be completed in the future needs to be modeled due to the heterogeneity in the reservoir properties to ensure that wells are not either underspaced to cause well production interference or overspaced to create upswept hydrocarbon reserves in the formation.\u0000 By adopting the key learnings and approach followed in this paper, operators can maximize subsurface understanding and will be able to place their wellbore in a nongeometric pattern based on reservoir heterogeneity to optimize well spacing and improve recovery.","PeriodicalId":265203,"journal":{"name":"Day 2 Wed, August 15, 2018","volume":"5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129912667","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":"Aggressive or Not? Experimenting with Fracturing Design and Fluids in Pursuit of Better Return","authors":"Max Nikolaev, Haiyan Zhao, Y. Christanti, S. Makarychev-Mikhailov","doi":"10.2118/191864-MS","DOIUrl":"https://doi.org/10.2118/191864-MS","url":null,"abstract":"\u0000 Unconventional plays in the US continue to be the biggest experiment in the history of the oil and gas industry. Particularly in the current market conditions of volatile oil prices, operators continue to introduce methods to maximize the efficiency of their operations. We examined the methods of adopting an aggressive approach to optimizing stimulation design to lower the breakeven level of operations and evaluated the results.\u0000 Public data were deciphered in a way they could be interpreted to the level of granularity sufficient to conclude an effect of certain fracturing techniques of different operators and to compare on a similar scale measures that had been taken to improve fracturing design. Various analytical and statistical tools were employed to handle the large amount of data in both unaltered and normalized ways to demonstrate the trends in different US basins.\u0000 Operators made significant improvement in production by changing parameters in the fracturing and completion design strategy, including, but not limited to, the amount of water used, the amount of sand pumped, stage spacing, maximum sand concentration, and fracturing fluid selection. However, the challenge remains of determining whether the design is indeed optimum. This paper addresses the importance of aggressive design, its evolution, and enablement technologies.","PeriodicalId":265203,"journal":{"name":"Day 2 Wed, August 15, 2018","volume":"22 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133196069","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":"Application of Natural Gas for Foamed Fracturing Fluid in Unconventional Reservoirs","authors":"P. Pankaj, Alhad Phatak, S. Verma","doi":"10.2118/191863-MS","DOIUrl":"https://doi.org/10.2118/191863-MS","url":null,"abstract":"\u0000 Foamed fracturing fluids have been used in unconventional reservoirs to reduce the water use and minimize deleterious impact on water-sensitive formations. As part of a Department of Energy (DOE) sponsored program, we previously identified an optimal thermodynamic pathway to transform wellhead natural gas (NG) into pressurized NG suitable for use as the internal phase in a foamed fracturing fluid. This study now aims to extend that work by determining the impact of using NG foam fracturing fluids on hydraulic fracture geometry and on productivity from the unconventional reservoirs.\u0000 The current study is focused on investigating the impact of the NG-based foam of various foam qualities in hydraulic fracture geometries and their production through simulation models. Field data and laboratory based measurements for NG foam fluid properties are incorporated in the study. In addition, the transient response of the fluid flowback from foam based fluid is studied using numerical simulation. Comparative analysis is done with typical slickwater, linear gel, and crosslinked fluid application for hydraulic fracturing using 3D-complex hydraulic fracture models. 1D and 2D particle transport models have been used to verify the differences in proppant distribution in the hydraulic fractures.\u0000 Rapid wellbore clean-up, low formation damage, and effect of the relative permeability improvement are added advantages apart from reducing the water requirements for hydraulic fracturing. In addition to providing the logistical benefit of using wellsite liberated low pressure gas, NG foamed fracturing fluid has a dynamic fluid leak-off behavior and increased effective viscosity over the base fluid that allows pumping and transporting proppant at least 10% farther in the hydraulic fractures than linear gel. Slickwater displays poor proppant transport and hence poses inability to pump higher concentrations of sand. NG foam fracturing fluid on the other hand displays improved proppant transport and has been shown to create more complexity than slickwater in our simulations.\u0000 Use of NG foamed fracturing fluid has not been practiced widely yet. Application of NG Foamin field test and reaping the economic benefit from simplified logistics and improved production would enables operators to invest in creating a safer handling environment for wellsite application of NG foam.","PeriodicalId":265203,"journal":{"name":"Day 2 Wed, August 15, 2018","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129087766","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":"Experience in Lateral Well and Perf Cluster Spacing for Shale Dry Gas","authors":"Fabio David Chiarandini","doi":"10.2118/191834-ms","DOIUrl":"https://doi.org/10.2118/191834-ms","url":null,"abstract":"\u0000 The objective of this work is to present an integrated methodology/workflow for optimizing lateral well spacing and fracture spacing for unconventional reservoirs based on multiple experience in Marcellus shale gas development. Optimal well plans and completion designs, based on geology and reservoir characterization, are key elements in developing economic projects. Well performance and reserves at a pad level can be improved thought coordinated efforts from multi-functional disciplines.\u0000 Workflow incorporates data integration and main analysis to be performed from all involved disciplines. Main disciplines are geology, reservoir and production engineering, drilling and completions teams, decision and economic evaluation and cost assurance process. A full set of reservoir modeling, economic analysis tools are described in the document. Workflow is optimized with a loop, where main routine and non-routine surveillance is used mainly for interference analysis and further optimization on both spacing for the factory-style development.\u0000 Reservoir simulation fed into two separate workflows. One is a single pad economic model and or DOE which incorporates decision analysis techniques. The other is a portfolio analysis with pads scheduled to fill a midstream capacity constraint through time. Both cases balance the increased capital costs against accelerated and increased production. The portfolio analysis tool is useful in understanding impacts of tighter well lateral and cluster spacing, particularly how they influenced capital costs over time. Additionally, results are compared with analog data and competitor analysis.\u0000 Methodology was field tested. Workflow application demonstrates that optimum lateral well spacing and cluster spacing in dry gas core area would have a positive impact on EUR (estimated ultimate recovery) at a pad level. Also, pad drilling and Completion optimizations provide increased NPV (net present value) and incremental DPI (discount profit investment) ratio.\u0000 The experience in lateral well and perf cluster spacing for shale dry gas for geometric completions is an example of how to manage uncertainty through cross-functional collaboration.\u0000 Workflow can be used as inputs in pilot test for well spacing and as a process to justify surveillance needs using value of information techniques.","PeriodicalId":265203,"journal":{"name":"Day 2 Wed, August 15, 2018","volume":"2013 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125660309","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":"Field Development Optimization Through Integrated Geosciences and Engineering Analysis","authors":"Agustin Hren, V. A. Exler, H. Peacock, R. Schmidt, M. Pellicer, Lucia Lamberghini, J. Gait","doi":"10.2118/191833-MS","DOIUrl":"https://doi.org/10.2118/191833-MS","url":null,"abstract":"\u0000 Lindero Atravesado field is located in Neuquen, western Argentina. It has been under development since 2012. Originally, its development was focused on conventional formations (Quintuco, Sierras Blancas and Lotena), considering the Punta Rosada and Lajas formations as geological traps. Development is now focused on these traps, especially in the northwest region the field, called the Lindero Atravesado Occidental. Fundamental challenges in the Occidental region of the field include optimum fluid engineering, avoiding shear-sensitive fluid systems, high PAD percentage and safe operational efficiency in deep HPHT wells.\u0000 However, original frac designs were optimized through a traditional cycle of design and pressure-matching evaluations using a conventional frac simulator. Obtained fracture geometries were bounded in length and a considerable height growth was observed. Other studies used microseismic, sonic profiles or traceable sands, and showed fractures contained in height and longer fracture lengths than those obtained with the traditional adjusted model.\u0000 A fracturing model coupled with microseismic interpretation allowed a better characterization of fracture geometry, vertical covering, effective production fracture length and drainage area efficiency, based on numerical production simulations and matching. The last point will have a direct impact on well spacing and future selection of in-fill locations.\u0000 This paper will discuss a fully integrated approach for field planning optimization, starting with geosciences characterization, workover, stimulation and production history matching, with a direct impact on well gridding and estimated ultimate recovery (EUR) per well.","PeriodicalId":265203,"journal":{"name":"Day 2 Wed, August 15, 2018","volume":"55 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-08-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133570557","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}