Day 4 Thu, June 06, 2019最新文献

{"title":"Investigation of Pore Structure and Fractal Characteristics in an Organic-Rich Shale Gas-Condensate Reservoir from the Duvernay Formation","authors":"Su Penghui, Xiang Zhaohui, W. Ping, Qu Liangchao, Kong Xiangwen, Zhao Wenguang","doi":"10.2118/195527-MS","DOIUrl":"https://doi.org/10.2118/195527-MS","url":null,"abstract":"\u0000 Interest has spread to potential unconventional shale reservoirs in the last decades, and they have become an increasingly important source of hydrocarbon. Importantly, pore structure of shale has considerable effects on the storage, seepage and output of the fluids in shale reservoirs so that reliable fractal characteristics are essential. To better understand the evolution characteristics of pore structure for a shale gas condensate reservoir and their influence on liquid hydrocarbon occurrences and reservoir physical properties, we conducted high-pressure mercury intrusion tests (HPMIs), field emission scanning electron microscopies (FESEM), total organic carbon (TOC), Rock-Eval pyrolysis and saturation measurements on samples from the Duvernay formation. Furthermore, the fractal theory is applied to calculate the fractal dimension of the capillary pressure curves, and three fractal dimensions D1, D2 and D3 are obtained. The relationships among the characteristics of the Duvernay shale (TOC, organic matter maturity, fluid saturation), the pore structure parameters (permeability, porosity, median pore size), and the fractal dimensions were investigated.\u0000 The results show that the fractal dimension D1 ranges from 2.44 to 2.85, D2 ranges from 2.09 to 2.15 and D3 ranges from 2.35 to 2.48. D2 and D3 have a good positive correlation. The pore system studied mainly consists of organic pores and microfractures, with the percentage of micropores being 50.38%. TOC has a positive relationship with porosity and D3 due to the development of organic pores. D3 has a positive correlation with gas saturation. With increased D3, median pore size shows a decreasing trend and an increase in permeability and porosity, demonstrating that D3 has a large effect on pore size distribution and the heterogeneity of pore size. In general, D3 has a better correlation with petrophysical and petrochemical parameters. Fractal theory can be applied to better understand the pore evolution, pore size distribution and fluid storage capacity of shale reservoirs.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"70 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114277480","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":"Mechanistic Simulation and History Matching of Alkaline-Surfactant-Polymer ASP Core Flooding Experiment at Optimum vs. Under-Optimum Salinity Conditions","authors":"M. Yegane, E. Battistutta, P. Zitha","doi":"10.2118/195564-MS","DOIUrl":"https://doi.org/10.2118/195564-MS","url":null,"abstract":"\u0000 Alkaline Surfactant Polymer (ASP) flooding is a chemical EOR method to increase oil recovery after water flooding through IFT reduction and increasing sweep efficiency. Previous studies have shown that maximal oil recovery is reached when ASP flooding is performed at optimum salinity conditions, i.e. Winsor type III micro-emulsion phase but a recently series of core-flood experiments indicated that comparable oil recovery could be obtained at under-optimum salinity conditions (Battistutta et al. 2015). Mechanistic simulation of ASP flooding considering phase behavior of water-oil-surfactant system, geochemical reactions and alkaline consumption is needed to validate the experimental data and provide a robust model for field scale studies. In this paper detailed history matching of series of core-flood experiments was attempted. Experiments were performed at different salinity conditions (optimum vs. under-optimum) and with different core types (Bentheimer and Berea) using a single olefin sulfonate (IOS) and crude oil with very low acid number (<0.05 mg KOH/g oil). The numerical simulations were performed using UTCHEM, multiphase multi-component simulator along with EQBATCH module to model the geochemical reactions.\u0000 Neglecting the effect of in-situ surfactant (soap) generation, since the acid number of crude oil was low, modeling of the phase behavior showed an excellent match against experimental data and optimal salinity was observed at 2.0 wt% NaCl (+ 2.0 wt% Na2CO3).Using this and considering aqueous and cation exchange as the most important geochemical reactions in alkaline propagation, several ASP core-flood experiments at optimum vs. under-optimum salinity conditions were successfully modeled. An excellent matching of all the measured parameters including oil cut and recovery, pressure drop, pH and carbonate, alkali and surfactant concentration at effluent was also achieved. Modeling confirms the results obtained from experiment which regardless of core type, although minimum achieved IFT at optimum salinity conditions is lower than the one achieved at under-optimum conditions, comparable final oil recovery was observed for both cases. This emphasizes the importance of performing ASP flooding at under-optimum salinity conditions due to lower surfactant retention and reducing the likelihood of achieving over-optimum salinity conditions.\u0000 In this paper a robust model which is calibrated with experimental data is presented to simulate ASP flood process at various conditions and the basic model can be used to perform further simulations and can provide practical and convenient approach to model field applications of ASP flooding.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"53 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130678895","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":"An Integrated Sanding Study in an HP/HT Tight-Sandstone Gas Reservoir","authors":"Yang Zhang, Yuanwei Pan, Xiaohu Cui, K. Qiu, Q. Teng, Yongjie Huang, Fen Peng","doi":"10.2118/195479-MS","DOIUrl":"https://doi.org/10.2118/195479-MS","url":null,"abstract":"\u0000 KS is a tight-sandstone and high-pressure-high-temperature (HPHT) gas reservoir in northwest China. It is characterized by a depth of more than 6000 m, temperature over 175°C, and pore pressure over 110 MPa. Despite the high unconfined compressive strength (UCS) of sandstone, almost half of the wells encountered sanding issues. The sanding wells exhibited low production rate, nozzle and pipeline erosion, sanding up, and even permanent closure. Investigating the sanding mechanism and developing solutions for sanding prevention are urgent needs due to the economic loss of low production.\u0000 An integrated sanding study was conducted to investigate the sanding mechanism. The entire sanding process was analyzed, including stress field alteration during production, rock failure, softening, and sand grain migration. First, wells with sanding issues were identified through production characteristics and field observation. After this, analysis of laboratory tests was performed to better understand the tight-sandstone properties, especially UCS, the softening parameter, and residual strength. Based on the tests, an elastoplastic damage model was proposed to delineate rock failure and sanding behavior. Then, a finite element model was built to simulate the damage of a perforation hole with field data, including hole diameter and length, rock stiffness and strength, drawdown, depletion, and so on. More simulation scenarios were performed to investigate the continuous sanding, transient sanding, and water hammer effect. Grain migration in perforation holes and in pipelines was also studied.\u0000 It was revealed that shear failure of perforation hole induced by drawdown and depletion was the root cause of sanding problem. Meanwhile, it was also confirmed that erosion and water hammer effect had very limited effect on sanding. Use of the elastoplastic damage model for the simulation of perforation hole failure enabled predicting the sand amount and determining the critical drawdown and depletion for sanding. In the end, an approach to identifying wells with high sanding risk and the key factors behind the sanding were provided, and sanding prevention suggestions were proposed.\u0000 The new elastoplastic damage model explains the sanding mechanism in a tight-sandstone reservoir and enables evaluating the sand volume, which has rarely been published previously. Laboratory tests, field observation, and numerical simulation were combined effectively to investigate the sanding issue. By utilizing the model, producers can find the key factors behind sanding issues, prevent sanding with a better production strategy, and avoid the economic loss, which are critical for the long-term exploration and production of this area.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"35 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131808061","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 New Modelling Approach to Simulate CO2 Movement and Containment Coupled With Geochemical Reactions and Geomechanical Effects for an Offshore CO2 Storage in Malaysia","authors":"W. Yong, A. I. Azahree, S. S. Ali, F. Azuddin, S. M. Amin","doi":"10.2118/195432-MS","DOIUrl":"https://doi.org/10.2118/195432-MS","url":null,"abstract":"\u0000 This paper presents a two-way coupled modelling approach to simulate CO2 movement and containment with geochemical reactions and geomechanical effects. CO2storage simulation studies cover three main disciplines, reservoir engineering, geochemistry and geomechanics. This new approach of coupled modelling simulation, by simultaneously simulate both effects of geochemistry and geomechanics, is considered as a more representative and better predictive modelling practice.\u0000 The integration of geochemistry and geomechanics effects is important for CO2 sequestration modelling. There are a number of published studies on coupled modelling for CO2 storage. However, the majority of the studies has only covered dynamic-geomechanics or dynamic-geochemistry interaction, without considering any direct geomechanics-geochemistry interaction in a reservoir condition. It is crucial to understand the integrated effects when injected CO2 dissolves into formation water and interacts with formation rock. Depending on in-situ conditions, the formation water with dissolved CO2 could weak or strengthen the formation stress due to geochemical reactions of formation minerals. Therefore, coupled modelling is needed to ensure the long-term safetyof CO2containment at a CO2 storage site with the interactions among geomechanical, geochemical and dynamic fluid flow, and especially to understand the slow and not experimentally accessible mineral reactions.\u0000 In this paper, a high CO2 content gas field in Malaysia with high temperature (~150°C) and high pressure (~350 bar) has been studied using integrated coupled modelling approach. The simulation input parameters are first investigated and collected from literature and laboratory studies. A two-way coupled modelling simulation with the consideration of geochemistry and geomechanics effects is desirable because it allows the updates of reservoir properties back and forth in every time step. Different CO2trapping mechanisms, long term fate analysis, subsidence and heaving analysis, and changes of porosity and permeability are investigated. The time frame of simulation studies consists of CO2 injection period (15 years) and post CO2 injection period (500 years).\u0000 During the first 15 years of CO2 injection, 95% of injected CO2 is structurally trapped, 4% of CO2is soluted in formation water and 1% is trapped by mineralization. About 0.04m of heaving is observed at the injection area while about 0.05m of subsidence is observed at the production area. In the investigation of long-term CO2fate, it is observed that CO2 gas will be trapped between the lighter hydrocarbon gas layer and aquifer due to density difference.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"10 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133639801","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":"Can Unconventional Completion Systems Revolutionise EGS? A Critical Technology Review","authors":"F. Guinot, P. Meier","doi":"10.2118/195523-MS","DOIUrl":"https://doi.org/10.2118/195523-MS","url":null,"abstract":"\u0000 The technical and economic successes of deep geothermal development rely on reducing drilling and completion risks. In the closely related oil and gas activities, the risk taken by the investors is balanced by the high reward that successful projects achieve by immensely offsetting the losses of the failed wellbores. Geothermal projects experience similar risks, however, the potential reward is limited by the competition with other energy sources, in a heavily regulated market. The economic acceptability of geothermal power generation requires low risk drilling and completion technologies that would work under many different geological conditions.\u0000 When wells are drilled into a petro-thermal formation, sometimes referred to as hot dry rock (HDR), there is normally no clear circulation path between these wells and when this path exists, the transmissivity is so low that no economical project is possible. Enhanced geothermal systems (EGS), in these circumstances is closer to reservoir creation than to conventional reservoir stimulation. Therefore, developing technologies that achieve the designed EGS size and transmissivity is vital to deep geothermal development.\u0000 The EGS becomes a viable proposition, when enough rock surface can be contacted by the geothermal fluid, and when the flow path runs smoothly through a sufficient rock volume to minimize the energy depletion and have the project running over a long period, compatible with a positive net present value (NPV). To that end, the well design and its completion system have to be engineered to maximize the chances of properly creating the EGS. In this paper, lessons learnt from past geothermal experience are reviewed and analysed to propose a multi-stage system as a mean of improving geothermal wells completion reliability. Current oil and gas (namely \"unconventional\") completion technologies related to multi-stage stimulation have been reviewed and different options are discussed in the scope of a deep geothermal hot dry rock project. While previous works conclude that technologies developed for oil and gas are readily available and applicable to deep geothermal projects and EGS (Gradl, 2018), this study shows that shortcomings exist and that further developments are necessary to reliably and economically complete EGS projects. The necessary tests before running different parts is also discussed. Other options for reservoir creation are debated with their potential benefits and associated risks. The developments that could make them work in an EGS project are discussed.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"38 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114511358","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":"How to Use Analytical Tools to Forecast Injectivity in Polymer Floods","authors":"E. Delamaide","doi":"10.2118/195513-MS","DOIUrl":"https://doi.org/10.2118/195513-MS","url":null,"abstract":"\u0000 One of the main uncertainties when designing polymer floods is the polymer injectivity, an important parameter that can affect the economics of the process. Reservoir simulation can be used to forecast injectivity, but the process is not straightforward and can be affected by grid size and other factors. Analytical methods are also available for that purpose, but they are considered too simplistic to deal with realistic reservoir conditions. The aim of this paper is to show that this is not the case and that simple analytical tools can be accurate and of great help to predict or history match polymer injectivity.\u0000 The analytical method has been developed by Lake in his classical textbook on Enhanced Oil Recovery, but few applications are documented in the literature. This paper will review the method and corresponding equations before presenting several actual field cases of injectivity in polymer flood pilots or tests from several countries that have been matched analytically.\u0000 Although it has not been used very often, the method has been found to give very good results in most of the field cases tested in a variety of situations; these cases will be presented along with recommendations on how to apply the method and a discussion of the results. Sensitivities to the various parameters will also be presented. Once the equations are programmed in a spreadsheet, the matching process takes only a few minutes and it is easy to run various scenarios and sensitivities.\u0000 Polymer injectivity remains one of the less understood and less predictable aspects of polymer flood projects. This paper will encourage engineers who are planning such projects to use simple yet accurate analytical tools before embarking in more complex and time-consuming reservoir simulations.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"18 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122200653","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":"Quantifying Geological Uncertainty for Complex Integrated Production Systems with Multiple Reservoirs and Production Networks","authors":"V. Pathak, Y. Hamedi, O. Martinez, Stephen Vermeulen, Anjani Kumar","doi":"10.2118/195477-MS","DOIUrl":"https://doi.org/10.2118/195477-MS","url":null,"abstract":"\u0000 Integrated production systems models are very valuable for predicting the performance of complex systems containing multiple reservoirs and networks. In addition, the value of quantifying uncertainty in reservoirs and production systems is immense as it can build confidence in operational investments. However, traditionally it has been extremely tedious to incorporate uncertainty assessments in the context of integrated production systems modelling. This has been addressed in the current work with the help of a case study.\u0000 In the current work, a complex integrated production systems model is presented - from Pre-Salt carbonates reservoir offshore of Brazil. The model includes multiple reservoirs with unique fluid types and complex fluid blending in the production network, multiphase and thermal effects in flowlines and risers, gas separation, gas processing, gas compression, and re-injection for either pressure maintenance or for miscible EOR.\u0000 The operational strategies, well placement, and well and network configurations are often based on a single geological realization. With the case study presented in this paper, an integrated way of quantifying geological uncertainty has been presented. A new multi-user, multi-disciplinary tool was used for this study that removed any discontinuities and inconsistencies that typically occur in such projects when multiple standalone tools are used for individual tasks. When quantifying uncertainty on production, the dependence on a single realization was eliminated as uncertain parameters were identified and used for creating robust probabilistic forecasts. Probability distribution curves were generated to represent the uncertainty in overall production from this asset, and the risk associated with operational investments was minimized.\u0000 Typically, an end-to-end uncertainty assessment is missing from the traditional Integrated Modelling workflows. With this new approach, the challenge of achieving a truly integrated uncertainty assessment for integrated reservoir and production models has been addressed successfully.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"40 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127786526","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 of Upscaling Approaches for the Amellago Carbonate Outcrop Model","authors":"Ching-Hsien Liu, K. Nunna, Imroj Syed, M. J. King","doi":"10.2118/195560-MS","DOIUrl":"https://doi.org/10.2118/195560-MS","url":null,"abstract":"\u0000 Carbonate reservoirs are extremely challenging for reservoir modeling and flow simulation due to their high heterogeneity and the complexity of controls on the porosity and permeability. The porosity and permeability may be connected or weakly connected, which can cause difficulties in coarse grid design and upscaling of flow. We report on the application of a recently developed \"Diffuse Source\" upscaling approach here applied to the upscaling of a high resolution 3D carbonate reservoir model.\u0000 A high-resolution 3D geological model of the Amellago carbonate outcrop was utilized for analysis. This model, which has similar stratigraphy, structure and diagenetic controls as Middle East reservoirs, has proven to be a challenge for existing layer upgridding and flow-based upscaling approaches. We utilize flow-based \"Diffuse Source\" upscaling to obtain the intercell transmissibility and well indices, as this approach has improved localization and resolution compared to steady state calculations, and also allows us to distinguish between well connected and weakly connected sub-volumes.\u0000 We report on the performance of the statistical layer upgridding approaches used to design the flow simulation grid from the underlying 3D geologic model, and the impact of the choice of the heterogeneity measure (velocity error, time of flight error, or a combination of the two). We benchmarked the Diffuse Source against several methods available in the literature. Finally, we demonstrate the utility of a recently developed method for flow diagnostics that allows us to test the quality of the coarse simulation models relative to the fine-scale geologic model. All of the upscaled models are tested using commercial finite difference simulation and are compared to the upscaling approaches available within commercial flow simulation and geologic modeling applications.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128670271","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":"Superposition, Convolution, Deconvolution, and Laplace: Pressure and Rate Transient Analysis Revisited with Some New Insights","authors":"T. Whittle, D. Viberti, E. S. Borello, F. Verga","doi":"10.2118/195554-MS","DOIUrl":"https://doi.org/10.2118/195554-MS","url":null,"abstract":"\u0000 \u0000 \u0000 Rate and pressure transient analysis is considered a routine process that has been developed and refined over many years. The underlying assumptions of linearity justify the use of superposition (in time and space), convolution and deconvolution. The reality of non-linearities are handled on a case by case basis depending on their source (fluid, well or reservoir). Shale gas wells are subject to significant non-linearity over their producing life.\u0000 We review some of the fundamental equations that govern pressure and rate transient behavior, introduce several new techniques which are suited to the analysis of data from producing wells and apply them to a synthetic example of a shale gas well.\u0000 \u0000 \u0000 \u0000 First, we use simple calculus to show how the convolution integral is derived from standard multi-rate superposition. Then, from the convolution integral, we derive an equation that describes the pressure response due to a step-ramp rate (i.e. an instantaneous rate change from initial conditions followed by a linear variation in rate). It results in a combination of the pressure change due to a constant rate and it's integral. Applying superposition to this equation allows any rate variation to be approximated by a sequence of ramps with far fewer points than those required to achieve the same level of accuracy using standard constant step rate superposition.\u0000 Second, we re-write multi-rate superposition functions allowing for stepwise linear variable rate which, when applied to flowing data and used to calculate the pressure derivative, can result in a much smoother response and hence an overall improvement in the analysis of rate and pressure transients recorded from producing wells.\u0000 Third, we review the use of the Laplace transform and how it can be applied to discrete data with a view to deconvolving rate transient data.\u0000 Finally, we demonstrate how data de-trending can remove the impact of long term non-linearities and apply the methods mentioned above to a synthetic dataset based on a typical shale gas well production profile.\u0000 \u0000 \u0000 \u0000 We illustrate the advantages of the newly introduced superposition functions compared to conventional analysis methods when applied to the pressure transients of wells flowing at variable rate.\u0000 As an example, we have simulated the production of two shale gas wells over twenty years. Both have the same production profile, but one includes pressure dependent permeability. At various intervals during the life of the well, we introduce a relatively short well test which imposes a small variation in rate but does not include a shut-in. We de-trend the rate transients and then apply the techniques described above to analyse the resulting data. The interpretation allows us to identify non-linearities that may be influencing well productivity over time and to obtain a better understanding of the physics of shale gas production.\u0000 The mathematics documented in the paper provides a useful overview of how convolution, su","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"258 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125715337","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 Well Spacing and Fracture Design Using Advanced Multi-Stage Fracture Modeling and Discrete Fractured Reservoir Simulation in Tight Oil Reservoir","authors":"C. Tian, Zhengdong Lei, Qingping Jiang, Tianquan Chang, Dongliang Chen, Zhiyuan Lu, Sheng Li","doi":"10.2118/195455-MS","DOIUrl":"https://doi.org/10.2118/195455-MS","url":null,"abstract":"Large platforms, long horizontal sections, small well spacings and dense cutting have become economical and effective development means for tight oil reservoirs. Well spacing and fracture design are critical parameters impacting production and Internal rate of return (IRR) of tight oil reservoirs. In order to maximize the total stimulated reservoir area and fracture-controlled reserves, the well spacing and fracture spacing should be small enough. However, in order to minimize the chance of fracture hits caused by offset wells and the overlapping drainage area of a nearby well to avoid Asset spillover, the spacing well should large enough.\u0000 Based on minifrac data and microseismic fracture mapping results, a natural/hydraulic fracture network was generated and input into an unstructured-grid-based discrete fracture reservoir simulation model. Its accuracy was calibrated with the well production history. For each group of fracture design and well spacing, well interference was determined by estimating ultimate recovery (EUR) difference between a single well and a middle well among multiple wells. Based on actual information of tight oil developments, the pressure interference were examined by field trail data and well spacing simulations. The real scenarios were selected to study effects of well spacing on EUR and ultimate IRR. Effects of reservoir permeability and fracture half-length on optimal well spacing were also analyzed.\u0000 It was found that the decrease in Long-term EURs for different well spacings is a good indicator for well spacing optimization. Based on the reservoir simulation and economic analysis, the maximum IRR of the tight oil reservoir with permeability of 0.23mD can achieved when the well spacing is 260m. Meanwhile, the detailed results were also illustrated to show the effects of fracture half-length, reservoir permeability as well as oil price variation on IRR.\u0000 The paper demonstrates an effective method and a workflow to optimize well spacing and fracture treatments design through integrating advanced multi-stage fracture modeling with discrete fracture reservoir simulation in the area of unconventional resource developments. Such optimization studies contribute to minimize operation cost and improve the economy of resource development.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"157 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132970799","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}