Day 4 Thu, June 14, 2018最新文献

{"title":"Modeling and Simulating Multi-Polymer Injections","authors":"C. Preux, I. Malinouskaya, Q. Nguyen, R. Tabary","doi":"10.2118/190759-MS","DOIUrl":"https://doi.org/10.2118/190759-MS","url":null,"abstract":"\u0000 In a process of enhanced oil recovery (polymer flooding), of well treatment (conformance control, water shut-off) or eventually any other process, the injection of several types of polymer solutions can be envisioned. Polymers considered could have different chemical structure, may not have been dissolved in the same water and may not necessarily be injected in a single and unique well. The same question appears in connection with a method where a mixture of two (or more) polymers would be intentionally injected. The few studies available involve mixtures of polymers in organic solvents.\u0000 We could not find a study dedicated to an injection of a blend of polymers in porous media. Only a theoretical paper by V.P. Budtov [1] drew our attention, focusing on the estimation of the relative viscosity of a mixture of several polymers. Its main message is that, in order to make sense, the mixture is assumed as a single homogeneous phase, at least in a given area of concentration. The adsorption of several \"polymer\" components raises a difficult question about the so-called competitive adsorption.\u0000 There are two opposite answers. In the first one, at the laboratory scale, chemical interactions on the rock surface are instantaneous (\"first come, first adsorbed\"). According to the other one, at the reservoir scale, exchanges have all the time necessary to occur and they take place in the direction of a preferential adsorption of the stronger mass or higher affinity polymer (\"hierarchical model\"). In this paper, we present a complete modeling and simulation of multi-polymer injection(s), based on physical data. The concepts of mobility reduction and adsorption are studied and validated through some test cases. In particular, the effect of multi-polymer injection(s) on adsorption is investigated. In the first part, we introduce the mathematical system and the method used to solve it. The second part addresses the modeling of different parameters such as mobility and permeability reduction and hierarchical adsorption based on experimental data. Then, we discuss some numerical experiments realized thanks to the in-house software PumaFlowTM to validate the model and study the effect of multi-polymer injection(s) on adsorption. Finally, we conclude with the benefit provided by such type of modeling and we present the perspectives of this work.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"17 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":"125214213","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":"Near Wellbore Two-Phase Effect of a Light Oil Field","authors":"Zhaocong Zhou, A. Lamberti, A. Locci, Valerio Parasiliti, P. Prevosti, G. Tripaldi","doi":"10.2118/190772-MS","DOIUrl":"https://doi.org/10.2118/190772-MS","url":null,"abstract":"\u0000 This work describes a case of a light oil field in Sub-Saharan Africa. Soon after the start up, the production wells showed a productivity index different from expectation. In particular, well test analysis showed different stabilizations between build-up and drawdown. Since the well is flowing with pressure below the bubble point, the impact of oil permeability reduction due to presence of free gas around the wellbore was considered as a possible explanation and was investigated.\u0000 We applied well test analysis on synthetic data generated by numerical simulation. The analysis confirms the different stabilizations between pressure build-up and drawdown, as observed from the real field case, when the flowing bottomhole pressure is below the bubble point pressure. The different flow capacity is caused by gas saturation around the wellbore, which reduces the effective permeability to oil, hence the productivity index.\u0000 Besides this, we experienced that a full field model with large grid size is not able to represent this phenomenon. Due to the grid size, the full field model shows less pressure drop than the radial sector model, hence different gas saturation calculation. We showed that in order to simulate the effect without impacting on simulation time, applying higher well skin instead of local grid refinement can be a way forward.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"5 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":"133862170","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":"Cyclic Flow of Two Immiscible Phases","authors":"A. Rabinovich","doi":"10.2118/190789-MS","DOIUrl":"https://doi.org/10.2118/190789-MS","url":null,"abstract":"\u0000 We derive an analytical solution for two-phase cyclic flow assuming incompressible fluid and rock, one dimensional flow and negligible capillary pressure effects. The solution is intended to model subsequent periods of injection and production in a reservoir or core sample. It pertains to applications such as gas storage in water bearing formations or enhanced oil recovery by CO2 cyclic injection. Derivation is based on the method of characteristics and leads to an extension of the Buckeley-Leverett solution to cyclic injection. The saturation profile consists of two functions separated by a discontinuity. It is shown that the moving front advances during injection and recedes during production until returning back to the well. Some injected phase may remain in the reservoir after production and this in turn contributes to a deeper penetration during the next injection period.\u0000 The solution for saturation profile as a function of time is analyzed and shown to become steady periodic after a number of cycles. We investigate the solution dependence on the controlling parameters: relative permeability (power n in krw, krnw functions), viscosity ratio μw/μnw and nondimensional production time t˜prod.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"19 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":"124946106","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-Scale Production Optimization with Intelligent Wells","authors":"Osho Ilamah, Ross Waterhouse","doi":"10.2118/190827-MS","DOIUrl":"https://doi.org/10.2118/190827-MS","url":null,"abstract":"\u0000 Intelligent wells with inflow control valves enable flexible management of multiple reservoir intervals. In this paper, we describe model based optimization of inflow control valve settings for a producing North Sea field. A two step, non-invasive, iterative pattern search optimization algorithm is applied. The first step provides global search of the feasible region using a discrete genetic algorithm whereas the second step provides local search around the incumbent solution. To account for reservoir uncertainties, optimization is performed on a diverse set of history matched reservoir model realizations, within an automated framework. The results show a significant improvement in predicted reservoir production performance over the remaining life of the field.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"58 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":"129665690","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":"Evolution of Permeability in Sand Injectite Systems","authors":"Yu Hu, Q. Gan, A. Hurst, D. Elsworth","doi":"10.2118/190853-MS","DOIUrl":"https://doi.org/10.2118/190853-MS","url":null,"abstract":"\u0000 Sand injectite complexes comprise kilometer-scale clastic intrusion networks that act as effective conduits for the migration, accumulation and then recovery of hydrocarbons and other fluids. An equivalent continuum model is constructed to represent a sand injectite reservoir, coupling stress and fluid flow in fractured rock using the continuum simulator TOUGHREACT coupled with FLAC3D to follow deformation and fluid flow. A permeability model, which uses staged percolation models, is proposed to improve permeability estimation of fracture networks by accommodating four different levels of fracture connectivity. This permeability model is confirmed against field and laboratory data, corresponding to the different connectivities of fracture networks. The new constitutive permeability model is incorporated into the coupled hydro-mechanical simulator framework and applied to sand injectites with the analysis of permeability evolution mechanisms and mechanical sensitivity. The results indicate that when the magnitudes of principal stresses increase in a constant ratio, normal closure is the dominant mechanism in reducing fracture aperture and thereby permeability. Conversely, the evolution of stress difference can accentuate aperture and permeability due to an increase in shear dilation for critically or near-critically oriented fractures. Also, the evolution of aperture and related permeability of fractured rock are more sensitive at lower stress states than at higher stress states due to the hyperbolic relationship between normal stress and normal closure of the fractures.","PeriodicalId":178883,"journal":{"name":"Day 4 Thu, June 14, 2018","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129000382","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}