Relevant bibliographies by topics / Petroleum and reservoir engineering

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  1. Journal articles
  2. Dissertations / Theses
  3. Books
  4. Book chapters
  5. Conference papers
  6. Reports

Academic literature on the topic 'Petroleum and reservoir engineering'

Author: Grafiati
Published: 4 June 2021
Last updated: 28 January 2023

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Journal articles on the topic "Petroleum and reservoir engineering"

1

Bennett, B., A. Lager, D. K. Potter, J. O. Buckman, and S. R. Larter. "Petroleum geochemical proxies for reservoir engineering parameters." Journal of Petroleum Science and Engineering 58, no. 3-4 (September 2007): 355–66. http://dx.doi.org/10.1016/j.petrol.2006.06.009.

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Archer, J. "Principles of petroleum reservoir engineering, vol. 1." Journal of Petroleum Science and Engineering 13, no. 3-4 (November 1995): 259–60. http://dx.doi.org/10.1016/0920-4105(95)90008-x.

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Barends, F. B. J., and P. A. Fokker. "Principles of petroleum reservoir engineering, volume 1." Earth-Science Reviews 39, no. 1-2 (September 1995): 132. http://dx.doi.org/10.1016/0012-8252(95)90018-7.

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FOKKER, P. "Principles of petroleum reservoir engineering, volume 2." Earth-Science Reviews 40, no. 1-2 (April 1996): 169–70. http://dx.doi.org/10.1016/0012-8252(96)90067-7.

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Buryakovsky, Leonid A., and George V. Chilingar. "Petrophysical Simulation in Petroleum Geology and Reservoir Engineering." Energy Sources 27, no. 14 (October 2005): 1321–47. http://dx.doi.org/10.1080/009083190519537.

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Lawal, Kazeem A. "Applicability of heat-exchanger theory to estimate heat losses to surrounding formations in a thermal flood." Journal of Petroleum Exploration and Production Technology 10, no. 4 (November 2, 2019): 1565–74. http://dx.doi.org/10.1007/s13202-019-00792-5.

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Abstract Heat losses to cap and base rocks undermine the performance of a thermal flood. As a contribution to this subject, this paper investigates the applicability of the principles of heat exchanger to characterise heat losses between a petroleum reservoir and the adjacent geologic systems. The reservoir-boundary interface is conceptualised as a conductive wall through which the reservoir and adjacent formations exchange heat, but not mass. For a conduction-dominated process, the heat-transport equations are formulated and solved for both adiabatic and non-adiabatic conditions. Simulations performed on a field-scale example show that the rate of heating a petroleum reservoir is sensitive to the type of fluids saturating the adjoining geologic systems, as well as the characteristics of the cap and base rocks of the subject reservoir. Adiabatic and semi-infinite reservoir assumptions are found to be poor approximations for the examples presented. Validation of the proposed model against an existing model was satisfactory; however, remaining differences in performances are rationalised. Besides demonstrating the applicability of heat-exchanger theory to describe thermal losses in petroleum reservoirs, a novelty of this work is that it explicitly accounts for the effects of the reservoir-overburden and reservoir-underburden interfaces, as well as the characteristics of the fluid in the adjacent strata on reservoir heating. These and other findings should aid the design and management of thermal floods.
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Okotie, S., and N. O. Ogbarode. "EVALUATION OF AKPET GT9 GAS CONDENSATE RESERVOIR PERFORMANCE." Open Journal of Engineering Science (ISSN: 2734-2115) 1, no. 1 (March 10, 2020): 1–13. http://dx.doi.org/10.52417/ojes.v1i1.80.

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To effectively evaluate a gas condensate reservoir performance, the reservoir engineer must have a reasonable amount of knowledge about the reservoir to adequately analyze the reservoir performance and predict future production under various modes of operation. Due to the multiphase flow that exists in the reservoir, characterization of gas condensate reservoirs is often a difficult task with the variation of its overall composition in both space and time during production which complicates well deliverability analysis and the sizing of surface facilities. This study is primarily concern with the evaluation of a gas condensate reservoir performance of Akpet GT 9 Reservoir in the Niger Delta region of Nigeria with material balance analysis tool “MBal” without having to run numerical simulations. The result obtained with MBal on the analysis of Akpet GT 9 reservoir gave 23.934 Bscf of gas initially in place which compares favorably with the volume obtained from volumetric techniques. Results also shows that the most likely aquifer model is the Hurst–Van Everdingen - Dake radial aquifer and the reservoir is supported by a combined drive of water influx and fluid expansion. Okotie, S. | Department of Petroleum Engineering, Federal University of Petroleum Resources (FUPRE), Effurun, Delta State, Nigeria.
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Gutierrez, M., R. W. Lewis, and I. Masters. "Petroleum Reservoir Simulation Coupling Fluid Flow and Geomechanics." SPE Reservoir Evaluation & Engineering 4, no. 03 (June 1, 2001): 164–72. http://dx.doi.org/10.2118/72095-pa.

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Summary This paper presents a discussion of the issues related to the interaction between rock deformation and multiphase fluid flow behavior in hydrocarbon reservoirs. Pore-pressure and temperature changes resulting from production and fluid injection can induce rock deformations, which should be accounted for in reservoir modeling. Deformation can affect the permeability and pore compressibility of the reservoir rock. In turn, the pore pressures will vary owing to changes in the pore volume. This paper presents the formulation of Biot's equations for multiphase fluid flow in deformable porous media. Based on this formulation, it is argued that rock deformation and multiphase fluid flow are fully coupled processes that should be accounted for simultaneously, and can only be decoupled for predefined simple loading conditions. In general, it is shown that reservoir simulators neglect or simplify important geomechanical aspects that can impact reservoir productivity. This is attributed to the fact that the only rock mechanical parameter involved in reservoir simulations is pore compressibility. This parameter is shown to be insufficient in representing aspects of rock behavior such as stress-path dependency and dilatancy, which require a full tensorial constitutive relation. Furthermore, the pore-pressure changes caused by the applied loads from nonpay rock and the influence of nonpay rock on reservoir deformability cannot be accounted for simply by adjusting the pore compressibility. Introduction In the last two decades, there has been a strong emphasis on the importance of geomechanics in several petroleum engineering activities such as drilling, borehole stability, hydraulic fracturing, and production-induced compaction and subsidence. In these areas, in-situ stresses and rock deformations, in addition to fluid-flow behavior, are key parameters. The interaction between geomechanics and multiphase fluid flow is widely recognized in hydraulic fracturing. For instance, Advani et al.1 and Settari et al.2 have shown the importance of fracture-induced in-situ stress changes and deformations on reservoir behavior and how hydraulic fracturing can be coupled with reservoir simulators. However, in other applications, geomechanics, if not entirely neglected, is still treated as a separate aspect from multiphase fluid flow. By treating the two fields as separate issues, the tendency for each field is to simplify and make approximate assumptions for the other field. This is expected because of the complexity of treating geomechanics and multiphase fluid flow as coupled processes. Recently, there has been a growing interest in the importance of geomechanics in reservoir simulation, particularly in the case of heavy oil or bituminous sand reservoirs,3,4 water injection in fractured and heterogeneous reservoirs,5–7 and compacting and subsiding fields.8,9 Several approaches have been proposed to implement geomechanical effects into reservoir simulation. The approaches differ on the elements of geomechanics that should be implemented and the degree to which these elements are coupled to multiphase fluid flow. The objective of this paper is to illustrate the importance of geomechanics on multiphase flow behavior in hydrocarbon reservoirs. An extension of Biot's theory10 for 3D consolidation in porous media to multiphase fluids, which was proposed by Lewis and Sukirman,11 will be reviewed and used to clarify the issues involved in coupling fluid flow and rock deformation in reservoir simulators. It will be shown that for reservoirs with relatively deformable rock, fluid flow and reservoir deformation are fully coupled processes, and that such coupled behaviors cannot be represented sufficiently by a pore-compressibility parameter alone, as is done in reservoir simulators. The finite-element implementation of the fully coupled equations and the application of the finite-element models to an example problem are presented to illustrate the importance of coupling rock deformation and fluid flow. Multiphase Fluid Flow in Deformable Porous Media Fig. 1 illustrates the main parameters involved in the flow of multiphase fluids in deformable porous media and how these parameters ideally interact. The main quantities required to predict fluid movement and productivity in a reservoir are the fluid pressures (and temperatures, in case of nonisothermal problems). Fluid pressures also partly carry the loads, which are transmitted by the surrounding rock (particularly the overburden) to the reservoir. A change in fluid pressure will change the effective stresses following Terzaghi's12 effective stress principle and cause the reservoir rock to deform (additional deformations are induced by temperature changes in nonisothermal problems). These interactions suggest two types of fluid flow and rock deformation coupling:Stress-permeability coupling, where the changes in pore structure caused by rock deformation affect permeability and fluid flow.Deformation-fluid pressure coupling, where the rock deformation affects fluid pressure and vice versa. The nature of these couplings, specifically the second type, are discussed in detail in the next section. Stress-Permeability Coupling This type of coupling is one where stress changes modify the pore structure and the permeability of the reservoir rock. A common approach is to assume that the permeability is dependent on porosity, as in the Carman-Kozeny relation commonly used in basin simulators. Because porosity is dependent on effective stresses, permeability is effectively stress-dependent. Another important effect, in addition to the change in the magnitude of permeability, is on the change in directionality of fluid flow. This is the case for rocks with anisotropic permeabilities, where the full permeability tensor can be modified by the deformation of the rock. Examples of stress-dependent reservoir modeling are given by Koutsabeloulis et al.6 and Gutierrez and Makurat.7 In both examples, the main aim of the coupling is to account for the effects of in-situ stress changes on fractured reservoir rock permeability, which in turn affect the fluid pressures and the stress field. The motivation for the model comes from the field studies done by Heffer et al.5 showing that there is a strong correlation between the orientation of the principal in-situ stresses with the directionality of flow in fractured reservoirs during water injection. There is also growing evidence that the earth's crust is generally in a metastable state, where most faults and fractures are critically stressed and are on the verge of further slip.13 This situation will broaden the range of cases with strong potential for coupling of fluid flow and deformation.
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Ivanova, Tanyana Nikolaevna, Aleksandr Ivanovich Korshunov, and Vladimir Pavlovich Koretckiy. "Dual Completion Petroleum Production Engineering for Several Oil Formations." Management Systems in Production Engineering 26, no. 4 (December 1, 2018): 217–21. http://dx.doi.org/10.1515/mspe-2018-0035.

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Abstract Cost-efficient, enabling technologies for keeping and increasing the reservoir recovery rate of oil-formations with high water cut of produced fluids and exhausted resource are really essential. One of the easiest but short-term ways to increase oil production and incomes at development of oil deposits is cost of development and capital cost reduction. Therefore, optimal choice and proper feasibility study on the facilities for multilayer oil fields development, especially at the late stage of reservoir working, is a crucial issue for now-day oil industry. Currently, the main oil pools do not reach the design point of coefficient of oil recovery. The basic feature of the late stage of reservoir working is the progressing man-made impact on productive reservoir because of water injection increasing for maintaining reservoir pressure. Hence cost-efficient, enabling technologies for keeping and increasing the reservoir recovery rate of oil-formations with high water cut of produced fluids and exhausted resource are really essential. To address the above concerns the dual completion petroleum production engineering was proposed. The intensity of dual completion of formation with of different permeability is determined by rational choice of each of them. The neglect of this principle results a disproportionately rate of highly permeable formations development for the time. In effect the permeability of the formations or their flow rate is decreasing. The problem is aggravated by lack of awareness of mechanics of layers' mutual interference in producers and injectors. Dual completion experience in Russian has shown, that success and efficiency of the technology in many respects depend on engineering support. One of the sufficient criteria for the choice of operational objects should be maximal involvement of oil-saturated layers by oil displacement from seams over the economic life of well producing oil. If it is about getting high rate of oil recovery for irregular formations there is no alternative to dual completion and production. The recommended dual completion petroleum production technology enables development several formations by single well at the time. The dual completion petroleum production technology has been more important than ever because it is right not only for formations but for thin layers with undeveloped remaining reserves.
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Ladopoulos, E. G. "Non-linear singular integral representation for petroleum reservoir engineering." Acta Mechanica 220, no. 1-4 (April 1, 2011): 247–55. http://dx.doi.org/10.1007/s00707-011-0476-0.

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Dissertations / Theses on the topic "Petroleum and reservoir engineering"

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Silveira, Mastella Laura. "Semantic exploitation of engineering models : application to petroleum reservoir models." Centre de géosciences (Fontainebleau, Seine et Marne), 2010. https://pastel.hal.science/pastel-00005770.

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Ce travail propose des solutions innovantes en vue de l'exploitation des modèles d'ingénierie hétérogènes. Il prend pour exemple le domaine de la prospection pétrolière. Les stratégies de prospection sont élaborées à partir de représentations tridimensionnelles du sous-sol appelées modèles géologiques. Ceux-ci reposent sur un grand nombre de données hétérogènes générées au fur et à mesure de la conduite de l'exploration par des activités telles que la prospection séismique, les forages, l'interprétation des logs de puits. A fin d'optimisation, les utilisateurs finaux souhaitent, pouvoir retrouver et réutiliser à tout moment les données et les interprétations attachés aux différents modèles successivement générés. Les approches d' intégration des connaissances susceptibles d'être mises en œuvre pour résoudre ce défi, doivent être dissociées aussi bien des sources et des formats de données que des outils logiciels en constante évolution. Pour cela, nous proposons d'utiliser l'annotation sémantique, technique courante du Web sémantique permettant d'associer la connaissance à des ressources au moyen d' "étiquettes sémantiques". La sémantique ainsi explicitée est définie par un certain nombre d' ontologies de domaine, qui, selon la définition classique, correspondent à autant "de spécifications formelles de la conceptualisation" des domaines considérés. En vue d'intégrer les modèles d'ingénierie considérés, nous proposons une architecture, qui permet de relier des concepts appartenant respectivement à des ontologies locales et à une ontologie globale. Les utilisateurs peuvent ainsi avoir une vision globale, intégrée et partagée de chacun des domaines impliqués dans chaîne de modélisation géologique. Un prototype a été développé qui concerne la première étape de la chaîne de modélisation (interprétation séismique). Les expérimentations réalisées prouvent que, grâce à l'approche proposée, les experts peuvent, en utilisant le vocabulaire de leur domaine d'expertise, formuler des questions et obtenir des réponses appropriées
This work intends to propose innovative solutions for the exploitation of heterogeneous models in engineering domains. It pays a special attention to a case study related to one specific engineering domain: petroleum exploration. Experts deal with many petroleum exploration issues by building and exploiting three-dimensional representations of underground (called earth models). These models rest on a large amount of heterogeneous data generated every day by several different exploration activities such as seismic surveys, well drilling, well log interpretation and many others. Considering this, end-users wish to be able to retrieve and re-use at any moment information related to data and interpretations in the various fields of expertise considered along the earth modeling chain. Integration approaches for engineering domains needs to be dissociated from data sources, formats and software tools that are constantly evolving. Our solution is based on semantic annotation, a current Web Semantic technique for adding knowledge to resources by means of semantic tags. The "semantics" attached by means of some annotation is defined by ontologies, corresponding to "formal specifications of some domain conceptualization". In order to complete engineering model exploitation, it is necessary to provide model integration. Correspondence between models in the ontology level is made possible thanks to semantic annotation. An architecture, which maps concepts from local ontologies to some global ontology, then ensures that users can have an integrated and shared global view of each specific domain involved in the engineering process. A prototype was implemented considering the seismic interpretation activity, which corresponds to the first step of the earth modeling workflow. The performed experiments show that, thanks to our solution, experts can formulate queries and retrieve relevant answers using their knowledge-level vocabulary
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Johnson, Andrew Charles. "Constructing a Niobrara Reservoir Model Using Outcrop and Downhole Data." Thesis, Colorado School of Mines, 2018. http://pqdtopen.proquest.com/#viewpdf?dispub=10843100.

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The objective of this study is threefold: 1) Build a dual-porosity, geological reservoir model of Niobrara formation in the Wishbone Section of the DJ Basin. 2) Use the geologic static model to construct a compositional model to assess performance of Well 1N in the Wishbone Section. 3) Compare the modeling results of this study with the result from an eleven-well modeling study (Ning, 2017) of the same formation which included the same well. The geologic model is based on discrete fracture network (DFN) model (Grechishnikova 2017) from an outcrop study of Niobrara formation.

This study is part of a broader program sponsored by Anadarko and conducted by the Reservoir Characterization Project (RCP) at Colorado School of Mines. The study area is the Wishbone Section (one square mile area), which has eleven horizontal producing wells with initial production dating back to September 2013. The project also includes a nine-component time-lapse seismic. The Wishbone section is a low-permeability faulted reservoir containing liquid-rich light hydrocarbons in the Niobrara chalk and Codell sandstone.

The geologic framework was built by Grechishnikova (2017) using seismic, microseismic, petrophysical suite, core and outcrop. I used Grechishnikova’s geologic framework and available petrophysical and core data to construct a 3D reservoir model. The 3D geologic model was used in the hydraulic fracture modeling software, GOHFER, to create a hydraulic fracture interpretation for the reservoir simulator and compared to the interpretation built by Alfataierge (2017). The reservoir numerical simulator incorporated PVT from a well within the section to create the compositional dual-porosity model in CMG with seven lumped components instead of the thirty-two individual components. History matching was completed for the numerical simulation, and rate transient analysis between field and actual production are compared; the results were similar. The history matching parameters are further compared to the input parameters, and Ning’s (2017) history matching parameters.

The study evaluated how fracture porosity and rock compaction impacts production. The fracture porosity is a major contributor to well production and the gas oil ratio. The fracture porosity is a major sink for gathering the matrix flow contribution. The compaction numerical simulations show oil production increases with compaction because of the increased compaction drive. As rock compaction increases, permeability and porosity decreases. How the numerical model software, CMG, builds the hydraulic fracture, artificially increases the original oil-in-place and decreases the recovery factor. Furthermore, grid structure impacts run-time and accuracy to the model. Finally, outcrop adds value to the subsurface model with careful qualitative sedimentology and structural extrapolations to the subsurface by providing understanding between the wellbore and seismic data scales.

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Dada, Olamide. "Reservoir Characterization of the Spraberry Formation, Borden County, West Texas." Thesis, University of Louisiana at Lafayette, 2014. http://pqdtopen.proquest.com/#viewpdf?dispub=1557545.

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The Spraberry Formation is a Leonardian age submarine fan deposit restricted to the Midland Basin. The formation consists of very fine-grained sandstone, medium to coarse grain size siltstones, organic shales and carbonate mudstones. These rocks show variability in sedimentary structures and bedding types varied from thinly laminated to convolute laminations. Bioturbations were present in some samples and soft sediment deformation, such as water escape features, sediment loading and flame structures.

The Spraberry Formation is a naturally fractured reservoir with low porosity and low matrix permeability. Porosity measured varied from 2% in rocks with poor reservoir quality such as the argillaceous siltstone and mudstone while good reservoir rocks had an average porosity of 9%. Seven lithofacies were identified based on sedimentary structures, grain size and rock fabrics. Petrographic analysis showed four porosity types: (1) intragraular porosity; (2) dissolution porosity; (3) fracture porosity and (4) intergranular porosity. Fractured porosity was only observed in the argillaceous siltstone lithofacies.

The prominent diagenetic influences on the Spraberry Formation are: quartz cementation, quartz overgrowth, illtization of smectite, feldspar dissolution, clay precipitation, carbonate cementation, formation of framboidal pyrite and fracture formation. These diagenetic features were observed using scanning electron microscope (SEM) and in thin sections. Generally, petrophysical properties, such as porosity and permeability, vary gradually from reservoir rocks to non-reservoir rock. Observed trends where: 1) increasing organic and argillaceous content with decreasing porosity and 2) increasing carbonate sediments and calcite cements with decreasing porosity. Mineralogical analysis from FTIR showed an abundance of quartz and calcite, while illite is the prominent clay mineral observed in all samples.

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Alaiyegbami, Ayodele O. "Porescale Investigation of Gas Shales Reservoir Description by Comparing the Barnett, Mancos, and Marcellus Formation." Thesis, University of Louisiana at Lafayette, 2014. http://pqdtopen.proquest.com/#viewpdf?dispub=1557534.

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This thesis describes the advantages of investigating gas shales reservoir description on a nanoscale by using petrographic analysis and core plug petrophysics to characterize the Barnett, Marcellus and Mancos shale plays. The results from this analysis now indicate their effects on the reservoir quality. Helium porosity measurements at confining pressure were carried out on core plugs from this shale plays. SEM (Scanning Electron Microscopy) imaging was done on freshly fractured gold-coated surfaces to indicate pore structure and grain sizes. Electron Dispersive X-ray Spectroscopy was done on freshly fractured carbon-coated surfaces to tell the mineralogy. Extra-thin sections were made to view pore spaces, natural fractures and grain distribution.

The results of this study show that confining pressure helium porosity values to be 9.6%, 5.3% and 1.7% in decreasing order for the samples from the Barnett, Mancos and Marcellus shale respectively. EDS X-ray spectroscopy indicates that the Barnett and Mancos have a high concentration of quartz (silica-content); while the Mancos and Marcellus contain calcite. Thin section analysis reveals obvious fractures in the Barnett, while Mancos and Marcellus have micro-fractures.

Based on porosity, petrographic analysis and mineralogy measurements on the all the samples, the Barnett shale seem to exhibit the best reservoir quality.

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Selle, Olav. "An Experimental Study of Viscous Surfactant Flooding for Enhanced Oil Recovery." Thesis, Norwegian University of Science and Technology, Department of Petroleum Engineering and Applied Geophysics, 2006. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-757.

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This Master Thesis work aims to find a model system combining the positive effects of surfactant and polymer flooding to enhance oil recovery. This report presents the results of 12 core floors performed to enhance recovery of waterflood residual oil. The recovery is enhanced by a visous surfactant flood consistent of one polymer to increase the viscosity, one surfactant for interfacial tension reduction, and one di-alcohol to function as co-surfactant and for salinity control.

The chemical treatment that gave the best result, gave an additional oil production normalized on OOIP of 20%, improving the oil recovery from 45 to 66% mostly by the means of mobility control. Pure viscosity floods gave an additional recovery of 12 to 13% of OOIP.

Novel technology is used to investigate environmental friendly enhanced oil recovery. A biopolymer made out of microfibrils from wooden material was for the first time ever to my knowledge, attempted used in a core flood to enhance oil recovery.

A viscous surfactant tertiary recovery process may help improve oil recoveries from many marginal oil fields or those that face shut-down due to uneconomic operating costs, but still contain significant amounts of oil.

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Guo, Yifei Guo. "Evaluation of Appalachian Basin Waterfloods Utilizing Reservoir Simulation Software CMG-IMEX." Marietta College Honors Theses / OhioLINK, 2018. http://rave.ohiolink.edu/etdc/view?acc_num=marhonors1524952375868231.

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Jin, Min. "The numerical modelling of coupled rock mechanics/fluid-flow and its application in petroleum engineering." Thesis, Heriot-Watt University, 1999. http://hdl.handle.net/10399/1258.

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Li, Bowei. "Implementation of full permeability tensor representation in a dual porosity reservoir simulator." Access restricted to users with UT Austin EID Full text (PDF) from UMI/Dissertation Abstracts International, 2001. http://wwwlib.umi.com/cr/utexas/fullcit?p3034930.

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Van, Ruth Peter John. "Overpressure in the Cooper and Carnarvon Basins, Australia /." Title page, abstract and table of contents only, 2003. http://web4.library.adelaide.edu.au/theses/09PH/09phv275.pdf.

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Aljuhani, Salem Gulaiyel. "Data integration for reservoir characterization : a central Arabian oil field /." Digital version accessible at:, 1999. http://wwwlib.umi.com/cr/utexas/main.

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Books on the topic "Petroleum and reservoir engineering"

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Principles of petroleum reservoir engineering. Berlin: Springer-Verlag, 1994.

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Petroleum reservoir engineering practice. Upper Saddle River, NJ: Prentice Hall, 2011.

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Ezekwe, Nnaemeka. Petroleum reservoir engineering practice. Upper Saddle River, NJ: Prentice Hall, 2011.

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1917-, Hawkins Murray F., and Terry Ronald E, eds. Applied petroleum reservoir engineering. 2nd ed. Englewood Cliffs, N.J: Prentice Hall, 1991.

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Chierici, Gian Luigi. Principles of Petroleum Reservoir Engineering. Berlin, Heidelberg: Springer Berlin Heidelberg, 1994. http://dx.doi.org/10.1007/978-3-662-02964-0.

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Chierici, Gian Luigi. Principles of Petroleum Reservoir Engineering. Berlin, Heidelberg: Springer Berlin Heidelberg, 1995. http://dx.doi.org/10.1007/978-3-642-78243-5.

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Reservoir engineering handbook. 3rd ed. Burlington, MA: Elsevier/Gulf Professional, 2006.

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Koederitz, Leonard. Introduction to petroleum reservoir analysis. Houston, Tex: Gulf Pub. Co., 1989.

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A, Beier Richard, ed. Fractals in reservoir engineering. Singapore: World Scientific, 1994.

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Islam, M. Rafiqul, and Rafiqul Islam. Advanced petroleum reservoir simulation. Hoboken, N.J: Wiley, 2010.

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Book chapters on the topic "Petroleum and reservoir engineering"

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Archer, J. S., and C. G. Wall. "Reservoir Performance Analysis." In Petroleum Engineering, 157–72. Dordrecht: Springer Netherlands, 1986. http://dx.doi.org/10.1007/978-94-010-9601-0_10.

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Archer, J. S., and C. G. Wall. "Properties of Reservoir Fluids." In Petroleum Engineering, 40–61. Dordrecht: Springer Netherlands, 1986. http://dx.doi.org/10.1007/978-94-010-9601-0_4.

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Archer, J. S., and C. G. Wall. "Characteristics of Reservoir Rocks." In Petroleum Engineering, 62–91. Dordrecht: Springer Netherlands, 1986. http://dx.doi.org/10.1007/978-94-010-9601-0_5.

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Taghavinejad, Amin, Mehdi Ostadhassan, and Reza Daneshfar. "Unconventional Reservoir Engineering." In SpringerBriefs in Petroleum Geoscience & Engineering, 11–34. Cham: Springer International Publishing, 2021. http://dx.doi.org/10.1007/978-3-030-82837-0_2.

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Chierici, Gian Luigi. "Reservoir Fluids." In Principles of Petroleum Reservoir Engineering, 17–46. Berlin, Heidelberg: Springer Berlin Heidelberg, 1994. http://dx.doi.org/10.1007/978-3-662-02964-0_2.

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Chierici, Gian Luigi. "Reservoir Rocks." In Principles of Petroleum Reservoir Engineering, 47–116. Berlin, Heidelberg: Springer Berlin Heidelberg, 1994. http://dx.doi.org/10.1007/978-3-662-02964-0_3.

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Archer, J. S., and C. G. Wall. "Concepts in Reservoir Modelling and Application to Development Planning." In Petroleum Engineering, 233–56. Dordrecht: Springer Netherlands, 1986. http://dx.doi.org/10.1007/978-94-010-9601-0_14.

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Chierici, Gian Luigi. "Hydrocarbon Reservoirs." In Principles of Petroleum Reservoir Engineering, 1–16. Berlin, Heidelberg: Springer Berlin Heidelberg, 1994. http://dx.doi.org/10.1007/978-3-662-02964-0_1.

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Archer, J. S., and C. G. Wall. "Reservoirs." In Petroleum Engineering, 7–19. Dordrecht: Springer Netherlands, 1986. http://dx.doi.org/10.1007/978-94-010-9601-0_2.

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Tavakoli, Vahid. "Reservoir Heterogeneity: An Introduction." In SpringerBriefs in Petroleum Geoscience & Engineering, 1–16. Cham: Springer International Publishing, 2019. http://dx.doi.org/10.1007/978-3-030-34773-4_1.

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Conference papers on the topic "Petroleum and reservoir engineering"

1

Blanc, G., and D. Patey. "Using Microcomputers as Reservoir Engineering Workstations." In Petroleum Computer Conference. Society of Petroleum Engineers, 1988. http://dx.doi.org/10.2118/17773-ms.

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Guevara-Jordan, J. M., A. K. Fermin, and R. J. Gonzalez. "A New Approach for Modeling Horizontal Well Singularities in Petroleum Engineering." In SPE Reservoir Simulation Symposium. Society of Petroleum Engineers, 1999. http://dx.doi.org/10.2118/51924-ms.

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Macias, L. C., and H. J. Ramey. "Multiphase, Multicomponent Compressibility in Petroleum Reservoir Engineering." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 1986. http://dx.doi.org/10.2118/15538-ms.

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Evdokimov, Igor N., Nikolaj Yu Eliseev, Aleksandr P. Losev, and Mikhail A. Novikov. "Emerging Petroleum-Oriented Nanotechnologies for Reservoir Engineering." In SPE Russian Oil and Gas Technical Conference and Exhibition. Society of Petroleum Engineers, 2006. http://dx.doi.org/10.2118/102060-ms.

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Boone, D. M., and T. A. Terril. "Reservoir and Production Engineering Application Programs." In Petroleum Industry Application of Microcomputers. Society of Petroleum Engineers, 1986. http://dx.doi.org/10.2118/15302-ms.

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Ehlig-Economides, Christine A. "Engineering Applications for Integrated Reservoir Characterization." In International Meeting on Petroleum Engineering. Society of Petroleum Engineers, 1995. http://dx.doi.org/10.2118/29994-ms.

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Settari, A., D. A. Walters, and G. A. Behie. "Reservoir Geomechanics: New Approach To Reservoir Engineering Analysis." In Technical Meeting / Petroleum Conference of The South Saskatchewan Section. Petroleum Society of Canada, 1999. http://dx.doi.org/10.2118/99-116.

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Blanc, Georges, Abel Givaudan, J.-P. Betoin, Didier Van Den Zande, and Eric Vives. "Hypertext-Based GUI for Reservoir Engineering Software." In European Petroleum Computer Conference. Society of Petroleum Engineers, 1992. http://dx.doi.org/10.2118/24283-ms.

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Thomas, G. W. "The Role of Reservoir Simulation in Optimal Reservoir Management." In International Meeting on Petroleum Engineering. Society of Petroleum Engineers, 1986. http://dx.doi.org/10.2118/14129-ms.

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Evdokimov, Igor N., Nikolaj Yu Eliseev, Aleksandr P. Losev, and Mikhail A. Novikov. "Emerging Petroleum-Oriented Nanotechnologies for Reservoir Engineering (Russian)." In SPE Russian Oil and Gas Technical Conference and Exhibition. Society of Petroleum Engineers, 2006. http://dx.doi.org/10.2118/102060-ru.

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Reports on the topic "Petroleum and reservoir engineering"

1

Sarg, J. The Bakken - An Unconventional Petroleum and Reservoir System. Office of Scientific and Technical Information (OSTI), December 2011. http://dx.doi.org/10.2172/1084030.

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Senum, G. I. Application of multitracer technology to petroleum reservoir studies. Office of Scientific and Technical Information (OSTI), April 1992. http://dx.doi.org/10.2172/5252116.

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Zyvoloski, G., L. Auer, and J. Dendy. High performance computing for domestic petroleum reservoir simulation. Office of Scientific and Technical Information (OSTI), June 1996. http://dx.doi.org/10.2172/237335.

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Sarg, Frederick. The Bakken-An Unconventional Petroleum and Reservoir System. Office of Scientific and Technical Information (OSTI), March 2012. http://dx.doi.org/10.2172/1050229.

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Rucinski, R. Solenoid Helium Reservoir Pressure Vessel Engineering Note. Office of Scientific and Technical Information (OSTI), April 1999. http://dx.doi.org/10.2172/1032095.

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Shook, G. M. An integrated approach to reservoir engineering at Pleasant Bayou Geopressured-Geothermal reservoir. Office of Scientific and Technical Information (OSTI), December 1992. http://dx.doi.org/10.2172/10146151.

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Calhoun, Jr, J. A research agenda for academic petroleum engineering programs. Office of Scientific and Technical Information (OSTI), March 1990. http://dx.doi.org/10.2172/7169330.

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Gu, Xiaozhong. A finite element simulation system in reservoir engineering. Office of Scientific and Technical Information (OSTI), March 1996. http://dx.doi.org/10.2172/572706.

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Senum, G. I. Application of multitracer technology to petroleum reservoir studies. [Perfluorocarbon tracer technology]. Office of Scientific and Technical Information (OSTI), September 1992. http://dx.doi.org/10.2172/7117982.

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Hanks, Catherine. Producing Light Oil from a Frozen Reservoir: Reservoir and Fluid Characterization of Umiat Field, National Petroleum Reserve, Alaska. Office of Scientific and Technical Information (OSTI), December 2012. http://dx.doi.org/10.2172/1080462.

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