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IOR 2005 - 13th European Symposium on Improved Oil Recovery
- Conference date: 25 Apr 2005 - 27 Apr 2005
- Location: Budapest, Hungary
- Published: 25 April 2005
21 - 40 of 80 results
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Scales, Scaling and Scale-Up
By L.W. LakeC25 SCALES SCALING AND SCALE-UP 1 Much engineering practice involves the manipulation and understanding of scales. The existence of scales seem to intrinsically evident from observations. But it is also evident that scales has a highly elastic meaning that is at the least a barrier for communication among disciplines and at the most is a source of error. This presentation reviews the idea behind scales and what they mean to petrophysical properties. There are 4 central ideas all related. The first idea the motivation for the remainder of the presentation is that all petrophysical properties seem to depend on scale
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Displacement of High-Viscosity Oil Using Microorganisms
Authors L.I. Svarovskaya, L.K. Altunina and V.S. OvsyannikovaC26 DISPLACEMENT OF HIGH-VISCOSITY OIL USING MICROORGANISMS Abstract 1 A complex method for enhanced oil recovery has been developed at the Institute of Petroleum Chemistry. This is a combination of physical chemical and microbiological techniques aimed at enhancing the efficiency of oil displacement from high-viscosity oil reservoirs employing multicomponent oil displacement systems with high detergent properties. The oil displacement systems used comprise hydrolyzed carbamide solution that is readily assimilated by microorganisms which enhances the geochemical processes involved in the microbial activity and brings about metabolism product accumulation and hence an improvement in the rheological properties of the oil. In view
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Interpretation of Microbial Oil Recovery from Laboratory Experiments
Authors E. Kowalewski, I. Rueslåtten, E. Gilje, E. Sunde, G. Bødtker, B.L.P. Lillebø, T. Torsvik, J.Å. Stensen, B. Bjørkvik and K.A. StrandC27 INTERPRETATION OF MICROBIAL OIL RECOVERY FROM LABORATORY EXPERIMENTS Abstract 1 Microbial Improved Oil Recovery (MIOR) involves stimulation of oil-degrading bacteria in order to mobilize previously trapped and bypassed oil. This paper presents a bacteria stimulated aerobic core experiment together with microbiological analyses and measurements of the impact aerobic bacteria may have on the interfacial tension (IFT). In addition the potential for improved recovery when including the measured IFT reduction is investigated by simulating a surfactant flood on a field scale model. The effect of microbial activity on relative permeabilities residual oil saturation IFT wetting properties etc. is important in
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Laboratory Study of 'Super' Surfactants as Candidates in Surfactant Flooding
Authors I. Lakatos, J. Tóth, Z. Bedö, J. Lakatos-Szabó, M. Hlatki, S. Puskás, P.D. Berger and C. LeeC28 Laboratory Study of “Super” Surfactants as Candidates in Surfactant Flooding Abstract 1 Extensive application of IOR/EOR methods represent a focus in rejuvenation strategy of matured oil fields operated by the Hungary Oil and Gas Plc. Among others the SAP and SA+P methods as mainstays may significantly contribute to improvement of both the sweep and displacement efficiency. Therefore the fundamental point of the laboratory experiments was the screening of newly developed “super” surfactants. The detailed study comprised the determination of surface and interfacial tension CMC bulk and interfacial rheological properties transmission and backscattering photon correlation analysis of micelle properties and
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Thermal Method of Gas Hydrate Fields Development
Authors K.S. Basniev, A.V. Nifantov and A.V. ShchebetovC30 THERMAL METHOD OF GAS HYDRATE FIELDS DEVELOPMENT Abstract 1 Gas hydrates are naturally occurring solid compounds of water and gas that are considered as alternative for conventional energy in the near future. In accordance with the latest estimations potential reserves of gas in hydrates in the world exceed conventional ones in many times. Taking into account instability of oil prices gas hydrates could play a great role in world’s energy balance. Gas hydrate field development technology of using the deep subterranean thermal water heat of underlying bed has been proposed. The 3D mathematical decomposition model has been developed. It
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Effects to be Considered When Planning Late Stage Depressurisation
Authors A. Skauge, D. Standnes and Ø. PettersenC31 EFFECTS TO BE CONSIDERED WHEN PLANNING LATE STAGE DEPRESSURISATION 1 DAG STANDNES ARNE SKAUGE AND ØYSTEIN PETTERSEN Centre for Integrated Petroleum Research University of Bergen Bergen Norway Abstract The main effects of depressurisation influencing oil recovery is changes in; fluid properties fluid saturation phase mobilities and rock properties. This paper includes a mechanistic simulation study including effects involved in depressurisation. The emphasis of this paper is special effects related to rock compaction which may occur during depressurization (DP) in mature oil fields. Empirical data indicate that reservoirs containing high-permeability channels (kc) in a background (kb) of more low-permeability soil
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Downhole Gasification for Improved Oil Recovery
Authors M. Greaves, T.X. Xia, R.R. Rathbone and A.H. BentaherIOR-C32 DOWNHOLE GASIFICATION FOR IMPROVED OIL RECOVERY AUTHOR(S) Abstract 1 M. GREAVES T. X. XIA R. R. RATHBONE AND A. H. BENTAHER Address Improved Oil Recovery Group Department of Chemical Engineering University of Bath Bath BA2 7AY England A new unique IOR concept has been investigated for application in light oil reservoirs that have been previously water flooded but which can be applied at any stage of oil production. The method operates via GSGI (gravity stabilized gas injection) but does not require the injection of displacement gas from the surface. Instead gas is generated in situ using a downhole (underground)
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Waterflooding of Fractured Carbonate Reservoirs
Authors T. Austad, S. Strand, E.J. Hønesen and P. ZhangD01 WATERFLOODING OF FRACTURED CARBONATE RESERVOIRS Abstract The wetting nature of a carbonate reservoir determines the potential of improved oil recovery by water injection especially if the formation is highly fractured which often is the case for chalk formations. The exceptional good response of seawater injection into the Ekofisk chalk formation is an indication of a special rock-water interaction which improves the spontaneous displacement of oil. In the present paper we will summarize the results from ongoing research to improve spontaneous imbibition of water into oil-containing chalk samples at various wetting states and temperatures. The chemical composition of the imbibing
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Qualitative and Quantitative Study of Asphaltenes Precipitation During a Gas Injection Project
Authors S. Sfakiotakis, N. Pasadakis, N. Varotsis and H.P. HjermstadD02 QUALITATIVE AND QUANTITATIVE STUDY OF ASPHALTENES PRECIPITATION DURING A GAS INJECTION PROJECT Abstract 1 Laboratory and field data from the Snorre reservoir oil in the North Sea confirm that asphaltenes due to the fact that they precipitate when the oil in which they are contained is subjected to considerable compositional changes can be used as a natural tracer for monitoring the success of a gas miscible flooding during IOR projects. The field data reveal that the change of GOR in producing wells affects the asphaltenes content of the producing oil only in the cases where injection gas has gone
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Waterflood Efficiency for Different Pore Classes in Carbonate Reservoirs
Authors A. Skauge, K. Spildo, A. Lønøy, G. Njøten and B. OttesenD03 WATERFLOOD EFFICIENCY FOR DIFFERENT PORE CLASSES IN CARBONATE RESERVOIRS 1 Abstract Carbonate reservoirs are usually very heterogeneous and contain a wide range of different pore classes. The main pore classes are primary and secondary interparticle pores mouldic pores intercrystalline pores and also chalk and chalky microporosity. In this paper we have studied limestone cores with intercrystalline macroporosity patchy intercrystalline mesoporosity and dolomite cores with mouldic micropores Single phase dispersion was measured by injecting a slug of water tracer. The dispersion characteristics can give information about the amount of dead-end pores inaccessible pore volume and hydraulic mixing due to the
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Improved Procedure for alculating Unsteady-State Relative Permeability
Authors A.S. Lackner and O. Torsaeter1 D04 Improved Procedure for Calculating Unsteady- State Relative Permeability A.S. Lackner and O. Torsæter Abstract Department of Petroleum Engineering and Applied Geophysics the Norwegian University of Science and Technology (NTNU) Norway The effects of capillary number viscosity-ratio and heterogeneity on unsteady - state calculated relative permeability were evaluated. Flow data from simulated waterflooded cores were generated in a 1D black-oil simulation model. Two different methods were used to calculate water and oil relative permeability from the output simulated flow data: First a traditional method that requires measured pressure drop versus time and cumulative volumes produced and second a method
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Contact Angle Determination Using Logs and Capillary Pressures for a Carbonate Reservoir
Authors F. Rashidi and B. Sedaee SolaD05 CONTACT ANGLE DETERMINATION USING LOGS AND CAPILLARY PRESSURES FOR A CARBONATE RESERVOIR Abstract 1 Distribution of fluids in a porous media is directly affected by rock Wettability. Therefore Know adage this parameter is necessary for optimum production. Data obtained from well log analysis is representative of real reservoir condition and therefore these data could be converted to water saturation profiles. On the other hand laboratory capillary pressures can be converted to saturation pressures. In this paper Wettability of an Iranian reservoir rock has been investigated by comparison between log and capillary pressure data. Results reviewed that this rock is
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Characterization of Sulfur in Reservoir Rocks by Rock-Eval Analysis
Authors F. Lorant, R. Antonas and J. EspitalieD06 CHARACTERIZATION OF SULFUR IN RESERVOIR ROCKS BY ROCK-EVAL ANALYSIS Abstract 1 As a result of steam or hot water injection reservoir rocks can generate significant amounts of H2S. Such recovery operations are therefore subject to corrosion and environmental risks which are currently difficult to predict. Previous works have shown that the formation of H2S is thermally induced by the alteration of organic sulfur in heavy oils (aquathermolysis). Other phenomena involving interactions between mineral sulfur (sulfates pyrite) and organic matter have been reported as sources of H2S as well. According to the current knowledge on these processes H2S can occur
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Interpretation of Displacement Data Obtained from Unsteady-State Radial Fluid Flow Systems
More LessD07 INTERPRETATION OF DISPLACEMENT DATA OBTAINED FROM UNSTEADY-STATE RADIAL FLUID FLOW SYSTEMS Abstract 1 This paper presents the practical interpretation formulae which can be used for determination of the relative permeability data obtained from immiscible fluid displacement experiments. The derived formulations are convenient to determine the relative permeability curves the Leverett functions and the displacement efficiency. The results were validated by using the laboratory data obtained by lateral immiscible fluid displacement in horizontal porous disks. For this purpose the convenient interpretation formulae elaborated and demonstrated by the authors (1998 2002) earlier for determination of relative permeability from unsteady-state twophase linear
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Experimental Evaluation of H2S Yields in Reservoir Rocks Submitted to Steam Injection
Authors V. Lamoureux-Var and F. LorantD08 EXPERIMENTAL EVALUATION OF H2S YIELDS IN RESERVOIR ROCKS SUBMITTED TO STEAM INJECTION Abstract 1 Steam injection can induce H2S generation resulting from physicochemical transformations of sulfur compounds in reservoirs at temperatures from 200°C to 300°C: reactions between organic sulfur compounds and water (aquathermolysis) organic and mineral interactions (sulfate reduction and/or pyrite oxidation). The occurrence of these processes depends on the availability of the different sources of sulfur in reservoirs: organic sulfur sulfates and pyrite. The organic and mineral sulfur contents of bulk reservoir rocks might therefore be correlated to the yield of H2S that is potentially generated within reservoirs
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Miscible Gas Injection Issues in a Thick Carbonate Volatile Oil Reservoir
Authors P.G. Denby, L. Tealdi, M. Vert and L. FranciaD09 MISCIBLE GAS INJECTION ISSUES IN A THICK CARBONATE VOLATILE OIL RESERVOIR Abstract 1 This paper discusses a number of challenges around the development by miscible gas reinjection of the Kashagan field situated in the North Caspian. The Kashagan field is a highly pressured sour carbonate oil reservoir. Due to the lack of a significant local gas market and the cost associated with treating the sour products re-injection of the associated gas is intended from early in the field development. This is not only environmentally and economically very sound but will also significantly enhance the recovery efficiency due to the
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Three-Phase Relative Permeabilities and Capillary Pressure by Upscaling
Authors A. Lohne, G.A. Virnovsky and A. HiorthD10 THREE-PHASE RELATIVE PERMEABILITIES AND CAPILLARY PRESSURE BY UPSCALING Abstract 1 Three phase flow properties are important for correct modeling and prediction of such IOR processes as WAG and blow-down/depletion after waterflooding. On the core-scale these properties can generally by obtained directly from experiments (though this is not usually done) from pore-scale modeling of threephase flow or from empiric formulae interpolating two sets of two-phase data oil-water and oil-gas which are supposed to have been measured into the three-phase saturation region like the ones proposed by Stone. For the usage in the simulator the core scale properties have to be
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Application of a New Upscaling Technique to a Miscible Gas Injection Field Study
Authors M.-H. Hui, L.J. Durlofsky and X.-H. WenD11 APPLICATION OF A NEW UPSCALING TECHNIQUE TO A MISCIBLE GAS INJECTION FIELD STUDY Abstract 1 A novel miscible upscaling technique incorporating the use of effective flux boundary conditions and an extended Todd & Longstaff treatment of upscaled relative permeabilities was recently developed and successfully applied to synthetic 2D permeability fields. In this work we extend the overall upscaling procedure to nonuniform 3D grids and apply it to a miscible gas injection field study. A near-well upscaling procedure is also incorporated into the methodology. It is shown that the original fine grid model must be refined areally to achieve numerical
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Numerical and Experimental Investigation into the Mechanisms of First Contact Miscible Simultaneous and Slug WAG Injection
Authors H. Al-Shuraiqi, A. Muggeridge and C.A. Grattoni1 D12 Numerical and Experimental Investigation into the Mechanisms of First Contact Miscible Simultaneous and Slug WAG Injection H. AL-SHURAIQI A. MUGGERIDGE and C.A. GRATTONI Department of Earth Science and Engineering Imperial College SW7 2AZ London United Kingdom Abstract Miscible Water-Alternate-Gas (WAG) injection is currently being performed in many fields around the world and a large number of numerical studies investigating both simultaneous and slug injection including the effects of slug sizes gravity and heterogeneity have been carried out in the past. However there are few laboratory studies to support the numerical work and to understand the interactions between injected
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Fluid Flow Properties of WAG Injection Processes
More LessD13 FLUID FLOW PROPERTIES OF WAG INJECTION PROCESSES Abstract 1 Immiscible water-alternating-gas (IWAG) experiments performed on equilibrated fluids are summarised together with the corresponding two-phase gas-oil and water-oil displacements. Experimental studies at reservoir condition and also mechanistic experiments over many years have shown accelerated oil production and higher core flood oil recovery as a result of three-phase flow. The three-phase effects that are included and analysed are; trapped gas and mobility for secondary processes (ex. water after gas injection). The oil recovery from the different oil recovery processes represented by; gas water and WAG core displacements are also compared. The
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