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IOR 2013 - 17th European Symposium on Improved Oil Recovery
- Conference date: 16 Apr 2013 - 18 Apr 2013
- Location: Saint Petersburg, Russia
- ISBN: 978-90-73834-45-3
- Published: 16 April 2013
21 - 40 of 73 results
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New Method of Active Electromagnetic Induction and Seismic Monitoring in Oilsaturated Media
Authors O.A. Hachay, O.Y. Khachay and A.Y. Khachayor equal observation periods changing by the method of phase diagram state of many phase medium in the oil layer is developed. The developed method allows on quality level to classify the state of the polyphase medium, which is the oil layer, using data of many cycles influence. In that paper we suggest the algorithm of modeling of 2-d seismic field distribution in the heterogeneous medium with hierarchic inclusions. Using the developed earlier 3-d method of induction electromagnetic frequency geometric monitoring we showed the opportunity of defining of physical and structural features of hierarchic oil layer structure and estimating of water saturating by crack inclusions. That allows managing the process of drainage and steeping by water displacement the oil out of the layer. Reference 1.Geosciences: Making the most of the Earth’s resources. S-Petersburg 2 - 5 April 2012 Field Development & EOR C024 Reflection of No Equilibrium Two Phase Processes of Filtration in Heterogeneous Media in the Active Seism Acoustic Borehole Monitoring Data O.A. Hachay* (Institute of Geophysics UB RAS), V.V. Dryagin (Institute of Geophysics UB RAS), G.V. Igolkina (Institute of Geophysics UB RAS) & O.Y. Khachay (Ural Federal University)
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Pore-scale to Core-scale Aspects of Capillary Desaturation Curves Using CT-scan Imaging
Authors R. Oughanem, S. Youssef, B. Bazin, E. Maire and O. VizikaSurfactant flooding is one of the effective technologies to enhance oil recovery of water flooded petroleum reservoirs. Several previous studies have demonstrated that the release of oil from a rock submitted to waterflood depends on the competition between displacing forces (viscous and buoyancy) and capillary forces. This competition is expressed by two dimensionless numbers, the Capillary number, defined as the ratio of viscous to capillary forces and the Bond number, defined as the ratio of gravity to capillary forces. At the core scale the evolution of the oil residual saturation as function of the capillary number is better known as the Capillary Desaturation Curve (CDC), which constitutes an important input parameter in EOR processes reservoir simulation. In this work we present a new experimental workflow to investigate the effect of rock structure on the CDC. This workflow combines core flood experiments and CT-scan imaging to accurately measure the mean residual oil saturation at different capillary number values as well as the local saturation distribution along the core plug. The CDC was measured on a set of water-wet sandstone with different permeability and degree of heterogeneity. The capillary number was varied by injecting a surfactant solution at different flow rates. Using this methodology, we first study the effect of core flood orientation (Horizontal injection and vertical downflow injection). The resulting local saturation curves show that in a horizontal configuration the oil migrates upwards in the sample inducing an oriented front strongly deviating from the piston like displacement, and very different from the one observed in the vertically placed sample. This behaviour is manly attributed to buoyancy forces that are no more negligible compared to capillary forces when surfactant is injected. This experiment shows that when measuring a CDC the capillary number needs to be corrected to take into account the buoyancy forces. In a second step we have investigated the effect of local heterogeneity of core plugs on the CDC with Clashach and Fontainebleau sandstones. Two samples of Clashash sandstone with equivalent mean properties were studied (mean permeability of 380 and 426 md and mean porosity of 13.4 % and 14.1% respectively). The resulting CDC curve exhibits almost two decades difference in the critical capillary number. This discrepancy is explained in terms of the local variation of the porosity that induces important differences in the local saturation profile.
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Micromechanical Analysis of Relative Permeability Hysteresis
Authors A.M. Galechyan and V.V. KadetThis paper represents the model of relative permeability hysteresis in drainage and imbibition with help of percolation theory. The following processes are considered. First of all the hydrophilic core is totally saturated by water. Oil displaces water under the pressure gradient – this process is called drainage. During this process oil firstly goes to large pores, because they have small hydrodynamic resistance and small capillary pressure. After the core is maximally saturated by oil the displacing of this oil by water begins under the pressure gradient. This process is called imbibition. During drainage oil changes the surface properties of some part of capillaries through which it passed. The cause of it is formation of thin hydrocarbon film during drainage. So one part of capillaries (ӕ) has unchanged hydrophilic surface properties, and the other part (1-ӕ) has changed surface properties, which can become both hydrophobic and hydrophilic with another angel of contact (θ1 and θ2 – angles of contact before and after oil pass through, α=cosθ1/cosθ2). Different variants of ӕ and α are considered in this paper. The cubic lattice of capillaries is taken for the basic model of porous media which has lognormal density of radius distribution function. The received results of relative permeability calculations for drainage and imbibition demonstrate the availability of hysteresis. The closest to experiment results are for ӕ=0.75 and α=-1. This shows that in proposed model after drainage oil changed surface properties from hydrophobic to hydrophilic in 25% of capillaries that is 1/3 of capillaries, trough which oil passed. Represented model is rather universal and allows taking into consideration different mechanisms of changing the surface properties of porous media. The best accordance with represented experiment is achieved by choosing the hydrophobisation of porous media during drainage as the main mechanism. Comparing with the experiment allows to find the right ӕ and α. This method can be used instead long and difficult experiments for plotting the relative permeability. It’s necessary to use the mineral structure data and the experimental density of radius distribution function in the calculating algorithm of represented model and the relative permeability will be plotted.
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Visualization of Pore-level Displacement Mechanisms During CO2 Injection and EOR Processes
Authors J. Gauteplass, H.N. Follesø, A. Graue, A.R. Kovscek and M.A. FernøMultiphase flow and fluid displacements at pore-level were visualized in two-dimensional micromodels retaining essential characteristics of porous rocks. Microvisual data during CO2 injection for enhanced oil recovery was obtained from high resolution images using UV-sensitive dye to improve contrast. The dominating mechanisms were piston-like displacement of one fluid by another, either by a stable moving interface or through Haines-like jumps. Film thickening, film drainage, snap-off mechanisms and capillary trapping of CO2 were also observed. Both stable and unstable flow regimes were identified as the front advanced through the network during two-phase flow. In the latter regime, instabilities in the displacements were manifested by capillary fingering perpendicular to the main flow direction. Oil was found to be spreading in the water-oil-gas system at the experimental conditions. This led to an efficient oil production at pore-level from CO2 gas injection, even at high water saturation. The injected gaseous CO2 contacted only oil in three-phase systems, and led to direct oil displacement, whereas water was displaced through double or multiple displacement events.
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Polymer Flooding - Designing of a Pilot Test for Unusually High Salinity and Hardness Reservoir
Reservoir conformance problems render uneven the flow of the injected water making waterflooding inefficient due to poor mobility control. This paper describes a systematic approach taken for the designing of a polymer flooding pilot test for a reservoir with challenging characteristics such as unusually high salinity and hardness that complicate the selection of the candidate polymer. This work includes a description of the characterization of a pre-selected candidate polymer, its rheological evaluation, its adsorption performance onto porous media, and its mechanical stability. Together with rheological properties, emphasis is given to the evaluation of flow performance of the polymer onto porous media at reservoir conditions. The experimental results indicate that the selected polymer (acrylamide/ATBS/acrylic acid ter-polymer) shows proper performance especially in terms of tolerance to reservoir salinity, hardness and high temperature. Numerical simulation studies demonstrate that polymer flooding at the selected zone could render a favourable incremental oil recovery (16%) over waterflooding.
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Impact of Polymer Mechanical Degradation on Shear and Extensional Viscosities
Authors D. Rousseau, I. Henaut, A. Dupas, P. Poulain, R. Tabary, J.F. Argillier and T. AubryField data from polymer flooding operations sometimes indicate a better-than-expected polymer injectivity below fracturing pressure. Current interpretations for this unexpected phenomenon are based either on geomechanical considerations (for unconsolidated sand formations) or on polymer mechanical degradation, potentially occurring in the injection facilities and the near wellbore area. In this paper, a new approach of polymer injectivity is suggested. It is based on the study of polymer mechanical degradation with respect to both shear and extensional viscosities. In the first part of this work, we have investigated the onset of mechanical degradation by submitting semi-dilute solutions of high molecular weight partially hydrolyzed polyacrylamide (HPAM) to extensional laminar flow created by an API capillary system. We have then measured both shear and extensional viscosity of the native and the degraded HPAM solutions. We consider the onset of mechanical degradation to be reached when shear viscosity loss is equal to 10%. At low degradation extensional rate, extensional viscosity decreases to the same extent as shear viscosity (10%), whereas, at high degradation extensional rates, the decrease reaches up to 60%. This means that degraded HPAM with weakly affected shear viscosity can develop much less resistance to extensional flow. In the second part, we have explored the influence of mechanical degradation on injectivity by determining resistance factors of native and degraded HPAM solutions. Solutions have been injected in reproducible unconsolidated sand packs. At low velocities, resistance factors were similar for both kind of solutions, as expected from their comparable shear viscosities. However, at high velocities, namely where flow in porous media implies high extensional deformations in the vicinities of the pore throats, rheo-thickening was much less marked for solutions degraded at high extensional rate. These results allow understanding why polymers which do not seem to be mechanically degraded according to their shear viscosity can show a very good injectivity, thanks to the reduction of extensional resistance in porous media. They could also lead to establish guidelines for designing new polymer pre-treatment methods aimed at improving injectivity while retaining the mobility control ability of polymers.
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Application of Quantitative Structure-property Relationship (QSPR) Method for Chemical EOR
Authors F. Oukhemanou, A. Maldonado, P. Moreau and B. CretonThe selection of high performance surfactants for chemical EOR is a challenging and time consuming task. A surfactant formulation, typically a blend of at least two surfactants must be developed for each case study. A tool to pre-select suitable surfactants would thus be highly valuable. In this paper, we describe the development of a quantitative structure-property relationship applied to the selection of surfactants for chemical enhanced oil recovery. A correlation is drawn between surfactant structures and optimal salinities, i.e. the salinity which corresponds to a minimum in interfacial tension. A comprehensive and coherent database has been generated using a high-throughput screening robotic platform and industrial products belonging to different families of surfactants: olefin sulfonates, alkyl ether sulfates and alkyl glyceryl ether sulfonates. This database has been built for specific reference conditions (temperature, oil, brine hardness). Industrial surfactants, most often constituted of a variety of molecules, have been carefully analyzed in order to identify predominant species. The structures of these compounds have then been drawn using molecular design tools, and molecular descriptors were generated for the whole set of amphiphiles. Finally, various statistical approaches have been used to develop multi-linear regressions correlating combinations of the most relevant molecular descriptors with the experimentally determined optimal salinity of surfactant mixtures. Our results indicate that a strong correlation exists between the surfactant structure and its optimal salinity. A limited set of descriptors can be used to predict this critical property with predictive models. These models can then be used to select promising existing products as well as to identify candidate raw materials or products for industrial surfactants development. We also demonstrate the ability of our models to predict optimal salinity of surfactant blends typically used in chemical EOR. Future developments will be focused on extrapolation of these models to the prediction of other application properties for chemical EOR (e.g. interfacial tension value) and to broaden the application domain to a wide range of conditions (temperature, brine composition, type of oil).
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Surfactant Flooding Evaluation for Enhanced Oil Recovery in Sandstones Reservoirs
Authors F.C. Bonilla and R.B.Z.L. MorenoThis research work considered surfactants for chemical oil recovery applications. Surfactant flooding is an EOR technique applied for decreasing capillary effects by molecular performance alterations on water-oil interface between injected water and displaced oil. In most situations, this method is implemented as a tertiary flood near of the end of waterflooding but it could be conducted after the initial stage of field production when oil saturations are high in the porous media. By an injector well, required volumes are introduced to the reservoir with the defined surfactant formulations for developing a new stabilized oil bank via ultralow interfacial tension between oil and water phases. The experimental methodology included Phase Behavior and Coreflooding tests for making comparative analyses between oil production responses of different configurations of surfactant flooding method. The phase behavior tests were conducted to select the best surfactant formulations through interfacial tensions and solubilization ratios determinations of different concentrations of five commercial surfactants: three anionic surfactants (Stepanol, sodium dodecyl sulfate and ammonium dodecyl sulfate) and two no-ionic surfactants (SPAN-20 and TWEN-20). Previously, it was performed surface tensions measurements to identify the critical micellar concentration (CMC), characteristic of each surfactant. The selected primary surfactant and co-surfactant formulations were tested for enhanced oil recovery using coreflood tests on high permeability sandstones from Bocatutu Formation. In these tests, the primary formulation solutions were followed by polymeric drive solutions injection. The tested formulations were also tested for porous media adsorption, evaluating surfactant losses during a surfactant flooding. The results are useful for running numerical simulation cases and single well field projects.
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Experimental Investigations into the Effect of Heterogeneities on the Recovery of Heavy Oil by VAPEX
Authors A.H. Muggeridge, M. Al-Hadhrami and A. AlkindiVapour extraction (VAPEX) of heavy oil is a low energy alternative to Steam Assisted Gravity Drainage (SAGD). Nearly miscible vapour is injected into the formation instead of steam. It dissolves in the heavy oil, reducing its viscosity. The diluted oil is then produced via gravity drainage (in the same way that heated oil drains during SAGD). Although there are many reported numerical and experimental studies into VAPEX, very few have investigated the impact of heterogeneities on this process. None have compared the predictions of simulation with experiment. We report a series of laboratory studies into the effect of layering and discontinuous shales on oil rate and recovery from VAPEX. These were performed in well characterized glass bead packs using glycerol and ethanol as analogues of oil and solvent respectively. The permeability, porosity and fluid properties (including diffusion and dispersion) were measured independently. Numerical predictions of the experiments were performed, using these data as input, to determine whether conventional reservoir simulation can capture the flow processes observed in the experiments. We found that the observed oil drainage rates from the layered packs were between the rates observed in homogeneous packs formed of the lowest permeability beads (lower bound) and the highest permeability beads (upper bound). The numerical simulations tended to underpredict oil drainage rate although they correctly predicted the pattern of solvent and oil distribution seen in the experiments. The performance of the layered system could be predicted by a homogeneous system using the arithmetic average of the layer permeabilities. A single discontinuous shale had little impact on recovery unless it was directly between the injection and production wells or its length approached that of the reservoir. These results suggest that these types of heterogeneity have little impact on VAPEX performance except through their influence on effective permeability of the reservoir.
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Secondary Polymer Flooding in Extra-heavy Oil - Core Experiments under Reservoir Conditions and Core Scale Simulation
More LessIn this work we present the results obtained from a coreflood experiment with polymer injection in secondary mode for extra heavy oil at 5500 cP viscosity. The work was carried out on a 30 cm length reconstituted core composed from cleaned reservoir sand. The core was packed using an in-house developed method, and then saturated with live oil partially degassed in PVT cell from initial reservoir conditions down to expected pressure at start of a field test (Pres). Saturation profiles were accurately measured by means of X-Ray scans on the core, enabling the visualization of flow instability development (viscous fingering). Effluents were collected in carbon cells under reservoir conditions with X-Ray production level measurements. The effluents were then flashed to atmospheric conditions, collected in test tubes and re-measured by X-Ray and UV measurements. The polymer flood carried out in secondary mode showed excellent results with a recovery of around 60% after 1.8 PV of polymer injected at 1 cc/h, even though viscosity ratio was highly unfavourable. The estimated apparent viscosity of the polymer was 60 cP at 7 s-1, corresponding to the frontal advancement rate achieved during the coreflood. This recovery is in the same order as that obtained in tertiary mode after water flood in outcrop cores ([9], [12]).
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Selection of the EOR Methods for the Russkoe High-viscosity Oil Field Based on Laboratory and Field Experiments
Authors I. Edelman, A. Shandrygin, E. Severinov, L. Gaidukov and D. DubrovskiyThe paper presents an approach and the results of laboratory tests of the EOR methods on core samples of Russkoe gas and oil field, and the results of pilot works to the implementation of the recommended method. The field is unique in terms of both its huge hydrocarbon reserves and problems associated with its development. It is located above the Polar Circle and is characterized with a complex geological structure of highly permeable poorly cemented reservoirs saturated with high-viscosity oil. Significant factors making field development difficult include presence of tectonic faults, extensive gas cap, and underlying water. At the first stage of the research the following main EOR methods have been analyzed: injection of hot water, steam injection, injection of polymer solutions and thermo-alkali flooding. Experimental studies have been conducted on natural cores and bulk models. The complexity of the preparation and conduct of experiments was attributed to work with weakly consolidated core. At the initial stage of the pilot project one of the most effective methods, which performance has been proven by both experiments and simulations, has been recommended for implementation, - the displacement of viscous oil with hot water. Test injection of hot water in one of the pilot areas commenced in August 2010 and, in general, confirms the effectiveness of oil displacement observed in laboratory experiments. The results of field tests of EOR methods in the Russkoe field by injecting hot water are described in detail in the report. In the next stage of the pilot project, which is aimed at finding appropriate technologies for the development of this extremely complicated field, the continuation of laboratory testing of the EOR methods is planned using new core samples. Along with this, further laboratory testing of WAG and surfactants applicability is envisaged. To achieve this objective, a special program of laboratory and analytical studies is planned.
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Performance of Associative Polymers in Porous Media
Authors A. Thomas, N. Gaillard, C. Favero, J. Bai, K. Green and F. WassmuthThe propagation of associative HPAM polymers in porous media is greatly dependent on the degree of hydrophobic modification. In this paper, the transport properties of several associative polymers with degree of association from none to high were investigated in Berea cores and silica sand-pack cores. The associative polymer solutions with customary bulk viscosities generated resistance factors that varied significantly, ranging from 10 to over 500. The increasing resistance factors were attributed to the higher level of polymer retention as the degree of association increased. On the other hand, two associative polymers, with a similar degree of association but different molecular weight and bulk viscosities generated similar resistance factors. Hence the effect of molecular weight and bulk viscosity is not as significant as hydrophobic modification in generating in-situ flow resistance. Linear coreflood tests were conducted to evaluate the potential of associative polymer flooding in recovering western Canadian heavy oil with viscosity of 18,700 mPa.s in 3-Darcy sandpacks. The properly selected associative polymer was able to propagate through the sandpack with no significant retention and generate in-situ apparent viscosity twice as high as the unmodified HPAM.
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EOR Technologies for Permocarbonic Deposit of High-viscosity Oil in Usinskoye Oil Field - Experience and Prospect
Authors V.A. Kuvshinov, L.K. Altunina, A.A. Alabushin and S.O. UrsegovPresented are the results of laboratory research and field tests of physicochemical technologies intended to improve oil recovery of high-viscosity oil deposits developed by steam injection. To increase the efficiency of thermal-steam and cyclic-steam stimulations we proposed to combine them with physicochemical methods using thermotropic gel-forming and oil-displacing systems: the gels increase reservoir coverage by steam injection and oil-displacing systems, which at thermal stimulation generate СО2 and alkaline buffer solution, promote decrease in oil viscosity and additional oil displacement. In 2007-2011 154 wells located on Permocarbonic deposit in Usinskoye oilfield were stimulated using IPC SB RAS IOR technologies. Daily increase in oil production rate ranged from 3 to 24 tons per well and additional oil production amounted to more than 2000 thousand tons. A complex technology of alternating injections of steam, thermotropic gel-forming and surfactant-based oil-displacing systems was shown to be promising to provide increased reservoir coverage with steam injection and oil after-washing.
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Polymer Flood Design for Displacement of Heavy Oil Analysed by 2D-imaging
Authors A. Skauge, P.A. Ormehaug, B.F. Vik, C. Fabbri, I. Bondino and G. HamonWaterflooding and polymer assisted waterflood in heavy oil reservoirs has recently gathered great attention. Enhanced water injection schemes represent an alternative in cases where thermal methods are either impractical or uneconomic. This study describes the frontal displacement and analyses the oil mobilization by use of 2D X-ray imaging. This study has investigated viscous instabilities, mechanisms for finger growth and water channeling at adverse mobility ratio during waterflood. Experiments have been made on Bentheimer sandstone slabs (30cm x 30cm x 2,5 cm) studying waterflooding and tertiary polymer injection in extra heavy oils (2000cp). The sandstone represents a relatively homogeneous and high permeability porous medium. The experiments utilize gamma and X-ray source for porosity and saturation measurements, and an X-ray imaging system to visualize displacements and thereby quantify the underlying flow mechanisms and oil recovery. The rock material was aged with crude oil to shift wettability and dampen the capillarity. The development of viscous fingers was detailed recorded by 2D X-ray imaging. This paper focuses on polymer slug design. The polymer slug will be influenced by polymer adsorption, inaccessible pore volume, dispersive mixing, and also chase water fingering into the polymer slug. The polymer slug mixing is studied using 2-D imaging by tagging each injected phase. Special focus has been on chase water mixing into the polymer slug. The oil recovery the waterflood was 39% OOIP, but more important a quick increase in oil cut was obtained by polymer injection. The oil recovery after polymer flooding reached final recoveries of more than 70% of OOIP.
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Toe-to-Heel Air Injection - Effect of Oil Layer Thickness
Authors M. Greaves, L.L. Dong and S.P. RigbyA simulation study of a full-section of the first THAI field pilot, conducted in the Athabasca Oil Sands of Alberta, Canada, has investigated the effect of different oil layer thicknesses:; namely,8, 25 and 40 metres. The physical model description was an idealised representation of the WHITESANDS Conklin field pilot, having an homogeneous oil layer and no bottom water, or interbedded shale features. For a 6-year operating period, the oil production showed an increasing trend with increasing oil layer thickness, up to 80 m3/day. However, for the 8 m thick reservoir, the oil production profile showed a continuous decline, with oxygen breakthrough occurring after 1350 days. A significant Steam Zone developed in all three cases, advancing fastest in the 8 m thick oil layer. This latter case was accompanied by an increase of gas channelling, in the direction of the production well end of the reservoir. Peak combustion temperatures were highest for the 25 m oil layer, and lowest for the 8 m thick case.
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Uncertainty Analyses for Thermal Development in Heavy Oil Fields
Authors R. Sabatino, I. Maffeis, F.M. Contento, A. Tegami and M. De SimoniThe main purpose of this work is to get an insight into thermal development strategies to be applied in an extra-heavy oil field. The goals of this study are: to study the feasibility of thermal EOR techniques; to perform a risk analysis highlighting the main uncertainties on reservoir development. Firstly, a general overview of the field is given. Steamflooding has been thoroughly investigated, by optimizing operating parameters and evaluating their effect on oil recovery and steam-oil-ratio (SOR). Similar sensitivity analyses have been performed for the down-hole electrical heating technique, focusing particularly on power input, and evaluating the propagation of heat in the reservoir. Risk analyses have been then performed in order to highlight the main uncertainties affecting the field development, in cold production as well as in steamflooding and electrical heating. Risk analysis was carried out by applying both the classic Monte Carlo workflow and the Experimental Design and Response Surface Modelling. This methodology becomes advisable when simulation runtime is excessive and a classic Monte Carlo workflow is too expensive. The last part of the paper covers basic pseudo-economic analysis to assist in the comparison between cost-benefits of steamflooding and electrical heating. The main outcomes of this work are the following: steamflooding proved to be an effective way to improve oil recovery, although for pessimistic scenarios (i.e. very high viscosity) its convenience should be properly evaluated; electrical heating can cheaply provide additional oil recovery. The performed analysis has highlighted the risk and the opportunities of the two thermal recovery techniques.
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Detrimental Effect of Capillary Forces in Extreme Low Permeable Unconventional Gas Reservoirs
Authors I.J. Lakatos, T. Bódi, J. Lakatos-Szabó and G. SzentesIn the 21st century the global gas demand will be met only by extensive production and utilization of unconventional gases. Unfortunately, these kind usually have extremely low permeability, small average pore sizes and strongly, often absolute water-wet surface character. As a result, the residual water saturation and the critical capillary pressure needed to mobilize water from natural porous systems might also be unexpectedly high. Therefore, a detailed laboratory studies have been carried out with the aim at determining the detrimental effects of pore structure, wettability, capillary and imbibition forces in reservoirs having D permeability. Using natural cores, the capillary pressure was calculated as a function of pore size distribution and wettability. Spontaneous imbibition tests were carried out to demonstrate the effect of aqueous and organic fluids. Based on experimental results, it was found that extremely high threshold pressure, sometimes several hundred bars, was needed to start water drainage from natural cores. Consequently, due to the unusual capillary forces, the water proved to be a natural blocking phase in such systems, and hence, the water may cause serious formation damaging hard to cure when the reservoirs is or were ever contacted with water. As a result, the operators definitely face with difficulties when water-based fluids are used in drilling, well completion, fracturing, and production technologies. Therefore, the physico-chemical considerations suggest that application of water-free fluids should be used in any phases of field operations. In addition, the presence of water in tight sand gas and BCGA reservoirs has detrimental effect on gas transport. Since the mass transport is usually diffusion, non-Darcy flow characterizes the gas rate, viz. the driving force of gas production should be treated with weaponry of physico-chemical approach and thermodynamic calculations. Thus, new paradigms and theoretical approach are necessary in the future, and further fundamental and applied research seems to be indispensable to develop novel technologies for gas recovery from unconventional gas reservoirs including tight sand, shale and BCGA formations.
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Comparison of Heating Methods for In-situ Oil Shale Extraction
Authors K.G. Hazra, K.J. Lee, C.E. Economides and G. MoridisOil shales are lamellar, non-porous, impermeable hydrocarbon bearing rocks that contain organic matter called kerogen which, when heated at pyrolysis temperature of approximately 650-700 oF, thermo-chemically decomposes to liberate hydrocarbons. They are at the base of the resource triangle because cutting edge technology and higher fuel prices are required to economically produce them. Technologies for oil shale production include surface and in-situ retorting. This study focusses on in-situ oil shale production methodologies. The process of heating oil shale to the pyrolysis temperature can be achieved by direct or indirect heating. Direct heating geometries include the Shell in-situ conversion process (ICP) using downhole electric heaters in vertical holes and the ExxonMobil approach using longitudinal vertical fractures created from horizontal wells and propped with electrically conductive material such as calcined coke. Indirect heating approaches propose injection and circulation of steam or a non-condensable gas like CO2. These include the Chevron concept of creating horizontal fractures in vertical wells or the Texas A&M concept using multiple vertical transverse fractures penetrated by horizontal wells. The objective of this paper is to compare energy and recovery efficiency of various in-situ retorting technologies using different heating schemes and well configurations as mentioned above. Thermo-physical parameters like thermal conductivity, specific heat capacity, porosity, permeability needed for the numerical simulation have been obtained by extensive literature survey of various oil shale deposits in Green river formation of USA. A sensitivity analysis of direct heating pattern and spacing reproduces previous work. Then the validated model is used to evaluate the size and fracture spacing sufficient to heat the oil shale in the direct and indirect heating approaches and to compare pressurized hot fluid circulation to heating elements. The use of the same wells for both heating and hydrocarbon production offer an economic edge for indirect heating approaches.
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Alkali Surfactant Gas Injection - Attractive Laboratory Results in Carbonates under Harsh Salinity and High Temperature
Authors C. Cottin, D. Morel, D. Levitt, P. Cordelier and G. Pope(Alkali) Surfactant, Polymer injection is an attractive enhanced oil recovery technique that allows achieving almost zero residual oil saturation at the microscopic scale when properly designed. In this combination of chemicals, the role of polymer is to achieve the necessary mobility control of the microemulsion / oil fronts which are formed and propagated through the reservoir. Foam has been recently identified as an alternative to polymers to achieve such a mobility control. This paper describes the (A)SG laboratory results which have been obtained on carbonate core samples under harsh salinity and temperature conditions. The starting point was the development of a surfactants formulation to achieve ultra low interfacial tensions between the oil and injected solution, using the classical test tubes approach. The efficiency (in terms of oil recovery) of this chemical formulation in this particular S and T condition was demonstrated with SP core floods. The same chemical formulation was used for (A)SG; the polymer was replaced by nitrogen co-injected with surfactant to create foam. Although SP and ASP flooding has been studied and implemented for decades, there remain few applications in carbonates, and none in the particular case of high salinity and high temperature carbonate reservoirs. Even if adequate surfactants can be tailored to these conditions, the use of polymers for mobility control in low permeability formations, particularly at high temperatures and in the presence of calcium, is a significant challenge. These results demonstrate that (A)SG is an alternative that works at laboratory scale and might be the starting point of a potential future pilot implementation . Foam quality has to be optimized in order to achieve the best recovery, but keeping also in mind that it is possible that gas sourcing and recycling will be a predominant consideration at the field scale; low quality foam may be suitable. In some situations the same surfactants can contribute to ultra low interfacial tension and have good foaming properties. - ASG results are presented in high salinity and high temperature conditions. Replacement of polymers by foam can work and is particularly attractive if lower permeability and higher temperature are targeted - For the many carbonate fields where water injection is already implemented, (A)SG EOR is a new option to consider.
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First Application in Russia of Bright Water™ Chemical for Waterflood Sweep Improvement in the Samotlor Field
Authors D.R. Thrasher, P. Denyer, A.S. Timchuk, Y.V. Zemtsov and D.V. AkininThe first pilot in Russia of Bright Water™ chemical (Thermally-Activated Particles or TAP) for improving waterflood sweep has been commenced in the Ust Vakh Satellite to the giant Samotlor Field in West Siberia in 2011. This field (the sixth largest in the world) has been under development since 1969. Water injection commenced in the early 1970s, and many wells now have very high watercut. However, large volumes of oil remain unrecovered in multiple reservoirs, and reservoir heterogeneity can have a significant impact on oil recovery by reducing reservoir sweep efficiency of the waterflood. A screening process was used to select the most suitable pilot candidate areas from a number of different fields which could potentially benefit from the technology. The Ust Vakh Satellite is a more recent development since early 2000s and possesses multiple wells completed in only a single zone, which is advantageous for pilot interpretation. Five wells in the Ust Vakh Satellite were selected on the basis of the number of good injectors, the presence of reservoir heterogeneity and high Water Oil Ratio wells despite the relatively short time under waterflood in this location. Another key criterion was selecting an area at the edge of the field with lowest interference possible in order to decrease the risk to interpreting a production response during the pilot. Tracer was injected in all wells prior to treatment which confirmed the lack of any high-rate fracture connectivity from the injectors to offset producers and validated the treatment design. The 5 wells were treated with a total of more than 400 tonnes of TAP over a period of 23 days. This paper describes aspects of candidate screening, treatment design, surveillance, implementation of the pilot and early response from the treatment. Note - Bright Water™ is a trademark of Nalco Company
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