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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
51 - 73 of 73 results
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Injection Fall-off Interpretation from Fractured Injectors
More LessWe performed numerical simulations of injection fall-off (IFO) testing for both water and (non-Newtonian) polymer in which the gradual closure of the induced fracture is explicitly included. A large variety of induced fracture sizes and shapes was included in this study. Results show that half-slope and quarter-slope ranges will only occur very exceptionally in the early-time pressure derivative curves. On the other hand, the unit slope (storage flow dominated) occurs very often at early time. In principle, both half-slope / quarter-slope and unit slope can be used for IFO test analysis to estimate the dimensions (length, height) of the induced fractures. However, based on the above, we conclude that fracture dimensions in IFO tests can only be reliably interpreted from the unit slope part. This point is further illustrated by a two IFO test examples from the field, where it is shown that interpretation of half-slope or quarter-slope can often result in unrealistically large fractures.
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Continuous Land Seismic Reservoir Monitoring of Thermal EOR in the Netherlands
Authors J. Cotton, L. Michou and E. ForguesA continuous reservoir monitoring system has been installed for Shell, on a heavy-oil onshore field situated in the Netherlands, to re-develop oil production by Gravity-Assisted Steam Drive. The challenge was to continuously monitor using seismic reflection the expansion of the steam chest injected in the reservoir during production. The main problems for onshore time-lapse seismic are caused by near-surface variations between base and monitor surveys which affect the seismic signal coming from the reservoir. In our system, a set of permanent shallow buried sources and sensors has been installed below the weathering layer to both mitigate the near-surface variations and minimize the environmental footprint. The very high sensitivity of our buried acquisition system allows us to track very small variations of the reservoir physical properties in both the spatial and calendar domains. The 4D reservoir attributes obtained from seismic monitoring fit the measurements made at observation, production, and injector wells. A daily 4D movie of the reservoir property changes allows us to propose a scenario that explains the unexpected behavior of the production and confirms that the steam does not follow the expected path to the producer wells but rather a more complicated 3D path within the reservoir.
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Experiments and Analysis of Imbibition in Carbonates
Authors R.A. Anderson, N.A. Al-Ansi and M.J.B. BluntWith around half the world's remaining conventional oil contained in fractured carbonate reservoirs, it is important that the fundamentals of the transfer of fluids from fracture to matrix are understood. We present the results of an extensive series of spontaneous imbibition ambient-condition experiments on three carbonate cores of different length, designed to test recent theoretical models of imbibition. We study the displacement dynamics, from an initial square-root-of-time recovery to an exponential relaxation to residual saturation as the wetting from reaches the end of the core. We also quantify the effect of pore structure in highly heterogeneous systems. The scaling models presented by Ma et al. (1995), Li and Horne (2004), and Schmid and Geiger (2012) were tested on the experimental data. Schmid and Geiger’s correlation was found to be the most reliable. The recovery, as a function of dimensionless time, could be fitted with the mass transfer function proposed by Aronofsky et al. (1958) and the analytical oil recovery solution presented by Tavassoli et al. (2005). The work suggests that recent correlations for transfer rates in the literature, combined with benchmark experimental results, can be used as a reliable technique to help predict field-scale recovery rates in fractured reservoirs.
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Integrated Laboratory and Numerical Investigations Towards a MEOR Pilot
Authors H.K. Alkan, E. Biegel, A. Herold and F. VisserA project on the application of MEOR in one of the Wintershall candidate fields has been initiated. The project aims mainly at developing nutrient formulations for stimulating microbial activity in terms of oil recovery and defining reservoir and process parameters for the selected field leading to a field trial. The project is structured with a workflow consisted of 5 work packages. The sampling activities were extended with a sub-surface sampling in one of the candidate fields to investigate the effect of pressure on bacterial activity. The works on the determination of growth rates and metabolite activities of microbial consortia derived from one field is continuing with batch tests and micromodels. Dynamic screening experiments are going on in sandpacks and cores under sterile and anaerobic conditions. Numerical works are performed in two parallel ways. On one hand, an analytical model is being applied to evaluate relevant process parameters. On the other hand, a numerical simulator is being tested and validated to implement it into a reservoir simulator. The recent results both in experimental and numerical parts are presented and discussed in the paper.
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An Integrated Laboratory Workflow for the Design of a Foam Pilot in Malaysia
An integrated laboratory workflow for the design of a foam pilot in Malaysia. Max Chabert (Rhodia), Lahcen Nabzar (IFPEN), Siti Rohaida, Pauziyah Hamid (Petronas PRSB). We present the laboratory feasibility study dedicated to the design of an enhanced water alternating gas (EWAG) process for a Malaysian oilfield. The field is currently submitted to produced gas injection, mainly consisting of CO2. We focus here on the design of a water soluble foaming surfactant formulation using advanced characterization methods and the evaluation of this formulation in corefloods experiments. On-field conditions make the design of a surfactant formulation particularly challenging, with a reservoir temperature of 100°C and only sea water available for foaming formulation injection. The ultimate goal of this design study is thus to obtain an industrially realistic formulation yielding stable foams in reservoir conditions (including in presence of oil) at an affordable price. We set-up a specific laboratory workflow to design a foaming surfactant formulation adapted to reservoir settings. An automated screening routine based on robotics was used at ambient and reservoir temperature to pre-select the most performing formulations for foam stabilization among more than 400 binary and ternary mixes. Formulations solubility maps were obtained using automated image analysis. Only formulations perfectly soluble in the window defined by injection and production waters salinities were retained for further testing. Selected formulations were then characterized for foam stabilization in reservoir pressure and temperature conditions using a high pressure variable volume view cell. Adsorption of the selected formulations on reservoir crushed rock was optimized by exploiting synergistic effects between surfactant families. A formulation yielding over 2 hours foam half-life in reservoir conditions with a static adsorption below 1 mg/g was obtained. This formulation was further characterized in petrophysics application tests using analog Berea sandstones and reservoir rocks. These tests were designed to mimic potential pilot conditions in terms of injection strategy, injection rate and gas composition. High values of mobility reduction factors were obtained, including in presence of residual oil. This set of results is a first step toward application of an enhanced WAG foam process.
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Dynamic Interactions between Matrix and Fracture in Miscible Solvent Flooding of Fractured Reservoirs
Authors A. Ameri Ghasrodashti, R. Farajzadeh, M. Verlaan, V.S. Suicmez and H. BruiningMiscible solvent injection has received increasing attention in recent years as an efficient method to improve oil recovery from fractured reservoirs. Due to the large permeability difference between fracture and matrix, the success of this method depends to large extent on the degree of enhancement of the mass exchange rate between the solvent flowing through the fracture and the oil residing in the matrix. A series of experiments have been conducted to investigate the mass transfer rate between the fracture and the matrix. Different scenarios have been considered to examine the effect of flow rate, matrix permeability, fracture aperture, and oil properties. To this end a porous medium (fully saturated with oil) is placed in a vertical core holder that can be used in a CT scanner, to simulate the matrix. A small slit between the porous medium and the core holder simulates the fracture. The interaction between the matrix and fracture is visualized for solvent flooding by means of CT-Scanning, which can be used to validate theories of enhanced transfer in fractured media. The experimental data are compared with a simulation model that takes diffusive, gravitational and convective forces into account.
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Enhancing Recovery from the Oil-Rim Using Energy from the Gas Cap
Authors N.N. Ivantsov and A.S. TimchukIn the environment of constant deterioration of resource base, stability of oil production in the nearest decades will depend on the prospects of development of geologically complicated fields. In Western Siberia significant part of undeveloped reserves is represented by highly viscous oil fields with gas cap. Such are Russkoye, Messoyakhskoye, Van-Yoganskoye, Severo-Komsomolskoye and other, having reserves over 4 bln. tons. Development of such assets is hindered by adverse geological and physical conditions. Presence of a gas cap and a fine oil rim leads to early gas breakthroughs. Viscous oil and poorly consolidated reservoir contribute to the risk of premature water breakthroughs (matrix breakthrough events), reducing the efficiency of injection. Permafrost and reservoir clay swelling limit the deployment of thermal techniques. The fields were discovered over 40 years ago and massive pilot work is being carried out only in Russkoye field, however, an efficient development technique has not yet been found. In such an environment it seems relevant to look into unconventional solutions. The authors propose an oil rim development technique using the energy of the gas cap. In this technique the design and the trajectory of horizontal wells allow for simultaneous controllable oil production from the oil saturated zone and gas production from the gas cap. This allows for enhancement of oil flow rate, reduction of gas coning and extends the period of stable well operation. The earlier achieved results of calculations made for Russkoye field have shown that while depletion recovery factor equals 6%, enhancement could provide up to extra 3%. In this work the authors, using modeling results, have determined optimal geo-technical conditions for deployment of this technique. Efficiency evaluation has been performed for operations at injection scheme. Particular features of this technique enable it to be viewed not only as an EOR technique, but also as a tool to prevent the main risks for similar fields, i.e. gas breakthroughs and reservoir damage. Based on the results of the study proposals were elaborated for pilot work in Russkoye field.
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Pelican Lake Polymer Flood - First Successful Application in a High Viscosity Reservoir
Authors E. Delamaide Inc., A. Zaitoun, G. Renard and R. TabaryThe Pelican Lake heavy oil field located in northern Alberta (Canada) has had a remarkable history since its discovery in the early 1970s. The reservoir formation is thin (less than 5m) and as the oil is viscous (from 600 to over 40,000cp), initial production using vertical wells was poor. Several methods were used in order to improve production and recovery, including an air injection scheme in the 1990’s. However it is only with the introduction of horizontal drilling that the field began to reach its full potential; indeed Pelican Lake was one of the first fields worldwide to be developed with horizontal then multi-lateral wells. With primary recovery around 5-7% and several billion barrels OOIP, the prize for EOR is large; polymer flood had never been considered in such high viscosity oil until 1995, when the idea of combining polymer flood and horizontal wells gave way to a polymer flood pilot in 1997. This was the first step on the way, and today the field is in the process of being fully converted to polymer flood, with several hundred injection wells already in action. Polymer flooding has the potential to increase recovery to over 20%OOIP at relatively low cost. Pelican Lake is the first successful application of polymer flood in a high viscosity oil reservoir (1,000-2,500cp). This paper presents the history of the field then focuses on the polymer flooding aspects. It describes the preparation and results of the first polymer flood pilots as well as the extension to the field.
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ASP Pilot in West Salym Field - Project Front-end Engineering
Authors Y.E. Volokitin, J. Nieuwerf, V. Karpan, M. Shuster, W. Tigchelaar, D. van Batenburg, M. Shaymardanov, I. Chmuzh, I. Koltsov and R. FaberSalym Petroleum Development N.V. (SPD) is a 50/50 Joint Venture of Shell and Gazpromneft. SPD is the License holder and operator of the Salym Group of fields in Western Siberia (Upper Salym, West Salym and Vadelyp Work on maturation of Enhanced Oil Recovery option for Salym Petroleum Development (SPD) has began in 2007 and after initial screening, the ASP (Alkaline-Surfactant-Polymer) technology has been chosen for further work. Follow-up work involved laboratory and field tests, subsurface modelling and surface high-level concept design. High-level assessment demonstrated production potential of 30+ mln tones additional oil and a significant potential value to be shared between SPD and Russian Government. At that stage work began on Production Pilot as a Separate Project with Pilot Concept selected and Front-End Engineering work completed in 2012.Construction and opperation is expected in 2013-2014. The chosen concept for the Pilot involves a single 100x100m square pattern with 4 injectors and one producer. Since the primary objective of the Pilot is to demonstrate technology and to collect data for further optimization, 2 additional observation wells will be drilled within the pattern to provide information about the effectiveness of the process. Wells will be drilled from a dedicated well pad in the Northern area of West Salym field. The same location will host standalone mixing and production facilities. Produced fluids will be collected in the tank farm at the well pad and analysed. Logistics and planning for assurance of quality control of chemical mix has provided a separate challenge, also exacerbated by remoteness of location, but also by rheology properties of viscous surfactnat concentrates. In addition all storage and mixing facilities have to survive harsh Siberian conditions with temperatures ranging from -50 to +40 deg C. The paper describes some subsurface, chemical and engineering solutions for Salym pilot that might be of value for other groups contemplating cEOR pilots and small-scale production in a similar area
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Effect of Nonionic Surface-active Substances on Paraffin Crystallization in the System
Authors L.K. Altunina, L.A. Stasyeva and V.A. KuvshinovPresented are physicochemical and rheological properties of viscous paraffinic oils recovered from the south of West Siberia, Russia, Germany and Mongolia in the temperature range of 20-90 °C at different shear rates and interactions with oil-displacing systems based on surfactants and alkaline buffer solutions. The systems were determined to have demulsifying effect on the viscous paraffinic oils under study, regardless of surfactants composition and structure. Temperature dependence of paraffin crystallization point on a preheating temperature is extreme. At the same time maximum paraffin crystallization points correspond to preheating temperatures of 50-60 °C. We studied the ability of non-ionic surfactants – oxyethylated alkylphenols with different degrees of oxyethylation, from 12 to 90, to exhibit depressant properties with respect to paraffinic oils, reduce the viscosity of crude oils and the paraffin crystallization point. Optimal degree of oxyethylation of non-ionic surfactants was determined equal to 50, at which the decreases in oil viscosity and paraffin crystallization point were maximal. One can use the proposed compositions to develop EOR technologies for high-viscosity paraffinic oils.
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Geological Factors in Acidizing Design
Authors N.A. Misolina and I.M. NasibulinField experience and laboratory tests indicate that the effective result of the use of acid solutions is "wormholes".This article studied the effect of the geological features of reservoir rocks in the acid treatment and the ability to influence the acid compositions to specific lithotypes limestone.The complex technology of the tests for acid stimulation of wells in carbonate reservoirs consisted of five stages: filtration studies using three different acid compositions, the microscopic method (thin sections), the electron microscope, X-ray tomography.Founnd that when exposed to different types of carbonate reservoir acid compositions, all other things being equal, the structure formed dissolving the following types: surface, tapered, dominant, even.Using modern methods of X-ray tomography, assured the visualization of inhomogeneities of the core sample, and scanning electron microscopy was used to answer questions related to the change of the internal structure, the structure of the pore space limestone after exposure to acidic agents. It has been shown that the decisive role in the choice of the method of intensification is the material composition of sediments and reservoir type.
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Harmonic Testing of Hydraulically Fractured Wells
By P.E. MorozovHydraulic fracturing is an effective technique for increasing productivity of damaged wells and wells producing in low permeability formation. Various methods have been proposed to estimate reservoir and fracture properties from transient pressure and flow rate data. The basic concept of harmonic testing is the use of a sinusoidal flow rate variation instead of a step change as in conventional well testing. When a pseudo-steady flow regime is achieved after a few periods, both flow rate and wellbore pressure exhibit a sinusoidal behavior. It is then possible to identify the modulus of the response and phase shift between the two signals. These data are used to evaluate the reservoir parameters. In this study, new analytical solutions are presented for analyzing amplitude- and phase-frequency characteristics of fractured wells in homogeneous or double-porosity reservoirs. The influence of wellbore storage effect, fracture storage and conductivity on the pressure modulus and phase shift is investigated. In case of high dimensionless frequencies a set of asymptotic solution is derived. These solutions can be used to solve the inverse problems for obtaining the formation and fracture properties.
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Chemical EOR in High Salinity-High Temperature Reservoir - Experimental Coreflooding Tests and Numerical Simulation
Authors V. Parasiliti Parracello, C. Callegaro, A. Dato, F. Siliprandi, P. Albonico and M. MatteiRecent developments in chemical EOR technologies make now possible to operate in severe environments, characterized by high-temperature conditions and by high salinity and hardness of reservoir brine. A feasibility study was conducted on a field operated by Eni, in order to design a surfactant injection under these challenging conditions. Laboratory studies and simulations were performed to evaluate the potentiality of the technique to increase the oil recovery. Two surfactant formulations presenting good phase behaviour and conferring low interfacial tension between brine and reservoir oil were tested. The dynamic performance of the chemicals was screened with a series of coreflooding tests, carried out using Berea sandstone. Sea water injection was followed by the chemical flooding, so that the additional recovery factor was evaluated. Surfactant adsorption was then measured to select the most suitable formulation. Moreover, core experiments were history matched through numerical simulation to validate the model and obtain scaling parameters of the chemical process for future forecast previsions of surfactant flood benefits at sector scale.
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Applying the Probabilistic Collocation Method to Surfactant-polymer Flooding
Authors A. Alkhatib and P. KingEnhanced oil recovery has achieved great attention during the past few years. However, broad scale implementation requires greater understanding of the relevant uncertainties and their effect on performance. Quantifying this uncertainty is very important for designing these processes, yet traditional methods which are usually based on Monte Carlo simulations require a large number of realizations to produce convergent results. We propose the use of a non-intrusive approach known as the Probabilistic Collocation Method (PCM) to quantify parametric uncertainty for surfactant-polymer flooding. The quantification of uncertainty was performed for surfactant/polymer related state variables such as adsorption rates and residual saturations. The PCM is performed on two reservoir models: a modified section of the SPE10 model and the PUNQ-S3 model. The random input variables PDFs are first approximated using polynomial chaos expansions and then probabilistic collocation is used to produce approximations of the reservoir model using the collocation points obtained via Gaussian quadrature and Chebyshev extrema. These approximations can then be used to produce PDFs for output variables such as the recovery factor. Results show that PCM produces similar results to those obtained via Monte Carlo simulation, which requires a large number of simulations, while requiring significantly lower number of simulation runs.
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Optimization of Polymer Flooding with a Tapered Concentration Slug
Authors A. Behr, L. Olie, F. Visser and B. LeonhardtThis paper provides hints and guidelines towards a better understanding of the correlation between the polymer injection schedule and the project profitability. In the optimization study, the polymer slug will be represented by three parameters: the slug length, which is the effective duration of polymer injection at maximal polymer concentration, the maximal injected polymer concentration itself and the tapering (in terms of slope of polymer concentration profile versus time). This last factor is often ignored due to the complex problems of parameterisation in numerical models. The polymer flood model and inverse problem formulation were adapted to be solved by CMG’s tools and a special method was introduced to account for the effect of varying the optimization parameters on the rheological properties of the water phase (combining viscosity dependence on shear-thinning and concentration) and on the polymer injectivity. The injectivity issue was treated by introducing an additional negative well skin factor which corrects the well inflow model for non-Newtonian polymer solutions. The Net Present Value was used as an objective function during the optimisation phase to estimate the economic benefit. The method was applied to a North-German mature oil field where a polymer project is at the stage of pilot testing.
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Design of Foam-assisted Carbon Dioxide Storage in a North Sea Aquifer Using Streamline-based Simulation
Authors A.M. Al Sofi, S. Vitoonkijvanich and M.J. BluntCarbon capture and storage (CCS) − the collection of CO2 from industrial sources and its injection underground − could potentially contribute to the reduction of atmospheric emissions of greenhouse gases. In this paper, we investigate the sequestration of CO2 in aquifers with the co-injection of surfactants for foam generation, to allow increased storage capacity. This is equivalent to the use of foam for conformance control in enhanced oil recovery applications. To study foam-assisted sequestration, we extend an in-house streamline-based simulator. We use two foam models: Hirasaki and Lawson (1985) and Rossen et al. (1999). In both models foam hinders gas mobility through increasing its apparent viscosity. The modified simulator is validated by comparison to analytical solutions. We then investigate the performance of CO2 sequestration with the co-injection of surfactants. We look at CO2 sequestration in a North Sea aquifer. We study both simultaneous and alternating surfactant-gas injection at different fractional flows (i.e. water:gas ratios). For cases where a seal provides a reliable trapping mechanism, the simulation results suggest that the use of surfactants to generate foam significantly improves the storage efficiency at a marginal increase in water consumption. In this setting, CO2/surfactant simultaneous injection at a 0.5 CO2 fractional flow was found to be the optimum injection strategy for the case investigated. If the seal is unreliable or absent, CO2/brine simultaneous injection at a 0.85 CO2 fractional flow was found to be the optimum injection strategy. Although foam-assisted sequestration in this case furthers improve the storage efficiency, it does so at a significant increase in water consumption. This is since, although foam generation improves the sweep during the sequestration phase, it significantly hinders the sweep during the chase brine injection phase. Based on that, having a design where the surfactant will degrade just before or during the chase brine injection phase would provide the optimum sequestration strategy—without reliance on the presence or integrity of the seal.
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WAG-CO2 Light Oil Recovery from Deep Offshore Carbonate Reservoirs
Authors S.F. Mello, E.L. Ligero, H.F.A. Scanavini and D.J. SchiozerBrazilian pre-salt reservoirs are constituted by carbonate rock and light oil with some CO2 and high solution gas ratio. A sustainable production of oil from pre-salt reservoirs requires a destination for the produced CO2 to mitigate its emission into the atmosphere. CO2 has been used to improve oil recovery when combined with water injection in the water-alternating-gas process (WAG). WAG-CO2 is an Enhanced Oil Recovery (EOR) method that modifies the fluid and rock-fluid properties. This injection process is associated to hysteresis of relative permeability and capillary pressure. Before implementation of the WAG injection in a field, the use of the reservoir simulation is required, a tool used to predict the oil recovery. A more rigorous way to simulate this process is by using a compositional reservoir simulator, given that an Equation of State (EOS) must be used to represent the pressure, volume, temperature (PVT) data that is different from the representation considered in conventional Black-Oil models. An EOS obtained from conventional PVT experiments and swelling tests must be employed to adequately represent the phase behavior resulting from the CO2 dissolution in the oil. Changes in relative permeability and capillary pressure resulting from hysteresis associated with the alternation between the injected fluids in the WAG process must be considered in the simulation model, avoiding a non-realistic oil recovery prediction. The impact of changes in oil properties and the hysteresis effect are considered in the prediction of WAG-CO2 oil recovery from a reservoir with petrophysical properties similar to a real carbonate reservoir constituted by light oil (about 8% molar of CO2). Reservoir simulation results give an indication of the expected oil recovery from a reservoir with pre-salt characteristics, enabling one to decide if the WAG-CO2 process is indicated for implementation in practice.
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Optimization of Water Flooding in Stratified Formations or Multiple Reservoirs
Authors A.I. Ermolaev, L.M. Surguchev, A.A. Khrulenko, R.A. Berenblyum and A.A. ShchipanovWater flooding of stratified reservoirs often resulted in non-uniform oil displacement and fast water breakthrough in high permeability layers. Increase in oil recovery may be achieved by improvement of oil displacement in different layers and getting simultaneous water breakthrough in production wells. A similar problem may arise when water flooding multiple reservoirs with constrains on total injection / production. Control of injection rate allocation may provide uniform oil displacement in a layered formation or multiple reservoirs. Constrains on local (per layer) and total (per formation) injection / production rates and on production period for each layer may be accounted for. In this study optimization algorithms have been developed to determine an optimal strategy enabling maximum possible oil production with minimum possible water cut from a group of non-communicating layers or reservoirs. A solution of the optimization problem was found using linear and discrete programming methods under an assumption of two-phase piston-like incompressible flow in the reservoir. An optimal strategy with maximum oil recovery is defined under constrains on local and total production rates, injection start-up time and duration of production period for each layer or reservoir. An analytical solution was also found for a partial statement of the problem, where injection rates remain constant over the whole production period, which in turn is the same for all layers. The general problem statement has flexible constrains available, while the analytical solution for the partial statement may be easily implemented and used without dimension (number of layers or reservoirs) limitations. Both solutions were coded and further tested at mechanistic reservoir models to confirm applicability and efficiency of the developed algorithms in the reservoir simulation practice. A two-dimensional cross-sectional model with non-communicating layers was set up to test efficiency of the optimization algorithms for a typical reservoir simulation problem where fluid / rock compressibility and relative permeability effects are accounted for. The reservoir simulation results have confirmed that the optimal solution remained in force and therefore the optimization algorithms may be successfully integrated in reservoir simulation workflow.
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Tensor Characteristics of Filtration and Capacity Properties for Anisotropic Reservoirs.
Authors A.N. Kuzmichev, V.V. Kadet and N.M. DmitrievIn recent years while determining filtration and capacity properties in cores greater attention is paid for considering the anisotropy, in particular, not only for identifying of the lateral anisotropy, but also for obtaining the tensor coefficients of absolute and relative permeability, relative phase permeabilities. At the same time many other characteristics such as tensor characterizing linear dimensions (pore radius), capillary pressure, Leveret`s function and etc. also have a tensor nature. It`s necessary to have methodology and theoretical concepts for determining these tensors. The results of comprehensive researches carried out in the real full-sized core from the North field of Samara region are presented in this paper. The presence of lateral anisotropy and the directions of the principal axes of the permeability coefficients were established in full-sized core with using the author`s technique. As a result of complex laboratory tests for each of the samples the absolute and relative permeability, the distribution of pore radius and the capillary pressure curves were obtained. The experimental results were computed with using the authors' theoretical formulas. After comparing the experimental and theoretical results the obtained filtration and capacity properties proved to have tensor nature.
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Experimental and Mathematical Workflow in Modeling In-situ Combustion Processes for Unconventional Resources Recovery
The development of new technologies to increase oil recovery and the improvement of old ones has become increasingly important in the world. One of such methods is based on in-situ combustion, which in reference to light oils is termed as High Pressure Air Injection – HPAI. There are a number of projects of air injection into light and heavy oil fields described in literature. Some of them are successfully operated for many years and up to this day. The in-situ combustion process is attended with CO and CO2 formation as well as thermal decomposition processes resulting in hydrocarbon gases output and fuel formation. The improvement in oil recovery is caused by contribution of several processes – rise of reservoir pressure and temperature, oil density and viscosity reduction under heating, evaporation-condensation of water, nitrogen and fuel gases displacement, dilution of oil due to dissolution of carbon dioxide, and many others. Nowadays there is no systematic and comprehensive approach to all the mentioned phenomena. That causes considerable risks in project’s efficiency and total oil recovery estimation. The present work includes theoretical and experimental study of the processes associated with HPAI. The first stage includes calorimetric study of oxidation process in differential scanning calorimeter (DSC) and kinetic parameters estimation (activation energy, pre-exponential factor, reactions’ rate and order etc.), which are then applied for in situ combustion modeling. In term of theoretical investigations the mathematical model of in-situ combustion based on experimental data is formulated. The model includes heat- and mass-transfer in three-phase multi-component system in porous medium. The mathematical model is also constructed to make the attempt to investigate some transition processes – in-situ ignition, attenuation and re-igniting. Set of dimensionless parameters is formulated which allow predicting the quality of in-situ-combustion of oil. Large number of geological and physical parameters responsible for the in-situ-combustion is reduced to the analysis of two dimensionless parameters. The conditions for development of self-sustained oxidation reaction in porous medium are obtained that is summarized in a form of ignition-combustion diagram for in-situ-combustion process. The modeling results will be calibrated with combustion tube experimental data, as well as the results will be used to perform some combustion cases with the tube. The main goal of the project is to enhance predictability of the modeling and reduce risks associated with HPAI.
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Enzymatic Generation of Oil-displacing Systems
Authors L.K. Altunina and L.I. SvarovskayaThe main method for the development of low-temperature reservoirs on viscosity oil deposits – thermal-steam stimulation. To improve oil recovery from low-temperature reservoirs we have developed and apply combined technologies based on steam injection into a reservoir followed by the injection of oil-displacing compositions based on surface-active substances. Besides surfactants such oil-displacing compositions contain nitrogen compounds including carbamide. At a high reservoir temperature carbamide is subjected to hydrolysis to yield СО2 and ammonia. Dissolving in water СО2 decreases oil viscosity and ammonia forms an alkaline buffer system with рН=9.0 10.0. It improves detergency of the system thereby improves oil recovery. To improve oil recovery from low-temperature reservoirs without thermal treatment we have developed a combined physicochemical and microbiological method based on simultaneous injections of the solution of oil-displacing system and urease enzyme catalyzing carbamide hydrolysis with the release of ammonia and СО2. Thus the effective oil-displacing system is generated in situ; it is capable to increase the oil-displacement factor of low-temperature oil deposit without thermal stimulation.
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Wormlike Micelles for Mobility Control - A Comparison with Different EOR Techniques
Authors H. Bertin, E. Tognisso, M. Morvan and A. ColinPolymers can be used for EOR operations to improve the mobility, however a major problem is its sensitivity to shear stress. An alternative method could be wormlike micelles, which are self assembled surfactant molecules, that show a similar behaviour than polymers in term of viscosity increase and have the advantage of breaking and reforming in the porous medium when shear stress is modified. We started this study by a complete characterization of a wormlike micelles solution prepared with betaine molecules. Micellar characterization, for different surfactant concentration, salinities and temperatures showed that that the kraff point decreases when the salt and surfactant concentration increase. This means that this system stability increases with temperature. Rheological experiments showed a classical shear thinning behavior. Experiments in porous media consist in one phase and two phase flow in sandstone cores. One phase flow has been performed to determine surfactant adsorption and permeability reduction. Two phase flow displacements were conducted to show the ability of wormlike micelles to improve oil recovery. Experimental data obtained with wormlike micelles displacement are compared with standard reference experiments using polymer and Alkaline Surfactant Polymer. Results show that, despite adsorption, wormlike micelles have a positive effect on mobility control.
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Forecasting IOR/EOR Potential Based on Reservoir Parameters
Authors A.A. Khrulenko, E.V. Babushkina, V.S. Rusakov, S.V. Rusakov, A. Shchipanov and R.A. BerenblyumThe oil and gas industry has accumulated significant experience in carrying out improved/enhanced oil recovery (IOR/EOR) projects. The outcome of different IOR/EOR methods applied to the fields world wide is available in open data sources as well as internal databases of oil companies. Open data typically include general information about oil field, average reservoir and fluid properties (reservoir parameters), and efficiency of an IOR/EOR method applied. Statistical analysis of such data may be applied to evaluate IOR/EOR potential of a particular field. Since such analysis requires small amount of information on a field, it is suitable for screening of large number of fields or evaluation of new discoveries or acquisitions. A new statistical approach to predict efficiency of different IOR/EOR methods for particular reservoir parameters has been developed and tested on actual filed data. The approach utilizes multi-dimensional statistical analysis based on data clustering. The K-means clustering is used to partition a filed case database into clusters based on reservoir parameters. A set of six representative parameters (porosity, permeability, depth and oil density, viscosity and temperature) has been chosen based on parameter correlation studies described in literature. Visualization of the cluster analysis results is performed via projection of six-dimensional vectors into two-dimensional space using the principal component method. IOR/EOR potential for a new field case is evaluated into two steps: (1) association of the case with a nearest cluster utilizing the discriminant analysis and (2) multi-dimensional interpolation of recovery factor for different methods within the cluster. A quality control is carried out at all stages of the statistical analysis to confirm its reliability. A list of potential methods with an estimation of recovery factor classified according to the confidence index (a measure of reliability) is outputted as a result of the analysis performed. Described algorithm was coded and tested on actual field case databases. The tests have shown good quality and reliability of the results obtained at all stages of the analysis. The testing has also revealed that reliable evaluation of IOR/EOR potential is possible for databases containing at least ten field cases with a particular method. Application of the new approach may serve as an IOR/EOR compass when potentially efficient methods have to be identified. A database containing actual field data and/or results of laboratory experiments and reservoir simulations may be used as an input for such analysis.
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