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Abstract This work describes an automated combinatorial process for selecting EOR surfactants. It is well known that low interfacial tension (IFT) required to mobilize oil corresponds to the appearance of middle phase microemulsions (Winsor III). Instead of systematic measurements of IFT, simple observation of phase behaviour in vials allows to select best formulations. As the number of parameters to be screened incorporate surfactants, co-surfactants, alkali and electrolytes, we have developed an automated method to accelerate the screening productivity. Among other requirements, critical issues we want to address concern compatibility with electrolyte, thermal stability and low cost. Sample preparation is done in 48 well format using a robotic liquid handling platform that supports stirring and heating. In a first step, the brine concentration above which the surfactant is not soluble anymore is determined optically using a digital camera. In a second step, we take images of the phase behaviour of surfactant formulations in the presence of model oil (dodecane, vaseline). Image analysis is used to detect middle phase microemulsions. An estimate of interfacial tension can be derived from the volume of the middle phase microemulsion. Phase diagram observations can be recorded from room temperature up to 80°C. Results are in good agreements with classical methods used to measure low interfacial tension. An example study of phosphate esters will be discussed to illustrate the method. This technique provides a powerful tool for testing formulations prior to more expensive core flood experiments. Introduction Surfactant formulations providing a low interfacial tension (IFT) with the oil phase are known to effectively displace oil trapped in porous media (Stegemeier G.L., 1976; Green D. W. and Willhite G.P., 1998). Basically when the surfactant formulation contacts residual oil, drops under a pressure gradient are deformed as a result of low interfacial tension and displaced through the pore throats. In a recent paper a process based on phase behavior screening has been described for evaluating potential EOR surfactants (Levitt D.B. et al., 2006). This approach is based on a well established relationship between low interfacial tension and a microemulsion phase behavior as originally described by Winsor (1954). Type I (oil in water), type II (water in oil) and type III (bicontinuous oil and water) microemulsions can be found. The type III microemulsion also referred to as middle phase exhibits the lowest interfacial tension. The larger the volume of oil and water per unit volume of surfactant in this middle phase, the lower is the interfacial tension (Hug C., 1979). From a practical point of view this means that rather than performing systematic measurements of interfacial tension, simply observing the microemulsion phase behavior in transparent vials allows for pre-screening of a large number of compositions. This paper describes a highthroughput (or combinatorial) workflow where surfactant formulations are automatically prepared and analyzed using a robotic platform. Results on phosphate ester surfactants are used to illustrate the approach.
Abstract In this work we generalize the Compositional Space Parameterization (CSP) approach, which was originally developed for two-phase compositional problems. The extension is valid for an arbitrary number of phases, regardless of the number of components. The compositional space is considered to be a high-dimensional simplex, and the phase behavior is represented using a low dimensional tie-simplex parameterization. FOr example, in the three-phase case, the space is parameterized using tie-triangles and tie-lines for three- and two-phase regions, respectively. This parameterization improves the accuracy of the phase behavior representation as well as the efficiency of various types of computation for compositional flow. One application of this approach is to speed up standard multi-component phase behavior computations. For general purpose compositional simulation, Compositional Space Adaptive Tabulation (CSAT) can be used to avoid most of the redundant Equation of State calculations. A Supercritical State Criteria algorithm, which is based on adaptive tabulation of the critical tie-simplex, is used to handle the super-critical region. Results of several challenging tests of practical interest indicate that the CSAT strategy is quite robust, and that it leads to an order of magnitude gain in computational efficiency. This strategy is valid for systems with any number of phases and components. Another application area for our CSP framework is to speed up standard thermodynamic computations for complex mixtures. For such systems, the methodology is generalized in terms of a multi-phase tie-simplex description, where one finds the closest tie-simplex and uses it as an initial guess for the computations. For better tie-simplex estimation, interpolation based on triangulation is used. For cases with wide variation in pressure and temperature, linear interpolation of the tie-simplex for these variables is adequate. The methodology is demonstrated using several challenging examples. Introduction Enhanced Oil Recovery (EOR) processes usually involve the injection of fluids in the reservoir to displace the resident, or remaining, oil. Miscible gas injection displacements, for example, rely on the mass transfer between the injected and resident fluids to improve the local displacement efficiency. These reservoir displacement processes are usually modeled using the assumption of instantaneous thermodynamic equilibrium. Using a multi-component description of the fluid system (resident and injected), an Equation of State (EoS) is used to describe the complex phase behavior as a function of composition, temperature, and pressure. To model the complex nonlinear flow associated with EOR processes, numerical reservoir simulators solve the component mass conservation equations, the energy balance, if necessary, thermodynamic equilibrium relations, and constraint relations, for the given discrete representation of the reservoir.
Abstract We propose a novel approach to flash calculation, with particular application to negative flash. The ability to compute a negative flash for any composition state is important in practice, as the construction of analytical solutions for multicomponent systems by the method of characteristics (MOC) relies heavily on the identification of tie lines and tie-line extensions. MOC solutions are at the heart of some techniques for the calculation of the minimum miscibility pressure, and are the key building blocks for fast simulation of multidimensional reservoir flows by the front-tracking/streamline method. The basis of the proposed negative-flash method is a parameterization of the tie-line field. Rather than solving the Rachford-Rice equation (or any of its variants) we solve directly for the parameters defining the tie line. For an N-component system, our approach leads to a system of N - 2 quadratic equations, which we solve efficiently using a Newton method. The iterative method is very robust: unlike other negative flash procedures, the solution displays continuous dependence on the overall composition, even in the transition to negative concentrations. We illustrate the properties and behavior of the proposed approach on three-component and four-component systems, and we then generalize the method to systems of N components. From the global triangular structure of the system with constant K-values, it follows that the system of N - 2 quadratic equations can only have two roots. For the important case of three components, the flash calculation is explicit.
Enhanced Gas Recovery and CO2 Sequestration by Injection of Exhaust Gases From Combustion of Bitumen
Sim, Steve Soo-Khoon (Alberta Research Council) | Brunelle, Patrick (Quadrise Canada Fuel Systems Inc.) | Turta, Alexandru T. (Alberta Research Council) | Singhal, Ashok Kumar (Alberta Research Council)
Abstract Enhanced gas recovery by gas-gas displacement can be achieved economically in several situations. For mature volumetric gas reservoirs suffering from low productivity due to low reservoir pressure, injection of waste gas can increase the ultimate gas recovery by maintaining gas production rates and preventing premature well abandonment. For water-driven gas reservoirs, pressure maintenance by gas injection will serve toretard the influx of aquifer and partially mitigate water coning caused by excessive pressure drawdown. This paper presents the results of laboratory core displacement tests conducted to investigate the feasibility of enhanced natural gas production by using exhaust gas from combustion of bitumen in an oxygen rich atmosphere. A synthetic gas mixture containing carbon dioxide, nitrogen and sulfur dioxide was used to represent the exhaust gas of interest. Displacement tests were conducted in Berea core and in porous media prepared with silica sand as well as crushed carbonate rocks at pressures ranging from 0.69 to 6.2 MPa. The objectives of the experiments were to determine the effects ofpressure, displacing gas composition formation water and rock mineralogy on recovery efficiency of uncontaminated methane from the porous media. Several interesting phenomena were observed during the course of this investigation. Separation of injection gas components was observed in the effluent gas during displacement. Breakthrough of carbon dioxide and sulfur dioxide were delayed relative to nitrogen. This can be attributed to the higher solubility of CO2 and SO2 in water relative to nitrogen. These results are beneficial to natural gas production as they reduce the operating costs associated with corrosion during production of CO2 and SO2. The amount of green house gases and acid gases being sequestered in the reservoir will also increase due to these effects. INTRODUCTION Improved oil and gas recovery by means of carbon dioxide injection has attracted increasingly more attention in recent years due torising value of petroleum and recognition that geological storage of CO2 in depleted oil and gas reservoirs could be a potential solution to global warming by controlling the amount of green house gases in the atmosphere. Enhanced oil recovery (EOR) by miscible CO2 flood has been practiced worldwide since the 1960's and is considered to be a mature technology. However, the idea of injecting wasted gas for enhanced gas recovery (EGR) is rarely practiced. So far, the only published field application of CO2 injection for EGR was conducted during 1986–1994 in the Budafa Szinfelleti Field of Hungry (Papay, 1999). Here, the injected gas consisted of 80% and 20% methane from an adjacent natural CO2 pool.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.60)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.49)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- (2 more...)
Abstract For over 10 years research has been carried out on the impact of low salinity waterflooding on oil recovery. Data derived from corefloods, single well tests, and log-inject-log tests have shown that injecting low salinity water into an oil reservoir should result in a substantial increase in oil recovery in many cases. The results varied from 2 to 40% increases in waterflood efficiency depending upon the reservoir and composition of the brine. In 2005, a hydraulic unit was converted to inject low salinity brine into an Alaskan reservoir, by switching a single injection pad to low salinity water from high salinity produced water. An injector well and 2 close production wells were selected within a reasonably well constrained area. A surveillance programme was devised which included capturing produced water samples at regular intervals for ion analysis and the capturing of production data. Detailed analysis of the production data, and the chemical composition of the produced water, demonstrated an increase in oil production and provided direct field evidence of the effectiveness of LoSal™ at inter-well scales. Additionally, the response of the reservoir to low salinity water injection was confirmed by single well chemical tracer test. In parallel, laboratory studies have led to mechanistic understanding of LoSal™ in terms of multiple-component ionic exchange (MIE) between adsorbed crude oil components, cations in the insitu brine and clay mineral surfaces. The results clearly show that the enhanced oil production and associated water chemistry response was consistent with the MIE mechanism proposed. The oil production data have been modeled using an in-house developed modification to Landmark's VIP reservoir simulation package. An excellent match for the timing of the oil response was obtained which provides a good basis for predicting the result for large scale application of LoSal™ flooding. Introduction It has been more than 10 years since Yildiz and Morrow (1996) pushed forward the research started by Jadhunandan(1990; 1991; 1995) and published their paper on the influence of brine composition on oil recovery. This paper showed that changes in injection brine composition can improve recovery. Since then, Tang & Morrow (1999) have progressed the research on the impact of brine salinity on oil recovery, followed by other researchers such as Webb et al. (2004) and McGuire et al. (2005); these authors performed an extensive research programme on low salinity injection (LoSal™). This programme included numerous core flood experiments performed at ambient and reservoir conditions (at high temperature and pressure, with 'live' fluids) both in secondary and tertiary mode, single well tracer tests (SWCTT) and log inject log tests, showed a significant increase in oil recovery due to low salinity brine injection.
- Geology > Mineral (0.73)
- Geology > Geological Subdiscipline (0.48)