Prior to starting any Enhanced Oil Recovery (EOR) process, it is desirable to characterize the flow pattern within the affected reservoir volume. This becomes of critical importance for in situ combustion in heavy oil reservoirs, where the mobility ratio is highly unfavorable, oftentimes resulting in channeling or early breakthrough. An inter-well connectivity test through immiscible gas injection aids in characterizing the flow distribution, in addition to: 1) calibrating estimates for sweep efficiency, 2) evidencing geological features that may lead to preferential flow towards a particular well or group of them, or lack of connection amongst them, 3) creating a gas path between the injector and producer wells to enable a safe progression of the combustion front, and 4) evaluating the performance of artificial lift and well control systems under high gas-liquid ratio conditions. A connectivity test using nitrogen was designed, implemented and evaluated at the Chichimene field, prior to the ignition of the in situ combustion pilot. This process is summarized and described in this paper. This will be the first in situ combustion trial in a deep (≈ 8,000 ft), extra-heavy oil reservoir, and will serve as a data source to evaluate the development of resources under similar conditions in the eastern plains basin of Colombia. This set of reservoirs bears a significant fraction of the hydrocarbon resources in the country and under Ecopetrol operation. The importance of this pilot makes this connectivity test of even larger relevance to reduce the subsurface and operational uncertainty, identify risks, and increase the probability of success of the combustion process as an option to economically producing these resources.
High Pressure Air Injection (HPAI) is an improved oil recovery process in which compressed air is injected into typically deep, light oil reservoirs. Part of the oil reacts exothermically with the oxygen in the air to produce flue gas (mainly composed of nitrogen, carbon dioxide and water). Literature explaining the reaction mechanisms and phase interactions is available. Nevertheless, little effort has been devoted to describing gas, oil and water three-phase flow behaviour under HPAI reservoir conditions. Three coreflood experiments were conducted on Berea sandstone core. The first experiment consisted of injecting flue gas into core at initial oil and connate water saturations to obtain liquid-gas relative permeability data. The second experiment was designed to evaluate oil re-saturation, after gas sweep, simulating an HPAI thermal front. The third experiment consisted of gas displacing both oil and water completing the data necessary to plot the three-phase relative permeability curves. Reservoir simulation was used to adjust relative permeability curves and hysteresis parameters by matching the pressure drop and production data. Introduction It is well-known that the oil recovery mechanisms in HPAI are a combination of highly efficient displacement by the reaction front and light oil/flue gas compositional interactions, such as oil swelling and/or vapourization and near-miscible behaviour(1). However, the contribution of each of these recovery mechanisms has not been properly assessed(2). Although significant effort has been devoted to the characterization of oxidation kinetics(3–5) and flue gas/light oil compositional interactions(6, 7), the process remains challenging to simulate even under controlled and ideal conditions, i.e., a combustion tube test. Some of the difficulties include the limited availability of experimental data to feed the numerical simulators with the required parameters, as well as the interdependence of these parameters and their variation with temperature. Assuming that these difficulties can be overcome by carrying out a study that allows a judicious analysis of experimental information and a careful treatment of the matched parameters in a numerical simulator, there is still a piece of information that has a strong influence on the simulation results and cannot be defaulted or left as a final matching tool: relative permeability. In an earlier study(2), it was suggested that for a combustion tube match, the steps previous to air injection (waterflood and inert gas flood) could be used to find a full set of relative permeability curves for the run. It was also pointed out that the rock-fluid dataset should include a variation of relative permeability data with interfacial tension to account for changes in pressure, composition, and most importantly, temperature. While this being necessary, it is still insufficient to ensure a correct representation of the flow of phases in a porous medium subjected to HPAI. Ahead of the reaction front, the high mobility flue gas (mainly composed of nitrogen and carbon oxides) displaces oil and water at nearly reservoir temperature, while in the high temperature zone, oil and water are evapourated to later condense downstream. In both zones, three-phase flow is occurring.
In this paper, an improved characterization of three-phase flow under high-pressure-air-injection (HPAI) conditions was achieved on the basis of experimental results and numerical reservoir simulation.A three-phase coreflood experiment was conducted at reservoir conditions, using 37°API stock-tank oil, an 84% nitrogen and 16% carbon dioxide flue-gas mixture, and 3% potassium chloride brine. The aim of the test was to evaluate the effects that the highly liquid-saturated front produced by the thermal reactions has on the mobility of each phase. Departing from connate-water saturation and reservoir pressure and temperature, sequential injection of water, gas, and oil was carried out, followed by a final gasflood to residual liquid saturation. Other two-and three-phase tests performed on this rock specimen were published elsewhere ). Numerical history matching was employed to determine oil/water and liquid/gas relative permeability (k r ) curves for both imbibition and drainage cases. A combustion-tube (CT) test was simulated using conventional k r curves and a set that included hysteresis. The degree of hysteresis observed during the coreflood test was maintained for the CT simulation.History matching of the coreflood showed that k r to the gas phase is much smaller during liquid reimbibition than during drainage. The use of gas-phase hysteresis for the CT test allows for a better matching of liquid volumes and pressure drop. Analysis of the simulated data suggests that the reduction in gas-phase mobility encourages an early increase in the oil rate, which is more consistent with experimental data than what is predicted by a model with conventional k r . The analysis also reveals that water distilled below the saturated steam temperature plays an important role in the increase of liquid saturation and oil mobilization.The improved characterization of relative permeability considering gas-phase hysteresis for simulating HPAI enhances the predictive capability of available commercial simulators, providing a more certain method to evaluate the technical and economical feasibility of a project. The ability to predict an early increase in oil rate, consistent with experimental observations, results in improved economics for the project.
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