Remaining oil saturation, trapped gas saturation, three-phase relative permeability and injectivity are among the many parameters that play a major role in miscible CO2 water-alternating-gas (WAG) injection efficiency. In this work, we present a series of coreflood experiments designed to assess these parameters and investigate the microscopic efficiency of CO2 WAG injection on carbonated reservoirs, far above minimum miscibility pressure (MMP). Experiments were carried out on intermediate-wet carbonate cores, initially saturated with light oil from a Middle East field, at reservoir conditions. Production was monitored at both reservoir and laboratory conditions providing material balance of each phase and separating the production of flashed oil, condensate and gas. A full compositional analysis was performed on produced volumes using gas chromatography (GC) and liquid analysis of flashed oil and condensate. Differential pressure across the core was also monitored for relative permeability estimation. Finally, a dual energy X-Ray scanner was used to measure three phase in-situ saturations, cross check material balance results and ensure that laboratory artifacts (end effects) do not influence interpretation conclusions. Coreflood data was complemented with PVT experiments including CO2-oil phase behavior characterization through multiple contact test (MCT) and supercritical fluid extraction (SFE). CO2 WAG injections showed great performance with faster and better recovery than pure CO2 injection. After several cycles of WAG injections, high levels of differential pressure across the core were reached due to a reduction in both water and gas relative permeabilities with injection cycles.
Good prediction of the performance of water-alternating-gas (WAG) processes relies on the proper estimation of three-phase relative permeabilities and their hysteresis with injection cycles. This is often a lengthy and expensive procedure requiring the numerical interpretation of several WAG corefloods, usually performed at reservoir conditions. In this paper, we propose an automated procedure based on multi-experiment optimization, leading to a consistent set of three-phase hysteresis parameters for all available experimental data. We apply it to two near-miscible WAG coreflood experiments that differ in the number and length of their injection cycles (long slugs versus short slugs). Both experiments were performed at reservoir conditions on a horizontal sandstone core, with light oil from a West African field and below minimum miscibility pressure. These experiments were carried out using extensive monitoring, including material balance at standard and reservoir conditions, full compositional analysis of liquids and gas produced at standard conditions, differential pressure measurements across the core and three-phase in situ saturations using a dual energy X-ray scanner. History-matching results were obtained by coupling our optimization tool with an in-house research reservoir simulator (IHRRS), combining an advanced EoS-based equilibrium relaxation model with a three-phase relative permeability hysteresis model. Optimization was performed with the Nelder-Mead algorithm, using a relatively large number (>10) of fitting parameters to model the relative permeability functions and their hysteresis. Multiple sets of parameters were easily obtained to match each experiment individually, suggesting that the history-matching of a single experiment is poorly constrained. As expected, muti-experiment optimization led to a better constrained but more challenging problem to solve; yet all available data could be matched reasonably well with a common set of parameters and several acceptable solutions were found. By providing a more robust estimation of three-phase hysteresis parameters, the proposed method increases the reliability of our simulation-based interpretations, necessary to evaluate the stakes of a WAG project.
Conventional miscible or near-miscible gas flooding simulation often overestimates oil recovery, mostly because it does not capture a series of physical effects tending to limit interphase compositional exchanges. Those can be for instance microscopic bypassing of oil situated in dead-end pores or blocked by water films, as well as macroscopic bypassing due to sub-grid size heterogeneities or fingering.We here present a new engineering solution to this problem in the near-miscible case, relying on our in-house research reservoir simulator (IHRRS). The principle is, while using a black-oil or an equation of state description, to dynamically decrease the K-value of heavy components and possibly increase the K-value of light components as the oil saturation reaches the desired residual limit; this enables changing the phase boundaries when needed while preserving the original fluid behavior during the initial production stages.The benefits of the proposed method are demonstrated on a reservoir conditions tertiary gas injection experiment, performed in our laboratories, for which residual saturations as well as oil phase and individual components production rate have easily and successfully been history matched. Results are then compared to matches obtained using saturation exclusion and ␣-factors methods. As a proof of concept, suitability of the method to simulate incomplete revaporization of condensate during gas cycling is also illustrated, on the third SPE comparative solution project case.
Summary Conventional miscible or near-miscible gasflooding simulation often overestimates oil recovery, mostly because it does not capture a series of physical effects tending to limit interphase compositional exchanges. Those can include microscopic bypassing of oil situated in dead-end pores or blocked by water films, as well as macroscopic bypassing caused by subgrid-size heterogeneities or fingering. We here present a new engineering solution to this problem in the near-miscible case, relying on our in-house research reservoir simulator. The principle is, while using a black-oil or an equation-of-state description, to dynamically decrease the K-value of heavy components and possibly increase the K-value of light components as the oil saturation reaches the desired residual limit; this enables changing the phase boundaries when needed while preserving the original fluid behavior during the initial production stages. The benefits of the proposed solution are demonstrated on a reservoir-conditions tertiary-gas-injection experiment, performed in our laboratories, for which residual saturations as well as oil-phase and individual-component production rates have easily and successfully been history matched. Results are then compared with matches obtained by use of saturation exclusion and α-factors methods. As a proof of concept, the suitability of the new method to simulate incomplete revaporization of condensate during gas cycling is also illustrated, on the third SPE comparative-solution-project case.
The interpretation of multiple water-alternating-gas (WAG) experiments carried out with different injection strategies (first injected fluid, lengths of injected slugs) is necessary to improve our understanding of WAG mechanisms and to build a reasonably predictive three-phase relative permeability model for reservoir simulation. This paper presents an extension to the well-known three-phase hysteresis model of Larsen & Skauge and its application to interpret an extensive series of WAG experiments carried out under mixed-wet conditions, on the same low permeability sandstone core, at three different levels of gas-oil interfacial tension (IFT), namely 0.04 (low), 0.15 (intermediate) and 2.7 mN.m−1(high). After presenting the main experimental results, we describe an extended formulation – which was implemented in our in-house research reservoir simulator (IHRRS) – where the conventional Land formalism for the calculation of imbibition scanning curves and gas trapping is replaced by a more general model allowing arbitrary trapping functions and accounting for the nature of the displacing fluid (oil, water, or a mixture of both). This new approach – which is thought to be necessary for accurate modeling of WAG processes in mixed-wet systems and/or when gas-water and gas-oil IFTs differ significantly – is used within a history-matching workflow to generate multiple sets of fitting parameters consistent with the experimental data. For each IFT, an experimental dataset consisting of a gasflood and two long slugs (> 1 PV) WAG corefloods starting with either gas or water was history-matched. Each individual WAG coreflood was first interpreted together with the corresponding gasflood data, and then a simultaneous history-matching of all the coreflood data was attempted. An acceptable match of the experiments could only be obtained by restricting the common set of fitting parameters and by introducing a trapping model tuned to the experimental data and accounting for a different amount of trapped gas in the presence of an oil bank (observed in some experiments). This work offers new insights on the methodology to follow and the physical aspects to be improved, such as the gas imbibition scanning curves under three-phase flow conditions, in order to build a more reliable three-phase hysteresis model, capable of predicting multiple injection strategies and applicable to different wettabilities and gas-oil IFTs.
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