Near-miscible Gas Injection Research Articles

A Mass-Conservative Sequential Implicit Multiscale Method for Isothermal Equation-of-State Compositional Problems

SummaryCompositional simulation is necessary for a wide variety of reservoir-simulation applications, and it is especially valuable for accurate modeling of near-miscible gas injection for enhanced oil recovery. Because the nonlinear behavior of gas injection is sensitive to the resolution of the simulation grid used, it is important to use a fine grid to accurately resolve the compositional and saturation gradients. Compositional simulation of highly detailed reservoir models entails the use of small timesteps and large, poorly conditioned linear systems. The high computational cost of solving such systems renders field-scale simulations practically unfeasible. The coupling of the flow and transport to the phase-equilibrium calculations adds to the challenge. This is especially the case for near-miscible gas injection, in which the phase state and the phase compositions are very strong functions of space and time.We present a multiscale solver for compositional displacements with three-phase fluid flow. The thermodynamic phase behavior is described by general nonlinear cubic equations of state (EOS). The fully implicit (FI) natural-variables formulation is used as the basis to derive a sequential implicit (SI) solution strategy, whereby the pressure field is decoupled from the multicomponent transport. The SI scheme is mass conservative without the need to iterate between the pressure and transport equations during the timestep. This conservation property allows the errors caused by fixing the total-velocity field between the pressure- and transport-updating steps to be represented as a volume error. The method computes approximate pressure solutions—within a prescribed residual tolerance—that yield conservative fluxes on the computational grid of interest (fine, coarse, or intermediate). We use basis functions computed using restricted smoothing to allow for generally unstructured grids.The new method is verified against existing research and commercial compositional simulators using a simple conceptual test case and also using more-complex cases represented on both unstructured and corner-point grids with strong heterogeneity, faults, and pinched-out and eroded cells.The SI method and the implementation described here represent the first demonstrated multiscale method applicable to general compositional problems with complexity relevant for industrial-reservoir simulation.

Application of Streamline Simulation to Gas Displacement Processes

Performance evaluation of miscible and near-miscible gas injection processes is available through conventional finite difference (FD) compositional simulation. Streamline methods have also been developed in which fluid is transported along the streamlines instead of using the finite difference grid. In streamline-based simulation, a 3D flow problem is decoupled into a set of 1D problems solved along streamlines. This reduces simulation time relative to FD simulation, and suppresses the numerical dispersion errors that are present in FD simulations. Larger time steps and higher spatial resolution can be achieved in these simulations. Thus, streamline-based reservoir simulation can be orders of magnitude faster than the conventional finite difference methods. Streamline methods are traditionally only applied to incompressible flow processes. In this paper, the method is adopted and assessed for application to compressible flow processes. A detailed comparison is given between the results of conventional FD simulation and the streamline approach for gas displacement processes. Finally, some guidelines are given on how the streamline method can potentially be used to good effect for gas displacement processes.

Relative Permeability of Near-Miscible Fluids in Compositional Simulators

Miscible gas injection is one of the most effective enhanced oil recovery techniques. There are several challenges in accurately modeling this process, which occurs in the near-miscible region. The adjustment of relative permeability for near-miscible processes is the main focus of this work. The dependence of relative permeability on phase identification can lead to significant complications while simulating near-miscible displacements. We present an analysis of how existing methods incorporate compositional dependence in relative permeability functions. The sensitivity of the different methods to the choice of reference points is presented with guidelines to limit the modification of the relative permeabilities to physically reasonable values. We distinguish between the two objectives of reflecting near-miscible behavior and ensuring smooth transitions across phase changes. We highlight an important link that combines the two objectives in a more general framework. We make use of Gibbs free energy as a compositional indicator in the generalized framework. The new approach was implemented in an automatic differentiation general purpose research simulator and tested on a set of near-miscible gas-injection problems. We show that including compositional dependencies in the relative permeability near the critical point impacts the simulation results with significant improvements in nonlinear convergence.

Recovery Mechanisms and Relative Permeability for Gas/Oil Systems at Near-Miscible Conditions: Effects of Immobile Water Saturation, Wettability, Hysteresis, and Permeability

Near-miscible gas injection represents a number of processes of great importance to reservoir engineers, including hydrocarbon gas injection and CO2 flood. Very little experimental data is available in the literature on displacements involving very low interfacial tension (IFT). In this paper, we present the results of a series of two- and three-phase gas injection (drainage) and oil injection (imbibition) core flood experiments for a gas/oil system at near-miscible (IFT = 0.04 mN m–1) conditions. Two different cores, a high-permeability (1000 mD) and a lower permeability (65 mD) core, were used in the experiments, and both water- and mixed-wet conditions were examined. The results show that, despite a very low gas/oil IFT, there is significant hysteresis between the imbibition and drainage oil and gas relative permeability (kr) curves in the 65 mD core. Hysteresis was less for the 1000 mD core (in comparison to the 65 mD core), but it still could not be ignored. Near-miscible kr hysteresis was significan...

Nonlinear Formulation Based on an Equation-of-State Free Method for Compositional Flow Simulation

Summary Compositional simulation is necessary for modeling complex enhanced oil recovery (EOR) processes. For accurate simulation of compositional processes, we need to resolve the coupling of the nonlinear conservation laws, which describe multiphase flow and transport, with the equilibrium phase behavior constraints. The complexity of the problem requires extensive computations and consumes significant time. This paper presents a new framework for the general compositional problem associated with multicomponent multiphase flow in porous media. Here, adaptive construction and interpolation using the supporting tie lines are used to obtain the phase state and the phase compositions. For the parameterization of the full solution of a complex compositional problem, we need only a limited number of supporting tie lines in the compositional space. The parameterized tie lines are triangulated using Delaunay tessellation, and natural-neighbor interpolation is used inside the simplexes. Then, the computation of the phase behavior in the course of a simulation becomes an iteration-free, table look-up procedure. The treatment of nonlinearities associated with complex thermodynamic behavior of the fluid is based on the new set of unknowns—tie-line parameters that allow for efficient representation of the subcritical region. For the supercritical region, we use the standard compositional variable set based on the overall composition. The efficiency and accuracy of the method are demonstrated for several multidimensional compositional problems of practical interest. In terms of the computational cost of the thermodynamic calculations, the proposed method shows results comparable to those of state-of-the-art techniques. Moreover, the method shows better nonlinear convergence in the case of near-miscible gas-injection simulation.

Visualisation of Residual Oil Recovery by Near-miscible Gas and SWAG Injection Using High-pressure Micromodels

We present results of high-pressure micromodel visualizations of pore-scale fluid distribution and displacement mechanisms during the recovery of residual oil by near-miscible hydrocarbon gas and SWAG (simultaneous water and gas) injection under conditions of very low gas–oil IFT (interfacial tension), negligible gravity forces and water-wet porous medium. We demonstrate that a significant amount of residual oil left behind after waterflooding can be recovered by both near-miscible gas and SWAG injection. In particular, we show that in both processes, the recovery of the contacted residual oil continues behind the main gas front and ultimately all of the oil that can be contacted by the gas will be recovered. This oil is recovered by a microscopic mechanism, which is strongly linked to the low IFT between the oil and gas and to the perfect spreading of the oil over water, both of which occur as the critical point of the gas–oil system is approached. Ultimate oil recovery by near-miscible SWAG injection was as high as near-miscible gas injection with SWAG injection using much less gas compared to gas injection. Comparison of the results of SWAG experiments with two different gas fractional flow values (SWAG ratio) of 0.5 and 0.2 shows that fractional flow of the near-miscible gas injected simultaneously with water is not a crucial factor for ultimate oil recovery. This makes SWAG injection an attractive IOR (improved oil recovery) process especially for reservoirs, where continuous and high-rate gas injection is not possible (e.g. due to supply constraint).

Microscopic Mechanisms of Oil Recovery By Near-Miscible Gas Injection

As gas flooding becomes a more viable means of enhanced oil recovery, it is important to identify and understand the pore-scale flow mechanisms, both for the development of improved gas flooding applications and for the predicting phase mobilisation under secondary and tertiary gas flooding. The purpose of this study was to visually investigate the pore-level mechanisms of oil recovery by near-miscible secondary and tertiary gas floods. High-pressure glass micromodels and model fluids representing a near-miscible fluid system were used for the flow experiments. A new pore-scale recovery mechanism was identified which significantly contributed to oil recovery through enhanced flow and cross-flow between the bypassed pores and the injected gas. This mechanism is strongly related to a very low gas/oil interfacial tension (IFT), perfect wetting conditions and simultaneous flow of gas and oil in the same pore, all of which occur as the gas/oil critical point is approached. The results of this study helps us to better understand the pore-scale mechanisms of oil recovery in very low-IFT (near-miscible) systems. In particular we show that in near-miscible gas floods, behind the main gas front, the recovery of the oil continues by cross-flow from the bypassed pores into the main flow stream and as a result almost all of the oil, which has been contacted by the gas, could be recovered. Our observations in high-pressure micromodel experiments have demonstrated that this mechanism can only occur in near-miscible processes (as opposed to immiscible and completely miscible processes), which makes oil displacement by near-miscible gas floods a very effective process.

Proper Use of Equations of State for Compositional Reservoir Simulation

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized to be experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Summary Equation-of-state (EOS) compositional reservoir simulation is an accurate and powerful means to model complicated phase and flow behavior involved in the displacement of oil and gas in porous media. The use of EOS simulation becomes even more effective when the process involves solvent injection for miscible or near-miscible displacement of crude oil in reservoirs. The current trend of combining the simulation of reservoirs and surface facilities increases the demand for the use of EOS compositional models. One key to proper use of compositional simulators is development of an EOS for describing the phase behavior of the fluids. This paper is a summary of experiences and developments in the use of EOS's for compositional reservoir simulation studies. The reader is referred to the recent monograph by Whitson and Brulé1 for a more complete treatment of the volumetric and phase behavior of petroleum fluids and the use of EOS's to model these fluids. Introduction When the displacement process depends on pressure and fluid composition, an EOS should be used to simulate the equilibrium mass transfer between phases and the pressure/volume/temperature (PVT) behavior of the fluids. PVT laboratory measurements are made on only a small portion of the composition path encountered throughout the displacement, whereas an EOS can be used to predict behavior for the entire composition path and pressure range of the process. Many field development projects have strong composition dependence, such as production from gas/condensate reservoirs, miscible and near-miscible gas injection, or water-alternating-gas injection for enhanced oil recovery. Until very recently, industry practice was to use a black-oil model and/or its modified versions2,3 or a limited-composition reservoir simulator4,5 to approximate the complicated phase behavior. These simplified approaches require less computer time and memory and can provide a quick preliminary evaluation of reservoir performance. However, efforts by industry and universities have led to rapid advancements in parallel-computer hardware and software during the last several years, which have increased simulation efficiency considerably6–9 and now make compositional simulation practical. Also, most of the commercially available EOS compositional simulators and in-house models have been improved significantly in terms of robustness, efficiency, and features. More frequent use of EOS compositional simulators should be expected in the future. However, uncertainties still exist that are associated with the use of an EOS to model petroleum reservoir fluids because of the complicated nature of such fluids and limitations of the most commonly used EOS's. Tuning the adjustable EOS parameters to match experimental fluid PVT data is a common practice. The proper use of EOS models for reservoir applications has been an active research topic since the 1970's. Although significant progress in this area has been made, engineers still face several challenging questions: How many fluid components should be used? How much experimental data and what kind of data are needed to tune an EOS? How good is the predictive power of an EOS that matches all of the experimental data available? What are limitations of the commonly used EOS's for hydrocarbons when the gas or oil contains significant concentrations of components other than hydrocarbons? Which EOS should be used when more than one option is available in a reservoir simulator? Representative-Sample Collection The accuracy of any EOS model depends on the quality of the laboratory PVT data and procedures used to obtain the EOS parameters. The value of the PVT data depends on the quality of the fluid samples. They must be representative of the reservoir fluid. Three common methods are used to sample the reservoir fluid. Downhole Sampling. A sample collector with a capacity of several hundred cubic centimeters is used to obtain a fluid sample from within the wellbore. The downhole flowing pressure at the sampling point must be greater than the saturation pressure of the fluid so that the sample is a single phase. At least three fluid samples should be collected to determine the appropriate fluid sample for the PVT measurements. Wellhead Sampling. A fluid sample can be collected directly from the wellhead. The fluid needs to be in the single-phase region at wellhead flowing conditions. Normally, the sample needs to be taken at a pressure of at least 100 psi greater than the bubblepoint to be valid. Again, taking multiple samples is recommended.

Effect of Wettability on Oil Recovery by Near-Miscible Gas Injection

Summary Oil can become bypassed during gas injection as a result of gravitational, viscous, and heterogeneity effects. Mass transfer from the bypassed region to the flowing gas is dependent upon pressure-driven, gravity-driven, and capillary-driven crossflows as well as diffusion and dispersion. The focus of this study is on the influence that wettability has on bypassing and mass transfer. Experimental results reveal comparatively less bypassing occurs in a strongly oil-wet sandstone than in a water-wet sandstone for gravity-dominated, secondary gasfloods. Mass transfer under oil-wet conditions is enhanced, as a result of oil-wetting film connectivity, over that of water-wet conditions, where water shielding is significant.

Effect of Wafer Saturation on Oil Recovery by Near-Miscible Gas Injection

SummaryDuring gas injection, bypassing of oil is common because of gravitational, viscous, and/or heterogeneity effects. The oil in the bypassed regions can be recovered through enhanced flow and mass transfer between the bypassed region and the injectant gas. Previously, experiments in our laboratory have been carried out to evaluate the effects of phase behavior and capillary crossflow in near-miscible gasfloods; however, these studies were conducted in the absence of water. In this paper, we evaluate the effects of water saturation on oil bypassing and the rate of mass transfer from the bypassed zones. Injectant gases are first-contact miscible (FCM), multicontact miscible (MCM), or submiscible with the bypassed oil. Gasfloods are conducted in different orientations with different levels of water saturation. Mass-transfer experiments are carried out to isolate and investigate mass-transfer mechanisms. Results indicate that oil recovery from vertical, submiscible gasfloods is not influenced by water-saturation level. Horizontal gasfloods showed evidence of less gravity override in the presence of water. The mass-transfer experiments showed that recovery increases with enrichment and is reduced by the presence of water. Effective diffusion coefficients are estimated as functions of water saturation and enrichment.

Scale-up of near-miscible gas injection processes; integration of laboratory measurements and compositional simulation

Results from laboratory PVT measurements, special core analysis studies, and reservoir condition core-flood studies were used to develop and test the accuracy of a compositional simulation model in predicting near-multicontact miscible gas flood performance at the laboratory scale. Excellent agreement was obtained between the core-flood measured recoveries and GOR and the compositional simulation model predictions. No history matching was required to obtain this result. The choice of PVT and special core tests were critical to our ability to model the near-multicontact miscible displacement process without history matching. This result provides a high degree of confidence in using the compositional simulation model in cross-section and 3D element models to predict field-scale performance. Cross-sectional simulation sensitivities were performed in a geostatistical model of a dipping reservoir. Gas-flood recovery was on par with water-flood recovery for this cross-section.