Fatemeh Kamali

Co-optimizing enhanced oil recovery and CO2 storage by simultaneous water and CO2 injection

This paper presents a numerical simulation study to investigate whether simultaneous water and gas (SWAG) injection can co-optimize CO2 storage and enhanced oil recovery. Compositional displacements in a three-dimensional, layered reservoir model are modeled to examine different injection scenarios for maximizing oil recovery and CO2 storage capacity. The effects of various CO2-water ratios and different miscibility conditions on sweep efficiency, incremental oil recovery and CO2 storage capacity are investigated. Compositional changes of oil and gas phases, in the presence of mobile water in immiscible, near miscible or miscible SWAG injection are examined. Simulation results show that SWAG injection can enhance oil recovery compared to waterflooding and continuous CO2 injection by 6 to 21% the original oil in place. The optimum gas fraction in injection fluid increases as miscibility develops. When CO2 is injected simultaneously with water, 30–60% of injected CO2 can be stored with optimum injection ratios depending on the miscibility condition. On the contrary, in continuous gas injection, both oil recovery and CO2 storage capacity increase with miscibility. The simulation results also reveal that, for the reservoir studied, near miscible SWAG injection yields the highest oil recovery and storage efficiency in shortest operating duration.

A Dynamic Mesh Approach for Simulation of Immiscible Viscous Fingering

Viscous fingering is a major concern in the waterflooding of heavy oil reservoirs. Traditional reservoir simulators employ low-order finite volume/difference methods on structured grids to resolve this phenomenon. However, their approach suffers from a significant numerical dispersion error due to insufficient mesh resolution which smears out some important features of the flow. We simulate immiscible incompressible two phase displacements and propose use of unstructured control volume finite element (CVFE) methods for capturing viscous fingering in porous media. Our approach uses anisotropic mesh adaptation where the mesh resolution is optimized based on the evolving flow features. The adaptive algorithm uses a metric tensor field based on solution interpolation error estimates to locally control the size and shape of elements in the metric. We resolve the viscous fingering patterns accurately and reduce the numerical dispersion error significantly. The mesh optimization, generates an unstructured coarse mesh in other regions of the computational domain where a high resolution is not required. We analyze the computational cost of mesh adaptivity on unstructured mesh and compare its results with those obtained by a commercial reservoir simulator based on the finite volume methods.

Adaptive Mesh Optimization for Simulation of Immiscible Viscous Fingering

Viscous fingering can be a major concern when waterflooding heavy-oil reservoirs. Most commercial reservoir simulators use low-order finite-volume/-difference methods on structured grids to resolve this phenomenon. However, this approach suffers from a significant numerical-dispersion error because of insufficient mesh resolution, which smears out some important features of the flow. We simulate immiscible incompressible two-phase displacements and propose the use of unstructured control-volume finite-element (CVFE) methods for capturing viscous fingering in porous media. Our approach uses anisotropic mesh adaptation where the mesh resolution is optimized on the basis of the evolving features of flow. The adaptive algorithm uses a metric tensor field dependent on solution-interpolation-error estimates to locally control the size and shape of elements in the metric. The mesh optimization generates an unstructured finer mesh in areas of the domain where flow properties change more quickly and a coarser mesh in other regions where properties do not vary so rapidly. We analyze the computational cost of mesh adaptivity on unstructured mesh and compare its results with those obtained by a commercial reservoir simulator on the basis of the finite-volume methods.

Effect of Fractional Gas Injected on Gas Relative Permeability in Near-miscible SWAG Flood

Simultaneous water and gas (SWAG) injection is known as an efficient enhanced oil recovery method. Numerical simulations generally use the two-phase gas relative permeability (krg) to model three-phase SWAG processes where the same krg is used for different fractional gas injected (FGI) values. This approach does not account for the reduction in krg in presence of water. In this paper, we investigate the impact of FGI on krg for predicting SWAG flood performance through an experimental and simulation methodology. Core flooding experiments are performed at different FGI values on a sandstone sample. A mixture of hexane and decane is used as the oil phase and CO2 and water as injectants. Experiments are run at 70oC and 1700 psi which represents the near-miscible displacements for the given fluids. Oil recovery, differential pressure and compositions are recorded during experiments. Then history matching is conducted to estimate the FGI-dependent relative permeability function. Numerical simulations show that accurate modelling of SWAG displacement requires FGI dependent relative permeability. Considerable reduction in krg in SWAG, compared to conventional two-phase functions, improves the vertical sweep efficiency of CO2. The highest reduction is obtained in displacement with FGI=0.75.

How to Co-optimize Oil Recovery and CO2 Storage during CO2 EOR - A Laboratory Study

This paper presents experimental observations that delineate co-optimisation of CO2 EOR and CO2 storage. Supercritical CO2 was injected into a homogeneous Bentheimer sandstone sample under various miscibility conditions. A two-component hydrocarbon system (65% hexane and 35% decane) was used to represent the oil phase. Three experiments were run at the same temperature (70oC) but different pressures (1,300, 1,700 and 2,100 psi). These pressures were determined using a PCT simulator before the experiments in order to obtain immiscible, near miscible and miscible conditions. Oil recovery and CO2 saturation were recorded during experiments. A co-optimisation function is defined and was calculated using the measured data for each experiment. Experimental observations demonstrate that oil recovery during miscible and near miscible displacement is almost the same while it is 20% less in the immiscible displacement. We note that heavier hydrocarbons produced from miscible and near miscible displacements are much higher than the immiscible displacement. On the other hand, CO2 is stored in the rock sample more efficiently during the near miscible displacement. The co-optimisation function also suggests that the near miscible displacement offers the best performance for coupling CO2 EOR and storage.

Optimizing Enhanced Oil Recovery and CO2 Storage by Simultaneous Water and CO2 Injection

Simultaneous water and gas (SWAG) injection is one of the effective secondary/tertiary enhanced oil recovery methods which can boost the sweep efficiency of a CO2/EOR project dramatically. Moreover, geological storage of CO2 in depleted or mature oil reservoirs is considered as a long-term controlling method of CO2 emissions into the atmosphere. This paper applies a defined objective function to co-optimize oil production of SWAG injection process and its CO2 storage efficiency. A compositional simulation study was carried out to examine the effect of various CO2-water ratios in SWAG process in different miscibility conditions on sweep efficiency, ultimate oil production and the stored CO2 in the reservoir during the process. Simulation results show that oil recovery can be increased 13-36% OOIP in SWAG injection compared to water flooding and continuous CO2 injection while SWAG optimum gas fraction is a direct function of reservoir pressure. Moreover, CO2 storage capacity when CO2 is injected simultaneously with water is 30-70% of the injected CO2 and this value decreases by miscibility. However, in CGI both oil production and CO2 storage increase with miscibility. The simulation results also reveal that the CO2 storage efficiency of near miscible SWAG and CGI process are almost the same.

Recovery based ranking oil reservoir for CO2 miscible injection

The use of CO2 for enhanced oil recovery of the Iranian oil reservoirs offers a unique opportunity to boost incremental oil recovery and reducing emissions of greenhouse gas through geological sequestration. In this paper, oil fields were screened and ranked for CO2 EOR suitability using new rapid and parametric method which can be applied to a large number of reservoirs with considering the technical feasibility of the EOR process and utilized eight essential reservoir properties: API gravity, oil saturation, ratio of reservoir pressure to minimum miscibility pressure (MMP), reservoir temperature, reservoir dip, net oil thickness, permeability and porosity via a developed program. By using this methodology, a systematic screening and ranking of all possible Iranian oil reservoirs was carried out. Evaluation and prediction of the efficiency of CO2 flooding technique were performed for candidate reservoirs by using an analytical method. In addition, a commercial stream-line type model was used to compare the results of this screening which clearly proves the pervious outcomes. Finally, best candidates were chosen by considering suitable distance from CO2 sources.