A New Approach to Compositional Modeling of CO2 Injection in Fractured Media Compared to Experimental Data

Abstract

In a recent PhD dissertation (Darvish 2007), data and modeling are presented from an experiment in which CO2 is injected in a tall vertical core, surrounded by fractures. After injecting CO2 for 22 days, 65% of the oil in place is recovered (and still increasing). However, the modeling with a commercial simulator results in only 12% recovery, despite adjusting parameters. We will discuss inherent flaws in current simulators that impede realistic simulation of CO2 injection in fractured media, even at laboratory scales. These issues include: problems in accounting for phase behavior effects and Fickian diffusion in dualporosity models, and excessive numerical diffusion in all simulators that use the finite difference methods. To improve on these weaknesses, we use a higher-order algorithm based on the combined discontinuous Galerkin, mixed hybrid finite element and discrete fracture techniques. We extend that model here to include a self-consistent model for Fickian diffusion, and time splitting in an improved-implicit-pressure-explicit-composition (IIMPEC) scheme. With this new approach, we can reproduce all experimental results in Darvish (2007). The results further confirm the prospects of CO2 injection for enhanced oil recovery in fractured reservoirs. Introduction The growing awareness and concern regarding the ecological and economic threats posed by global warming have triggered a high interest in the sequestration of CO2, produced by burning of fossil fuels, in either saline aquifers or oil reservoirs. The financial burden of such plans may be greatly alleviated by the growing proof that CO2 injection may significantly improve oil recovery as a secondary or tertiary recovery mechanism in fractured reservoirs. Irrespective of the global warming aspects, recovery in many of the world's largest oil reservoirs is declining, following primary and secondary recovery. CO2 injection is attracting the most new market interest as an enhanced oil recovery (EOR) mechanism and is, for instance, being piloted by the Department of Energy in a number of reservoirs, using geological as well as industrial sources of CO2 (DOE 2008). In light of this, a proper understanding of CO2 injection in oil reservoirs and saline aquifers is essential to both governments and the industry. Governments do not, for instance, currently allow trading of carbon bonds under the Kyoto treaty for CO2 injection in oil reservoirs over concerns of CO2 breakthrough at later times, back into the atmosphere. For the industry, reliable estimates of the incremental oil recovery have to justify the cost of a CO2 supply (capture and/or transport). Due to the exceedingly large scale of field problems, most commercial simulators employ highly simplified models that may or may not capture the essential physics. In particular, there are concerns regarding the accuracy and flexibility of finite difference methods and of dual-porosity models in modeling the fracture-matrix interactions. Fickian diffusion poses further challenges that have not been resolved in dual-porosity models (a literature overview is given in Hoteit and Firoozabadi 2009). To gain further insight in the fundamental physical aspects of CO2 injection in fractured reservoirs, we consider a rich dataset provided by experiments (Darvish 2007), in which CO2 is injected at the top of a tall cylindrical chalk core saturated with live oil and surrounded by fractures. These data provide a unique test-bed for our compositional modeling, which uses higherorder methods for increased numerical accuracy in the computation of the velocity and pressure fields as well as mass transport and handles fractures as discrete 1D elements in a 2D domain algorithm (Hoteit and Firoozabadi 2005, 2006a,b, 2009). We have implemented a new model for Fickian diffusion coefficients, based on irreversible thermodynamics (Leahy-Dios and Firoozabadi 2007), to better model the diffusion in the injection experiment.

Effect of Salinity and Pressure on the Rate of Mass Transfer in Aquifer Storage of CO2

“…A denser phase above a less dense phase initiates convective currents that enhance the dissolution rate, thus accelerating dissolution of CO 2 in the aqueous phase. The initial stage of natural convection in a saturated porous layer with a denser fluid on top of a lighter fluid has been extensively studied by means of a linear stability analysis, numerical simulations and the energy method ( (Bachu et al, 1994;Class et al, 2009;Dentz and Tartakovsky, 2009;Elder, 1968;Ennis-King et al, 2005;Foster, 1965;Gasda, 2010;Khosrokhavar et al, 2014c;Meulenbroek et al, 2013;Moortgat et al, 2009;Myint and Firoozabadi, 2013;Nordbotten and Celia, 2011;Nordbotten et al, 2005;Pruess et al, 2003;Ranganathan et al, 2012;Riaz et al, 2006;Van Duijn et al, 2004;Walker and Homsy, 1978)). …”

Reservoir Fluid Characterization for Tight Fractured Reservoirs: Effect of Diffusion

“…Molecular diffusion effect is important when we simulate gas injection processes in fractured media (Moortgat et al 2009; Yanze and Clemens 2012). Molecular diffusion has been ignored in many conventional reservoir simulation cases, but it can play a significant role in tight fractured reservoirs.…”

Experimental and Simulation of CO2-Foam Flooding in Fractured Chalk Rock at Reservoir Conditions: Effect of Mode of Injection on Oil Recovery

“…The capillary pressure contrast between the fracture and the matrix may also contribute to the low recovery efficiency in fractured reservoirs (Firoozabadi and Markeset, 1994). However, there is growing evidence that CO 2 injection can significantly improve oil recovery as a secondary or tertiary recovery mechanism in fractured reservoirs (Moortgat et al 2009). Laboratory experiments (Darvish et al 2006a, b;Darvish et al 2004;Øyno et al 1995) and simulation studies (Moortgat et al 2009;Alavian and Whitson, 2005;Darvish et al 2004) have demonstrated that CO 2 at elevated pressures can recover oil in fractured reservoirs.…”

“…However, there is growing evidence that CO 2 injection can significantly improve oil recovery as a secondary or tertiary recovery mechanism in fractured reservoirs (Moortgat et al 2009). Laboratory experiments (Darvish et al 2006a, b;Darvish et al 2004;Øyno et al 1995) and simulation studies (Moortgat et al 2009;Alavian and Whitson, 2005;Darvish et al 2004) have demonstrated that CO 2 at elevated pressures can recover oil in fractured reservoirs. In principle, the development of miscibility or near-miscibility may eliminate or reduce the capillary pressure contrast and enable the recovery of residual oil.…”

“…However, the behaviour of a particular CO 2crude oil mixture depends on parameters such as concentration of CO 2 , oil composition, temperature and pressure. During miscible CO 2 -EOR processes in fractured reservoirs, the overall oil recovery and transport of CO 2 will be controlled by a number of mechanisms such as viscous and capillary flow, diffusive and gravity forces (Berenblyum et al 2008;Darvish et al 2006a, b;Asghari and Torabi, 2008;Moortgat et al 2009). The influence on the displacement process of factors such as the phase behaviour of CO 2 -crude oil mixtures, swelling of oil by dissolved CO 2 , reduction of oil viscosity, IFT and pore-size distribution has been extensively studied (Hao et al 2004;Ghedan, 2009).…”