document preview

Abstract
This paper presents a modeling study of CO2 injection in chalk core base on data reported by Darvish (2007). The experiment consisted of a vertically-oriented 60 cm long chalk outcrop core initially saturated with live reservoir oil at 130oC and 300 bar. After saturating the core with oil and water by displacement, a small fracture volume surrounding the core was created by heating solid Wood’s metal that originally filled the volume between the core and core holder. CO2 was then injected for 20 days. The experiment was performed at a pressure above the minimum miscibility pressure (MMP), as defined by a traditional 1D multi-contact displacement process.

Our modeling was conducted with a compositional reservoir simulator. The 2-dimensional r-z model used fine grid for the core matrix and surrounding fracture. The match of reported oil and water production data gave a high degree of confidence in the model. Mass fractions of components measured periodically during the experiment were also matched.

Our modeling study indicates that gravity drainage is affecting the displacement process but mass transfer including vaporization, condensation and molecular diffusion has a significant impact on recovery performance for CO2 injection in the Darvish experiment. Another observation made in our study was the strong influence of surface separator temperature on surface oil production. CO2 injection rate and initial water saturation effects were investigated by comparing this experiment with similar experiments where CO2 was injected at lower rates, and tests with no initial water saturation.

Introduction
CO2 injection has been considered as potentially enhancing oil recovery from naturally fractured reservoirs. Alavian and Whitson (2010a) study the IOR potential for CO2 injection in the naturally-fractured Haft Kel field, Iran, based on detailed compositional simulations of the matrix-fracture system. Obviously, it would be useful to experimentally investigate the efficiency of gas injection in naturally fractured reservoirs, followed by CO2 injection, before this procedure is applied to a
reservoir.

Few experiments are reported in the literature to studying gravity drainage in CO2 injection in fractured reservoirs. Li et al. (2000) perform CO2 injection after water flooding in a dead oil system. They studied water imbibition followed by CO2 injection on artificially fractured cores. They report that CO2 gravity drainage could significantly increase oil recovery after water flooding. They found that CO2 gravity drainage declines as the rock permeability decreases and initial water saturation increases. Asghari and Torabi (2008) conduct miscible and immiscible CO2 gravity drainage experiments with dead oil (n- C10). They show miscible CO2 injection improves oil recovery, but they could not match laboratory experiment with a simulation model. Karimaie (Karimaie 2007, Karimaie and Torsæter 2008) performed equilibrium gas injection followed by CO2 experiments on chalk and carbonate cores at reservoir conditions where cores were saturated with live synthetic oil. The experiments were designed to illustrate CO2 injection in a fractured reservoir, but fracture permeability so low that it affected the production performance (Alavian and Whitson 2011). 

Trivedi and Babadagli (2008) investigated injection flow rate effect on first contact miscible displacement. They used heptane (C7) as solvent with kerosene and mineral oil at atmospheric condition. They reported that higher solvent injection rate yield higher production rate of oil at early stage of the experiment. However lower injection rate resulted in higher ultimate oil recovery. Er, Babadagli and Zhenghe (2010) investigated micro scale matrix/fracture interaction during CO2 injection in naturally fractured reservoir. They used glass bead model with normal decane (n-C10) as oil and CO2 as solvent.