Mathematical Problems in Engineering

Volume 2016, Article ID 2562971, 9 pages

http://dx.doi.org/10.1155/2016/2562971

## Simulation Study on Miscibility Effect of CO_{2}/Solvent Injection for Enhanced Oil Recovery at Nonisothermal Conditions

Department of Natural Resources and Environmental Engineering, Hanyang University, 222 Wangsimni-ro, Seongdong-gu, Seoul 04763, Republic of Korea

Received 13 October 2015; Revised 8 January 2016; Accepted 13 January 2016

Academic Editor: Chaudry Masood Khalique

Copyright © 2016 Moon Sik Jeong and Kun Sang Lee. This is an open access article distributed under the Creative Commons Attribution License, which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

#### Abstract

The minimum miscibility pressure (MMP) determines the main mechanism of CO_{2} flooding, which is either an immiscible or miscible process. This paper examines the recovery improvements of CO_{2} flooding in terms of both the injection temperature and solvent composition. The results show that a lower temperature injection and LPG (liquefied petroleum gas) mixture can considerably improve oil recovery due to the reduced MMP in the swept area caused by the injected solvent. For the pure CO_{2} injection at the reservoir temperature, oil recovery is 59% after 1.0 PV CO_{2} injection. The oil recoveries by CO_{2}-LPG mixtures are improved to 73% with 0.1 mole fractions of LPG and 81% with 0.2 mole fractions of LPG. The recovery factor from low-temperature CO_{2} injection is 78%, which is 32% higher compared to the isothermal case. The recoveries obtained by low-temperature CO_{2}-LPG injection increase up to 87% of the initial oil. Heat transfer between the reservoir and the formation of over/underburden should be considered in order to describe the process more accurately. Additionally, the recovery factors from the heat transfer models are decreased by 4–12% in comparison with the original nonisothermal models.

#### 1. Introduction

CO_{2} flooding is a common process used to enhance oil recovery for light to medium crude oil and is generally implemented to recover the remaining oil after waterflooding [1, 2]. The performance of CO_{2} flooding is mainly affected by the minimum miscibility pressure (MMP). The MMP of CO_{2} is known to depend on various parameters including the temperature, pressure, molecular weight of the heavy fraction, and composition of the injecting solvent [3–12]. Generally, high temperature and large mole fractions of the heavy component result in a high MMP [13].

To examine the effects of temperature on the MMP and recovery factor of CO_{2} flooding, a number of experimental studies have been conducted. Holm and Josendal [4] defined a simple correlation for the CO_{2} MMP versus the reservoir temperature and C_{5+} molecular weight of the oil. Stalkup [5] showed that the CO_{2} purity, oil composition, and reservoir temperature determine the MMP. Yellig and Metcalfe [6] stated that the CO_{2} MMP is significantly influenced by the reservoir temperature. Johnson and Pollin [8] looked at the molecular weight, oil gravity, reservoir temperature, and injection gas composition in an attempt to improve the accuracy of MMP correlation. Alston et al. [9] analyzed the temperature, C_{5+} molecular weight, volatile oil fraction, intermediate oil fraction, and composition of the injected CO_{2}.

Low-temperature injection was first applied by Shu [14]. Injection of a coolant decreases the MMP, thereby increasing the recovery. He suggested an equation to calculate the CO_{2} MMP reduction in terms of the coolant volume. This equation, however, assumes that the injected fluids are entirely mixed with the reservoir oil. Khanzode [15], Wang [16], and Wang et al. [17] performed numerical simulations to prove the potential of reservoir cooling for enhanced oil recovery from CO_{2} injection. They considered temperature gradients in realistic reservoir situations. Although the injection composition, like the injection temperature, is known to affect the MMP, these simulation studies only considered the effect of the injection temperature on the MMP.

CO_{2} can be injected in an immiscible or near-miscible process at reservoir conditions. The performance of the immiscible process is generally lower than that of the miscible flood. The recovery in immiscible conditions can be improved by lowering the CO_{2} MMP via injection of a LPG (liquefied petroleum gas). Kumar and Von Gonten [19] investigated the recovery by injecting mixtures of CO_{2} and LPG. They carried out experiments with Woodruff reservoir oil in Berea sandstone cores. The recovery of the mixture injection was 11% higher than that using only a CO_{2} injection. Lee et al. [20] optimized the injection composition for gas injection. Their results stated that an injectant rich in C_{3} to C_{4} led to a higher oil rate with higher API oil. Delfani et al. [21] simulated the gas injection process in the Iranian field. The performance of LPG injection was better than that of CO_{2} flooding.

Various researchers have explained that both the temperature and injection composition are important factors that influence the recovery efficiency. However, the effect of temperature has been often ignored in most simulations of gas flooding. This study investigates the combined effects of the temperature of the injected fluids and the composition of the CO_{2}-LPG mixture on oil recovery. A lower temperature solvent and composition of the solvent can impact the MMP, which subsequently affects the oil recovery. The fluid model used for MMP calculation, reservoir model, and injection schemes is indicated. The recovery factors are analyzed with respect to the LPG mole fraction and injection temperature with an integrated model of compositional flow and heat transfer in the reservoir.

#### 2. Methodology

##### 2.1. Model Formulation

Simulations of CO_{2} flood were conducted with GEM, which is a 3D, multicomponent, multiphase, compositional simulator considering important mechanisms of miscible gas injection process such as composition changes of reservoir fluids, swelling of oil, viscosity reduction, and the development of a miscible solvent bank through multiple contacts.

The basic mass conservation equation for components can be written as follows:where is the porosity, the phase index, the total number of phases, the density of phase , and the Darcy velocity of phase .

The phase flux from Darcy’s law iswhere is the intrinsic permeability tensor, the vertical depth, the relative permeability, the viscosity, and the specific weight of phase .

To describe nonisothermal conditions and investigate their influence on oil recovery, thermal module was also used. General total energy balance in the reservoir by conduction and convection can be described as follows:where is the reservoir temperature, is the density of rock, and are the heat capacities of rock and phase at constant volume, is the heat capacity of phase at constant pressure, is the thermal conductivity, and is the heat loss to overburden and underburden formations.

Heat transfer between the reservoir and surrounding formations should be considered to more accurately describe the recovery process. When the injected fluids flow through the reservoir, heat transfer occurs between the reservoir and over/underburden across its boundaries. Vinsome and Weterveld’s semianalytical method [22] is used to calculate the heat loss by linear conduction. It assumes that conduction within surrounding rocks rapidly eliminates any temperature differences and longitudinal heat conduction in the surroundings can be neglected. The temperature profile in the over/underburden can be calculated as function of time and distance from reservoir interface bywhere is the over/underburden temperature at time at a distance from the reservoir boundary, and are the time dependent parameters, is the thermal diffusion length, is the temperature in the boundary grid block, and is the initial temperature in the boundary grid block. The diffusion length is represented bywhere is the thermal diffusivity defined byHere, is the rock thermal conductivity, is the rock heat capacity, and is the mass density of the rock. Parameters and are derived aswhereand the heat loss rate iswhere is the cross-sectional area for heat loss to the overburden and underburden.

##### 2.2. Crude Oil Characterization

Oil from the Weyburn reservoir [18, 23, 24] is chosen to model the reservoir oil. The saturation pressure is 2.89 MPa at 59°C. The oil composition is shown in Table 1. Table 2 represents PVT properties as a function of dissolved gas mole fraction. The properties include saturation pressure, gas oil ratio (GOR), gas solubility, formation volume factor (FVF), and swelling factor (SF). Fluid characterization, lumping of components, and matching with laboratory data through regression are carried out by fluid modeling with WinProp of CMG. The oil density and viscosity are matched with experimental results [18] through the Peng-Robinson equation of state model (Tables 3 and 4). Table 5 represents viscosity data for the oil and CO_{2} mixture. The CO_{2} MMP was calculated using the multiple-mixing-cell method [25] over a temperature range of 49–82°C. The predicted MMPs at 82°C are 18.9 MPa for CO_{2}, 13.2 MPa for 90% CO_{2} with 10% LPG, and 9.4 MPa for 80% CO_{2} with 20% LPG. The LPG consists of 0.2 mole fractions of propane and 0.8 mole fractions of butane. The MMPs are plotted against temperature in Figure 1. This result explains that the MMP decreases as the temperature decreases and the concentration of LPG increases.