Fracture aperture is usually estimated by cubic law, which assumes flow between two smooth parallel plates. However, many researchers have proved that the fracture aperture is not a smooth surface but rather has tortuous paths and roughness, and hence the flow behavior is different. Previous research showed that fracture aperture follows lognormal distribution. Nevertheless, there has not been any research conducted to validate the fracture aperture distribution with the change in stress conditions, which is common in fractured reservoirs. With the advent of X-ray CT scanner in the field of petroleum engineering, fracture apertures can be visualized and measured. Since there is no direct calculation for fracture aperture measurement from CT scanner data, a calibration curve needs to be established. We developed a calibration curve based on existing calibration techniques, which involves area integration of the fracture region to obtain a correlation between integrated CT numbers and the calibrated fracture aperture. Using this calibration curve, we obtained distribution patterns for fracture apertures along the length of the core for various stress conditions, from about six thousand fracture aperture measurements for each stress condition. The results show that aperture distributions still follow lognormal distribution under various stress conditions.

Fractured reservoirs have always been considered poor candidates for enhanced oil recovery. This is mainly due to the complexities involved in predicting performance in such reservoirs. A good understanding of multiphase flow in fractures is important to reduce oil bypass and increase recovery in these reservoirs. This paper presents CO 2 flooding experiments in homogeneous and fractured rocks with in-situ saturation and porosity measurements using an X-Ray CT scanner. We found that injection rates played an important role in the recovery process, more so in the presence of fractures. At high injection rates we observed faster CO 2 breakthrough and higher oil bypass than at low injection rates. But very low injection rates are not attractive from an economic point of view. Hence we injected viscosified water to reduce the mobility of CO 2 , similar to the WAG process. Breakthrough time reduced significantly and a much higher recovery was obtained. Saturation measurements were made from the CT scans and were found to be in good agreement with those obtained from effluent data.

Fractured reservoirs have always been considered as poor candidates for enhanced oil recovery. The fractures provide a pathway for injected fluids to channel through directly from injection to production wells. The interaction between these fractures and the reservoir rock matrix often determines the degree of bypassing during injection of CO2. The use of CO2 as a displacing agent through these reservoirs aggravates the problems of low sweep efficiency due to its high mobility. The microscopic displacement efficiency of CO2 is very high, but the overall displacement efficiency is often hindered by its high mobility that is largely the results of viscosity and density contrasts between the CO2 phase and the reservoir oil and brine phases. In this study, we performed CO2 injection experiments with different injection rates and utilized X-ray CT to determine the saturation distribution along the core and measure oil bypassed during CO2 process in fractured cores. We improved the CO2 sweep efficiency by controlling the CO2 mobility in the fracture. Water viscosified with a polymer was injected directly into the fracture, to divert CO2 flow into the matrix and delay breakthrough. Although the breakthrough time reduced considerably, water "leak off" into the matrix was very high. To counter this problem, a cross-linked gel was used in the fracture for conformance control. The gel was found to overcome "leak off" problems and effectively divert CO2 flow into the matrix. This experimental results increase the understanding of fluid flow and conformance control methods in fractured reservoirs. Introduction CO2 injection has been widely used for recovering oil from reservoirs due to its easy solubility in crude oil and its ability to "swell" the net volume of oil and thereby reduce oil viscosity by a vaporizing-gas-drive mechanism (Martin and Taber, 1992). The quantity of hydrocarbons that can be recovered from a reservoir is influenced by several characteristics of the reservoir including reservoir rock properties, reservoir pressure and temperature, physical and compositional properties of the fluid and structural relief, to name a few. However, the predominant factor in deciding the success of a CO2 flood is the reservoir heterogeneity. Highly heterogeneous reservoirs with variable lateral and vertical permeability characteristics can cause potential problems during CO2 injection. The injection gas tends to finger ahead into areas with high mobility ratios. This results in the gas forming preferential paths and "bypassing" large volumes of oil. Uleberg and Hoier (2002) suggest that the injection gas tends to flow in the highly permeable fractures, instead of the normally expected displacement path. These fractures are often responsible for early and excessive breakthrough of CO2, thus greatly affecting the economics of the project. In the recent years, there has been an increasing interest in the WAG process, both miscible and immiscible. The continuous CO2 injection process is an important process to identify displacement mechanisms but is not likely to be economic in practice unless significant recycling of gas is employed. Inherent in all gas injection processes is the lack of mobility and gravity control (areal and vertical sweep) necessary to sweep significant portions of the reservoir. Therefore, the replacement of high cost CO2 by a cheaper chase fluid such as water for horizontal displacements appears economically attractive. The WAG process involves alternate injections of small pore volumes (5% or less) of CO2 and water until the desired volume of CO2 has been injected. Since the microscopic displacement oil by gas normally is better than by water, the WAG injection combines the improved displacement efficiency of gas flooding with an improved macroscopic sweep by the injection of water. This has resulted in an improved recovery (compared to pure water injection) for most field cases.

Flow through a fracture is usually assumed to take place between two smooth parallel plates. However, it is widely accepted that the fracture has tortuous paths and roughness and hence the flow behaviour in these paths compared to that in parallel plates is different. Although previous studies have shown that the fracture aperture follows lognormal distribution, studies have not been conducted to determine the distribution of fracture aperture with changes in stress conditions. In this paper, we present fracture aperture measurements under different stress conditions using an X-Ray CT scanner. We developed a calibration curve to obtain a correlation between CT numbers and fracture aperture since there is no direct calculation of aperture from CT scanner data. Aperture distribution patterns from about six thousand aperture measurements were obtained for each stress condition evaluated. The results of this study show that the apertures follow lognormal distribution even at elevated stress conditions. We then performed waterflood experiments to validate the use of distributed apertures in simulators. A sensitivity analysis was also performed to analyze the effect of injection rates and fracture roughness on oil recovery. Introduction Modeling of fluid flow through rough fractures has gained importance over the years. This can be attributed to the extremely low ultimate recoveries obtained from naturally fractured reservoirs, in spite of their huge reserves. Attempts are being made to develop efficient models to better formulate depletion plans. The first comprehensive work on flow through open fractures was done by Lomize1, in which he used parallel glass plates and demonstrated the validity of cubic law for laminar flow. He modeled fluid flow with different fracture shapes and investigated the effects of changing the fracture walls from smooth to rough. Witherspoon et al.2 conducted laboratory experiments to validate parallel plate theory and they showed that the parallel plate approximation tends to break down at higher normal stress (>10 MPa) across the fracture. Alfred3 also confirmed that the parallel plate assumption is not valid to adequately model the fluid flow experiments when overburden pressure is significant. The flow through a single fracture does not progress uniformly as assumed by parallel plate theory; rather, it flows through a limited number of channels4,5. Hence, the fluid flow in these tortuous channels tends to follow a preferred path. Pyrak et al.6 (1985) performed laboratory experiments wherein they injected molten wood's metal into single fractures at different applied stress conditions. The direct evidence of tortuous paths was observed upon opening the cooled metal in the fracture. The fluid flow in these paths will be through the larger apertures which offer least resistance to flow. When the parallel plate approach was proved invalid, Tsang and Witherspoon5 accounted for the variation of apertures in a rough fracture. Later, Tsang4 modeled the variation of fracture apertures by electrical resistors with different resistance values placed on a two-dimensional grid. The results indicated that smaller apertures play a key role in restricting fluid flow. When the fracture contact area increases, tortuosity and connectivity of fractures become important. The flow through a single fracture took place in a limited number of channels, which was evident from the field experiment carried out in a single fracture7. Gentier8 measured fracture surface roughness profiles in a granite fracture. Upon plotting the apertures, the aperture density distribution was approximated by a gamma function. The density distribution is given byEquation 1 where bo represents the distribution peaks, and the mean aperture is 2bo. The same distribution was assumed when considering the channeling of flow through fractured media9. Tsang and Tsang9 assumed the channel width to be a constant of the same order as the correlation length ?, where correlation length is the spatial length within which the apertures have similar values. The reduction in channel apertures affected the tracer breakthrough curves when normal stress across a fracture was increased.