3.3 Enhanced oil recovery

Enhanced oil recovery (EOR) through injecting CO2 into oil reservoirs (CO2 EOR) is an established technique and has been used in the petroleum industry for almost four decades. A survey published by the Oil and Gas Journal in 2008 [27] showed that there were 123 CO2 injection projects worldwide, contributing an incremental oil recovery of approximately 270 thousand barrels per day. This represents less than 0.5% of total crude oil production. However, enhanced oil production through CO2 flooding has increased steadily.

The motivation for almost all CO2 injection projects is to enhance oil recovery, not to reduce CO2 emissions into the atmosphere. One of the major limitations of the EOR projects is the cost of CO2. Most CO2 injection projects have used naturally occurring CO2 which has been transported from distant sources through pipelines. If the availability of injection gas at low enough cost is made possible, either because the cost of capture was reduced or because incentives for CO2 storage were in place, many more oil reservoirs would be candidates for CO2 injection. Recent estimates by Kinder Morgan show that about 650 Mt of CO2 have been injected in EOR projects over the past 4 decades, which is an average of approximately 18 Mt/yr. This is approximately equivalent to the CO2 emissions from five 500 MW capacity coal-fired power plants.

A combination of CO2 EOR with underground disposal of CO2 is a co-optimisation problem which involves maximizing both incremental oil recovery and CO2 storage. Co-optimisation is relatively new to the industry and needs further research.

3.3.1 CO2 EOR mechanisms

There are two mechanisms by which CO2 EOR can enhance recovery — miscible flooding and immiscible flooding. Miscible flooding

In a miscible flood, or, more accurately, multi-contact miscible flood project, the miscibility between CO2 and oil is the main mechanism that improves oil recovery. Miscibility affects the phase behavior of CO2 at subsurface pressure and temperature during and after injection. It must be understood thoroughly for a proper assessment of incremental oil recovery and CO2 storage. At the reservoir pressure and temperature above the critical point for CO2 (7.38 MPa and 31.1°C), which can be achieved at reservoir depths above 800 m, CO2 density becomes very similar to oil and water densities. However, the viscosity of CO2 remains lower than the viscosities of oil and water. This may lead to a viscous unstable flood which may weaken the sweep efficiency and hence recovery factor.

When the reservoir pressure is near or above the minimum miscibility pressure (MMP), CO2 can displace oil quite efficiently in the invaded zones of the reservoir. The MMP depends on the reservoir temperature and the composition of the oil. It can be estimated by various methods such as slim tube experiments, semi-analytical and analytical methods. For example, the following expression can be used to calculate the MMP in MPa [28] –

This pressure is most accurate for light oils at temperatures (T) below 50°C. It also is a useful parameter for assessing CO2 sequestration because the efficient use of the pore space requires that relatively dense CO2 be stored. Immiscible flooding

In an immiscible flood, the CO2 EOR mechanism may be different. In immiscible flooding, CO2 displacements are usually more efficient than nitrogen and methane displacements. Even at the pressures below the MMP where the flood is immiscible, CO2 flooding occurs in low-to-medium interfacial tension zones. In these cases, CO2 can be injected up-dip in a gravity drainage mode to displace oil more efficiently towards the producing wells located down-dip.

3.3.2 Numerical simulation

For both miscible and immiscible floods, the CO2 EOR process must be simulated numerically over a scale of meters to kilometres in order to estimate the lateral extent of the CO2 plume in subsurface. The phase behaviour of the CO2-oil-water system and pore-scale physics are important elements of simulating the behaviour of CO2 EOR. The former assesses the mass interactions between the phases while the latter helps to assess the displacement efficiency.

3.3.3 Fluid movement

CO2 can be stored in those zones in which CO2 replaces reservoir oil or water. CO2 is soluble in water and it is approximately 10 times more soluble in oil. The movement of oil and gas in a reservoir is dominated by the pressure gradient created between injection and production wells and by the heterogeneity of the rocks. The viscosity of CO2 is low compared with that of the oil and water in the reservoir. The injected CO2 invades high-permeability flow paths as it makes its way to production wells. A detailed description of the permeability distribution in the reservoir is required to obtain accurate predictions of (a) when the injected CO2 breaks through to the production wells and (b) the amount of CO2 produced with the oil. Those predictions forecast the amount of subsequent production, recompression, and recycling of CO2 that is produced with oil. In virtually all CO2 EOR projects, large volumes of CO2 are recycled.

3.3.4 Options

The local availability of CO2 and its cost are two important economic criteria which need to be considered in screening reservoirs for CO2 EOR. If the objective is also to increase storage of CO2, then changing injection horizons, injecting CO2 into a saline formation below the reservoir, or injection into the capillary transition zone may also be useful. While many of the specific actions taken to increase CO2 storage will depend on the details of the particular reservoir setting, it is apparent that many opportunities exist for developing the design of CO2-injection projects in a way that increases storage substantially over the amounts stored in secondary EOR projects. For example, modifications of the commonly used water-alternating-gas ("WAG") injection schemes may allow greater CO2 storage while at the same time controlling the cycling of injected CO2.

3.3.5 Screening reservoirs for CO2 EOR and CO2 storage

Screening criteria for oil reservoirs that might be candidates for incremental oil and CO2 storage through CO2 injection have been suggested by several authors [28–30]. The MMP required for a given oil increases with temperature because at higher temperatures the density of CO2 and its solubility in oil decreases. Since the reservoir temperature increases with depth, so does the MMP (see Equation (1)).

However, the fracture pressure of the reservoirs increases much faster than temperature so there is an MMP "window of opportunity". Oils heavier than 40°API would have an MMP/temperature/depth correlation above the line. A depth of greater than 760 m is more appropriate for CO2 EOR projects. Most of the relationships between temperature, oil composition and pressure come from extensive work on oils from U.S. discoveries such as those from the Permian basin of West Texas and southeast New Mexico. Therefore, the oils that differ from these require more study. Hagedorn and Orr [31] showed that a high percentage of multi-ring aromatics will raise the MMP significantly because they are extracted so poorly by CO2. Taber suggested that incremental oil recovery would increase when the composition of the crude has a high percentage of C5 to C12, when the quality is 22°API or greater, when the viscosity is 10 cP or lower and when the oil saturation is 20% or more. Hagedorn and Orr do not consider permeability to be a critical factor affecting incremental oil recovery.

Shaw and Bachu [32] present an analytical methodology for screening reservoirs for both incremental oil recovery and CO2 storage. We adapt their methodology and screen the basins in Asia-Pacific based on the Pres/MMP ratio, net thickness, permeability and porosity. Given the lack of data of the oil properties, we exclude API gravity and initial oil saturation, which also play important role in screening. We weight the parameters, the Pres/MMP ratio, gross thickness and permeability the same. They are also significant, whereas the porosity is less significant.

Equation (1) was used to estimate MMP and results are given in Table 2. The results show that the first three formations are suitable for CO2 EOR based on their favourable gross thickness and permeability, although their pressures are estimated to be below the MMP.

The relative importance of the different parameters (the relative weighting) is based on a subjective assessment. Different subjective assessments will yield different rankings. In addition, more data, especially describing oil properties, will refine the ranking.

The potential for CO2 EOR is very case-specific and requires detailed data on individual oil reservoirs. We do not have sufficient data to carry out a detailed assessment of the potential for CO2 EOR in individual reservoirs across the basins covered in this study.

A detailed analysis of the scope for enhanced oil recovery from individual oil fields in South-East Asia is beyond the scope of this study. As shown above, CO2 EOR is likely to have application in particular circumstances where (a) CO2 is readily available at an appropriate price, (b) reservoir conditions are suitable and (c) the fields are on decline. In other words, many conditions must be met at the same time to ensure a viable CO2 EOR project. While there might be several suitable candidates for CO2 EOR, they might not increase overall oil production in South-East Asia significantly and might not require significant volumes of CO2.

From the perspective of reducing CO2 emissions, enhanced oil recovery is not strictly comparable to CO2 storage in saline formations or depleted oil or gas fields. Enhanced recovery produces additional hydrocarbons, which are ultimately burned and therefore cause additional CO2 emissions unless those emissions are captured and stored.

Table 2 – Ranking of storage formations for CO2 EOR

(iv) Approximate ranking using rock properties only. The best formation has a rank of 1.

(v) The weights are based on a subjective assessment of relative importance.