Problems Associated with CO 2 Flooding

Introduction and Literature Review

1.4 Problems Associated with CO 2 Flooding

Chapter 1 Introduction and Literature Review

As far as India is concerned, Oil and Natural Gas Corporation (ONGC) is mainly involved in studying the feasibility of CO₂-EOR application in Indian oilfields.

One CO2-EOR pilot project was planned in the Ankleshwar oil field of Western India, where experimental and modeling studies had given encouraging results. These studies indicated that CO2-EOR is technically feasible in this field and recovery could be expected to improve by approximately 4% in the project life of 35 years. The anthropogenic CO2 for injection would be supplied from an adjacent gas processing plant in Hazira. The CO2 gas of the plant is being vented to the atmosphere and by injecting into the oilfield it is expected to sequester 5 to 10 million tons of CO₂ [43, 44].

Chapter 1 Introduction and Literature Review

layers. The resultant effect is early gas breakthrough, reduced Evo, and high residual oil saturation.

The other problems associated with CO2 flooding that reduce the process- efficiency are corrosion and asphaltene precipitation. When CO₂ reacts with formation water carbonic acid form making the formation water acidic. The acidic environment may corrode the downhole tubular and production equipment increasing the risk of leaks. Moreover, the acidic water may dissolve harmful elements affecting drinking water sources. Another dominant problem that may occur during CO2 flooding is the possibility of asphaltene precipitation. Asphaltenes tend to remain in solution under reservoir temperature and pressure conditions stabilized by resins adsorbed on their surface. Asphaltenes may start to precipitate if the stability of crude oil is destabilized due to changes in temperature and/or pressure during primary depletion. Asphaltenes may also become unstable as a result of the mixing of fluids as well as during gas injection for EOR operations [46]. During CO2 flooding, the interaction of the CO2 and crude oil may cause the asphaltene-to-resin ratio of crude oil to altered leading to asphaltene precipitation and thereby its deposition [47]. In the reservoir, the precipitation may obscure the movement of CO2 into the portions of the reservoir containing residual oil and thereby lower E_vo. Resins have the effect of keeping asphaltenes in solution. A high resin to asphaltene ratio (R/A) indicates that asphaltenes are less likely to come out of solution [48]. Leontaritis and Mansoori [49] presented a condition for asphaltene stability as follows: R/A > 3.0 as steady-state, 2.0 < R/A < 3.0 as meta-steady state and R/A < 2.0 as unsteady state. However, among all the complications of CO2 flooding, unfavorable mobility ratio and conformance issues are considered the most dominant ones affecting the process.

Chapter 1 Introduction and Literature Review

The techniques commonly employed to overcome CO2 mobility and conformance control problems are summarized below:

(a) Water-alternating-gas (WAG): This is the technology of choice for CO2

mobility control where instead of continuous injection, CO₂ is alternately injected with water into the reservoir as short slugs so as to provide better Evo and reduce CO2 consumption. This technique lowers the relative permeability to CO₂ through increased water saturation and lower CO2 gas saturation in the pore spaces of the reservoir rock.

The mobility of gas is controlled and early gas breakthrough is alleviated through WAG injection which improves the displacement efficiency of the process [50, 51]. The first reported WAG field application was a pilot study in the North Pembina oil field in Alberta, Canada in 1957 [52, 53]. The obvious advantage of WAG lies in the fact that both the injected fluids are available in large volumes and so less costly. The schematic representation of the CO₂-WAG process is shown in Fig. 1.3.

Fig. 1. 3: Schematic representation of CO2-WAG flooding showing the alternated CO2

and water injection cycles[[54], modified]

Impermeable rock Cap Rock

Injector Producer

Injected Fluids Oil + water + gas

Drive

water CO₂ CO2 Mixing

zone Oil Bank

Extra oil recovery water CO2 water

Injected CO₂ encounters residual oil

CO₂ mixes with oil

Oil swelling, viscosity reduction, gas drive

mobilizes oil

Chapter 1 Introduction and Literature Review

(b) Direct Thickener: The use of direct thickeners like soluble polymers that significantly increase CO₂ viscosity is sometimes used for mobility control during CO₂ flooding. The thickened CO2 gas injected without water improves the displacement efficiency without the water blocking problems and corrosion issues associated with WAG.

(c) CO₂-foams: Foam has been used to control gas mobility and improve oil recovery during gas EOR processes. Foam exhibits various favorable attributes which makes it an attractive method for improving oil recovery. Foam reduces the apparent viscosity of the gas and lowers the relative permeability of the liquid, making the mobility ratio favorable. Additionally, foam reduces CO2 mobility by a greater fraction in high-permeability cores than in lower-permeability cores [55, 56]. This unique property of foam is termed as selective mobility reduction which assists in smoothening heterogeneities [57]. The stronger foam generated in the high-permeability zones behaves like a more viscous fluid which diverts fluid to low-permeability zones of the reservoir, thus providing better mobility control to improve Evo [58]. The presence of surfactant during foam flooding, on the other hand, helps to mobilize residual oil by lowering the oil-water IFT value.