Application of Low Concentration Surfactant Enhanced Water-Alternating-Gas Flooding

Large amounts of oil left in the petroleum reservoir after primary and secondary enhanced oil recovery methods have brought about the implementation of several tertiary means of oil recovery. Increment of oil recovery can support the world’s oil supply. Water alternating gas injection has been a very popular method of gas injection to improving volumetric sweep efficiency. Although water alternating as injection has been shown to improve oil recovery, this process suffers inherent challenges such as water blocking, mobility control in high viscosity oil and gravity segregation. To combat these problems associated with water alternating gas flooding, the use of surfactant has been employed in water alternating gas injection. Due to the high operational cost arising from chemical cost in surfactant alternating gas injection, a new technique which involves the injection of low concentration surfactant before water alternating as flooding has been proposed. This work investigates experimental and numerical oil recovery potential of surfactant enhanced water alternating gas flooding. The distinctive feature of this technique is that instead of injecting surfactant slugs alternatively with gas, which will result to using a greater amount of surfactant, a low concentration surfactant is injected into the reservoir before water alternating gas flooding. The aim is to evaluate the performance of this technique as a low cost and effective means of chemically enhanced oil recovery by combining both mechanisms of surfactant reduction of water-oil interfacial tension and creation of foam with gas. This study begins with surfactant evaluation to characterise surfactants compatibility with reservoir brine and oil. Then followed by series core flooding experiments which include waterflooding, gas flooding, water alternating gas flooding and surfactant-enhanced water alternating gas flooding. Core flood data was history matched for water alternating as flooding and surfactant-enhanced water alternating as flooding via commercial simulator by inputting relative permeability curves, rock, fluid properties and interfacial tension. The results showed that experimentally, surfactant enhanced water alternating as flooding had the highest oil recovery when compared to conventional enhanced oil recovery methods. History matching of core flood experiment predicted similar increment in oil recovery during surfactant enhanced WAG. The effectiveness of this technique is based on the injection pattern after the initial surfactant injection and oil recovery potential is similar to that of surfactant alternating gas flooding

Modelling foam improved oil recovery : towards a formulation for pressure- driven growth with flow reversal

The pressure-driven growth model that describes the 2-D propagation of a foam through an oil reservoir is considered as a model for surfactant-alternating-gas improved oil recovery. The model assumes a region of low mobility, finely-textured foam at the foam front where injected gas meets liquid. The net pressure driving the foam is assumed to reduce suddenly at a specific time. Parts of the foam front, deep down near the bottom of the front,must then backtrack, reversing their flow direction. Equations for 1-D fractional flow, underlying 2-D pressure-driven growth, are solved via the method of characteristics. In a diagram of position vs time, the backtracking front has a complex double fan structure, with two distinct characteristic fans interacting. One of these characteristic fans is a reflection of a fan already present in forward flow mode. The second fan however only appears upon flow reversal. Both fans contribute to the flow’s Darcy pressure drop, the balance of the pressure drop shifting over time from the first fan to the second. The implications for 2-D pressure-driven growth are that the foam front has even lower mobility in reverse flow mode than it had in the original forward flow case