Modeling Near-Miscible Gas Foam Injection in Fractured Tight Rocks and Its Challenges

Haishan Luo,Kishore K Mohanty

doi:10.3390/en14071998

Abstract

Unlocking oil from tight reservoirs remains a challenging task, as the existence of fractures and oil-wet rock surfaces tends to make the recovery uneconomic. Injecting a gas in the form of a foam is considered a feasible technique in such reservoirs for providing conformance control and reducing gas-oil interfacial tension (IFT) that allows the injected fluids to enter the rock matrix. This paper presents a modeling strategy that aims to understand the behavior of near-miscible foam injection and to find the optimal strategy to oil recovery depending on the reservoir pressure and gas availability. Corefloods with foam injection following gas injection into a fractured rock were simulated and history matched using a compositional commercial simulator. The simulation results agreed with the experimental data with respect to both oil recovery and pressure gradient during both injection schedules. Additional simulations were carried out by increasing the foam strength and changing the injected gas composition. It was found that increasing foam strength or the proportion of ethane could boost oil production rate significantly. When injected gas gets miscible or near miscible, the foam model would face serious challenges, as gas and oil phases could not be distinguished by the simulator, while they have essentially different effects on the presence and strength of foam in terms of modeling. We provide in-depth thoughts and discussions on potential ways to improve current foam models to account for miscible and near-miscible conditions.

Highlights

Carbonate or tight reservoirs account for over half of total oil reserves worldwide and contribute to a vast amount of oil production [1]
We have demonstrated an approach to set up the simulation of near miscible or miscible gas foam injection coreflood experiments in fractured oil-wet rock
Simulations were successfully carried out and able to match the experimental data of near miscible gas foam injection corefloods with respect to both oil recovery and pressure drop

Summary

Introduction

Carbonate or tight reservoirs account for over half of total oil reserves worldwide and contribute to a vast amount of oil production [1]. The production rate of such reservoirs could be high during the early stage of primary recovery owing to connected natural fracture network that facilitates oil flow, but it is difficult to sustain the same oil production with secondary (such as gas flooding) or traditional tertiary recovery methods after the reservoir pressure has depleted [2]. This is because the injected fluids usually bypass the matrix in fractured rocks, and the injected fluid is not imbibed into the carbonate matrices because they are typically oil-wet and hinder the drainage of oil from matrices into the fractures [3,4]. Foam is stable in low capillary pressure and low oil saturation environment, making it a smart and adaptable agent, i.e., being strong in fractures or high permeability streaks and weak in tight matrices [8,9,10]

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