Retention of CO2-Foaming Agent in CO2-Foam Flooding of Heterogeneous Carbonate Reservoirs

Abstract

The efficiency of carbon dioxide (CO 2 )-flooding in highly heterogeneous reservoirs may be low due to poor macroscopic sweep. One of the possible ways to increase macroscopic sweep efficiency is by reducing the CO 2 mobility by foam. Retention of the foaming agent during CO 2 -foam flooding is an important aspect affecting both technical and economical potential of the process. This paper presents both experimental and numerical simulation studies performed to investigate the retention of CO 2 -foaming agents in heterogeneous carbonate reservoirs. These reservoir types consist of high permeable "thief zones" -fractures or high permeable layers and the rest of the reservoir -matrix or low permeable layers. The retention of CO 2 -foaming agent was studied in flow-through laboratory experiments with CO 2 -foaming agents; branched ethoxylated sulphonates with different ethoxylation degree in outcrop Liege chalk rock at 55 o C. The retention of the foaming agents was determined by breakthrough curves based on chromatographic separation between the foaming agent and a tracer. The flow-through retention experiments were reproduced in a numerical simulator. The results indicate that the retention (the amount of foaming agent lost per rock weight) depends on the type of foaming agent and oil saturation. It is concluded based on simulation results that the amount of the foaming agents retained in heterogeneous reservoirs would strongly depend on its transfer mechanism from high into low permeable zones. The diffusion process is slow and therefore the foaming agent might penetrate only into a certain fraction of the matrix blocks or low permeability layers during the project life time. The retention of the foaming agent in these heterogeneous carbonate reservoirs may therefore be much lower than estimated based on viscous floods. A numerical model describing diffusion and retention by adsorption was established. A good match between experimental and modeling results was obtained without individually tuning the numerical model for each specific experiment. Additional simulation results showed that on the field scale the amount of foaming agent retained in heterogeneous reservoirs will depend on the number of high permeable zones and the size of the matrix blocks.

CO2 foam flooding for improved oil recovery: Reservoir simulation models and influencing factors

“…There are a lot of foam models proposed in literature, including the local-equilibrium foam model (Cheng et al, 2000;Rossen and Boeije, 2013), and the mechanistic model (Friedmann et al, 1991;Skoreyko et al, 2012). In the local-equilibrium model, the gas relative permeability is multiplied by a factor FM to reduce the gas mobility, as shown in Equation (1).…”

“…And the comparison has been made between the performance of CO 2 foam flooding and that of N 2 foam to show the differences between two techniques (Farajzadeh et al, 2009;Emadi et al, 2012). Besides the CO 2 foam technique was proving to be a feasible and successive IOR method in oilfield flooding processes, a lot of work has been done to study the mechanisms of CO 2 foam flooding through experiments and numerical simulations (Kovscek et al, 1997;Liu et al, 2011;Fjelde et al, 2011). Different kinds of theory were developed and various laboratory experiments were conducted in order to understand the flowing behavior and to establish the simulation models of foams in porous media (Kovscek et al, 2010;Chang and Grigg, 1994;Du et al, 2007).…”

“…The models currently used to describe foam properties include population-balance models, limiting-capillary-pressure model, fractional-flow theory, Stone's model for continuous foam injection and idealized models for SAG displacement (Falls et al, 1988;Friedmann et al, 1991;Kam and Rossen, 2003;Kovscek et al, 1995;Zuta and Fjelde, 2011;Renkema and Rossen, 2007;Ma et al, 2015;Zhang et al, 2000;Rossen et al, 1999;Farajzadeh et al, 2012b;Ma et al, 2014).…”