Feasibility Study of a Steam-Foam Process Application in Kuwait

Foam has been extensively investigated as a method to improve the mobility control of non-condensable gases in the EOR context. Recently, there has been renewed interest in foam applied to steam injections. However, steam is a condensable gas and thus steam-foam requires special analyses that differ from classical foam assessments. This work presents the coreflood results of a steam-foam process evaluation for the Ratqa Lower Fars (RQLF) heavy oil reservoir in Kuwait. Using specifically designed foaming surfactants, coreflood tests in the absence and presence of heavy crude oil are performed in native sandpack cores under RQLF reservoir conditions (220°C; 360 psi). In order to limit steam condensation due to the build-up of the foam pressure, steam has been supplemented with a small amount of non-condensable gas (nitrogen, about 1 - 5 mol.%). Interstitial velocity was decreased from 40 ft/day down to 1 ft/day (CWE). Phase equilibria at the core inlet were estimated based on thermodynamics flash calculations. From these calculations inlet steam quality was varied from 10 to 70 wt.%. In absence of oil, the apparent viscosity of the generated steam-foam is measured between 25 and 50 cP, depending on the interstitial velocity and inlet steam quality. Indeed, beside the classical shear-thickening behaviour observed with the decreasing flow rates, the critical or optimal steam quality is found to be closed to 30 wt.%. Furthermore, even at higher steam quality the foam is still stable and efficient with a viscosity higher than 25 cP. Experiments in the presence of crude oil were carried out under the same conditions in native cores at a steam residual oil saturation of 7% and 13%. These experiments showed that the optimal steam quality is shifted to approximatively 10 wt.%. Furthermore, the foam flow curve shows a shear-thinning behavior that is elaborated upon. Finally, the viscosity in the presence of heavy crude oil of the generated steam-foam is within the range of 7 to 22 cP, depending on the oil saturation and on the injection conditions. Considering the oil viscosity (2 to 3 cP) under the same conditions, this means that the foam effect should translate into efficient improved conformance control of the steam within the reservoir. For the first time, an efficient and stable steam-foam is generated in coreflood experiments. The generated foam achieved high apparent viscosities, even in the presence of oil, and this has not been reported in the literature to date. The results presented here are far more than a proof of concept as they bring new evidences regarding steam-foam efficiency and mechanisms with heavy crude oil.

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Very High Temperatures Steam Foam Additives

Odier

Kerdraon

Lacombe

et al. 2021

Day 3 Wed, November 17, 2021

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In heavy oil reservoirs operated by steam injection, foam has a double benefit. By improving the steam sweep efficiency within the reservoir, foam increases oil recovery while reducing the amount of injected steam. However, in the field, this technology is not always very effective due to the fact that it is difficult to find foaming agents that can withstand temperatures above 200°C. Moreover, the agents that form stable foams at such temperatures are often insoluble at ambient temperature, and therefore difficult to solubilize in the field. Thus, a compromise between good solubility in surface conditions and high temperature foaming performances in the reservoir has to be found. In this study, we show that it is possible to boost chemicals that form foam at very high temperature with an additive to greatly improve their solubility at ambient temperature while maintaining their high foaming performance at high temperature. Two foaming agents of increasing degree of hydrophobicity (H and HH) were initially selected for this study. The first one shows high foaming performances in porous media and in a high-pressure cell at temperatures comprised in between 150 and 220°C. The second one, more hydrophobic, is particularly performant at temperatures comprised in between 220°C and at least 280°C. Using a robotic platform, the temperature at which the foaming solution for agents H and HH needs to be heated to be solubilized, was evaluated with an accuracy of 5°C in four brines (varying salinity and hardness). We found that the temperature at which both agents become soluble is above 60°C, still too high for a field application. In the second part of the study, these hydrophobic molecules were coupled to a pre-selected additive. The resulting mixtures were again qualified in terms of solubility and foaming performances. We show that by coupling these hydrophobic agents with an additive, we are able to maintain their excellent foaming performances while decreasing their solubilisation temperature down to room temperature. To the best of our knowledge, this is the first time that very high temperature foam stability assessment up to 280°C is combined to solubility measurements to design performant foaming solutions that will be easy to handle in the field for steam foam applications. Interestingly, we show that the hydrophobicity of agents that is required for high temperature foam generation can be balanced by a more hydrophilic agent without reducing their foaming performances.

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Feasibility Study of a Steam-Foam Process Application in Kuwait

Cited by 3 publications

References 12 publications

The foam reinforced with Janus amphiphilic graphene oxide to control steam channeling in heavy oil reservoir

The foam reinforced with Janus amphiphilic graphene oxide to control steam channeling in heavy oil reservoir

Steam-Foam Assessment Using Native Cores from the Ratqa Lower Fars RQLF Heavy Oil Reservoir in Kuwait to De-Risk Field-Scale Deployment

Very High Temperatures Steam Foam Additives

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