Reservoirs foam injection processes

Foam Injection Processes. Foams can be injected in to a reservoir for mobility control or for blocking and diverting. The foam can thus act to reduce the effects of ... 

Foams, in the form of froths, are intimately involved and critical to the success of many mineral-separation processes (Chapter 10). Foams may also be applied or encountered at all stages in the petroleum recovery and processing industry (oil-well drilling, reservoir injection, oil-well production and process-plant foams). A class of enhanced oil recovery process involves injecting a gas in the form of a foam. Suitable foams can be formulated for injection with air/nitrogen, natural gas, carbon dioxide, or steam [3,5]. In a thermal process, when a steam foam contacts residual crude oil, there is a tendency to condense and create W/O emulsions. Or, in a non-thermal process, the foam may emulsify the oil itself (now as an O/W emulsion) which is then drawn up into the foam structure the oil droplets eventually penetrate the lamella surfaces, destroying the foam [3], See Chapter 11. 

Enhanced oil recovery The process in which a foam is made to flow through an underground reservoir. The foam, which can either be generated on the surface and injected or generated in situ, is used to increase the drive fluid viscosity and improve its sweep efficiency. 

Nearly all of the treatment processes in which fluids are injected into oil wells to increase or restore the levels of production make use of surface-active agents (surfactant) in some of their various applications, e.g., surface tension reduction, formation and stabilization of foam, anti-sludging, prevention of emulsification, and mobility control for gases or steam injection. The question that sometimes arises is whether the level of surfactant added to the injection fluids is sufficient to ensure that enough surfactant reaches the region of treatment. Some of the mechanisms which may reduce the surfactant concentration in the fluid are precipitation with other components of the fluid, thermally induced partition into the various coexisting phases in an oil-well treatment, and adsorption onto the reservoir walls or mineral... 

Recently, use of a surfactant in the injected water such that a foam or emulsion is formed with carbon dioxide has been proposed (20.21) and research is proceeding on finding appropriate surfactants (22-24). The use of such a foam or emulsion offers the possibility of providing mobility control combined with amelioration of the density difference, a combination which should yield improved oil recovery. Laboratory studies at the University of Houston (25) with the same five-spot bead-pack model as used before show that this is so, for both the relatively water-wet and relatively oil-wet condition. We have now simulated, with a finite-difference reservoir process computer program, the laboratory model results under non-WA3, WAG, and foam displacement conditions for both secondary and tertiary recovery processes. This paper presents the results of that work. 

Petroleum occurrences of foams may not be as familiar but have a similarly widespread, long-standing, and important occurrence in industry. Foams may be applied or encountered at all stages in the petroleum recovery and processing industry (oil well drilling, reservoir injection, oil... 

Steam-based processes in heavy oil reservoirs that are not stabilized by gravity have poor vertical and areal conformance, because gases are more mobile within the pore space than liquids, and steam tends to override or channel through oil in a formation. The steam-foam process, which consists of adding surfactant with or without noncondensible gas to the injected steam, was developed to improve the sweep efficiency of steam drive and cyclic steam processes. The foam-forming components that are injected with the steam stabilize the liquid lamellae and cause some of the steam to exist as a discontinuous phase. The steam mobility (gas relative permeability) is thereby reduced, and the result is in an increased pressure gradient in the steam-swept region, to divert steam to the unheated interval and displace the heated oil better. This chapter discusses the laboratory and field considerations that affect the efficient application of foam. 

Interfacial Tension Behavior. Reduction in the residual oil saturation over and above that obtained by steam injection is desirable and, in many heavy oil reservoirs, essential to ensure efficient foam formation during application of steam-foam processes (13). The extent of heavy oil desaturation is, however, dependent on the reduction in interfacial tension between oil and water. Thus, foam-forming surfactants can improve their own cause by reducing interfacial tensions at steam temperature. 

Flow Resistance of Foams in Porous Medium. Foam flows in the reservoir by making and breaking processes. Because of its dispersed nature, foam exhibits low flow mobilities depending on texture (bubble size and distribution) in relation to the imposed injection and reservoir conditions (27). To perform successfully, the foam must withstand a vast range of conditions and still maintain its integrity and flow resistance properties. For a given surfactant and reservoir type, therefore, it is important to consider a range of gas and liquid velocities, and liquid volume fraction (LVF). 

The purpose of this chapter is to describe an alternate mode of characterizing foam for reservoir application with emphasis on production-well treatments where the gas-blocking properties of foam, rather than its viscous flow effects, are paramount. The results should also be of relevance to other foam processes where gas flow is primarily to be blocked, such as the diversion of injected gas or steam and the sealing of leaks in gas storage reservoirs. 

It is pointed out in [252] that more than 10% of the world oil recovery is accomplished by injecting steam or CO2 for the production of oil by EOR. Here, the foam bubble size is comparable or slightly more than the pore diameter. To increase oil production, highly disperse steam foam is required, which pushes the oil out of the reservoir while moving both as a continuous and discontinuous flow. It has to be emphasized that the choice of surfactant is important to accomplish the process. Typically, the surfactant concentration is much higher than CMC, which predetermines the expensiveness of the process. The foam is destroyed when coming in contact with oil and rock, which requires its increased consumption. Three mechanisms of foam formation under reservoir conditions are proposed in [253], determined by the liquid flow rate and the throat radius between the pores. When the foam flows in a reservoir, its aggregative stability is disturbed due to coalescence. Hence, the choice of... 

Schramm [257] considers it a big problem that foams are sensitive to the contact with oil under porous medium in oil recovery. While proposing a several foam breaking mechanisms under reservoir conditions, the author believes the emulsification process of oil in water is the most important step. In emulsification, the contact area of pseudo-emulsion films increases with the oil contents. In case the pseudo-emulsion films are stable, the foam stability and thus the process efficiency increases. Thinning of pseudo-emulsion films leads to its rupture when gas is continuously injected into the media, flooded with a surfactant solution at residual oil... 

The reports of the enhanced oil recovery projects concluded that the reservoir heterogeneities is the most frequent cause for failure of enhanced oil recovery processes which involve foam and surfactant flooding. It was deserved that the reservoir heterogeneity was much more dominant than expected. Geologic and permeability heterogeneities were the most probable cause of the low recovery efficiency realized by Goodrich and Watson The wettability of the pore surface affects the recovery efficiency, but this effect is poorly understood because it is almost impossible to determine which portions of the surface are oil-wet and which ones are water-wet in the subsurfaces. The wettability of the reservoir rocks can be influenced by the injection of surfactant solution for foam flooding. 

A large percentage (80%) of Canadian enhanced oil production comes from hydrocarbon miscible flooding [1], The low density and viscosity of the injected fluids cause hydrocarbon miscible EOR processes to suffer from poor sweep efficiency, due to viscous fingering and gravity override. Mobility control foams provide a means for improving the sweep efficiency and could significantly increase oil production from Canadian reservoirs. 

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