The addition of polymer has the potential to enhance both the viscosity and the stability of surfactant-stabilized foams. However, the degree to which the bulk properties of polymer-thickened foams are retained or enhanced in porous rock is not well understood and is difficult to predict. We have compared the viscosities, at equivalent shear rates, of two different types of polymer-thickened foams in laminar pipeline (bulk) flow vs. the same foams flowing in consolidated sandstone rock. For one kind of foam, the apparent viscosity in the rock is very similar to that in pipeline flow. However, for another kind of foam, the apparent viscosity in the rock is an order of magnitude greater than that in pipeline flow. Low-energy scanning electron microscopy was used to examine the pore-scale morphology of the two foams in the rock. It was found that the morphologies of the two foams explain at least a large part of the observed differences in foam flow properties between bulk (pipeline) flow and constrained (porous medium) flow. This work is important to the specifications and formulation of the most effective surfactants for varying applications including mobility control, blocking, and diverting. Introduction Aqueous foams are used in a variety of the petroleum industry's enhanced oil recovery flooding techniques(1). For example, surfactant stabilized foams have been used as mobility control agents in gas-flooding(2–4). The foam, which has an apparent viscosity greater than the gas, lowers the gas mobility in the swept and/or higher permeability regions of the formation. Thus, the foam will divert some of the gas into other parts of the reservoir formation that were previously unswept, or poorly swept, to recover additional oil. Significant foam stability is a prerequisite for the successful application of foam flooding. There are also many other applications of foams in the petroleum industry, all requiring controlled stability(5–8). Foams have also been used as blocking agents because of their selective ability to reduce the gas permeability(9). Foam that has been developed for a blocking application must meet different requirements than foam that has been developed for sweep efficiency applications. A blocking foam must possess the ability to completely fill a selected volume in all locations where the gas could travel through, and to act as a barrier to flow. The gas blocking foam must stay in place and possess long-term stability, providing the largest possible gas mobility reduction for the longest periods. For the formulation of either kind of foam, one of the challenges that must be met is the proper selection of foam-forming surfactants. The foaming capability of a surfactant relates to both foam formation and foam persistence, which are influenced by many bulk and interfacial properties(10). Unfortunately, it is generally found that the performance of foams in porous media is not easily predicted based on these physical properties(11), although they can be exploited to increase foamability and foam persistence. Harsh chemical environments are sometimes present in oil reservoirs and several reviews have been published identifying desirable foam-forming characteristics for harsh and less demanding environments(1, 12).
The use of foams for controlling gas oil ratio (GOR) has been tested successfully in the North Sea,1,2 and North America.3,4 However, foams have a limited lifetime (weeks to months), and the treatment often needs to be repeated. A more permanent solution, with the same placement advantage, is to use gelling foams. During the gelation processes the foam structure solidifies, imparting greater stability and increased gas blocking ability to the gel-foam. In this work, several polymer-enhanced foam and gel-foam formulations were screened, and tested for their gas blocking ability under reservoir conditions. Initially, chromium crosslinked gelation experiments were undertaken to obtain suitable gelation times at 85 °C. Polymer-enhanced foam and gel-foam formulations were injected into Berea sandstone cores, and carbonate packs (in the presence and absence of oil), to examine their injectability, and gas-blocking capability. In addition, the effects of shear degradation, permeability, and flow rate on the effective viscosity of polymer-enhanced foams were investigated. It was determined that gel-foams, with suitable gelation delay, can be injected, and propagated into packed cores in a similar manner to polymer-enhanced foams. The gas blocking ability of cured gel-foam was far superior to that of polymer-enhanced foam. The gel-foam blocked gas flow completely, even in the presence of oil, and a significant pressure differential had to be exceeded before the gas could channel through the gel-foam and flow through the core. Introduction The desired effect of a foam application in oil producing wells possessing a high GOR is to block the gas influx without hindering the oil production. Therefore, the gas blocking capability of the foam is of utmost importance. A gel-foam application involves placing foam inside problem fractures, or high permeability streaks, and allowing it to gel, thus generating a long lasting barrier to gas flow. The optimal response to a gel-foam treatment should indicate incremental oil recovery at improved oil rates. Compared to regular foams, the advantage of gel-foam lies in its better gas blocking capability, greater effective lifetime, and larger residual resistance factor after gas has broken through the barrier. Thach et al4. reported laboratory development and field application of polymer-enhanced foams in which polymer-enhanced foams displayed high co-injection pressure with a strong resistance to gas flow. The effects lasted for over a year in a hydraulically fractured production well. Dalland and Hanssen5 compared the gas blocking efficiency of regular foams, polymer-enhanced foams, and gel-foams and determined that improved blocking performance could be obtained through the addition of polymer. They found that gel-foams were more persistent than polymer-enhanced foams, but were not necessarily more efficient in gas blocking, and that placement of the gel-foam was crucial to the success of the process. Having a relatively low density should allow gel-foam to be placed above an oil-bearing zone, towards a gas cap. Furthermore, since it is difficult to propagate foams into areas with oil saturations above 30%, due to foam-oil interaction effects6, a gel-foam can be prevented from entering and damaging oil-producing zones during placement. In addition to the use of gel-foams for GOR control, they have also recently been applied to improve conformance in injection wells. Friedman7 et al. discuss the development and field application of gel-foam to improve conformance in a CO2 flood in the Rangely field. They describe a gel-foam that resisted a 15 psi/ft pressure gradient. Miller and Fogler8,9 used glass micromodels to investigate the effectiveness of gel-foams for profile modification during water injection. They also identified flow regimes in the gel-foam system, which are relevant to our investigation, and will be referred to again.
Summary Polymer-enhanced foam and gel-foam formulations were screened and tested for their injectability and gas-blocking ability in Berea sandstone cores and carbonate packs (in the presence and absence of oil at 85°C). Gel foams, with suitable gelation delay, were propagated through packed cores in a similar manner as polymer-enhanced foams (PEF's). However, the gas-blocking ability of cured gel foam was far superior to that of PEF. The gel foam blocked gas flow completely, even in the presence of oil, and a significant pressure differential had to be exceeded before the gas could channel through the gel foam and flow through the core.
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