Foam Propagation at Low Superficial Velocity: Implications for Long-Distance Foam Propagation

Since the 1980s experimental and field studies have found anomalously slow propagation of foam that cannot be explained by surfactant adsorption. Friedmann et al. (1994) conducted foam-propagation experiments in a coneshaped sandpack and concluded that foam, once formed in the narrow inlet, was unable to propagate at all at lower superficial velocities towards the wider outlet. They hence concluded that long-distance foam propagation in radial flow from an injection well is in doubt. Ashoori et al. (2012) provide a theoretical explanation for slower or non-propagation of foam at decreasing superficial velocity. Their explanation connects foam propagation to the minimum velocity or pressure gradient required for foam generation in homogeneous porous media (Gauglitz et al., 2002). The conditions for propagation of foam are less demanding than those for creation of new foam. However, there still can be a minimum superficial velocity necessary for propagation of foam, except that it could be significantly smaller than the minimum velocity for foam generation from an initial state of no-foam. At even lower superficial velocity, theory (Kam and Rossen, 2003) predicts a collapse of foam. In this study, we extend the experimental approach of Friedmann et al. in the context of the theory of Ashoori et al. We use a cylindrical core with stepwise increasing diameters such that the superficial velocity in the outlet section is 1/16 of that in the inlet. N2 foam is created and stabilized by an alpha olefin sulfonate surfactant. Previously (Yu et al., 2019), we mapped the conditions for foam generation in a Bentheimer sandstone core as a function of total superficial velocity, surfactant concentration and injected gas fraction (foam quality). In this study, we extend the map to include the conditions for propagation of foam, after its creation in the narrow inlet section at greater superficial velocity. Thereafter, by reducing superficial velocity, we map the conditions for foam collapse. Our results suggest that the minimum superficial velocities for foam generation, propagation and maintenance increase with increasing foam quality and decreasing surfactant concentration, in agreement with theory. The minimum velocity for propagation of foam is much less than that for foam generation, and that for foam maintenance is less than that for propagation. The implications of our lab results for field application of foam are discussed.Green Open Access added to TU Delft Institutional Repository ‘You share, we take care!’ – Taverne project https://www.openaccess.nl/en/you-share-we-take-care Otherwise as indicated in the copyright section: the publisher is the copyright holder of this work and the author uses the Dutch legislation to make this work public.Petroleum Engineerin

Nanoparticle Stabilized Foam in Carbonate and Sandstone Reservoirs

Foam flooding as a mechanism to enhance oil recovery has been intensively studied and is the subject of multiple research groups. However, limited stability of surfactant-generated foam in presence of oil and low chemical stability of surfactants in the high temperature and high salinity of an oil reservoir are among the reasons for foam EOR not being widely applied in the field. Unlike surfactants, nanoparticles, which are shown to be effective in stabilizing bulk foam, are chemically stable in a wide range of physicochemical conditions. Recent studies suggest that synthesized nanoparticles with altered surface properties can aid foam generation and increase foam stability in porous media. In this paper, the focus lies on a silica-based nanoparticle that is available in large quantities and can be processed economically without separate surface treatment, which gives it the potential to become a practical solution in the field. The research is primarily conducted by performing core-flooding experiments under varying conditions to quantitatively assess and compare the potential of the nanoparticle-enhanced foam. Two types of reservoir rocks have been investigated: sandstone and carbonate rocks. It is observed that by adding even low concentrations of nanoparticles to a near-CMC surfactant solution, the foam viscosity considerably increases.Geoscience & EngineeringCivil Engineering and Geoscience

Fall-off test analysis and transient pressure behavior in foam flooding

Gas injection projects often suffer from poor volumetric sweep because under reservoir conditions the density and viscosity differences between the gas and the in-situ oil leads to override and bypassing of much of the oil in place. Foam has been suggested as a potential solution to this shortcoming and has shown success in some of the field applications. In the field scale foam can reduce the gas mobility, fight against gravity by inducing excess viscous forces and reduce the gas-oil ratio in the producer. Nevertheless, foam propagation in the reservoir, with low fluid velocities, and survival of foam in the path from injector to producer are among major uncertainties in foam projects. This necessitates the design of surveillance plans to monitor foam rheology and its propagation in porous media. Usually foam generation inside a porous medium is indirectly inferred from the pressure response; once foam is generated in the reservoir the pressure increases. Foam frequently exhibits non-Newtonian (shearthinning) behaviour, as it is propagated through the porous medium, which can influence the pressure transient test behaviour. This paper studies different well testing interpretation and pressure behaviour of foam flow in a homogenous reservoir. Local-equilibrium or implicit-texture foam model (that of STARS) are used to model the foam behaviour in porous media. Pressure fall-off test behaviour presented in this paper is new for foam injection. The flow regimes including inclined radial flow, radial flow, transient section, and reservoir boundary are discussed. A method which uses a pressure and a pressure derivative plot is developed for foam injection so that the mobility changes, flow behaviour index, location of foam front, reservoir parameters and reservoir boundary can be estimated. The results of this study can be used to analyse data from injection well, where monitoring of the generation, stability and distribution of foam is a key factor in the success of a foam field project. This paper discuss the dependency of the results on foam-model parameters, which indicates that by using pressure transient data one can obtain the foam model parameter.Geoscience & EngineeringCivil Engineering and Geoscience

Small core flood experiments for foam EOR: Screening surfactant applications

Aqueous foams are a means of increasing the sweep efficiency of enhanced oil recovery processes. An understanding of how a foam behaves in the presence of oil is therefore of great importance when selecting suitable surfactants for EOR processes. The consensus is currently that the most reliable method for determining the foam behavior in the presence of oil is to inject foam through a rock core. Coreflood tests, however, are typically carried out using large rock cores (e.g. diameter = 4 cm, length = 40 cm or longer), and hence foam flow tests can take days or weeks to achieve steady-state flow. In this study, we present the preliminary results for a core-flood system where the rock core is pen-sized (diameter = 1 cm, length = 17 cm). These small cores allow for short-duration foam flow tests, where steady-state flow is achieved in a few hours. Using this system, the foam quality/effective viscosity response curves can be plotted, both with and without oil in the system. These small size cores then enable rapid screening of surfactants and foam properties in different rocks and with different oils. Benefits and limitations of these small coreflood experiments are discussed.Geoscience & EngineeringCivil Engineering and Geoscience

Impact of Crude Oil on Pre-generated Foam in Porous Media

As foam is injected into an oil reservoir, the region near an injector can become oil-free due to the relatively high capillary number. Foam created in this region encounters oil further out in the reservoir. The impact of oil on foam in porous media is usually investigated by co-injecting surfactant, gas and oil, or by injecting pre-generated foam into an oil-saturated core. However, the former experiment does not give information on the impact of oil on pre-generated foam, and from the latter experiment one cannot easily obtain data at different oil fractional flows, necessary to model the impact of oil on pre-generated foam. Here the impact of crude oil on pre-generated foam is studied by co-injecting surfactant solution and gas into a relative narrow core (0.01 m diameter), and injecting oil into the porous medium some distance downstream from the inlet, through ports in the side of the porous medium. By injecting the three phases into the core we investigate the flow behaviour of foam with oil at fixed fractional flows of all three phases. The relatively narrow core allows rapid contact between the injected crude oil and pre-generated foam. We observe a progressive decrease in the apparent viscosity of the foam after encountering oil. Foams with a higher gas fraction experience a more significant weakening by oil over the length of the core than foams with a lower gas fraction. By the end of the core, the apparent viscosities of foam with a higher gas fraction approach values observed with three-phase co-injection. Foam made with surfactant pre-equilibrated with the crude oil propagated for a shorter distance in presence of oil than foam made with surfactant that hasn’t contacted oil before. We present a novel, but relatively simple method to investigate the change of foam mobility as it encounters oil in a porous medium, at controlled fractional flows of all phases. We show that in our case the apparent viscosity of foam with oil can decrease by more than a factor of four over a distance of 0.15 m, indicating that foam and oil reach steady-state (as observed with three-phase co-injection) almost instantaneously compared to the length of a reservoir-simulation grid-block.Green Open Access added to TU Delft Institutional Repository ‘You share, we take care!’ – Taverne project https://www.openaccess.nl/en/you-share-we-take-care Otherwise as indicated in the copyright section: the publisher is the copyright holder of this work and the author uses the Dutch legislation to make this work public.Petroleum Engineerin

Injectivity of Multiple Gas and Liquid Slugs in SAG Foam EOR: A CT Scan Study

Surfactant-alternating-gas (SAG) is often the injection method for foam enhanced oil recovery (EOR) in order to improve injectivity. However, liquid injectivity can be very poor once foam is created in the near-wellbore region. In a previous study, we reported core-flood experiments on liquid injectivity after foam flooding and liquid injectivity after a period of gas injection following foam. Results showed the importance of the gas slug to subsequent liquid injectivity. However, the effects of multiple gas and liquid slugs were not explored. In this paper, we present a coreflood study of injectivities of multiple gas and liquid slugs in a SAG process. We inject nitrogen foam, gas and surfactant solution into a sandstone core sample. The experiments are conducted at a temperature of 90°C with 40-bar back pressure. Pressure differences are measured to quantify the injectivity and supplemented with CT scans to relate water saturation to mobility. We find that during prolonged gas injection in the first gas slug following foam, a collapsed-foam region forms near the inlet due to the interplay of evaporation, capillary pressure and pressure-driven flow. This region slowly propagates downstream. During subsequent liquid injection, liquid mobility is much greater in the collapsed-foam region than downstream, and liquid sweeps the entire core cross section there rather than a single finger. In the region beyond the collapsed-foam region, liquid fingers through foam. Liquid flow converges from the entire cross section to the finger through the region of trapped gas. During injection of the second gas slug, the liquid finger disappears quickly as gas flows in, and strong foam forms from the very beginning. A collapsed-foam region then forms near the inlet and slowly propagates downstream with a propagation velocity and mobility similar to that in the first gas slug. Behavior of the second liquid slug is likewise similar to that of the first liquid slug. Our results suggest that, in radial flow, the small region of foam collapse very near the well is crucial to injectivity because of its high mobility. The subsequent gas and liquid slugs behave like the first slugs. The behavior of the first gas slug and subsequent liquid slug is thus representative of near-well behavior in a SAG process.Green Open Access added to TU Delft Institutional Repository ‘You share, we take care!’ – Taverne project https://www.openaccess.nl/en/you-share-we-take-care Otherwise as indicated in the copyright section: the publisher is the copyright holder of this work and the author uses the Dutch legislation to make this work public.Petroleum Engineerin