Investigation of Foam Stability in Porous Media at Elevated Temperatures

Abstract

Summary This paper describes a laboratory study of the factors controlling the formation and breakdown of foams in porous media at elevated temperatures. The degradation of a foam when gas injection was discontinued involved the gradual transformation of a foam with a noncondensable gas phase (gas foam) to a foam with steam as the gas phase (steam foam). The ability to prevent release of the noncondensable gas phase was strongly influenced by surfactant type and concentration. The formation of steam foams in the absence of noncondensable gas was a critical function of steam velocity and permeability. Surfactant concentration and chain length, salinity, and the presence of oil were important variables in determining mobility reduction of steam. Increased oil recovery from cores undergoing steam displacement was obtained when surfactant slugs were injected with and without noncondensable gas. The presence of a noncondensable gas led to the formation of a more effective and durable foam. Introduction Steam injection is the most widely used method to recover heavy oil. Channeling and gravity segregation effects can considerably reduce the amount of oil potentially recoverable by this process. Adding surfactant to the injected steam with and without noncondensable gas to create foams in situ is a promising technique used for conformance control. A number of authors1–3 have reviewed foam field results, mainly from California reservoirs, together with the underlying laboratory work. Additional field results have been reported for reservoirs in California4 and Venezuela,5 and recent laboratory studies have focused on the factors influencing foam formation and propagation,5–11 flow behavior,12,13 oil displacement efficiency,14 and the development of predictive models.2,6 From a review of field data and theoretical considerations,2 it has been demonstrated that foams are more effective when noncondensable gas is present even in small concentrations. The major attraction of injecting surfactants without a noncondensable gas is an economic one. Steam foams are viable in reservoirs where channeling is relatively close to the wellbore and heat losses are small, as well as in reservoirs having substantial gas production. They also appear to be well suited for cyclic steam injection.5 The rational selection of a cost-effective foam process, with or without a noncondensable gas, requires not only an understanding of the reservoir characteristics, but also the factors that control the formation and breakdown of the foams in porous media. In this study, noncondensable-gas foams were generated in a sandpack by injection of hot water (or steam), gas, and surfactant. The degradation process was studied at a function of ending surfactant and gas injection. The influence of surfactant concentration and salinity on the degradation kinetics was also studied. Surfactants were evaluated in terms of their ability to prevent washout of the foam. Experiments in the absence of noncondensable gas were conducted to determine the effect of steam velocity, permeability, oil injection, salinity, and surfactant concentration on mobility reduction. Surfactants were evaluated in terms of their efficiency in producing a steam foam with minimum concentrations. The results of these investigations were related to increased oil recovery from Athabasca oil-sand cores undergoing steam displacement. Experimental Materials. The surfactants used in this study are listed with their properties in Table 1. All surfactant concentrations given refer to the active ingredients dispersed in de-ionized water or NaCl brine. Sandpacks were prepared from silica sand or Ottawa sand sieved into mesh fractions of 30/60, 60/80, 80/120, 120/200, and <200, giving absolute permeabilities of 110, 40, 20, 13 to 10, and 5 to 2 darcies, respectively. Oil sand used in the displacement experiments was obtained from the McMurray formation at the Suncor mine site. Refined hydraulic oil with a viscosity of 205 mPa·s at 40°C [205 cp at 104°F] was obtained from the PetroCan Refinery in Edmonton. Equipment. A schematic of the apparatus used for both gas-foam and steam-foam experiments is shown in Fig. 1. The jacketed cell (2.5-cm [1-in.] ID and 59 cm [23.2 in.] long) was dry-packed with sand by a vibrational technique16 designed to give a uniform packing density. The absolute permeability of the pack was measured at a number of water flow rates before and after each experiment to indicate when the pack had to be renewed because of silica dissolution at test temperatures. Steam or hot water was injected by passing water at a constant rate through copper tubing immersed in two constant-temperature oil baths placed in series. The first bath preheated the water before its conversion to steam in the second bath. A third bath, used to circulate heating fluid through the core jacket, provided additional control of the steam saturation in the pack. The injected water was degassed by bubbling helium gas for long periods before and during injection. Two syringe pumps were used to inject water or brine and surfactant concentrate directly into the steam or hot water flow. Mass flowmeters were used to inject nitrogen gas downstream of the surfactant injection line. The pressure in the core was controlled by backpressure regulators. All lines leading into and out of the cell were traced with electric heating tape and the entire apparatus was insulated to minimize heat loss. Pressure drops, temperature (T-type thermocouples), and weights of the injected and produced fluids were continuously monitored. Data were acquired by a Hewlett-Packard 3497A data logger controlled by a Hewlett Packard 86B computer. Materials. The surfactants used in this study are listed with their properties in Table 1. All surfactant concentrations given refer to the active ingredients dispersed in de-ionized water or NaCl brine. Sandpacks were prepared from silica sand or Ottawa sand sieved into mesh fractions of 30/60, 60/80, 80/120, 120/200, and <200, giving absolute permeabilities of 110, 40, 20, 13 to 10, and 5 to 2 darcies, respectively. Oil sand used in the displacement experiments was obtained from the McMurray formation at the Suncor mine site. Refined hydraulic oil with a viscosity of 205 mPa·s at 40°C [205 cp at 104°F] was obtained from the PetroCan Refinery in Edmonton. Equipment. A schematic of the apparatus used for both gas-foam and steam-foam experiments is shown in Fig. 1. The jacketed cell (2.5-cm [1-in.] ID and 59 cm [23.2 in.] long) was dry-packed with sand by a vibrational technique16 designed to give a uniform packing density. The absolute permeability of the pack was measured at a number of water flow rates before and after each experiment to indicate when the pack had to be renewed because of silica dissolution at test temperatures. Steam or hot water was injected by passing water at a constant rate through copper tubing immersed in two constant-temperature oil baths placed in series. The first bath preheated the water before its conversion to steam in the second bath. A third bath, used to circulate heating fluid through the core jacket, provided additional control of the steam saturation in the pack. The injected water was degassed by bubbling helium gas for long periods before and during injection. Two syringe pumps were used to inject water or brine and surfactant concentrate directly into the steam or hot water flow. Mass flowmeters were used to inject nitrogen gas downstream of the surfactant injection line. The pressure in the core was controlled by backpressure regulators. All lines leading into and out of the cell were traced with electric heating tape and the entire apparatus was insulated to minimize heat loss. Pressure drops, temperature (T-type thermocouples), and weights of the injected and produced fluids were continuously monitored. Data were acquired by a Hewlett-Packard 3497A data logger controlled by a Hewlett Packard 86B computer.