No abstract

We report an experimental study of the behavior of CO2 and N2 foams in granular porous media using X-ray computed tomography. In the experiments either CO2 or N2 gas is forced through natural porous media initially saturated with a surfactant solution, a process known as surfactant-alternating-gas or SAG. The CO2 was either under sub- or supercritical conditions, whereas N2 remained under subcritical conditions at all experimental conditions. We found that CO2 injection following a slug of surfactant can considerably reduce its mobility and promote higher liquid recovery at the experimental conditions investigated. Foaming of CO2 builds-up a lower pressure drop over the core at both low and high pressures than N2. Both gases require space to develop into foam. The space is longer for N2 (larger entrance effect) and increases with increasing gas velocity. Moreover, the ultimate liquid recovery by CO2 foam is always lower than by N2 foam. The possible mechanisms explaining the observed differences in foaming behavior of the two gases are discussed in detail.

We report the study of flow of CO 2 and N 2 foam in natural sandstone cores containing oil with the aid of X-ray computed tomography. The study is relevant for enhanced oil recovery (EOR). The cores were partially saturated with oil and brine (half top) and brine only (half bottom) to mimic the water-oil transition occurring in oil reservoirs. The CO 2 was used either under subcritical conditions (P ) 1 bar) or under supercritical (immiscible (P ) 90 bar) and miscible (P ) 137 bar)) conditions, whereas N 2 remained subcritical. Prior to gas injection the cores were flooded with several pore volumes of water. In a typical foam experiment water flooding was followed by the injection of 1-2 pore volumes of a surfactant solution with alpha olefin sulfonate (AOS) as the foaming agent. We visually show how foam propagates in a porous medium containing oil. At low-pressure experiments (P ) 1 bar) in the case of N 2 , weak foam could be formed in the oil-saturated part. Diffused oil bank is formed ahead of the foam front, which results in additional oil recovery, compared to pure gas injection. CO 2 hardly foams in the oil-bearing part of the core, most likely due to its higher solubility. Above the critical point (P ) 90 bar), CO 2 injection following the slug of surfactant reduces its mobility when there is no oil. Nevertheless, when the foam front meets the oil, the interface between gas and liquid disappears. The presence of the surfactant (when foaming supercritical CO 2 ) did not affect the oil recovery and pressure profile, indicating the detrimental effect of oil on foam stability in the medium. However, at miscible conditions (P ) 137 bar), injection of surfactant prior to CO 2 injection significantly increases the oil recovery.

No abstract

This paper reports a laboratory study of foams intended to improve immiscible gas flooding in oil production. The study is relevant for both continuous and water alternating gas (WAG) injection schemes. The effect of oil on the longevity of nitrogen and air foams was studied in bulk for a selected set of surfactants. Foam heights were measured in a glass column as a function of time, in the absence and presence of mineral and crude oils. The column experiments indicated that foam longevity increases as the carbon chain length in the oil molecule increases; that is, foam is generally more stable in the presence of higherviscosity oils. The surfactant formulation that gave the most stable foam in the presence of oil was used in core floods. Oil recovery from natural sandstone cores with CO 2 and with N 2 foams was studied with the aid of X-ray computed tomography, while the injection rates, foam quality, and surfactant concentration were varied. The core floods revealed that foam increases oil recovery by as much as 20% of the oil initially in place (OIIP) as compared with water flooding, while gas injection increases oil recovery by 10% only. Thus, foam can achieve an additional recovery of up to 10% relative to gas injection. This confirms that foam is potentially an efficient enhanced oil recovery (EOR) method.

No abstract

This paper reports a laboratory study of foam for improving immiscible gas flooding. The study is relevant for both continuous and Water Alternating Gas (WAG) injection schemes. The effect of oil on the longevity of nitrogen and air foams was studied in bulk for a selected set of surfactants. Foam heights were measured in a glass column as a function of time, in the absence and presence of mineral and crude oils. From the column experiments it was found that foam longevity increases as the carbon chain length in the oil molecule increases, i.e. foam is more stable for higher viscosity oils. A surfactant formulation that gave the most stable foam in the presence of oil was used in the core-floods. Oil recovery with CO 2 and with N 2 foams from natural sandstone cores was studied with the aid of X-ray Computed Tomography, varying the injection rates, foam quality and surfactant concentration. The core-floods revealed that foam increases the oil recovery by as much as 20% of the oil initially in place (OIIP) over water flooding while injection of gas increased oil recovery by 10% only. Thus, foam adds up to 10% additional recovery on top of gas injection. This confirms that foam is potentially an efficient Enhanced Oil Recovery (EOR) method.

A systematic CT-scan-aided laboratory study of N2 foam in Bentheimer sandstone cores is reported. The aim of the study was to investigate whether foam can improve oil recovery from clastic reservoirs subject to immiscible gas flooding. Foam was generated in situ in water-flooded sandstone cores by coinjecting gas and surfactant solution at fixed foam quality. It was stabilized using two surfactants, namely, C14–16 α-olefin sulfonate (AOS) and mixtures of AOS and a polymeric fluorocarbon (FC) ester. The effects of surfactant concentration, injection direction, surfactant preflush, and core length on foam behavior were examined in detail. Stable foams were obtained in the presence of waterflood residual oil. It was found that foam strength (mobility reduction factor) increases with surfactant concentration. Foam development and, correspondingly, oil recovery without surfactant preflush were delayed compared to the case with preflush. Gravity-stable foam injection caused a rapid increase in foam strength and an incremental oil recovery almost twice that for unstable flow conditions. Core floods revealed that the incremental oil recovery by foam was as much as (23 ± 2)% of the oil initially in place after injection of 4.0 pore volumes (PV) of foam (equal to the injection of 0.36 PV of surfactant solution). Incremental oil recovery was only (5.0 ± 0.5)% for gas flooding under the same injection conditions. It appears that oil production by foam flooding occurs by the following main mechanisms: (1) residual oil saturation to foam flooding is lower than that to water flooding; (2) formation of an oil bank in the first few injected pore volumes, coinciding with a large increase of capillary number; and (3) a long tail production due to the transport of tiny oil droplets within the flowing foam at a fairly constant capillary number. The observations of this study support the concept that foam is potentially an efficient enhanced oil recovery (EOR) method.