Long-Time Diversion in SAG Foam Enhanced Oil Recovery From Field Data

Abstract

The ability of foam to divert gas flow over a long period of gas injection in a Surfactant Alternating Gas (SAG) foam process is important for the economics of foam-diversion processes for enhanced oil recovery. Here we interpret field data from the foam test in the Cusiana field in Colombia, South America (Ocampo et al., 2013). In this test surfactant was injected into a single layer that had been taking about half the injected gas before the test; then gas injection resumed into all layers. Based on the size of the surfactant slug injected and estimates of adsorption and of water saturation in the foam in situ, we estimate that the treated region extended about 5.3 m from the injection well: fortunately the results to follow are not sensitive to this estimate. Based on the change in injection logs before the test and at day 5 of the test, when approximately 30 pore volumes of gas has been injected, foam still reduced gas mobility in the treated layer by about a factor of 9. We base this estimate on the decrease of injection into the treated layer and the increase into the other layers; the results are consistent among the layers. After 35 and 152 days of injection (220 and 1250 pore volumes gas injected), foam reduced gas mobility in the treated zone by about a factor of 4 and 2, respectively. This result suggests that foam continued to reduce mobility by a modest amount even after long injection of gas. In this test, the large volume of gas had quickly penetrated far beyond the edge of the surfactant bank. In a design where a larger bank of surfactant were injected, a much greater and longer diversion of gas would be expected. On the other hand, foam did weaken progressively as it dried out. Foam models where foam remains strong at irreducible water saturation would greatly overestimate foam effectiveness at long times in this test.

Effects of Surface Acidity and Polarity of SiO2 Nanoparticles on the Foam Stabilization Applied to Natural Gas Flooding in Tight Gas-Condensate Reservoirs

“…Because of the massive production of gases, such as methane or natural gas in the tight gas-condensated reservoirs in Colombia, the natural gas flooding with foam is a viable alternative for enhancing the recovery of oil. − Nevertheless, a significant limiting factor of foams during field applications is the fact that they are thermodynamically unstable, , hindering their long-term use . Some factors that affect the stability of the foams are the temperature, pressure, and presence of electrolytes and solid particulate material in the lamellae .…”

Injectivity Errors in Simulation of Foam EOR

“…For single-phase gas flow (at S w ¼ S wr ¼ 0.05), λ rt ¼43,250. One expects (Khatib et al, 1988; see also Rossen et al (2014)) that foam has collapsed at the large capillary pressure at S wr . If the model represented complete collapse, mobility at the wellbore would be 43,250 instead of 4301 as in Fig.…”

Injectivity of Multiple Slugs in Surfactant Alternating Gas Foam EOR: A CT Scan Study

“…Multiple gas and liquid slugs are injected in an SAG process. Many studies and field application of an SAG process have been published (Harpole et al 1994;Grigg et al 2002;Skauge et al 2002;Awan et al 2008;Farajzadeh et al 2009aFarajzadeh et al , 2009bNorris et al 2014;Rossen et al 2014;Mukherjee et al 2016). Most of these work were focused on in-situ foam generation, gas injectivity, and gas sweep efficiency in an SAG foam process.…”

“…Higher gas injectivity compared to coinjection of gas and surfactant solution was observed, as foam in the near-well region dries out and injectivity increases (Kibodeaux et al 1997;Shi and Rossen 1998;Shan and Rossen 2002). In a separate study, Rossen and Renkema (2007) conducted a series of simulation of multiple-cycle SAG process with conventional foam simulators. They found that injectivity of later slugs decreases after the first gas-and liquid-slug injection.…”