Evaluation of Surfactants for CO2 Mobility Control in Dolomite Reservoirs

Abstract

Laboratory studies were conducted to find the best surfactant for generating CO2 foam in the presence of residual oil for two dolomite reservoirs. Conventional anionic and nonionic surfactants did not foam very well in core tests at reservoir conditions. The poor performance was attributed to the oil-wet nature of the dolomite cores. A new surfactant formulation was developed that alters wettability and has much better oil tolerance. CO2 foams were generated easily with the new formulation and were more stable. Field tests are planned to demonstrate improvement of sweep efficiency using the new surfactant. Evaluation of surfactants for mobility control applications involved a series of tests that measured brine compatibility, bench foam height, flow resistance in corefloods, and adsorption on reservoir rock. Bench foam tests, often used for surfactant screening, were unable to predict the effects of oil in the corefloods. Even the low oil saturation remaining after immiscible or miscible CO2 injection was detrimental to foam generation. The new surfactant formulation works over a wide range of brine salinities, controls CO2 mobility better than conventional surfactants, and has moderately low adsorption on dolomite rock. Introduction Oil production from CO2 flooding is increasing steadily in the U.S. despite marginal oil prices. There are many field-wide projects under way in West Texas, and new projects are planned for the mid-90's. CO2 is injected continuously or alternated with water if there is channeling and gravity override. The need for better CO2 mobility control grows as the older projects mature because of declining oil production and increasing CO2 recycling costs. The use of foam-forming surfactants to improve sweep efficiency and reduce CO2 breakthrough has received extensive laboratory evaluation but only limited field testing with mixed results. A large field demonstration of CO2 foam is planned for 1992 that should define better the potential of this promising technology. This paper describes the evaluation of foam-forming surfactants for two dolomite reservoir applications. The objective for Reservoir A was to find a suitable surfactant to improve the performance of immiscible cyclic CO2 treatments. For Reservoir B, surfactant would be used in a CO2 drive to improve the injection profile and control in-depth CO2 mobility under miscible conditions. Both reservoirs are challenging applications for foam because the dolomite rock tends to be oil-wet, which inhibits in-situ foam generation. Residual oil saturations are higher in Reservoir A than in Reservoir B because the CO2 is injected well below the minimum miscibility pressure. Our strategy in evaluating surfactants was to select a few commercial products that were identified previously as good foaming agents. These products were passed through a series of screening tests that measured brine compatibility, bench foam height, adsorption on reservoir rock, and foam performance in corefloods at reservoir conditions. The corefloods were a critical part of our evaluation because they modeled reservoir behavior more accurately than bulk foam, glass bead pack, or sand pack tests. P. 215^

Effects of Foam Quality and Flow Rate on CO2-Foam Behavior at Reservoir Temperature and Pressure

“…Much of the early research has been reviewed by Heller and Taber, 5 Heller et al, 6 Marsden, 7 and Hirasaki. 8,9 Studies of foam mechanisms can be generally divided into two major groups: studies [10][11][12][13][14][15][16][17] conducted in most cases with nitrogen or steam at low and moderate pressures ͑below 1500 psia͒ and studies [18][19][20][21][22][23][24][25][26] conducted with CO 2 at higher pressures. To avoid confusing CO 2 foam with nitrogen foam, we would like to point out that nitrogen is a gas-like fluid while CO 2 is a dense, liquidlike fluid over much of the range of pressures and temperatures found in many oil reservoirs.…”

“…When a steady-state pressure drop across the core is achieved, the total mobility of CO 2 /surfactant solution can be calculated for the corresponding foam quality ͑CO 2 fraction͒, flow rate ͑total injection rate͒, and surfactant concentration. The foam resistance factor 25,27 is an expression commonly used to assess the magnitude of the mobility reduction in laboratory foam tests. The foam resistance factor is defined as the total mobility of CO 2 /brine divided by the foam mobility ͑total mobility of CO 2 /surfactant solution͒, where both mobility measurements are conducted at the same CO 2 -liquid volumetric injection ratio.…”

Core Flood Evaluation of Solvent Compositional And Wettability Effects On Hydrocarbon Solvent Foam Performance

“…Oil recovery by foam has been attributed to the emulsification and imbibition of oil into foam lamellae (14,45) . A very slow approach to steady state and continued slow oil production have previously been observed with nitrogen-and CO 2 -foams that exhibit some sensitivity to oil (16,17,46,47) . When the methane fractional flow was lowered to 72%, the pressure drop increased more steeply, correlating directly with an increased rate of oil production [ Figure 6(b)].…”

Numerical Study of Immiscible Foam Propagation in Porous Media in the Presence of Oil Using an Implicit-Texture Foam Model

“…While the gas injection rate is constant, the bottomhole injection pressure has an upward trend (Figure ). Because the presence of surfactant leads to gas trapping near the injection well and consequently mobility reduction of injected gas, more injection pressure is required for fluid displacement and the resistance to flow also increases . Even though the presence of surfactant is a necessary condition for foam creation, two other conditions ( S w > fmdry and S o < fmoil ) should also be fulfilled.…”