Analysis of Oil Recovery by Spontaneous Imbibition of Surfactant Solution

Abstract

Abstract Depending on rock and oil type, lowered interfacial tension (IFT) by the addition of surfactant to brine may contribute to capillary imbibition recovery with the support of gravity drainage in naturally fractured reservoirs (NFR). This paper aims at identifying and analyzing the recovery mechanisms and performing up-scaling exercises for oil recovery from different rock types by the capillary (spontaneous) imbibition of surfactant solution. Laboratory tests were performed using four different rock types that could possibly be the reservoir rock matrix of the NFRs (sandstone, limestone, dolomitic limestone and chalk). The sandstone sample was surface-coated to create a boundary condition causing only counter-current interaction. Wide variety of oils (light and heavy-crude oils, kerosene, and engine oil) was selected as the oleic phase. Different types (non-ionic and anionic) and concentrations of surfactants were used as the aqueous phase as well as the brine as a base case. The samples fully saturated with oil (Swi=0) were exposed to static capillary imbibition and the recovery was monitored against time. Some experiments on the chalks were repeated using pre-wet samples (Swi>0) to clarify the changes in the capillary imbibition characteristics of the rock. The changes (positive or negative) in the recovery rate and ultimate recovery compared to the brine imbibition were evaluated for the rock, surfactant and oil types. It was observed, for some rock samples, that the imbibition recovery by surfactant solution was strictly controlled by the concentration of the surfactant. On the other hand, the difference in the recovery rate and ultimate recovery between high and low IFT could be due not only to change in the IFT but also the change in the wettability and adsorption, which might vary with the rock type. This was also analyzed using the shape of the curves that indicates the strength of the capillarity on the recovery and the interaction type, i.e., co- or counter-current. In addition to the above-mentioned qualitative analysis, the recovery curves were evaluated for up-scaling. Existing dimensionless scaling groups were tested. The scaling exercise helped identify whether the recovery is driven by gravity or capillary forces and clarify the interaction type, i.e., co-or counter-current or both. The ultimate recoveries were correlated to the Inverse Bond Number using twenty-five cases covering different combinations of four rock types, four oil and four surfactant samples. It was shown that the inclusion of the wettability factor would make the correlation more universal. Introduction Injection of surfactant solution into naturally fractured reservoirs (NFR) has gained a great deal of attention in recent years. Although reported field cases are limited, considerable amount of laboratory studies have appeared in literature. Capillary imbibition recovery can be enhanced by the addition of surfactant into water to reduce the IFT. Depending on the size and wettability characteristics of the reservoir matrix, the gravitational forces might play a role in the matrix recovery as well. Different aspects of capillary imbibition of low IFT aqueous phase were studied in the past1–13. More research is needed to clarify the effects of surfactant addition to the aqueous phase on the capillary imbibition recovery rate and ultimate recovery and understand the mechanics of the low IFT imbibition. The changes on the rock-fluid and fluid-fluid interactions due to surfactant addition could act in different ways in oil recovery by capillary imbibition. It has been observed that the reduction in IFT yields higher ultimate recovery but slower imbibition rate3–6,10 for water wet sandstone samples. Schechter et al.4 observed the same for iso-octane recovery from limestones whereas Babadagli13,14 reported that the capillary imbibition of low IFT solution (with a non-ionic surfactant) was faster than high IFT case when a light crude oil is used with a limestone sample. Austad et al.9 observed the same for chalks with cationic surfactant. Keijzer and deVries1 showed that the surfactant imbibition did not yield any incremental recovery for water-wet sandstone but some effects were observed on the recovery rate.