Little oil can be produced from fractured oil-wet reservoirs by water flooding. Introduction of surfactant into the brine phase can improve the oil production by lowering the oil-water interfacial tension (IFT) and by altering the wettability of the matrix block to water-wet. A 3-D numerical simulator is developed to model this process. The capillary pressure, relative permeability and residual saturations of both phases are considered as functions of IFT and wettability, which are correlated to the surfactant and salt concentrations based on the data obtained from laboratory experiments. The mass balance equations are solved with a fully implicit scheme. Numerical simulation matches the experimental data obtained for alkaline surfactant imbibition. Simulation results indicate that both capillarity and gravity help to improve oil production: in the early stage of the production, capillarity is found to be the major driving force, and in the later stage, gravity dominates the production. Surfactant diffusion into the matrix block leads to IFT and wettability alterations which in turn lead to oil mobilization. Oil recovery by the time surfactant completely diffuses into the matrix block is found to be about 30% of the total recovery. As matrix block height increases, or surfactant alters wettability to a lesser degree, or permeability decreases, oil production rate decreases.


Carbonate reservoirs are mostly naturally fractured and are oil-wet or mixed-wet.[1,2] Recovery factor in these reservoirs depends on matrix permeability, wettability, fracture intensity, and fluid properties.[3] Water flooding is an effective technique for fractured reservoirs if the matrix is water-wet. The positive capillary pressure helps in spontaneous imbibition of water into the matrix leading to oil recovery. But since most of the carbonate reservoirs are oil-wet/mixed-wet in nature, capillary pressure is predominantly negative and water flooding does not lead to a significant amount of oil recovery from the matrix. Surfactant flooding (or "huff-n-puff") techniques are being developed[4–18] to improve oil recovery from oil-wet/mixed-wet, fractured carbonate formations and are the subject of this study.

Austad and coworkers have conducted a series of studies[10–13] on oil recovery from oil-wet chalk cores by use of cationic surfactant solutions. They have shown that cationic surfactants, such as DTAB, are quite effective (recovery ∼70% original oil in place, OOIP) in imbibing water into originally oil-wet cores at concentrations greater than their CMC (∼1 wt%). The imbibition mechanism is proposed as

  • the formation of ion pairs by the interaction between surfactant monomers and adsorbed organic carboxylates from the crude oil,

  • water-wettability of the solid surface due to dissolution of the ion pairs into the oil phase and micelles,

  • countercurrent imbibition of brine due to positive capillary pressure.

The imbibition rate increases with temperature and decreases with connate water saturation. The interfacial tension between the surfactant solution and oil are not low (> 0.1 mN/m). Austad et al.[14–16] identified on several inexpensive cationic surfactants of the form C10NH2 and bioderivatives from the coconut palm, termed Arquad and Dodigen (priced at 3 US$ per kg), which were able to recover 50 to 90% of OOIP.

The higher cost of cationic surfactants compared to anionic surfactants (which are usually priced at ∼1 US$ per kg) and relatively higher concentration required (∼1 wt %) has encouraged other to evaluate anionic surfactants for fractured carbonates[17–18] in the presence of a low concentration potential determining ions (∼0.3 M Na2CO3). They found that interfacial tension (IFT) can be lowered to ultralow levels (∼10–3 mN/m), wettability can be changed to intermediate wettability, and imbibition can be improved (>50% OOIP) by the use of very dilute (0.05 wt %) anionic surfactant/alkali solutions.

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