Conventional alkali flooding in numerous carbonatic reservoirs is often not effective due to insufficient contact time to reverse rock wettability from oil-wet into a more favorable condition to get the highest ultimate oil recovery, i.e., water-wet or partially water-wet conditions. Therefore, conventional flooding might be not completely efficient and/or adequate. Applying intermittent flow helps rock surface to complete its wettability reversal and to improve the final oil recovery. In the present study, laboratory evaluations of alkali and Alkali-Surfactant-Polymer (ASP) flooding combined with intermittent flow are presented and comparatively discussed. An alkaline solution is injected into oil-wet homogeneous carbonatic core samples and aged for a week. This aging period represents an "intermittent flow" which allows rock surface to reach a more favorable condition for oil recovery; oil is repulsed from the rock surface and the core is then flooded by displacing brine. Core flood test is performed vertically in order to avoid the early breakthrough of injected water phase. In the solely alkali flooding, the results demonstrates that the concentration of alkali strongly affects the flooding efficiency. Alkali concentration is intentionally kept low.In fact, high alkali concentration (of about 0.5 molar) is not recommended because the insolubility of insitu soap (soap produced by the reaction of the alkaline substance with the acid present in the oil phase) causes pore space plugging and therefore permeability reduction. The application of intermittent flow is therefore less significant in the case where high initial water saturation is present. The second part of this study emphasizes on alkali-surfactant-polymer flooding. In particular, laboratory tests highlighted that the highest final oil recovery with the lowest Water-to-Oli Ratio (WOR) is obtained by aging the alkaline solution after the injection of a surfactant, and then flooding the whole system by a polymer solution. Fractured oil-wet carbonatic reservoirs seem the best candidates for the application of this technique since aging time would allow alkali to diffuse and reverse rock wettability also in otherwise unaccessible zones. The proposed technique seems very effective to increase the ultimate oil recovery of these reservoirs. Traditionally, alkali flooding in oil-wet carbonatic reservoir is believed to require the consumption of a large mass of alkaline substances. However, the mass of this substance is responsible for the wettability reversal into a more favorable condition for oil recovery, and can be acceptably managed by a proper design of the flooding parameters.

Intermittent alkali flooding can significantly enhance oil recovery in oil-wet carbonate reservoirs. The method basically acts in two ways, by reducing the interfacial tension between the reservoir fluids and by reversing the wettability to a more favorable condition. However, the reversal of wettability requires aging time to reach the equilibrium. An intermittent or a pausing period is then adopted for the proposed alkali flooding process to let the surface reaching the maximum favorable wettability. As the injected fluid is paused during the flood process, vertical or inclined reservoirs are more suitable for this combination because the water tongue effect does not cause an early breakthrough. Laboratory results show that one-week-intermittent alkali flooding in homogeneous carbonate rock yields greater oil recovery, about 10 percent larger than conventional continuous alkali flooding in a proper range of injected alkali concentration. Low alkali concentration causes quick alkali depletion as time increases, while high alkali concentration causes pore plugging by in-situ precipitation of insoluble soap. The alkalinity of injected fluid should be kept as high as possible. Therefore, a strong alkali such as sodium hydroxide is recommended. High acid concentration in crude drives in-situ saponification frontward; hence, alkali concentration range should be carefully studied. Normally, high initial water saturation prevents the system from alkali accumulation and, as a consequence, insoluble soap precipitation is less concerned. Fractured carbonate reservoirs are probably the most suitable candidates for the application of this technique, since aging time would allow alkali to diffuse to, and reverse the wettability of the inaccessible and unswept zones. The proposed technique seems very effective to increase the ultimate oil recovery in oilwet carbonate reservoir. The drawbacks seem acceptable and the expected results are promising. Introduction The best practices of petroleum production suggest that oil is first produced by primary recovery by means of natural drive mechanisms. After a certain period of production, the natural drive decreases and eventually large amount of oil cannot be recovered. Prolonging the production will not yield further economical results, unless secondary recovery and/or Enhanced Oil Recovery (EOR) are utilized to extend the productive life of the reservoir. Secondary recovery (mostly waterflood) is performed by injecting water (normally natural, artificial, or sea brine) below the water table. Additional oil is released from the reservoir rock by waterflood pressure that overcomes the oil-entrapped capillary force. Some reservoirs may not respond to waterflood because of the unfavorable reservoir characteristics and of the overall geological conditions. The ultimate oil recovery after primary and secondary recovery is less than 40% of the Original Oil In Place (OOIP) in most reservoirs 1. EOR may thus be chosen to improve oil recovery. EOR, also called tertiary recovery, is performed by injecting fluid materials that are absent in the reservoir 2. EOR is not necessarily performed after the water flooding phase. An EOR method can be designed after primary recovery when waterflood is expected to give uneconomical results, or even waterflood can be adopted since the early production phase. Amongst conventional EOR methods are steam flooding, miscible flooding (e.g. CO2 injection), and immiscible flooding (injection of polymer, surfactant, alkali, gel, and foam). Nowadays, each method has been modified to suit the requirements of specific reservoir conditions. Alkali flooding has been investigated since 1917. Alkaline substances are quite inexpensive, but this technique normally yields questionable results. Sodium hydroxide is the most commonly used alkali because it shows the highest efficieny amongst other alkaline substances. Alkali display several actions to improve the oil recovery when they are injected into the reservoir. The most noticed phenomena taking place during the displacement of alkali in reservoir rocks are a) Interfacial Tension (IFT) reduction of reservoir fluids by acid-base interaction and b) wettability changes of rock matrix. Normally, the injected alkaline solution reacts with the natural acid substances existing in the crude oil phase to form in-situ surfactant at the interface, which causes spontaneous emulsification. Moreover, the injected alkali reacts as well with the rock matrix and eventually the wettability characteristic turns into a more favorable condition for the water displacement process.

Reduction of interfacial tension (IFT) between residual crude oil and formation fluids in oil reservoirs is the key to enhanced oil recovery (EOR) by surfactant flooding. However, adsorption of injected surfactant on minerals in the oil-bearing rock matrix reduces the effectiveness of this method. The present study investigated the effects of surfactant adsorption and desorption in the rock matrix on the oil recovery ratio achieved by surfactant-EOR. Sodium dodecylbenzene sulfonate (SDBS), a common surfactant in EOR, was used with Berea sandstone samples (rock particles and cores) as adsorbent. Adsorption of SDBS in the samples increased with concentration, and the static saturated amount was 0.9 mg-SDBS/g-rock for 1.0 wt% SDBS-water solution. If brine (1.0 wt% salinity) was injected after saturated adsorption of SDBS in the core, 83 % of adsorbed SDBS was desorbed into the brine (the reversibility effect). To clarify the reversibility effect in oil reservoirs, field scale numerical simulations were conducted for a typical 5 spot model (area: 180 m 180 m, thickness: 60 m) using core-flooding data reported previously. By introducing the reversibility model into the simulations on of surfactant flooding injection of slugs of 0.1 PV and 0.3 PV into the initial reservoir, oil recovery factor showed differences of 2.3 % and 2.9 % compared to without the model, respectively. Injection of the surfactant solution after water-flooding caused a difference of only 0.4 %

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