Intermittent Alkali Flooding in Vertical Carbonate Reservoirs

Abstract

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.

Wettability Index of Carbonatic Reservoirs and EOR: Laboratory Study to Optimize Alkali and Surfactant Flooding

“…Previous studies of the writers 19,20 show that oil recovery increases with the rise of alkali concentration when continuous flow is applied. The insoluble soap was detected as a colloidal form in the alkali concentration range used, even though it must be noticed that the continuous flow does not allow the precipitation of this insoluble soap onto the rock surface.…”

“…The range of alkali and surfactant concentrations have been obtained from previous IFT measurement optimization, corresponding to 0.05, 0.2, and 0.5 molar for alkali and 0.05% by weight for surfactant 19,20 . All the experimental activity described in this study has been performed at the Petroleum Engineering Laboratory, Department of Mining, Petroleum and Environmental Engineering of the University of Bologna (Italy).…”

“…Moreover, by aging anionic surfactant in carbonatic rock it is likely to have a depletion of surfactant by co-adsorption, which does not turn into a more favorable wettability condition 14 . The solely alkali foods at 0.05 and 0.5 molar are not performed in continuous flow case because results can be expected as oil recovery increases with the increment of alkali concentration 19,20 . Each flood is performed on two or more samples and the representative values of ultimate oil recovery and wettability index are averaged.…”

Enhanced Oil Recovery: An Update Review

“…As of date, no chemical flooding other than polymer-flooding field in carbonate reservoirs have been reported in the literature reviewed. However, ASP has been tested in carbonate formations in the lab in Arab-D [193] and Upper Edward's [19] and Pietra Leccese outcrop [194][195][196] in core samples. Alkali-Surfactant single well test has been reported in the Mauddud carbonate reservoir in Bahrain as part of ASP feasibility studies in oil-wet limestone reservoirs [197].…”

“… High-pressure air injection (HPAI) has been proposed (e.g., Ekofisk, North Sea), but has not yet been tested for technical and economical reasons [288,289]. Mexico has also considered the potential of air injection in offshore fields [194]. However, we do not foresee offshore implementation of HPAI in the near term.…”