Ramez Nasralla

Demonstrating the Potential of Low-Salinity Waterflood to Improve Oil Recovery in Carbonate Reservoirs by Qualitative Coreflood

Low salinity waterflood (LSF) is a promising improved oil recovery (IOR) technology. Although, it has been demonstrated that LSF is an efficient IOR method for many sandstone reservoirs, the potential of LSF in carbonate reservoirs is still not well-established as only a limited number of successful coreflood experiments are available in the literature. Therefore, the aim of this study was to examine the oil recovery improvement by LSF in carbonate reservoirs by performing coreflood experiments. This paper proposes an experimental approach to qualitatively evaluate the potential of LSF to improve oil recovery and alter the rock wettability during coreflood experiments. The corefloods were conducted on core plugs from two Middle Eastern carbonate reservoirs with a wide variation of rock properties and reservoir conditions. Seawater and several dilutions of formation brine and seawater were flooded in the tertiary mode to evaluate their impacts on oil recovery compared to formation brine injection. In addition, a geochemical study was performed using PHREEQC software to assess the potential of calcite dissolution by LSF. The experimental results confirmed that lowering the water salinity can alter the rock wettability towards more water-wet, causing improvement of oil recovery in tertiary waterflood in plugs from the two reservoirs. Furthermore, seawater is more favorable for improved oil recovery than formation brine as injection of seawater after formation brine resulted in extra oil production. This demonstrates that the brine composition plays an important role during waterflooding in carbonate reservoirs, and not only the brine salinity. It was also observed that oil recovery can be improved by injection of brines that cannot dissolve calcite based on the geochemical modeling study. This implies that calcite dissolution is not the dominant mechanism of IOR by LSF. To conclude, this paper demonstrates that low-salinity waterflood has a good potential as an IOR technology in carbonate reservoirs. In addition, the proposed experimental approach ensures the verification of LSF effect, either it is positive or negative. However, more work is required to further explore the most influential parameters affecting LSF response and explain the dominant mechanisms. Introduction Low salinity waterflood (LSF) is a relatively mature improved oil recovery technique for sandstone reservoirs. The concept of LSF, for sandstones, is to lower the ionic strength of the injected brine, which leads to an alteration of the rock wettability towards more water-wet and hence an improvement of oil recovery. Numerous laboratory studies demonstrated the effect of LSF by spontaneous imbibition tests and coreflood experiments (Bernard 1967, Jadhunandan and Morrow 1991, Yildiz and Morrow 1996, Tang and Morrow 1997, Lager et al. 2006, Ligthelm et al. 2009, Masalmeh et. al. 2013). Furthermore, published data confirmed the positive response of LSF at the field scale (Webb et al. 2004, Lager et al. 2008, Vledder et al. 2010). However, the potential of LSF for carbonate reservoirs has not been well investigated. Several spontaneous imbibition tests were performed on Stevns Klint outcrop chalk (Austad et al. 2005, Zhang and Austad 2006, Strand et al. 2006). The results demonstrated the wettability alteration towards more water-wet by seawater or modified seawater. Increasing the sulfate concentration in seawater resulted in more change of wettability towards waterwetness. Ferno et al. (2011) performed spontaneous imbibition tests on different chalk outcrops (Stevns, Rordal, and Niobrara) using brines with and without sulfate. The effect of adding sulfate to the brines on wettability alteration was observed only in plugs from Stevns Klint chalk, but not from the other 2 chalk types. Webb et al. (2005) performed

Driving Mechanism of Low Salinity Flooding in Carbonate Rocks

Several studies conducted mainly on the laboratory scale indicate that in carbonate rocks oil displacement can be influenced by the ionic composition of the brine, providing an opportunity to improve recovery by optimizing the brine mixture used in secondary or tertiary recovery. In industry this topic has been termed “low salinity flooding (LSF) in carbonates” while the underlying mechanisms are not very well understood. The increased oil recovery has been attributed to wettability alteration to a more water-wet state. However, in some studies a positive low salinity effect (LSE) has been ascribed to dissolution of rock, which occurs on the laboratory scale but due to equilibration of brine with carbonate minerals on larger length scales this is not relevant for the reservoir scale. Therefore, the objective of this paper is to gain a better understanding of the underlying mechanism(s) and investigate whether calcite dissolution is the primary mechanism of the LSE. We used a model system where the contact angle of crude oil deposited on planar surfaces coated with crushed carbonate rock particles was monitored as a function of brine composition. The approach is similar to the one published in Mahani et al. (2014) for sandstone rock, but instead of clay minerals we used carbonate materials from natural limestone and Silurian dolomite rocks. Furthermore, the effective surface charge at the oil-water and water-rock interfaces was quantified via zeta-potential measurements at several salinity and pH levels in order to establish a link between changes in the intermolecular interactions at the solid-liquid interface and the contact angle at the brine-oil-rock contact line, which is an indicator for wettability change. The impact of mineral dissolution was addressed by comparing the response to brines that were fully equilibrated (and hence dissolution suppressed) and the response to those completely under-saturated with calcium carbonate (leading to dissolution). The investigation was accompanied by geochemical modeling using PHREEQC. It was observed that by switching from formation water (FW) to seawater (SW), diluted seawater (dSW) and diluted seawater equilibrated with calcite (dSWEQ), the limestone surface became less oil-wet reflected in contact angle decrease. The recession of the 3-phase contact line observed for both SW and dSWEQ, which are not impacted by dissolution, suggests that the LSE occurs even in the absence of mineral dissolution. The trends observed for the zeta-potential data on brine composition clearly support the surface-charge-change mechanism for limestone, where at lower salinities the charges at the limestone-brine interface become more negative, causing lower adhesion or even repulsion between oil and rock. Dolomite rock shows a different behavior. First, there is a much smaller response in terms of contact angle change. Also, the zeta-potential of dolomite shows generally more positive charges at higher salinities and less decrease at lower salinities, where in comparison to limestone the electrostatic interaction remains attractive or becomes only weakly repulsive. In summary we conclude that a positive LSE in carbonate rock exists without any dissolution and it is driven by the brine composition dependency of electrostatic interactions between crude oil and rock. However, the magnitude of the LSE is impacted by the mineralogy of carbonate material.

Coupled Geochemical-Reservoir Model to Understand the Interaction Between Low Salinity Brines and Carbonate Rock

Low salinity waterflood (LSF) is a promising technology for improving oil recovery. Several laboratory studies have demonstrated the potential of LSF to alter the rock wettability and improve oil recovery in carbonate reservoirs. Some studies have considered calcite dissolution as a mechanism behind the wettability alteration by LSF in carbonates. Moreover, the interaction between rock and injected brine can lead to change in the injected brine composition and pH. Therefore, it is important to better understand the interaction between injected brine and carbonate rock to de-risk the LSF technology for field applications. A numerical model was developed by coupling a reservoir simulator (Shell in-house Simulator, MoReS) with a geochemical model (PHREEQC) to study the interaction between the injected brine and carbonate rock. Calcite is assumed to be the rock mineral to represent most of carbonate reservoirs. Two reservoir rock models are presented: one for coreflood scale and another for field scale. To mimic reservoir condition, the rock is saturated with formation brine (180 g/l) and several brines with different salinity and composition are injected. The model is calibrated to the published experimental data in the literature. Both Local Equilibrium and Kinetic approaches are used to model the interaction between injected brines and rock. Furthermore, the impact on calcite dissolution is examined against various parameters such as brine composition and pH, and temperature. The model results indicate that interaction between calcite and brine can reach equilibrium quickly. As a result, LSF may dissolve calcite from part or the whole core during flooding experiments depending on the kinetics of the interaction. However at field scale, the calcite dissolution occurs only in the area near the injector. This suggests that if calcite dissolution is one of the LSF mechanisms, this mechanism will not contribute to improving oil recovery at field scale. Although calcite dissolution can occur only near the injector, it can still change the composition and pH of the injected brine, which may have an impact on the oil recovery. The increase in salinity due to calcite dissolution in not significant in absence of CO 2 , but the brine pH may reach 8-9.