# Wettability of Carbonate Reservoir Rocks:
## 1 Introduction  
Wettability is a two- or multi-phase property defined as the preference of solid matrix of rocks to be in contact with one fluid rather than another [1]. It is one of the most critical properties controlling multiphase flow and transport in porous media [2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13]. Studies have shown that the wettability of rocks has a direct impact on relative permeability [4, 14, 15, 10], capillary pressure [3, 16], and performance of secondary and tertiary oil recovery methods [5, 17, 18]. A lack of knowledge of rock wetting behavior may lead to substantial uncertainties in the estimation of a reservoir's accessible oil and recovery rate [18, 19, 20, 21]. Therefore, an advanced understanding of this parameter can significantly contribute to better assigning saturation functions to reservoir simulation models, modeling CO\({}_{2}\) geo-sequestation [22, 23, 24], and evaluation of formation damage [25, 26, 27] as well as assessing secondary and tertiary enhanced oil recovery efficiencies [21]. Typically, reservoir rocks are initially water-wet since rock particles tend to be solely in contact with brine [1]. However, as crude oil migrates into a reservoir from a source rock, heavier components of oil get adsorbed to the surface of rock over time. Accordingly, reservoir rocks incline towards have less water-wet tendency as they age. Several studies suggested that the wettability of reservoir rocks is a function of various parameters, including aging time [28, 29], temperature [1, 30], heavy components of the crude oil [1, 29], mineral composition of the rocks [31], and pore structures [31]. In the literature, indirect evaluations of wettability have been performed by measuring petrophysical parameters affected by contact angle, e.g., relative permeability and capillary pressure curves [1, 15, 32]. Laboratory methods, such as Amott [33], Amott-Harvey [34, 35],standard USBM [36], and modified USBM [37] have been widely applied in the oil industry. In addition, relative permeability-based techniques including [PERSON]'s triple rules of thumb [38], the normalized water fractional flow curve [39], Lak [15], and modified Lak [13] were proposed to deduce knowledge of wettability in rocks. There exist other wettability indicators, such as the relative pseudo work of imbibition [40], MPMS (MPMS stands for Mirzaei-Paiaman, Mashih and Standnes) [41; 42], relative imbibition rate [43], rise in core [44], and NMR-based techniques [45; 46; 47; 48; 49; 50] that require additional experiments. Various studies have been conducted to evaluate wettability characteristics of reservoir rocks. For example, [PERSON] and [PERSON] [51] measured contact angle by analyzing the droplet of oil on a polished crystal of reservoir rock on 50 reservoir rocks and noted that 64% of carbonate reservoirs were intermediate-wet, 28% oil-wet, and 8% water-wet. [PERSON] and [PERSON] [52] measured wettability of 161 carbonate samples using image analysis and concluded that 80% of the samples were oil-wet (100-180 degrees), 12% intermediate-wet (80-100 degrees), and 8% water-wet (0-80 degrees). [PERSON] et al. [53] analyzed the wettability of Saudi Arabian carbonate reservoir rocks using the USBM, Amott, and CryoSEM methods and found that almost all samples were neutral to slightly oil-wet. [PERSON] et al. [54] used displacement characteristics and indicated that preserved carbonate samples exhibited significantly more oil-wet character than restored samples. [PERSON] [55] investigated the wettability of Thammama and Arab carbonate reservoirs in Abu Dhabi. The survey revealed oil-wet conditions in the oil zone, mixed-wet in the transition zone, and water-wet in the water zone. [PERSON] et al. [56] investigated the wettability of Arab carbonate reservoir using Amott, USBM, and relative permeability techniques as well as measurements of contact angle by analyzing the droplet shape placed on a smooth substrate (calcite plate).