Recently, the application of nanoparticles for enhancing oil recovery (EOR) in carbonate reservoirs has received great attention from various researchers across the oil and gas industry. In contrast to sandstone reservoirs, carbonates are naturally neutral wet or preferentially oil wet and, therefore, the recovery of oil from these reservoirs by waterflooding techniques is relatively low and inefficient. Hence, the addition of chemical agents can modify rock wettability and increase the efficiency of the waterflooding process. The role of nanoparticles and their implementations in the field of oil recovery has been highlighted by many researchers in the past, due to their attractive features and characteristics. However, choosing the appropriate nanoparticles is not the only limiting factor to guarantee better performance in EOR but also depends on their stability and dispersion under aqueous conditions. Accordingly, many metal oxides or silicate-based nanomaterials have been subjected to surface modifications, following some complex and costly ineffective functionalization steps before their application. In this study, novel and stable nanomaterials of faujasite were synthesized at mild conditions without following any surface modification steps to alter the wettability of Austin Chalk carbonate rocks from oil wet to strongly water wet in the presence of low-salinity water (LSW). The synthesized nanoparticles were well characterized by scanning electron microscopy (SEM), transfer electron microscopy (TEM), X-ray diffraction (XRD), dynamic light scattering (DLS), and ζ potential to confirm their surface identity, functionality, morphology, and stability. The prepared nanofluids from the synthesized nanoparticles were tested in comparison to brine for their EOR efficiency in carbonate cores. The EOR performance was investigated by interfacial tension (IFT), contact angle, spontaneous imbibition, and displacement tests. The results showed that, compared to formation brine and LSW, the formulated nanofluid could notably alter the rock wettability from strong oil wet to strong water wet. To confirm this, a core-flooding test was performed, which further reiterated the capability of these nanofluids as effective EOR agents in hydrocarbon carbonate reservoirs by recovering an additional 9.6% of OOIP. Consequently, on the basis of the obtained findings, these faujasite-based nanofluids provide a prospect of being applied in EOR in carbonate formations.

Laboratory analysis was conducted in order to study the effect of a phosphonate scale inhibitor on a mixture of hypersaline Arabian Gulf seawater and formation water under high temperature/high pressure (HT/HP) applications. The objective of this study was to identify the minimum scale inhibitor concentration required at various temperatures to achieve a cost-effective solution in minimizing the formation of common oilfield scales. Development of such a product would aid in the utilization of seawater-based fracturing fluids by controlling the scaling tendencies of the system, especially when exposed to formation waters. Utilizing a scaling software, various types of scales were modeled by testing different seawater/formation water ratios at temperatures ranging from 270 – 330°F. A dynamic scale loop was used which allowed seawater and formation water to be pumped into the system, thereby generating differential pressure data. The exponential increase in pressure would indicate scale formation. Various concentrations of scale inhibitor were then introduced to the mixtures and tested to determine the minimum scale inhibitor required for scale mitigation. Compatibility tests were also conducted to test for the efficacy of the scale inhibitor. Based on the scaling software, barite was identified as the primary scale generated. Barite scale has a low solubility of 2 mg/L and is one of the most difficult scales to mitigate. The highest concentration of barite scale occurred in a 50/50 ratio mixture of formation water and seawater. For all the temperatures tested, the scale loop was run at the concentration with the most barium sulfate present. The results for this research concluded that at 270°F and 300°F, the minimum scale inhibitor concentration was 2000 ppm and 1500 ppm, respectively. Both treatments successfully mitigated the following types of scales: barium sulfate, calcium sulfate(s), and strontium sulfate. At 330°F, the minimum scale inhibitor concentration was lower. This decreasing trend in scale inhibitor concentration as temperature was increased is attributed to the temperature constraint of phosphonate scale inhibitors. As a result, adding the phosphonate scale inhibitor contributed to the formation of calcium phosphonate complexes that led to the rise in pressure in the scale loop test. This hindered the efficiency of the treatment and portrayed the dramatic effects of temperature and inhibitor concentration on scale mitigation. This research pushes the thermal constraints of a phosphonate scale inhibitor up to 330°F to test its efficiency and overall treatment integrity. There are also fracturing fluid applications introduced utilizing a seawater source with one of the highest total dissolved solids (TDS) concentrations in the world. Barium sulfate and other scales were successfully mitigated at various high-temperature applications for these systems utilizing a phosphate scale inhibitor.

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