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Enhanced oil recovery (EOR) and maximizing recovery from declining production fields remain a challenge in the offshore industry. The challenge is to find an EOR method that is both technically and economically feasible considering the high capital and operating costs in the offshore environment. The goal of this work was to conduct a simple cost-benefit analysis based on a technical, facility, and economical screening of chemical EOR methods applicable to the offshore. Offshore Newfoundland, Canada is used as a base case as it represents a challenging geographical environment. The reservoir properties are good, based on volumetrics and characteristics, but the fields are located over 300 km offshore in a harsh environment where operational costs are high. A data mining approach was used for the EOR screening process. Data from over one thousand core flooding experiments investigating various chemical EOR methods, including surfactant, polymer, alkaline-surfactant (AS), alkaline-surfactant-polymer (ASP), nanoparticle, and low salinity water injection (LSWI), were collected. Factors with the greatest influence on the performance of a given EOR method were statistically examined and discretized. The ranges of recovery factor, rock type, chemical concentrations, and the most commonly used chemicals are presented in this review paper. Economic factors examined included capital expenditures (CAPEX) and the operating cost of production (OPEX). Benefits are found to be strongly related to oil production and Brent crude oil forecasts. Sensitivity studies of the recovery factor ranges with the different chemical concentrations, net present values (NPV), and the influence of the inflation were all taken into consideration. Two different injection plans were considered: injection from day one of production, and injection after secondary production. The highest CAPEX and OPEX were calculated for the ASP method, whereas LSWI resulted in the lowest. The results indicate that most of the chemical EOR methods could be economically successful, however, the timing of implementation will affect the potential benefits. If high recovery and low chemical concentrations are considered, ASP flooding is the most successful chemical EOR method when injecting from day one. However, if the EOR method starts after a decline in production, surfactant flooding proves more beneficial, regardless of the scenario considered. This paper presents a systematic approach to chemical EOR screening, combining available technical data using a data analytics approach with economic and technical uncertainty.

Traditional concepts of simple liquid spreading may not apply to nanoparticle-fluids. Most investigations pertaining to the wettability alteration of solid surfaces due to the presence of nanoparticles in the fluid are oversimplified, i.e. nanoparticles dispersed in DI-water and smooth, homogeneous, and clean surfaces have been used. From a practical enhanced oil recovery (EOR) point of view, the nanoparticles must be dispersed in either seawater or high salinity formation water containing diverse types and concentrations of ions. These ions interact with the electrostatic properties of the nanoparticles. Likewise, the oil phase may contain many surface active components like asphaltene and naphthenic acids which can interact with nanoparticles at oil-water and oil-rock interface. In reality, the rock sample is a heterogeneous, non-smooth, mixed-wet substrate with a diverse mineralogical composition. The electrical charge of minerals can vary when contacted with an ionic fluid. This can alter the electrostatic repulsion between substrate and nanoparticles and consequently the substrate can either attract or repel charged particles, including nanoparticles. Hence, the role of nanoparticles must be evaluated considering multicomponent complex fluids and real formation rock. Despite numerous reports regarding the wettability alteration of reservoir rock from oil-wet to water-wet by nanoparticles, some inherent limitations in the wettability alteration experiments prevent conclusions about the performance of nanoparticles in practical complex conditions. For instance, the wettability alteration by nanoparticles is often determined by contact angle measurements. In this method, the substrates are either aged with (immersed in) nanoparticle-fluids before conducting the experiments or contacted with nanoparticle-fluids before attachment of the oil droplet on the rock surface. Hence, in both cases, before initiating the contact angle measurements, the nanoparticles would already exist at the oil-rock interface possibly giving inaccurate measurements. The objective of this work is to investigate the mechanism of wettability alteration by silica nanoparticles pre-existing on the rock interface (conventional contact angle measurements) and using a new displacement contact angle method to better mimic the scenario of injecting a nanoparticle fluid into the reservoir already containing formation brine. The impact of pre-existing nanoparticles at the oil-rock interface (in the conventional contact angle measurements) on the contact angle measurements are examined for simple (n-decane, NaCl brine, and pure substrates) and complex (crude oil, seawater, and reservoir rock) systems on various wetting conditions of substrates (water-wet and oil-wet). The nanoparticles are dispersed in seawater using our H+ protected method [1]. Then, the effect of surface and nanoparticle charge on the contact angle is evaluated by adjusting the aqueous phase salinity. We also differentiate between the disjoining pressure mechanism and diffusion of silica nanoparticles through the oil phase by testing the attachment of nanoparticles on the rock surface.