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.

A preliminary enhanced oil recovery (EOR) screening was completed for the Ben Nevis Formation, Hebron Field, offshore Canada. Polymer flooding was determined to be the most viable methodology based on the oil and reservoir properties and known challenges with respect to sourcing potential injection gas. Digital image analysis and microscopic petrographic analysis were applied to investigate the pore system characterization in Ben Nevis formation sandstone cores, which were subjected to an experimental polymer injection at 62 °C. Polymer Flopaam 5115 delivered the best performance in terms of oil recovery irrespective of the flooding sequence or permeability facies. Initial grain size before flooding has a profound impact on oil displacement efficiency. Pore network analyses before and after flooding indicate that the movement of fine grains potentially affects porosity postflooding, depending on the permeability facies.

Prolonged injection of magnesium chloride (MgCl2) brine into water-wet chalk cores leads to dissolution of calcite and precipitation of magnesium-bearing minerals. In low permeable and highly porous chalk, the mineral surfaces dominate multiphase flow properties. The hydrophobic/hydrophilic behavior of these mineral surfaces is subject to changes when aged in oil at high temperature over time, and from mineral dissolution and precipitation processes. In this study, we evaluate to which extent chemical interactions induced by the continuous MgCl2 brine injection modify the water wetness of chalk samples saturated by oil/water mixtures and compare the evolving results to a 100% water-saturated parallel reference test. The potential of MgCl2 brine to improve the oil recovery after the freely movable hydrocarbons are produced is also assessed. In situ wettability measurements were carried out during the injection program using chromatographic separation, where the delay in the increase of effluent concentration of the adsorbing sulfate ion was compared to a nonaffine tracer. These measurements were performed every 10 days to estimate the evolution in mineral surface area in contact with water. The results show an increased delay time for the sulfate ion, linked to an increase of the mineral surface area. This is observed in both water-wet and mixed-wet cores, but is found to be more dominating in the mixed-wet samples. This implied that oil, which was adsorbed on the mineral surfaces, got mobilized in addition to an increased overall specific surface area as new magnesium-bearing minerals precipitated and grew during the MgCl2 brine flow. This is supported by continuous effluent analysis displaying a reduced magnesium and increased calcium concentration. Petrophysical analysis of cores before and after flow displayed trends along the axis of the sample. Changes in density and specific surface area were more dominant on the inlet side than the outlet side. Even though magnesium (Mg2+) ions in the injection brine increased the available water-wet area in the samples, the nonequilibrium chemical reactions did not lead to additional oil recovery.