Reservoir Engineer interview questions

I've been a reservoir engineer for eleven years, the last six in Oman. Started at an Indian E&P operator on conventional sandstone reservoirs, then moved to Petroleum Development Oman (PDO) where I've worked on three major fields: a mature waterflood field in north Oman, a heavy oil thermal recovery development in the south, and most recently EOR optimisation on a tight carbonate. I hold a master's in petroleum engineering and SPE membership. I'm comfortable in static and dynamic modelling, history matching, EOR screening, and increasingly the integration of data science with traditional reservoir engineering.

Start with the static model: are the structural framework, reservoir property distributions, and rock-fluid properties as good as the data supports? History matching can't fix a bad geomodel. Then dynamic: I match in stages. Pressure data first (RFT/MDT, then static pressures at wells), then water cut and GOR trends, then individual well rates. I'd rather match aggregate field behaviour well than over-tune individual wells. Use assisted history matching tools (CMG-CMOST or similar) for sensitivity, but I always validate the matching parameters are physically meaningful, not just mathematical. Beware of over-matching; a model that fits perfectly today is often wrong for the future because it's over-constrained.

Multi-stage process. First, screening using analogue databases (SPE EOR screening criteria): reservoir depth, temperature, pressure, fluid properties, rock characteristics. This narrows to feasible EOR methods. Second, laboratory work: core flooding for the candidate EOR methods, fluid PVT analysis, rock-fluid compatibility tests. Third, simulation: build a sector model and run pilot-scale forecasts for each viable method. Fourth, economics: each method has different capex, opex, and chemical cost profiles. Recommend the method that combines technical feasibility with commercial robustness across oil-price scenarios. Pilot ahead of full-field expansion; learn before committing capital.

I use Monte Carlo and scenario-based approaches. For static models: build multiple realisations of the geomodel using different stochastic seeds; sensitivity on key parameters (porosity, permeability, structural framework). For dynamic: run the simulation across the realisations and across price decks. Output is a P10-P50-P90 range, not a single number. Critical when communicating to management: never present a single forecast number without uncertainty; senior leaders make better decisions when they see the range. I also clearly mark which parameters drive most of the uncertainty so we know where to invest in data acquisition.

Multi-disciplinary collaboration is essential. I try to integrate early; once a study is in flight, geo-disagreements are expensive. We run joint workshops at the start to align on the structural framework, the rock-property model, and the fluid model. I respect the geoscientist's interpretation of the geology; they respect my translation into flow units. When we disagree, we go back to the data: well logs, cores, seismic. Healthy disagreement is part of good subsurface work; the answer is rarely 'one of us is right'; it's usually 'we need more data'. Building those relationships is as important as the technical work itself.

For a senior reservoir engineer role in Oman with major operator experience I'd target OMR 2,500 to 3,200 total package depending on the bonus structure, housing allowance, and asset criticality. Reservoir roles on flagship fields typically carry a premium. I'd want to understand the field portfolio I'd cover and the technical authority level. I'm on 90 days' notice from my current employer. Beyond pay I'd value the technical complexity; my career is built on the studies I've led, and a routine maintenance asset role at higher pay is not as valuable as a complex EOR pilot at lower pay.