Reservoir Engineering interview prep.

Reservoir engineers, simulation engineers, surveillance + production engineers, field development planners, asset team REs.

What interviewers look for

  • Can the candidate articulate reserves under SPE-PRMS + SEC rules - 1P / 2P / 3P, PDP / PUD, technical vs commercial maturity?
  • Do they have hands-on decline curve discipline - Arps, b-factor selection, unconventional adaptations, EUR confidence intervals?
  • Are they fluent in reservoir simulation workflow - gridding, upscaling, history match quality, prediction uncertainty?
  • Can they read material balance + well test data to diagnose drive mechanism + connected volume?
  • Do they understand surveillance + RTA + production allocation in a multi-well field setting?
  • Are they grounded in waterflood + EOR screening + the economics that gate them?
  • Long-game fit - RE I / II / III / senior / asset lead / sub-surface manager trajectory across conventional + unconventional?

Behavioural questions to expect

  1. Walk me through your background + reservoir engineering experience.

    What it tests: Story arc - degree, asset exposure, reserves + simulation + surveillance breadth, the bridge to capital decisions.

  2. Tell me about an asset or field you've worked.

    What it tests: Subsurface rigor - reserves + simulation + surveillance discipline, uncertainty handling, economics linkage.

  3. Why upstream reservoir engineering vs other subsurface or energy paths?

    What it tests: Authentic alignment - subsurface uncertainty + economics + multi-decade asset stewardship.

  4. Why this asset type - conventional / unconventional / offshore / EOR / heavy oil?

    What it tests: Specificity. Generic 'I like reservoirs' answers fail. Conventional vs shale vs offshore vs EOR is a real distinction.

  5. Why this firm?

    What it tests: Real homework - basins, plays, reserves track record, recent results - not name-drop.

  6. What's your read on our asset portfolio + recent reserves disclosure?

    What it tests: Industry literacy - basin / play mix, reserves quality, recent revisions, production trajectory.

  7. Tell me what you understand about our recovery posture + simulation + surveillance maturity.

    What it tests: Recovery + simulation fluency on this firm's record - drive mechanisms, EOR posture, simulation + surveillance investment.

  8. Walk me through a reserves booking or revision decision you've been part of.

    What it tests: Reserves discipline - SPE-PRMS / SEC fluency, technical maturity assessment, audit + governance posture, materiality awareness.

Technical concepts to master

Reserves + SEC + SPE-PRMS discipline

SPE-PRMS (Petroleum Resources Management System)
Industry-standard resources classification - 2D matrix of technical certainty (P90 / P50 / P10) × commercial maturity (reserves / contingent / prospective).
SEC reserves rules (Reg S-X 4-10)
US filers must disclose proved reserves under reasonable-certainty test; PUDs must be developable within 5 years (Modernization Rule, 2009).
Reasonable certainty + reliable technology
SEC standard for 1P - high confidence based on geology + engineering + analogous well performance, including reliable-technology basis for analog-based bookings.
Reserves audit + third-party report
Annual third-party reserves audit by qualified reserves auditor / engineer (e.g. third-party reserves auditor, Ryder Scott, DeGolyer) covers 1P + sometimes 2P.

Decline curve + type curve workflow

Arps decline (b-factor selection)
Standard hyperbolic decline q(t) = qi / (1 + b·Di·t)^(1/b); b in [0, 1) for boundary-dominated flow; transient flow can produce apparent b>1.
Modified hyperbolic + terminal exponential
Standard unconventional practice - hyperbolic transient, switch to exponential at min decline (typically 5-10% / yr) for terminal forecast.
Diagnostic plots (rate-cum, log-log, RTA)
Rate-time + rate-cum + log-log derivative + Blasingame / Agarwal-Gardner plots used to identify flow regime + boundary effects.
Type curve construction
Multi-well shale forecast - normalise wells by completion design + vintage + area; fit central + P10 / P50 / P90 forecasts.

Reservoir simulation workflow

Static -> dynamic model handoff
Geomodel (porosity / permeability / facies / structure) is upscaled to the dynamic grid - typical upscaling 10-100× cells for tractable runtimes.
Initialization + PVT + relperm
Initial reservoir state - fluid contacts, pressure, saturation; PVT (Bo, Rs, Bg, viscosity); relperm (kr curves + endpoints) define flow physics.
History match
Tune simulation parameters (kh, fault transmissibility, aquifer strength, relperm endpoints) until simulated rates + pressures match historical.
Prediction + uncertainty
Forecast cases (do-nothing, base, upside) under multiple operating scenarios; uncertainty via parameter ranges or AHM ensemble.

Recovery mechanisms + EOR screening

Primary drive mechanisms
Solution-gas drive, gas-cap expansion, water drive (aquifer or edge), gravity drainage, depletion drive. Recovery factor typically 5-30% depending on drive.
Waterflood basics
Inject water to maintain reservoir pressure + sweep oil; typical incremental recovery 10-20% OOIP on top of primary; dominant secondary process.
Gas + miscible EOR
Injected gas (hydrocarbon, CO2, N2) develops miscibility with oil, reducing residual saturation; CO2 floods common in Permian + onshore US.
Chemical EOR (polymer, surfactant, ASP)
Polymer improves mobility ratio; surfactant lowers interfacial tension; ASP (alkali / surfactant / polymer) combines mechanisms.

Practical drills

  • A shale oil well IP is 800 bbl/d. After 12 months it's at 250 bbl/d. Sketch your DCA workflow + give a back-of-envelope EUR using modified hyperbolic with b=1.2 transitioning to 8% terminal exponential. Abandonment rate 15 bbl/d.
  • You have a new shale gas well drilled in a Tier-1 area, 6 months of production data, IP 12 MMcf/d declining to 4 MMcf/d. Five undrilled offset locations on company-controlled acreage with drilling permits. The 3-yr plan funds two of them. Walk through how you'd classify - PDP / PDNP / PUD / contingent - for this well + the offsets.
  • Your simulator matches field-level cum oil well but two wells in the east flank consistently over-predict rate by 30%, and field-level pressure runs ~200 psi above measured major mining major. Walk through your diagnostic + next moves before committing to a development plan.

Smart-question anchors

  • Asset portfolio + basin mix - conventional / unconventional / offshore / heavy, oil / gas / NGL split
  • Reserves posture - 1P / 2P / 3P breakdown, replacement ratio, recent revisions narrative
  • Recovery + EOR strategy - waterflood / gas / chemical / thermal across portfolio + maturity
  • Simulation + surveillance maturity - software platform, digital subsurface, type-curve discipline
  • Type curve + completion design evolution - lateral length, proppant intensity, parent-child handling

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