Reservoir Engineering interview prep.

Behavioural questions to expect

1. Walk me through your background + reservoir engineering experience.
2. Tell me about an asset or field you've worked.
3. Why upstream reservoir engineering vs other subsurface or energy paths?
4. Why this asset type - conventional / unconventional / offshore / EOR / heavy oil?
5. Why the firm?
6. What's your read on our asset portfolio + recent reserves disclosure?
7. Tell me what you understand about our recovery posture + simulation + surveillance maturity.
8. Walk me through a reserves booking or revision decision you've been part of.

Technical concepts to master

• Reserves + SEC + SPE-PRMS discipline

  SPE-PRMS (Petroleum Resources Management System) · SEC reserves rules (Reg S-X 4-10) · Reasonable certainty + reliable technology · Reserves audit + third-party report · Reserves replacement + F&D cost

• Decline curve + type curve workflow

  Arps decline (b-factor selection) · Modified hyperbolic + terminal exponential · Diagnostic plots (rate-cum, log-log, RTA) · Type curve construction · Parent-child interference

• Reservoir simulation workflow

  Static -> dynamic model handoff · Initialization + PVT + relperm · History match · Prediction + uncertainty · Software platforms (Eclipse, CMG, INTERSECT, tNavigator)

• Recovery mechanisms + EOR screening

  Primary drive mechanisms · Waterflood basics · Gas + miscible EOR · Chemical EOR (polymer, surfactant, ASP) · Thermal EOR (steam, SAGD, ISC)

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

Sourced from

SPE-PRMS (Petroleum Resources Management System) + SEC Reg S-X 4-10 / Modernization Rule · SPE-published decline curve + RTA literature (Arps 1945, Ilk-Rushing-Blasingame, Duong, SEPD, PLE references) · SPE Reservoir Engineering Handbook + Dake + Craft & Hawkins applied PE textbooks · Simulator vendor documentation (SLB Eclipse / INTERSECT, CMG, Rock Flow Dynamics tNavigator) + DOE EOR screening reports · Operator type-curve disclosures + investor presentations (Permian / Bakken / Eagle Ford / Marcellus operator decks) + state regulator production data (RRC, NDIC, BOEM)