What does a field development manager do in oilfield projects?

Field Development Manager — Role Overview

Leads the end-to-end maturation of oil and gas fields from appraisal through concept select, FEED, execution readiness, and handover to operations—integrating subsurface, wells, facilities, commercial, and HSSE to maximize value and assure safe, compliant delivery.

I. Core Responsibilities

• 1.1 Concept and Strategy
  • Define development objectives, recovery strategy (primary/secondary/EOR), and concept alternatives.
  • Lead concept select (FEL1–FEL2) and prepare the Basis of Design and Concept Select Report.
  • Set field depletion plans, well count/type, drive mechanisms, and facility sizing philosophy.
• 1.2 Integrated Planning and Stage-Gate Governance
  • Own the Field Development Plan (FDP) from appraisal through DG2/DG3 sanction.
  • Run structured decision reviews, value assurance, and readiness assessments.
  • Maintain opportunity and risk registers; drive Value Improving Practices and Management of Change.
• 1.3 Economics, Reserves, and Decision Analysis
  • Direct economic screening, NPV/IRR/EMV evaluation, and uncertainty analysis (deterministic and probabilistic).
  • Lead reserves maturation and documentation to PRMS; coordinate Competent Person’s reviews.
  • Optimize phasing, pacing, and portfolio sequencing for capital efficiency and cash flow.
• 1.4 Subsurface–Wells–Facilities Integration
  • Integrate static/dynamic models with well performance and surface network models (IAM).
  • Direct well portfolio definition (exploration/appraisal/infill/producer–injector pairing).
  • Balance facility turndown, compression/boosting, water/gas handling, and flow assurance.
• 1.5 Cost, Schedule, and Execution Readiness
  • Oversee cost estimates (AACE Class 5–2), schedule development, and long-lead strategy.
  • Shape contract strategy (drilling, subsea, EPC), local content plans, and logistics.
  • Set commissioning, start-up, and readiness-for-operations requirements.
• 1.6 HSSE, Regulatory, and Stakeholder Management
  • Ensure HSSE risk management (HAZID/HAZOP/SIL/RAM); drive inherently safer design.
  • Lead regulatory engagements, FDP approvals, permits, and environmental submissions.
  • Manage partner, community, and government interfaces; align JV decisions.
• 1.7 Brownfield/Tie-backs and Late-Life
  • Identify debottlenecking, artificial lift upgrades, enhanced recovery, and tie-back options.
  • Plan life extension and decommissioning concepts and provisions.
• 1.8 Digital, Data, and Performance
  • Own data quality for key models, dashboards, and decision records.
  • Establish KPIs, lookbacks, and lessons learned across the development lifecycle.

Key Quantitative Methods (selected)

• Economics: \( \mathrm{NPV} = \sum_{t=0}^{T} \dfrac{CF_t}{(1+r)^t} \); IRR solves \( \mathrm{NPV}=0 \); \( \mathrm{EMV} = \sum_i p_i V_i \).
• Decline/forecasting (Arps): \( q(t) = \dfrac{q_i}{(1+b D_i t)^{1/b}} \) (with \(b=0\) exponential).
• Inflow performance: \( q = J\,(p_\mathrm{res}-p_\mathrm{wf}) \); radial flow: \( q = \dfrac{2\pi k h (p_e - p_\mathrm{wf})}{\mu B \ln(r_e/r_w) + s} \).
• Material balance (dry gas, linearized): \( \dfrac{p}{z} = \dfrac{p_i}{z_i} - \dfrac{G_p}{G} \cdot m \) (illustrative).

II. Required Skills and Physical Demands

• 2.1 Technical Skills
  • Reservoir engineering (volumetrics, PRMS, forecasting, IAM), production technology, and well engineering.
  • Facilities/process: separation, dehydration, compression, water/gas injection, power, subsea/SURF, flow assurance.
  • Petroleum economics, fiscal systems, project controls, and AACE estimate classes.
  • Decision analysis (probabilistic evaluation, Monte Carlo, option value, sensitivity and scenario planning).
  • HSSE risk management (HAZID/HAZOP, SIL, ALARP) and regulatory compliance.
  • Data literacy: model validation, uncertainty management, and KPI design.
• 2.2 Soft Skills
  • Leadership of multi-disciplinary teams; clear decision framing and facilitation.
  • Stakeholder engagement and negotiation across partners, regulators, and communities.
  • Crisp communication (technical and executive) and conflict resolution.
  • Change management and coaching of discipline leads and early-career staff.
• 2.3 Credentials (typical)
  • Master’s in petroleum or related engineering; 12–18 years upstream experience; prior discipline lead.
  • Certifications: PMP, decision analysis, PRMS/reserves, AACE cost/schedule (preferred).
• 2.4 Physical Demands
  • Office-based with periodic field/offshore visits; ability to travel 25–50% as needed.
  • Fit for offshore/site: BOSIET/FOET, H2S, confined space/working at height (as required).
  • Use of PPE; ability to climb ladders and conduct facility walkdowns.

III. Typical Tools, Software, and Equipment

Toolchain Snapshot

• 3.1 Subsurface and Forecasting
  • Static/dynamic modeling: Petrel; simulators (ECLIPSE, CMG).
  • Material balance/production: MBAL; reservoir surveillance: Saphir/KAPPA.
  • Decline and probabilistic forecasting tools; integrated asset modeling platforms.
• 3.2 Wells and Network
  • Well performance: PROSPER; network: GAP/PIPESIM; multiphase transient: OLGA (flow assurance).
  • Well planning: drilling and completion design suites; torque and drag/hydraulics models.
• 3.3 Facilities and Process
  • Process simulation: HYSYS/UniSim; piping hydraulics and network analysis.
  • Reliability/availability: RAM analysis tools; SIL allocation tools.
• 3.4 Economics and Project Controls
  • Economic models: ARIES/PEEP/Merak; spreadsheet models with add-ins.
  • Planning/scheduling: Primavera P6/MS Project; cost estimating and benchmarking tools.
  • Risk analysis: Monte Carlo (Crystal Ball/@RISK); decision trees; real options calculators.
• 3.5 Collaboration and Visualization
  • Dashboards: Power BI/Tableau; document control and model repositories.
  • 3D model viewers (Navisworks) and digital twin interfaces; GIS for corridor/route selection.
  • Field walkdown aids: laser rangefinders, drones for flare/stack inspections (estimated).

IV. Work Environment

• 4.1 Location and Setting
  • Primarily office-based (onshore corporate or asset office) with frequent site/yard and offshore visits.
  • Engagement across appraisal wells, greenfield developments, tie-backs, and brownfield upgrades.
• 4.2 Time and Travel
  • Standard business hours; peak workload around stage gates and sanction; global travel as required.
  • Short offshore/site hitches to align scopes and verify constructability/operability.
• 4.3 Safety and Compliance
  • Strict adherence to HSSE policies, permit-to-work, and contractor HSE management.
  • Regulatory and partner reviews; audits and verifications embedded in stage-gate cadence.

V. Reporting Lines and Cross-Functional Interfaces

• 5.1 Reporting Lines
  • Reports to: Development Director, Asset Manager, or Projects Vice President.
  • Direct reports (typical): subsurface lead, drilling/wells lead, facilities/engineering manager, project controls lead, economics lead, HSSE advisor, and document control.
• 5.2 Key Interfaces
  • Subsurface (geoscience/reservoir), drilling and completions, production operations, maintenance, and reliability.
  • Facilities engineering, subsea/SURF, flow assurance, and commissioning/start-up teams.
  • HSSE, regulatory, supply chain/procurement, finance, tax, legal, and commercial/marketing.
  • Partners, authorities, EPC and drilling contractors, and specialized service companies.

Deliverables & Interfaces

• Core deliverables: Field Development Plan, Concept Select Report, Basis of Design, Appraisal Plan, Integrated Asset Model, Cost and Schedule (AACE Class 5–2), Risk/Opportunity Registers, HSSE Studies (HAZID/HAZOP/SIL), Execution Plan, Contracting Strategy, AFE/Investment Dossiers, PRMS Reserves Packages, Regulatory Submissions, Local Content Plan, and Readiness-for-Operations dossier.
• Hand-offs: to FEED/EPC project teams, drilling operations, procurement, and operations for start-up and steady-state ownership.
• Approvals: internal investment committees (DG2/DG3), partners (JMC/OMC), and regulatory authorities.

VI. Career Ladder and Progression

• 6.1 Typical Path
  • Prior roles: reservoir engineer, production technologist, drilling/completions engineer, or facilities engineer; then discipline lead or project study lead.
  • Next-step roles: Asset Manager, Development Director, Project Director, or Country Manager.
• 6.2 What It Takes to Move Up
  • Delivery of sanctioned FDPs with strong value outcomes and safe start-ups.
  • Proven decision quality under uncertainty; effective partner/regulator engagement.
  • Capability to lead multi-asset portfolios and mentor future study managers.

Progression Trigger

• Typically promoted after delivering 2–3 full FDPs to DG3 and achieving 1–2 successful start-ups, plus credentials such as PMP and AACE certification, PRMS/reserves competency, and demonstrated leadership in cross-functional teams.