Turn a Production Profile Into a Decision Somebody Will Sign
Advanced Reservoir Economics
Cash flow modelling, fiscal regime mechanics, probabilistic economics, decision analysis and real options, economic limit and reserves, and the economics of infill, enhanced recovery and abandonment decisions.
Advanced Reservoir Economics
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Advanced Reservoir Economics - RE-ARE-PEA27
| Code | Date | Time | Duration | Location | Currency | Early Bird Fee Per Person |
|---|---|---|---|---|---|---|
| RE-ARE-PEA27 | 26 - 30 Apr 2027 | 10 AM CST | 4 Hours Per Day |
Online |
USD |
4000 |
Boost your team's skills and your budget! Enjoy group discounts for collaborative learning. Send an inquiry to info@peassociations.com.
Advanced Reservoir Economics
Description
A reservoir engineer produces a production profile. What the company acts on is a cash flow. Between the two sits a chain of conversions — pricing, differentials, tariffs, operating cost structure, capital phasing, fiscal terms, tax treatment, discounting — each of which can change the sign of the answer. An engineer who hands over a profile without understanding that chain has no way of knowing whether the recommendation that emerges reflects the reservoir or reflects a fiscal artefact. Many technically excellent development plans have been rejected for reasons that had nothing to do with the subsurface, and many economically marginal ones have been approved because the evaluation was built on assumptions nobody challenged.
This course covers the chain in full and at a level appropriate to engineers who will build and defend the evaluations themselves. It includes cash flow model construction with correct treatment of timing, inflation and working capital; the mechanics of royalty and tax systems, production sharing contracts, cost recovery, profit oil splits and ring fencing; capital and operating cost estimation with contingency and phasing; price assumptions, differentials and contract structures; discount rate selection and the properties and failure modes of the standard investment indicators; probabilistic economics linking subsurface uncertainty to value distributions; expected value, decision trees, value of information and real option valuation; economic limit calculation and its role in reserves determination under recognised classification systems; and the economics of the specific decisions reservoir engineers face, including infill drilling, enhanced recovery projects, rate acceleration, marginal field development, tie-backs and abandonment timing.
Petroleum economics is where subsurface uncertainty meets commercial commitment. The reservoir engineer knows that recoverable volume is a distribution, that the profile depends on assumptions about aquifer strength or fracture conductivity, and that the well count could reasonably vary. The investment decision, by contrast, is binary and irreversible. Somebody signs, capital is committed, and the field either delivers or does not.
The translation between those two worlds is not neutral. Fiscal terms determine how much of the upside the contractor retains and how much of the downside it absorbs, and they differ enough between regimes that the same reservoir can be attractive in one country and uneconomic in another. Discounting compresses long-dated recovery so heavily that a project delivering the same volumes over twenty years instead of eight can be worth a fraction as much, which is why acceleration decisions are often more valuable than recovery decisions even when they add no reserves. Cost structure determines the economic limit and therefore the reserves that can be booked at all. None of this is visible in the production profile.
Advanced work in this area requires more than running the standard indicators. It requires knowing why the internal rate of return misleads on projects with unconventional cash flow shapes, why probability-weighted values must be aggregated rather than averaged, why a project with negative expected value can still be worth funding as an option, and how to keep an evaluation honest when every input is uncertain and several are politically sensitive. This course is built for engineers and evaluators who are expected to reach a defensible economic position and hold it in front of a management committee, a partner or an auditor.
By the end of this training, participants will be able to:
- Construct a complete after-tax cash flow model with correct treatment of timing, inflation, depreciation and working capital
- Apply concessionary fiscal terms including royalty, allowances, depreciation schedules and petroleum taxation
- Model production sharing contracts including cost recovery limits, profit oil splits, sliding scales and ring fencing
- Estimate and phase capital, operating and decommissioning costs with appropriate contingency treatment
- Select and defend price assumptions, differentials and discount rates and test their effect on the decision
- Calculate and interpret the standard investment indicators and identify where each one gives misleading guidance
- Link subsurface uncertainty to a value distribution through probabilistic economic modelling
- Apply expected value analysis, decision trees, value of information and real option methods to development choices
- Determine economic limit and apply it correctly in reserves classification and reporting
- Evaluate infill drilling, enhanced recovery, acceleration, tie-back and abandonment timing decisions on economic grounds
The course is delivered as an advanced technical and commercial programme aimed at experienced subsurface and evaluation professionals. Each concept is developed through the mechanics of the calculation rather than through general finance theory, and is then applied to field cases spanning different fiscal regimes, project types and maturity stages. Evaluations are built from the production profile forward, so participants see exactly how each assumption propagates into the result. Cases include projects that were approved and underperformed and projects that were rejected on assumptions later shown to be wrong, so that the failure modes of economic evaluation are examined as directly as the methods.
Organisations sending participants to this training will:
- Improve the quality and consistency of the economic evaluations supporting capital decisions
- Ensure development options are compared on a common and correctly constructed basis
- Strengthen negotiating positions on fiscal terms, partner arrangements and acquisitions
- Reduce the risk of approving projects whose value rests on assumptions nobody tested
- Close the gap between subsurface teams and commercial functions on how value is created
- Support better sequencing of capital across a portfolio of competing projects
Participants will:
- Build and defend a full economic evaluation independently rather than handing over a profile
- Understand how fiscal terms shape the value of technical work in each operating environment
- Recognise where an indicator or an assumption is driving a recommendation more than the reservoir is
- Quantify the value of reducing uncertainty and advise on whether to acquire data or proceed
- Communicate technical results in the terms decision makers use
- Move into senior evaluation, planning, commercial or advisory responsibilities
- Senior reservoir engineers and petroleum engineers involved in development planning
- Reserves evaluators, technical auditors and competent person report contributors
- Field development planners and subsurface team leads
- Petroleum economists and commercial analysts working with technical teams
- Business development, acquisition and divestment professionals
- Asset managers and technical authorities approving capital proposals
- Government, regulatory and national oil company staff assessing development submissions
Module 1 — Economic Framework for Reservoir Decisions
- How technical work becomes an investment case
- Project life cycle and the decision gates at each stage
- Value drivers: volume, rate, cost, price and timing
- Distinguishing accounting profit from cash flow
- Sunk cost, incremental analysis and the correct decision boundary
- Common failures in the technical to commercial handover
- Evaluation governance, assumptions registers and audit trails
Module 2 — Cash Flow Model Construction
- Model architecture, period definition and timing conventions
- Revenue build-up from production profile, price and entitlement
- Operating cost structure: fixed, variable and tariff components
- Capital expenditure phasing and commitment timing
- Working capital, inventory and payment lag treatment
- Real and nominal terms, inflation and consistency of treatment
- Currency, exchange rate exposure and translation
- Model quality control, checks and sensitivity readiness
Module 3 — Concessionary Fiscal Systems
- Royalty structures: fixed, sliding scale and price-linked
- Deductibility, uplift and investment allowances
- Depreciation and capital allowance schedules
- Corporate income tax and special petroleum taxes
- Loss carry-forward, consolidation and ring fencing
- State participation and carried interest arrangements
- Government take, effective tax rate and progressivity assessment
Module 4 — Production Sharing and Service Contracts
- Production sharing contract structure and terminology
- Cost oil, cost recovery ceilings and unrecovered cost carry-forward
- Profit oil splits: fixed, R-factor, rate-based and IRR-based
- Domestic market obligation and government participation
- Bonuses, rentals and training and social obligations
- Risk service and technical service contract structures
- Comparing regimes on a common basis and regime sensitivity to price
- Contractor entitlement volumes and their reporting implications
Module 5 — Cost Estimation, Phasing and Decommissioning
- Cost estimate classes and expected accuracy by project stage
- Capital cost build-up for wells, facilities and subsea equipment
- Operating cost modelling and its dependence on activity level
- Contingency, allowance for change and estimate bias
- Cost escalation and market cycle effects
- Decommissioning cost estimation, timing and provisioning
- Fiscal treatment of decommissioning and tax relief
- Effect of cost structure on economic limit and recoverable reserves
Module 6 — Price, Markets and Revenue Realisation
- Price forecasting approaches and their limitations
- Crude quality differentials and gravity and sulphur adjustments
- Gas pricing structures, contracts and take-or-pay provisions
- Transportation, processing and marketing costs and tariffs
- Netback calculation and point of valuation
- Price scenarios, screening prices and internal planning assumptions
- Hedging and its treatment in project evaluation
Module 7 — Discounting and Investment Indicators
- Time value of money and discount rate selection
- Cost of capital, hurdle rates and risk-adjusted discounting
- Net present value and its correct interpretation
- Internal rate of return, multiple roots and reinvestment assumptions
- Modified internal rate of return and its use
- Profitability index, discounted payback and their limits
- Unit technical cost and break-even price
- Selecting indicators appropriate to the decision being made
- Ranking mutually exclusive projects and capital rationing
Module 8 — Probabilistic Economics and Risk Quantification
- Linking subsurface uncertainty to economic outcome distributions
- Distribution selection and dependency between technical parameters
- Monte Carlo cash flow modelling and result interpretation
- Value distributions, downside exposure and probability of loss
- Expected monetary value and risked value calculation
- Chance of success, geological and commercial risk factors
- Aggregation across wells, projects and portfolios
- Sensitivity analysis, tornado diagrams and spider plots
- Distinguishing risk from uncertainty in evaluation practice
Module 9 — Decision Analysis and Real Options
- Decision tree construction and expected value at each node
- Sequential decisions and staged development evaluation
- Value of information and whether to acquire data before committing
- Value of flexibility and the cost of premature commitment
- Real option concepts: defer, expand, contract and abandon
- Option valuation approaches and their practical limitations
- Utility, risk tolerance and corporate risk preference
- Applying decision analysis to appraisal and development sequencing
Module 10 — Economic Limit, Reserves and Reporting
- Economic limit calculation at well, platform and field level
- Effect of cost sharing and infrastructure on economic limit
- Reserves and resource classification frameworks
- Commerciality criteria and the economic test for booking
- Proved, probable and possible reserves and probabilistic equivalents
- Contingent and prospective resources and their treatment
- Price basis for reserves reporting and its effect on booked volumes
- Reserves reconciliation, revisions and audit expectations
Module 11 — Economics of Reservoir Development Decisions
- Infill drilling: incremental recovery versus acceleration
- Value of acceleration and its dependence on discount rate
- Waterflood and pressure maintenance project economics
- Enhanced oil recovery project evaluation and phasing
- Workover, recompletion and intervention economics
- Marginal and small field development thresholds
- Tie-back versus standalone development evaluation
- Facility capacity optimisation and plateau length trade-offs
- Abandonment timing and the option to defer decommissioning
Module 12 — Portfolio, Transactions and Wider Value Considerations
- Portfolio construction and capital allocation across projects
- Efficient frontier concepts and diversification of technical risk
- Asset valuation for acquisition and divestment
- Due diligence on technical and economic assumptions
- Farm-in, farm-out and carried interest economics
- Unitisation, equity redetermination and partner alignment
- Carbon cost, emissions pricing and their entry into project economics
- Presenting an evaluation to a decision forum and defending it under challenge
Upon successful completion of this training course, delegates will be awarded an official Certificate of Completion issued by the Petroleum Engineers Association (PEA), an ISO 9001:2015 certified training organization. The certificate carries 10 Credits and formally records the total learning hours completed.
Each certificate is signed by the Course Facilitator and the CEO of the Petroleum Engineers Association, and serves as verifiable proof of professional training that delegates can present to employers and professional bodies worldwide.
Frequently Asked Questions
All course bookings made through PEA are strictly non-refundable. By registering for a course, you acknowledge and accept that all fees are payable in full and are not subject to refund under any circumstances, including changes in personal or professional commitments or partial attendance.
PEA reserves the right to make reasonable adjustments to course content, trainers, or schedules where necessary, without entitling delegates to a refund. Comprehensive details of each course — including objectives, target audience, and content — are clearly outlined before enrolment, and it is the responsibility of the delegate to ensure the course's suitability prior to booking.
For any inquiries related to cancellations or bookings, please contact our support team, who will be happy to assist you.
