Decisions about how to develop and produce a reservoir are made under uncertainty and over long time horizons. The data behind those decisions comes from many sources — cores, fluid samples, logs, well tests, production history — and engineers need to know how to evaluate each data type, how it fits into the broader reservoir picture, and how to use it to forecast performance. This course is built around that workflow. Rather than treating reserves estimation, material balance, well testing, and simulation as separate topics, it shows how they connect and how to move between them when planning field development.

By the end of the course, participants will be able to:

Calculate original hydrocarbon in place using volumetric and material balance methods

Estimate reserves using deterministic and probabilistic techniques, including Monte Carlo simulation

Build material balance models for history matching and production prediction

Couple well models (IPR and VLP) with material balance calculations to improve forecast accuracy

Apply Arps and Fetkovich decline curve methods and understand the assumptions behind each

Interpret pressure transient tests using type curves and pressure derivative analysis

Design a waterflooding project, including voidage replacement and fractional flow analysis

Set up a reservoir simulation model, initialize it, and define development cases

Monitor fluid contacts (OWC and GOC) and predict reservoir or well lifetime

Model multiple juxtaposed connected reservoirs and estimate transmissibility between them

Prepare an integrated field development plan covering reservoir characterization, evaluation, and forecasting

The course is delivered through instructor-led sessions that pair theory with worked examples. Each topic begins with the underlying physics and assumptions, then moves to calculation procedures, and finishes with case studies drawn from real field data. Participants work through hands-on exercises using industry-standard tools for material balance, decline curve analysis, well test interpretation, and reservoir simulation. Discussion is built into each session so participants can compare approaches and bring questions from their own assets.

Companies sending engineers on this course gain team members who can:

Move between data domains — geology, petrophysics, reservoir, production — without needing handoffs between groups

Produce reserves and production forecasts that are defensible under audit and consistent with PRMS guidelines

Identify weak points in existing material balance and simulation models, and improve history matches

Support field development planning with integrated input rather than siloed analysis

Reduce reliance on external consultants for routine reservoir management tasks

Participants will:

Build a workflow they can apply directly to their own field, from data review through forecast

Understand how each piece of reservoir data contributes to the development plan, not just how to calculate with it

Develop judgment about when to use simple methods (decline curves, volumetrics) versus when to invest in detailed simulation

Strengthen their case in technical reviews by knowing the assumptions and limitations of each method

Earn a certificate recognized across the industry

Reservoir engineers at any career stage looking for a structured view of the full management workflow

Petroleum engineers moving into reservoir-focused roles

Production engineers who interact with reservoir teams and need to understand the underlying analyses

Asset team members responsible for field development planning, reserves reporting, or production forecasting

On successful completion of this training course, PEA Certificate will be awarded to the delegates