Recovery factor is the number that surprises people most. A typical oil field produces perhaps a third of the oil it contains, and many produce less. The remainder is not lost through inefficiency in any correctable sense; it is held in the rock by capillary forces, bypassed by water that took an easier path, or left in regions no well drains. Understanding this explains why enhanced recovery attracts so much attention, why infill drilling is valuable, and why an apparently modest improvement in recovery factor represents a large volume.

Reserves are estimates with defined confidence levels, not measurements. Proved reserves are quantities that are much more likely than not to be recovered, which means they are deliberately conservative and that actual recovery will normally exceed them. Probable and possible reserves carry successively lower confidence. Reserves change as production data accumulates, and revision is normal; what matters is whether revisions are random or systematically in one direction, because persistent downward revision indicates a process problem rather than reservoir behaviour.

Forecasts have known biases. Production forecasts across the industry have tended to be optimistic, particularly early in field life and particularly for new technology and new plays. The causes are structural rather than individual: forecasts are prepared by people whose projects depend on them, uncertainty ranges are systematically too narrow, and the analytical methods used early in a well's life extrapolate optimistically. A manager who knows this asks different questions.

Finally, the useful questions are mostly about evidence and alternatives. What evidence supports this number? What would have to be true for it to be wrong? What alternative interpretations fit the same data? What is the range and what drives it? How has this team's previous forecasts performed? These questions do not require technical expertise to ask and they reveal the quality of the work behind an answer more effectively than technical interrogation would.

By the end of this training, participants will be able to:

• Explain how reservoirs produce and what physically limits recovery
• Interpret in-place volume estimates and understand their uncertainty
• Interpret reserves categories, their confidence levels and their evidence requirements
• Understand how production forecasts are constructed and how reliable they are
• Recognise the systematic biases affecting subsurface estimates and forecasts
• Understand the principal development decisions and what drives them
• Understand waterflooding, gas injection and enhanced recovery and when each applies
• Interpret surveillance data and performance indicators for a producing asset
• Review a technical case and identify its weaknesses
• Ask the questions that distinguish sound technical work from weak work

Organisations sending participants to this training will:

• Improve the quality of challenge applied to subsurface work
• Improve communication between subsurface teams and management
• Reduce commitments made on forecasts that the evidence does not support
• Improve investment decisions involving subsurface uncertainty
• Strengthen the organisation's ability to interrogate its own technical work
• Reduce the gap between technical understanding and commercial decision making

Participants will:

• Understand what subsurface teams do and what their numbers mean
• Interpret reserves, forecasts and development plans confidently
• Recognise weak technical cases without needing to perform the analysis
• Ask questions that improve the quality of work presented to them
• Discuss subsurface matters credibly with technical staff and with partners
• Make better decisions on the largest uncertainties their business carries

• Asset managers and general managers with subsurface accountability
• Commercial, business development and portfolio staff
• Finance, planning and investment personnel
• Legal and contracts staff working on upstream agreements
• Non-subsurface engineers and technical staff
• Board members and executives with upstream responsibility
• Government, regulatory and partner representatives

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.