Day 1 Session 1

Day 1Introductions Economics and accounting Building a basic project cash flow Economic and risk indicators The cost of finance and the discount rate Day 2 Economic and risk indicators (continued) Complicating factors: inflation, multiple currencies, taxation Uncertain assumptions Uncertain outcomes Green field investment opportunities Brownfield projects and opportunities Day 3Production dynamics Introduction to exploration and appraisal Exploration and appraisal economics and opportunities Modelling for negotiations Choosing contracts and IOC partners

 Accounting ◦ Wealth (balance sheet) ◦ Annual increase in wealth (profit and loss or net income statement) ◦ Cash flow ◦ Historical input ◦ Create the most realistic picture of the financial health of the organisation  Project economics ◦ Cash flow ◦ Value (discounted cash flow) ◦ Other economic and risk indicators from processing cash flow ◦ Forward looking except for historical inputs to tax, cost recovery or remuneration fee calculations ◦ Create, maximise and risk-protect value in each project decision ◦ Recognise the true value of assets to be bought or sold

 At what discount rate is the NPV of the cash flow zero? Leasing Co. Shareholder Risk or Reward

Day 3 Session 1 Reservoir drives Primary, secondary and enhanced recovery Artificial lift Other brownfield improvement options Exercise 7

Reservoirs vary in the amount of energy available to drive petroleum to the surface. It is therefore useful to investigate the potential sources of energy in order to understand their impact on the production of petroleum over time if we rely on natural flow. This also helps us to study the potential for, and limitations to, artificially stimulating flow to the surface if this is required. The potential drive mechanisms are: Under-saturated oil drive Dissolved gas drive (depletion drive, solution gas drive) Gas cap drive Water drive Artesian flow drive Compaction drive

A single drive mechanism is unlikely to dominate throughout the whole life of a reservoir. When several of these make a significant contribution together, the reservoir is said to have a combination drive. An under-saturated oil reservoir has a pressure that is above its bubble point, i.e. all gas is in solution in the oil and none is free (no gas in the pore space and no gas cap). Drive is mainly provided by expansion of the oil, and as oil’s compressibility is low the reservoir pressure drops rapidly during production. When 1 or 2% of the oil initially in place has been produced, the bubble point is normally reached and the reservoir switches to a dissolved gas drive. Once free gas is present, expansion of this gas provides the main driving force. This is known as dissolved gas drive, solution gas drive or depletion drive. As gas is much more compressible than oil, the reservoir pressure falls more slowly than with an under-saturated oil drive.

The gas produced is initially immobile, held within the pore space, but as quantities build up the bubbles begin to coalesce and it begins to flow to the producing wells. If the reservoir has the right shape and permeability a secondary gas cap may be formed, i.e. one that was not initially present. As free gas saturation continues to increase, the permeability of the formation to gas will increase while its permeability to oil will decrease, leading to a sharp increase in the producing gas/oil ratio (GOR). This is undesirable because the source of the main force driving out the oil is itself rapidly leaving the reservoir. Technical attempts to minimise this effect are rarely successful, and the economic limit of production (when sales revenues equal operating costs and economic logic is that the field should be abandoned) is reached at quite low recovery efficiencies, typically 15 to 25%. Control of production rates or closer spacing of the wells will not generally improve this situation.

Leasing Co. £ CAPITAL £ 15% 8% 6% 10% Shareholder