Integrating Parallel Engineering with Phased Field Development in order to Balance Cash Flow, Net Present Value, and Risk

Abstract

The future of the offshore oil/gas industry in the UKCS faces a growing number of challenges. Not least of these are the technical complexity of the reservoirs currently available for development, and their lower recoverable reserves. Current exploration and production efforts are concentrating on either stand alone small/marginal fields or brown field developments, exploiting hitherto untapped reserves near to existing facilities. Technical advancements are playing their role in enhancing the ability of operators to reduce development costs. The greatest constraint on extracting the maximum value of these reserves is, however, the field development process. This constraints can only be overcome by introducing new business and engineering processes which are focused on achieving both the goals of the operator and of the field development contractor. An integrated field development contractor, with access to key technology, personnel, and equipment, can assist in the enhancement of the value of these small/marginal fields by structuring the development process such that it provides the optimal balance between cash flow, Net Present Value (NPV), and risk. Introduction Many of the oil and gas reserves which have recently been developed, or are currently under consideration, in the UKCS are classed as economically marginal. This is despite the relatively high stable oil price and the level of existing process and transportation infrastructure available in the region. As other regions throughout the world open their territories for exploration and development activities, the UKCS has to compete for development capital against a background of increasing alternative investment opportunities. In addition, as this global market expands, developments also have to compete for construction resources and equipment which are also now becoming scarce. When considering the viability or ranking of a potential investment, a number of ratios are employed such as Unit Cost, Net Present Value (NPV), NPV/Capital expenditure (Capex), Discounted Cash Flow (DCF), Payback, and more recently risk weighted criteria such as Estimated Monetary Value (EMV). Each of these calculations has as their key inputs capital expenditure, revenue, and the time scale. The objective of this paper is to demonstrate how an integrated field development contractor can assist in the optimisation of marginal field exploitation by implementing a development plan which balances the engineering solution and these key investment metrics. Field Characteristics A 1994 UKOOA study, Study 20201, covered a detailed assessment of existing oil and gas developments and the probable outcome of future exploration activity. The scope of the study was to quantify the probable capital expenditure in the UKCS over the next 25 years. The study identified 187 existing oil discoveries and 133 existing gas discoveries. Of these 96 and 64 fields respectively were in production. The average initial size of producing oil fields was 219 million barrels, accounting for 85% of total reserves then discovered. For the 91 fields still to be developed the average reserves was only 41 mmbbls. Figure 1 shows the size distribution of these fields. The same percentage of known reserves existed for gas fields, where the average initial size of the 64 producing fields was 860 bn cubic feet. For remaining known reserves the average size was 140 bn cubic feet.