Current offshore marginal field development and mature field re-development in Malaysia consistently encountered high development cost and low recovery or incremental recovery. Wells are being drilled and completed at a typical cost of 10 to 35 MM$ per well while the estimated ultimate recovery (EUR) per well is as low as < 0.5 MM Bbl. The corresponding well development cost (WDC) can be higher than 20 to 70 $/Bbl. This high WDC cost, and accordingly high UDC (including surface facilities) and UTC (including operation) cost can significantly deteriorate the commercial development feasibility of our resources.
In this paper, correlations between EUR and NPV in several key field development projects were first presented to illustrate the art of balancing cost and value on increasing the EUR per well and reducing well cost in various stages of the IOR and EOR projects. A simple chart of “Cost vs. Value” was used to determine the commercial feasibility of well construction and field development plan. This paper also entails discussions on changing the way we do for well placement and reservoir contact well path design to optimize reservoir drainage and to reduce well counts. Then it proceeds on discussion of changing well architecture and completion design using new and advanced technical approach, methodology, and technology for optimizing down-hole flow control and sand production control, in the quest for increasing well productivity and EUR per well.
dditional examples of marginal field development, brown field redevelopment, and EOR project development were further used as exhibits to illustrate the importance of balancing the cost and value in field development planning and implementation.
Development or redevelopment of a field involves the determination of subsurface reservoir drainage potential, the construction of a production system for life-cycle production and operation, and the implementation of a fluid and power processing, transportation and delivery system (cable, pipeline, FPSO and tankers). The value is solely estimated based on subsurface reservoir drainage and sequential reservoir depletion plan either by reservoir model simulations or by analytical methods. The cost is incurred by the construction of wells with optimized completions, capable of handling life-cycle oil, gas, water and sand production, by the construction and continuous modification of the surface support and fluid transportation facilities. Figure 1 illustrated this integration on value and cost. Well construction is the key link bridging the subsurface potential and commercial feasibility of the field development.
Well value can certainly be optimized by well design increasing reservoir fluid contact, improving fluid displacement, maintaining or minimizing reservoir pressure decline. This entails the determination of the optimum reservoir drainage and injection points (Ref. 1), selection of the well type (Ref. 2), optimization of well reservoir multiple contact trajectory design (Ref. 3), optimization of smart (Ref. 4), sand control (Ref. 5), and artificial lift completion (Ref. 6).
Well cost can also be optimized by first minimizing the well counts (Ref. 7), further simplifying the well completion (Ref. 8), modifying the drilling trajectory (Ref. 9), optimizing drilling schedule and offline operation to minimize the rig days (Ref. 10).