A Model for Evaluating the Commerciality of an Unconventional Factory Development Outside of North America
Authors: Charlez Philippe A. , Delfiner Pierre 
Published: March 2016

The North American shale oil and gas “revolution” relies on four pillars not guaranteed elsewhere: knowledge of the subsurface, a strong oil- and gas-services industry in an open and competitive market, favorable mining rights, and a long oil and gas culture backed by political support. These pillars enabled massive “factory development” on the basis of drilling and fracturing a large number of inexpensive wells.

To evaluate the commerciality of a play outside North America and identify its most influential factors, a fit-for-purpose model was developed. It simulates the development of a core area and takes into account technical and economic parameters. An algorithm calculates the drilling and completion (i.e., fracturing) schedule required to reach and maintain a constrained production plateau determined by the capacity of the export pipe. The initial number of drilling rigs and the time required to mobilize them are important factors differentiating the US from other parts of the world where rig availability can be less evident. Wells are drilled in pads, and production is treated at the pad level by use of average decline curves. The model also includes drilling and completion learning curves.

Pretax net present value (NPV) and internal rate of return (IRR) are calculated on the basis of oil and gas prices, development capital expenditures (Capex), which are a fine breakdown between drilling, completion, and tie-in costs, and operating expenditures (Opex), which are fixed and variable. The appraisal phase and central-processing facilities (CPF) are also included. Curves of IRR vs. integrated well cost are computed for several values of well estimated ultimate recovery (EUR) and indicate for a given oil or gas price the maximum well cost compatible with a desired level of profitability.

A number of interesting conclusions can be drawn from the model. One is the resilience of the production of a field against investment slowdown. A large portfolio of wells does not behave like a single well. Instead, it acts as a “shock absorber” limiting global decline even with reduced drilling and fracturing activities. Another source of resilience is the fact that once the Capex are paid, the Opex are comparatively small, allowing for lower break-even costs. The model also highlights the key role of all consumable costs (casings, mud and cement, completion costs, fracturing fluids, and proppant), which suggests a simplification of the well design, a standardization of equipment, and the negotiation of large supply contracts to obtain wholesale prices. By contrast, drilling time appears as a secondary parameter, a consequence of the relatively low daily rates of the rigs used to develop unconventional plays. Finally, a comparison is made between the development of a derisked sweet area with an expensive appraisal phase and the development of the entire area. Economically speaking, focusing development on a sweet area appears as a high-risk/high-reward approach very similar to a conventional strategy.