Economic and Physical Optimization of Hydraulic Fracturing

Abstract

Abstract Optimization has taken several different hues in all areas of engineering. Hydraulic fracturing, as applied to petroleum wells, has had its share. In the past, and before the maturing of high-permeability fracturing and the tip screen out techniques, this well stimulation procedure was limited to low-permeability reservoirs and unrestricted fracturing. In such cases, the fracture length would be an appropriate design optimization variable against an economic criterion, e.g., the Net Present Value (NPV). This involved the balancing of incremental future revenue against the cost of execution. Also interesting are parametric studies, allowing the variation of execution variables and the detection of differences in their respective design NPV. Such differences would be useful in decisions to measure a variable or stay within reasonable assumptions. The emergence of higher-permeability fracturing and the Unified Fracture Design (UFD) concept allowed two important notions. First, there is no difference between low and high-permeability reservoirs in terms of benefiting for fracturing. Just execution issues need to be resolved. Second, and more important, for any mass of proppant to be injected in any well, there exists only one fracture geometry that would maximize production. This geometry, consisting of length and propped width (with height as a parasitic variable) can be readily determined and, if placed, it will provide the maximum productivity index. All other configurations would result in lower productivity values. This is physical optimization. In this paper we combine the two: the economic and physical. For each proppant mass we first optimize the fracture physically and then we apply the NPV criterion. We perform a series of parametric studies for a range of reservoirs and we use economic variables that differ in various parts of the world. We show how to determine the optimum fracture size. We then show how fracture treatments may be attractive in certain reservoirs in mature areas but not attractive elsewhere. We also show that for a diversified company, given the choice, few successful fractures in high-permeability reservoirs are far preferable to fracturing large numbers of wells in lower permeability fields, although the latter can be made economically attractive only through hydraulic fracturing. Introduction Arguably, with the exception of some rare locations or companies, the petroleum industry has finally reached the stage where hydraulic fracturing is no longer considered as a stimulation technique exclusively suitable for low permeability formations. This took a couple of decades, at least, following the development of the tip screenout (TSO) and the voluminous body of work in places such as the Gulf of Mexico and Russia. Better yet, fracturing is now viewed as an integral part of well and reservoir management and a mainstay of production engineering rather than a choice of last resort for depleted or inexplicably underperforming wells. Fracturing has continuously expanded until it has become the completion of choice for all types of wells but, particularly, for gas wells. The choice to develop a field either with conventional completions or through the application of hydraulic fracturing has a big impact on the number of wells to be drilled and on the in-fill plan of a field. The tremendous advantage in fracturing most wells is now largely accepted; even near water or gas contacts, considered the bane of fracturing. High permeability fracturing is finding application because it offers controlled fracture extent and limits drawdown. A proper design and execution of a fracturing treatment involves several disciplines such as reservoir, production and completion engineering, requires a background in rock mechanics and fluid dynamics, is constrained by the physical limits of the materials and equipment used as well as by the operational issues, and last but not least must satisfy certain economic criteria.