Optimal Stimulation Treatments in Tight Gas Sands

Abstract

Why Hydraulic Fracturing Works Hydraulic fracture stimulation can improve the productivity of a well in a tight gas reservoir because a long conductive fracture transforms the flow path natural gas must take to enter the wellbore.Fig. 1a illustrates radial flow in the reservoir when no hydraulic fracture has been created.As can be seen, all of the gas must converge radially to a very small area called the wellbore.For a radial flow pattern, most of the pressure drop in the reservoir occurs near the wellbore. Figs. 1b and 1c show what the flow path of natural gas from the reservoir to the wellbore looks like after a successful fracture stimulation treatment.At early time, Fig. 1b, natural gas enters into the fracture from all points along the fracture in a linear fashion.The highly conductive fracture rapidly transports the gas to the wellbore.At late time, Fig. 1c, the gas in the reservoir is flowing towards an elliptical pressure sink and most of the gas enters near the tip of the fracture.Conventional wisdom in designing hydraulic fracture treatments for tight gas sands would suggest that successful stimulation of tight gas sands requires creating a long, conductive fracture filled with proppant opposite the pay zone interval.This is accomplished by pumping large volumes of proppant at high concentrations into the fracture using fluids that can transport and uniformly distribute proppant deeply into the fracture. As fracture treatment technology has evolved, the trend has been to use more viscous fluids carrying higher concentrations of propping agents to create long, conductive fractures in tight gas sands. In the 1960's, slick water carrying very low concentrations of proppants (around 1 lb/gal) were used in many situations.These treatments were called water fracture treatments[1]. In the early 1970's, more viscous fluids were developed that were capable of carrying 5–6 lbs/gal of propping agents[2]. By 1980, delayed cross-linked polymer fluids were allowing the industry to pump treatments carrying as much as 10–12 lbs/gal of proppant[3].The trend in the industry was to pump more proppant, to create the long, conductive fractures needed to optimize production from tight gas reservoirs. Basic reservoir engineering calculations can be used to show that gas recovery and deliverability will be a function of propped fracture length and fracture conductivity in the reservoir interval. As the hydraulic fracture length and conductivity increase opposite the pay interval, the well will produce more gas at higher flow rates[4].