The success of producing gas from unconventional resources, such as shales, is often tied to maximum exposure to the reservoir. Usually this is achieved by drilling horizontal wellbores and creating fractures that originate from multiple points along the wellbore. Each fracture "stage" must be isolated from the previous stage so as to create additional unique flow paths for the gas. One mechanism to create the fracture isolation points is to use chemical swelling packers between the liner and the formation. These chemical swelling packers can be swollen using water-based fluids, hydrocarbon-based fluids, or combinations of both.
Certain shale formations, like the Lower Huron and Marcellus, are often drilled with air or foam. One reason for air drilling is that these formations have shown a propensity to incur damage from traditional drilling fluids (both hydrocarbon- and water-based). Because of this, there can be reluctance to use traditional fluid systems to activate chemical swelling packers in these formations.
This paper documents the laboratory investigation and development of a novel activation fluid system that minimizes the potential damage to the reservoir but still permits operations to take advantage of the unique characteristics of the chemical swelling packer. Included is a discussion of the operational issues encountered to "scale up" for the first field trials and the results of the first commercial applications.
Packers for zonal isolation are commonplace fixtures in subterranean wells. Packers can be set through a variety of mechanisms that include mechanical, hydraulic, inflatable, or chemical swelling. The swellable packers offer many advantages over more conventional packers, which include the ability to adjust to irregular borehole geometries, overgauge hole, other wellbore incongruities, and lower running profiles, just to name a few (Evers et al. 2008; Yakeley, Foster, and Laflin 2007). However, one disadvantage is that sensitive formations have the potential to be damaged by the swelling fluid, as the formation is often in contact with the fluid for an extended period of time. Fig. 1a is an illustration of a swellable packer in an open hole. The packer string is run downhole, and an activating fluid is circulated into the annulus. Over a period of time, the packer elements will respond to the fluid and swell to seal against the formation. After the packer has swollen to sufficient dimensions to establish an isolation point, the production casing can be perforated and fracture stimulated (Fig. 1b). As the completion techniques advance using swell technology, many wells avoid perforating time and expense by incorporating a sliding sleeve to provide access to the reservoir. Upwards of 15 sliding sleeves and 16 swelling element packers have been used to create 15 unique and individual fractures within the pay zone. This combination of simple, reliable tools functions equally as well in horizontal and vertical wells (Yakeley, Foster, and Laflin 2007).
It is typical for the fluid to be in contact with the formation for one to two weeks. The fluid acclimates to the bottomhole static reservoir temperature during that time frame.