When hydraulic fracturing techniques are used to stimulate production from an oil or gas well, successful job placement is often jeopardized by near-wellbore (NWB) problems. These problems may be related to the perforation entry or to the fracture width in the immediate vicinity of the wellbore. It has often been concluded that insufficient width generation in the NWB area is the result of the fracture having a very tortuous (rapidly turning or twisted) path for the first few inches or feet before adopting its generally planar shape after it grows beyond the wellbore area. In other cases, the inadequate width problem may result from the generation of several independent fracture planes instead of only one (or a few). During the early 1990's, the oil industry began to consider these problems more seriously, and many operators now use techniques to mitigate such problems before or during a fracture stimulation. The completion plan must sometimes be altered to reduce the occurrence of similar problems in future wells completed in a particular reservoir. Proppant slugs and viscous gel slugs have helped remediate this problem during several applications throughout the world.
Contrary to what we would like to believe, proppant and/or viscous gel slugs do not cure every premature screenout. Of course, some people still believe that these slugs would prevent every premature screenout if they were applied properly for the particular problem. If economics were not a real-life consideration, and every completion could be treated as an experiment, that position might be valid. In today's oil and gas exploration environment, the more practical constraints of "economic benefit" present several limitations. This paper discusses these "slug" techniques and their evolution in recent years. It also presents some of the current state-of-the-art methodologies being used. We also offer practical limits to be considered for use with these techniques. Several case histories are presented as illustrations, and suggestions for alternate completion techniques are discussed.
There is much debate about the first use of proppant slugs in hydraulic fracturing operations and many claims to "inventor" status. Considering the typical size of fracturing treatments over the past 20 years, the original frac jobs of the late 40's and early 50's were no more than "proppant slugs" by modern standards. From the 60's through the 80's, proppant slugs were used only sporadically and seldom through a premeditated or scientific method. McMechan et al. 1 reported dramatic effects from small slugs improving perforation entry problems in very deep Okla-homa reservoirs. To some extent, this phenomenon has probably existed for 50 years. History also shows that the use of very small, 100-mesh sand added to the pad volume or just before the primary (larger size) propping agent was started in an attempt to improve fluid-loss control into natural fractures. This application was rare before the late 70's; however, as Cipolla et al.2 have reported, it continues to find significant applications today.