When using hydraulic fracturing techniques to stimulate production from an oil or gas well, successful job placement is often jeopardized by near-wellbore (NWB) problems. Many times, these problems are specifically related to the perforation entry or to the width of the fracture near the wellbore. A likely conclusion is that insufficient width generation in the NWB region is the result of a tortuous (rapidly turning or twisted) path for the first few inches or feet of the fracture. Within this near-wellbore region, such fractures must overcome rock stresses greater than the least principle stress. In other instances, the inadequate width problem may result from the generation of a large number of independent near-wellbore fracture planes (starter fractures) instead of only one fracture (or at least only a few). Additionally, the hydraulic fracture may initiate from a fluid-filled microannulus rather than the perforations, which can lead to significant proppant-pumping limitations.
During the early 1990's, the oil industry began to consider these NWB problems more seriously. Procedures to help identify the problems were developed, and techniques involving proppant slugs and viscous gel slugs were used to mitigate such problems before or during a fracture-stimulation treatment. Alterations of the well completion plan proved to be a major part of successfully reducing the occurrence of similar problems in future wells in that reservoir. This paper discusses this technology and its evolution through recent years, as well as current applications of these techniques.
History and Background
The first use of proppant slugs in hydraulic fracturing operations and the inventor are debatable. Between the 60's and the 80's, proppant slugs were used sporadically, and seldom through a premeditated or scientific method. In the early 1980's, McMechan and Conway1 reported small slugs dramatically improving perforation entry problems in very deep Oklahoma reservoirs. To some extent, this phenomenon has probably existed for 50 years. 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. History also shows that adding very small, 100-mesh sand to the pad volume or just before the primary (larger size) propping agent was begun 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.
In the early 70's, Daneshy3 was the first to extensively study the effect of perforated (rather than openhole) wellbores in laboratory testing with realistic insitu stress conditions on synthetic (hydrostone) blocks. When he investigated perforations perfectly aligned with the preferred fracture plane (PFP), he reported that most of these test specimens had a single planar bi-wing fracture emanating from the perforations, but he also found that a less desirable fracture path sometimes resulted. Fig. 1 (Page 13) represents his photograph of this anomaly. Daneshy investigated many other perforation alignments and various degrees of perforation misalignment with the PFP. He also presented a photograph of his observations with a zerodegree phasing of five perforations that were 60° out of alignment with the PFP. Fig. 2 (Page 13) depicts the fracture path he reported as typical for this condition.
Many later investigators4–9 also found that fracture initiations do not always begin at the perforations but sometimes initiate from a microannulus outside the casing. Abass et al.7 extensively retested the perforation effect in the NWB region. They observed perforation dominated fracture behavior with perforations aligned within 30° or less to the PFP. Part of their results of tests with higher angles are shown in Fig. 3 (Page 13).
