Optimizing Horizontal Completion Techniques in the Barnett Shale Using Microseismic Fracture Mapping

Abstract

Abstract The Barnett Shale of North Texas is an ultra low permeability reservoir that must be effectively fracture stimulated in order to obtain commercial production. As a result, techniques to optimize hydraulic fracturing effectiveness have evolved over the past decade. The first Barnett Shale "discovery" well, the C.W. Slay #1, was drilled in 1981 and it was almost 17 years before any significant commercial success was found in the Barnett, so the Barnett is a relatively new play. In fact, 75% of the producing wells in the Barnett have been drilled since 2000. In 1995, when the USGS was performing a gas in place assessment of the significant gas fields in the United States, the Barnett was not even evaluated. In 2002, according to the Energy Information Administration, the Newark East Field produced 202 Bcf, more than any other field in Texas, and was the 7th largest gas producer in the United States! In some areas of the Barnett, horizontal drilling has recently been applied in an attempt to optimize gas production. Issues such as nearby water bearing intervals, inadequate surface locations, improved gas production rates and cost per scf can, in some cases, be addressed by the use of horizontal wellbores. The goal is to maximize fracture network surface area in the targeted pay intervals, and in some areas, reduce the probability of excessive fracture height growth. Several horizontal completion techniques have recently been utilized, including single and multiple stage treatments with multiple perforation clusters in uncemented casing and multiple stage treatments performed in cemented perforated casing. In order to understand created fracture geometry for various completion designs, fracture treatments are often mapped with microseismic and tilt sensors. Production results from this pilot study of the first twenty-three horizontal wells in the same general "Core" area of the Fort Worth Basin are compared in addition to mapped fracture geometry from eleven of these with vertical wellbores. This paper will discuss drilling and completion strategies, look at fracture network areas obtained from each, and then compare and contrast the fracture effectiveness with the standard procedures used in vertical Barnett wells. Introduction The current commercial success of Barnett Shale development programs actually has its roots in the 1998 paradigm shift in stimulation techniques. Prior to that time, most Barnett Shale wells were completed with massive hydraulic fracture treatments using crosslinked gelled fluids carrying a few hundred thousand pounds to more than one million pounds of proppant. Because of the extremely low permeability of the Barnett, its inability to efficiently clean up fracture damage from gels, and the high cost of massive hydraulic stimulations, most Barnett treatments did not provide an adequate investment return. In 1998, Devon Energy experimented with an old fracturing technique that was gaining new acceptance at the time in East Texas. The technique was light sand fracturing or "water fracs"1. In many reservoirs, such as the East Texas Cotton Valley Sand, light sand fracturing is used to reduce stimulation costs without decreasing production. In the Barnett Shale, this technique has been successful and is now widely used for a different reason: it provides a much larger surface area of contact with the reservoir and minimizes fracture face damage resulting in improved productivity. Today, nearly every Barnett treatment is performed using light sand fracturing or some permutation of this technique and it has proven to be the most important advancement in the resurgence of Barnett Shale development programs for operators in this basin.