In recent years, the upswing in drilling activity and the higher price of natural gas has caused the industry to focus more on non-conventional gas reservoirs. Heading up this list are gas shales. This peaked interest was brought on not only by an increase in natural gas prices, but also the apparent abundance of potential gas shales present in the continental United States and the well publicized success of the Barnett Shale of North Texas. In order to obtain commercial production from these low permeability shale reservoirs, fracture stimulation is required. Numerous technical papers have been published on the merits and success of stimulation in this well documented reservoir. While slickwater treatments have become the stimulation method of choice, it is important to note that several other stimulation and completion techniques have been employed that have resulted in economic and commercially viable Barnett Shale producers over the last 20 years. Although there has been tremendous success with slickwater fracture treatments, many believe this technology can be universally applied to all gas shale reservoirs. While this may be the case in the Barnett Shale it is not necessarily true for other prospective shale basins being explored. This paper will include a brief history of Barnett Shale stimulation practices and go on to address shale reservoirs and characteristics that make each one unique from a stimulation perspective. It is not the attempt of the authors to provide a stimulation checklist, but to identify a number of shale reservoir characteristics and their effect on the process of stimulation optimization. Case histories in the Ft. Worth Barnett and Permian Basin Barnett and Woodford Shales will be used to infer key differences in reservoir attributes and how these differences influence stimulation decisions. Introduction to gas Shales Natural gas production from shale reservoirs is commonly thought to be a recent phenomenon. However, the earliest known production occurred in the Devonian shale of Fredonia, New York in 1821 and more substantial gas production was recorded in the late 1880's in the Appalachian region again in Devonian gas shale. The Barnett Shale of the Fort Worth Basin has received the most attention in recent years as its explosive production growth has brought it into prominence as the largest gas producing field in Texas with current production in excess of 1.6 Bcf/d. The success of the Barnett Shale and strong gas prices have spurred exploration in many new gas shale plays across the United States. Figure 1 shows the gas shale basins and plays across the continental United States. As knowledge of the Barnett shale has matured over the first 25 years of its productive life, it has provided many insights and benchmarks by which to judge other basins for their prospective gas shale reservoirs. The Barnett demonstrates the significance of shale hydrocarbon content, frac barriers and the structural environment. Variations in these three major geological and geochemical variables across the Fort Worth Basin greatly impact the well plan and specific engineering designs required to maximize its productive potential. East Texas Barnett Shale The Barnett Shale of North Texas is a Mississippian-age marine shelf deposit that exhibits variations in mineralogical and geochemical properties. It is described as a black, organically rich, fine-grained shale1. The depth and thickness range from 3500 ft and 150 ft in Erath County to over 8000 ft and 1000 ft in Denton county, respectively. As with all gas shales, the quality of the reservoir is dependent on many factors such as kerogen type, total organic content (TOC), thermal maturity (measured by vitrinite reflectance), gas content, mineral content and traditional petrophysical properties. The North Texas Barnett has provided excellent data resources to define the favorable geochemical attributes for gas productive shale as well as the transition area into oil productive shales that are not as thermally mature. The silica-rich Barnett has proven to be conducive to hydraulic fracturing due to its mechanical properties and mineral composition. Early field development focused on an area that was very environmentally friendly in that the shale was thick and well bounded by hard, dense limestone, both above and below, and the structural setting was relatively calm with very minor faults, if any, and no karsts. Once its productive capability was firmly established and the limits of the "core area" were developed with vertical wellbores, the more challenging environments of the Barnett were explored where fracture boundaries were weak and faults/karsts communicated with a wet Ellenberger (Dolomite) below. With proven economic success in these challenging environments, horizontal completions have become the standard throughout the basin.
Development of marginal fields offers unique challenges during drilling, completion, stimulation, and production. The underlying objective should be to maximize the value of the field over its productive lifetime. Every phase of the well construction needs to be fully evaluated for subsequent impact on the safety and economics of producing oil and gas from the field. Log evaluation of formation type, thickness, and characteristics may determine the final completion plan, although lack of natural barriers from close water contact may be of major concern when a large stimulation program is required. Specialized low-density cementing systems may be necessary for maintaining satisfactory equivalent circulating density (ECD) for coverage across weak formations. These low-density systems can be prepared either by an engineered foaming operation or by the use of specialized additives blended with cement to lower the density, but production quality properties should be maintained. Consideration should also be given to the final cement sheath properties, which can provide isolation for the "life of well" following cyclic pressure loading from stimulation, testing, and flowing phases. This paper addresses the advantages and disadvantages of the historical approach to constructing and producing horizontals. Completion processes and procedures with emphasis on cementation designs and best practices for horizontal casing are presented with major focus on resulting production rates. These case histories will cover both cemented and uncemented producing wells. Also included will be new methods for predicting cement failure modes as a result of cyclic pressure loading from stimulation jobs. Recent design procedures and ensuing effect for maximum value of the producing asset for life of the field will be compared with historical procedures. Introduction As industry drilling and completion activity increases in the horizontal play of such prospects as the Barnett Shale, many completion techniques will be investigated to determine optimum production performance of the existing wellbore. An important aspect that should be considered is the role of cementation of the lateral section and design considerations relative to execution of this operation. Factors to consider for cementing operations are close water proximity, containment of fracture pressure within treating interval as related to fracture volume size, and number of stages to be performed. Reduced formation pore pressure caused by early depletion of the reservoir should be of concern also in the development stages of well production. Past investigation of horizontal cementing has identified some critical factors necessary for obtaining a successful primary cement job. During the drilling phase of the wellbore, solids settling from the drilling fluid along the low side of the hole can cause mud channels that can be difficult to remove.1 If not removed before cementing, interzonal flow could later be formed, which may jeopardize the production results because of poor zonal isolation. Besides the difficulty associated with displacing low-side solids, the high side of the hole could be susceptible to free water breakout if the cement slurry is not properly designed and tested in the laboratory and mixed on location. A channel formed from free fluid could result in a primary cement failure. This possibility is especially likely in high-angle/horizontal wellbores. Final slurry properties, with particularly close attention paid to free-fluid testing, should result in high-quality cement slurry with long-term isolation characteristics. Particular emphasis on free-fluid testing is found in a later section.
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