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.

Summary A large hydraulic-fracture diagnostic project was undertaken in the summer of 2001 that integrated fracture-diagnostic technologies, including tiltmeter (i.e., surface and downhole) and microseismic mapping. The extensive data gathered resulted in a much clearer understanding of the highly complex fracture behavior in the Barnett shale of north Texas. The detailed fracture-mapping results allowed construction of a calibrated 3D fracture simulator that better reflects the observed mechanics of fracturing in this fractured-shale reservoir. More than just simple calibration was required. Indeed, a whole new understanding of fracture growth was developed. The Barnett shale has seen a rebirth of drilling and refracturing activity in recent years because of the success of water fracture, or "light-sand," fracturing treatments. This extremely low-permeability reservoir benefits from fracture treatments that establish long and wide fracture "fairways," which result in connecting very large surface areas of the formation with an extremely complex fracture network. Understanding the created-fracture geometry is key to the effectiveness of any stimulation program or infill-drilling program, particularly in this area, with its nonclassical fracture networks. Integrated-fracture diagnostics have led to the identification of new fracturing techniques, as well as additional refracturing and infill-drilling candidates. A new method for evaluating large microseismic data sets was developed. Combining the microseismic analysis with surface- and downhole-tilt fracture mapping allowed characterization of the created-fracture networks. Correlations between production response and various fracture parameters will be presented along with a discussion of methods for calibrating a fracture model to the observed fracture behavior. Barnett Basics The Mississippian-age Barnett shale is a marine shelf deposit that unconformably lies on the Ordovician-age Viola limestone/Ellenburger group and is conformably overlain by the Pennsylvanian-age Marble Falls limestone. The Barnett shale within the Fort Worth basin ranges from 200 to 800 ft in thickness and is approximately 500 ft thick in the core area of the field. The productive formation is typically described as a black, organic-rich shale composed of fine-grained, nonsiliciclastic rocks with extremely low permeability, ranging from .00007 to .005 md. The formation is abnormally pressured, and hydraulic-fracture treatments are necessary for commercial production because of the low permeability. The first decade of Barnett shale stimulation treatments was dominated by massive hydraulic-fracture treatments (more than one million lbm of proppant carried by highly viscous gel systems). Production was variable, with wells producing up to 1 Bcf estimated ultimate recovery. In 1997, Devon Energy (formerly Mitchell Energy) began experimenting with waterfractures, or light-sand, fracturing treatments, which were at the time, being successfully applied in the Cotton Valley sandstone—a tight gas reservoir approximately 100+ miles to the east of the Fort Worth basin.1 The waterfractures were successfully reintroduced into the Cotton Valley because of the then-current lack of commercial viability for large, expensive cross-linked fracture treatments in that reservoir. Devon believed that similar success would be achieved in the Barnett shale with large-volume slickwater treatments and subsequently experimented with several versions of these treatments before evolving to the current design. Today, depending on the location within the Barnett, viability of limestone barriers surrounding the Barnett intervals, and net-pay thickness, a "typical" Barnett treatment may consist of 750,000 gal of slickwater and 80,000 lbm of proppant pumped at 60 bpm, with proppant concentrations averaging 0.1 to 0.5 ppg throughout the treatment. The lack of gel solids in the fracturing fluid is believed to contribute to longer, more complex fractures and additionally, leave no gel residue or filter cake behind that may damage the fracture conductivity in these treatments. Because of the low-permeability nature of the reservoir, it is imperative that extremely large fracture-surface areas are created by the fracture treatments. The use of light-sand, or waterfracture, treatments has considerably improved both the production performance and the economics in this reservoir. Because of its extremely low permeability, the drainage distance from the fracture face is very small. Introduction The classical description of a hydraulic fracture is a single biwing planar crack with the wellbore at the center of the two wings. However, almost all physical fracture verifications performed to date, from corethroughs to minebacks, have proved this description to be oversimplified. Therefore, fracture-mapping technologies can provide insight into reservoir-depletion dynamics and significantly help optimize reservoir management. Fractures can be categorized as simple (the classical description), complex, or very complex. An illustration of how these fractures may look is found in Fig. 1. Because of several factors, including the presence of natural fractures, a fracture treatment in the Barnett is more likely to look like the "very complex" fracture description than the "simple" case. This allows a fracture fairway to be created during a treatment with many fractures in multiple orientations, resulting in large surface areas potentially contributing to production. Numerous treatments have been mapped in the Barnett to gain a better understanding of how these fractures propagate.

A large hydraulic fracture diagnostic project was undertaken in the summer of 2001, which integrated fracture diagnostic technologies including tiltmeter (surface and downhole) and microseismic mapping. The extensive data gathered resulted in a much clearer understanding of the highly complex fracture behavior in the Barnett Shale of North Texas. The detailed fracture mapping results allowed construction of a calibrated 3-D fracture simulator that better reflects the observed mechanics of fracturing in this fractured-shale reservoir. More than just simple calibration was required. Indeed, a whole new understanding of fracture growth was developed. The Barnett Shale has seen a rebirth of drilling and refracturing activity in recent years due to the success of waterfrac or "light sand" fracturing treatments. This extremely low permeability reservoir benefits from fracture treatments that establish long and wide fracture fairways, which result in connecting very large surface areas of the formation with an extremely complex fracture network. Understanding the created fracture geometry is key to the effectiveness of any stimulation program or infill-drilling program, particularly in this area with its non-classical fracture networks. Integrated fracture diagnostics have led to the identification of new fracturing techniques as well as additional refrac and infill drilling candidates. A new method for evaluating large microseismic data sets was developed. Combining the microseismic analysis with surface and downhole tilt fracture mapping allowed characterization of the created fracture networks. Correlations between production response and various fracture parameters will be presented along with a discussion of methods for calibrating a fracture model to the observed fracture behavior. Barnett Basics The Mississippian-age Barnett Shale is a marine shelf deposit that unconformably lies on the Ordovician-age Viola Limestone / Ellenburger Group and is conformably overlain by the Pennsylvanian-age Marble Falls Limestone. The Barnett Shale within the Fort Worth Basin ranges from 200 to 800 feet in thickness and is approximately 500 feet thick in the core area of the field. The productive formation is typically described as a black, organic-rich shale composed of fine grained, non-siliciclastic rocks with extremely low permeability, ranging from.00007 to.005 millidarcies. The formation is abnormally pressured and hydraulic fracture treatments are necessary for commercial production due to the low permeability.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractRefracturing can be used to increase production in poorly fractured wells. A different application of this technology is to refracture wells with strong initial fractures. In this paper, we provide evidence of increased production due to refracturing two tight gas wells having deeply penetrating initial fractures. Surface tiltmeter measurements show refracture orientations at oblique angles to the azimuth of the initial fractures.

INTRODUCTION The Gas Research Institute's (GRI) fourth Staged Field Experiment (SFE No. 4) well was drilled as part of a field-based research program that has been conducted in the Frontier formation of southwest Wyoming. During this experiment, data were collected from whole cores, multiple sets of openhole logs, in-situ stress measurements, microseismic surveys, and multiple injection (mini-frac) tests.1 These comprehensive data sets have been used to fully describe the Frontier sandstone. This paper summarizes the analysis of abnormally high fracture treating pressures that were observed on SFE No. 4. Over the past two decades, the analysis of the net or excess pressure has become an important diagnostic tool for the petroleum engineer to evaluate hydraulic fracture treatments. The technique was introduced to the industry by Nolte and Smith2 and has been used in many situations to diagnose fracture growth patterns. Net pressure analysis can also be used to categorize formation types based on their net pressure response.3 Abnormally high fracture pressures encountered in certain formations have also been evaluated with this method4 It was evident from the initial injection tests on SFE No. 4 that the injection pressure was noticeably higher than other wells in the area.5-9 Due to this high injection pressure, a series of diagnostic injection tests was developed to evaluate the cause of the high pressure. These tests indicated the high injection pressures were caused in part by high near wellbore friction. We also saw evidence of high net pressures in the fracture, indicating that multiple fractures were propagating simultaneously.