Progress in horizontal drilling and hydraulic fracturing techniques allow the oil and gas industry to get the most out of ultra tight, naturally fractured formations and unconventional reservoirs. The increasing price differential between crude oil and natural gas is resulting in unprecedented activity in the Bakken, Eagle Ford, Niobrara, and other oil rich shales. The industry is actively building drilling rigs and the fracturing companies are adding equipment and crews at an escalating rate to keep up with the market growth.These events have placed demands on hydraulic fracturing consumables as never before. Proppant shortages are expected to worsen before additional capacity can begin to offer some relief. Consequently, more and more operating companies are pumping lower quality Natural Quartz Proppant (NQP) in deeper, hotter, and higher closure stress environments, some of which exceed conventional design limits. All this in an effort to maintain completion intervals which are comparable to the accelerated drilling programs.Recent proppant testing indicates significant conductivity reductions over time as it relates to proppants with lower crush strengths when compared to the higher strength Northern Whites. These conductivity variations were identified using a Discrete Fracture Network (DFN) fracture simulation model which indicated substantial reductions in ultimate recovery and productivity over time. The conductivity and modeling results were compared to actual post-fracture analysis data in the Marcellus Shale. This comparison further substantiated the test results.This paper challenges the industry concept that pumping lower quality crush resistant proppants in a shale reservoir will not result in productivity losses. The findings presented in this paper clearly show that creating and retaining fracture conductivity is a prerequisite to achieving high initial productivity, ultimate recovery, and maximizing project economics.

Many engineers today do not have the training needed to fully understand the importance of fracture mechanics principles and are easily overwhelmed in trying to deal with proper proppant and fluid selections, perforation design and strategy, and on-site quality control of the fracturing process. The unfortunate reality is that many fracture designs are improperly engineered with critical reservoir and hydraulic fracture parameters either ignored or improperly addressed. Many completions are either marginally economical or produce at reduced commercial rates. Regardless of reservoir type, it is critically important to achieve a highly conductive hydraulic fracture that provides connectivity between the reservoir and the wellbore.Since its inception, fracturing and completion knowledge has expanded exponentially allowing the oil and gas industry to develop ultra-low permeability unconventional reservoirs. During the 1980's and 1990's technology pioneers such as Holditch, Nolte, Warpinski, Veatch, and others, further developed the principles of fracturing which recognize the importance of critical fracture parameters and their effect upon initial productivity and ultimate recovery. These gains in expertise have resulted in unprecedented activity in the Bakken, Eagle Ford, Barnett, Haynesville, and Marcellus with increasing activity in new reservoirs such as the Utica, Niobrara, and Mississippian. Although each of these reservoirs is unconventional, each is uniquely different with respect to lithology, permeability, and hydrocarbon chemistry and interaction. This paper will challenge the industry notion that infinitely conductive fractures are being placed in many unconventional completions. It further addresses the critical fracturing parameters required to achieve a high conductivity fracture, why they are important, and how to achieve proper proppant and fluid treatment designs. The importance of these fundamental principles is documented and illustrated by several case histories which demonstrate the value of achieving high conductivity fractures and the effects of improper design. This paper should be of great value to completion and operations engineers to help further their knowledge with regard to the importance of fracture conductivity and connectivity in all hydraulic fracturing applications.

The G-Function plot originally developed by Castillo was based on the work of Nolte's pressure decline analysis. This plot provides a graphical methodology for establishing fracture closure pressure from which the fluid efficiency, fracture geometry and leakoff coefficient could be determined. The Nolte method of pressure decline minifrac analysis using the G-Function plot has become a standard for fracture calibration in the industry from the high permeability (low efficiency) to low permeability (high efficiency) tight gas formations worldwide. Minifrac analysis has become a critical part of the fracture model calibration procedure for the successful design, evaluation, and implementation of hydraulic fracture treatments. Although Nolte's original work has many simplifying assumptions regarding fracture closure (e.g., constant leakoff coefficient, no spurt, no fracture growth after shut-in, constant compliance, etc.), it still provides the foundation for the basic first order parameters affecting pressure decline behavior. The G-Function analysis is now routinely used as a starting point for calibrating the input data required in 3D fracture simulators. To date, little or no information has been published supporting G-Function testing and analysis in the Barnett or other fractured shale formations. Fractured shale completions are still expanding in the Barnett and are becoming more prevalent throughout many additional geographic locations. Ultimately, completion success and the commercial viability of an asset in a tight naturally fractured shale formation, such as the Barnett, depends on an optimized hydraulic fracture stimulation using design parameters obtained through G-Function testing and analysis. Using this fracture diagnostic technology leads to increased reserve recovery and cost effective proppant fracture treatments.

Over the last several years, intensive reservoir studies were performed on the Davis formation (known locally as the Pregnant Shale) in the Fort Worth Basin, and the Travis Peak formation in the East Texas Basin. These studies were part of the Gas Research Institute's Tight Gas Sands Program designed to improve the overall understanding of hydraulic fracturing processes and production performance in tight gas sand reservoirs. The reservoir studies consisted of production data analysis using analytical models and reservoir simulators. In addition, pre-fracture and post-fracture pressure buildup tests were analyzed using both conventional transient analysis techniques and reservoir simulators. This approach allowed us to evaluate various reservoir conditions ranging from simple single-phase, single-layer models to multiphase, three-dimensional models. As such, the analyses provided a more thorough description of the reservoir parameters that control well performance, one of which is the effective drainage area or recovery efficiency. This paper summarizes the results of the reservoir studies conducted on the Davis formation and the Travis Peak formation and demonstrates the importance of proper reservoir characterization to maximize per well recovery and drainage pattern efficiency.

SPE Members Abstract The Gas Research Institute (GRI) Tight Gas Sands program has conducted hydraulic fracturing research since 1983 to learn how to compute and/or measure the shape and extent of a hydraulic fracture ill real time. GRI has conducted field projects in the Travis Peak and Cotton Valley sands in east Texas, the Canyon Sands ill west central Texas, and tile Frontier sands in southwestern Wyoming. These field projects have lead to substantial progress in the understanding of tight gas reservoirs and hydraulic fracture stimulation processes. In addition, new technology has been developed that has improved fracture modeling and fracture diagnostic methods. Even with substantial progress over the years, there are still many "questions" Concerning the hydraulic fracturing process. One problem is that few data sets are available to test and validate the problem is that few data sets are available to test and validate the results generated from 2-D and 3-D fracture propagation models. To provide "Proof-of-Concept" experiments to validate fracture propagation models and to resolve certain questions concerning the propagation models and to resolve certain questions concerning the fracturing process, GRI has designed a Hydraulic Fracture Test Site (HFTS). The HFTS will be used to conduct experiments and gather data sets that will be valuable to both fracture model developers and scientists involved with fracture diagnostic measurements. This paper summarizes the goals, research objectives, and planning requirements set forth for the HFTS. Data have been gathered on three tight gas formations that have been identified as candidates for the HFTS laboratory. These formations include the Canyon sandstone in the Val Verde Basin, the Corcoran sandstone in the Piceance Basin, and the Clinton sandstone in the Appalachian Basin. Introduction When the GRI Tight Gas Sands project was organized, it was envisioned that fracture diagnostic methods could be developed to remotely sense the direction and the dimensions of a hydraulic fracture. Specifically, it was envisioned that fracture height and fracture length could be determined with reasonable accuracy using fracture diagnostic systems, such as geophones and tiltmeters. The diagnostic systems that have been developed by GRI since 1984 are capable of estimating values of fracture azimuth and fracture height. However, current fracture diagnostic systems still do not provide the data needed to validate 3-D fracture propagation models. To validate the fracture models and develop new fracture diagnostic technology, a more sophisticated field experiment is required. This field experiment will be conducted at the GRI Hydraulic Fracture Test Site (HFTS). The GRI Hydraulic Fracture Test Site will be a well characterized, highly instrumented field research laboratory that will provide the fracture diagnostics necessary to characterize the shape and extent of a hydraulic fracture within an actual tight gas formation. The Hydraulic Fracture Test Site will serve as a facility to continue with the development of many research projects that originated and were tested during the early stages of the Tight Gas Sands program. At the HFTS, sufficient core, geophysical logging data, and in-situ stress test data will be obtained to fully characterize each layer of rock in detail. We will concentrate our research on fracture diagnostics and fracture modeling. To verify the results of the various analysis techniques, the actual shape (height, length, and width) of the hydraulic fracture and the pressure distribution in the fracture will be measured using surface tiltmeters, pressure sensing devices, inclinometers, geophones, and other research instrumentation located in monitor wells that will either directly offset, or intersect the created hydraulic fracture. In addition, experiments at the HFTS will be conducted to measure the pressure gradient down the hydraulic fracture and at the fracture tip for various conditions of fluids viscosity and shear rate. One of the principal objectives of the GRI Hydraulic Fracture Test Site will be to provide a field laboratory for testing, and proving technologies developed specifically for hydraulic fracturing research and for the analysis of tight gas formations. The HFTS will also provide a location for the integration of multi-disciplinary research projects investigating the mechanics of hydraulic fracturing. Experience over the past six years has clearly demonstrated the need for contributions from a variety of disciplines in order to fully characterize the hydraulic fracturing process. P. 417