Fracture-Stimulation in the Marcellus Shale—Lessons Learned in Fluid Selection and Execution

Abstract

This paper provides a look-back review of lessons learned from early exploration to the full-scale development phase of the Marcellus shale in Pennsylvania. Fracture stimulation of over 100 wells has resulted in an in-depth understanding of details needed to achieve optimal frac performance. Much of the necessary learning curve is derived from the empirical testing of theory and what many refer to as "trial and error." The ability to evaluate and capture the best practices and develop them into a standing operating procedure (SOP) is one of the most important aspects in development of a new unconventional play. Lessons learned involving fracturing strategies and technologies to date have greatly narrowed the learning curve enabling more rapid advancement toward full-scale development. Introduction Shale reservoirs are characterized by extremely low permeability rock that has a number of unique attributes, including high organic content, high clay content, extremely fine grain size, plate-like microporosity, little to no macroporosity, and fickian vs. darcy flow through the rock matrix. This combination of traits has led to the evolution of hydraulic-fracture stimulation involving high rates, low-viscosities, and large volumes of proppant. Production from shale is dependent upon many variables including hydrocarbon content, total organic carbon, shale maturity, porosity, permeability, kerogen content, formation pressure, and net thickness. Improvements in drilling and completion techniques have improved gas recovery, namely landing a horizontal borehole strategically and creating a series of multiple staged hydraulic fractures. Even though horizontal drilling and fracturing have become the completion methods most commonly applied, a significant number of successful wells are being completed vertically in the Marcellus Shale. The extremely low permeability of shale requires a complex fracture to create primary induced fractures, reactivate and/or intercept more naturally occurring fractures or parting planes and ultimately expose more surface area. Early increased production is dependent upon the number of natural fractures intercepted and long-term production is dependent upon the amount of surface area exposed in the fracture network. Total improved production is dependent upon complex fracture geometry, which is influenced by many factors: stress contrasts, fluid leakoff, natural fractures, layering, weak planes, brittleness, fracture height growth, differing critical stress, post-fracture retention of connectivity to the created frac network, and mechanical stratigraphy, which controls the frac network creation. Large stimulation volumes of slickwater have been employed to create the extremely complex fracture fairway. High rate is needed to carry the large proppant volumes in a slickwater system and stimulation is achieved by bridging and diverting in induced fractures and natural fractures. The created fracture network is more productive than a dominant single fracture plane in a shale reservoir because more surface area is exposed for gas desorption and long-term natural gas production. Although many lessons have been learned from previous successful shale plays, many new lessons and unique "tricks of the trade" have been developed or tailored specifically for the Marcellus. This is especially true of the fluid systems and geochemical environment that has driven a number of new developments and fluid innovations.

Water Pollution Risk Associated with Natural Gas Extraction from the Marcellus Shale

“…( 10 ) For this analysis, the drilling and fracturing fluid used, F , was set as a nonparametric distribution with a mean of 17,000 m 3 , a minimum of 9,000 m 3 , and a maximum of 30,000 m 3 . The rate of return of hydraulic fracturing fluid for shale gas wells has been stated to range from: 9% to 35%, ( 10 ) 30% to 60%, ( 34 ) 15% to 60%, ( 35 ) 15% to 80%, ( 36 ) or even 10% to 100%. ( 33 ) For this analysis, the portion of drilling and fracturing fluid returned from the well, P R , was set as a mean of 0.3 with minimum and maximum bounds of 0.1 and 1, respectively.…”

Characterization of Marcellus Shale and Huntersville Chert before and after exposure to hydraulic fracturing fluid via feature relocation using field-emission scanning electron microscopy

“…4, while clay minerals appeared unaltered in all FE-SEM images. Clay minerals remained visibly unaltered to FE-SEM characterization likely because illite and chlorite in the Marcellus Shale are not water sensitive [13]. Carbonate has the potential to dissolve and become etched as the mineral structure is less stable compared to that of clay during interaction with acidic water based fracturing fluid.…”

The Effects of Fracture Orientation and Elastic Property Anisotropy on Hydraulic Fracture Conductivity in the Marcellus Shale

“…Natural white sand is the most common proppant utilized in fracture stimulation, with 40/70 mesh sand being the most common size. Fracture treatment designs are always changing, but approximately 40% of the sand used in horizontal Marcellus wells is 40/70 mesh sand, with the balance being 80/100 and 20/40 or 30/50 mesh sand (Houston et al, 2009;Mayerhofer et al, 2011;Shelley et al 2014). Water with a small amount of friction reducer, known as slickwater, is the most common fracturing fluid (Shelley et al, 2014).…”