Flashback 10 years ago to 2008: the North American hydraulic fracturing industry utilized a then record breaking 21.41 Billion pounds and experienced exponential growth year-over-year (excluding 2015 and 2016). Prior to 2008, proppant demand grew at a relatively modest pace and overwhelmingly consisted of 20/40 mesh high quality natural sands and synthetic proppants. Fundamental changes in drilling and completion practices has given rise to a significant increase in the application of smaller mesh proppants, most notably 40/70, 30/50 and various forms of what is generically referred to as 100 mesh sand (i.e., sands that are predominantly smaller than 70 mesh) in natural gas and liquid applications. Proppant demand has now soared, increasing significantly as a result of the new high-intensity completions practices in horizontal wells. In 2018, an estimated 200 Billion pounds will be used for the first time in history (or 10 times that used in 2008). The proppant supply industry responded well to the increased demand in the past decade, but the industry is increasingly concerned about future supply limitations and the potential impact on completion practices subject to high volume, quality and mesh size availability. This paper summarizes the historical supply of proppant by type and source, and the driver for each proppant type based on the authors’ current and prior research. The paper will further clarify the basics of proppant by type and size (e.g., what is 100 mesh?) and will address some of the challenges that both the proppant supplier and end-user may face subject to current or desired completion practices. Key observations will be: 1) Potential limitations in the amount of proppant size and type, 2) The impact that specific proppant shortages may have on both supplier and end-user, and 3) Risk factors the proppant supply base may experience subject to future changes in completion design. The objective of this effort is to encourage the need to study alternative completion designs subject to proppant availability. It is specifically not the intent of this paper to propose one form of completion practice or proppant type over the other.

In conventional formations it has long been established that designing fracture treatments with improved near-wellbore conductivity generates improved production and economic returns. This is accomplished by pumping treatments with increased proppant concentration in the final stages (the traditional proppant ramp design), and in some cases by changing proppant size or type in the final stages to effect greater near-wellbore conductivity - commonly referred to as a "tail-in" design. These designs overcome the impacts of greater near-wellbore pressure loss during production caused by flow concentration in the near-wellbore region compared to distal parts of the fracture. For vertical wells and crosslinked fracture fluid treatments, the fluid flow and suspended proppant transport is effectively "piston" flow and it was a relatively straight forward matter to engineer the near-wellbore region with a tail-in of higher conductivity proppant. For unconventional reservoirs, with multi-stage horizontal completions using slickwater fluids, it has not been obvious how best to create this improved near-wellbore conductivity and most operators have employed a "one size fits all" strategy of pumping a single proppant type unless there was perhaps a need for flowback control in which case a resin coated proppant might be used as a tail-in. This paper reports the results of two projects to address the engineering of the near-wellbore fracture conductivity for horizontal well fracturing. Firstly, a series of laboratory tests were run in a 10 ft. × 20 ft. slot wall to visualize near-wellbore proppant duning and layering associated with both "lead-in" and "tail-in" designs. The impacts of these depositions were then quantified using a 3D hydraulic fracture / reservoir simulation code for a variety of stimulation designs in the Middle Bakken and Three Forks formations of the Williston Basin. The results of this work show that well stimulation treatments in liquid-rich unconventional formations would benefit from a combination of small (5 to 10%) lead-ins and tail-ins of high conductivity ceramic proppant. This minimizes the effects of radial flow convergence in the transverse fractures generated from the horizontal well and maximizes the economic benefit of the well stimulation. In addition to paying out the small cost increase in only 1 to 2 months, the proppant bands of higher conductivity ceramic help mitigate the effects of longer-term sand crushing and degradation on near-wellbore plugging and thus increases 3-year cumulative free cash flow and the Estimated Ultimate Recovery (EUR) of the well.