This paper was prepared for presentation at the SPE Annual Technical Conference & Exhibition originally scheduled to be held in Denver, Colorado, USA, 5-7 October 2020. Due to COVID-19, the physical event was postponed until 26-29 October 2020 and was changed to a virtual event. The official proceedings were published online on 21 October 2020.
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 straightforward 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.