An Advanced Proppant Depositional Study with Post-Production Flow Evaluation in a 10' X 20', Transverse Fracture, Slot Flow Configuration

Abstract

While the shale revolution flourished prior to the pandemic, the increased supply bubble had already taken a toll on the profitability of horizontal wells with multiple transverse fractures. A significant shift previously occurred to reduce proppant costs by utilizing cheaper, smaller grained, lower strength, and broadly diverse grain sized sands. Due to the extremely low matrix permeability in active unconventional plays, the use of regional 40/70 and 100 mesh sands (50/140, 70/140, etc.) has become commonplace with adequate results. What remains is the need for enhanced conductivity near the wellbore to handle the radial flow convergence loss when the well is brought on-line. Research is being conducted to better understand how to efficiently increase near-wellbore conductivity using lead and tail-in stages with higher permeability (ceramic) proppant when frac sand is the majority of the material pumped into the well. A 10’x20’ Large Slot Flow (LSF) apparatus, equipped with multiple injection points, side-panel ports for leak-off and/or post-test injection, with the ability to be disassembled for sample analysis after testing, was utilized for this project. For this data, the inlet was moved to the centerline of the wall to allow for proppant and fluid to transport into an environment similar to a horizontal wellbore connecting with a transverse fracture. Various tests were conducted to study the depositional characteristics of lead and tail-in stages with ceramic proppant (15% BW-Lead, 5% BW-Tail) and a main stage of 100 mesh sand (80%). Three inlet positions were established in the lower, middle, and upper portion of the apparatus. Tests were recorded to visually capture the efficiency of placing the premium proppants near the wellbore for increased conductivity. A key addition to the study was the innovative, post-production analysis through the side-panel ports. Fluid was injected into the proppant pack to observe the effect of increased near-wellbore conductivity. To improve visibility, the fluid was colored with a fluorescent dye and observed under black lights. The injection front geometry was radial initially, but typically elongated toward the exit point after contacting the ceramic proppant. The amount of time and distance for the fluid to travel through the sand pack, as well as that for the fluid to reach the offtake point once the ceramic bed was reached, were monitored and recorded. The ratio of the velocities should represent a valid qualitative indication of the conductivity contrast of the two proppants. This paper will describe the unique experimental configuration, outline the testing program for both deposition and post-production assessments performed on the deposits, along with results that could provide better design practices leading to improved transverse fracture performance.