Abstract
Abstract
Proppant production could damage downhole and surface equipment, reduce well performance, and lead to workover operations. Production rate control, drawdown management and solid separation at surface are often used for unconventional wells. An in-depth understanding of factors affecting proppant production is a crucial step toward mitigating the issues. An experimental investigation was conducted to determine key parameters affecting proppant production and develop mitigation strategies.
This study led to the construction of a unique fracture cell, inside which a proppant pack is sandwiched between two rock platens with similar reservoir formations. The fracture cell can be configured horizontally or vertically to mimic different fracture orientations. To simulate flowback process, slickwater is injected from the inlet boundary and produced through perforations at the outlet boundary, while injection rate and confining stress are increased gradually. Low-viscosity oil or a mixture of oil/slickwater is injected to simulate production operations. Injection rate, stress, proppant production and pack width vs. time are recorded. After each test, a novel technique is used to preserve the shape of the channel created by proppant production. Twenty five tests were performed using raw, resin-coated, and surfactant-treated frac sands (40/70 and 100 mesh).
Lab results show that proppant pack failure and proppant production initiate at perforations when fluid flow velocity is above a critical value, creating a channel progressing outwards from perforations. Channel growth continues until the proppant pack becomes stabilized due to reduced velocity through the channel. Proppant production and channel growth are more severe in vertical fractures than horizontal ones. In vertical fractures, gravity effects make the proppant at the arc area above the channel unstable and become mobile. At irreducible water saturation, the proppant pack is more stable in the presence of oil. Once water is mobile, proppant production becomes more severe. Altering the proppant surface to hydrophobic reduces channel size and proppant production. Resin-coated sand (RCS) can stop or mitigate sand production if enough RCS is placed near the perforations. Proppant particle shape, proppant surface conditions (coating or wettability), multiphase effects, stress, flowrate, fracture orientation (vertical or horizontal), and ratio of fracture width to proppant size are recognized as key factors. The lab results led to a few cost-effective mitigation strategies: larger proppant near wellbore, local sand with lower sphericity/roundness during the entire treatment, and resin-coated or hydrophobic sand toward the end of treatment, etc.
Based on learnings from this study, proppant sequencing trials were implemented, with 40/70-mesh sand pumped first, placed near wellbore, and followed by 100-mesh sand. Field trial results showed significant reduction of proppant production and solid separation cost. At the time of this writing, the evaluation of the hydrophobic frac sand was in progress.