Chemical degradation of guar gum solutions via the addition of a strong oxidant is a common process step in hydraulic fracturing. Unfortunately, this degradation step leads to the formation of an insoluble precipitate which clogs the porous rock formation, reducing efficiency, reducing oil recovery potential, and increasing energy costs. The chemical composition, particle size, and molecular weight distributions of the oxidatively degraded guar (“broken guar”) are largely unknown, making it difficult to develop mitigation strategies. In this work, broken guar gum solutions are systematically analyzed to understand the origin of the observed residue. Our results indicate that cellulose fibers and proteins, rather than galactomannan oligomers, are the two major components (>50%) of the solid residue (the water‐insoluble fraction of broken guar). This finding suggests that removal of the cellulose fiber and proteins from the guar source material may be a potential residue mitigation strategy. Separately, we provide evidence for a potential second mitigation strategy employing chemical additives to reduce aggregation of the insoluble species, effectively reducing their potential to cause formation damage.

Flowback aid surfactants are key components for optimal water recovery after a fracturing treatment. However, comprehensive guidelines and discovery workflows for selecting an optimal flowback aid are lacking. A suite of carefully designed high-throughput screening tests coupled with industry performance tests was developed and applied to over 50 surfactants representing 12 chemical classes to create a portfolio of formation-specific flowback aids. Experiments were carried out in a two-stage approach that focuses both on intrinsic surfactant properties and on interactions with the reservoir environment. In the first stage, promising surfactant candidates were selected using high-throughput testing of surface tension, critical micelle concentration, cloud point, mineral adsorption, emulsification, and heat-aged stability. In the second stage, efficacy of surfactant candidates was assessed by testing fracturing fluid cleanup from selected shale matrices. We observed trends in critical performance parameters with simple engineering design criteria, such as hydrophile/lipophile balance (HLB), or field conditions, such as salinity. All surfactants tested showed efficient surface tension reduction and minimal effect of salinity on surface tension. Critical micelle concentrations, however, decreased with increasing salinity, and the effect was more pronounced for surfactants with a greater HLB number. Further candidate differentiation for the optimal surfactant package was achieved by testing adsorption on shale minerals. The validity of the approach was confirmed by testing cleanup from sand and shale matrices with final product candidates.

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