Laboratory-scale study on proppant behaviour in unconventional oil and gas reservoir formations

Persisting oil/gas recovery controversies throughout the fracture stimulation stage due to early production reductions have raised questions about realistic proppant performance in deep in-situ fractures. Therefore, a detailed understanding of proppant behaviour and performance in fractures exposed to deep reservoir environments is required for enhanced oil/gas exploitation. This experimental study aims to analyse the importance of proppant injection techniques, and also oil and gas reservoir formation properties (fracture surface roughness and formation saturation conditions) on the mechanisms of proppant distribution, proppant crushing and proppant embedment. Importantly, the impact of injecting mono-sized proppants and different-sized proppant mixtures are analysed in this comprehensive experimental approach. Moreover, the influence of microstructural and mineralogical alterations in fracture surfaces on proppant behaviour upon exposure to different fracturing/reservoir fluids (deionized (DI) water, NaCl 10%, NaCl 25% and, oil) are studied. The results reveal that increased fracture surface roughness tends to result in non-uniform distribution of proppants in the fracture surface, which leads to greater proppant embedment and crushing. However, the injection of different-sized ceramic proppant mixtures upon subjecting to high stresses yields better results in terms of proppant distribution, reduced fracture aperture drop and reduced fracture tortuosity increase compared to injection of monosized proppants. Despite the proppant injection mechanism and fracture surface roughness, fracture tortuosity increases due to the effect of proppant re-arrangement, crushing and embedment. The microstructural analysis confirmed that proppant embedment is more likely to occur at kaolinite-rich zones. In addition, CT-scan analysis confirmed the initiation and propagation of secondary micro-cracks from proppant-embedded locations. Exposure of siltstone specimens to fracturing/reservoir fluid conditions substantially increased proppant embedment. Whatever the proppant size, concentration, roughness and axial load, the fracturing/reservoir fluid interaction-induced coupled process of fracture surface softening and chemical corrosion were found to be critical factors in estimating proppant embedment under reservoir conditions.