We measure spontaneous imbibition of aqueous (deionized water and KCl solutions of various concentrations) and oleic (kerosene and iso-octane) phases in several dry organic shale samples selected from two wells drilled in the Horn River basin. We find that the imbibition rate of aqueous phases is much higher than that of oleic phases even when plotted versus scaling dimensionless time, contrary to capillary-driven imbibition models. The observed difference is more pronounced in samples with higher clay content. The results suggest that the excess water intake is due to (1) the additional driving force provided through water adsorption by clay minerals, and (2) the enhancement of sample permeability through adsorption-induced microfractures.

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Summary The abundant hydrocarbon resources in low-permeability formations are now technically accessible because of advances in the drilling and completion of multilateral/multifractured horizontal wells. However, measurement and modeling of petrophysical properties, required for reserves estimation and reservoir-engineering calculations, are the remaining challenges for the development of tight formations. In particular, characterizing wettability (wetting affinity) of tight rocks is challenging because of their complex pore structure, which can be either in hydrophobic organic materials or in hydrophilic inorganic materials. We conduct comparative and systematic imbibition experiments on 10 twin core plugs from the Montney tight gas formation, which is an enormous tight gas fairway in the Western Canadian Sedimentary Basin. Both contact-angle and imbibition data indicate that the formation has a stronger affinity to oil than to water. However, the ratio between oil and water uptake of these samples is usually higher than what capillary-driven imbibition models predict. This discrepancy can be explained by the strong adsorption of oil on the surface of a well-connected organic-pore network that is partly composed of degraded bitumen. We also define a wettability index on the basis of the equilibrium oil and water uptake of the twin samples. Oil-wettability index is positively correlated with total organic carbon and clay content of the rocks, which generally increase from the upper Montney to the lower Montney.

The combined application of multi-lateral horizontal drilling and multi-stage hydraulic fracturing has successfully unlocked unconventional tight hydrocarbon reservoirs. However, the field data show that only a fraction of the large water volume used in hydraulic fracturing treatments is recovered during flowback operations. The fate of non-recovered water and its impact on hydrocarbon production are poorly understood. This paper aims at understanding the relationship between water loss and rock petrophysical properties. It also investigates the correlation between water loss and soaking time (well shut-in time). Extensive spontaneous imbibition experiments are conducted on downhole samples from the shale members of the Horn River basin and from the Montney tight gas formation. These samples are characterized by measuring porosity, mineralogy and TOC. Further, a simple methodology is used to scale up the lab data for predicting water imbibition volume during the shut-in period after hydraulic fracturing operations.

The combined application of multilateral horizontal drilling and multistage hydraulic fracturing has successfully unlocked unconventional tight hydrocarbon reservoirs. However, the field data show that only a small fraction of the injected water during hydraulic fracturing treatments is recovered during flowback operations. The fate of nonrecovered water and its impact on hydrocarbon production are poorly understood. This paper aims at understanding the relationship between water loss and rock petrophysical properties. It also investigates the correlation between water loss and soaking time (well shut‐in time). Extensive spontaneous imbibition experiments are conducted on downhole samples from the shale members of the Horn River Basin and from the Montney tight gas formation. These samples are characterized by measuring porosity, mineralogy and TOC. Further, a simple methodology is used to scale up the laboratory data for predicting water imbibition volume during the shut‐in period after hydraulic fracturing operations.