Fluid-rock interaction of Wolfcamp Shale: the effects of pore structure and mineralogy

Shale has been focused because of its potentials in fossil fuel as unconventional reservoirs and in carbon storage as cap rocks. Fluid rock interaction is important for shale study. Because hydraulic fracturing in unconventional oil and gas development and the sealing ability of cap rock are all related to the fluid-rock interaction. The fluid-rock interactions,  such as the spontaneous imbibition (SI), were studied on Wolfcamp Shale core samples in Midland Basin, west Texas in this work. Multiple experiments including X-ray diffraction (XRD), contact angle measurement, scanning electronic microscopy (SEM), and (ultra-) small angle X-ray scattering [(U)SAXS] were performed to characterize the mineralogy, wettability, and pore structure to assist the analysis of the SI data in Wolfcamp Shale. XRD results indicated the Wolfcamp Shale samples were dominated by carbonate and siliciclastics with different sample depths, which is concordant with the well-logging data. The SI experiments were conducted in hydrophilic de-ionized water (DIW) and hydrophobic D2T (a mixture of two parts of decane and one part of toluene). Most samples have layer structure, therefore, the SI experiments were performed in directions that parallel to the layer (P direction) and transverse to the layer (T direction) on each sample. The fitting slopes of SI results show that samples have better pore connectivity in hydrophobic D2T than DIW in both directions. In P direction, the imbibed volume of DIW and D2T are very close to each other, which indicate the Wolfcamp Shale could be more oil wet. (U)SAXS results provided the pore diameter distribution (PDD) of the samples, which separates the samples into two groups. Associated with mineralogy, group 1 is dominated by siliciclastic with pores at 10 nm and 50 nm, and group 2 is dominated by carbonate with pores at 100 nm and 600 nm. Coupled with PDD and mineralogy, the fitting slopes in group 2 in DIW P direction decrease and then increase with clay content with the turning-point at 30%. The micro-fractures and well-aligned clay minerals in SEM images in samples with more clay content could help to form fluid pathways during the DIW imbibition. Such a positive relationship in fitting slopes and clay content also appeared in D2T P direction imbibition. In summary, the experiments conducted on the Wolfcamp Shale in west Texas including SI, XRD, SEM, and (U)SAXS could investigate fluid transport mechanisms in shale to support the studies for unconventional reservoir development and carbon storage.