Advances in Understanding Wettability of Tight and Shale Gas Formations

Lan, Qing (University of Alberta) | Xu, Mingxiang (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Wood, James (Encana)



This paper aims at understanding the factors controlling the wettability of unconventional rocks. In the first part, we report the results of comparative imbibition experiments on several binary 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 is strongly oil-wet. However, the ratio between oil and water imbibition rate of these samples is 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 coated by pyrobitumen. We also define a wettability index by using the equilibrium imbibed volume of oil and water in binary plugs. Oil wettability index is in general positively correlated to the total organic carbon (TOC), measured by the Rock-Eval technique. In the second part, we report similar imbibition experiments on several binary core samples collected from the cores drilled in the shale members of the Horn River Basin. In contrast to the Montney (MT) samples, the Horn River (HR) samples imbibe significantly more water than oil. This observation contradicts the contact angle results which suggest that the HR samples are strongly oil-wet. Clay hydration, imbibition-induced microfractures, depositional lamination, and osmotic potential are collectively responsible for the excess water uptake. We also measure and compare spontaneous imbibition of oil and water into the crushed packs of the similar HR samples. Interestingly, in contrast to the intact samples, the crushed samples consistently imbibe more oil than water. The comparative study suggests that the connected pore network of the intact HR samples is water-wet while the majority of rock including poorly connected pores is oil-wet.Overall, the results suggest that the well-connected pore network of the MT samples is dominantly hydrophobic and is very likely to be coated by pyrobitumen. This is the main reason why these samples imbibe more oil than water. On the other hand, the well-connected pore network of the HR samples is strongly hydrophilic primarily due to the presence of clay minerals and precipitated salt crystals coating the rock grains.


Increasing the energy demand has shifted the industry focus towards unconventional resources worldwide. Recent advances in horizontal drilling and multi-lateral/multi-stage hydraulic fracturing has unlocked the challenging unconventional resources. However, successful and sustainable development of such reservoirs requires correct characterization of reservoir properties (Burke et al., 2011). In particular, knowing the reservoir rock properties such as permeability, porosity and wettability (wetting affinity) is critical for reserve estimation, production forecasting and designing optimum fracturing and treatment fluids.

The affinity of a reservoir rock on a particular fluid is defined as wettability, which depends on various factors such as rock mineralogy and the properties of the materials coating the rock surface (Anderson, 1986; Rao et al., 1994; Hamon, 2000; Mohammed B et al., 2010; Mohammadlou et al., 2012). Characterizing the wettability of reservoir rocks is important for 1) selecting fracturing and treatment fluids, 2) investigating residual phase saturation and its pore-scale topology, 3) investigating the occurrence water blockage at fracture face, and 4) selecting relevant capillary pressure and relative permeability models for reservoir engineering calculations.

  Country: North America > United States (1.00)
  Industry: Energy > Oil & Gas > Upstream (1.00)
  Technology: Information Technology (0.34)