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Revisiting the Concept of Wettability for Organic-Rich Tight
Wettability is an important petrophysical property, which governs irreducible fluid saturations, relative permeability, and fluid invasion. Unlike conventional reservoirs, which have relatively uniform pore-surface properties, the concept of wettability is questionable in organic-rich tight reservoirs. These rocks do not only have a nanoporous system, but also possess multiple pore types with different interfacial affinities. Previous studies have shown that the unconventional reservoirs consist of three major pore types: inorganic pores (assumed to be water-wet), organic pores (assumed to be oil-wet, controlled by organic matter and thermal maturity), and mixed-wet pores (controlled by organic-inorganic distribution) (Curtis et al., 2012).
The current study revisits the concept of pore-type partitioning in tight rocks. We propose and demonstrate a new workflow to evaluate pore partitioning using four companion samples from Wolfcamp B Shale. First, all the specimens were vacuum dried at 100°C for 6 days to remove the free fluids until the weight stabilized. Total porosity was estimated as the sum of irreducible liquid volume (using nuclear magnetic resonance (NMR)) and gas-filled volume (using a high-pressure helium pycnometer). Two of the specimens were saturated with a single fluid (either dodecane or 2.5 wt% KCl brine)—first, via imbibition for 5 days, followed by step pressurization (up to 7,000 psi) to achieve 100% saturation. The imbibition step was done hydrostatically with fluid injected into the samples from all directions. The other companion specimens were subjected to multiple injection cycles—starting with imbibition, then counter imbibition, and finally, step pressurization with the replacing phase. During this process, we used brine-then-dodecane and dodecane-then-brine as the injection fluid sequences. The counter-imbibition process refers to the imbibition of the samples by one liquid followed by another liquid. All four samples were continuously monitored by both gravimetric and NMR measurements until equilibration. Relative fractions of both replaced and replacing phases were calculated from sample weights and pore-fluid volumes.
The new approach classifies the connected pore network into three categories—oil-wet, water-wet, and mixed-wet, respectively, occupying 50, 15, and 35% of total movable pore volume in the Wolfcamp B. Mixed-wet pore is defined as the pore fraction, in which both oil and water can replace air under capillary suction. Using a conventional NMR wettability index, based on the difference between brine and oil intakes (Looyestijn and Hofman, 2006), this sample would appear to be oil-wet. However, this is a misleading interpretation. It is important to emphasize that mixed-wet pores are not equivalent to neutral-wet systems. We observe that the mixed-wet pores prefer brine over oil. During the counter-imbibition step, the samples initially imbibed with dodecane tend to intake brine while replacing dodecane, whereas the samples initially imbibed with brine and then counter imbibed with dodecane do not show a significant change in fluid concentrations. Instead, it required 1,500 psi of injection pressure for dodecane to reenter the pore system.
During well completion, water blockage will likely happen in this formation due to the capillary preference of mixed-wet pores. This formation damage can be reduced by the addition of surfactants into fracturing fluids. Moreover, the effect of water blockage is expected to reduce with more than 1,500 psi of drawdown. Thus, the workflow is promising to fully describe the pore network in tight formations in which pore-type partitioning is a more reasonable concept than wettability.
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Sanchay Mukherjee, Son Thai Dang, Chandra Rai, and Carl Sondergeld
The University of Oklahoma