Pore-Type Partitioning in Unconventional Tight Reservoirs: Impact on Formation Damage and Long-Term Production
Authors: Mukherjee Sanchay , Dang Son , Rai Chandra , Sondergeld Carl H. 
Published: October 2020

Wettability is an important petrophysical property, which governs irreducible fluid saturations, relative permeability, and fluid invasion in rocks. Unlike conventional reservoirs, which have relatively uniform pore surface properties, the concept of wettability is not clear 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).

This study revisits the concept of pore-type partitioning in tight rocks. We propose and demonstrate a new workflow to evaluate pore partitioning. 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 residual liquid volume [using nuclear magnetic resonance (NMR)] and gas-filled volume [using helium high-pressure pycnometer (HPP)]. The companion specimens from two formations (Eagle Ford and Wolfcamp B) 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 companion 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-fluidvolumes.

The new approach not only classifies the connected pore network into three categories—oil-wet,water-wet, and mixed-wet—but also quantifies their respective proportions. The mixed-wet pore is defined as the pore fraction, in which both oil and water can replace air under capillary suction. We observe that the behavior of mixed-wet pores is different among formations: they prefer brine over oil in Wolfcamp B shale, while they prefer oil over brine in the Eagle Ford Formation. Unlike conventional wettability assessments, from which an overall wettability is provided, the novelty of this method is to clearly classify different pore types and their distributions. The concept of fractional wettability is highlighted for organic-rich tight rocks, and the contribution of mixed-wet pores in relative flow is emphasized.

Hydraulic fracturing is a necessary stimulation process for tight reservoirs, in which the usage of fracturing fluid can affect formation performance. During well completion, water blockage is more likely to happen in the Wolfcamp B Formation than Eagle Ford Formation. Due to the capillary preference of mixed-wet pores, the water blockage might aid the Wolfcamp Formation to boost initial production, however, at a later stage, damage the formation. The workflow thus is promising to fully describe the pore network in tight formations, in which pore-type partitioning is a more reasonable concept than wettability.