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Spatial Variation of Wettability at Sub-Micron Scale

Kristian Mogensen and Søren Frank
Maersk Oil Research and Technology Centre, Doha, Qatar

Wettability has long been recognized as an important factor influencing flow in carbonates. Fifty years ago, it was a common-held view that reservoirs were water-wet but with the work of Salathiel (1973), Morrow (1990) and many others, it was gradually recognized that especially carbonates could exhibit wettability variations ranging from partially water-wet to mixed-wet and even strongly oil-wet. It became clear that the current reservoir wettability state was influenced by the past filling history and hence that wettability may show variation laterally as well as with depth.

At the pore-scale, wettability is often characterized via a contact angle, which is measured on a flat surface. Morrow (1971) pointed out that contact angle may depend on flow direction; he found that the advancing and receding angles could be very different. To reproduce both primary drainage and secondary imbibition capillary pressure curves, Blunt and Scher (1995) proposed a procedure that accounts for wettability alteration from initially water-wet to fractionally oil-wet after primary drainage by allowing wettability to change only in pores invaded by oil. The wetting state in certain pores of their network model would therefore change after primary drainage. DiCarlo (2008) described a method for calculating the interfacial curvature between grains of different wettability.

At the core scale, wettability is sometimes characterized by the Amott wettability index; Strand et al. (2006) have proposed a different way to quantify the average core-scale wetting preference. At the grid-block scale, wettability is taken into account for flow simulations via its effect on relative permeability and capillary pressure, denoted KrPc curves hereafter. It is well-known that KrPc curves for water-wet and oil-wet rocks are very different and has been experimentally observed in most reservoir lithologies that oil recovery reaches its maximum for neutrally-wet rocks. This observation has led many researchers to focus on methods to alter wettability from either strongly water-wet or strongly oil-wet towards neutrally-wet using chemicals such as surfactants (Sharma and Mohanty, 2011) or using modified seawater (Fathi et al., 2010).

At present, the physical mechanisms behind wettability alteration are not completely understood, but surface reactivity is a key controlling factor, reflecting interaction between rock and fluids. Studies of surface chemistry have been made possible by advances in digital imaging over the last decade. New imaging techniques enable mapping of the spatial distribution of wettability at sub-micron level. Preliminary results from an undisclosed study of a Middle East limestone indicate that rough surfaces are oil-wet and that water only wets smooth surfaces. A similar observation in an unrelated area of research has been made by Zhang et al. (2011) who study water-repellent materials.

Observations made by authors indicate that rough surfaces are found at the pore throats. This observation suggests that the narrower throats and the larger pore bodies have different wetting preferences. It seems at first a bit counter-intuitive that throats are predominantly oil-wet, because wetting (water) films are thought to be thicker in the corners of the pore space, which would make it more difficult for the oil to get in contact with the rock. However, this argument is based on the assumption of a spatially uniform mineral composition forming a smooth continuum inside the rock sample. High-resolution imaging indicates that roughness caused by variation in mineral composition can be a controlling parameter at the sub-micron level.

While the imaging reveals further complexity that was not previously recognized, the newly gained understanding may also present some opportunity for improving oil recovery. One such area could be acid stimulation, which is critically important for well performance in low-permeability carbonate reservoirs. Carbonate acid stimulation below fracturing pressure relies on pumping hydrochloric acid at a rate which is optimal for propagation of wormhole (Fredd and Fogler, 1997) to maximize the effective wellbore radius per barrel of acid pumped. Furthermore, the acid must be diverted along the entire reservoir section, either by mechanical means (Mogensen and Hansen, 2007) or with chemicals (Al-Ghamdi et al., 2011).

With the right mix of chemical additives, it may be possible to design an acid job to target only an enlargement of the throats and leave the pore bodies untouched. If the rock surface near the throats has different wetting preference from the rest of the surface, one could devise a chemical additive to the acid to target throat dissolution. Instead of focusing on skin reduction by attempting to create and control wormholes, acid stimulation could be viewed as a way to enhance permeability for a much larger drainage area using the same volume of acid.


Al-Ghamdi et al. (2011), SPE 142564.
Blunt and Scher (1995), Phys. Rev. E52, 6387-6403.
DiCarlo (2008), SPE 115732.
Fathi et al. (2010), Energy and Fuels 24 (4), 2514-2519.
Fredd and Fogler (1997). SPE 38167.
Mogensen and Hansen (2007), SPE 110135.
Morrow (1971), JCPT 10, 38
Morrow (1990), JPT 42, 1476-1484.
Salathiel (1973), JPT 25, 1216-1224.
Sharma and Mohanty (2011), SPE 147306.
Strand et al. (2006), JPSE 52, 187-197.
Zhang et al. (2011), Langmuir 27, 12585-12590.


AAPG Search and Discovery Article #120034©2012 AAPG Hedberg Conference Fundamental Controls on Flow in Carbonates, Saint-Cyr Sur Mer, Provence, France, July 8-13, 2012