ABSTRACT:

It is often presumed that fine-scale surface pores and roughness in reservoir rock remain water-wet. To test this assumption, deposition tendency of asphaltenes and resins during crude oil aging of brine-filled pores was investigated. Model frameworks of water-wet silica with sub-micron pores were synthesized as planar films of thickness 5 μm. These pore networks were conditioned in brine, submerged wet into crude oil for aging in the absence of applied pressure, then cleaned. Brines covering a wide range of NaCl concentrations, without or with added CaCl2 and/or brine degassing, were analyzed. Spectroscopy and microscopy were employed to determine the amount and distribution of asphaltene/resin deposits. The results clearly demonstrate that crude oil is capable of spontaneously invading these fine pores to render them oil-wet. All samples exhibited at least some deposition, with the overall NaCl concentration having little effect, whereas the increasing presence of CaCl2 led to a reduction in deposition. Scanning electron microscopy revealed that deposition typically took the form of uniform thin layers lining pore walls. A mechanism for spontaneous displacement of brine from tight water-wet pores, based on local rupture of convexly-curved brine thin films, is discussed.

INTRODUCTION

Reservoir wettability is largely dictated by the ability/inability of the more polar heavy components of the crude oil, namely its asphaltenes and resins, to adsorb or deposit over geological timescales on rock pore surfaces to alter their originally water-wet state. This depends on rock mineralogy and surface properties, oil and connate brine composition and their temperature and pressure history of pore occupation. The most widely accepted model, termed mixed wettability (Anderson, 1986; Kovscek et al., 1993; Morrow, 1990; Robin, 2001; Salathiel, 1973; Skauge et al., 2004), predicts that pore surfaces supporting sufficiently high local meniscus curvature to prohibit displacement at the maximum applied capillary pressure of primary drainage remain overlain by their bulk brine and retain water-wetness. Surfaces presenting lower curvature can admit oil and be altered to oil-wet if directly exposed via rupture of the intervening thin brine film. Special core analysis attempts to reproduce the wettability state in the reservoir through cleaning, reinstating the brine and draining with the crude oil and aging at reservoir conditions. Subsequent displacement testing yields global empirical wettability measures such as Amott-Harvey index (Morrow, 1990) or rates and extents of recovery by spontaneous brine imbibition (Morrow and Mason, 2001). Analogous brine-oil aging treatments are applied to flat smooth mineral substrates (e.g., glass, quartz, mica, calcite) to measure contact angle behavior (Lui and Buckley, 1999) and nanoscale morphology of adsorbed or deposited layers by AFM (Lord and Buckley, 2002), in order to interpret core analysis results or aid in simulating them by network modeling (Blunt, 1998). Despite the developments in techniques for 3D pore-scale structural characterization of rock cores, direct methods to map the distribution of local wettability borne by the pore walls remain elusive. This knowledge gap limits applicability of wettability studies on smooth impervious substrates, in turn limiting the predictive power of simulations of multiphase transport.

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