Incorporation of viscosity scaling group into analysis of MPMS index for laboratory characterization of wettability of reservoir rocks

Abstract

Wettability is a key parameter affecting petrophysical properties of reservoir rocks. Mirzaei-Paiaman et al. (Energy Fuels 27:7360-7368, 2013) presented an index (referred to as MPMS) for laboratory characterization of wettability of native-or restored-state reservoir rock samples. To use this index two counter-current spontaneous imbibition (COUCSI) experiments are needed, one on the native-or restored-state core sample and another on the strongly water-wet (SWW) reference system. Slope analysis of recovery data in these two systems gives inputs for determination of MPMS index. The two systems must have the same pore structure, initial water saturation, and viscosity ratio. The case of high viscosity reservoir crude needs the reference COUCSI test to be performed using a high viscosity polar compounds-free oil. Such test could be very slow and time consuming. The purpose of this study is to remove the need for limiting condition of the same viscosity ratio between the two systems, so that the reference experiment could be performed using any viscosity ratio independent of viscosity ratio of the native-or restored-state system. Thus, in the case of high viscosity reservoir crude, the reference test can be conducted using a low viscosity oil. Such test is relatively very fast and time efficient. We do this by benefiting the viscosity scaling group (VSG) proposed by Mason et al. (J Pet Sci Eng 72:195-205, 2010). Using experimental data from three sets of mixed-wet systems, we show that applicability of this VSG is not limited to SWW systems only. This VSG is used to relax the need for the limiting condition of the same viscosity ratio between the native-or restored-state and reference systems in the MPMS method. Using two sets of experimental data, we show that acceptable results are observed when comparing the MPMS indices estimated by the proposed technique and the original MPMS method.

Analysis of the Impact of Fluid Viscosities on the Rate of Countercurrent Spontaneous Imbibition

“…Mason et al further improved on this model by introducing an extended empirical mobility term in the scaling expression. The applicability of the mobility term has recently been confirmed by Mirzaei-Paiaman et al Several other authors have also investigated the challenges related to how changes in fluid viscosities are impacting the rate of SI both theoretically and numerically using simulations. Ruth et al used a numerical approach and proposed an empirical relationship for accounting for these variations.…”

“…An empirical scaling expression addressing changes in fluid viscosities was introduced by Mason et al to improve upon the expression proposed by Fischer et al The call for improvement was the failure of the geometrical mean expression in eq to depend solely on the water viscosity in the limit when the oil viscosity ceases as observed experimentally by Handy . It reads as Since it was an improvement to the inverse of the geometrical mean expression and applied successfully by Mirzaei-Paiaman et al, it will be included here for comparison purposes. Hence, oil recovery will in the next section be plotted vs dimensionless time using eqs , , and and their ability to account for changes in fluid viscosities assessed by visual inspection.…”

Investigation of Oil Saturation Development behind Spontaneous Imbibition Front Using Nuclear Magnetic Resonance T2

“…The chemical property of quartz sand is stable and will not react with fluids employed in our work. As wettability has a strong effect on spontaneous imbibition, , contact angle tests are used to test the wettability of quart sand (Figure ).…”

“…The chemical property of quartz sand is stable and will not react with fluids employed in our work. As wettability has a strong effect on spontaneous imbibition, 35,36 contact angle tests are used to test the wettability of quart sand (Figure 1). The 100−200 mesh quartz sand is compressed to rock slices under the pressure of 30 MPa, and we soak the rock slices in the kerosene where a water droplet drips afterward.…”

Wettability of Carbonate Reservoir Rocks: A Comparative Analysis

“…In addition, relative permeability-based techniques including Craig's triple rules of thumb [38], the normalized water fractional flow curve [39], Lak [15], and modified Lak [13] were proposed to deduce knowledge of wettability in rocks. There exist other wettability indicators, such as the relative pseudo work of imbibition [40], MPMS (MPMS stands for Mirzaei-Paiaman, Masihi and Standnes) [41,42], relative imbibition rate [43], rise in core [44], and NMR-based techniques [45][46][47][48][49][50] that require additional experiments.…”