In Situ Local Contact Angle Measurement in a CO 2 –Brine–Sand System Using Microfocused X-ray CT

The relaxation dynamics toward a hydrostatic equilibrium after a change in phase saturation in porous media is governed by fluid reconfiguration at the pore scale. Little is known whether a hydrostatic equilibrium in which all interfaces come to rest is ever reached and which microscopic processes govern the time scales of relaxation. Here we apply fast synchrotron-based X-ray tomography (X-ray CT) to measure the slow relaxation dynamics of fluid interfaces in a glass bead pack after fast drainage of the sample. The relaxation of interfaces triggers internal redistribution of fluids, reduces the surface energy stored in the fluid interfaces, and relaxes the contact angle toward the equilibrium value while the fluid topology remains unchanged. The equilibration of capillary pressures occurs in two stages: (i) a quick relaxation within seconds in which most of the pressure drop that built up during drainage is dissipated, a process that is to fast to be captured with fast X-ray CT, and (ii) a slow relaxation with characteristic time scales of 1-4 h which manifests itself as a spontaneous imbibition process that is well described by the Washburn equation for capillary rise in porous media. The slow relaxation implies that a hydrostatic equilibrium is hardly ever attained in practice when conducting two-phase experiments in which a flux boundary condition is changed from flow to no-flow. Implications for experiments with pressure boundary conditions are discussed. Plain Language Summary What happens to fluids in a porous medium after pumping is stopped? Fast X-ray tomography shows that even in a sample smaller than a sugar cube fluid interfaces continue to move for hours until an optimal fluid configuration is reached. The pace is limited by slow relaxation of dynamic contact angles. Therefore hydrostatic equilibrium, which is the state at which all fluid interfaces come to rest, is hardly ever attained in practice when conducting two-phase flow experiments where the flow is stopped in much larger soil or rock samples.

“…As a consequence the dynamic contact angle (

α = 29 °

) slowly relaxes from a value close to the one observed for quasi‐static drainage (

α = 27 °

) toward the equilibrium value of

α = 42 °

(Figure b). For the first time, we have derived dynamic contact angles by treating them as a fitting parameter between the macroscopic pressure difference

P_{n} - P_{w}

Section: Discussionmentioning

confidence: 99%

Time scales of relaxation dynamics during transient conditions in two‐phase flow

Schlüter

Berg

et al. 2017

“…The advent of micron-resolution imaging tools has made it possible to measure fluid/fluid interface curvature (Andrew et al, 2014b;Armstrong et al, 2012;Singh et al, 2016) and contact angle (Andrew et al, 2014b;Klise et al, 2016;Scanziani et al, 2017) between immiscible fluids at the pore scale. Also, recent studies have employed some of these methods for the in situ characterization of wettability and pore-scale multiphase displacements in natural porous media (Garing et al, 2017;Khishvand et al, 2017Khishvand et al, , 2016Lv et al, 2016Lv et al, , 2017Tudek et al, 2017). However, measuring contact angle and fluid/fluid interface curvature in typical microcomputed tomography (CT) images with low resolution (large voxel size) and for complex rocks is still not a routine and all these methods are either cumbersome or may introduce significant errors generated by voxelization artifacts.…”

Section: 1029/2017wr022124mentioning

confidence: 99%

Spatial Correlation of Contact Angle and Curvature in Pore‐Space Images

AlRatrout

Blunt

Bijeljic

2018

We study the in situ distributions of contact angle and oil/brine interface curvature measured within millimeter‐sized rock samples from a producing hydrocarbon carbonate reservoir imaged after waterflooding using X‐ray microtomography. We analyze their spatial correlation combining automated methods for measuring contact angles and interfacial curvature (AlRatrout et al., 2017, https://doi.org/10.1016/j.advwatres.2017.07.018), with a recently developed method for pore‐network extraction (Raeini et al., 2017, https://doi.org/10.1103/PhysRevE.96.013312). The automated methods allow us to study image volumes of diameter approximately 1.9 mm and 1.2 mm long, obtaining hundreds of thousands of values from a data set with 435 million voxels. We calculate the capillary pressure based on the mode oil/brine interface curvature value and associate this value with a nearby throat in the pore space. We demonstrate the capability of our methods to distinguish different wettability states in the samples studied: water‐wet, weakly oil‐wet, and mixed‐wet. The contact angle and oil/brine interface curvature are spatially correlated over approximately the scale of an average pore. There is a wide distribution of contact angles within a single pore. A range of local oil/brine interface curvature is found with both positive and negative values. There is a correlation between interfacial curvature and contact angle in trapped ganglia, with ganglia in water‐wet patches tending to have a positive curvature and oil‐wet regions seeing negative curvature. We observed a weak correlation between average contact angle and pore size, with the larger pores tending to be more oil‐wet.

“…In recent years, pore-scale X-ray microtomography (micro-CT) imaging has been widely used in geologically related studies (Al-Khulaifi et al, 2018;Al-Menhali et al, 2016;Andrew et al, 2014a;Berg et al, 2013;Blunt et al, 2013;Cnudde & Boone, 2013;Ketcham & Carlson, 2001;Lai et al, 2015;Lin et al, 2018;Lin, Al-Khulaifi, et al, 2016;Lin, Neethling, et al, 2016;Qajar & Arns, 2016;Reyes et al, 2017;Reynolds et al, 2017;Saif et al, 2017;Schlüter et al, 2016). In particular, imaging of multiphase flow in porous rock has been performed, covering a wide range of topics, including wettability characterization based on contact angle measurement, relative permeability, and curvature analysis in the pore space to estimate capillary pressure (Akbarabadi & Piri, 2013;Alhammadi et al, 2017;AlRatrout et al, 2017;Andrew et al, 2014b;Armstrong, Pentland, et al, 2012;Arns et al, 2003;Berg et al, 2016;Gao et al, 2017;Garing et al, 2017;Herring et al, 2017;Krevor et al, 2012;Lin et al, 2017;Lv et al, 2017;Norouzi Apourvari & Arns, 2016).…”

Section: Introductionmentioning

confidence: 99%

Imaging and Measurement of Pore‐Scale Interfacial Curvature to Determine Capillary Pressure Simultaneously With Relative Permeability

Lin

Bijeljic

Pini

et al. 2018

104

There are a number of challenges associated with the determination of relative permeability and capillary pressure. It is difficult to measure both parameters simultaneously on the same sample using conventional methods. Instead, separate measurements are made on different samples, usually with different flooding protocols. Hence, it is not certain that the pore structure and displacement processes used to determine relative permeability are the same as those when capillary pressure was measured. Moreover, at present, we do not use pore‐scale information from high‐resolution imaging to inform multiphase flow properties directly. We introduce a method using pore‐scale imaging to determine capillary pressure from local interfacial curvature. This, in combination with pressure drop measurements, allows both relative permeabilities and capillary pressure to be determined during steady state coinjection of two phases through the core. A steady state waterflood experiment was performed in a Bentheimer sandstone, where decalin and brine were simultaneously injected through the core at increasing brine fractional flows from 0 to 1. The local saturation and the curvature of the oil‐brine interface were determined. Using the Young‐Laplace law, the curvature was related to a local capillary pressure. There was a detectable gradient in both saturation and capillary pressure along the flow direction. The relative permeability was determined from the experimentally measured pressure drop and average saturation obtained by imaging. An analytical correction to the brine relative permeability could be made using the capillary pressure gradient. The results for both relative permeability and capillary pressure are consistent with previous literature measurements on larger samples.