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Wettability is a key factor influencing multiphase flow in porous media. In addition to the average contact angle, the spatial distribution of contact angles along the porous medium is important, as it directly controls the connectivity of wetting and non-wetting phases. The controlling factors may not only relate to the surface chemistry of minerals but also to their texture, which implies that a length-scale range from nanometres to centimetres has to be considered. So far, an integrated workflow addressing wettability consistently through the different scales does not exist. In this study, we demonstrate that such a workflow is possible by combining micro-computed tomography imaging with atomic force microscopy (AFM). We find that in a carbonate rock, consisting of 99.9% calcite with a dual porosity structure, wettability is ultimately controlled by the surface texture of the mineral. Roughness and texture variation within the rock control the capillary pressure required for initializing proper crude-oil-rock contacts that allow ageing and subsequent wettability alteration. AFM enables us to characterize such surface-fluid interactions and to investigate the surface texture. In this study, we use AFM to image nano-scale fluid-configurations in situ in 3D at connate water saturation and compare the fluid configuration with simulations on the rock surface assuming different capillary pressures.
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* Corresponding author:
Workflow for upscaling wettability from the nano- to core-scales
Maja Rücker1,3, Willem-Bart Bartels2,3, Tom Bultreys1,4,6, Marijn Boone7, Kamaljit Singh 5,6, Gaetano Garfi 6, Alessio
Scanziani 6, Catherine Spurin6, Sherifat Yesufu 1, Samuel. Krevor6, Martin. J. Blunt6, Ove Wilson3, Hassan Mahani3,
Veerle Cnudde2,4, Paul F. Luckham1, Apostolos Georgiadis1,3 and Steffen Berg1,3,6
1Department of Chemical Engineering, Imperial College London, UK
2Earth Sciences Department, Utrecht University, NL
3Shell Global Solutions International B.V., Grasweg 31, 1031 HW Amsterdam, NL
4UGCT- PProGRess, Ghent University, BE
5Institute of Petroleum Engineering, Heriot-Watt University, Edinburgh, UK
6Department of Earth Science and Engineering, Imperial College London, UK
7Tescan XRE, Bollenbergen 2B bus 1, 9052 Ghent, BE
Abstract. Wettability is a key factor influencing multiphase flow in porous media. In addition to the average
contact angle, the spatial distribution of contact angles along the porous medium is important, as it directly
controls the connectivity of wetting and non-wetting phases. The controlling factors may not only relate to
the surface chemistry of minerals but also to their texture, which implies that a length-scale range from
nanometres to centimetres has to be considered. So far, an integrated workflow addressing wettability
consistently through the different scales does not exist. In this study, we demonstrate that such a workflow is
possible by combining micro-computed tomography imaging with atomic force microscopy (AFM). We find
that in a carbonate rock, consisting of 99.9% calcite with a dual porosity structure, wettability is ultimately
controlled by the surface texture of the mineral. Roughness and texture variation within the rock control the
capillary pressure required for initializing proper crude-oil-rock contacts that allow ageing and subsequent
wettability alteration. AFM enables us to characterize such surface-fluid interactions and to investigate the
surface texture. In this study, we use AFM to image nano-scale fluid-configurations in situ in 3D at connate
water saturation and compare the fluid configuration with simulations on the rock surface assuming different
capillary pressures.
1 Introduction
Wettability is the preference of a solid to be in contact
with one fluid over another fluid. In petroleum
applications, rock represents the solid phase, crude oil the
first fluid phase and brine, which may be either present in
the reservoir (formation water) or injected for oil
recovery, the second fluid phase. A rock surface is called
water-wet when the water tends to cover it and is called
oil-wet when it prefers to be in contact with the oil phase.
Furthermore, wettability may vary from location to
location with a mixture of water-wet and oil-wet regions.
In this case the rock is called mixed-wet [1-5].
Wettability by itself is not a property used as a direct
input parameter for reservoir models. Yet, it is known to
significantly impact input values such as relative
permeability- and capillary pressure-saturation functions
[6-8]. So far, these relationships can only be determined
with core-scale experiments. To predict these parameters
for a specific reservoir a better understanding of the
principles behind wettability is crucial.
In a reservoir the wettability depends on various
properties which act at different length scales. An
overview of the different properties over increasing length
scales is shown in Fig. 1. Brine and crude oil composition,
surface chemistry and the P-T conditions affect molecular
interactions, which can be assessed for instance through
adhesion force measurements obtained with atomic force
microscopy (AFM) [9-11].
At the sub pore scale, roughness, which may facilitate
formation of thin water- or oil-films, becomes an
additional factor. On this length scale the contact angle
forming along three-phase contact lines may be measured
At the larger pore and pore-network scale ( to mm),
the confined space within a porous medium is taken into
account. Mineralogy and mineral distribution as well as
the saturation history need to be considered. On this
length scale wettability can be characterized through
contact angle distributions [13], fluid distributions [14],
by defining local capillary pressure [15, 16] and small
scale relative permeability [17, 18].
To predict wettability at the core scale the contribution
of each consecutive scale to the overall wettability of the
system needs to be considered.
1.1 Wettability at the molecular scale
Most minerals of reservoir rock are originally strongly
water-wet [4, 9, 19]. However, the adsorption of surface
active components or the precipitation of asphaltenes
present in the crude oil may alter the wettability towards
more oil-wet [4, 20-23]. Correspondingly, crude oils are
usually classified by assessing their acid (TAN) and base
(TBN) numbers as well as saturate, aromatics, resins and
asphaltene (SARA) fractions, which indicate the stability
of asphaltenes within the crude [24, 25].
In addition to the chemistry of the crude oil and the
rock, the brine composition may also impact the
wettability. Along a mineral surface, the balance between
electro-static forces and van der Waals forces leads to a
double layer of counter ions of the brine phase in
correspondence with Derjaguin-Landau-Verwey-
Overbeek [26, 27] (DLVO theory), which impacts the
repulsive/attractive forces of approaching oil molecules
[28, 29].
Various studies addressed the impact of these different
components [30-33]. In this work, we keep these values
constant by focussing on specific crude oil/rock/brine
systems to assess the impact of various parameters
controlling wettability at larger length scales.
1.2 Wettability at the sub-pore scale
At the sub-pore scale the measure of wettability is the
contact angle, which can be obtained by imaging a droplet
on a surface e.g. with a contact angle goniometer [34-41].
However, sub-resolution features are known to impact the
observed response. Surface roughness may lead to
pinning and therewith to a range of possible equilibrium
contact angles [12, 42, 43]. This effect even occurs on
surfaces considered atomically flat [42, 44].
Correspondingly, any contact angle measured represents
an effective contact angle
e. The intrinsic contact angle
i, which is solely related to the molecular interactions, is
only a theoretical descriptor obtained e.g. through
Table 1. TAN, TBN, SARA fractions, viscosity and density of the crude oils used.
[mg KOH g
[mg kg
[wt %]
[wt %]
[wt %]
[wt %]
20 °C [mPa s]
20 °C [g cm-3]
crude A
crude B
Table 2. Composition of formation water (FW) and a high salinity brine (HS) used.
Fig. 1. Wettability depends on various properties acting at different length scales such as brine- and crude-oil composition, reservoir
pressure and temperature (
P-T) conditions, surface chemistry associated with mineralogy at the molecular scale, surface structure
and fluid
-film formation at the sub-pore scale as well as saturation history and mineral distribution at the pore scale. They all
influence wettability, and thereby the pore
-dynamics during two-phase flow and the relative permeability. [71]
molecular models assuming a perfectly smooth surface
with the fluid phases being equilibrated [12, 45].
Dynamic contact angle measurements allow the
assessment of roughness through an advancing contact
angle and receding contact angle , which represent
the upper and lower boundary of possible contact angles
for the studied surface. The detected contact angle
hysteresis depends on the intrinsic contact angle, the
surface roughness and velocity of the moving contact line
Furthermore, grooves on a rough surface lead to
entrapment of the wetting phase [46-48]. This can have
large effects on the wettability alteration process. During
drainage, in most cases the aqueous phase is wetting and
forms water-films and layers within such grooves. These
water-films and layers prevent the intimate contact
between the oil and the solid and therewith wettability
alteration in this regions Correspondingly, such water
films may lead to mixed wettability patterns along the
surface [3, 22, 49, 50].
1.3 Wettability at the pore scale
So far, most 3D studies on mixed-wet and oil-wet rock
systems have focussed on wettability characterization.
Andrew et al. [13] introduced in situ measurements of
contact angles in rock and Scanziani et al. [51] and
AlRatrout et al. [52] automated the process. Contact angle
distributions are sensitive to image resolution and may
vary in case of non-equilibrium conditions [13]. However,
they provide an indication of the wettability and
wettability changes of the system. Alhammadi et al. [53]
showed a shift of the contact angle distribution when the
wettability of the rock is altered by aging. Yet, these
contact angles are not sufficient for prediction of larger
scale relative permeabilities. The obtained distribution
does not necessarily cover the advancing contact angle
, which is used as input for most multiphase flow
models in porous media, nor for its spatial distribution in
case of a mixed-wet rock [17].
Another way to characterize wettability is through
fluid distribution. In oil-wet and mixed-wet systems the
oil clusters appear sheet-like and flat compared to the
more spherical geometry in water-wet systems [54, 55].
Singh et al. [56] observed oil layer formation on the rock
surface and between two water interfaces, which provides
a conductive flow path for the oil phase in mixed-wet
systems. Lin et al. [57] observed the formation of minimal
fluid-fluid interfaces with a mean curvature of
approximately zero and deviating principal curvatures.
The fluid phase distribution or geometry may be fully
characterized through morphological descriptors known
as the four Minkowski functionals: volume, surface area,
integrated mean curvature and Euler characteristic [14,
Recent work focuses on linking the pore scale
wettability parameter to core scale properties such as
capillary pressure -saturation and relative permeability -
saturation relationships [16, 18, 63-65].
1.4 Wettability at the core scale
In conventional special core analysis (SCAL)
experiments, the capillary pressure - saturation
relationship is used to assess the wettability of a system.
This relationship can be obtained by combining the Amott
spontaneous imbibition test, in which the cumulative
production of the displaced phase versus time is recorded
as well as waterfloods to obtain the forced part of the
capillary pressure. Various indices, with the Amott and
USBM index being the most common, have been
introduced to derive wettability from the capillary
pressure - saturation relationship [66, 67]. However, the
results of such experiments are difficult to interpret as
other factors besides wettability may impact the results.
These factors include, for instance, viscosity, interfacial
tension and flow dynamics [68-70]. An alternative is the
wettability characterization by re-scaling the Leverett J
function to provide an average contact angle [71, 72]. Yet,
this method is not able to account for mixed wettability.
The wettability of a system can also be inferred from
the relative permeability- saturation functions using the
end-point water relative permeability, oil-layer drainage
and shape of the water relative permeability: An end point
permeability 
 < 0.3 indicates a water-wet system, 0.3
< 
 < 0.6 a mixed wet and 
 > 0.6 an oil-wet
system. Oil-layer drainage can be assessed from kro near
to the end-point: If kro < 0.05, while the saturation is still
decreasing, oil is moving through a continuous oil layer,
which is indicative of a mixed- or oil-wet system. If the
shape of krw shows a sharp rise with a cross over saturation
 < 0.5 the system is often oil-wet. A low krw < 0.2
for Sw = Swi + 0.2 is indicative of a water-wet system [73].
To predict the described core-scale output using
computational models this behaviour needs to be linked to
the smaller scale wettability responses. In this work we
combine the results of various experiments across length
scales using similar systems to describe this relationship.
2 Methodology
In this work, we compiled the results of previous studies
addressing wettability in similar systems [49, 74-77] and
complemented the results with additional measurements
to obtain wettability descriptions across all length scales.
2.1 Sample selection
1.1.1 Crude oil
The crude oils were chosen based on their high wettability
alteration potential. The corresponding total acid number
(TAN) and total base number (TBN) as well as the
Saturates, Aromatics, Resins, Asphaltene (SARA)
analysis are listed in Table 1. The crude oils are rich on
surface active components and asphaltenes, which
represent the components that are expected to change the
wettability of the rock.
Crude oil B was doped with 20% - iododecane, to
enhance the contrast to the brine phase for µCT imaging.
In all experiments with crude oil A, the brine phase was
doped with potassium iodide. In one experiment, n-
decane was used as a model oil.
1.1.2 Brine
The brine composition used in the current studies is listed
in Table 2. The formation water (FW) recipe, typical for
a carbonate reservoir, was taken from Mahani et al. [78].
For the first study with a doped brine a 17 wt% KI-brine
was chosen. Based on the ionic strength this corresponds
to 70400 ppm NaCl and therefore is considered a high
salinity solution (HS). For the other experiment a 9 wt%
KI-brine (S) was chosen to obtain better contrast between
the two fluid phases.
1.1.3 Rock
Ketton rock is a middle Jurassic oolithic carbonate rock
consisting of round grains (ooids and peloids) ranging
from 100 µm 1 mm size. Oolites are marine sediments,
which form during evaporation. Dissolved carbonate
precipitates along nuclei floating in the seawater, which
leads to concentric growth and to the round shape of the
grains. Once the particles become too heavy they
accumulate at the seafloor, where they become cemented
[79]. The geological history of the formation leads to a
homogeneous and simple structure of the rock, which
makes the rock highly suitable for µCT flow experiments
[49, 80, 81].
The rock has a porosity of φ = 23% with a bimodal
pore size distribution and permeability of 3 6 D. It
consists predominantly of calcite (99.1%) with minor
quartz (0.9%) components [82].
2.2 Core scale wettability assessment
At the core scale, wettability can be derived from relative
permeability-saturation and capillary pressure-saturation
functions. These can be obtained through special core
analysis (SCAL) experiments such as steady-state core
floods or Amott spontaneous imbibition tests.
2.2.1 Steady-state core flood experiment
Experiments to determine relative permeability were
performed in a custom-built X-ray saturation
measurement apparatus at Shell [18, 83, 84] following the
steady-state method [85, 86].
The Ketton sample (SCAL-plug: diameter d = 2.5 cm
and length L = 5 cm) was first saturated with HS-brine
and then mounted inside an X-ray transparent core holder
and placed in the flow apparatus for steady-state relative
permeability measurement. Afterwards, the sample was
desaturated with crude oil A by flooding at 1 ml/min until
no further change in saturation was detected. The sample
was then aged at 30 bar and 70˚ C for 1 week. The
measurements were conducted at a constant flow rate,
where the fractional flow fw was systematically changed
from 100% crude oil to 100% brine in 10 steps (fw1 = 0,01;
fw2 = 0,05; fw3 = 0,1; fw4 = 0,3; fw5 = 0,5; fw6 = 0,7; fw7 = 0,9;
fw8 = 0,95; fw1 = 0,99; fw10 = 1). At each step saturation
(and spatial profile along the core) and phase pressures
were recorded after steady-state was reached. The SCAL
data (pressure drop over the core and in situ saturation
profiles at each fractional flow step) were matched
numerically using Shell’s in-house simulator (MoReS) to
estimate the relative permeability as a function of
2.2.2 Amott spontaneous imbibition tests
In an Amott spontaneous imbibition test an oil-saturated
rock sample is placed into a vessel containing brine. In
water-wet and mixed-wet samples the water starts to
spontaneously imbibe into the rock sample replacing the
oil, which then gets produced, collected and monitored
over time. The production rate and the cumulative
production are used as a measure for wettability [67].
Bartels et al. [77] conducted an Amott spontaneous
imbibition test on a SCAL plug sample and a mini plug
sample commonly used for µCT studies (mini-plug:
diameter d = 4 mm and length L = 20 mm).
Both samples were cleaned, saturated with brine and
then desaturated with crude oil B. The SCAL plug was
desaturated by centrifugation (URC-628, 129 Coretest
Systems Inc., used at 3500 RPM) for 24 hours while the
temperature was kept constant at 40˚C. The mini plug was
desaturated by flooding 0.5 ml/min and then placed into
an oven at 40 ˚C for 24 h.
Consecutively the samples were placed into Amott
vessels. The production of the SCAL plug was monitored
with HECTOR, a high energy µCT scanner at the Centre
for X-ray Tomography (UGCT) in Ghent, Belgium [87]
and the production of the mini plug with the
Environmental MicroCT scanner (EMCT) also at UGCT
[88]. The scans were reconstructed using dedicated
reconstruction tools in the Acquila software package from
Tescan XRE. Visualization and additional post-
processing of the data were performed with Avizo 9.2.0
(Thermo Fischer Scientific).
The detailed experimental procedures can be found in
Bartels et al. [77].
2.3 Pore scale wettability assessment
Lin et al. [89] stated that sample initialization, especially
flooding as opposed to centrifugation may have a
significant impact on the outcome. For this reason, both
initialization protocols (centrifugation and flooding) were
assessed at the pore scale.
2.3.1 Unsteady-state waterflood experiments initialized
by flooding
The unsteady-state waterflood experiment was obtained
from cker et al, [90]. The mini plug samples were first
saturated with HS brine and then desaturated with crude
A by flooding 0.5 ml/min using the flow cell described in
Armstrong et al. [13]. The samples were aged at 3MPa
and 70 ˚C for one week. The waterflood was performed at
a flow rate of 0.03 ml/min. During the experiment the
fluid distributions within the sample were monitored
using fast µCT facility at the TOMCAT-SLS beamline at
the Paul Scherrer Institute, PSI, in Switzerland, while the
HS brine was injected into the sample.
The images were reconstructed using the Paganin
method [91] and processed and segmented with Avizo
9.0. The wettability of the system was assessed visually
and by contact angle measurements following the
workflow described in Andrew et al. [13] using the
filtered grey scale image of the final timestep measured
during this flooding sequence.
2.3.1 Unsteady-state waterflood experiments initialized
by centrifugation
The unsteady-state waterflood performed on a centrifuged
sample was prepared following the protocols from Lin et
al. [89]. 8 subsamples with a diameter ø = 6 mm and
length L = 20 mm were predrilled in a SCAL plug with a
diameter ø = 3.8 cm and length L = 4 cm. Subsequently,
the plug was saturated with HS-brine, desaturated in a
centrifuge with crude A (URC-628, 129 Coretest Systems
Inc., used at 3500 RPM for 24h) and then stored under
elevated pressure of 3 MPa and temperature of 70 °C for
4 weeks. Afterwards, the smaller sample was chopped off
the SCAL plug and fitted into the Viton sleeve while
being kept in the crude oil and placed into a core holder
described in Singh et al. [56]. Consecutively, a waterflood
experiment was performed by injecting HS-brine at a flow
rate of 0.03 ml/min for 2 h. µCT scans with a voxel size
of 6.1 µm were taken for the full sample and two smaller
(988 ×1014 × 997) subsamples with a voxel size of 2 µm
prior to and after the experiment using a Xradia μCT-
scanner (Zeiss).
The images were reconstructed using the proprietary
software provided by Zeiss, filtered with a non-local
means filter and segmented with the trainable WEKA
segmentation tool [92] provided by Fiji [93]. The contact
angle distribution was measured manually using the
filtered image obtained after the waterflood following the
procedure described in Andrew et al. [13]
2.3 Topographical measurements with AFM
At the sub-pore scale the impact of the surface
structure of a rock was assessed with atomic force
microscopy (AFM). As illustrated in Fig. 2., AFM images
the topography of a surface mechanically. The surface of
the rock is raster scanned by an atomically sharp tip
attached to the end of a cantilever. Close to the surface,
intermolecular forces acting on the tip lead to a bending
of the cantilever, which is monitored by a laser. For the
measurements presented, special attention was given to
the location at which the rock was scanned, to avoid spots
affected by drilling or breakage. The rock surface was
scanned with a silicon tip (PPP-NCHAuD from
NANOSENSORSTM) along a 10 µm x 10 µm area (128 ×
128 pixels) using the Quantitative Imaging mode (QITM-
mode). In this mode at each pixel a full force distance
profile is obtained (i.e. the force between the AFM tip and
the surface is monitored as the tip approaches the surface).
The rock sample was first saturated with brine and then
desaturated with n-decane by flooding (500 µl/min) to
mimic the distribution of fluid films and layers at the end
of drainage. In addition, test experiments were performed
on calcite minerals cleaved in oil and cleaved in brine and
then submerged in oil.
The image was analyzed with JPKSPM data
processing software (JPK instruments) and then
transformed into a 3D image using MATLAB (R2018b).
These 3D images were then further processed with
Geodict 2015 (Math2Market). A morphological drainage
simulation assuming a water-wet contact angle of 3 [94]
was applied. Avizo 9.0 (a) was used for visualization.
Fig. 2. AFM was used to image the surface of the original rock
surface within a pore (a) using QITM-mode, which creates a force
distance curve at each pixel (b) by monitoring the deflection of
a cantilever with an atomic sharp tip as it approaches and
disengages from the surface (c) [71].
3 Results and discussion
3.1 Wettability at the core scale
Fig. 3 shows the core-scale responses obtained from the
core-scale steady-state flooding experiment and the
Amott spontaneous imbibition test. The results show a
difference in wettability depending on the sample
The samples prepared by flooding appear mixed-wet
to water-wet. Following the guidelines to assess
wettability from relative permeabilities by Blunt [73], the
steady-state experiment initialized by flooding appears
with a water permeability end-point of 
 = 0.2 at the
upper limit for a water-wet system, but would not yet be
considered mixed-wet. However, with a very low residual
oil saturation of ,= 0.06 and a low water relative
permeability at low water saturations (< +.) of
( +.)= 0.03, this system fulfils two of three
criteria proposed to identify a mixed-wet system and
correspondingly is considered mixed-wet leaning to the
water-wet side.
The Amott spontaneous imbibition test of the sample
initialized by flooding also showed a water-wet response.
As illustrated in Fig. 3d the oil droplets emerging while
the brine invades the pore space show a water-wet shape.
Similar observations for a Ketton rock initialized by
flooding have been reported by Alyafei et al. [95].
The sample initialized by centrifugation, however,
showed only a little oil production from the pore space
(1%) and the oil droplets accumulating at the top of the
sample showed an oil-wet structure (Fig. 3c) [77].
The difference between the initialization by
flooding and the initialization by centrifugation is the
capillary pressure applied during drainage.
Based on the Young-Laplace equation, a higher
capillary pressure leads to the invasion of smaller pores
by oil compared to a lower capillary pressure. As the rock
surface is altered in contact with the crude [22], only the
pores invaded by oil are expected to change wettability.
Fig. 4 shows the pore (inlet) diameter distribution of
Ketton rock obtained by mercury porosimetry and the
estimated pore (inlet) diameter invaded by centrifugation
and flooding respectively for the Amott test examples
[77]. The pore sizes invaded by centrifugation were
estimated based on the rotation speed, interfacial tension
and fluid densities assuming an advancing contact angle
of 30˚. Based on this calculation pores down to a diameter
of 0.3 µm are expected to be filled with oil [77]: this is
sufficient to invade some micro-porosity and hence make
the solid surfaces oil-wet. As no porous plate was used
during flooding the maximum capillary pressure achieved
is controlled by the pore structure itself. An exact value
cannot be determined. However, the capillary pressure is
expected to be at the lower end of the peak pore (inlet)
diameter. µCT images obtained with the EMCT scanner
after drainage were used for validation. In these images,
all the resolved pore sizes showed occupancy with oil.
The small amounts of water detected did not show a
correlation with the pore diameter. However, it is likely
that the micro-porosity in the grains remained water-
saturated and water-wet. This is evident in the high initial
water saturation of approximately 0.4 in the results shown
in Fig. 3. The solid grains are micro-porous if they are
water-filled, they act like a wet sponge and may prevent
contact of oil with the surface of the grains even in the
larger pores, and hence retaining water-wet characteristics
in this case. We will test this directly later in the paper by
Fig. 3. The core scale steady-state SCAL experiment initialized by flooding shows a relative permeability, here displayed on an
ic (a) and semi-logarithmic scale (b), which is typical for a mixed-wet system leaning towards the water-wet side [71]. As
the oil droplets (red) emerging from the rock illustrate, the Amott spontaneous imbibition tests show an oil
-wet behaviour for the
mple initialized by centrifugation (c, imaged using HECTOR) and water-wet behaviour for the sample initialized by flooding
imaged using EMCT)
. [74]
measuring water film thicknesses in the corners of the
macro-pore space using AFM.
Fig. 4. Pore size distribution of Ketton rock. Based on the oil-
saturations obtained from the experiments, initialization by
flooding filled pores down to a diameter of 20 µm and
centrifugation down to 0.3 µm [77].
Correspondingly, the estimated minimum pore radius
accessed during flooding was set at 20 µm at the image
resolution boundary (4 voxel lengths) and below the
larger peak pore (inlet) diameter (Fig. 4). Smaller scale
imaging techniques such as µCT and AFM can give
further insights into the core-scale wettability response
and will be discussed below in more detail.
3.2 Wettability at the pore scale
The µCT unsteady-state waterflood experiments were
used to compare the impact of centrifugation and flooding
on sample initialization at the pore-scale.
The images Fig. 5 and Fig. 6 show some examples of
the fluid distribution at the pore-scale before and after an
unsteady-state waterflood for a sample initialized by
flooding (Fig. 5, measured at SLS) and by centrifugation
(Fig. 6, measured with Xradia).
Next to the brine phase (white), the oil phase (black)
and the rock (light grey) both figures also show the
presence of a water-in-oil emulsion. In the sample
initialized by flooding the emulsion appears as a third
phase (dark grey) [76]. In the sample initialized by
centrifugation, the emulsion appears in distinct droplets
with a diameter of up to 100 µm. The emulsion forms due
to the presence of surface active components in the crude,
which are also responsible for the wettability alteration of
the system itself. The identification and image processing
of this third phase was discussed in detail by Bartels et al.
Furthermore, both figures show the presence of oil
films along the grain surface and in the crevices in
between after the waterflood. However, for the
centrifuged sample, this oil appears continuous, while the
oil films in the flooded sample appear discontinuous
(comparison Fig. 5 and Fig. 6). This supports the findings
observed at the core-scale. The discontinuous oil films
observed in the µCT images hint to a mixed-wet sample,
while the continuous oil films indicate a predominantly
oil-wetting surface. The difference in the emulsion phase
can be explained in the same way. As the surface is oil-
wet after centrifugation, large water droplets may form
and remain stable, while in a mixed-wet system larger
droplets are likely to collapse as they get in contact with
the preserved water films in a mixed-wet system and only
small droplets, (below the image resolution) remain
Fig. 5. µCT images obtained before (left) and after the
waterflood experiment (right) of a Ketton rock sample (grey)
initialized by flooding. Next to the oil (black) and brine (white),
the images show the presence of emulsion (dark grey).
Furthermore, the images show the presence of discontinuous oil
films along the surfaces and in crevices [47, 71]. The images
were obtained at the SLS.
Fig. 6. µCT images obtained before (left) and after the
waterflood experiment (right) of a Ketton rock sample initialized
by centrifugation. The emulsion phase appears in form of
distinct brine droplets. The oil films appear continuous. The
images were obtained with Xradia [71].
The images obtained at the end of each waterflood
experiment were further used to measure the contact angle
distribution displayed in Fig. 6. The contact angle
distribution obtained for the Ketton sample indicates a
water-wet system with a peak < 90 ˚. However, compared
to the contact angle distribution for the strongly water-wet
decane-brine-Ketton rock sample reported by Scanziani et
al. [51], this system seems shifted by 30˚ towards more
oil-wet conditions.
Yet, the contact angle distribution does not show the
mixed-wet system observed in the image. The reason
might be the patchy small-scale wettability pattern, which
leads to pinning of the fluid-fluid interface, when the
surface changes from water-wet to oil-wet.
The contact angles detected in the sample initialized by
centrifugation varied from 50 ˚ to 130˚, with a median
value of 115˚ (Fig. 7). Only 21 contact angles could be
obtained for this sample. The reason was that the oil
remained predominantly in the poorly resolved pore
throats, which are less suitable for contact angle
measurements. For the same reason, the contact angles
obtained may be more affected by measurement errors,
which needs to be considered for the following
interpretation: The low values of 50˚ might be a sign of a
mixed-wettability pattern. However, as the oil-phase in
this sample is continuous, the pinning of the fluid-fluid
interface is less pronounced.
The sample initialization of the two cores investigated
were subject to different capillary pressures applied
during the drainage process and aging time. However, the
impact of aging time was assumed to be minor for the
following reasons. First, the core-scale studies indicate
that the wettability alteration of Ketton rock appears
already after 24h. Second, previous studies indicated that
the water-wet appearance of Ketton rock is preserved for
even longer aging periods [95]. Third, oil layers, present
in the flooded sample, show that wettability alteration
happened where the oil was in contact with the surface.
The oil layer, however, was discontinuous, which might
have been caused by sub-resolution surface features,
which can be investigated with AFM.
3.3 Wettability at the sub-pore scale
AFM was utilized to investigate the water films and layers
present within the Ketton rock sample initialized by
The water-decane interface and the height of the rock
surface were obtained from the force distance curves
collected for all of the 128 × 128 pixels along the 10 µm
× 10 µm area. Fig. 8 shows examples for such force
distance curves obtained from measurements on calcite
surfaces prepared with and without water.
Fig. 8. Representative force distance curves obtained from a
calcite surface without (a) and with the presence of a water film
(b). As the tip passes through the brine-decane interface the
cantilever is bending towards the surface, which is recorded as a
negative force. Once the cantilever reaches the rock surface it
gets bent in the opposite direction [71].
As the tip is water-wet, the cantilever bends towards
the surface when it passes through the fluid-fluid interface
during the approach, which is displayed in form of a
negative force. The height of the rock surface is obtained
7. The contact angle distribution (100 contact angles) for the unsteady-state waterflood µCT experiment with a rock sample
initialized by flooding indicates a water
-wet state even though more oil-wet than the water-wet reference obtained from Scanziani et
al. (2017). Due to the low number of contact angles (21 contact angles)
obtained for the unsteady-state waterflood µCT ex-periment
performed on a centrifuged sample flooding, solely the median value, the maximum and minimum are plotted [4
7, 49, 71].
010 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180
aged system
water-wet system (Scanziani et al. 2017)
water-wet oil-wet
x x
minimum maximum
aged system (centrifugation)
from the bending of the tip in the opposite direction
recorded as a positive force on the cantilever.
In the resulting image shown in Fig. 9, 60% of the
surface was covered with brine. Only 40% of the surface
were directly in contact with decane.
Fig.10. a Water film (blue) on top of a rock surface (grey)
measured in decane. The water layer shows a film thickness
ranging between 0 nm and 200 nm with a peak film thickness of
125nm (b) [71].
The 3D measurement of the wetting film also allows
to quantify fluid film thickness. Fig.9b shows that the film
thickness ranges between 0 nm and 200 nm with a peak
film thickness of 125 nm.
Furthermore, the rock surface obtained was used to
simulate the coverage of the rock for different capillary
pressures applied using a morphological drainage
simulation. The algorithm fits spheres of different radii,
representing different capillary pressures, onto the surface
to model the drainage process as it is applied prior to the
wettability alteration in a rock.
The result is shown in Fig. 10. Fig. 10d shows the
surface area coverage as a function of sphere diameter.
The higher the diameter and the lower the corresponding
capillary pressure the larger the surface area covered
with brine. 50% of the surface was covered with water for
a sphere diameter of 7 µm. For sphere diameters below
1.5 µm only 1.5% of the surface remained in contact with
the aqueous phase. These results are in line with the
detected water films.
These findings show that surface roughness of a rock
can facilitate the formation of water-layers. Different
capillary pressures applied on the rock during drainage
result in different water coverage of the rock surface.
Based on the assumption that wettability alteration occurs
predominantly when the surface is in direct contact with
the oil, the difference in coverage would result in a sub-
pore-scale wettability pattern as indicated in section 3.2
and explain the different wettability responses observed at
the core-scale.
4 Conclusions
In this study we assessed the wettability across the length
scales using similar oil-brine-rock system, including
AFM at the sub-pore scale, µCT imaging and in situ
contact angle distributions at the pore-scale combined
with Amott spontaneous imbibition tests and steady-state
relative permeability measurements at the core-scale,
demonstrating that upscaling is possible.
For this crude oil-brine-rock system, surface
roughness and the capillary pressure applied during
initialization were found to control the larger scale
wettability response after aging.
AFM studies showed the formation of water films
along the rock surface preventing a direct contact of the
oil and the rock which lead to a patchy sub-pore scale
Fig. 9. Water films (blue) on top of a rock surface (grey) obtained from a drainage simulation based on sphere fitting (a: sphere
diameter = 1.6
µm, b: sphere diameter = 5.6 µm, c: sphere diameter = 6 µm). d shows the percentage of surface area covered with
as a function of sphere diameter [71].
wettability pattern after aging. This small-scale
wettability pattern leads to a water-wet contact angle
distribution at the pore-scale, while some surface show
discontinuous oil layers and a mixed-wet core-scale
response leaning towards the water-wet side.
Furthermore, nano-scale simulations showed that the
higher the capillary pressure, the larger the oil-rock
contact area. Once the oil film becomes continuous the
core scale response for the same system appears oil-wet at
the pore- and core-scale.
This study demonstrates that for predictions of the
core-scale wettability response, the nano-scale surface
structure of the rock needs to be considered.
We would like to acknowledge the staff of UGCT, Ghent,
Belgium for support for the spontaneous imbibition
experiment and the Paul Scherrer Institute, Villigen,
Switzerland for the provision of synchrotron radiation
beamtime at TOMCAT beamline of the SLS and for
assistance during the session. Furthermore, we would like
to thank Anne Bonnin, Christian Hinz, Arne Jacob,
Christian Wagner, Steven Henkel and Frieder Enzmann
for support during the beamline experiments. We would
like to acknowledge Alex Schwing and Rob Neiteler for
the design of the setup and instrumentation, Fons Marcelis
for sample preparation, Holger Ott, Ryan Armstrong and
James McClure, Alex Winkel, Hayley Meek, Matthew
Leivers, Tannaz Pak, the Shell Digital Rock team at
Imperial and the team from Math2Market for helpful
discussions. We gratefully acknowledge Shell Global
Solutions International B.V. for their permission to
publish this work.
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... Wettability is a two-or multi-phase property defined as the preference of solid matrix of rocks to be in contact with one fluid rather than another [1]. It is one of the most critical properties controlling multiphase flow and transport in porous media [2][3][4][5][6][7][8][9][10][11][12][13]. Studies have shown that the wettability of rocks has a direct impact on relative permeability [4,10,14,15], capillary pressure [3,16], and performance of secondary and tertiary oil recovery methods [5,17,18]. ...
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Various methods have been proposed for the evaluation of reservoir rock wettability. Among them, Amott–Harvey and USBM are the most commonly used approaches in industry. Some other methods, such as the Lak and modified Lak indices, the normalized water fractional flow curve, Craig’s triple rules of thumb, and the modified Craig’s second rule are based on relative permeability data. In this study, a set of capillary pressure curves and relative permeability experiments was conducted on 19 core plug samples from a carbonate reservoir to evaluate and compare different quantitative and qualitative wettability indicators. We found that the results of relative permeability-based approaches were consistent with those of Amott–Harvey and USBM methods. We also investigated the relationship between wettability indices and rock quality indicators RQI, FZI, and Winland R35. Results showed that as the rock quality indicators increased, the samples became more oil-wet.
... In petroleum systems, more AFM applications related to surface studies have been verified, such as oil film characterization and relevant asphaltene deposition problems (Batina et al., 2003), interaction mechanism of oil-in-water emulsions (Shi et al., 2016), and mineral wettability with oils (Kumar et al., 2005). The nanoscale wettability measured by AFM can also be upscaled to realize core scale characterization, such as the workflow established by Rücker et al. (2020). These findings show promising development of AFM in oil production, welldeposition, adherence and changes of reservoir properties. ...
Atomic force microscopy (AFM) has been widely used in materials science and chemistry research since it was invented in the 1980s. It is a relatively new tool for geosciences and is very powerful for micro- and nano-scale surface characterization with a resolution down to atomic scale. One of the major advantages of this microscopy technique is that it can perform continuous non-destructive measurements on a sample surface. Surface studies provide important structural information for geological materials, especially in energy geosciences. In this review, recent applications of AFM in energy geosciences are critically reviewed, including surface topography, mechanical properties, surface dynamics, and state-of-the-art AFM-based infrared spectroscopy (AFM-IR) and the AFM-Raman technique. AFM imaging enables the mapping and recording of surface information and enhances the understanding of morphology and mechanical properties of geological materials, and is especially useful for those displaying a strong heterogeneity. This review aims to demonstrate the accessibility, versatility, limitations, and promising developments of AFM techniques in energy geoscience. We highlight the major advantages and disadvantages of AFM analysis of geological materials and highlight where factors can cause potential deviations between different experimental results. We further highlight where we believe are the most promising potential uses of AFM. It is foreseen that with the improvement of experimental processes and hardware, AFM will provide indispensable information on surface characterization in a wide range of geological studies.
The various microscopic processes that take place during enhanced oil-recovery upon injecting low salinity brines are quite complex, particularly for carbonate reservoirs. In this study, we characterize the in-situ microscopic responses of the organic layers deposited on flat Iceland spar calcite surface to brines of different salinity using Atomic force Microscopy (AFM). Organic layers were deposited from crude oil at the end of a two-step aging procedure. AFM topography images reveal that the organic layers remain stable in high-salinity brines and desorb upon exposure to low-salinity brines. In addition, the organic layers swell in low-salinity brines, and the stiffness of the organic layers is found to directly proportional to the brine salinity. These observations are explained in terms of ‘salting-out’ effects, where the affinity of organic layers to solvent molecules increases upon reducing the brine salinity. The swelling and desorption of organic materials provide access for the brine to mineral surface causing dissolution and change in wetting properties of the surface. Our results show the significance of de-stabilizing the organic layer on rock surfaces in order to design any successful improved oil recovery (IOR) strategy.
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Wettability is one of the key controlling parameters for multiphase flow in porous media, and paramount for various geoscience applications. While a general awareness of the importance of wettability was established decades ago, our fundamental understanding of how wettability influences transport and of how to characterize wettability has improved tremendously in recent years through breakthroughs in imaging technology and modeling techniques. Numerical modeling studies clearly show not only that macroscopic two-phase flow is influenced by the average wettability, but also that the spatial distribution of wetting significantly impacts the macroscopic parameters. Herein, we explore the thermodynamics for porous multiphase systems, and recent breakthroughs in wettability characterization. Our view is that bridging the multiscale characterization of wetting must consider two fundamental perspectives: geometry and energy. Advancing the overall description requires an improved understanding of the operative mechanisms that dominate at various scales, and the development of quantitative approaches to capture these effects. We take a multistage approach, looking at these fundamental perspectives from the sub-pore-to-pore length scales, followed by the pore-to-core length scales using various analytical techniques and numerical simulations. Within this context, there remain many open-ended questions, and we therefore highlight these issues to provide guidance on future research directions. Our overall aim is to provide comprehensive guidance on the multiscale characterization of wettability in porous media, in order to facilitate novel research.
Hypothesis: Contact angle measurements alongside Young’s equation have been frequently used to quantitatively characterize the wettabilities of solid surfaces. In the literature, the Wenzel and Cassie-Baxter models have been proposed to account for surface roughness and chemical heterogeneity, while precursor film models have been developed to account for stress singularity. However, the majority of these models were derived based on theoretical analysis or indirect experimental measurements. We hypothesize that sub-nanometer-scale in situ investigations will elucidate additional complexities that impact wettability characterization. / Experiments: To develop further insights into in situ wettability, we provide the first direct experimental observation of fluid-solid occupancies at three-phase contacts at sub-nanometer resolution, using environmental transmission electron microscopy. / Findings: Considering the partially spreading phenomenon and capillarity, we provide an improved physics-based interpretation of measuring the sub-nanometer-scale contact angle at the inflection point of the fluid-fluid interface. The difference between this angle and the commonly-used apparent one at a lower resolution is also discussed. Furthermore, we provide direct experimental evidence for the density differences between the adsorbed wetting film and the bulk wetting phase. For the effect of surface roughness, the applicability of the Wenzel model is discussed based on the observed in situ solid-fluid occupancies.
Hypothesis Roughness is an important parameter in applications where wetting needs to be characterized. Micro-computed tomography is commonly used to characterize wetting in porous media but the main limitation of this approach is the incapacity to identify nanoscale roughness. Atomic force microscopy, AFM, however, has been used to characterize the topography of surfaces down to the molecular scale. Here we investigate the potential of using AFM to characterize wetting behavior at the nanoscale. Experiments Droplets of water on cleaved calcite under decane were imaged using quantitative imaging QI atomic force microscopy where a force-distance curve is obtained at every pixel. Findings When the AFM tip passed through the water droplet surface, an attraction was observed due to capillary effects, such that the thickness of the water film was estimated and hence the profile of the droplet obtained. This enables parameters such as the contact angle and contact angle distribution to be obtained at a nanometer scale. The contact angles around the 3-phase contact line are found to be quasi-symmetrically distributed between 10° -30°. A correlation between the height profile of the surface and contact angle distribution demonstrates a quasi-proportional relationship between roughness on the calcite surface and contact angle.
This review analyses the fundamental thermodynamic theory of the crude oil-brine-rock (COBR) interface and the underlying rock-brine and oil-brine interactions. The available data are then reviewed to outline potential mechanisms responsible for increased oil recovery from low salinity waterflooding (LSWF). We propose an approach to studying LSWF and identify the key missing links that are needed to explain observations at multiple length scales. The synergistic effect of LSWF on other chemical enhanced oil recovery methods such as surfactant, alkaline, nanoparticle and polymer flooding are also outlined. We specifically highlight key uncertainties that must be overcome to fully implement the technique in the field.
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Wax or paraffin formation in subsea pipelines is a major problem in the upstream petroleum industry, accounting for tremendous economic losses. Researchers have reported that approximately 85% of the world’s oils encounter problems from wax formation (Thota and Onyeanuna 2016). In this manuscript, the authors briefly discuss the mechanism of wax formation in pipelines. Next, a review of various wax-mitigation technologies is provided. The review includes citations of various thermal, chemical, mechanical, biological, and other innovative methods reported by previous researchers and used in the industry.
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Wettability is a major factor that influences multiphase flow in porous media. Numerous experimental studies have reported wettability effects on relative permeability. Laboratory determination for the impact of wettability on relative permeability continues to be a challenge because of difficulties with quantifying wettability alteration, correcting for capillary-end effect, and observing pore-scale flow regimes during core-scale experiments. Herein, we studied the impact of wettability alteration on relative permeability by integrating laboratory steady-state experiments with in-situ high-resolution imaging. We characterized wettability alteration at the core scale by conventional laboratory methods and used history matching for relative permeability determination to account for capillary-end effect. We found that because of wettability alteration from water-wet to mixed-wet conditions, oil relative permeability decreased while water relative permeability slightly increased. For the mixed-wet condition, the pore-scale data demonstrated that the interaction of viscous and capillary forces resulted in viscous-dominated flow, whereby nonwetting phase was able to flow through the smaller regions of the pore space. Overall, this study demonstrates how special-core-analysis (SCAL) techniques can be coupled with pore-scale imaging to provide further insights on pore-scale flow regimes during dynamic coreflooding experiments.
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Plain Language Summary In geological systems, in particular in oil reservoirs, the wetting condition of rock, the preference of a fluid to be in contact with a surface in the presence of another fluid, has a significant impact on multiphase flow. Often a simplified picture based on static, wettability‐dependent fluid configurations is used as a basis for modeling where the fluids are assumed to flow through the porous rock within definite connected pathways. Our research, which is based on a time series of 3‐D images obtained during multiphase flow showing the pore‐scale fluid configurations of the brine and oil, demonstrates that this picture is too simplistic. In reality the flow paths change. In systems in which one phase is strongly wetting those changes are fast, small, and rare. However, oil reservoirs are mostly mixed‐wet as surface active components contained in crude oil alter the rock surface. In such mixed‐wet situations, we observe that the movement is slower (minutes instead of seconds), is more frequent, and involves larger fluid volumes. This indicates a different flow regime that cannot be estimated from an extrapolation from strongly wetting rock. This has consequences for the way how multiphase flow in mixed‐wet rock is described in models.
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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.
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In recent years, research activity on the recovery technique known as low salinity waterflooding has sharply increased. The main motivation for field application of low salinity waterflooding is the improvement of oil recovery by acceleration of production (’oil faster’) compared to conventional high salinity brine injection. Up to now, most research has focused on the core scale by conducting coreflooding and spontaneous imbibition experiments. These tests serve as the main proof that low salinity waterflooding can lead to additional oil recovery. Usually, it is argued that if the flooding experiments show a positive shift in relative permeability curves, field application is justified – provided the economic considerations are also favorable. In addition, together with field pilots, these tests resulted in several suggested trends and underlying mechanisms related to low salinity water injections that potentially explain the additional recovery. While for field application one can rely on the core scale laboratory tests which can provide the brine composition dependent saturation functions such as relative permeability, they are costly, time consuming and challenging. It is desirable to develop predictive capability such that new candidates can be screened effectively or prioritized. This has not been yet achieved and would require under-pinning the underlying mechanism(s) of the low salinity response. Recently, research has intensified on smaller length scales i.e. the sub-pore scale. This coincides with a shift in thinking. In field and core scale tests the main goal was to correlate bulk properties of rock and fluids to the amount of oil recovered. Yet in the tests on the sub-pore scale the focus is on ruling out irrelevant mechanisms and understanding the physics of the processes leading to a response to low salinity water. Ultimately this should lead to predictive capability that allows to pre-select potential field candidates based on easily obtained properties, without the need of running time and cost intensive tests. However, low salinity waterflooding is a cooperative process in which multiple mechanisms acting on different length and time scales aid the detachment, coalescence, transport, banking, and eventual recovery of oil. This means investigating only one particular length scale is insufficient. If the physics behind individual mechanisms and their interplay does not transmit through the length scales, or does not explain the observed fast and slow phenomena, no additional oil may be recovered at core or field scale. Therefore, the mechanisms are not discussed in detail in this review, but placed in a framework on a higher level of abstraction which is ’consistency across the scales’. In doing so, the likelihood and contribution of an individual mechanism to the additional recovery of oil can be assessed. This framework shows that the main uncertainty lies in how results from sub-pore scale experiments connect to core scale results, which happens on the length scale in between: the pore-network scale. On the pore-network scale two different types low salinity responses can be found: responses of the liquid-liquid or the solid-liquid interfaces. The categorization is supported by the time scale differences of the (optimal) response between liquid-liquid and solid-liquid interfaces. Differences in time scale are also observed between flow regimes in water-wet and mixed-wet systems. These findings point to the direction of what physics should be carried from sub-pore to core scale, which may aid in gaining predictive capability and screening tool development. Alternatively, a more holistic approach of the problems in low salinity waterflooding is suggested.
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Pore-scale two-phase flow modeling is an important technology to study a rock's relative permeability behavior. To investigate if these models are predictive, the calculated pore-scale fluid distributions which determine the relative permeability need to be validated. In this work, we introduce a methodology to quantitatively compare models to experimental fluid distributions in flow experiments visualized with microcomputed tomography. First, we analyzed five repeated drainage-imbibition experiments on a single sample. In these experiments, the exact fluid distributions were not fully repeatable on a pore-by-pore basis, while the global properties of the fluid distribution were. Then two fractional flow experiments were used to validate a quasistatic pore network model. The model correctly predicted the fluid present in more than 75% of pores and throats in drainage and imbibition. To quantify what this means for the relevant global properties of the fluid distribution, we compare the main flow paths and the connectivity across the different pore sizes in the modeled and experimental fluid distributions. These essential topology characteristics matched well for drainage simulations, but not for imbibition. This suggests that the pore-filling rules in the network model we used need to be improved to make reliable predictions of imbibition. The presented analysis illustrates the potential of our methodology to systematically and robustly test two-phase flow models to aid in model development and calibration.
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X-ray microtomography (micro-CT) provides a nondestructive way for estimating rock properties such as relative permeability. Relative permeability is computed on the fluid distributions generated on three dimensional images of the pore structure of a rock. However, it is difficult to numerically reproduce actual fluid distributions at the pore scale, particularly for a mixed-wet rock. Recent advances in imaging technologies have made it possible to directly resolve a large field of view for arbitrary wetting conditions. Herein, the objective of this study is to evaluate relative permeability computations on imaged fluid distributions under water-wet and mixed-wet conditions. By simultaneously injecting oil and brine on a Bentheimer sandstone before and after wettability alteration, imaged fluid distributions are obtained under steady state conditions. Then relative permeability computations performed on imaged fluid distribution are compared with experimental data obtained on the same rock. We find that relative permeabilities computed directly from imaged fluid distributions show agreement with experimental data in water-wet rock while for mixed-wet rock, the imaged connected pathways provided a poor estimate of relative permeability. Analysis of imaged fluid distributions and connectivity demonstrates that under mixed-wet conditions, increased dynamic connectivity and ganglion dynamics result in non-equilibrium effects at the fluid-fluid interface. These effects result in more energy dissipation during fractional flow in mixed-wet systems and thus lower effective permeability than water-wet rock at the same saturation.
Published in Petroleum Transactions, AIME, Vol. 216, 1959, pages 156–162.Paper presented at Fall Meeting of Los Angeles Basin Section in Los Angeles, Calif., Oct. 16–17, 1958. Abstract A test is described in which the wettability of porous rock is measured as a function of the displacement properties of the rock-water-oil system. Four displacement operations are carried out:spontaneous displacement of water by oil,forced displacement of water by oil in the same system using a centrifuging procedure,spontaneous displacement of oil by water, andforced displacement of oil by water. Ratios of the spontaneous displacement volumes to the total displacement volumes are used as wettability indices.Cores having clean mineral surfaces (strongly preferentially water-wet) show displacement-by-water ratios approaching 1.00 and displacement-by-oil ratios of zero. Cores which are strongly preferentially oil-wet give the reverse results. Neutral wettability cores show zero values for both ratios. Fresh cores from different oil reservoirs have shown wettabilities in this test covering almost the complete range of the test. However, most of the fresh California cores tested were slightly preferentially water-wet. The changes in core wettabilities, as indicated by this test, resulting from various core handling procedures were observed. In some cases the wettabilities of fresh cores were changed by drying or by extracting with toluene or dioxane; in other cases they were not changed. Contact of cores with filtrates from water-base drilling muds caused little change in wettability while contact with filtrates from oil-base muds decreased the preference of the cores for water. Using this test to evaluate wettability, a study was made of the correlation of wettability with waterflood oil recovery for outcrop Ohio sandstone and for Alundum. Results indicate that no single correlation between these factors applies to different porous rock systems. It is thought that differences in pore geometry result in differences in this correlation.
High-resolution x-ray imaging was used in combination with differential pressure measurements to measure relative permeability and capillary pressure simultaneously during a steady-state waterflood experiment on a sample of Bentheimer sandstone 51.6 mm long and 6.1 mm in diameter. After prolonged contact with crude oil to alter the surface wettability, a refined oil and formation brine were injected through the sample at a fixed total flow rate but in a sequence of increasing brine fractional flows. When the pressure across the system stabilized, x-ray tomographic images were taken. The images were used to compute saturation, interfacial area, curvature, and contact angle. From this information relative permeability and capillary pressure were determined as functions of saturation. We compare our results with a previously published experiment under water-wet conditions. The oil relative permeability was lower than in the water-wet case, although a smaller residual oil saturation, of approximately 0.11, was obtained, since the oil remained connected in layers in the altered wettability rock. The capillary pressure was slightly negative and 10 times smaller in magnitude than for the water-wet rock, and approximately constant over a wide range of intermediate saturation. The oil-brine interfacial area was also largely constant in this saturation range. The measured static contact angles had an average of 80∘ with a standard deviation of 17∘. We observed that the oil-brine interfaces were not flat, as may be expected for a very low mean curvature, but had two approximately equal, but opposite, curvatures in orthogonal directions. These interfaces were approximately minimal surfaces, which implies well-connected phases. Saddle-shaped menisci swept through the pore space at a constant capillary pressure and with an almost fixed area, removing most of the oil.