1
Wettability Alteration and Imbibition Effects in
Steam Recovery from Matrix Blocks in
Fractured Reservoirs
SIYAVASH MOTEALLEH, BERT-RIK DE ZWART AND HANS BRUINING
DIETZ LABORATORY, CENTRE OF TECHNICAL GEOSCIENCE
DELFT UNIVERSITY OF TECHNOLOGY
DELFT, THE NETHERLANDS
Abstract
Imbibition in matrix blocks is one of the most important mechanisms for oil recovery from
fractured reservoirs. However, imbibition is impeded if the matrix blocks are oil-wet. The
alteration of wetting from oil-wet to water-wet enhances the recovery. Contact angle
measurements show that steam (high temperature) alters the wetting properties. Therefore steam
injection has been suggested as an alternative for water drive. Still, the mechanism of thermally
induced wetting changes remains unclear. Moreover a change in contact angle only indicates the
possibility of imbibition. An imbibition test involving steam and condensed water will provide
more direct evidence of the usefulness of steam drive recovery.
Therefore we have conducted steam experiments at 20 bars (218 oC) in tubes filled with
carbonate or sand samples. In a number of cases the carbonate samples were made oil-wet by
ageing crude oil for 15 days. The porous media were filled with dead oil or with live oil. The
tube was closed at one end and injection and production occurred from the same side. At the
injection side one used either electrical heating or steam heating. This configuration is
considered representative of a matrix block facing a fracture through which steam is blown. The
experiments in the water-wet system show that an important contribution to the recovery of oil
comes from imbibition. Experiments in the oil-wet system show a smaller but significant
contribution due to imbibition, showing that the high temperature was able to change the wetting
properties in the porous medium.
Introduction
Water drive recovery from fractured reservoirs (e.g. carbonate reservoirs) is low, typically a few
percent, if only oil from the fractures can be recovered8. Therefore there is much interest in
methods that can stimulate recovery from the matrix. Reis9 gives an overview of possible
mechanisms that contribute to steam drive recovery of oil in fractured reservoirs. He concludes
that thermal expansion is the main mechanism for additional oil recovery with respect to water
drive. Solution gas drive is considered as a less important mechanism. However, thermal
methods can also enhance imbibition because they are able to decrease the viscosity. It has also
been suggested that heat can alter the wettability from oil-wet to water-wet1,2,5.
Evidence that steam is indeed able to alter the wettability in carbonates from oil to water-wet is
found in contact angle measurements7,11. All these experiments were conducted below 100 oC.
We did not find literature on contact angle measurements in the crude oil-brine- CaCO3 system
at elevated temperatures (> 100 oC). Al-Hadhrami and Blunt1 theoretically investigated the effect
of wettability alteration on oil recovery in carbonate rocks. They mention wetting alteration by
the application of steam or hot water as a mechanism to enhance imbibition.
13th European Symposium on Improved Oil Recovery — Budapest, Hungary, 25 - 27 April 2005
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A few tube experiments mimicking fractured reservoir behavior have been reported in the
literature. Sumnu, et al.10 reported experiments on a sand stone core filled with water, where a
spacing between the core holder and the core represented the fracture. The experiments were
used to validate numerical modeling. Numerical simulation for oil filled cores showed that
imbibition was the most important mechanism. Tang and Kovscek5,6 conducted isothermal
counter-current imbibition experiments at elevated temperatures. They attribute wettability
alteration in sandstone reservoirs to fines production.
However, in spite of a vast literature on wetting alteration, the mechanism for thermally induced
wetting changes remains unclear5. Also there is no clear relation between contact angle
measurements and imbibition. Indeed imbibition requires a change in wettability in a complex
geometric configuration, whereas in contact angle measurements the configuration is much
simpler. Hence an imbibition test involving steam and condensed water can provide more direct
evidence of wetting alteration in steam drive recovery.
Experiments
In total 25 tube experiments were carried out to investigate the mechanisms contributing to
steam drive recovery from matrix blocks. More specifically we want to determine the relative
importance of thermal expansion, thermally induced solution gas drive and thermally enhanced
imbibition (wettability effects). The distinguishing feature of the experiments is that injection
and production occur at the same side of the tube.
Injection and production
Steam entered the tube and produced fluids left the tube at the same side. As an alternative a
heating element was used to heat the injection side of the tube to 218-225 oC. In this case we
used either only heating or also bypassed water in front of the injection/production side.
Produced fluids were cooled by a heat exchanger and liquids were collected in a graded cylinder.
Reading errors of the graded cylinder are estimated at 5% of aliquots of 10 ml in the small
cylinder and less than 1% in the large cylinder. Gases were measured by a wet gas meter. The
pressure regulator maintained a pressure of 20 bars, monitored by a pressure transducer, during
the experiment.
Porous medium properties
The sand used originated from the Maas river bedding and has an average grain diameter of 90
m. The porosity of the sand has been determined by weighing and was in all cases about .
The Carman-Kozeny relation estimates a sand permeability of 9.5 Darcy. We crushed carbonate
rock to produce carbonate grains with size range between 100-200 m diameter. For a water-wet
carbonate system we ran the experiments with carbonate outcrop samples obtained from Egypt
and Mexico. The oil-wet experiment used a carbonate sample from the Qishn outcrop, which is
representative of the Shu'aiba reservoir.
Sample preparation
First the tube was filled with crushed carbonate or sand. The sample was saturated with oil at
connate water saturation. The tube (ID = 0.04 m and length is 0.26 or 0.15 m) was evacuated for
48 hours. Then the tube was mounted in a vertical position and one side of the tube was
connected via tubing to a water reservoir. Due to the vacuum created the whole pore space was
filled with air free (double distilled) water and the porosity could be measured. Then the tube
was mounted in the setup and flushed with two or three pore volumes of oil. For oil-wet
experiments the sample was allowed to age for 15 days. Connate water saturations varied
between 0.2 and 0.4. After each experiment the grain pack was cleaned by flushing steam
through the core for 12 hours.
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Oil properties
The oil used consists either of pure hexadecane, live oil (hexadecane + methane) or crude oil
from Qarn Alam (Oman) (oil-wet system). For the live oil experiments we mixed 175 ml
hexadecane with 2014 ml of methane in the two ISCO pumps. The mixture was pumped from
one pump to the other at 40 bar for 24 hours. The density of hexadecane (285 K) = 770 [kg/m3]
and the temperature dependent viscosity [Pa.s] is described by ln  = 1803.27/T - 11.8519. For
crude oil the density at 285 K is 866 [kg/m3] and the temperature dependent viscosity [Pa.s] is
described by ln  = -8.589 + 377.7/(T-200.9). The crude oil contains 0.84 gr asphaltene / 100 ml
oil and the acid number is 0.84 mg KOH/g.
Experimental results
The experiments discussed below only differ with respect to the experimental parameters that
were varied in our study; method of heating (steam or electrical); type of oil (live oil, dead oil or
crude oil); type of medium (carbonates or sand); circulation of water in the fracture and wetting
of the porous medium (oil-wet or water-wet).
Sand experiments
First we discuss experiments performed with sand (see Figure 1) in a 0.26 m long tube. In these
experiments we used both dead and live oil and also both heating methods. We observed the
lowest recovery with electric heating and dead oil. Electric heating with live oil gave a higher
recovery. However with steam we found much larger recovery. All but one of the steam
experiments were carried out using live oil. The dead oil steam experiment produced about the
same amount of oil as the live oil experiments. The steam experiments show a large recovery
variation. This recovery is not correlated to the amount of steam used in the experiments. The
recovery variation possibly depends on the pressure fluctuations during the experiments. The oil
production (Np) of the six live oil experiments can be expressed in terms of the standard
deviation of pressure (s) during the live oil experiments as Np = 0.20 ± 0.29 + (2.64 ± 1.24)s
[ml/oC].
Water-wet versus oil-wet systems
To investigate the importance of wetting on imbibition processes in the matrix we used crushed
carbonate and sand samples in water-wet and oil-wet conditions. Figure 2 plots the cumulative oil
production versus the average temperature (oC) for experiments at water-wet conditions4.
A first observation from Figure 2 is that experiments performed under identical conditions show a
good reproducibility. Also all experiments reached a steady state temperature profile due to the
balance between heating at the injection/ production side and heat losses from the reactor tube.
After reaching a steady state temperature, the experiments were continued to observe extra oil
recovery from the samples. In experiments HW_c1 and HW_c2 water, which were heated to 225
degrees, water was circulated through the injection/production side of the tube. The production
only increased very slowly with increasing average temperature. A steady state average
temperature was attained at 170 oC. The experiment was continued during steady state
temperature conditions for more than one day during which a considerable amount of oil was
produced. In contrast, the oil production for the steam experiment (steam_c) increased more
steadily before it reached a steady state temperature profile. The experiment EH-c concerned an
experiment where we only used electrical heating without circulating water. We observed a
steady increase of cumulative production as the average temperature increased. Finally, for
reasons of comparison with Figure 1 we show three equivalent experiments EH-s,1,2,3 using
sand and electrical heating without circulating water. Pressure fluctuations in all these
experiments were small (<0.5 bar).
13th European Symposium on Improved Oil Recovery — Budapest, Hungary, 25 - 27 April 2005
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100
steam experiments
90
oil production (ml)
80
70
60
50
dead oil
40
E- heating
life oil
30
20
E- heating
dead oil
10
0
0
50
100
150
average temperature oC
Figure 1. Experiments in 26 cm tube with a pore volume of 131 ml. We distinguish experiments with
steam (all live oil except the one indicated (dead oil)) and electric heating experiments with live and with
dead oil.
Figure 2. Oil production versus average temperature for selected experiments with carbonates and sand
for water-wet conditions in the 15 cm tube (PV 85 ml). The indication is as follows: steam-c means
experiment circulating steam with the tube filled with crushed carbonate. HW-c1, HW-c2 are two
experiments circulating water heated electrically. EH-s1,2,3 are three sand experiments using electrical
heating without circulating water. EH-c is an experiment using electrical heating with crushed carbonate.
Figure 3 shows experiments carried out with oil-wet conditions. The pressure fluctuations of
these experiments were small (< 0.5 bar), except otherwise stated. In experiments
"HW_Crudeoil" and "EH 1,2,3" we did not age for 15 days, but replaced the (aged) oil used in
the previous experiment with fresh oil and performed the experiment the next day. In the steam
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experiment (Steam_oilwet) we observe a steady increase with temperature until the average
temperature reached its steady state value at 160 oC. During the next two hours an additional 5
ml of oil was produced. The pressure fluctuations in this experiment were very high (3.6 bar).
The experiments "HW_oilwet 1-4" show an almost linear increase with the average temperature
until the steady state temperature profile is attained.
Figure 3. Oil production versus average temperature for selected experiments with crushed carbonates
for oil-wet conditions. The indication is as follows: Steam_oil-wet means experiment circulating steam.
HW_oilwet1-4 and HW_Crude oil concern experiments circulating water heated electrically. EH 1,2,3
are three experiments using electrical heating without circulating water.
Figure 4. Comparison of experiments with oil-wet and water-wet carbonate cores plotted versus the
square root of time. The oil production for “Cold water circulation” shows only very small oil production
at the start of the experiment.
The average temperatures at steady state conditions varied between 165 – 170 oC, because
different experiments used slightly different electrical power. Experiments "HW_oilwet 1-3"
show an additional production of about 10 ml during steady state temperature conditions.
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Experiment "HW_oilwet 4" produced only an additional 5 ml. Experiment "HW_Crudeoil"
shows a higher oil production between 100 – 165 oC than experiments "HW_oilwet 1-4".
Experiment "HW_Crudeoil" exhibited pressure fluctuations of 2.1 bars. Finally in experiments
"EH 1,2,3" no water circulation was applied. The production is more or less linear with the
temperature.
Figure 4 plots the recoveries from the water-wet experiment HW_waterwet1 and the oil-wet
experiments HW_oilwet1-4 versus the square root of time. All experiments show initially a large
increase of the cumulative oil production followed by a slower production rate. The water-wet
experiment shows initially a smaller contribution, but eventually its cumulative production
exceeds the production from the oil-wet experiments. The experiment circulating cold water was
performed with a carbonate sample aged with crude oil for more than 15 days. This experiment
shows no oil production after an initial production of 1.4 ml.
Contact angle measurements
Contact angle measurements showed that “Qishn” outcrop carbonates (blocks of 0.7 × 2.5 × 2.5
cm3) made oil-wet using lauric acid became water-wet again when the temperature was raised
above 60 oC. A block exposed to crude oil was shown to exhibit oil-wet behavior (contact angle
137o) as opposed to the experiment where the same block was exposed to hexadecane, which
remained water-wet (~15o). The block exposed to crude oil remained oil-wet even after
immersing it in a water bath of 70 oC for five days. In the current setup heating to higher
temperatures was not feasible.
Discussion
First we discuss experiments performed with sand, shown in Figure 1. The experiments using
electrical heating of dead oil are expected to only show a contribution due to thermal expansion,
but it includes a contribution due to expansion of spuriously introduced trapped air. The
electrical heating experiments with live oil show an additional contribution due to solution gas
drive effects. In our experiment the (conducted) heating rate is larger than for normal porous
media, because it is dominated by the high thermal conductivity of the iron tube.
The much higher recovery shown in Figure 1 using steam heating can be attributed to imbibition
effects. The experiments show large variations in recovery. The single dead-oil experiment
shows about the same recovery as the recovery from the live oil experiments. It is plausible that
the large variations for the live-oil steam experiments can be correlated to the pressure
fluctuations. Further work on this subject has to be done.
We now turn to a comparison between sand and carbonate experiments. The sand experiments
EH_s1,2,3 and the carbonate experiment EH_c1, all for water-wet conditions, show about the
same behavior because the oil production mechanism is dominated by the thermal expansion of
the oil. The electrical heating experiments circulating water i.e. HW_c1, HW_c2 show initially
less production than the experiments without circulating water. Possibly this can be attributed to
trivial reasons e.g. dead volume effects. The production increase of HW_c1, HW_c2, after
attainment of the steady state temperature profile, is attributed to imbibition effects. There is no
clear reason why the imbibition effects in HW_c1, HW_c2 is so much delayed with respect to
the imbibition effects in the Steam_c experiment. Indeed the Steam_c experiment shows similar
behavior as the experiment with dead oil and steam heating shown in Figure 1.
Also thermal expansion and imbibition are the main contributors to the oil recovery in the crude
oil (oil-wet) experiments shown in Figure 3. The experiment HW_crude oil shows an early
imbibition effect. It is tempting to relate this behavior to the fact that this experiment was only
aged for 2 days as opposed to the experiments HW_oilwet1-4, which were aged for 15 days.
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However this behavior is not shown in the experiments with (water-wet) hexadecane
experiments shown in Figure 2. The experiments HW_oilwet1-4 show imbibition effects in spite
of aging for 15 days. From this it is concluded that hot water (225oC) is able to change the
wetting behavior of the carbonates, made oil-wet with crude oil. High temperatures are required
because the contact angle measurements for crude oil show no effect on wetting below 70oC.
The steam experiment shows a contribution of the imbibition much sooner than the water
circulation experiments. We have no explanation for this difference between steam experiments
and circulating hot-water experiments.
Figure 4 shows that the water-wet experiment HW_waterwet1 has a larger contribution due to
imbibition than the oil-wet experiments HW_oilwet1-4. In all curves two slopes are observed.
The first slope represents initial oil production due to thermal expansion. The second slope
represents imbibition effects and the slopes become proportional to the square root of time
within experimental error. This is further evidence that the recovery mechanism is imbibition.
However the slopes for the single water-wet experiment and the four oil-wet experiments are
different. Cumulative oil production3 is proportional to the square root of the dimensionless time
tD. For the oil-wet samples the slope is roughly one third of the slope in the water-wet samples.
This shows that the behavior of initially oil-wet samples is different from the totally water-wet
experiment.
The factor relating the time to the dimensionless time3 contains both viscosity effects and
relative permeability effects. If only viscosity effects would explain the difference in slopes in
Figure 4 we would only expect a ratio of about 1.02, which is far too low as can be seen in Figure
4. Another explanation could be a different relative permeability behavior of the water-wet
samples. However all results are obtained with Qishn outcrop samples, which should have
similar relative permeability behavior for the same wetting conditions. Hence the sample has
been converted from a completely oil-wet to a partially water-wet medium.
The fact that we observe such a contribution due to imbibition indicates that hot water (225 oC)
is able to gradually convert the sample to water-wet behavior. Experiment “Cold water
circulation” in Figure 4 shows that at room temperature no wetting alteration is induced. If the
initially oil-wet samples would remain oil-wet there can be no contribution to the recovery
during the period that the temperature remains stationary. Hence our experiments show
unambiguously that hot water can imbibe in an originally oil-wet carbonate sample. We
conclude that due to heating the wettability of the samples is changed. In the field the exposure
times are longer and hence the conversion to water-wetness can be expected to be more
effective.
Conclusions
1. Electrically heated experiments with dead oil give only a contribution due to thermal
expansion. Experiments with live oil show an additional contribution due to thermally
liberated solution gas.
2. For steam experiments a large additional contribution to oil production due to imbibition is
observed in both sand and carbonate samples.
3. Contact angle measurements at 70 oC, showed no effect of heat treatment on the carbonate
sample made oil-wet by crude oil. However, the same temperature is able to reverse the
wettability of a carbonate sample made oil-wet with lauric acid.
13th European Symposium on Improved Oil Recovery — Budapest, Hungary, 25 - 27 April 2005
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4. Hot water is able to gradually change the wetting of carbonate samples made oil-wet with
crude oil. All oil-wet experiments show a contribution due to imbibition. This contribution is,
however, smaller than for the water-wet samples.
Acknowledgement
We thank Shell(E&P) for financial support. We thank Wim Swinkels for providing outcrop
samples and Rien Faber, Dan Pribnow and Arnold de Vries for many discussions and useful
suggestions. Technical support was provided by Leo Vogt, Rudi Ephraim and Henk van Asten.
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