Bourbiaux, b. et al. 2016. experimental and numerical assessment of chemical enhanced oil recovery in oil wet naturally fractured reservoirs unlocked

Experimental and Numerical Assessment
of Chemical Enhanced Oil Recovery in
Oil-Wet Naturally Fractured Reservoirs
Bernard Bourbiaux, André Fourno, Quang-Long Nguyen, Françoise Norrant, Michel Robin, Elisabeth Rosenberg,
and Jean-François Argillier, IFP Energies Nouvelles
Summary
Among various ways to extend the lifetime of mature fields,
chemical enhanced-oil-recovery (EOR) processes have been sub-
ject of renewed interest in the recent years. Oil-wet fractured res-
ervoirs represent a real challenge for chemical EOR because the
matrix medium does not spontaneously imbibe the aqueous sol-
vent of chemical additives. The present paper deals with chemical
EOR by use of wettability modifiers (WMs).
The kinetics of spontaneous imbibition of chemical solutions
in oil-wet limestone plugs and mini-plugs was quantified thanks
to X-ray computed-tomography (CT) scanning and nuclear-
magnetic-resonance (NMR) measurements. Despite the small size
of samples and the slowness of experiments, accurate recovery
curves were inferred from in-situ fluid-saturation measurements.
Scale effects were found quite consistent between mini-plugs and
plugs. During a second experimental step, viscous drive condi-
tions were imposed between the end faces of a plug, to account
for the possibly significant contribution of fracture viscous drive
to matrix oil recovery.
The recovery kinetics and behavior, especially the occurrence
of countercurrent and cocurrent flow, are interpreted through the
analysis of modified forces in the presence of a diffusing or con-
vected WM that alters rock wettability and reduces water/oil
interfacial tension (IFT) to a lesser extent. This work calls for an
extensive modeling study to specify the conditions on chemical
additives and recovery-process implementation that optimize the
recovery kinetics.
Introduction
Carbonate reservoirs hold a large share of worldwide oil reserves,
maybe on the order of 60% (Akbar et al. 2000). Although Manri-
que et al. (2006) report very few field applications of chemical
EOR in carbonate reservoirs of the United States, surfactant injec-
tion seems to be a promising EOR strategy for multiple reasons
lying in the low capital expenditure required for already-water-
flooded mature fields, and in encouraging results obtained in sur-
factant pilot tests. The recovery potential from carbonate oil-wet
fractured reservoirs is underlying in Allan and Qing Sun (2003)
that shows a contrasted (bimodal) distribution of recovery factors
in typical porous fractured reservoirs, with maximum-frequency
recovery values of 10 to 20% and 30 to 40%.
The present paper tries to illuminate the enhanced imbibition
mechanisms taking place in the oil-wet matrix blocks of carbonate
fractured reservoirs, from the interpretation of carefully moni-
tored imbibition experiments on a realistic rock/fluid system.
One can find a review of major findings and unsolved ques-
tions regarding the chemical enhancement of water/oil spontane-
ous imbibition in natural porous media in Bourbiaux et al. (2014).
A summary of that review is given hereafter to set the framework
and objectives of the present paper.
Recovery Issues for Fractured Carbonate
Reservoirs
Studies from Treiber and Owens (1972), Chilingar and Yen
(1983), and Cuiec (1984) lead to the same conclusion that
approximately 90% of carbonate reservoir rocks are oil-wet, in-
termediate, or neutral. Such a wettability has multiple origins,
including the oil composition in asphaltenes and other compo-
nents such as resins and sulfur, the rock mineralogy, and the ionic
composition of the water phase, in particular, divalent ions (Cuiec
1984, 1986; Hirasaki and Zhang 2004; Zhang and Austad 2006;
Gupta and Mohanty 2008, among others). Obviously, these fac-
tors may be determinant for the implementation of an EOR
method changing the rock wettability by means of a specific
water-soluble additive. Unfortunately, no predictive wettability
model incorporating all these factors is available to date and
WMs have to be selected from direct measurements of wettability
on rock/fluids/additive systems.
The present study does not investigate the nature of rock/fluid
interactions driving the wettability of the studied outcrop lime-
stone. However, aging of the studied limestone in a crude oil was
checked to invariably establish an intermediate to slightly oil-wet
wettability, and, thus, to annihilate any significant capability of
that carbonate to imbibe the water phase spontaneously.
One can increase the oil recovery from nonwater-wet matrix
blocks by enhancing one or several of the three recovery
mechanisms:
• Capillary imbibition through the restoration of positive cap-
illary forces, thanks to a WM added to the injection water
• Viscous drive by increasing the pressure gradient in the frac-
ture network, with either a higher injection rate or a higher
viscosity of the injected fluid
• Buoyancy, which can give rise to water/oil gravity drainage
if the ratio between buoyancy and capillary forces (as
expressed by Bond number) is increased through the use of
an additive that reduces the water/oil IFT to very low values
However, the slowness of buoyancy mechanism and the low
impact of viscous drive in fractured reservoirs with a high frac-
ture-to-matrix permeability contrast leave capillarity as the sole
potential recovery mechanism if one can modify the rock wett-
ability and the matrix blocks are not too large (Bourbiaux 2009).
Hence, the use of WMs is subject of particular interest for
chemical EOR in nonwater-wet fractured reservoirs. To that
respect, a recent publication from Stoll et al. (2007) reports that
the imbibition of oil-wet chalk samples with WM is some 1,000
times slower than the imbibition of the same water-wet medium,
which raises real concern about the viability of that strategy of
wettability modification. Such a slow kinetics probably resulted
from the absence of any significant buoyancy forces and any vis-
cous drive to convey the chemical solution into the matrix; hence,
matrix wettability change was entirely conditioned or limited by
the slow rate of surfactant molecular diffusion. However, the
kinetics of WM-induced recovery remains an open question in
real reservoir situations involving gravity and viscous forces.
More precisely, the choice of an EOR strategy must realize the
optimal compromise between a rapid-recovery kinetics and a
high-ultimate recovery. The former objective would privilege
wettability reversal to restore high-intensity driving capillary
Copyright V
C 2016 Society of Petroleum Engineers
This paper (SPE 169140) was accepted for presentation at the SPE Improved Oil Recovery
Symposium, Tulsa, Oklahoma, USA, 12–16 April 2014, and revised for publication. Original
manuscript received for review 4 February 2015. Revised manuscript received for review 26
June 2015. Paper peer approved 9 September 2015.
J169140 DOI: 10.2118/169140-PA Date: 8-June-16 Stage: Page: 706 Total Pages: 14
ID: jaganm Time: 18:58 I Path: S:/J###/Vol00000/150113/Comp/APPFile/SA-J###150113
706 June 2016 SPE Journal

forces. The latter one would privilege drastic IFT reduction to
mobilize all the matrix oil, but by means of buoyancy forces that
time because capillary forces have then a negligible intensity
compared with unchanged buoyancy forces, as expressed by the
high value of the Bond number. Hence, the two strategies of wett-
ability reversal and IFT reduction considered separately satisfy
different objectives. One must find an optimum between these
two objectives to guarantee substantial recovery within a reasona-
ble time. That optimum goes through the careful selection of a
WM that does not reduce too much the IFT to restore driving cap-
illary forces of significant intensity. Chabert et al. (2010) showed
that a screening methodology on the basis of contact-angle meas-
urements and Amott/USBM tests in cores is helpful to find such
an optimum. The additive used in the present study was selected
with this methodology.
The assessment of any chemical-recovery strategy should also
consider the viscous drive exerted by the fluids circulating in the
fracture-network delimitating matrix blocks. Viscous-flow contri-
bution to fractured-reservoirs production has long been neglected
in laboratory and reservoir-simulation studies, as a consequence
of the high-permeability contrast between fracture network and
matrix medium that characterizes most fractured reservoirs. But a
recent experimental study on an array of matrix blocks from Naja-
fabadi et al. (2008) and the extensive mechanistic modeling study
from Abbasi-Asl et al. (2010) showed that the pressure gradient in
fractures could contribute greatly to the oil recovery from frac-
tured-reservoir matrix blocks and to the efficiency of a chemical-
recovery process in such reservoirs. The impact of viscous drive
on production kinetics is profitable mostly for a gravity-domi-
nated transfer under low-IFT conditions. For a capillarity-domi-
nated transfer (Bourbiaux and Kalaydjian 1988), the benefit of a
viscous drive may a priori be questionable because countercurrent
flows contribute significantly to matrix oil recovery at least on the
short-term. However, WMs do not restore very-high-intensity
capillary forces because of the unavoidable impact of additives on
IFT (although moderate); therefore, evaluating the fracture-flow
impact on matrix-blocks oil production is an advisable precaution
that was considered in the present study.
Regarding the choice of chemical agents changing the wett-
ability of carbonates, Hirasaki and Zhang (2004) and Seethepalli
et al. (2004) report the high-recovery performance of alkaline sol-
utions of dilute anionic surfactants, whereas Standnes et al.
(2002) report the use of nonionic or cationic surfactants. In alka-
line conditions, one cannot attribute the oil-recovery improvement
to the surfactant agent alone but also to the presence of the alkali
that makes the carbonate surface negatively charged at pH values
exceeding 9. Alkali and surfactants actually have a synergetic
impact on carbonate matrix oil recovery, inasmuch as the efficient
use of surfactants at an economic (i.e., low) concentration requires
limiting adsorption through the addition of an alkali, which may
also significantly alter the rock-surface wettability to certain crude
oils. However, the respective/mutual contributions of alkali and
surfactant to change wettability still need to be investigated fur-
ther. To this respect, Zhang et al. (2008) showed that, under lim-
ited buoyancy conditions, emulsification may contribute largely
to matrix oil recovery in the presence of some surfactants.
The objective of the present work is not focused on the selec-
tion of an optimal formulation but nevertheless took into consid-
eration the advantages offered by the use of a WM in alkaline
conditions. Therefore, the preselected WM used for this work
was always used in alkaline conditions (0.094 M Na2CO3), to
optimize recovery conditions a priori. The selection of that addi-
tive was performed with the methodology described by Chabert
et al. (2010).
Experimental Methodology
The complexity of coupled flow and physicochemical mecha-
nisms of chemical recovery justifies the realization of well-docu-
mented experiments in which the involved physical mechanisms
or parameters are as few as possible. Regarding matrix/fracture
transfers, the boundary conditions applied on the block determine
the penetration of fluids and/or chemical agents into the matrix by
means of countercurrent flows and/or cocurrent flows (Bourbiaux
and Kalaydjian 1990). For this work, we searched for a compro-
mise between the necessity to perform “simple” experiments
involving well-defined flow-exchange mechanisms while incorpo-
rating the essential physics of chemical transfer taking place in
the reservoir. That concern led to the choice of a countercurrent
flow configuration and of a cocurrent-driven flow configuration.
With a 3D countercurrent flow configuration (Fig. 1, left side),
3D imbibition tests were performed on different mini-plugs
(0.95 cm in diameter and 2.0 cm in length), with average core sat-
uration measured at various time intervals, thanks to an NMR
method (Fig. 1, right side).
With the experimental device shown in Fig. 2, a sequence of
spontaneous, then pressure-driven, imbibition tests, described
more in detail later on, was carried out during five to six months
on a larger plug, 5.9 cm in length and 4 cm in diameter, with a
monitoring of local saturation evolution at each stage.
B1
B0
Magnet
Cooling
system
Signal
Acquis.
Magnet
NMR probe
Amplitude
Mini-plug
immersed in
chemical solution
3D Imbibition
Fig. 1—The 3D imbibition experiments on mini-plugs.
June 2016 SPE Journal 707

Mini-plugs make it possible to perform numerous tests during
a short period of time, whereas tests on plugs with saturation mon-
itoring are devoted to the detailed analysis of recovery mecha-
nisms. The reproducibility of spontaneous imbibition at plug and
mini-plug scales was checked from a preliminary, incomplete test
on another plug and from the reiteration of one of the tests on
mini-plugs. The rock/fluids/additives system was the same for all
tests, except for a few differences specified in the following.
Experiments were performed at room temperature and atmos-
pheric pressure.
Porous Medium. All experiments were performed on the same
outcrop limestone supplied from Lavoux quarry in the Poitou
region on the border of the Paris sedimentary basin. That Middle
Jurassic carbonate was deposited in a low-depth platform environ-
ment. The complex multistage evolution of the rock with geologi-
cal time led to various petrophysical facies and properties of the
present rock. Lavoux-limestone pore distribution is composed of
two main pore classes characterized by a ratio of approximately
30 between their respective average pore sizes (Tabary et al.
2009). To avoid disparity between studied samples, all plugs and
mini-plugs were cored in two very similar blocks.
Table 1 gives the dimensions and average petrophysical char-
acteristics of mini-plugs and plugs. Contrary to plugs, the perme-
ability of mini-plugs was not measured directly, but a value in the
order of 100 md was inferred from the processing of mercury-
injection data on a mini-plug from the same block. Plugs and
mini-plugs properties are very close, if we consider the usual dis-
parity of properties for that limestone that has a permeability that
may differ by a factor of 10.
One can find adsorption data referring to this limestone in
Tabary et al. (2009). The order of magnitude of adsorption
capacity is 1.0 mg/g. One should consider that value as an esti-
mate because measurements were performed on crushed sam-
ples and for a surfactant other than the one used in the present
study.
Fluids and Additives. Phases’ characteristics and additives’ con-
centrations are given in Table 2. The composition of the water
phase was simple, without any particular solutes, except for the
presence of potassium iodide (KI) to enhance X-ray-absorption
contrast, of some alkali (Na2CO3) and the preselected WM.
An irreducible water saturation (Swi) was established within all
samples with a centrifuge method. Swi values range from 0.08 to
0.14, with an average value of 0.10 for the mini-plugs. The aver-
age Swi value was 0.13 for the plugs.
Because they were water-wet in the beginning, samples at ini-
tial water saturation were aged in the presence of a crude oil
(characteristics in Table 2) to annihilate their capacity to sponta-
neously imbibe water. Aging was performed at 30 bar and 70
C
during 3 weeks. Then, the crude oil was miscibly displaced by do-
decane for the imbibition tests on plugs, whereas it was kept in
place for the imbibition tests on mini-plugs. No specific reason
motivated the use of these two different oils, except that the two
sets of experiments were designed independently from one
another without any initial purpose of comparison.
To end with, the efficiency of the aging process to annihilate
water wettability was checked on Plug P0 with the device shown
in Fig. 2. To that end, before being replaced by the full chemical
formulation, the aqueous solution, without neither WM nor
Na2CO3, was flowed along the left end-face during several days.
No oil was recovered, and no water was found to penetrate
the plug.
All imbibition tests were performed with a chemical formula-
tion of brine containing 10 g/L of alkali (Na2CO3) and fairly high
concentrations of the preselected WM, that is 0.5 wt% for the
main tests analyzed in this paper. Such WM concentrations were
significantly higher than the critical micelle concentration (CMC)
of that additive; hence, IFT was constant whatever the concentra-
tion of WM when present. WM concentrations were also higher
than the dilute concentration values sometimes reported in the lit-
erature. Actually, at that research stage, our objective was to
emphasize the effects of wettability change on fluid transfers for
analysis and modeling purposes, and not to optimize the
Table 1—Size and petrophysical characteristics of mini-plugs and plugs (*: Indirect permeability
determination for mini-plugs).
Dodecane
(+Swi)
Pump
Surfactant alkaline solution circulating
along a single end-face
X-ray CT
scanning
Laterally coated
porous medium
X
Closed end-face with
oil-filled dead volume
Countercurrent
oil production
Fig. 2—Imbibition experimental device for plugs—device is shown as used for the spontaneous-imbibition stage of the test, with
downstream face (on the right) that is closed (see Fig. 3 for the pressure-driven stage of the test).

consumption of additive, which, of course, one has to consider at
the field-implementation stage.
3D Imbibition of Mini-Plugs (NMR). Mini-plugs were immersed
in vertical position in the aqueous solution of additive during a pe-
riod of 2 to 3 weeks. At given times, distributed over that period,
samples were removed from the imbibition cell and introduced
within a small NMR device for measuring their global saturation
by a method of proton relaxation. The method was made quite
accurate, thanks to the use of “deuterated” water, thus making
possible assigning the amplitude of relaxation signal to the crude
oil phase alone. It is noteworthy to indicate that the resolution of
the NMR-measurement method as implemented is as low as
0.005 cm3
of oil, which corresponds to a saturation of 1 to 2% of
the mini-plugs pore volume (PV) that is only 0.35 cm3
. Actually,
consistent and fairly smooth evolutions of oil recovery were
obtained for all mini-plugs (see next section).
1D Sequential Imbibition of a Horizontal Plug (With X-Ray
CT). Two cylindrical plugs, 5.9 cm in length and 4 cm in diame-
ter, were used for 1D imbibition tests. They were set in a horizon-
tal position, and a confinement pressure was permanently applied
on their lateral cylindrical face by means of an elastomer sheath.
The first plug was used for a preliminary test that was performed
to tune procedures and also to check the reproducibility of the
spontaneous-imbibition behavior by comparison with the first
stage of the sequential test on the second plug. That sequential
test is actually the main test of interest that is detailed hereafter.
As illustrated by Fig. 2, the first stage of the main test con-
sisted of a pure countercurrent imbibition by one end-face, along
which the brine solution of additives was flowing from starting
time of imbibition onward. The aqueous solution circulates along
a small spiral channel in close contact with one end-face of the
porous medium so that the imbibing phase remains in contact
with the whole end-face area all through the imbibition period,
whereas the other end-face remains closed, with a dead volume
filled with oil to keep the same capillary condition at the end of
the plug as that obtained at the end of the core-saturation process.
That initial countercurrent imbibition stage, which was slow,
was not pursued until the oil production was completed, but was,
however, long enough to be able to characterize the recovery pat-
tern with sufficient accuracy. P0 and P1 samples were thus sub-
jected to pure-countercurrent imbibition, respectively, during 15
days and 90 days.
Then, a second stage of imbibition of Plug P1 was undertaken,
during which we simulated experimentally the fracture-pressure
drop that water injection in the fracture network of a naturally-
fractured reservoir (NFR) might generate. The methodology to
parameterize such flow conditions in the laboratory from available
fractured reservoir-characterization data is described in a recent
patent (Bourbiaux and Fourno 2013). Because of the small length
and the fairly high permeability of the plug sample, quite a small
pressure-drop value had to be imposed, even assuming moderate
fracture-to-matrix permeability ratios in the order of 10. For such
a permeability ratio, considering a typical water front velocity of
1 ft/D, the pressure gradient would actually be in the order of 5
mbar/m (i.e., approximately 0.3 mbar between the two ends of our
plug), that is equivalent to a water pressure load of 3 mm. Such a
low pressure drop would have been impossible to impose with
sufficient accuracy and stability during a long period of time. That
reason and the necessity to complete the whole test during a lim-
ited period of time led us to impose higher pressure values. Then,
two successive pressure-driven imbibition steps were performed.
The first step involved a differential pressure of 1.5 to 2.0 mbar
that was maintained during a period of 20 days by imposing a
waterload of 1.5 to 2.0 cm between the end face in contact with
water and the other end face that remained in contact with oil but
was now open to the ambient atmosphere, as illustrated by Fig. 3.
During the last step, the waterload was increased up to 5 cm (pres-
sure drop equal to 5.0 mbar, with an uncertainty of 0.5 mbar) and
maintained during a long period of 52 days. Indeed, such pres-
sure-gradient values, 5 to 15 times higher than expected ones in a
moderately fractured reservoir, are not representative of water-
flood conditions, but may well mimic the injection of a polymer
or foaming solution.
During all stages of spontaneous and pressure-driven imbibi-
tion, local saturation was measured within joined one-millimeter-
thick cross sections of the sample at various times selected
according to the kinetics of the imbibition process. Obviously, the
slowness of the whole process and joined CT scans gave the pos-
sibility to measure with a high accuracy the detailed 3D distribu-
tion of fluids within the plug, and its evolution with time and/or
imposed flow conditions.
Results and Discussion
Tests on mini-plugs and on plugs are analyzed separately and
jointly to elucidate the involved physical mechanisms of enhanced
recovery and to check the applicability of scaling rules to the
chemical EOR process under consideration.
Results on Mini-Plugs. Regarding mini-plugs experiments, oil-
recovery curves are superposed in Fig. 4a and Fig. 4b with,
respectively, linear and logarithmic time scales, to analyze the re-
covery behavior both on the short term and the long term. The oil
recovery increases with the concentration of WM, from 14% of
initial oil in place (IOIP) in the absence of WM (alkaline water
alone) to 42% IOIP for a 1-wt% concentration of WM. If we focus
on the “net” additional recovery caused by the presence of WM,
we obtain incremental recovery values ranging from 7 to 29%
IOIP in the presence of 0.1, 0.5, and 1 wt% of WM in alkaline
Alkali (Na2CO3)
Concentration (g/L)
Table 2—Fluids and additives (*: Aqueous phase is a deuterium water for tests on mini-plugs).

conditions. One can make a few observations to elucidate the
observed evolution of enhanced recovery with concentration.
First, a very similar kinetic trend is observed for the tests with
additives. However, the trend of alkaline water-imbibition Curve
MP0 (without WM) differs from that observed for the three other
tests in the presence of WM. MP0 curve shows a fast initial imbi-
bition phase followed by a very much-attenuated imbibition
phase. That initial imbibition capacity might result from an inter-
mediate or neutral wettability state of the mini-plug(s) rather than
a strictly oil-wet state. Actually, numerous other experimental
studies carried out with that rock/fluid system systematically
revealed such a neutral or intermediate wettability although natu-
ral-imbibition capacity was most often very close to zero. A
“blank” imbibition test performed with a 20-g/L NaCl confirmed
the latter assumption because it led to a similar oil recovery, of
13% IOIP. Hence, the spontaneous imbibition of those WM-free
solutions is mostly related to some remanent water wettability af-
ter aging. Under this assumption, the faster imbibition kinetics of
Test MP0 compared with other test results from the higher inten-
sity of capillary forces for WM-free solutions because the water/
oil IFT of a WM-free solution is close to seven times higher than
that of WM solutions. The volume of imbibed WM-free solution
is, however, limited, whereas in the presence of WM, it increases
with time because of a gradual wettability alteration.
A representation of recovery as a function of the square root of
time in Fig. 5 clearly indicates that one can assimilate WM-
enhanced recovery to a diffusion process. The kinetics of that pro-
cess increases with WM concentration as shown by curves’
slopes. That behavior is not surprising if one refers to the analysis
of previous experiments of that kind (Stoll et al. 2007). However,
if we assume that rock-surface wettability change results essen-
tially from interactions with WM molecules and not micelles,
then the fact that recovery differs very much with WM concentra-
tion is not expected because the tested values of WM concentra-
tion are much higher than the CMC of that WM. These
differences were found to result from the limited volume of
imbibing chemical solution around the mini-plug, which was not
renewed during imbibition. To investigate that point, Tests MP1
and MP2 were then reiterated on two other mini-plugs with a vol-
ume of chemical solution that was approximately 20 times larger
than the one used for the initial MP1 and MP2 tests, and imbibi-
tion was pursued during one or two months instead of 2 to 3
weeks for the initial Tests MP1 and MP2. These reproducibility
tests are instructive on several aspects. First, a very good reprodu-
cibility of the first 2 to 3 weeks of imbibition is observed (Fig.
4a). The imbibition process takes more time and leads to a higher
recovery for Tests MP1bis and MP2bis (Fig. 4b) than for Tests
MP1 and MP2. Interpretation is that the chemical-concentration
gradient vanished during Test MP1, and during Test MP2, to a
lesser extent, because of a too-small volume of solution. Taking
into account those effects, the ultimate recovery to be reached
appears to be in the same order, between 40 and 50% of the IOIP,
0
5
10
15
20
25
30
35
40
45
50
0 100 200 300 400 500 600 700
Oil
Recovery
(%
IOIP)
Time (hours)
(a)
MP3: 10 g/L Na2CO3 + 1 wt% WM
MP2 bis: 10 g/L Na2CO3 + 0.5 wt% WM
MP2: 10 g/L Na2CO3 + 0.5 wt% WM
MP1: 10 g/L Na2CO3 + 0.1 wt% WM
MP0: 10 g/L Na2CO3
0
5
10
15
20
25
30
35
40
45
50
0.1 1.0 10.0 100.0 1,000.0
Oil
Recovery
(%
IOIP)
Time (hours)
(b)
MP3: 10 g/L Na2CO3 + 1 wt% WM
MP2: 10 g/L Na2CO3 + 0.5 wt% WM
MP1: 10 g/L Na2CO3 + 0.1 wt% WM
MP0: 10 g/L Na2CO3
Fig. 4—The 3D imbibition of mini-plugs by alkaline solutions of WM at different concentrations, with a (a) linear or (b) logarithmic
time scale.
Dodecane
(+Swi)
Pump
Surfactant alkaline solution circulating
along end-face
X-ray CT
scanning
Open end-face with
oil-filled dead volume
Cocurrent
oil production
Countercurrent
oil production
Differential waterload
H between end-faces
(H = H1 then H2)
Fig. 3—Imbibition experimental device for Plug P1— pressure-driven imbibition stages.

for the three-tested concentrations. Then, the positive effect of an
increased WM concentration mainly concerns the kinetics, and
most probably reflects the impact of the concentration gradient
between the surrounding solution at a given concentration and the
in-situ solution quasideprived of WM at the leading edge of its
progression into the porous medium because of adsorption.
Results on Plugs. As indicated previously, the first spontaneous
imbibition test on Plug P0 was incomplete, and consisted in the
spontaneous imbibition of an alkaline WM solution at 0.5 wt%
concentration of WM. The imbibition was pursued during only 15
days, instead of three months for the first stage of test on Plug P1.
This was, however, sufficient to check the significance and repro-
ducibility of results, as shown by Figs. 6a and 6b. Oil-recovery
values for plugs are all inferred from local saturation measure-
ments. The superposition of detailed recovery curves on Plugs P0
and P1 shows the satisfactory reproducibility of the imbibition
behavior, despite the small experimental artifacts that were identi-
fied during preliminary Test P0. Fig. 6b emphasizes the quality
and reliability of results by showing that the recovery kinetics dif-
ferences between Plugs P0 and P1 are insignificant if compared
with the differences observed between plugs and Mini-plug MP2
for the same concentration of additive.
A few saturation profiles measured along the two plugs at
comparable times are shown in Fig. 7. The invasion of the two
plugs by the chemical solution occurs in a very similar way, with
smooth water-oil fronts. The small saturation increase observed
ahead of the front during the preliminary Test P0 is probably the
consequence of a suspected failure in the confining device that
occurred during the test and that led to the decision to stop it. The
experimental device was modified to that respect before starting
Test P1.
The confidence on results justified pursuing the spontaneous
imbibition of Plug P1 during 3 months. Fig. 8 shows a gradual but
very slow imbibition of the chemical solution into the plug. The
12.8% of the initial oil in place (OIP) was recovered during these
three months. Saturation profiles are shown in Fig. 9 at selected
times of that first stage of the test (six first profiles). The 2D fluid
distribution in five 4-mm-spaced cross sections of the plug after 3
months of spontaneous imbibition are shown in Fig. 10. One can
make several observations. Three months are necessary for the
chemical solution to partly imbibe the first half of the plug. Satu-
ration profiles are very much tilted, progressing more or less par-
allel to one another. The gradual saturation increase all over the
imbibed half of the plug probably stems both from a very gradual
wettability modification of the porous medium, and from the
countercurrent flow of water and oil. Actually, countercurrent sat-
uration profiles measured in water-wet media show very rapid
increase of saturation near the imbibing end (Bourbiaux and
Kalaydjian 1990). However, the saturation sections shown in Fig.
10 also reveal a nonuniform saturation at any given distance from
the imbibing end-face. That nonuniformity of water saturation in
each cross section is seen both vertically and horizontally in each
cross section. In particular, the strong saturation gradient observed
in the vertical direction reveals an influence of buoyancy on the
imbibition process. That is, the denser chemical solution seems to
imbibe the bottom part of the plug whereas the oil phase seems to
be produced countercurrently in the upper part. The saturation
inhomogeneity along horizontal lines within cross sections looks
random and is probably driven by the local heterogeneities of the
rock. In addition to the peculiar mechanism of chemically
enhanced countercurrent imbibition, the presence of two pore
families in this carbonate may also be another reason for the very
gradual increase of saturation in any cross section of the plug dur-
ing the whole imbibition process.
During the two following “forced-imbibition” stages, a small
pressure drop was imposed with a waterload between the
“upstream” end face in contact with water and the “downstream”
end-face in contact with oil. The latter end face was open at
0
5
10
15
20
25
30
35
40
45
50
0 5 10 15 20 25 30 35 40
Oil
Recovery
(%
IOIP)
Square Root of Time (hours)
MP3: 10g/l Na2CO3+1 wt % WM
MP2 bis: 10g/l Na2CO3+0.5 wt % WM
MP2: 10g/l Na2CO3+0.5 wt % WM
MP1 bis: 10g/l Na2CO3+0.1 wt % WM
MP1: 10g/l Na2CO3+0.1 wt % WM
MP0: 10g/l Na2CO3
Fig. 5—The 3D imbibition of mini-plugs by three alkaline solu-
tions of WM at different concentrations, as a function of the
square root of time.
0.0
0.2
0.4
0.6
0.8
1.0
1.2
10 100 1,000
Recovered
Oil
Volume
(cm
3
)
Time (hours)
(a)
Plug P0
Plug P1
0
5
10
15
20
25
30
35
40
1 10 100 1,000 10,000
Oil
Recovery
(%
IOIP)
Time (hours)
(b)
Mini-plug MP2
Plug P0
Plug P1
Fig. 6—Comparison of spontaneous imbibition of alkaline 0.5 wt% WM solution into Plugs P0 and P1 [(a), left hand], and into plugs
and Mini-Plug MP2 [(b), right hand].

atmospheric pressure during those stages. The imposed waterload
had a strong impact on the mobilization of oil. Water saturation
increased in the already imbibed part of the plug, and the water/
oil front progression was accelerated, as clearly shown by Fig. 9.
For either stage of forced imbibition, one observes a transient pe-
riod of rapidly increasing imbibition (Figs. 8 and 9), then a period
of steady progression of the front at a higher speed. The first
forced-imbibition stage was, however, too short to be quantified
very much in detail; hence, the magnitude of the recovery step
observed for either of the two forced-imbibition stages cannot be
interpreted quantitatively. The test was stopped after 162 days, af-
ter breakthrough of the chemical solution at the downstream end-
face of the plug. At that time, the oil recovery, although close to
80% IOIP in average value (78.3% IOIP), was not yet completed
because the oil-saturation profile along the plug was still showing
a difference of more than 20% in value between the upstream
end-face (So ¼ 90% PV) and the downstream end-face (So less
than 70% PV). The amount of oil finally remaining in place in the
plug was determined by an NMR method after dismantling the de-
vice. Considering all measurements-calibration uncertainties, we
noted that the final recovery value obtained through that method,
84% IOIP, was consistent with the value inferred from the final
saturation profile measured by X-ray CT.
An unexpected observation was made during those forced-imbi-
bition stages. Actually, no oil was produced by the downstream
end-face as long as the aqueous phase did not break through that
downstream end-face. That is, oil production remained driven by a
countercurrent mechanism, as during the initial spontaneous imbi-
bition stage with closed “downstream” end-face. Actually, the satu-
ration cross sections measured after 150 days (Fig. 11) clearly
0.4
0
43
124
355
Plug P0 (time in hours)
0
49
144
355
Plug P1 (time in hours)
0.35
0.3
0.25
0.2
0.15
0.1
0.05
0
0 10 20 30 40 50 60
Distance From Open End-face (mm)
0 10 20 30 40 50 60
Distance From Open End-face (mm)
Water
Saturation
0.4
0.35
0.3
0.25
0.2
0.15
0.1
0.05
0
Water
Saturation
Fig. 7—Saturation profiles measured during the spontaneous imbibition of alkaline 0.5 wt% WM solution into Plugs P0 (left hand)
and P1 (right hand).
0
10
20
30
40
50
60
70
80
90
0 20 40 60 80 100 120 140 160 180
Oil
Recovery
(%
IOIP)
Time (days)
Plug P1
1st stage
(spontaneous)
3rd stage
(P-driven,
5 mbar)
2nd stage
(P-driven,
1,7 mbar)
Water
breakthrough
at downstream
end-face
Fig. 8—Evolution of the oil recovery during all the stages of
imbibition (spontaneous, then pressure-driven) of Plug P1.
Section Number (Distance From Open End-face) (mm)
0
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
10
End Sp. Imb. -- ΔP1
E
n
d
Δ
P
1
-
-

Δ
P
2
20 30 40 50 60
0
Plug P1 (time in days)
5
27
90
93
110
120
140
154.6
155.9
161.7
2
11
67
92
96
112
130
150
155.0
157.7
Water
Saturation
Fig. 9—Water-saturation profiles measured during all the stages of imbibition (spontaneous, then pressure-driven) of Plug P1.

indicate that imbibition remains incomplete all over the plug just
before water breakthrough. After the chemical solution reached the
downstream end-face (i.e., after 155 days), fluids started being pro-
duced by that end-face while water saturation went on increasing
all over the plug, as shown by the last profiles of Fig. 9. That
downstream fluid production required to more than double the tan-
gential circulation rate along the upstream end-face, which was
1 cm3
/hr before breakthrough, to maintain the prescribed waterload
between the upstream and downstream end-faces. That unexpected
flow behavior is interpreted as the result of the chemically
enhanced imbibition process. Actually, countercurrent flows take
place in the wettability-modified (i.e., water-wet) zone, whereas
cocurrent imbibition from upstream to downstream end-faces is
inhibited by the absence of driving capillary forces in the down-
stream part of the plug remaining at irreducible water saturation.
Yet, that observation has to be explained further because one may
consider that the chemical solution changes the wettability at the
leading edge of the water-oil progressing front and should make
possible classical cocurrrent imbibition, inasmuch as the oil phase
can more easily flow in the downstream part of the plug than in the
upstream water-invaded part. A possible explanation then lies in
the adsorption of the WM by the rock, a phenomenon that impov-
erishes the solution all the more as it penetrates deeper into the ma-
trix. Hence, at the leading edge of the water-oil front, the solution
that is nearly chemically depleted can barely change the rock wett-
ability, thus keeping capillary pressures at a very low level there
contrary to what is achieved in the upstream part in which concen-
tration remains at a higher level through solution renewal from the
upstream end face. That interpretation is qualitatively sustained by
the low water-saturation values measured at the very leading edge
of the imbibing front. To end with, the previous observations and
interpretation need to be confirmed from additional tests with con-
trasted WM concentrations. Other factors, such as the initial non-
uniform saturation profile, may also, but to a lesser extent, have
influenced the enhanced imbibition process.
A representation of the oil recovery as a function of the square
root of time is shown in Fig. 12, separately for the spontaneous
imbibition stage of the test and for the two forced pressure-driven
stages. The evolution of recovery vs.
ffiffi
t
p
is clearly linear during
the spontaneous imbibition stage. The pressure drive imposed at
the beginning of the two subsequent stages of the test entails a
transient high increase of the oil-recovery rate, followed by a
steady progression of recovery that seems rather proportional to
the elapsed time (Fig. 8) than to
ffiffi
t
p
(Fig. 12), especially for the
last highest-pressure-driven stage of the test.
Scaling Chemically Enhanced Spontaneous
Imbibition
The scaling of spontaneous imbibition of water-wet media has
long been studied and shown to be satisfactorily predicted if that
transfer is driven by a single predominant mechanism, that may
be capillarity or buoyancy (Jacquin et al. 1985), generally capil-
larity for laboratory-scale experiments (Mattax and Kyte 1962).
The problem may seem more complex for nonwater-wet media in
the presence of a chemical solution. If a very-low-IFT (less than
0.01 mN/m, for instance) fluid system is implemented, the role of
buoyancy is emphasized because capillarity is quasiannihilated.
But in the presence of a WM, the problem needs to be examined
carefully. Actually, driving capillary forces are restored, but grad-
ually with time and nonuniformly in space contrary to buoyancy,
and also to a limited extent if the chemical agent also decreases
the water/oil IFT. Then, the whole transfer process cannot a priori
be properly scaled with a dimensionless time referring exclusively
to one of the two capillary or buoyancy mechanism. This was
extensively demonstrated by Babadagli (2001), who tried to scale
Fig. 10—Five 4-mm-spaced Sw cross sections of Plug P1 starting from open end face (left section), after 81 days (end of spontane-
ous imbibition stage), showing that the chemical solution imbibes very gradually, starting by the lower part of the plug set in hori-
zontal position. Oil is shown in dark blue, water in red.
Fig. 11—Five 12-mm-spaced Sw cross sections of Plug P1 starting from open end face (left section), after 150 days (near the end of
the second stage of forced imbibition), showing that imbibition remains incomplete, leaving flow paths for both phases as long as
water has not reached the downstream end face in contact in oil. Oil is shown in dark blue, water in red.
0
10
20
30
40
50
60
0 10 20 30 40 50
Oil
Recovery
During
Step
(%
IOIP)
Square Root of Step Duration Time in Hours
1st Step (Spont. Imb.) 2nd Step (DP1) 2nd Step (DP2)
Fig. 12—Oil-recovery curves from Plug P1 as a function of the
square root of time of the duration of each stage (i.e., spontane-
ous imbibition, first and second steps of forced imbibition).

multiple sets of brine/oil and surfactant-solution/oil experiments
on water-wet cores. In particular, this author observed that neither
a dimensionless time referring to capillarity (for brine/oil tests)
nor a dimensionless time referring to gravity (for surfactant solu-
tion-oil tests) was able to gather the recovery kinetics of counter-
current imbibition tests on a single curve. Joint contribution of
capillary forces and of gravity forces was invoked as a possible
origin of that difficulty. Actually, adopting a dimensionless time
referring to gravity for low-IFT countercurrent flows presents a
conceptual difficulty because gravity forces are also infinitesimal
at initial time for countercurrent flow-boundary conditions.
To confirm the acknowledged trends recalled previously and to
identify further the dominating recovery mechanisms, we tried to
scale the two Tests P1 and MP2 that were carried out with the same
fluid system (i.e., with the 0.5 wt% WM alkaline solution). The anal-
ysis is limited to the first spontaneous imbibition stage for Test P1.
In a first step, capillarity was assumed to be the driving mecha-
nism of Matrix oil production. We then adopted the generalized
expression of dimensionless time proposed by Ma et al. (1999):
tDc ¼
ffiffiffiffi
k
/
s
r
lm
t
L2
c
ð1Þ
or
tDc ¼
t
tcap
; ð2Þ
with t the measured real time and tcap a reference time with
respect to capillary forces expressed as
tcap ¼
lmL2
c
r
ffiffiffiffiffiffiffi
k=/
q ; ð3Þ
where / is the porosity, k the single-phase permeability, r the IFT
between the chemical aqueous solution and oil, and lm the fluid
viscosity taken equal to the geometrical mean of aqueous phase
and oil viscosities that is
ffiffiffiffiffiffiffiffiffiffi
lwlo
p
. Lc is a characteristic length that
takes into account the number and dimensions of open faces and
their distance to the no-flow boundary. For a cylindrical sample
imbibing by all faces (as mini-plugs), the expression of that char-
acteristic length (Ma et al. 1999) is
Lc ¼
LD
2
ffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi
2L2
þD2
p ; ð4Þ
with L the sample length and D its diameter.
Stoll et al. (2007) derived another expression of Lc:
Lc ¼
LD
2D þ 4L
: ð5Þ
For our mini-plugs, we determined a characteristic length value
equal to 0.32cm or to 0.19 cm, whether, respectively, either the Ma
et al. (1999) formula or the Stoll et al. (2007) formula is adopted.
For a cylindrical plug imbibing by a single end-face, Lc equals
plug length, that is L.
We used the same crude oil for aging plugs and mini-plugs,
but the crude oil was replaced by a refined oil (dodecane) for the
tests on plugs, whereas crude oil was left in place for the imbibi-
tion tests on mini-plugs. Hence, the scaling of mini-plugs and
plug results involved a change of characteristic length, and of oil
viscosity to a lesser extent.
Fig. 13 shows the scaling results of Tests P1 and MP2, with
the two Lc values from Ma et al. and Stoll et al. for Mini-plug
MP2. The ratio between plug and mini-plug times for a given oil
recovery is close to 100 if real times are considered, whereas, con-
sidering dimensionless times t/tcap, that ratio is close to 1, or 2 to
3, whether the Ma et al. (1999) or Stoll et al. (2007) formula is
used for Lc. After considering the impact of characteristic-length
definition on scaling, the different geometries of the two tests, and
the assumed internal homogeneity of samples, one can note that
scaling is satisfactory in a first approach. The scaling of chemical-
imbibition tests would, however, require further analysis to make
sure that the space- and time-dependent interfacial and wettability
properties involved in the process are properly taken into account
in that conventional scaling formula.
To try to ascertain that interpretation, we tested a scaling
with respect to a gravity-controlled production mechanism.
Actually, the saturation gradient observed in the vertical cross
sections of the plug seems to reveal a significant impact of buoy-
ancy on fluid distribution.
The following dimensionless time expression (Jacquin et al.
1985) was used:
tDg ¼
t
tg
; ð6Þ
with tg a reference time with respect to gravity forces expressed as
tg ¼
lmL2
g
DqgHk
; ð7Þ
. . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
0
5
10
15
20
25
30
35
40
1 10 100 1,000 10,000
Oil
Recovery
(%
IOIP)
Time (hours)
(a)
Mini-plug MP2
Plug P1
0
5
10
15
20
25
30
35
40
100 1,000 10,000 100,000 1,000,000
Oil
Recovery
(%
IOIP)
Dimensionless Time (t/tcap)
(b)
Plug P1
Mini-plug MP2 (Lc= 0.32 cm -
Ma et al. 1999)
Mini-plug MP2 (Lc= 0.19 cm -
Stoll et al. 2007)
Fig. 13—Comparison of the recovery kinetics measured on Mini-Plug MP2 and Plug P1 vs. real time [left hand, (a)] and scaled dimen-
sionless time [right hand, (b)]. Two formulas are used to determine the characteristic length referring to the 3D test on mini-plug.

where lm replaces lo in the original formula from Jacquin et al.
(1985) for the sake of consistency with previous tcap formula. H is
the sample dimension (height) in the vertical direction and Lg the
sample dimension (length) along the main flow direction. Then,
Lg equals L for both the vertical mini-plugs and the laterally
coated horizontal plugs. H coincides with L for mini-plugs but is
equal to D for the horizontal plugs.
Fig. 14 shows that this gravity-based scaling does not reduce
at all the recovery-kinetics gap between plug and mini-plug. That
is, despite the observed influence of buoyancy on fluid distribu-
tion, the recovery is essentially driven by a capillary mechanism
or an equivalent diffusion mechanism. Assuming capillarity
drives the production, the corresponding capillary pressures are
very low. Actually, whereas the half-recovery time of the aged
Mini-plug MP2 is 56 hours (Fig. 4), a nonaged water-wet mini-
plug is known to imbibe water within a few minutes, according to
available water-dodecane imbibition data measured on the same
Lavoux limestone. That is, the equivalent or characteristic capil-
lary pressure in the enhanced imbibition process under considera-
tion is three orders of magnitude lower than that of the original
water-wet rock/fluid system.
Numerical Modeling of Chemically Enhanced
Imbibition With WM
A generic macroscopic chemical model is proposed hereafter to
simulate the enhanced imbibition of nonwater-wet porous media
by a WM solution. That model simulates the coupling between a
supposed mechanism of wettability modification and multiphase
fluid transfer. The purpose is to demonstrate the possibility to sim-
ulate that chemical EOR process, even if to date, the involved
physics remains matter of investigation.
Indeed, the multiple physicochemical mechanisms responsible
for wettability modification are not yet fully established. First,
WMs do not always play a role on wettability alone, but may
interact with the in-situ-generated surface-active compounds that
are formed in the presence of reactive oils in alkaline conditions
(Trabelsi et al. 2011, 2012). Then, different mechanisms related
to the thermodynamic behavior of the oil-water-surfactant sys-
tems may explain the observed effects of WM on recovery, such
as water adsorption on the rock surface from reversed micelles in
the oil phase (Austad et al. 1998), or conversely, the solubilization
of oil into water-soluble surfactant micelles. The nature of electro-
lytes in presence also has a dramatic influence on rock-surface af-
finity for hydrophobic compounds (Zhang and Austad 2006).
Hence, chemical EOR simulators cannot incorporate that phys-
icochemical complexity and remain essentially empirical in their
approach, with the use of very simple physical models that link
local WM presence in the porous medium to wettability-depend-
ent properties. Two such models are based on an assumed
“coating” mechanism whereby the chemical agent adsorbs itself
on the oil-wet surface, and on an assumed “cleaning” mechanism
whereby naturally adsorbed organic compounds are eliminated
from the rock surface through a competition or association with
the chemical agent. Such models were implemented by Stukan
et al. (2012) with a molecular-dynamics-simulation approach.
Conventional Darcy-based macroscopic models from the petro-
leum industry simulate wettability-modification effects on recov-
ery by introducing capillary pressures and relative permeabilities
that are not only functions of the saturation but also of a WM-con-
centration variable. For instance, Pc and kr may vary as a function
of the adsorbed surfactant concentration (Delshad et al. 2006) or
of the contact angle correlated with the surfactant concentration
(Adibhatla et al. 2005; Kalaei et al. 2013).
Our simulator can model different chemical EOR methods—
namely, alkaline, surfactant, and polymer options including salts
effects (Douarche et al. 2011). A specific option was developed to
simulate both wettability and IFT changes when a WM is used
instead of a conventional surfactant with major impact on IFT.
The WM additive is assumed to be present in the aqueous phase
or adsorbed on the rock but not present in the oil phase. General-
ized Darcy’s law and Fick’s law are used to simulate WM transfer
between the cells of the numerical model. Two sets of relative
permeability and capillary pressure saturation-functions are
defined under initial wettability conditions and under modified
wettability conditions achieved in the presence of WM, assuming
no IFT change. That is, the set of kr and Pc curves has to be dupli-
cated as model input. In the general case of a WM that changes
both wettability and IFT, capillary pressures are IFT-dependent,
and the relative permeability curves, including shape and satura-
tion endpoints, are also functions of a capillary number Nc, which
varies with IFT. In that case, a two-stage interpolation of kr and
Pc, vs. wettability and vs. Nc, is applied. The main specific point
of WM modeling lies in the way to interpolate kr and Pc values
between the initial kr-Pc saturation-dependent curves and the
modified curves, as a function of WM concentration. Two physi-
cal suboptions are considered to interpolate kr and Pc vs. wettabil-
ity, the first one assuming a “coating” mechanism and the second
one that is based on a “cleaning” mechanism. A coating mecha-
nism is assumed for the present paper. The kr and Pc values at a
given water saturation are interpolated linearly between the values
at the initial wettability state and the values at the modified wett-
ability state, as a function of the normalized mass fraction of wett-
ability-altered solid. According to coating mechanism, that
fraction of altered rock is directly related to the aqueous-phase
concentration of WM, through a WM adsorption equilibrium that
is a Langmuir isotherm in the present version. The procedure for
modeling a cleaning mechanism does not substantially differ,
except for the type of equilibrium between the WM concentration
in solution and the fraction of wettability-altered solid.
The reported simulation results concern one mini-plug
experiment. The purpose is not to tune the parameters of the
above-described model to experimental data but to demonstrate
the possibility to simulate a WM-enhanced imbibition process of
nonwater-wet media, while underlining the necessity of defining
further involved parameters and mechanisms.
Test MP3 showing the highest EOR performance is selected. A
regular fine-grid 3D model is used with 3,321 cells. The mini-plug
is represented as a parallelepiped with a cross-section area equal to
the actual circular one, and is surrounded by high-porosity cells
that represent the imbibing solution of WM. A set of initial and
chemically modified capillary pressure curves was defined at best
from centrifuge data measured on aged nonwater-wet samples and
on chemically treated water-wet samples of Lavoux limestone.
Positive Pc data were defined further through the numerical match
of water-oil spontaneous imbibition data measured on a native
0
5
10
15
20
25
30
35
40
0.01 0.10 1.00 10.00 100.00
Oil
Recovery
(%
IOIP)
Dimensionless Time (t/tg)
Mini-plug MP2
Plug P1
Fig. 14—Scaled recovery curves for Mini-Plug MP2 and Plug P1
with a characteristic reference time defined with respect to
gravity forces instead of capillary forces.

(water-wet) outcrop sample core. This set of Pc curves referring to
the initial (nonwater-wet) porous medium and to the chemically
modified porous medium is shown in Fig. 15. The modified
(water-wet) Pc curve is given both for the initial IFT value of 8.5
mN/m of the fluid system under consideration without any addi-
tive, and for the IFT value of 1.2 mN/m obtained as soon as the
additive concentration exceeds 0.1 g/L (Fig. 16). Similarly, as for
Pc, a set of initial and chemically modified relative-permeability
curves was estimated from the compilation of available water/oil
displacement data formerly measured on water-wet and intermedi-
ate- to oil-wet cores of the same Lavoux limestone (Fig. 17). The
model took into account all impacts of IFT changes, which con-
cern the capillary-pressure intensity, and the relative permeabilities
and the saturation endpoints. However, in a first approach, we
assumed that the wettability alone (i.e., at given IFT) did not
change the residual oil saturation (ROS), because modeling focus
was on the recovery kinetics. The adsorption capacity of the rock
was fixed at an estimated value of 1.0 mg per g of solid, drawn
from the Tabary et al. (2009) adsorption data that were measured
on crushed samples of the same aged limestone but for another
surfactant additive rather than the WM used in the present study.
Ideally, dynamic-adsorption data should have been measured on
two aged and native (noncrushed) cores with exactly the same
fluid system. A high value of the Langmuir isotherm parameter
(i.e., 100 l/g) was adopted, assuming that the WM has a high affin-
ity for the rock surface, in view of its capability to change wett-
ability. The molecular-diffusion coefficient in the aqueous phase,
Dm,was estimated at 4.3 10–11
m2
/s for WM molecules.
Simulation results with the previous data set are shown in
Fig. 18. Final recovery is reproduced to within 4% IOIP, and the
simulated recovery kinetics has a fairly similar trend as the exper-
imental one, although the simulated recovery is somewhat too
rapid. That is, the proposed WM model is a plausible model to
reproduce the imbibition enhancement of nonwater-wet media by
WM additive. However it has still to be validated further on the
basis of a more specifically documented data set. Concerned data
include diffusion and adsorption data as well as the evolution of
Pc and kr with WM concentration because the recovery process
involves coupled mechanisms of diffusion, wettability change,
and capillary imbibition. To illustrate that point, model sensitivity
was tested with respect to two parameters that are the molecular-
diffusion coefficient of the additive and the additive adsorption
capacity of the porous medium, which were, respectively, reduced
and increased by a factor equal to 2. Fig. 19 clearly indicates the
high sensitivity of the matrix oil-recovery kinetics to the rate of
diffusion transfer between the fracture and the heart of the matrix
block, and to the amount of additive required to modify the wett-
ability of a given rock-mass unit. Such results are consistent with
the model predictions of Hammond and Pearson (2010), who
showed that the countercurrent chemical-recovery rate is driven
by the diffusion of WM to the imbibition front and by the way
that capillary pressure is altered toward positive (water-wet) val-
ues as a function of the local WM concentration. Another simula-
tion was performed ignoring the effects of IFT changes in the
presence of WM. That run confirmed that the enhanced imbibition
stems essentially from a wettability modification because the
simulated recovery evolution vs. time was identical to the base
case one, except for a small difference in the final oil recovery,
44.5 instead of 45.8% IOIP in the base case, that can be attributed
to the higher magnitude of capillary retention forces at the end of
the imbibition process when IFT changes are ignored. To end
with, those limited numerical interpretation results call for other
sensitivity studies concerning, in particular, the evolution of (kr,
Pc) petrophysical properties vs. wettability. Furthermore, one
should compare the wettability-alteration model considered herein
with models that are based on other rock/additive mechanisms of
interaction with possible kinetics effects.
Conclusions and Perspectives
The chemically enhanced imbibition experiments reported in
that paper provide a detailed insight into natural and chemically
–0.08
–0.06
–0.04
–0.02
0.00
0.02
0.0 0.2 0.4 0.6 0.8 1.0
Pc
(bar)
SW (% PV)
Pcini (IFT = 8.5 mN/m)
Pcmod (IFT = 8.5 mN/m)
Pcmod (IFT = 1.2 mN/m)
Fig. 15—Set of Pc curves used to simulate the chemically
enhanced spontaneous-imbibition test on Mini-Plug MP3.
9
8
7
6
5
4
3
2
1
0
0.001 0.01
Surfactant (WM) Concentration (g/L)
IFT
(mN/m)
0.1 1 10
Fig. 16—Water/oil IFT data for simulating Test MP3.
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8
k
rw
,
k
ro
Water Saturation
Initial krw
(NON-water-wet)
Initial kro
(NON-water-wet)
Modified krw
(by WM)
Modified kro
(by WM)
Fig. 17—Set of kr curves used to simulate the chemically
enhanced spontaneous-imbibition test on Mini-Plug MP3.
0
10
20
30
40
50
0.1 1.0 10.0 100.0 1,000.0
Oil
Recovery
(%
IOIP)
Time (hours)
MP3 (Experiment)
MP3 (Simulation)
Fig. 18—Comparison of simulated and experimental recovery
curves for Test MP3.

enhanced matrix/fracture transfers that can take place in a
waterdrive fractured reservoir. The following conclusions can
be drawn:
Thanks to specifically designed devices and high-performance
measurement equipment, accurate and reproducible chemically
enhanced imbibition data can be acquired on very-small porous-
medium samples, with PVs as low as a few tenths of cubic cen-
timeter. That possibility to quantify imbibition at such a small
scale constitutes a decisive progress because durable imbibition
experiments on large cores were formerly required to obtain
meaningful recovery-kinetics data, and because high-resolution
local saturation measurements were not available. Numerous
well-documented and reliable imbibition tests can now be
undertaken under various chemical EOR conditions to select
high-performance chemical systems, and also under representa-
tive fracture-drive conditions to assess the prevailing matrix oil-
recovery mechanisms within the reservoir.
• Regarding experimental results:
* Chemically enhanced spontaneous imbibition of nonwater-
wet matrix media appears as a very slow oil-recovery process
that may be several orders of magnitude less rapid than the
imbibition of the same strongly water-wet rocks.
* The viscous drive resulting from flow in the fractures can,
however, significantly improve that unfavorable-recovery di-
agnosis, as was clearly demonstrated by the successive spon-
taneous and pressure-enhanced chemical-imbibition test on
Plug P1. That important result enlarges the field of EOR solu-
tions applicable to many carbonate reservoirs characterized
by a preferential affinity for oil.
* Countercurrent flows were found to be the predominating
mechanism of chemically enhanced oil production from the
matrix, even under the pressure-driven conditions of that study.
The probable reason is that the chemical solution can further
imbibe the already wettability-modified periphery of matrix
blocks more easily than the chemically depleted solution can
progress into the nonwater-wet heart of matrix block. Trans-
verse segregation of phases may also promote that unexpected
flow behavior, as revealed by the tests on the horizontal plugs.
• Preliminary numerical modeling of tests on mini-plugs indi-
cates that the chemical-imbibition enhancement process can be
reproduced numerically. However, model predictive capacity
implies to carefully characterize the evolution of capillary pres-
sures in the presence of chemical additive(s) as well as influent
chemical parameters such as diffusion and adsorption parame-
ters. In addition, local/molecular physicochemical mechanisms
of rock-surface wettability modification still need to be investi-
gated further to validate the underlying physics of available
chemical models to date.
To conclude, the proposed experimental and numerical meth-
odology for assessing chemically enhanced matrix/fracture trans-
fer mechanisms opens a promising field of research and
application regarding the production and recovery optimization of
numerous fractured reservoirs.
Nomenclature
D ¼ sample diameter, L
Dm ¼ molecular-diffusion coefficient, L2
T–1
g ¼ gravity acceleration, LT–2
k ¼ single-phase permeability, L2
kr ¼ relative permeability
L ¼ sample length, L
Lc ¼ characteristic length, L
qmax ¼ adsorption capacity, MM–1
t ¼ time, T
tcap ¼ reference time with respect to capillary forces, T
tDc ¼ dimensionless time with respect to capillary forces
tg ¼ reference time with respect to gravity forces, T
tDg ¼ dimensionless time with respect to gravity forces
/ ¼ porosity
lm ¼ average fluid viscosity, ML–1
T–1
Dq ¼ fluid-density difference between the aqueous phase and
the oil phase, ML–3
r ¼ water/oil IFT, MT–2
Acknowledgments
The authors wish to thank management for permission to publish
and also the members of the Chemical EOR Alliance (IFPEN,
Beicip-Franlab, and Solvay) for providing their support to the pro-
ject. They are also indebted to Joëlle Behot and Marie-Claude
Lynch for their contribution to the setup and followup of
experiments.
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Bernard Bourbiaux is a research engineer in the Geosciences
Division of IFP Energies Nouvelles (IFPEN). He has been with
IFPEN for more than 30 years. Bourbiaux’ research interests
include multiphase transfers in porous media, fractured-reser-
voir modeling, and EOR. He holds an engineering degree from
École Nationale Supérieure de Géologie (Nancy, France) and
an MS degree in reservoir management from IFP School (Rueil
Malmaison, France).
André Fourno has been a research engineer with IFPEN since
2005. His research interests include reservoir characterization,
upscaling, history matching, and reservoir simulation. The main
applications of his work are dedicated to fractured reservoirs
and are integrated into FracaFlow and CobraFlow software.
Fourno has authored or coauthored seven refereed publica-
tions and holds three US patents. He holds an engineering
degree from ESM2 (Centrale Marseille), an MS degree in fluid
mechanics from Marseille University, and a PhD degree from
Poitiers University.
Quang Long Nguyen has been a research engineer and a
program developer at IFPEN since 2009. He started working in
the Geosciences Division and then changed to the Mecha-
tronics, Computer Science, and Applied Mathematics Division
in which he continues working on the PumaFlow reservoir simu-
lator. Nguyen’s research interests are multiphase transfers in

porous media, EOR, and reservoir modeling. He holds an engi-
neering degree and an MS degree from Institut National des
Sciences Appliquées, Rouen, France. Nguyen also earned a
PhD degree from Pierre-et-Marie-Curie University.
Françoise Norrant has been with IFPEN for more than 30 years.
Her research interests focus on methods and techniques
improving core analysis and reservoir characterization. The
main applications of Norrant’s current work are dedicated to
characterization of porous media with low-field nuclear mag-
netic resonance. She has authored or coauthored many tech-
nical papers and holds five patents. Norrant holds a BS degree
from Saint-Denis University, Institute of Technology, in physics.
Michel Robin is a research engineer in the Geosciences Divi-
sion of IFPEN. His research interests include thermal methods,
mainly steam injection with or without additives (foam or sol-
vent). Robin specialized in interfacial phenomena such as
fluid/fluid and fluid/rock interactions, or wettability phenom-
ena. He recently worked on carbon dioxide (CO2) storage in
deep saline aquifers, mainly by studying brine/CO2 IFT at stor-
age conditions.
Elisabeth Rosenberg is a research engineer in the Physics and
Analysis Division of IFPEN, in charge of the X-Ray Tomography
Laboratory. Her current work is dedicated to characterization
of materials, fluid transport in porous media (e.g., rocks, cata-
lysts, polymers) and structure/properties relationships. Rosen-
berg holds an engineering degree from École Nationale
Supérieure de Chimie de Lille (France) and a PhD degree from
Pierre-et-Marie-Curie University.
Jean-François Argillier is Project Manager of EOR and Water
Management in the IFPEN EP Technology business unit. He is
also IFPEN Expert in Colloids Interface Sciences. Argillier’s
research focuses on colloidal systems in oil applications—in
particular, polymers, surfactants, emulsions, foams, asphal-
tenes, scales, encountered in EOR, well productivity, oil pro-
duction, and water management. He holds a PhD degree in
chemical engineering from Paris University (1989). Argillier
serves on different organizing committees (e.g., SPE Forums,
Petrophase Conference, World Emulsion Conference). He is
the author of many publications on colloidal systems in oil pro-
duction and holds multiple patents thereon.

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