Fuel 92 (2012) 216–230
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Fuel
journal homepage: www.elsevier.com/locate/fuel
Geochemical modeling and experimental evaluation of high-pH floods: Impact
of Water–Rock interactions in sandstone
Mahdi Kazempour, Eric Sundstrom, Vladimir Alvarado ⇑
Department of Chemical and Petroleum Engineering, University of Wyoming, Laramie, WY 82071, USA
a r t i c l e
i n f o
Article history:
Received 27 March 2011
Received in revised form 8 July 2011
Accepted 14 July 2011
Available online 28 July 2011
Keywords:
Alkaline flood
Anhydrite
pH buffering
Oil recovery
Chemical flooding
a b s t r a c t
Injection of alkaline solutions in reservoir leads to mineral dissolution and precipitation, possibly resulting in changes in permeability and porosity, and consequently altering solution pH. Accurate prediction
of pH, alkali consumption and aqueous chemistry changes are required to design suitable chemical
blends in alkaline-polymer (AP) or alkaline-surfactant-polymer (ASP) flooding. Excessive consumption
of alkali can result in degradation of flood performance and lower than expected oil recovery. We report
state-of-the-art geochemical simulation results for sandstone reservoir mineral assemblages and alkali
solutions (NaOH, Na2CO3, and NaBO2) employed in AP and ASP formulations. Single-phase high-pH corefloods were completed using Berea sandstone and reservoir samples to calibrate and validate geochemical simulations. Results show that rock-fluid interactions depend strongly on mineral type and amount,
alkaline solution injection flowrate, and composition of the injected and formation water. Anhydrite, a
commonly found calcium sulfate, significantly impacts pH buffering capacity, water chemistry and permeability damage against conventional alkali agents in chemical flooding particularly for Na2CO3, but no
significant pH buffering is observed during NaBO2 flooding. Experimental data and model results show
that the pH-buffering effect is maintained even after several pore volumes of alkaline solution are
injected, if a sufficient fraction of relevant minerals is present. The end consequence of this is insufficient
alkalinity for reactions with the oil phase and the likely formation damage.
Ó 2011 Elsevier Ltd. All rights reserved.
1. Introduction
The role of an alkali agent in enhanced oil recovery methods has
been studied for more than four decades. A common claim is that
alkali aids oil mobilization by generating in situ soap [1–3], or by
lowering IFT to ultra-low values in synergy with surfactants [4–
6]. An alkaline agent can sequester divalent cations from the aqueous phase enhancing the efficiency of surfactant partitioning and
avoiding its precipitation [7]. Alkali agents can increase negative
charge density on rock surfaces, altering its wettability toward
water wetness in presence of crude oil [8]. Alkali can also reduce
the adsorption of anionic surfactants on rock surfaces [7,9]. The
aforementioned roles of alkaline agents are attributed to their ability to increase pH. One of the most important phenomena affecting
high pH front propagation through a formation is alkali consumption or retention by rock during the injection period.
Ehrlich et al. [10] completed a series of static tests to measure
alkali consumption in presence of different minerals at room temperature. They found that gypsum, a more stable form of anhydrite,
is largely responsible for alkali consumption in contact with 1.25 N
⇑ Corresponding author.
E-mail address: [email protected] (V. Alvarado).
0016-2361/$ - see front matter Ó 2011 Elsevier Ltd. All rights reserved.
doi:10.1016/j.fuel.2011.07.022
NaOH solution, more than quartz, dolomite, calcite, illite, kaolinite
and montmorillonite. Sydansk [11] showed that caustic solutions
in the form of a sodium-hydroxide solution strongly interacts
with sandstone at elevated temperature. Sydansk concluded that
sodium hydroxide interacted with sandstone at elevated temperature to promote: (a) significant dissolution of the more susceptible
silicate minerals, predominantly clay and large-surface-area silica
minerals; (b) sandstone weight loss; (c) increased porosity; (d)
propagation of significant concentrations of water-soluble silicates,
including sodium orthosilicate; (e) in situ formation of new immobile aluminosilicate material; (f) changes in permeability; and (g)
hydroxide ion consumption. Larrondo and Urness [12] performed
core flooding tests on unconsolidated sandstone with quartz, chert,
feldspar, rock fragments and kaolinite as a clay using sodium
hydroxide, sodium orthosilicate and sodium methasilicate. They
showed that NaOH produced the greatest long-term consumption.
They also concluded that loss of alkali possibly occurred through
ion exchange and mineral dissolution reactions. Cheng [13] found
that alkali consumption can be significantly decreased with the use
of sodium carbonate compared to caustic and silicate alkali in
presence of Wilmington and Ottawa sand with dolomite.
Dezabala et al. [14] used a simple equilibrium chemical model
to present continuous, linear, alkali flooding of acid oil reservoirs.
Jensen and Radke [15] used a local equilibrium chromatographic
217
M. Kazempour et al. / Fuel 92 (2012) 216–230
model to predict alkali propagation through Berea cores. Labrid
and Bazin [16] describe a model designed for calculating the transport of alkali in permeable media with either the assumption that
alkali consumption was determined by thermodynamics or by the
interference of kinetic process. They considered quartz and kaolinite as the only minerals initially in the system and analcime as a
product of rock-alkali interaction. Soler [17] used Global Implicit
Multicomponent Reactive Transport (GIMRT) code to simulate
the interaction between hyper-alkaline solution and fracture marl
at 25 °C. Soler used different kinetics for mineral dissolution and
precipitations, but there was no experimental data for comparison
or testing the efficiency of the model.
In this research, we are interested in determining how rockfluid interactions affect pH and aqueous-phase chemistry in chemical enhanced oil recovery (EOR) that include alkaline agents. Since
high-pH conditions favor EOR performance by mechanisms such as
saponification and by affecting rheological behavior of polymers
[18], understanding the so-called alkali consumption is vital to a
sustainable alkaline flood in any of its modalities. A systematic approach is utilized to investigate the effect of anhydrite on pH buffering capacity during alkaline floods. We test two different
sandstones, Wyoming’s Minnelusa reservoir and Berea cores using
three different alkaline agents: NaOH and Na2CO3, which are the
most commonly used alkalis in EOR processes, and NaBO2, which
has been proposed as a promising alkali in harsh environment
[19]. We perform all the experiments at reservoir temperature
and moderate confining pressure, and unlike other studies, a comprehensive chemical analysis of samples at effluent is completed
and reported to track ions concentrations and other related information. In addition to chemical analysis, thin sections and X-ray
diffraction (XRD) tests are obtained. Subsequently this information
is used for building a reactive transport model using a state-of-theart geochemical simulator (Geochemist’s Workbench [20]). Once
calibrated, this base model is used to predict the results of other
tests to evaluate its robustness. After successful evaluation, the
base model is used to predict the high pH penetration length in
presence of anhydrite in forward (field) simulation cases. For this
case, a 1-D radial case was examined.
2. Materials and methods
2.1. Experimental
The cores are vacuum-saturated with a 30,000 ppm NaCl solution and aged at 60 °C for one week. The cores dimensions are
1.500 300 (diameter length). The core flooding experiments are
conducted at 200 psi of confining pressure. The physical properties
of these cores are tabulated in Table 1. The results of XRD test for
Minnelusa and Berea cores are shown in Figs. 1 and 2. The flow rate
for the core flooding experiments is set at 0.5 ml/min for Berea
cores and 0.2 ml/min for Minnelusa cores, due to lower permeability and porosity of the latter. The flooding sequence is as follows.
First, 5 pore volumes of the 30,000 ppm NaCl solution are injected,
followed by 20 pore volumes of an alkali solution, having one shutin event, after 15 pore volumes of alkali for 15 h. Three alkaline
solutions were prepared at 1 wt% NaOH, 1 wt% Na2CO3, and
1 wt% NaBO2 in 3 wt% NaCl brine with the resulting initial pH at
25 °C: 13.13, 11.15 and 10.36 respectively. For each alkaline solution, two different cores were used to test the effect of anhydrite
on results. The cores are flushed with brine at the end of the alkaline flood for additional 5 pore volumes. Pressure drop is recorded
to track the permeability changes during each test. Effluent samples are collected in vials using an automated fraction collector.
The vials are used to determine the effluent samples pH, charting
the change in pH as a function of pore volumes injected. The effluent samples are also analyzed for anion and cation concentrations
to determine the dissolution of minerals within the core from alkali flooding. The cores are dried, cut and thin sections are made for
analysis.
2.2. Numerical simulation
The Geochemist’s Workbench Professional 8.0 (GWB) [20] is
used as a numerical simulator. GWB can model reactive transport
fluid flow in porous media under a variety of conditions. The model
for activity coefficient calculation is the B-dot equation, which
works better for intermediate and high salinity solutions [21].
The standard thermodynamic database was modified to include
thermodynamic properties of sodium carbonate and sodium metaborate from the thermo.com.v8.r6+ and thermo_phrqpitz databases. For radial cases, rapid changes in velocity around the
wellbore require increasing spatial resolution by adding more
nodes particularly around the wellbore in order to provide more
accurate solutions. To find the most efficient balance between
model node density and computational time, the number of grid
blocks was increased until no significant changes in predictions
were observed. Calibration of the simulation model is based on
the experiment done on Minnelusa rock using sodium hydroxide
at 60 °C.
The base model contains five minerals: quartz, dolomite, anhydrite, kaolinite and k-feldspar. The choice of minerals in the model,
particularly anhydrite, is determined through X-ray diffraction
(XRD) on Minnelusa and Berea core samples (Figs. 1 and 2). As
shown, Minnelusa cores contain anhydrite, but Berea does not.
For all the initial minerals in the system, different dissolution kinetic rates are considered. Except anhydrite, other minerals have
pH dependent dissolution rate kinetics. Due to the high temperature condition, Arrhenius type of dissolution kinetic rate (1) is used
for each mineral (Tables 2 and 3):
dmi
¼ Ai K i e
dt
Eai
RT
n
ð1 Xi ÞaHiþ
ð1Þ
i
where dm
is dissolution kinetic rate in mole
; Ai is the surface area in
sec
dt
cm2, K i is the modified Arrhenius pre-exponential factor in
J
mole=cm2 s; Eai is the activation energy in mole
, R is the universal
J
gas constant in mole K, T is temperature in K, Xi is saturation ratio,
aHþ is activity of hydrogen ion, ni is an empirical parameter and i denotes each mineral (i = 1, 2, . . . , 5).
During the injection of alkali, secondary minerals, e.g. calcite,
portlandite and brucite, can be produced if certain conditions are
Table 1
The properties of the cores.
Core
Type
Porosity (%)
Permeabilityair (md)
Size
Injected alkali
BC-Y-13
C-10
Berea
Minnelusa
19.9
8.73
203.9
3.4
1.500 300
1.500 300
NaOH
BC-Y-11
C-12
Berea
Minnelusa
19.92
9.26
206.6
6.0
1.500 300
1.500 300
Na2CO3
BC-Z-05
C-7
Berea
Minnelusa
20.9
17.6
179
71
1.500 300
1.500 300
NaBO2
M. Kazempour et al. / Fuel 92 (2012) 216–230
Counts/Minute
218
Degrees 2-Theta
Counts/Minute
Fig. 1. XRD spectrum of Berea sample used in this study.
Degrees 2-Theta
Fig. 2. XRD spectrum of Minnelusa sample used in this study.
met. Our strategy for history matching (or calibration) keeps the
dissolution rate constant (here pre-exponential factor and activation energy) of each mineral the same as the reported value [22],
changing their initial volumes and their specific surface areas.
The ultimate initial volume and specific surface area of each mineral in the base model are shown in Table 4. For predicting the re-
219
M. Kazempour et al. / Fuel 92 (2012) 216–230
Table 2
Information on minerals reaction status in the model [21].
Mineral
Reaction
condition
Dissolution kinetic rate
constant (K) at 25 °C
(mole/(m2 s)) at high pH
Activation
energy
(Ea) (J/mole)
Quartz
Anhydrite
Dolomite
Kaolinite
K-feldspar
Kinetic
Kinetic
Kinetic
Kinetic
Kinetic
1016.29
103.19
105.11
1017.05
1021.20
108,366
14,300
34,800
17,900
94,100
pH
(a)
14
13
12
11
10
9
8
7
6
5
4
Table 3
Used dissolution kinetic rate formula for each mineral at high temperature.
Kðat 25 CÞ
Ea
expðR298:15
Þ
2
(moles/cm s)
Quartz
0.001 [21]
Anhydrite
2.07 105
Dolomite
9.71 104
18
Kaolinite
1.22 10
K-feldspar
1.93 109
Applied dissolution
kinetic rate (mole/s)
(b) 10
Ea1
RT Þ
dm1
dt
¼ A1 K 1 eð
dm2
dt
¼ A2 K 2 e
dm3
dt
¼ A3 K 3 e
dm4
dt
¼ A4 K 4 e
dm5
dt
A5 K 5 e
¼
ð1 X1 Þa0:5
Hþ
Ea2
RT
ð1 X2 Þ
Ea3
RT
ð1 X3 Þa0:5
Hþ
Ea4
RT
ð1 X4 Þa0:472
Hþ
Ea5
RT
ð1 X5 Þa0:823
Hþ
Table 4
Final values of adjusted parameters in base model.
Mineral
Quartz
Anhydrite
Dolomite
Kaolinite
K-feldspar
Mineral vol. (%)
80
3
2.267
3
3
Components in fluid (molal)
Calculated K ¼
Shut−in for s15 hr
Inlet pH
Brine injection
0
5
10
15
20
25
20
25
PV
0
2−
−1
SO 4
10
−2
10
2+
Ca
−3
10
−4
10
Brine injection
NaOH injection
−5
10
−6
10
0
2
Specific surface area (cm /gr)
400
400
400
400
400
sults of those tests completed on Berea, the base model is changed
by dropping anhydrite from mineral assemblage, keeping other
parameters unchanged. We have included modeling results of alkali flood at elevated temperature to evaluate the robustness of
the model under reservoir conditions.
3. Results and discussion
3.1. Results of high pH flood in Minnelusa sandstone
3.1.1. Results of NaOH flood
Upon injection of this alkaline solution, 0.5 pH unit difference
between inlet and outlet pH was observed. This is an indication
of weak pH buffering capacity of this rock during NaOH flood
(Fig. 3a). Only small amounts of aluminum, silica and potassium
were produced during this experiment, which might have been
due to the low dissolution rate of quartz and aluminum–silicate
minerals in this rock. First, during brine injection the molar
amounts of produced calcium and sulfate were equal, which was
interpreted as ions originating from the same source mineral (presumed here to be anhydrite). After initiating the alkaline flood,
these ions were no longer produced in equal molar fractions
(Fig. 3b), which provided good evidence for significant precipitation of secondary calcium minerals such as portlandite (calcium
hydroxide) mainly and calcite (calcium carbonate), to some extent,
in this high pH environment. Also, there was no significant amount
of magnesium in effluent samples, which was probably caused by
brucite (magnesium hydroxide) precipitation (Fig. 3c). Saturation
ratios of different minerals, in this study, were calculated using
GSS module of GWB for each collected sample at effluent. It is
important to remark that by injecting NaOH through this type of
5
10
15
PV
(c)
Mineral saturation (Q/K)
Mineral
NaOH injection
10
2
10
0
Saturation line
Anhydrite
Portlandite
Brucite
−3
10
−6
10
−9
10
0
NaOH injection
Brine injection
5
10
15
20
25
PV
Fig. 3. (a) Inlet and effluent pH during NaOH flooding through Minnelusa core; (b)
Chemical composition of effluent; (c) Mineral saturation status of possible
secondary minerals of collected samples.
rock, the amount of calcium in the aqueous phase drops should,
which should favor chemical EOR processes, because the phase
behavior of components in chemical blends, such as polymers
and surfactants, improves with decreased calcium concentration.
In contrast, the amount of sulfate increases drastically, which is
unfavorable because of its side effect on typical anionic surfactants
as well as for its ability to form harmful deposits in the presence of
some certain cations. Sulfate precipitates such as barium and
strontium sulfate are common oilfield scales that can cause a significant reduction in permeability [23].
3.1.2. Results of Na2CO3 flood
In this case, the inlet-to-outlet pH difference during alkali injection at about 2 pH units is a sign of strong pH buffering capacity of
this rock to Na2CO3 flooding (Fig. 4a). Like sodium hydroxide, no
M. Kazempour et al. / Fuel 92 (2012) 216–230
significant amounts of aluminum, silica and potassium were produced (Fig. 4b). Unlike NaOH, the chance of portlandite and brucite
formation is very low here because, as expected, the pH is lower
(Fig. 4c). Because of the improbable portlandite precipitation, the
possible sink for calcium becomes calcite precipitation due to the
high concentration of carbonate ion coming from the injected alkali plus the present calcium ions in the solution coming from anhydrite. Similar to NaOH, Na2CO3 sequesters calcium and it increases
significantly the amount of sulfate in the water phase.
pH
(a)
14
13
12
11
10
9
8
7
6
5
4
Inlet pH
Shut−in for 15 hrs
Na CO injection
Brine injection
14
13
12
11
10
9
8
7
6
5
4
Inlet pH
NaBO injection
Brine injection
0
5
10
10
15
20
25
Al
Ca
−1
10
Cl
SO
K
Mg
−2
10
Na
SO
Ca
NaBO injection
Brine injection
−3
10
−4
−5
10
0
5
10
SO
10
Mg 2+
K+
−2
+
Na
10
Cl
Ca
−
SO2−
−3
4
10
SiO
2
−4
10
Na CO injection
−5
10
Brine injection
0
5
10
15
20
25
Mineral saturation (Q/K)
Components in fluid (molal)
(c)
Ca2+
10
15
20
25
PV
−6
10
Anhydrite
Portlandite
Brucite
2
Saturation line
0
Brine injection
−3
10
NaBO injection
−6
10
−10
10
0
PV
Mineral saturation (Q/K)
SiO
10
30
Al 3+
−1
5
10
15
20
25
PV
3
Anhydrite
Portlandite
Brucite
Fig. 5. (a) Inlet and measured pH at effluent during NaBO2 flood through Minnelusa
core; (b) Chemical composition of effluent; (c) Mineral saturation status of some
possible secondary minerals of collected samples.
Saturation line
10 0
−3
10
−6
Brine injection
10
Na2CO3 injection
−9
10
25
−6
5
100
10
20
10
0
10
(c)
15
(b) 100
PV
(b)
Shut−in for 15 hrs
PV
Components in fluid (molal)
3.1.3. Results of NaBO2 flood
Fig. 5a shows that the pH buffering capacity of the rock during
NaBO2 flooding, as reflected by the inlet-to-outlet 0.35 pH difference. Unlike NaOH and Na2CO3, after initiating NaBO2 injection,
(a)
pH
220
0
5
10
15
20
25
PV
Fig. 4. (a) Inlet and effluent measured pH during Na2CO3 flood through Minnelusa
core; (b) Chemical composition of effluent; (c) Mineral saturation status of possible
secondary minerals of collected samples.
no additional molar fraction of sulfate was produced (Fig. 5b) and
both calcium and sulfate ions were produced at almost equal molar
fractions during the injection period. This latter result is attributed
to the lack of effective calcium sink under test conditions. Fig. 5c
shows all the collected samples were under-saturated with respect
to shown minerals, but the saturation ratio of brucite is close to one,
showing that brucite might precipitate. If this is the case, calcite
might form as well due to the high concentration of calcium in
aqueous solution and intensified dolomite dissolution, which can
supply required carbonate ion. By having no strong evidence of secondary mineral precipitation and pH buffering, NaBO2 is found in
principle to be a good candidate for alkali flooding under this core
flooding condition. However, EW need to consider the reaction
routes and upscaling. For instance, longer-term bottle test demonstrate that this alkali can and will precipitate in a matter of weeks.
221
M. Kazempour et al. / Fuel 92 (2012) 216–230
3.1.4. Formation damage in the presence of anhydrite
To track possible permeability damage of Minnelusa cores under different alkali floods due to rock-fluid interactions, the pressure drop was continuously recorded during each flood, as
shown in Fig. 6. Changes in inlet-to-outlet pressure drop were used
as a permeability damage indicator. If a significant increase in pressure drop upon injection of an alkali occurs, this is taken as a sign
of formation damage. It was observed that among the utilized alkalis, NaOH caused the most severe permeability damage in presence
of anhydrite. Low-permeability rock is more prompt to permeability damage, but when compared to Na2CO3 results in similar rock
samples, the observed damage is much higher, which clearly evidence secondary minerals precipitation. No significant permeability damage was observed during NaBO2 flooding.
3.2. Results of high pH flood in Berea sandstone
3.2.1. Results of NaOH, Na2CO3 and NaBO2 floods
As shown in Fig. 7, there is no sign of significant pH buffering by
Berea rock in these tests for the entire time period of flooding.
There is a small pH drop after shut-in for Na2CO3 and NaBO2 that
might be a sign of possible long-tem alkali consumption. Produced
amounts of silica, potassium and aluminum concentrations were
higher for NaOH than for other alkalis, probably caused by higher
dissolution rate of quartz and aluminum–silicate clays and minerals under higher pH condition at elevated temperature. Very low
concentration of calcium and magnesium were produced in all
the experiments of this part attributed to the lack of anhydrite in
the system and lower contribution of dolomite dissolution using
Berea rock samples.
3.2.2. Pressure drop
Pressure drop data of this set is depicted in Fig. 8. Unlike the results of previous test on Minnelusa, none of utilized alkali resulted
in severe permeability damage in Berea core. The equivalent data
from NaOH, Na2CO3 and NaBO2 floods were somewhat noisy, but
served to establish that the permeability damage was not significant, when compared to the former case. The latter can be attributed to the fact that no secondary minerals were formed during
Berea
3.5
NaOH with Kair=204 md
Minnelusa
70
Pressure drop (psi)
Pressure drop (psi)
2
3
Shut−in for 15 hrs
50
NaOH with K =3.4 md
air
Na CO with K =6 md
2
40
3
air
NaBO2 with Kair=71 md
30
20
Brine Inj.
2.5
Alkali injection
5
10
15
20
25
30
35
Brine Inj.
1.5
1
0
Shut−in
0
5
10
Inj. PV
Fig. 6. Pressure drop along the core during the injection of brine & different alkali
solutions through Minnelusa core.
air
2
0.5
10
air
NaBO with K =179 md
2
60
0
0
Na CO with K =207 md
3
Brine Inj.
Alkali Inj.
Brine Inj.
15
20
25
30
35
Inj. PV
Fig. 8. Pressure drop along the core during brine & different alkaline floods through
Berea core.
Fig. 7. Inlet and measured pH at effluent for different alkali floods in Berea.
222
M. Kazempour et al. / Fuel 92 (2012) 216–230
alkali injection through Berea core to plug some pore throats causing permeability reduction.
3.3. Geochemical modeling results
3.3.1. Predicted results of calibrated geochemical base model
The predicted results of base model are plotted in Fig. 9. There is
a good agreement for pH and cations concentration between
predicted and measured values. The discrepancy shown between
predicted and measured sulfate concentration might be explained
as follows: barium and strontium present in this Minnelusa core
can react with sulfate to form barium (Ba) and strontium (Sr) sulfates, two well-known insoluble precipitates. This was examined
by X-ray Fluorescence (XRF) to determine the amount of trace elements in one Minnelusa core sample (Table 5). As shown, barium
and strontium are indeed found in this rock. Although the reported
values are not sufficient to cause this much difference, their existence in this type of sandstone can contribute to consume sulfate.
1200
14
Brine
injection
pH
10
Ca 2+ conc. (ppm)
12
Alkali
injection
8
6
Shut-in
2
800
600
400
Measured
Predicted
4
0
5
Measured
Predicted
1000
200
10
15
20
25
0
5
10
20
25
10
Measured
Predicted
80
Al3+ conc. (ppm)
SiO 2 conc. (ppm)
100
60
40
20
0
15
Inj. PV
Inj. PV
Measured
Predicted
8
6
4
2
0
5
10
15
20
0
25
0
5
10
Inj. PV
15
20
25
Inj. PV
Measured
Predicted
10000
SO4 2- conc. (ppm)
Mg 2+ conc. (ppm)
40
30
20
10
8000
6000
4000
2000
0
0
5
10
15
20
25
Measured
Predicted
0
5
10
Inj. PV
15
20
25
Inj. PV
Fig. 9. Comparison between predicted and measured pH and also predicted and measured different ions concentrations for base model.
Table 5
Trace element analysis (in Minnelusa sample (C13)).
Element
Conc. (ppm)
Ti
397.6
Sr
331.2
Ba
59.4
Zr
53.5
Co
36.4
Mn
29.4
Ce
19.5
Cr
13.5
As
12.1
Rb
9.3
Nd
9.1
V
4.8
Ta
4.8
Ni
4.3
M. Kazempour et al. / Fuel 92 (2012) 216–230
A second possibility is gypsum formation (or replacement of anhydrite by gypsum) which can reduce sulfate concentration in aqueous phase. Both possibilities can lead to the formation of sulfate
precipitates that create conditions that explain the observed permeability damage of Minnelusa core during NaOH flood. Regardless to the type of sulfate sink, this does not affect the
concentration of calcium in aqueous phase because there is always
a balance between anhydrite dissolution and portlandite deposition. The presence of sulfate sink can affect anhydrite dissolution
and portlandite precipitation without modifying the calcium concentration. Due to the important role of portlandite precipitation
in the aforementioned mechanisms, XRD and scanning electron
microscope (SEM) tests were run on C-10 sample after NaOH flooding to prove its formation. The results (both XRD and SEM) (Fig. 10)
clearly shows formation of portlandite during NaOH flood in
Minelusa cores.
3.3.2. Predictability of base model
The based model was used to predict the results of other floods
(including remaining Minnelusa and Berea samples). It should be
pointed out that for each evaluation test only the initial volume
223
of quartz was changed to consider porosity changes in different
cores keeping other parameters unchanged. Quartz was chosen because the results have the lowest sensitivity with respect to quartz
initial volume among present minerals. Fig. 11 shows a comparison
between measured and predicted pH values for Na2CO3 flood in
Minnelusa. As depicted, the predictive model shows high pH buffering capacity by rock in tests similar to measured data. However,
at some points, the measured pH data are lower than the predicted
values and their trend is not linear, showing more complex buffering mechanisms, which were included in this test during Na2CO3.
Despite the small discrepancy between measured and predicted
pH values, there is a reasonable match between predicted ions concentration and experimental data in this complex system. Unlike
the predicted sulfate concentration in the base model, there is a
close match between predicted and measured sulfate. Similar to
the results from NaBO2 flood experiment in Minnelusa, no pH buffering was predicted by the model either (Fig. 12) and the difference between measured and predicted pH values represents
uncertainties involved in thermodynamic databases (Table 6). In
the case of alkali flood in Berea, in which anhydrite is not present,
our model did not predict any strong alkali buffering by this rock
Fig. 10. The results of XRD (upper) and SEM (lower) tests on C-10 sample after NaOH flood.
224
M. Kazempour et al. / Fuel 92 (2012) 216–230
14
1200
Measured
Predicted
12
Ca 2+ conc. (ppm)
1000
10
pH
Measured
Predicted
1100
8
Brine
injection
Alkali injection
6
800
700
600
500
400
Shut-in
300
-Measured inlet pH = 11.09
-Predicted inlet pH = 11.23
4
900
200
100
2
0
5
10
15
20
25
30
0
5
10
Inj. PV
15
20
25
Inj. PV
40
11000
Measured
Predicted
35
10000
9000
SO42- conc. (ppm)
Mg 2+ conc. (ppm)
30
25
20
15
8000
Measured
Predicted
7000
6000
5000
4000
3000
10
2000
5
1000
0
0
5
10
15
20
25
Inj. PV
0
5
10
15
20
25
Inj. PV
Fig. 11. Comparison between predicted and measured pH and also predicted and measured different ions during Na2CO3 flood in Minnelusa.
and it is consistent with experimental data (Fig. 13). In this case,
small discrepancy between measured and predicted values states
different degree of uncertainty for different materials in these thermodynamic databases. For instance, the error for NaOH is smaller
than that for Na2CO3 and they both exhibit smaller error than for
NaBO2 under this study conditions (Table 6).
3.4. Forward geochemical simulation under high pH flood
In this step, the calibrated base model was used to complete
forward simulations. In this forward simulation, a 1D radial model
was built to see how far high pH conditions extent into the reservoir during different alkaline injections. To build a 1D radial case,
grid blocks with higher density resolution around the wellbore
were generated. The advantage of this technique, which includes
finer nodes around the wellbore and coarser ones away from it,
is that it avoids numerical dispersion and captures abrupt changes
around the wellbore. The chemistry of formation water was set to
mimic water chemistry in Minnelusa sandstone core at the end of
3% NaCl flooding.
3.4.1. Forward simulation (1D radial case)
The forward simulation in 1D radial case has one injector and
one producer. The properties of this model are summarized in
Table 7. This case was selected to show the importance of nonlinear velocity profile around the wellbore. pH profile (at 60 °C)
and the effect of anhydrite dissolution and secondary minerals precipitation after one pore volume injection of 1 wt% NaOH in 3 wt%
NaCl brine are plotted in Fig. 14. As plotted, by flooding the formation with NaOH, anhydrite is dissolved and replaced with portlandite and other minor minerals and the net volume changes of these
minerals leads to create more porosity around the wellbore. Also,
this graph shows that the high inlet pH is only attainable just
around the wellbore and the rest of the field remains at lower
pH than the inlet, which is unfavorable for the chemical process.
Forward simulations were also completed for the case of Na2CO3,
as shown in Fig. 15. Notice that for this alkali, severe pH buffering
occurs and calcite precipitation is prevalent. Sodium carbonate
cannot produce significant alkalinity as long as anhydrite is present, as the insert shows. This particular alkali is unlikely to be a
good candidate for chemical floods, as can be concluded from this
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M. Kazempour et al. / Fuel 92 (2012) 216–230
14
12
Brine injection
Alkali injection
pH
10
8
Shut-in
Measured at effluent
Predicted at effluent
Measured inlet pH
Predicted inlet pH
6
4
2
0
5
10
15
20
25
Inj. PV
Fig. 12. Comparison between predicted and measured pH during NaBO2 flood through Minnelusa core.
Table 6
Predicted and measured pH values for initial alkaline solutions.
Alkali solution
T = 25 °C
1 wt% NaOH + 3 wt% NaCl
1 wt% Na2CO3 + 3 wt% NaCl
1 wt% NaBO2 + 3 wt% NaCl
T = 60 °C
Measured pH
Calculated pH by GWB
Difference
Predicted by GWB
13.07
11.09
10.36
13.13
11.23
10.92
0.06
0.14
0.55
12.15
10.66
10.37
Berea
14
12
Shut-in for Na CO
2
3
10
Shut-in for NaOH & NaBO
pH
2
Alkali injection
8
Brine injection
Measured pH for NaOH
Predicted pH for NaOH
6
Measured pH for Na CO
2
3
Predicted pH for Na CO
2
4
Measured pH for NaBO
Predicted pH for NaBO
2
0
5
10
15
3
2
2
20
25
Inj. PV
Fig. 13. Comparison between predicted and measured pH during different alkali floods through Berea cores.
evaluation under single-phase flow conditions. However, this
might change in the presence of crude oil. Similar to the other
two alkalis, a high pH value is reachable just around the wellbore
after one pore volume injection of 1 wt% NaBO2 (Fig. 16) too. As observed, unlike NaOH and Na2CO3, NaBO2 injection does not form
significant amount of secondary minerals and the dominant
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M. Kazempour et al. / Fuel 92 (2012) 216–230
Table 7
1D radial case properties.
Case
Injected fluid
Injected pH at 60 °C
Injection time (days)
Flow rate (m3/day)
Field size
/(%)
H (m)
Mineral (vol.%)
1D radial
1 wt% + NaOH 3 wt% NaCl
12.15
365
263.6
Rw = 12.7 cm
20
5
Q: 68.733, D: 2.267
A: 3
1D radial
1 wt% NaBO2 + 3 wt% NaCl
10.37
Re = 175 m
K: 3
K–f: 3
Fig. 14. pH profile, formed secondary minerals and anhydrite status after 1 pore volume injection of NaOH versus radial distance from wellbore.
Some minerals (volume %), t = 365.2 days
11
10.5
pH, t = 365.2 days
10
9.5
9
10
Calcite
Anhydrite
1
.1
.01
.001
1e–4
1e–5
1e–6
1e–7
0
20
40
60
80
100
120
140
160
180
X position (m)
8.5
8
7.5
0
20
40
60
80
100
120
140
160
180
X position (m)
Fig. 15. pH profile, formed secondary minerals and anhydrite status after 1 pore volume injection of Na2CO3 versus radial distance from wellbore.
M. Kazempour et al. / Fuel 92 (2012) 216–230
227
Fig. 16. pH profile, formed secondary minerals and anhydrite status after 1 pore volume injection of NaBO2 versus radial distance from wellbore.
mechanism for porosity increase around the wellbore is dissolution of anhydrite. It should be pointed out that compared to NaBO2,
NaOH has larger high-pH penetration length into the formation,
which might be more desirable in enhanced oil recovery; NaOH
can cause more side problems than NaBO2, such as propagation
of a front which is more enriched in sulfate and also permeability
reduction.
3.5. Thin section analysis
To gain insight into what goes on in these alkaline floods, several thin sections were taken from the inlet and outlet sections
of rock plugs used in the experiment. In this study, both plain
and polarized lights were used for better detection of anhydrite
crystals in Minnelusa’s sample. It is known that sulfate cements,
i.e. gypsum, anhydrite, and barite, are present in some clastic systems, e.g. sandstones, particularly those deposited in evaporitic
environments, where gypsum is precipitated as a cement at shallow burial depth. Late-stage anhydrite may precipitate at greater
burial depths if an adequate source of SO2
4 ions is available in subsurface brines [24]. Gypsum and anhydrite crystals take a variety
of forms including single crystals, radial clusters of crystals, and
numerous types of complex twinned crystals. The crystallographic
information can be used to detect gypsum and anhydrite in thin
sections, because their crystalline features allow one to differentiate them from other minerals present. Gypsum crystals can be
identified by characteristic lath-like crystal shapes, weak birefringence and low reliefs. Anhydrite is distinguished from gypsum by
a higher relief and stronger birefringence. The results of thin section analysis for one of the Minnelusa samples (before flooding)
under non-polarized and cross polarized light is shown in Fig. 17.
Presence of anhydrite particles and their widespread distribution
are noticeable in the micrographs. Fig. 18 shows the porosity difference between inlet and outlet cross sections of the cores used
for NaOH and Na2CO3 respectively. As observed, dissolution is
higher than precipitation at inlets, yielding porosity values larger
Fig. 17. A thin section sample of Minnelusa core under non-polarized and cross
polarized light.
228
M. Kazempour et al. / Fuel 92 (2012) 216–230
Fig. 18. Comparison between porosity values of inlet and outlet face of Minnelusa cores afte NaOH (upper one) and Na2CO3 (lower one) floods.
at inlet than at the outlet. Also, the micrographs show a reduction
in porosity during the NaOH flood is more significant than that of
Na2CO3 flood (although this is only qualitative comparison), which
is consistent with what was found before in this study.
4. Discussion
The premises of an alkaline flood include the sustenance of high
pH conditions with limited formation damage. Significant number
of experiments for screening purposes rely on the use of outcrop
rock such as Berea. The results shown here clearly indicate that
outcrop rock would not represent a good analog for rocks containing easily dissolvable minerals such as anhydrite, typically present
in evaporite (sandstone). As previously shown in Fig. 3, sodium
hydroxide is buffered as portlandite precipitates, but pH quickly
rises by continuously injecting the alkali. The observed pH would
sustain conditions to saponify the crude oil and create surfactant.
However, several drawbacks are the significant formation damage
(as shown in Fig. 6) and the increase in sulfate concentration
(Fig. 4b), especially for the NaOH injection. The former problem
would limit the use of sodium hydroxide in low-permeability formations, as secondary mineral precipitation is likely to cause significant formation damage, as clearly shown in Fig. 6, while the
latter would affect surfactant (synthetic and natural) phase behavior. This means that the choice of surfactant in laboratory screening
must account for the geochemical conditions originating in the
rock. Traditional bottle tests for surfactant screening use simple
aqueous phase chemistry, i.e. typically sodium chloride solutions,
which would not reflect in situ conditions. On the other hand,
the extreme buffering of sodium carbonate, as illustrated in
Fig. 4, seriously limits the ability of this alkali to provide conditions
for saponification of acid crude oils (pH should be close to 11 to be
effective). This buffering effect is even more apparent at field scale,
as shown in Fig. 15. Significant precipitation of secondary minerals
is also observed with sodium carbonate, althought the formation
damage was not as significant as in the case of sodium hydroxide.
In addition, the use of this alkali would lead to increase in sulfate
concentration without the benefits provided by stronger alkalis
(e.g. sodium hydroxide) such as eventually sustaining high pH. Finally, sodium metaborate appears to fulfill at least one of the desirable conditions for an alkali, namely limited formation damage.
However, we should not neglect the uncertainties in understanding the long-term behavior of this alkali on one hand. It turns
out that our ability to predict this for sodium metaborate is not
completely adequate and up to one pH unit may be associated in
predicting metaborate behavior in solution. On the other hand,
longer-term observations in bottle tests clearly indicate precipitation. This signals that sodium metaborate may not be able to provide alkaline conditions necessary for EOR processes requiring
high-pH conditions in practice.
Upscaling of coreflooding experiments through simulation are
quite revealing, as illustrated in Figs. 1,14–16. Portlandite is the
dominant precipitant in sodium hydroxide injection, not observed
in sodium metaborate flooding. Sodium carbonate leads to precipitation of calcite, which can cause formation damage. In contrast,
however, the amount of calcite precipitation for sodium metaborate is significantly higher than for sodium hydroxide and more
comparable to the sodium carbonate case. Also, high-pH fronts
are more likely to propagate with sodium hydroxide as opposed
M. Kazempour et al. / Fuel 92 (2012) 216–230
to sodium metaborate. It is important to contrast the experimental
observations, i.e. coreflooding results, with field predictions. Despite the elevated pH that can be sustained in the cases of sodium
hydroxide and to a lesser extent with sodium metaborate, this is
only attainable after a couple of pore volumes in the lab and what
the simulation indicates is that the high-pH front rapidly decays
with distance, particularly for sodium carbonate and sodium metaborate. It might be misleading to extrapolate lab inferences to field
situations without proper modeling of field effects. The radial cases
simulated here clearly indicate the impact of geometrical effects in
the field and further evidence of applicability or lack thereof of a
given alkali to field situations. In this sense we refer to lab results
as limited predictors of field observations. However, at least for the
sodium carbonate case, the poor expectations derived from corefloods are confirmed by modeling field-size cases.
Notice that the results reported here will be impacted by the
presence oil and the combined effects of the original rock wettability and the resulting one from the addition of alkali to chemical
blends. The presence of oil should limit access to the rock surface,
particularly in oil-wet formations, and therefore will affect the
rock-fluid interaction. In order to draw conclusions regarding this,
additional research must be carefully conducted, because as alkali
is consumed, the possible wettability alteration associated with
the injection of alkali will change. Additionally, some of the alkali
will be consumed in neutralization reactions, some of which will
generate desirable soaps, depending on the acid number and composition of the oil. However, since excess alkali is usually injected
in chemical floods, this sink of alkali should dominate only after a
substantial fraction of the alkali has been consumed through fluidmineral reactions. A detailed example of this in heavy oil can be
found in reference [25].
The results regarding secondary mineral precipitation can be related to large field pilot projects of alkali-surfactant-polymer (ASP)
floods in which scales are a severe problem, such as Daqing in China, where some of the largest ASP pilots have been developed [26].
Silicate scales have been found during NaOH-based ASP formulations [27], reason why silicate scale inhibitors have been used to
protect production infrastructure. However, carbonate scales have
been found in conjunction with silicates [28,29]. Calcite has also
been found in the production system intermixed with silicates.
The modeling strategy developed in this work can contribute to
the prediction of scale formation in downhole and surface facilities,
but the extent of formation damage requires additional experimental data.
5. Conclusion
1. The impact of anhydrite as a pH buffering mineral in the rock
and its contribution to changes in water chemistry during alkali
flood are strongly dependent on alkali used in the flood, i.e. the
maximum pH buffering occurred when Na2CO3 solutions are
injected, while the minimum corresponds to NaBO2 flooding.
However, this buffering is significant at field scale.
2. Small amounts of anhydrite can limit the maximum attainable
pH upon injection of NaOH and more markedly Na2CO3, even
after several pore volumes of the alkaline solution have been
injected, although high pH is quickly attained after several volumes of NaOH are injected.
3. Conventional alkalis, namely NaOH and Na2CO3, reduce the
amount of calcium in the aqueous phase in presence of anhydrite, but they cannot completely sequester it. On the other
hand, these alkalis will promote an increase in the amount of
sulfate in solution to values three times larger or more than
the values observed during waterflooding, which represents a
risk to the success of any chemical flood.
229
4. Associated permeability damage by alkali flood can be intensified by presence of anhydrite in mineral assemblage due to
the secondary minerals precipitation particularly for NaOH.
5. pH buffering capacity obtained in linear core flooding tests can
be more significant at field scale, as simulation results predict,
indicating the importance of upscaling and forward simulation.
6. A robust geochemical model is a powerful tool that is essential
for field application design of chemical flooding for which pH,
water chemistry and optimum salinity are key factors, as lab
results can turn out to be poor predictors of field behavior.
Acknowledgments
We would like to acknowledge the Enhanced Oil Recovery Institute at the University of Wyoming for financial assistance. The
authors thank the School of Energy Resources (SER) at the University of Wyoming for financial assistance through the Anadarko Fellowship for Excellence in Energy Scholarship.
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