International Journal of Engineering & Technology IJET-IJENS Vol:10 No:04 47
107704-2929 IJET-IJENS © August 2010 IJENS
I J E N S
Effects of Pressure and Temperature on
Well Cement Degradation by Supercritical CO2
Arina binti Sauki and Sonny Irawan, Geoscience and Petroleum Engineering Department, Universiti Teknologi PETRONAS, Bandar Seri Iskandar, 31750 Tronoh,
Perak, Malaysia
Abstract – The overall objective of this study was to
investigate the physical and chemical effects of supercritical CO2
attack on well cement at different temperature and pressure condition. The dissimilarity of attack was compared in two-
exposure conditions i.e. CO2-saturated brine and wet
supercritical CO2. Type of cement used for this invent was neat
cement, Class G and was prepared according to API
recommended practice 10B-2 by using Constant Speed Mixer. Curing of cement slurry and CO2 exposure test were done by
using Curing Chamber and Cement Autoclave. Measurement
and evolution of cement alteration against CO2 attack was
determined under various temperatures and pressure condition
at different exposure duration. Results from BackScattered Electron of Scanning Electron Microscopy (BSE-SEM), Energy-
dispersive X-Ray Spectroscopy (EDX), X-Ray Diffraction (XRD)
and compressive strength tester was analysed and studied. At
high temperature, 1200C, cement will lose its strength faster than
lower temperature, 400C. Same goes to pressure, the strength will lose faster in higher pressure, 140 bar as compared to lower
pressure, 105 bar. Faster reduction in strength was found in
CO2-saturated brine exposure compared to wet supercritical
CO2.
Index Term – Supercritical CO2, brine, alteration, compressive
strength, curing.
I. INTRODUCTION
OILWELL cement is used as a seal to secure and support
casing inside the well and prevent fluid communication
between the various underground fluid-containing layers or
the production of unwanted fluids into the well. It has been
used as the primary sealant in oil and gas wells throughout the
world and is manufactured to meet specific chemical and
physical standards set up by the API. There are eight class
listed in API Specification for Oilwell cement i.e. Class A to
H. The depth of well determines the difference types of
oilwell class used. For this invent, Class G cement was used
where it is intended to be used as a basic cement from surface
to a depth of 8000ft (2439m) as manufactured. Presently,
Class G oilwell cement is being used in oil and gas industry
for all types of cementation jobs.
Supercritical CO2 has a unique property that can improve
oil and gas production in the reservoirs. These would be a
great value for Enhanced Oil Recovery (EOR), Enhanced Gas
Recovery (EGR) and Enhanced Coal Bed Methane Recovery
(ECBM) project to boost the oil and gas production in their
fields. The focus of CO2 injection is normally found in the
areas that have a history of oil, natural gas and coalbed
methane production. It was first exploited in the mature fields
of the Permian Basin, West Texas, during the early 1970s for
EOR. In Natuna Gas Field (Greater Sarawak Basin in South
China Sea), high concentration of CO2 was found at the
production field. One of the solutions that could possibly do is
the reinjection of the CO2 gas into deep ground for storage or
for the use of EOR, EGR and ECBM project. However, the
major concern here is that the Portland cement is not stable in
CO2 rich environment. The main concern of CO2 exposure
should be taken to some existing oil and gas wells, which may
lead to an additional risk of properly sealing and may cause
potential CO2 leak paths [2]. The possible leakage pathway
would be from the reservoir to the shallower formation then
through that formation to the well cement.
Saline formations commonly have low flow velocities.
Some CO2 will remain as a separate free phase (hydrodynamic
trapping), that occurs because of the CO2 is less viscous than
brine, even at depths of more than 800m where CO2 is a
supercritical fluid [10] and will migrates upwards through
permeable pathways in the rock formation. CO2 behaves as a
supercritical fluid above its critical temperature of 31.6 °C and
critical pressure of 73.8 bar, expanding to fill its container like
a gas but with a density like that of a liquid. Nevertheless,
some CO2 will dissolve in the brine (solubility trapping) [10].
The dissolves CO2 will migrate along with the formation
water and leads to cement-carbonated brine contact. This
study evaluates cement degradation under two scenarios i.e. in
contact to wet supercritical CO2 (hydrodynamic trapping) and
in contact to CO2-saturated brine (solubility trapping).
When cement slurry is placed in the well, it is exposed to
elevated temperatures and pressures . The temperature and
pressure in oil & gas wells increases with depth. Typically, the
well temperature increases of about 3°C for each 100m depth.
Deeper than 20,000ft (6096m), the well temperature can easily
reach 175°C. Therefore, this experiment was performed in
different temperature and pressure condition to investigate the
effect of pressure and temperature on degradation of wellbore
cement by CO2.
Four major crystalline compounds in Portland cement are
tricalcium silicate (Ca3SiO5), dicalcium silicate (Ca2SiO4),
tricalcium aluminate (Ca3Al2O6), and tetracalcium
aluminoferrite (Ca4Al2Fe2O10). The most plentiful phases in
Portland cement are the silicates, comprising over 80 wt % of
the cement, mostly in the form of tricalcium silicate [4]. When
the compounds of Portland cement mixed with water, the main
hydration products formed are C-S-H and Ca(OH)2 [4].
Portland cement tends to degrade once exposed to CO2. In this
study, the mechanisms of interest were described as per
following to explain the CO2 attack to these main products in
the form of carbonic acid [2]:
International Journal of Engineering & Technology IJET-IJENS Vol:10 No:04 48
107704-2929 IJET-IJENS © August 2010 IJENS
I J E N S
CO2 dissociation:
CO2 + H2O → H2CO3 (1)
Cement Carbonation:
H2CO3 + Ca(OH)2 → CaCO3 (2)
C-S-H + H2CO3 → CaCO3+amorphous silica (3)
Calcium Carbonate dissolution:
CaCO3 + H2CO3 → Ca(HCO3)2 (4)
Ca(HCO3)2 + Ca(OH)2 → 2CaCO3 + H2O (5)
Initially, the CO2 dissolves in the water film through the
capillary pores of the cement resulting from internal
condensation or diffusion of environmental fluids , forming
carbonic acid in Equation (1). The acid then reacts with the
Ca(OH)2 in the cement as well as the C-S-H gels to form
CaCO3 in Equation (2) and (3). However, the CaCO3 can
continue to react with fresh carbonic acid in Equation (4)
which may leads to dissolution of CaCO3. In these reactions,
CaCO3 is converted to water soluble calcium bicarbonate that
will then coupled with the formation of water in Equation (5)
to produce CaCO3 and water. Consequently, the water can
tolerate for the additional dissociation of CO2 to form carbonic
acid. Thus, a continuation of the reaction process will occur.
As a result, the compressive strength of the set cement
decreases and the permeability increases, leading to the loss of
zonal isolation. As such, it is crucial to study how such cement
behaves at depth in the presence of CO2 rich fluids.
Many experimental studies have been published on
cement reactivity with CO2-rich fluid, which pressure and
temperature similar to CO2 storage facilities and oil and gas
production field that initially related to the alteration of well
cement in oil and gas production fields studied by Onan [5].
Recently, the invention was continued to well cement integrity
in the context of CO2 storage by Jose Condor [3], Emilia
Liteanu [8], V. Barlet et al [7], Barbara et al [4], W. Scherer
[11] and O. Brandvoll
et al [14]. In this invent, an
experimental study was done to evaluate the effects of
temperature and pressure variation against CO2 attack towards
this well cement. It was hardly to explain the exact value of
pressure and temperature in the reservoirs as the pressure and
temperature were varied dependence on the depth and
reservoir environments.
Barlet-Gouedard [1] has concluded that CO2 dissociation
stage starts earlier in CO2-saturated water than in wet
supercritical CO2. Under these severe conditions, Portland
cement is not resistant to CO2 and is not a good candidate for
cementing new wells for CO2 storage. In this research, the
dissimilarity of CO2 attacked in wet supercritical CO2 and
CO2–saturated brine condition was studied instead of CO2-
saturated water as Barlet et al [1] did at different pressure and
temperature conditions.
II. EXPERIMENTAL METHODOLOGY
A. Cement Slurry Samples Preparation
In order to prepare a cement slurry sample, the Class G
oilwell cement were mixed (35 seconds on Waring Blender at
high speed) with fresh water at a water-to-cement ratio of
0.44 by using Model 7000 Constant Speed Mixer according to
API Recommended Practice 10B-2 [9].
B. Curing Process
The cement samples were casted by slowly pouring the
degassed slurry down the cubical mould containing eight
cubic samples (2-inch-height x 2-inch-length) before
launching the curing chamber. The samples were cured for 8
hours, following the ISO/API standard procedures to simulate
the setting of the cement under reservoir condition. In order to
determine the effects of pressure and temperature of well
cement degradation, the pressure was kept constant when
temperature was varied and vice versa as shown in Table I.
TABLE I
TEMPERATURE AND PRESSURE VARIATION USED
Constant Pressure (140 bar)
Constant Temperature (400C)
Temperature
(0C)
40 Pressure
(bar)
105
120 140
After 8 hours curing period, the samples were demolded
and washed to remove the grease from their surface. The
cubes were then examined and only the most perfect cubes
were accepted for the testing to avoid any interference on the
results due to surface imperfections on the cubes. Then, the
cubes were weighed before submerged them in the water.
Prior to CO2 exposure, the cubic samples were cored to obtain
1.5-inch-diameter cylindrical samples with 2-in length for CO2
exposure.
C. CO2 Exposure Test
Cement Autoclave was used to expose cement core samples
(1.5in-D x 2in-L) after curing with supercritical CO2 under
two situations: wet supercritical CO2 and CO2-saturated brine.
The CO2 experiments were performed under static condition.
This condition was considered as a realistic simulation of the
CO2-exposure conditions at the formation/ cement sheath
interface.
The hardened cement samples were exposed to brine
(0.01M NaCl) solution saturated with supercritical CO2 under
identical condition with curing as shown in Table I. The
volume content of the CO2 fluids in the vessel was about 40%
brine and 60% CO2 at atmospheric pressure and room
temperature. This experiment was performed at different
durations: 24 hours, 72 hours and 120 hours.
To remove each sample, the pressure was released slowly
over a period of four hours to prevent sample damage. The
samples were then photographed and weighted. pH of residual
brine was also measured by using pH meter after each
duration of experiment. Finally, mechanical strength, chemical
and microscopic composition were systematically analyzed.
International Journal of Engineering & Technology IJET-IJENS Vol:10 No:04 49
107704-2929 IJET-IJENS © August 2010 IJENS
I J E N S
D. Alteration Measurements
Measurement was taken before and after CO2 exposure
to compare the alteration results of the followings:
i. The mineralogical composition of the samples were
identified by using XRD and EDX.
ii. The specific phases within the cement and the
microstructural development and alteration front of the
samples are verified by BSE-SEM.
iii. Compressive strength of cement core sample was
obtained by using OFITE Automated Compressive
Strength Tester.
iv. Other indirect measurements such as pH of the sample
brine, mass of the cement samples and the dimension of
the cement samples are measured by using pH meter,
Balance and Vernier Caliper.
III. RESULT AND DISCUSSION
A. Effects of Different Temperature Conditions on Cement
Degradation By Supercritical CO2
Based on the observation from BSE-SEM image before
CO2 attack showed that samples cured at 1200C had smaller
and more uniform distributed unhydrated cement grains
throughout the solid matrix of the cement compared to sample
cured at 400C as shown in APPENDIX [I]-A. This was shown
that higher degree of hydration of cement grain could be seen
at rising temperature. The hydration showed that the reaction
between water and cement grains to produce Ca(OH)2 and C-
S-H was greater at 1200C which may leads to the formation of
smaller unhydrated grains compared to the low temperature,
400C. This may provide large impact on the CO2 to attack in
term of carbonation process between C-S-H and Ca(OH)2 as
per Equation (2) and (3) to occur.
Result from cement sample after CO2 exposure in brine
solution showed the depth of penetration always increased by
time. A slight increase in depth of penetration was clearly
observed at the rim of sample by using BSE-SEM image as
early as 24hours of CO2 attack as shown in APPENDIX [III].
Sample exposed at 1200C showed greater depth of penetration
after 120-hours of attack up to 0.78 mm whereas sample
exposed at 400C had smaller depth of penetration that was up
to 0.55mm deep after 120hours of CO2 attack. Based on
theory [16], the outer-product C-S-H gel become denser and
does not fill the capillary pore space as effectively at elevated
temperature and thus the microstructure is more
heterogeneous. This pore space may provide easier CO2 to
attack in the form of carbonic acid. The CO32-
ion from acid
carbonic will attack the leached Ca2+
ion from C-S-H and
Ca(OH)2 to produce CaCO3 and amorphous silica. Extensive
reduction of Ca can be shown in APPENDIX[V] which about
30-40weight% at high temperature, 1200C sample rather than
about 5-weight% reduction at low temperature, 400C sample.
Compressive strength on sample exposed at 1200C
showed strong reduction that was about 80% rather than about
70% in sample exposed at 400C after 120-hours of CO2 attack.
Based on cement chemistry theory [16], cements lose much of
their strength at greater temperature. These effects could be
related to the increased rate of silicate polymerization at
elevated temperatures, more than 1100C, which densifies and
stiffens the C-S-H as it forms [16]. This loss of strength which
is accompanied by an increase in permeability, caused by the
formation of an alpha hydrate form of calcium silicate which
has no cementitious value [17]. The production of amorphous
silica from reaction between C-S-H and acid carbonic may
decrease the compressive strength of this cement due to the
lack and highly porous of its structure and may provide easier
acid to attack. Apart from that, the reduction in strength was
believed because of the loss of silica which hardened the
cement paste. Result from EDX analysis from APPENDIX
[VI] showed the reduction in s ilica in the range of 5-10
weight% at 1200C after 120-hours of CO2 attack as a result of
loss in compressive strength of cement. The diverse degree of
compressive strength evolution was also due to the production
of calcium carbonate from carbonation process that was
believed can increase the compressive strength of cement
sample.
Mass alteration of the sample did not show any significant
different. The mass loss in sample exposed at 1200C was
greater about 0.5% than sample exposed at 400C after 24-
hours of CO2 attack due to the higher degree of hydration
occurred at higher temperature. The less water filled the
capillary pore of the cement may reduce the mass of cement
sample. However, the mass kept increasing after 72-hours of
CO2 attack resulting from higher carbonation rate of cement
by CO2. The formation of CaCO3 was believed increase the
mass of sample and strong degradation at the rim of sample
may cause the reduction of mass in cement sample after 120-
hours of CO2 attack.
Hydrated cement is a highly alkaline material that is
chemically stable only when pH more than 10 [11]. Hence,
the introduction of CO2 in brine will make the downhole
conditions extremely aggressive against the existing well
cement. Sample of brine was taken out from vessel after each
moment of CO2 attack duration and was tested in pH. The
result was shown in APPENDIX [VIII]. It was observed that
CO2 attack-related decrease the pH of brine for sample
exposed at high temperature, 1200C from 8 to 7.5 after 24-
hours. However, the reduction in pH at lower temperature,
400C was faster that was about 6.5 after 24-hours. This delay
in deduction was believed due to temperature variant. The
capacity and solubility of CO2 dissolves in brine decrease with
rising temperature [11]. Apart from that, the aggressive
removal of alkaline OH- from pore water filled at high
temperature will react with CO32-
from acid carbonic to form
Ca(OH)2 made this process a little bit delay in pH deduction
until the equilibrium phase was achieved and decrease the pH
around 6.78 after 120-hours of attack. It was believed from
previous researcher that Ca(OH)2 constitutes the alkaline
reserve to provide acid resistance [11]. It was a key
component in hardened cement that buffers the pH of the
porewater [11].
International Journal of Engineering & Technology IJET-IJENS Vol:10 No:04 50
107704-2929 IJET-IJENS © August 2010 IJENS
I J E N S
B. Effects of Different Pressure Conditions on Cement
Degradation By Supercrtical CO2
In term of pressure, slight increase in depth of penetration
can be observed in sample exposed at 105 bar that was up to
0.65mm deep compared to 140 bar that was merely about
0.55mm after 120hours of CO2 attack in brine solution as
shown in APPENDIX [III]. It was happened due to higher
carbonation process occurred at lower temperature. This can
be shown from the depletion of calcium at low pressure, 105
bar as shown in APPENDIX [V] that was about 30-weight%
as compared to high pressure at about 2-weight% in reduction.
The outcome from compressive strength tester on sample
exposed to CO2 attack in brine solution at 105 bar showed an
increment in strength which was about 50% after 24-hours of
exposure. However, after 120-hours, the compressive strength
shows a slight decrease about 10%. In contrast with sample
exposed at 140 bar, the compressive strength showed a
reduction as early as 24-hours of CO2 attack which was almost
20% and kept decreasing up to 85% after 120-hours of CO2
attack. The increment of compressive strength for sample
expose at 105bar was believed due to the higher rate of
carbonation occurred and produced more CaCO3. The
formation of CaCO3 had been reported to decrease
permeability and increase the compressive strength of the
cement since the solid CaCO3 filled the capillary pore of
cement grains [4]. This can be proved from strong depletion of
Ca that was about 50-weight% at 105 bar as compared to
sample exposed at 140 bar which was merely about 6-
weight% of reduction.
Reduction in mass can be seen in sample exposed at
140bar in the range of 1-2% after 120-hours of CO2 attack in
brine solution as shown in APPENDIX [VII]. However, mass
was gained in sample exposed at 105 bar up to 1.8% at 72-
hours exposure prior to slightly depletion at 0.5% after 120-
hours exposure. The increased of mass resulting from higher
carbonation rate of cement by CO2. The formation of CaCO3
was believed increase the mass of sample and strong
degradation at the rim of sample may cause the reduction of
mass in cement sample.
Virtually similar trend of pH evolution was observed in
both samples exposed at 105 bar and 140 bar. However,
sample exposed at 140 bar was having slightly lower pH after
120-hours of CO2 exposure in brine solution that was 6.06 as
compared to sample exposed at 105 bar that was 6.17 as
shown in APPENDIX [VIII]. It was believed that the
solubility of CO2 in brine will increase at rising pressure [11].
Hence, it reduced the pH greater at higher pressure.
C. Effects of Cement Degradation by Supercritical CO2 in
wet supercritical CO2 and CO2-saturated brine
Examination with BSE-SEM and EDX analysis, revealed
that the exposure of cement by CO2 under wet supercritical
CO2 and CO2-saturated brine altered the cement in four zones
as shown in Figure 1. Zone 1 was the innermost unaltered
cement surrounded by three altered zone. Zone 2 was a 50 to
100μm-large zone exhibited a slight increase in porosity and
decrease in Ca(OH)2 while Zone 3 was a ring of decreased
porosity and increased calcium content that is about 100 to
200μm-large zone. The BSE-SEM image of Figure 1 indicates
that zone 3 was less porous than any other regions including
the unaltered cement (zone 1). Calcium carbonate (CaCO3)
precipitates in the cement matrix characterize this front. From
XRD analysis, only CaCO3 in the form of calcite and
Aragonite were visible in all carbonated samples. No vaterite
contain was found. The outermost evidence of attack was zone
4 (200 to 400μm-large zone), which exhibited a significant
increase in porosity and highly depleted in calcium as a result
of strong degradation of the cement in this zone. From the
overall analysis, all samples tested were having the same
distinct altered zone as Figure 1 except for being poles apart in
depth of penetration. It was observed that the sample exposed
in wet supercritical CO2 had wider zone 3 than sample
exposed to CO2-saturated brine as shown in APPENDIX [II]-
C. It shows that higher carbonation occurred in wet
supercritical CO2 which produced more CaCO3.
Fig. 1. BSE-SEM image of cement degradation after a 120-hr-CO2 attack in
brine solution at 140 bar and 40 deg C.
Roughly the degradation effect can be detected by
viewing at the rim of the cement samples. The outer surface of
the cement exposed to CO2-saturated brine was orange in
color and smooth texture while wet Supercritical CO2 was
light grey and rough texture as shown in Figure 2. The change
of colour for sample submerged in brine from grey to orange
was explained due to change in oxidation state of the iron
contain in neat cement. The increase in ring thickness was
observed at each moment as shown in Figure 3.
Fig. 2. Different colour of ring between cement exposed to wet supercritical
CO2 and CO2-Saturated Brine.
International Journal of Engineering & Technology IJET-IJENS Vol:10 No:04 51
107704-2929 IJET-IJENS © August 2010 IJENS
I J E N S
Fig. 3. Alteration at the rim of cement thin section under different exposure
durations for cement samples exposed to wet supercritical CO2 and CO2-
Saturated Brine at 40 deg C and 105 bar.
Depth of penetration for sample exposed to wet
supercritical CO2 was greater compared to sample exposed in
CO2-saturated brine at each moment of exposure duration as
shown in APPENDIX [III]. This was believed due to the
solubility of CO2 in water, which filled the capillary pores of
sample in wet supercritical CO2 was greater than the solubility
of CO2 in brine solution. High solubility may provide higher
carbonation rate of attack. Thus, enlarge deeper depth of
penetration.
In average, the mass of sample exposed in wet
supercritical CO2 increase 2% to 7% more than CO2-saturated
brine due to the higher carbonation occurred in wet
supercritical CO2 rather than those in CO2-saturated brine.
However, in contrast with depth, the compressive
strength decrease more in CO2-saturated brine rather than wet
supercritical CO2 in the range of 20% to 50% after 120-hours
of CO2 exposure as shown in APPENDIX [IV]. Higher
carbonation in wet supercritical CO2, may produce more
CaCO3 which can increased the compressive strength of
cement.
IV. CONCLUSION
Based on experiment made, temperature and pressure do
play an important role for the chemical and physical alteration
of cement by CO2 attack. It was observed that cement tends to
degrade and loss its strength once expose to supercritical CO2
environment. The loss in compressive strength was greater at
increase temperature due to the formation of alpha-calcium
silicate. For pressure, the loss of compressive strength was
greater at increased pressure. Formation of CaCO3 was
observed can increase the compressive strength of cement
sample. Greater carbonation in wet supercritical CO2, slow
down the reduction in strength as compared to CO2-saturated
brine. This carbonation can give a temporary strength but
cannot be guaranteed for the long term exposure. Same goes
to the depth of penetration, although it can be seen in a very
little value for this short term of CO2 exposure, it will possibly
destroying zonal isolation in a long period since the depth of
penetration kept increasing by time. As such, it is important to
study these cement behaviors on supercritical CO2 attack in
order to find a great solution for CO2 resistance cement
additive that has been major concerns of many researchers
nowadays.
APPENDIX [I] A. Before CO2 Attack at Constant Pressure and Different
Temperature Conditions
Fig. 4. Sample cured at 40
0C
Fig. 5. Sample cured at 120
0C
B. Before CO2 Attack at Constant Temperature and Different Pressure Conditions
Fig. 6. Sample cured at 105 bar
International Journal of Engineering & Technology IJET-IJENS Vol:10 No:04 52
107704-2929 IJET-IJENS © August 2010 IJENS
I J E N S
Fig. 7. Sample cured at 140 bar
APPENDIX [II] A. Degradation at the rim of oil well cement after 120 hours of
Supercritical CO2 exposure in brine solution at constant
pressure and different temperature:
Fig. 8 Sample exposed at 40
0C
Fig. 9. Sample exposed at 120
0C
B. Degradation at the rim of oil well cement after 120 hours of
Supercritical CO2 exposure in brine solution at constant
temperature and different pressure:
Fig. 10. Sample exposed at 105 bar
Fig. 11. Sample exposed at 140 bar
C. Degradation at the rim of oil well cement after 120 hours of
CO2-saturated brine and wet supercritical CO2 exposure at
pressure of 140 bar and 400C:
Fig. 12. Sample exposed in CO2-saturated brine
International Journal of Engineering & Technology IJET-IJENS Vol:10 No:04 53
107704-2929 IJET-IJENS © August 2010 IJENS
I J E N S
Fig. 13. Sample exposed in wet supercritical CO2
APPENDIX [III]
Fig. 14. Depth of penetration evolution against exposure duration at constant
temperature, 400C and constant pressure, 140 bar
APPENDIX [IV]
Fig. 15. Compressive strength evolution against exposure duration at constant
temperature, 400C and constant pressure, 140 bar
APPENDIX [V]
Fig. 16. Calcium content evolution after 120-hour of CO2 attack at constant
temperature, 400C and constant pressure, 140 bar
APPENDIX [VI]
Fig. 17. Silica content evolution after 120-hour of CO2 attack at constant
temperature, 400C and constant pressure, 140 bar
CONSTANT
TEMPERATURE
CONSTANT
PRESSURE
CONSTANT
TEMPERATURE
CONSTANT
PRESSURE
CONSTANT
TEMPERATURE
CONSTANT
PRESSURE
CONSTANT
TEMPERATURE
CONSTANT
PRESSURE
International Journal of Engineering & Technology IJET-IJENS Vol:10 No:04 54
107704-2929 IJET-IJENS © August 2010 IJENS
I J E N S
APPENDIX [VII]
Fig. 18 Mass evolution against exposure duration at constant temperature,
400C and constant pressure, 140 bar
APPENDIX [VIII]
Fig. 19. pH evolution against exposure duration at constant temperature, 40
0C
and constant pressure, 140 bar
NOMENCLATURE α = constant related to the rate of diffusion of ionic species API = American Petroleum Institute BSE-SEM = BackScattered Electron Scanning Electron Microscopy
Ca2SiO4 = Dicalcium Silicate Ca3SiO5 = Tricalcium Silicate Ca3Al2O6 = Tricalcium Aluminate
Ca4Al2Fe2O10 = Tetracalcium Aluminoferrite CaCO3 = Calcium Carbonate
Ca(OH)2 = Calcium Hydroxide Ca(HCO3)2 = Calcium Bicarbonate CO2 = Carbon Dioxide C-S-H = Calcium Silicate Hydrate gels
EDX = Energy-dispersive X-Ray Spectroscopy ECBM = Enhanced Coal Bed Methane Recovery EGR = Enhanced Gas Recovery EOR = Enhanced Oil Recovery
H2CO3 = Carbonic Acid H2O = Water L = Depth of Carbonation (mm) SEM = Scanning Electron Microscopy
t = T ime of Exposure (hr) XRD = X-Ray Diffraction
ACKNOWLEDGMENT
The authors thank to Lafarge Malaysia for the contribution of
Class G cement for this research.
REFERENCES [1] V.Barlet-Gouedard and G. Rimmele, “Mitigation Strategies for the
Risk of CO2 Migration Through Wellbores”, paper SPE 98924
presented at the IADC/SPE Drilling Conference held in Miami, Florida, U.S.A, 21-23 February 2006.
[2] Glen Benge, SPE, ExxonMobil, “Improving Wellbore Seal Integrity in CO2 Injection Wells”, paper SPE 119267 presented at the SPE/IADC
Drilling Conference and Exhibition held in Amsterdam, The Netherlands, 17-19 March 2009.
[3] Jose Condor, Koorosh Asghari, “Experimental Study of Stability and Integrity of Cement in Wellbores Used for CO2 Storage”, Elsevier,
2009. [4] Barbara G.Kutchko, Brian R. Strazisar, David A. Dzombak, Gregory
V. Lowry, Niels Thaulow, “Degradation of Well Cement by CO2 under Geologic Sequestration Conditions”, Environ. Sci. Technol.
2007. [5] D.D Onan, Halliburton Services “ Effects of Supercritical Carbon
Dioxide on Well Cements”, paper SPE 12593 presented at the 1984 Permian Basin Oil & Gas Recovery Conference held in Midland, TX,
March 8-9, 1984. [6] Julian Cooper, “Wellbore Integrity…” Say What??”, Kinkaid School
Class 2010, USA, Elsevier 2009.
[7] V. Barlet-Gouedard*, G.Rimmele1, O.Porcherie
1, N.Quisel
1,
J.Desroches1, “A solution against well cement degradation under CO2
geological storage environment”, Schlumberger Riboud Product Centre (SRPC), 1 rue Becquerel, BP 202, 92142 Clamart Cedex, France,
Elsevier 2009. [8] Emilia Liteanu*, Christopher J. Spiers, Colin J. Peach, “Failure
behavior wellbore cement in the presence of water and supercritical CO2”, Utrecht University, Faculty of Geosciences, HPT Laboratory,
Budapestlaan 4, Utrecht, 3584 CD, The Netherlands, Elsevier 2009. [9] Recommended Practice for Testing Well Cements, ANSI/API
Recommended Practice 10B-2 (Formerly 10B), First Edition, July 2005.
[10] Barbara G. Kutchko, Brian R. Strazisar, Gregory V. Lowry, David A. Dzombak, and Niels Thaulow, “Rate of CO2 Attack on Hydrated Class H Well Cement under Geologic Sequestration Conditions”, U.S
Department of Energy, National Energy Technology Laboratory, Pittburgh, Received January 7, 2008, Revised manuscript received April 18, 2008. Accepted June 3, 2008.
[11] George W. Scherer, Michael A. Celia, Jean-Herve Prevost, Andrew
Duguid, “Leakage of CO2 Through Abandoned Wells: Role Of Corrosion Of Cement”, Carbon Dioxide Capture for Storage in Deep Geologic Formations, Volume 2, 2005.
[12] Fred L. Sabins & David L. Suttons, “The relationship of Thickening
T ime, Gel Strength and Compressive Strength of Oilwell Cements”, SPE, Halliburton Services, March 1986.
CONSTANT
TEMPERATURE
CONSTANT
PRESSURE
CONSTANT
TEMPERATURE
CONSTANT
PRESSURE
International Journal of Engineering & Technology IJET-IJENS Vol:10 No:04 55
107704-2929 IJET-IJENS © August 2010 IJENS
I J E N S
[13] Gaetan Rimmelea.*, Veronique Barlet-Gouedard
a, Olivier Porcherie
a,
Bruno Goffeb, Fabrice Brunet
b, “Heterogeneous porosity distribution in
Portland cement exposed to CO2-rich fluids”, aSchlumberger Riboud
Product Center, Well Integrity Technologies, 1 rue Henri Becquerel, BP 202, 92142, Clamart, France.
bEcole normale superieure, CNRS,
Laboratoire de Geoogie, 24 rue Lhmond, 75005, Paris, France,
Elsevier 2008. [14] O. Brandvoll
a*, O.Regnault
a, I.A. Munz
a, I.K. Iden
a,H.Johansen
a,
“Fluid – solid interactions related to subsurface storage of CO2 Experimental tests of well cement”, Institute for Energy Technology,
P.O Box 40, Kjeller NO-2027, Norway, Elsevier 2009. [15] Spycher, N., Pruess, K., CO2-H20 mixtures in the geological
sequestration of CO2. II. Partitioning in chloride brines at 12 – 100oC
and up to 600 bar. Geochimica et Cosmochimica Acta 69 (13), 3309-
3320, 2005. [16] Jeffrey J. Thomas, David Rothstein, Hamlin M. Jennings, Bruce J.
Christensen, Effect of hydration temperature on the solubility behavior
of Ca-, S-, Al-, and Si-bearing solid phases in Portland cement pastes, Received 18 December 2002; accepted 27 June 2003
[17] Dwight K.Smith, Cementing, Monograph Volume 4, SPE,1989.
International Journal of Engineering & Technology IJET-IJENS Vol:10 No:04 56
107704-2929 IJET-IJENS © August 2010 IJENS
I J E N S