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Effects of Pressure and Temperature on Well Cement Degradation by Supercritical CO 2


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Effects of Pressure and Temperature on

Well Cement Degradation by Supercritical CO


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 S peed 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 BackS cattered Electron of S canning Electron Microscopy (BS E-S EM), Energy-dispersive X-Ray S pectroscopy (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. S ame 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


Index Term– Supercritical CO2, brine, alteration, compressive

strength, curing.


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 s ome 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


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 diss ociation 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.


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.



Constant Pressure (140 bar) Constant T emperature (400 C)

T emperature (0C)

40 Pressure



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


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


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.


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.


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 120


C 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


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 s amples 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. 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



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 streng th 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.


A. Before CO2 Attack at Constant Pressure and Different

Temperature Conditions

Fig. 4. Sample cured at 400C

Fig. 5. Sample cured at 1200C

B. Before CO2 Attack at Constant Temperature and Different

Pressure Conditions


Fig. 7. Sample cured at 140 bar


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 400C

Fig. 9. Sample exposed at 1200C

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. 13. Sample exposed in wet supercritical CO2


Fig. 14. Depth of penetration evolution against exposure duration at constant temperature, 400C and constant pressure, 140 bar


Fig. 15. Compressive strength evolution against exposure duration at constant temperature, 400C and constant pressure, 140 bar


Fig. 16. Calcium content evolution after 120-hour of CO2 attack at constant temperature, 400C and constant pressure, 140 bar


Fig. 17. Silica content evolution after 120-hour of CO2 attack at constant temperature, 400C and constant pressure, 140 bar










Fig. 18 Mass evolution against exposure duration at constant temperature, 400C and constant pressure, 140 bar


Fig. 19. pH evolution against exposure duration at constant temperature, 400C and constant pressure, 140 bar


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 = T ricalcium 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


The authors thank to Lafarge Malaysia for the contribution of Class G cement for this research.


[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, T he 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 T haulow, “Degradation of Well Cement by CO2 under Geologic Sequestration Conditions”, Environ. Sci. T echnol. 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, T X, 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.Porcherie1, N.Quisel1, J.Desroches1, “A solution against well cement degradation under CO

2 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, T he Netherlands, Elsevier 2009. [9] Recom m ended Practice for Testing Well Cem ents, ANSI/API Recom m ended Practice 10B-2 (Form erly 10B), First Edition, July 2005.

[10] Barbara G. Kutchko, Brian R. Strazisar, Gregory V. Lowry, David A. Dzombak, and Niels T haulow, “Rate of CO2 Attack on Hydrated Class H Well Cement under Geologic Sequestration Conditions”, U.S Department of Energy, National Energy T echnology 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 T hrough 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 T hickening T ime, Gel Strength and Compressive Strength of Oilwell Cements”, SPE, Halliburton Services, March 1986.





[13] Gaetan Rimmelea.*, Veronique Barlet -Gouedarda, Olivier Porcheriea, Bruno Goffeb, Fabrice Brunetb, “Heterogeneous porosity distribution in Portland cement exposed to CO2-rich fluids”, aSchlumberger Riboud Product Center, Well Integrity T echnologies, 1 rue Henri Becquerel, BP 202, 92142, Clamart, France. bEcole normale superieure, CNRS, Laborat oire de Geoogie, 24 rue Lhmond, 75005, Paris, France, Elsevier 2008.

[14] O. Brandvolla*, O.Regnaulta, I.A. Munza, I.K. Idena,H.Johansena, “Fluid – solid interactions related to subsurface storage of CO2 Experimental tests of well cement”, Institute for Energy T echnology, 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. T homas, 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



Fig. 2.  Different colour of ring between cement exposed to wet supercritical  CO2 and CO2-Saturated Brine
Fig. 4.  Sample cured at 400C
Fig. 11. Sample exposed at 140 bar
Fig.  16. Calcium content evolution after 120-hour of CO2 attack at constant temperature, 400C and constant pressure, 140 bar


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