Effects of Pressure and Temperature on Well Cement ... - CiteSeerX

International Journal of Engineering & Technology IJET-IJENS Vol: 10 No: 04

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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 twoexposure 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), Energydispersive 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 CO2saturated brine exposure compared to wet supercritical CO2. Index Terms – Supercritical CO2, brine, alteration, compressive strength, curing.

I. INTRODUCTION

O

ILWELL 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), and tetracalcium tricalcium aluminate (Ca3Al2O6), 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

International Journal of Engineering & Technology IJET-IJENS Vol: 10 No: 04 II. EXPERIMENTAL METHODOLOGY

following to explain the CO2 attack to these main products in the form of carbonic acid [2]: A. CO2 dissociation: CO2 + H2O → H2CO3

(1)

Cement Carbonation: H2CO3 + Ca(OH)2 → CaCO3 C-S-H + H2CO3 → CaCO3+amorphous silica

(2) (3)

Calcium Carbonate dissolution: CaCO3 + H2CO3 → Ca(HCO3)2 Ca(HCO3)2 + Ca(OH)2 → 2CaCO3 + H2O

(4) (5)

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.

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 CO2saturated water as Barlet et al [1] did at different pressure and temperature conditions.

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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 1. TABLE 1 TEMPERATURE AND PRESSURE VARIATION USED

Constant Pressure (140 bar) Temperature (0C)

Constant Temperature (400C)

40

Pressure

105

120

(bar)

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 1. 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.

International Journal of Engineering & Technology IJET-IJENS Vol: 10 No: 04 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. 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 CS-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

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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 silica 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 24hours 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 120hours 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 24hours. 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

International Journal of Engineering & Technology IJET-IJENS Vol: 10 No: 04 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]. 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 6weight% 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 72hours exposure prior to slightly depletion at 0.5% after 120hours 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.

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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.

International Journal of Engineering & Technology IJET-IJENS Vol: 10 No: 04

Fig. 2 Different colour of ring between cement exposed to wet supercritical CO2 and CO2-Saturated Brine.

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. 3 Alteration at the rim of cement thin section under different exposure durations for cement samples exposed to wet supercritical CO2 and CO2Saturated 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.

Fig. 4 Sample cured at 400C

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

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Fig. 5 Sample cured at 1200C

International Journal of Engineering & Technology IJET-IJENS Vol: 10 No: 04 B.

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Before CO2 Attack at Constant Temperature and Different Pressure Conditions

Fig. 9 Sample exposed at 1200C Fig. 6 Sample cured at 105 bar

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. 7 Sample cured at 140 bar

APPENDIX [II] A.

Fig. 10 Sample exposed at 105 bar

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. 11 Sample exposed at 140 bar Fig. 8 Sample exposed at 400C

International Journal of Engineering & Technology IJET-IJENS Vol: 10 No: 04 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:

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APPENDIX [III]

CONSTANT TEMPERATURE

CONSTANT PRESSURE

Fig. 12 Sample exposed in CO2-saturated brine Fig. 14 Depth of penetration evolution against exposure duration at constant temperature, 400C and constant pressure, 140 bar

APPENDIX [IV]

CONSTANT PRESSURE

Fig. 13 Sample exposed in wet supercritical CO2


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

International Journal of Engineering & Technology IJET-IJENS Vol: 10 No: 04 APPENDIX [VII]

APPENDIX [V]

CONSTANT PRESSURE CONSTANT TEMPERATURE

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

APPENDIX [VI]


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CONSTANT PRESSURE

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

APPENDIX [VIII]

CONSTANT PRESSURE


CONSTANT PRESSURE

Fig. 17 Silica content evolution after 120-hour of CO2 attack 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

International Journal of Engineering & Technology IJET-IJENS Vol: 10 No: 04 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 = Time of Exposure (hr) XRD = X-Ray Diffraction

[11]

[12] [13]

[14]

[15]

[16]

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.Porcherie1, N.Quisel1, 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

[17]

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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. 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. Fred L. Sabins & David L. Suttons, “The relationship of Thickening Time, Gel Strength and Compressive Strength of Oilwell Cements”, SPE, Halliburton Services, March 1986. 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 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. 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 Technology, P.O Box 40, Kjeller NO-2027, Norway, Elsevier 2009. 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), 33093320, 2005. 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 Dwight K.Smith, Cementing, Monograph Volume 4, SPE,1989.