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CO2 stability of Portland cement based well cementing systems for use on carbon capture & storage (CCS) wells
Cement and Concrete Research 45 (2013) 45–54
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CO2 stability of Portland cement based well cementing systems for use on carbon capture & storage (CCS) wells M. Lesti, C. Tiemeyer, J. Plank ⁎ Technische Universität München, Chair for Construction Chemicals, 85747 Garching, Lichtenbergstr. 4, Germany
a r t i c l e
i n f o
Article history: Received 23 February 2012 Accepted 5 December 2012 Keywords: Corrosion Carbonation (C) Long-term performance (C) Permeability (C) Oil well cement (D)
a b s t r a c t Three Portland cement based systems formulated with specific inorganic particles and organic admixtures were tested against conventional API Class G oil well cement with respect to CO2 tolerance. Hardened specimens (30×50 mm) were prepared and stored under supercritical CO2 (90 °C/400 bar) for one and six months, respectively. CO2 ingress was probed via phenolphthalein test and thermogravimetry. In all samples, formation of different CaCO3 modifications was observed, proving carbonation. Carbonation rates were relatively low and similar, except for one sample. Most detrimental was cracking of specimens as a result of massive CaCO3 formation which comes along with expansion. Best CO2 resistance was obtained from a slag cement (CEM III) blended with a reactive filler which can bind large quantities of portlandite, and by providing pore space in the cementitious matrix for growing of CaCO3. The addition of latex polymers or of other organic admixtures did not provide much improvement over conventional API oil well cement. © 2012 Elsevier Ltd. All rights reserved.
1. Introduction As an alternative to reducing CO2 emissions, already back in 1977 Marchetti proposed to capture carbon dioxide from the exhaust streams of coal power plants and then store it subterraneously in suitable geological formations [1]. Following his idea, this concept of geological storage of CO2 was explored further [2,3]. Depleted oil and gas reservoirs, deep saline aquifers and unminable coal beds were identified as preferential storage formations [4]. An important criteria for the feasibility of geological CO2 disposal is that no leakage must occur over time periods of several hundred years. For example, in Germany it was proposed that potential disposal sites must guarantee sealing quality for at least 1000 years, to avoid any safety risk for the population. By the end of 2010, well over 200 CCS (“carbon capture & storage”) projects were active or planned worldwide, and substantial field experience has been gained with this technology [5]. Geological disposal of CO2 requires to drill and cement wellbores through which liquid supercritical CO2 (scCO2) is injected. There are multiple pathways that CO2 may use to migrate and escape from the reservoir. Apart from leakage through the capping formation, it may ascend through the cement sheath surrounding the wellbore casing or through the cement plug which caps the well. Conventional oil well cements (e.g. the types API Class G and H) are based on Portland cement technology [6]. However, Portland cement is known to be degraded by CO2 [7]. As a result, many studies have been performed to evaluate the stability of oil well cements against CO2 under wellbore ⁎ Corresponding author. Tel.: +49 89 289 13151; fax: +49 89 289 13152. E-mail address: [email protected] (J. Plank). 0008-8846/$ – see front matter © 2012 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.cemconres.2012.12.001
conditions. Also, in conventional oil production, cement can be exposed to CO2 in multiple ways. For example, Duguid studied the degradation of oil well cements exposed to carbonated brines occurring in some reservoirs [8]. In this article, he summarized the findings of several other groups which report about multiple reactions occurring between CO2 and well cement [7,9–16]. The CO2 attack starts with carbonation of calcium hydroxide (portlandite) which is formed by hydration of the silicate phases C3S and C2S. Once all portlandite is consumed, then even the calcium silicate hydrates (C-S-H phases) which constitute the main solid matrix of hardened cement and provide its strength, are decomposed into CaCO3 and silica gel [8]. These corrosion reactions are shown in Eqs. (1) and (2). CaðOHÞ2ðaqÞ þ CO2ðaqÞ →CaCO3 þ H2 O Portlandite
ð1Þ
Cx SHy þ xCO2ðaqÞ →xCaCO3 þ SiO2 ⋅ yH2 O C−S−H phases:
ð2Þ
According to this, CO2 and in particular the considerably more aggressive scCO2 (“super critical CO2”) can affect wellbore integrity in two different ways [14]: CaCO3, which initially densifies the cementitious matrix and reduces its permeability and porosity, thus constituting a positive process with respect to the sealing quality of the cement, can be dissolved in CO2 saturated water as Ca(HCO3)2(aq) (Eq. (3)). Unfortunately, most oil and gas reservoirs contain saline reservoir fluids, hence any CO2 injected will contain water. Second, once all portlandite has been carbonated, then the remaining silicate-based matrix will be converted into products of poor strength
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(SiO2·y H2O or CaCO3). The consequence of this process is gradual dissolution of major parts of the cement sheath, loss of wellbore integrity and ultimately leakage of CO2. CaCO3 þ CO2ðaqÞ þ H2 O→CaðHCO3 Þ2ðaqÞ insoluble dissolved:
ð3Þ
For decades, scCO2 has been injected in producing oil wells as an EOR (“enhanced oil recovery”) measure to maintain reservoir pressure. Additionally, there are some natural CO2 producing wells. There, the CO2 produced is utilized in industrial applications, mainly in oil field operations. From there, long-term field experience on cements exposed to supercritical CO2 exists. For example, Crow et al. studied cement core samples retrieved from a natural CO2 producing well in Dakota sandstone formation [17]. X-ray diffraction analysis of samples taken in direct proximity of the reservoir (~6 m) showed almost complete conversion of portlandite to calcium carbonate. Additionally, an increase in porosity and permeability was found. Samples recovered at further distance from the reservoir (~50 m) and at the top of the caprock had retained most of their original cement mineral composition and were carbonated only slightly. This example demonstrates that even within the relatively short time span of 30 years, at first significant carbonation can occur near the reservoir which is followed later by increased porosity due to dissolution of CaCO3 as Ca(HCO3)2. These negative experiences are contradicted by another field experience from CO2 injection wells in the Permian basin of West Texas [18]. There, cores retrieved from downhole (~3.5 m above the reservoir) composed of ordinary oil well cement which had been exposed to scCO2 showed only minor carbonation. As a result, serious dispute evolved whether or not conventional API oil well cement is stable enough against CO2 and can be used for CCS wells. Very recently, some researchers developed models taking cement permeability, CO2 diffusion rates and typical wellbore depths (length of migration path to surface) into account [19]. They conclude that for well depths below 2000 m, the risk of leakage is negligible over a time span of several hundred years. Another risk analysis was performed by Loizzo et al. [20]. They calculated that possibly 20% of all wells may be leaking at some point of their life. Most of those leaks will be insignificant and thus will not affect the population or the environment. However, according to the authors still less than two out of 1000 wells will have major leakage, which is unacceptable. Other authors report that approx. half of the leaks may not end up at the wellhead [21]. These examples demonstrate the complexity of the subject which is under high scrutiny from the public and governmental institutes. Common oil well cementing formulations include numerous chemical additives to control the set behavior (retarders), water loss (fluid loss additives), pumpability (dispersants/superplasticizers) and permeability (film forming latex polymers) [22]. The specific influence of all those additives on CO2 resistance of well cements has not yet been investigated sufficiently. In particular, any measure which can lower the permeability of hardened cement or a polymer coating deposited on cement minerals should enhance the lifetime of cement exposed to scCO2 [16]. The first effect can be achieved by simply reducing the water-to-cement ratio, thus reducing the capillary pores. However, this approach has two disadvantages. First, while it can slow down the reaction rate considerably, it does not produce a Portland cement which no longer is susceptible to degradation by CO2 [23]. Second, not all wellbores can tolerate the high hydrostatic pressure instigated by high density cement slurries [16]. An alternate method to reduce cement permeability is the incorporation of special additives such as latex polymers or pozzolans (e.g. fly ash) which fill the pore spaces in the hardened cement matrix. Another concept is to completely eliminate cement constituents which are potential reactants for CO2. This approach involves the use of special binders such as calcium sulfoaluminate cement, geopolymer-based cement, calcium aluminate-phosphate
cement [24,25], magnesium oxide cement and hydrocarbon-based cement [16,23]. However, it would take many years of laboratory research work and field testing to adjust such radically new cements to the harsh conditions of deep wellbores, and to acquire suitable equipment which allows their routine practical use. Here, an attempt was made to formulate conventional API Class G oil well cement with admixtures in such a way that its gas permeability was reduced. Four cementing formulations, designated as cementing systems A–D, which included various chemical and mineral additives which are required in actual field use (e.g. for sufficient pumping time, low rheology, low water loss, no free water/bleeding) were prepared, stored at atmospheric conditions for two weeks and cured for 28 days at 90 °C under 400 bar N2 pressure. Subsequently, the hardened cylindrical specimens (d= 30 mm, h = 50 mm) were stored under supercritical carbon dioxide at 400 bar and 90 °C in 4 L autoclaves. After 1 and 6 months exposure times, the samples were characterized by visual analysis, thermogravimetry (content of CO2 bound) and measurement of permeability, porosity and compressive strength. From these data it was aimed to identify cementing systems and specific additives which can help to improve the CO2 resistance of conventional oil well cements. 2. Materials and methods 2.1. Materials 2.1.1. Cement formulations Four cementing systems using different approaches to enhance CO2 resistance were employed in this study. All cements contained salt (NaCl) to account for salt-bearing reservoir fluids which are most common in the oil fields of Lower Saxony, Germany. All cementing systems were based on a commercially available API oil well cement and formulated by the industry partners to meet the specific slurry property requirements which guarantee applicability under actual field conditions. Those include: for slurry rheology n and k values (according to the Power-Law model; for calculation of values see Eq. (4) [26]) of 0.8–1.0 and 0.2–1.3 respectively; API static fluid loss values at 80 °C/70 bar: b200 mL (except for cementing system B which was not adjusted for fluid loss control) and API free water content b 4 mL. Individual parameters for each cement slurry were collected, but are not shown here. n
τ ¼ k⋅γ
ð4Þ
whereby τ is the shear stress (Pa); k the consistency index (Pa·s n); γ the shear rate (s −1) and n the Ostwald index. Cementing system A contained inorganic, CO2 resistant particles of such specific grading as to fill the pore space in the cement matrix as much as possible and thus decrease its permeability against CO2. It was composed of 709.42 g cement blended with the inorganic material, 33.75 g sodium chloride (17% by weight of water, bwow), three different liquid admixtures and 205.13 g DI (deionized) water (w/s ratio = 0.25). The resulting cement slurry possessed a density of 1.91 kg/L. Cementing system B was based on a commercial CEM III/B 42.5 LH/HS/NA cement which was further blended with a specific type of fly ash (electro filter ash, also referred to as EFA filler) in such a way as to reduce the CaO:SiO2 weight ratio from 1.0 present in the original CEM III cement to 0.53 in the blend. This excess SiO2 reacts with Ca(OH)2(aq) released during hydration of this cement. This way, no portlandite is available to react with scCO2. The cement slurry consisted of 1351 g cement blend, 108 g sodium chloride (22% bwow), a solid retarder admixture and 501 g DI water (w/s ratio = 0.37). The slurry density was 1.82 kg/L. It should be noted here that cementing system B was relatively difficult to mix as a result of higher viscosity caused by the fine particulate filler material.
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The concept of cementing system C (density = 1.91 kg/L) was based on pore plugging by film formation from organic latex particles. This polymer-modified cement slurry incorporated seven chemical admixtures and was formulated as follows: 1350 g cement blend, 79.2 g sodium chloride (25% bwow), two dry admixtures (retarder, dispersant), four liquid admixtures (e.g. latex dispersion and defoamer) and 316.2 g DI water (w/s= 0.33). Cementing system D was used as reference sample. It was prepared from conventional API Class G oil well cement (type “black label” from Dyckerhoff AG, Werk Lengerich/Germany) and contained no specific additive to alter cement properties. The oxide composition of this cement as measured by XRF is given in Table 1. The slurry was prepared from 1280 g cement, 110 g sodium chloride (20% bwow), two dry (dispersant, water retention additive) and one liquid admixture (retarder) to control rheology, set time and water loss, and of 550 g DI water (w/c ratio = 0.43; density = 1.96 kg/L). 2.1.2. Preparation of synthetic reservoir fluid Curing of the cement samples was performed in a synthetic reservoir fluid. This liquid simulates the electrolyte contents which typically occur in an abandoned oil well in Northern Germany which was considered for actual CO2 disposal. In a 20 L stirred glass reactor, 13,100 g DI water were mixed in this order with 4169 g NaCl, 467 g CaCl2·2 H2O, 220 g MgCl2·6 H2O, 10.6 g K2SO4 and 9 g KCl (see Table 2). 2.2. Preparation of cement samples The preparation of cementing system A was carried out employing a modified test procedure (longer mixing time; lower shear rates) as set forth in Recommended Practice for Testing Well Cements, API Recommended Practice 10 B, issued by the American Petroleum Institute [26]. Cementing systems B, C and D were prepared applying a procedure established by the industrial project partners which deviated significantly from the one described in the API norm. The slurries of cementing system A were mixed using a blade-type laboratory blender manufactured by Waring Products Inc. (Torrington/ CT, USA). First, NaCl was dissolved in DI water by stirring for 2 min at 1500 rpm. Next, the liquid admixtures were added and stirred for 5 s at 4000 rpm. Within the next 30 s, the cement blend was added and then stirred for additional 5 min at 4000 rpm. Cementing systems B–D were prepared by using a propeller-type mixer model Eurostar digital (manufactured by IKA, Staufen, Germany) instead of the Waring blender specified by API RP 10B norm. The admixtures were added one by one to DI water and dissolved (stirring time for each liquid admixture: 1 min.; for each solid admixture: 3 min.; stirring speed: 200 rpm). After completion of additions, mixing was continued for additional 8 min at 300 rpm. Then, within 30 s, the cement was added and the resulting slurry was stirred for another 10 min at 300 rpm. Table 1 Oxide composition of the API Class G (“black label”) cement sample, as measured by XRF. Oxide
Content (wt.%)
CaO SiO2 Al2O3 Fe2O3 MgO TiO2 P2O5 Na2O K2O SO3 SrO Loss of ignition Total
62.20 21.90 4.18 4.86 0.95 0.18 0.12 0.15 0.67 2.22 0.17 1.50 99.28
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Table 2 Ion concentrations contained in the synthetic reservoir fluid used for curing the cement samples. Ions/salinity
Concentration (g/L)
Sulfate (SO42−) Sodium (Na+) Potassium (K+) Calcium (Ca2+) Magnesium (Mg2+) Chloride (Cl−) Total salinity
0.39 110.24 0.64 8.53 1.74 188.04 309.60
Subsequent to mixing, all cement slurries were cast into cylindrical plastic containers (diameter 30 mm, height 50 mm) and cured in the synthetic reservoir fluid under atmospheric conditions for two weeks to achieve full saturation. After this, the plastic containers were removed and the cement cores were cured for another 28 days at 90 °C and 400 bar pressure in the synthetic reservoir fluid. For this high pressure/high temperature curing, 8 L stainless steel autoclaves manufactured by Parr Instrument Company (Moline/IL, USA) were used. 2.3. Carbonation experiment The cured samples were exposed to CO2(aq) in both liquid and gaseous environment using the following experimental setup and procedure. Static (non-stirred) conditions were considered to present a more realistic simulation of CO2 exposure conditions occurring in an actual CCS well. A total of 24 pre-cured cement specimens were placed on a stainless steel rack as shown in Fig. 1 and then placed in 4 L stainless steel autoclaves (Parr Instrument Company, Moline/IL, USA). The autoclaves were then half filled with the synthetic reservoir fluid, thus the top samples were stored in a supercritical CO2 gas atmosphere saturated with water vapor while the bottom samples were immersed in CO2 saturated reservoir fluid (liquid phase). The carbonation experiments were performed for 1 and 6 months respectively at a temperature of 90 °C and a CO2 pressure of 400 bar. Under those conditions, carbon dioxide in the gas phase is in a supercritical state and very reactive to cement. For reference, a second series of samples was prepared from all cementing systems and stored under the same conditions, but using nitrogen instead of scCO2 in the second curing. 2.4. Visualization of carbonation The samples exposed to scCO2 were retrieved from the autoclave after careful decompression over a total period of 22 h, then photographed to document their visual appearance, and cut with a diamond saw into two equal halves. Their inner face was sprayed on using a 1 wt.% aqueous phenolphthalein solution to test for alkalinity. From this, the carbonated zone (ingress of CO2) was determined. 2.5. Thermogravimetry TG measurements were conducted using a NETZSCH TG 209 system (Netzsch-Gerätebau GmbH, Selb, Germany) equipped with a mass spectrometer for the identification of decomposition products (here: CO2(g)). 2.6. Compressive strength First, the cured cement samples were treated with gypsum paste to achieve absolutely planar surfaces. After hardening of the gypsum, the cylinders were tested according to DIN EN 12390-4 on a Toni NORM instrument (Toni Technik, Berlin, Germany). The data presented is the arithmetic average of 3 cement samples.
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Fig. 1. Experimental setup for scCO2 storage of cement specimens; left and middle: 4 L autoclaves; right: stainless steel rack employed to hold the cement specimens placed in the autoclave.
2.7. Porosity
3.2. Cracking of samples
Porosity and pore size distribution of the cured cement samples were measured employing a mercury intrusion porosimeter (Poremaster60, Quantachrome GmbH & Co. KG, Odelzhausen, Germany). This instrument is capable of detecting pore sizes from 3 nm to 360 μm. For preparation, the cylindrical samples were crushed, ~0.3–0.4 g pieces were obtained and dried for 34 h at 105 °C prior to measurement.
Massive crack formation was observed in samples prepared from cementing systems C and D after 6 months storage under CO2 (Fig. 3). The samples of cementing system C were destroyed completely and only fragments of the samples could be retrieved after storage in the liquid phase. Cementing system D prepared from neat API Class G oil well cement also showed significant cracking after exposure in both liquid and gas phase, however less severe than in the cement sample C. These cracks immediately provide pathways for further migration and spread of CO2, thus presenting a threat for cement seal integrity. Cracking is the result of CaCO3 formation from Ca(OH)2(aq) and CO2(g) which is associated with a volume expansion of ~ 11% [27]. During its crystallization, CaCO3 can fracture the cement matrix due to its crystallization pressure. Very recently, Fabbri et al. presented a model describing the correlation between the porosity of an oil well cement matrix and the probability of crack formation as a result of carbonation [28]. They conclude that upon carbonation, low cement porosity (which is characteristic for oil well cements) will lead to increased cracking of the matrix. This aspect will be discussed in greater detail below.
2.8. Gas permeability Permeability against air was measured at Westphal Präzisionstechnik GmbH (Celle, Germany) using a Fachner-type cell Modell RIEKMANN (Westphal Präzisionstechnik GmbH, Celle, Germany). Here, wet, nondried cement samples (entire cylinders, except for cementing systems C and D where fragments of the cylinders were tested) as retrieved from the autoclave were employed. 3. Results and discussion 3.1. Visual appearance of scCO2 exposed samples
3.3. Phenolphthalein test The visual appearance of the cement samples stored for 1 and 6 months, respectively, in scCO2 and CO2 saturated brine is displayed in Fig. 2. After one month of CO2 exposure, no major effect on the cement samples (e.g. cracking) was visible. On some specimens, salt crusts were present on their surface, as was evidenced by XRD measurement. After six months exposure, the specimens from cementing system A (both in gas and liquid phase) showed a rough surface, similar to that of porous sandstone, thus indicating substantial leaching of CaCO3 as soluble Ca(HCO3)2(aq) from the matrix (Fig. 2). For cementing system B, no impact of CO2 on the visual appearance was apparent. However, cracks were observed on specimens prepared from cementing systems C and D stored in the liquid phase, and from cementing system D stored in the gas phase. These preliminary observations suggest that cementing systems A, C and D are attacked by CO2 whereas cementing system B is more resistant to CO2.
The depth of CO2 ingress was determined by using the phenolphthalein test. Generally, no differences between samples stored in the gas phase (water saturated CO2 atmosphere) and the liquid phase (reservoir fluid containing CO2) were detected. Therefore, only photographs of samples stored in the gas phase are displayed in Fig. 4. For cementing system A, after only one month of storage the very high pH characteristic for portlandite was not present anymore, thus indicating complete carbonation of the sample. This cementing system contained a relatively low amount of binder and apparently is quickly carbonated. The slag cement/fly ash-based cementing system B showed a carbonation depth of 10 mm (~2/3 of core radius) whereas cementing systems C and D exhibited only small carbonation zones which were 3 mm for system C, and 0.5 mm for system D. Thus, it is demonstrated that after 1 month exposure, cementing systems C and D are less degraded by CO2 than the systems A and B.
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Fig. 2. Visual appearance of cement samples exposed to scCO2 in liquid phase (bottom) and gas phase (top) at 90 °C and 400 bar for 1 and 6 months, respectively (note: samples exhibiting a height of less than 50 mm had not shrunk, but were cut for other investigations).
After six months exposure, cementing systems A–C showed complete carbonation. Cementing system D maintained its alkalinity, but there, similar to the sample from cementing system C, multiple cracking was observed, apparently due to reaction with CO2. On cement sample A, the cut face had attained a rough appearance, with clearly discernible pores, as is shown in Fig. 4. The high pH characteristic for portlandite was not found anymore and only slight scratching resulted in substantial loss of a fine powder from the surface of the specimen. It appears that from this sample, most of the cementitious
matrix has been consumed by corrosion involving CO2, and the remaining CO2-resistant inorganic particles provide a poorly coherent matrix. It has been suggested that knowing the carbonation depth obtained after one month of sample exposure to CO2 allows to estimate the progression of the carbonation front after prolonged periods of time. Barlet-Gouédard et al. assume a linear correlation between the thickness of the carbonation front and the square root of exposure time [13]. Applying this model we calculated the spread
Fig. 3. Cracking of specimens prepared from cementing systems C and D after six months exposure to scCO2 at 90 °C and 400 bar.
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Fig. 4. Visual appearance of cement samples exposed to wet CO2 atmosphere at 90 °C and 400 bar for one and six months, respectively, after staining with phenolphthalein.
of the carbonation front in cementing systems B, C and D after a time period of 100 years. For cementing system B, carbonation would have moved ~35 cm while for cementing systems C and D a layer of only ~11 cm and ~2 cm would have been carbonated. According to this model, the carbonation front is moving very slowly through the cement samples tested (except for cementing system A). However, this result is contradicted by field experience from natural CO2 producing wells, as mentioned earlier [17]. One potential explanation is the occurrence of microchanneling and crack formation which is not considered in these calculations. With the aim to understand the differences in the behaviors of the cement samples, a series of analytical experiments was devised with the hope to understand the individual physico-chemical processes occurring under CO2 attack.
3.4. Quantification of CO2 uptake Utilizing thermogravimetry, the amount of CO2 which is chemically bound in the cementing systems before and after storage in CO2 was determined. For the specimens exposed for one month in the gas phase, measurements were taken from the outer zone and from the center of the sample. For the samples stored over six months, cores exposed to the gas phase as well as in the liquid phase were analyzed separately. Here, samples were taken from the carbonated zone only. The results are shown in Table 3. The reference sample of cementing system A which was cured under N2 and not exposed to CO2 contained no chemically bound CO2. After one month exposure to CO2, 5 wt.% of CO2 was taken up by the sample, both in the outer zone as well as at the center of the
Table 3 Amounts of chemically bound CO2 for different cement samples exposed to supercritical CO2 (T=90 °C, p=400 bar) over one and six months, respectively. Cementing system
A B C D
Chemically bound CO2 (wt.%) Reference sample (no CO2 exposure)
1 month CO2 gas phase (carbon. zone)
1 month CO2 gas phase (center of core)
6 months CO2 gas phase (carbon. zone)
6 months CO2 liquid phase (carbon. zone)
0 1 3 5
5 11 14 11
5 4 5 6
7 16 17 26
10 16 17 17
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sample. This signifies that carbonation had occurred throughout the entire cement specimen, as was shown before in the phenolphthalein test. Under continued exposure, carbonation proceeded further and after six months of storage, the amounts of chemically bound CO2 increased to 7 wt.% for the sample exposed in the gas phase and to 10 wt.% for the specimen stored in the liquid phase. Generally, the amount of CO2 bound by cement sample A is low. This is because cementing system A contains a relatively low amount of cement. For cementing system B, one mass percent of CO2 bound was detected in the reference sample. After one month of storage under CO2, the amount of carbon dioxide bound increased to 11 wt.% in the carbonated zone and to 4 wt.% at the center of the core. After six months exposure, a strong increase in the amounts of CO2 bound to 16 wt.% for both samples stored in the gas and liquid phase was experienced, indicating significant carbonation. The reference sample of cementing system C (no CO2 exposure) showed a high value of 3 wt.% for the amount of CO2. This was attributed to the presence of certain admixtures in this cementing system. After one month of CO2 exposure, a significant increase of CO2 bound was observed for the carbonated zone (14 wt.%), while at the center of the core only a slight increase to 5 wt.% was detected. This signifies that in this sample, carbonation progressed only slowly and had not reached the center of the core within one month. After six months of CO2 exposure, the entire cement sample was carbonated. Consequently, a high carbon dioxide content of 17 wt.% for both specimens stored in the gas and liquid phase was detected. The reference sample for cementing system D already showed elevated amounts of CO2 bound (5 wt.%) as a consequence of high loading with organic admixtures. After one month storage in CO2, the amount bound rose to 11 wt.% in the carbonated zone and to 6 wt.% at the center of the core. This indicates that also for this cementing system, carbonation proceeds rather slowly. After six months of exposure, the amounts of CO2 bound increased to 26 wt.% for the sample stored in the gas phase and to 17 wt.% for the specimen in contact with the brine, indicating massive carbonation in both cases.
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The large difference can plausibly be explained by the leaching of solid CaCO3 as soluble Ca(HCO3)2 into the reservoir fluid.
3.5. Compressive strengths For the reference samples stored under nitrogen, no differences in compressive strength after one or six months of storage time were observed. The compressive strengths measured after six month storage are shown in Fig. 5. All values obtained exceed by far the requirement for sufficient support of casing which lies around 5 MPa. The compressive strengths of cementing systems A and B were reduced drastically after exposure to CO2. No differences between samples stored in the liquid or the gas phase were observed. Obviously, the carbonates formed were already washed out either by the reservoir fluid or the water vapor present in the gas phase. Cementing systems C and D showed the opposite trend, namely an increase in compressive strength. Here, compressive strength was not measurable for the cylindrical specimens because the samples were broken into several pieces as a result of severe crack formation. When tested, these fragments showed low carbonation and therefore relatively high compressive strength values.
3.6. Cement porosity In hardened cement, pores represent channels in which CO2 can migrate from the bottom of the bore hole to the top. To ensure a low permeability of the cement seal, the hardened cement must have low porosity and small pore diameters. To investigate the effect of CO2 on porosity and pore size distribution of the hardened cement samples, mercury intrusion porosimetry experiments were conducted on specimens stored for one and six months respectively. Samples stored in the liquid as well as the gas phase were looked at separately. The results are shown in Fig. 6.
Fig. 5. Compressive strengths of cement samples exposed for six month to CO2 at 90 °C and 400 bar, stored in reservoir fluid (liquid phase) or in wet CO2 gas atmosphere; note that for cementing systems C and D, only pieces of the specimens could be tested, as a consequence of cracking.
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After one month exposure, cementing system A showed a significant increase in overall porosity from 19 vol.% to 34 vol.% (liquid phase) and 27 vol.% (gas phase) for the CO2 exposed specimens. Also, a shift to larger pore sizes was detected. This effect is plausibly due to proceeding carbonation and washout of Ca(HCO3)2. This process is not yet finished after one month of exposure. After six months, the number of large pores with sizes around 80 nm had increased further, while the overall porosity remained relatively constant at ~26 vol.%. The exposure of cementing system B to CO2 did not affect the porosity of the hardened sample which remained nearly constant at ~ 22–26 vol.% for all specimens. The pore sizes, however, showed a shift to higher diameters which signifies that soluble carbonates were formed and then washed out. Leaching was more pronounced for the samples stored in the liquid phase as is shown by the decrease of pores possessing a diameter of ~ 10 nm, compared to the samples stored in the gas phase. Cementing systems C (latex polymer cement) and D (non-modified reference system) exhibit a low porosity, even after six months of CO2 exposure (system C ~ 15 vol.%, system D ~ 14–20 vol.%). Only a very minor shift of the pore sizes to higher diameters was observed which is owed to the leaching of carbonates. To summarize, specimens prepared from cementing systems A and B showed increased porosity after CO2 exposure while samples from systems C and D exhibit low porosities. This data explains the
occurrence of cracks in cementing systems C and D while specimens from systems A and B were not affected. According to FABBRI et. al., low porosity values generally lead to increased crack formation [28]. For their growth, CaCO3 crystals need space for expansion which is provided in matrixes possessing high porosity. In cases where only limited pore space is available, the high crystallization pressure will fracture the solid matrix.
3.7. Gas permeability A key parameter for the tightness of hardened cement is the permeability against gas. Here, permeability of specimens with respect to CO2(g) was measured after exposure times of one and six months, respectively. Again, samples stored in the CO2-saturated reservoir fluid (liquid phase) and in water vapor saturated CO2 gas phase were looked at separately. The results are displayed in Table 4. The reference samples of all cementing systems showed gas permeabilities which are below the detection limit of 0.0001 mD. Such values demonstrate the initial extreme tightness of the cements against gas migration. After CO2 exposure, cementing system A showed increased permeability (0.0025 mD after one month and 0.089 mD after six months storage in the gas phase). This is due to
Fig. 6. Pore size distribution and porosity of cement samples stored under 400 bar scCO2 pressure at 90 °C for one month or six months, respectively, in synthetic reservoir fluid (liquid phase) or water vapor saturated CO2 gas phase.
M. Lesti et al. / Cement and Concrete Research 45 (2013) 45–54 Table 4 Gas permeabilities of four cementing systems after exposure to scCO2 in gas and liquid phase for 1 month and 6 months, respectively. Cementing system
Permeability (mD) Reference sample
1 month CO2 Liquid phase
1 month CO2 Gas phase
6 months CO2 Liquid phase
6 months CO2 Gas phase
A B C D
b0.0001 b0.0001 b0.0001 b0.0001
0.0083 b0.0001 0.0125 b0.0001
0.0025 b0.0001 0.109 0.307
b0.0001 0.0002 0.288 0.554
0.089 0.0016 0.0061 1.54
53
shrinkage and cracking due to dehydration by cement. As a consequence, flow paths can form which allow intruded CO2 to ascend much more quickly to the surface than through carbonation of the cementitious matrix. Such channeling possibly can pose a much more severe risk for leakage of CO2 than corrosion of the cement. To control this risk, best practices must be applied when cementing CCS wells which include for example pipe rotation when cement is pumped. Also, use of highly efficient spacer fluids to clean the wellbore from residual drilling mud is compulsory. Acknowledgments
increased porosities and larger pore sizes occurring in the carbonated cement samples. Similar effects were observed for the latex based cement and the non-modified API Class G cement (systems C and D, respectively). Only the gas permeability of the fly ash containing cementing system B is not affected by CO2 exposure. Here, no increase after a storage time of one month (gas permeability b 0.0001 mD) and only a slight increase in permeability after six months (liquid phase = 0.0002 mD, gas phase = 0.0016 mD) were detected. This result correlates well with the porosity data. Apparently, carbonation proceeds slowly in this cementing system.
4. Conclusions The study demonstrates that none of the modified cementing formulations tested here was able to entirely prevent carbonation of conventional oil well cement. The best results were obtained from a slag cement (CEM III) blended with a reactive filler which can bind portlandite through the puzzolanic reaction, leading to additional C-S-H phases. This approach can prevent cracking of the cementitious matrix as a result of less CaCO3 formation, it can keep gas permeability low and thus enhance the robustness of cement against CO2. In contrast, chemical admixtures such as e.g. latex polymers or cellulose ethers did not provide a significant improvement. While unmodified, conventional API class oil well cement exhibited a surprisingly low rate of carbonation, but substantial cracking. The study suggests that perhaps the most critical phenomenon resulting from cement carbonation in a CCS well is crack formation as a consequence of expansion during CaCO3 crystallization. These cracks can immediately provide pathways for further migration and the ascent of CO2. Through this process, ascension of CO2 to the surface might be accelerated much more than through leaching of Ca(HCO3)2 or decomposition of the C-S-H matrix which both constitute relatively slow processes. In the future, it would be useful to study the speed of CO2 migration on large scale cement specimens (height ~ 30 cm) which will form cracks (e.g. cementing systems C or D) and compare them with samples such as cementing system B which exhibit no cracking. Still, as any Portland cementing system – even the one performing best here – inevitably will be subject to carbonation, the question remains whether its use on CCS wells is recommendable from the point of risk of leakage. A worst case scenario would produce a migration strata of 60 cm/year (this assumes a linear carbonation rate of 50 mm/month which was found only for cementing system A). Considering that depleted oil reservoirs typically lie at least 2000 m below surface, it would take ~3300 years until this CO2 can reach the surface. This seems to present a comfortable safety margin. A more serious threat for surface leakage appears to lie in crack formation within the cementitious matrix, and perhaps microchanneling occurring at the interface between the mud filter cake and cement. Owing to incomplete removal of the drilling fluid filter cake from the borehole well, cement always is placed on top of this filter cake which possibly may undergo
The authors wish to thank RWE Dea, Hamburg/Germany, for initiating and financing this study, and for their permission to publish the data. E. Maikranz is thanked for the numerous advises on field requirements and Dr. Plack from Dyckerhoff AG, Werk Lengerich/Germany for providing the 8 L autoclaves for curing the samples. References [1] C. Marchetti, On geoengineering and the CO2 problem, Clim. Chang. 1 (1977) 59–68. [2] J.L. Sarmiento, N. Gruber, Sinks for anthropogenic carbon, Phys. Today (2002) 30–36. [3] D. Gielen, The future role of CO2 capture and storage, in: Results of the IEA-ETP Model, Report Number EET/2003/04, Paris, November 2003. [4] S. Bachu, Sequestration of CO2 in geological media: criteria and approach for site selection in response to climate change, Energy Convers. Manage. 41 (2000) 953–970. [5] R. Beckwith, Carbon capture and storage: a mixed review, J. Petrol. Technol. 63 (2011) 42–45. [6] D.K. Smith, Cementing, SPE Monograph, Society of Petroleum Engineers, New York, NY, 1990. [7] R.A. Bruckdorfer, Carbon Dioxide Corrosion in Oil Well Cements, SPE Paper 15176, Society of Petroleum Engineers, Billings, MT, 1986. [8] A. Duguid, An estimate of the time to degrade the cement sheath in a well exposed to carbonated brine, Energy Procedia 1 (2009) 3181–3188. [9] B.G. Kutchko, B.R. Strazisar, D.A. Dzombak, G.V. Lowry, N. Thaulow, Degradation of well cement by CO2 under geologic sequestration conditions, Environ. Sci. Technol. 41 (2007) 4787–4792. [10] A. Duguid, M. Radonjic, G.W. Scherer, The effect of carbonated brine on the interface between well cement and geologic formations under diffusion-controlled conditions, in: 8th International Conference on Greenhouse Gas Control Technologies, Trondheim, Norway, 2006. [11] B.G. Kutchko, B.R. Strazisar, G.V. Lowry, D.A. Dzombak, Rate of CO2 attack on hydrated Class H well cement under geologic sequestration conditions, Environ. Sci. Technol. 42 (2008) 6237–6242. [12] A. Duguid, M. Radonjic, R. Bruant, G.W. Scherer, Degradation of well cements exposed to carbonated brine, in: 4th Annual Conference on Carbon Capture and Sequestration, Washington D.C., USA, 2005. [13] V. Barlet-Gouédard, B. Rimmelé, B. Goffé, O. Porcherie, Mitigation strategies for the risk of CO2 migration through wellbores, SPE paper 98924, in: IADC/SPE Drilling Conference, Miami, Florida, USA, 2006. [14] D.D. Onan, Effects of supercritical carbon dioxide on well cements, SPE paper 12593, in: Permian Basin Oil and Gas Recovery Conference, Midland Texas, USA, 1984. [15] G. Rimmelé, V. Barlet-Gouédard, O. Porcherie, B. Goffé, F. Brunet, Heterogeneous porosity distribution in Portland cement exposed to CO2-rich fluids, Cem. Concr. Res. 38 (2008) 1038–1048. [16] G. Benge, Improving wellbore seal integrity in CO2 injection wells, Energy Procedia 1 (2009) 3523–3529. [17] W. Crow, D.B. Williams, J.W. Carey, M. Celia, S. Gasda, Wellbore integrity analysis of a natural CO2 producer, Energy Procedia 1 (2009) 3561–3569. [18] J.W. Carey, M. Wigand, S.J. Chipera, G. Woldegabriel, R. Pawar, P.C. Lichtner, S.C. Wehner, M.A. Raines, G.D. Guthrie, Analysis and performance of oil well cement with 30 years of CO2 exposure from the SACROC Unit, West Texas, USA, Int. J. Greenhouse Gas Control 1 (2007) 75–85. [19] J. Shen, P. Dangla, Reactive transport modeling of CO2 through cementitious materials under CO2 geological storage conditions, in: 13th International Conference on the Chemistry of Cement, Madrid, Spain, 2011, p. 77. [20] M. Loizzo, O.A.P. Akemu, L. Jammes, J. Desroches, S. Lombardi, A. Annunziatellis, Quantifying the risk of CO2 leakage through wellbores, SPE Drill. Complet. 26 (2011) 324–331. [21] T.L. Watson, S. Bachu, Evaluation of the potential for gas and CO2 leakage along wellbores, SPE Drill. Complet. 24 (2009) 115–126. [22] E.B. Nelson, D. Guillot, Well Cementing, 2nd ed. Schlumberger Dowell, Sugar Land, TX, 2006. [23] V. Barlet-Gouèard, S. James, B. Drochon, B. Piot, J.-P. Caritety, Cement Composition for a Carbon Dioxide Supercritical Environment, EP patent 1770 073, 2007.
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[24] T. Sugama, M. Allan, J.M. Hill, Calcium phosphate cements prepared by acid–base reaction, J. Am. Ceram. Soc. 75 (1992) 2076–2087. [25] F. Dugonjić-Bilić, C. Tiemeyer, J. Plank, Study on admixtures for calcium aluminate phosphate cement useful to seal CCS wells, in: SPE International Symposium on Oilfield Chemistry, The Woodlands, TX/USA, SPE Paper 141179, 2011. [26] American Petroleum Institute, API Specification 10B-2, 1st ed. American Petroleum Institute, Washington, 2005.
[27] H.F.W. Taylor, Cement Chemistry, 2nd ed. Thomas Telford Ltd., London, 1997. [28] A. Fabbri, N. Jecquemet, D.M. Seyedi, A chemo-poromechanical model of oilwell cement carbonation under CO2 geological storage conditions, Cem. Concr. Res. 42 (2012) 8–19.
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Cement and Concrete Research journal homepage: http://ees.elsevier.com/CEMCON/default.asp
CO2 stability of Portland cement based well cementing systems for use on carbon capture & storage (CCS) wells M. Lesti, C. Tiemeyer, J. Plank ⁎ Technische Universität München, Chair for Construction Chemicals, 85747 Garching, Lichtenbergstr. 4, Germany
a r t i c l e
i n f o
Article history: Received 23 February 2012 Accepted 5 December 2012 Keywords: Corrosion Carbonation (C) Long-term performance (C) Permeability (C) Oil well cement (D)
a b s t r a c t Three Portland cement based systems formulated with specific inorganic particles and organic admixtures were tested against conventional API Class G oil well cement with respect to CO2 tolerance. Hardened specimens (30×50 mm) were prepared and stored under supercritical CO2 (90 °C/400 bar) for one and six months, respectively. CO2 ingress was probed via phenolphthalein test and thermogravimetry. In all samples, formation of different CaCO3 modifications was observed, proving carbonation. Carbonation rates were relatively low and similar, except for one sample. Most detrimental was cracking of specimens as a result of massive CaCO3 formation which comes along with expansion. Best CO2 resistance was obtained from a slag cement (CEM III) blended with a reactive filler which can bind large quantities of portlandite, and by providing pore space in the cementitious matrix for growing of CaCO3. The addition of latex polymers or of other organic admixtures did not provide much improvement over conventional API oil well cement. © 2012 Elsevier Ltd. All rights reserved.
1. Introduction As an alternative to reducing CO2 emissions, already back in 1977 Marchetti proposed to capture carbon dioxide from the exhaust streams of coal power plants and then store it subterraneously in suitable geological formations [1]. Following his idea, this concept of geological storage of CO2 was explored further [2,3]. Depleted oil and gas reservoirs, deep saline aquifers and unminable coal beds were identified as preferential storage formations [4]. An important criteria for the feasibility of geological CO2 disposal is that no leakage must occur over time periods of several hundred years. For example, in Germany it was proposed that potential disposal sites must guarantee sealing quality for at least 1000 years, to avoid any safety risk for the population. By the end of 2010, well over 200 CCS (“carbon capture & storage”) projects were active or planned worldwide, and substantial field experience has been gained with this technology [5]. Geological disposal of CO2 requires to drill and cement wellbores through which liquid supercritical CO2 (scCO2) is injected. There are multiple pathways that CO2 may use to migrate and escape from the reservoir. Apart from leakage through the capping formation, it may ascend through the cement sheath surrounding the wellbore casing or through the cement plug which caps the well. Conventional oil well cements (e.g. the types API Class G and H) are based on Portland cement technology [6]. However, Portland cement is known to be degraded by CO2 [7]. As a result, many studies have been performed to evaluate the stability of oil well cements against CO2 under wellbore ⁎ Corresponding author. Tel.: +49 89 289 13151; fax: +49 89 289 13152. E-mail address: [email protected] (J. Plank). 0008-8846/$ – see front matter © 2012 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.cemconres.2012.12.001
conditions. Also, in conventional oil production, cement can be exposed to CO2 in multiple ways. For example, Duguid studied the degradation of oil well cements exposed to carbonated brines occurring in some reservoirs [8]. In this article, he summarized the findings of several other groups which report about multiple reactions occurring between CO2 and well cement [7,9–16]. The CO2 attack starts with carbonation of calcium hydroxide (portlandite) which is formed by hydration of the silicate phases C3S and C2S. Once all portlandite is consumed, then even the calcium silicate hydrates (C-S-H phases) which constitute the main solid matrix of hardened cement and provide its strength, are decomposed into CaCO3 and silica gel [8]. These corrosion reactions are shown in Eqs. (1) and (2). CaðOHÞ2ðaqÞ þ CO2ðaqÞ →CaCO3 þ H2 O Portlandite
ð1Þ
Cx SHy þ xCO2ðaqÞ →xCaCO3 þ SiO2 ⋅ yH2 O C−S−H phases:
ð2Þ
According to this, CO2 and in particular the considerably more aggressive scCO2 (“super critical CO2”) can affect wellbore integrity in two different ways [14]: CaCO3, which initially densifies the cementitious matrix and reduces its permeability and porosity, thus constituting a positive process with respect to the sealing quality of the cement, can be dissolved in CO2 saturated water as Ca(HCO3)2(aq) (Eq. (3)). Unfortunately, most oil and gas reservoirs contain saline reservoir fluids, hence any CO2 injected will contain water. Second, once all portlandite has been carbonated, then the remaining silicate-based matrix will be converted into products of poor strength
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M. Lesti et al. / Cement and Concrete Research 45 (2013) 45–54
(SiO2·y H2O or CaCO3). The consequence of this process is gradual dissolution of major parts of the cement sheath, loss of wellbore integrity and ultimately leakage of CO2. CaCO3 þ CO2ðaqÞ þ H2 O→CaðHCO3 Þ2ðaqÞ insoluble dissolved:
ð3Þ
For decades, scCO2 has been injected in producing oil wells as an EOR (“enhanced oil recovery”) measure to maintain reservoir pressure. Additionally, there are some natural CO2 producing wells. There, the CO2 produced is utilized in industrial applications, mainly in oil field operations. From there, long-term field experience on cements exposed to supercritical CO2 exists. For example, Crow et al. studied cement core samples retrieved from a natural CO2 producing well in Dakota sandstone formation [17]. X-ray diffraction analysis of samples taken in direct proximity of the reservoir (~6 m) showed almost complete conversion of portlandite to calcium carbonate. Additionally, an increase in porosity and permeability was found. Samples recovered at further distance from the reservoir (~50 m) and at the top of the caprock had retained most of their original cement mineral composition and were carbonated only slightly. This example demonstrates that even within the relatively short time span of 30 years, at first significant carbonation can occur near the reservoir which is followed later by increased porosity due to dissolution of CaCO3 as Ca(HCO3)2. These negative experiences are contradicted by another field experience from CO2 injection wells in the Permian basin of West Texas [18]. There, cores retrieved from downhole (~3.5 m above the reservoir) composed of ordinary oil well cement which had been exposed to scCO2 showed only minor carbonation. As a result, serious dispute evolved whether or not conventional API oil well cement is stable enough against CO2 and can be used for CCS wells. Very recently, some researchers developed models taking cement permeability, CO2 diffusion rates and typical wellbore depths (length of migration path to surface) into account [19]. They conclude that for well depths below 2000 m, the risk of leakage is negligible over a time span of several hundred years. Another risk analysis was performed by Loizzo et al. [20]. They calculated that possibly 20% of all wells may be leaking at some point of their life. Most of those leaks will be insignificant and thus will not affect the population or the environment. However, according to the authors still less than two out of 1000 wells will have major leakage, which is unacceptable. Other authors report that approx. half of the leaks may not end up at the wellhead [21]. These examples demonstrate the complexity of the subject which is under high scrutiny from the public and governmental institutes. Common oil well cementing formulations include numerous chemical additives to control the set behavior (retarders), water loss (fluid loss additives), pumpability (dispersants/superplasticizers) and permeability (film forming latex polymers) [22]. The specific influence of all those additives on CO2 resistance of well cements has not yet been investigated sufficiently. In particular, any measure which can lower the permeability of hardened cement or a polymer coating deposited on cement minerals should enhance the lifetime of cement exposed to scCO2 [16]. The first effect can be achieved by simply reducing the water-to-cement ratio, thus reducing the capillary pores. However, this approach has two disadvantages. First, while it can slow down the reaction rate considerably, it does not produce a Portland cement which no longer is susceptible to degradation by CO2 [23]. Second, not all wellbores can tolerate the high hydrostatic pressure instigated by high density cement slurries [16]. An alternate method to reduce cement permeability is the incorporation of special additives such as latex polymers or pozzolans (e.g. fly ash) which fill the pore spaces in the hardened cement matrix. Another concept is to completely eliminate cement constituents which are potential reactants for CO2. This approach involves the use of special binders such as calcium sulfoaluminate cement, geopolymer-based cement, calcium aluminate-phosphate
cement [24,25], magnesium oxide cement and hydrocarbon-based cement [16,23]. However, it would take many years of laboratory research work and field testing to adjust such radically new cements to the harsh conditions of deep wellbores, and to acquire suitable equipment which allows their routine practical use. Here, an attempt was made to formulate conventional API Class G oil well cement with admixtures in such a way that its gas permeability was reduced. Four cementing formulations, designated as cementing systems A–D, which included various chemical and mineral additives which are required in actual field use (e.g. for sufficient pumping time, low rheology, low water loss, no free water/bleeding) were prepared, stored at atmospheric conditions for two weeks and cured for 28 days at 90 °C under 400 bar N2 pressure. Subsequently, the hardened cylindrical specimens (d= 30 mm, h = 50 mm) were stored under supercritical carbon dioxide at 400 bar and 90 °C in 4 L autoclaves. After 1 and 6 months exposure times, the samples were characterized by visual analysis, thermogravimetry (content of CO2 bound) and measurement of permeability, porosity and compressive strength. From these data it was aimed to identify cementing systems and specific additives which can help to improve the CO2 resistance of conventional oil well cements. 2. Materials and methods 2.1. Materials 2.1.1. Cement formulations Four cementing systems using different approaches to enhance CO2 resistance were employed in this study. All cements contained salt (NaCl) to account for salt-bearing reservoir fluids which are most common in the oil fields of Lower Saxony, Germany. All cementing systems were based on a commercially available API oil well cement and formulated by the industry partners to meet the specific slurry property requirements which guarantee applicability under actual field conditions. Those include: for slurry rheology n and k values (according to the Power-Law model; for calculation of values see Eq. (4) [26]) of 0.8–1.0 and 0.2–1.3 respectively; API static fluid loss values at 80 °C/70 bar: b200 mL (except for cementing system B which was not adjusted for fluid loss control) and API free water content b 4 mL. Individual parameters for each cement slurry were collected, but are not shown here. n
τ ¼ k⋅γ
ð4Þ
whereby τ is the shear stress (Pa); k the consistency index (Pa·s n); γ the shear rate (s −1) and n the Ostwald index. Cementing system A contained inorganic, CO2 resistant particles of such specific grading as to fill the pore space in the cement matrix as much as possible and thus decrease its permeability against CO2. It was composed of 709.42 g cement blended with the inorganic material, 33.75 g sodium chloride (17% by weight of water, bwow), three different liquid admixtures and 205.13 g DI (deionized) water (w/s ratio = 0.25). The resulting cement slurry possessed a density of 1.91 kg/L. Cementing system B was based on a commercial CEM III/B 42.5 LH/HS/NA cement which was further blended with a specific type of fly ash (electro filter ash, also referred to as EFA filler) in such a way as to reduce the CaO:SiO2 weight ratio from 1.0 present in the original CEM III cement to 0.53 in the blend. This excess SiO2 reacts with Ca(OH)2(aq) released during hydration of this cement. This way, no portlandite is available to react with scCO2. The cement slurry consisted of 1351 g cement blend, 108 g sodium chloride (22% bwow), a solid retarder admixture and 501 g DI water (w/s ratio = 0.37). The slurry density was 1.82 kg/L. It should be noted here that cementing system B was relatively difficult to mix as a result of higher viscosity caused by the fine particulate filler material.
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The concept of cementing system C (density = 1.91 kg/L) was based on pore plugging by film formation from organic latex particles. This polymer-modified cement slurry incorporated seven chemical admixtures and was formulated as follows: 1350 g cement blend, 79.2 g sodium chloride (25% bwow), two dry admixtures (retarder, dispersant), four liquid admixtures (e.g. latex dispersion and defoamer) and 316.2 g DI water (w/s= 0.33). Cementing system D was used as reference sample. It was prepared from conventional API Class G oil well cement (type “black label” from Dyckerhoff AG, Werk Lengerich/Germany) and contained no specific additive to alter cement properties. The oxide composition of this cement as measured by XRF is given in Table 1. The slurry was prepared from 1280 g cement, 110 g sodium chloride (20% bwow), two dry (dispersant, water retention additive) and one liquid admixture (retarder) to control rheology, set time and water loss, and of 550 g DI water (w/c ratio = 0.43; density = 1.96 kg/L). 2.1.2. Preparation of synthetic reservoir fluid Curing of the cement samples was performed in a synthetic reservoir fluid. This liquid simulates the electrolyte contents which typically occur in an abandoned oil well in Northern Germany which was considered for actual CO2 disposal. In a 20 L stirred glass reactor, 13,100 g DI water were mixed in this order with 4169 g NaCl, 467 g CaCl2·2 H2O, 220 g MgCl2·6 H2O, 10.6 g K2SO4 and 9 g KCl (see Table 2). 2.2. Preparation of cement samples The preparation of cementing system A was carried out employing a modified test procedure (longer mixing time; lower shear rates) as set forth in Recommended Practice for Testing Well Cements, API Recommended Practice 10 B, issued by the American Petroleum Institute [26]. Cementing systems B, C and D were prepared applying a procedure established by the industrial project partners which deviated significantly from the one described in the API norm. The slurries of cementing system A were mixed using a blade-type laboratory blender manufactured by Waring Products Inc. (Torrington/ CT, USA). First, NaCl was dissolved in DI water by stirring for 2 min at 1500 rpm. Next, the liquid admixtures were added and stirred for 5 s at 4000 rpm. Within the next 30 s, the cement blend was added and then stirred for additional 5 min at 4000 rpm. Cementing systems B–D were prepared by using a propeller-type mixer model Eurostar digital (manufactured by IKA, Staufen, Germany) instead of the Waring blender specified by API RP 10B norm. The admixtures were added one by one to DI water and dissolved (stirring time for each liquid admixture: 1 min.; for each solid admixture: 3 min.; stirring speed: 200 rpm). After completion of additions, mixing was continued for additional 8 min at 300 rpm. Then, within 30 s, the cement was added and the resulting slurry was stirred for another 10 min at 300 rpm. Table 1 Oxide composition of the API Class G (“black label”) cement sample, as measured by XRF. Oxide
Content (wt.%)
CaO SiO2 Al2O3 Fe2O3 MgO TiO2 P2O5 Na2O K2O SO3 SrO Loss of ignition Total
62.20 21.90 4.18 4.86 0.95 0.18 0.12 0.15 0.67 2.22 0.17 1.50 99.28
47
Table 2 Ion concentrations contained in the synthetic reservoir fluid used for curing the cement samples. Ions/salinity
Concentration (g/L)
Sulfate (SO42−) Sodium (Na+) Potassium (K+) Calcium (Ca2+) Magnesium (Mg2+) Chloride (Cl−) Total salinity
0.39 110.24 0.64 8.53 1.74 188.04 309.60
Subsequent to mixing, all cement slurries were cast into cylindrical plastic containers (diameter 30 mm, height 50 mm) and cured in the synthetic reservoir fluid under atmospheric conditions for two weeks to achieve full saturation. After this, the plastic containers were removed and the cement cores were cured for another 28 days at 90 °C and 400 bar pressure in the synthetic reservoir fluid. For this high pressure/high temperature curing, 8 L stainless steel autoclaves manufactured by Parr Instrument Company (Moline/IL, USA) were used. 2.3. Carbonation experiment The cured samples were exposed to CO2(aq) in both liquid and gaseous environment using the following experimental setup and procedure. Static (non-stirred) conditions were considered to present a more realistic simulation of CO2 exposure conditions occurring in an actual CCS well. A total of 24 pre-cured cement specimens were placed on a stainless steel rack as shown in Fig. 1 and then placed in 4 L stainless steel autoclaves (Parr Instrument Company, Moline/IL, USA). The autoclaves were then half filled with the synthetic reservoir fluid, thus the top samples were stored in a supercritical CO2 gas atmosphere saturated with water vapor while the bottom samples were immersed in CO2 saturated reservoir fluid (liquid phase). The carbonation experiments were performed for 1 and 6 months respectively at a temperature of 90 °C and a CO2 pressure of 400 bar. Under those conditions, carbon dioxide in the gas phase is in a supercritical state and very reactive to cement. For reference, a second series of samples was prepared from all cementing systems and stored under the same conditions, but using nitrogen instead of scCO2 in the second curing. 2.4. Visualization of carbonation The samples exposed to scCO2 were retrieved from the autoclave after careful decompression over a total period of 22 h, then photographed to document their visual appearance, and cut with a diamond saw into two equal halves. Their inner face was sprayed on using a 1 wt.% aqueous phenolphthalein solution to test for alkalinity. From this, the carbonated zone (ingress of CO2) was determined. 2.5. Thermogravimetry TG measurements were conducted using a NETZSCH TG 209 system (Netzsch-Gerätebau GmbH, Selb, Germany) equipped with a mass spectrometer for the identification of decomposition products (here: CO2(g)). 2.6. Compressive strength First, the cured cement samples were treated with gypsum paste to achieve absolutely planar surfaces. After hardening of the gypsum, the cylinders were tested according to DIN EN 12390-4 on a Toni NORM instrument (Toni Technik, Berlin, Germany). The data presented is the arithmetic average of 3 cement samples.
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Fig. 1. Experimental setup for scCO2 storage of cement specimens; left and middle: 4 L autoclaves; right: stainless steel rack employed to hold the cement specimens placed in the autoclave.
2.7. Porosity
3.2. Cracking of samples
Porosity and pore size distribution of the cured cement samples were measured employing a mercury intrusion porosimeter (Poremaster60, Quantachrome GmbH & Co. KG, Odelzhausen, Germany). This instrument is capable of detecting pore sizes from 3 nm to 360 μm. For preparation, the cylindrical samples were crushed, ~0.3–0.4 g pieces were obtained and dried for 34 h at 105 °C prior to measurement.
Massive crack formation was observed in samples prepared from cementing systems C and D after 6 months storage under CO2 (Fig. 3). The samples of cementing system C were destroyed completely and only fragments of the samples could be retrieved after storage in the liquid phase. Cementing system D prepared from neat API Class G oil well cement also showed significant cracking after exposure in both liquid and gas phase, however less severe than in the cement sample C. These cracks immediately provide pathways for further migration and spread of CO2, thus presenting a threat for cement seal integrity. Cracking is the result of CaCO3 formation from Ca(OH)2(aq) and CO2(g) which is associated with a volume expansion of ~ 11% [27]. During its crystallization, CaCO3 can fracture the cement matrix due to its crystallization pressure. Very recently, Fabbri et al. presented a model describing the correlation between the porosity of an oil well cement matrix and the probability of crack formation as a result of carbonation [28]. They conclude that upon carbonation, low cement porosity (which is characteristic for oil well cements) will lead to increased cracking of the matrix. This aspect will be discussed in greater detail below.
2.8. Gas permeability Permeability against air was measured at Westphal Präzisionstechnik GmbH (Celle, Germany) using a Fachner-type cell Modell RIEKMANN (Westphal Präzisionstechnik GmbH, Celle, Germany). Here, wet, nondried cement samples (entire cylinders, except for cementing systems C and D where fragments of the cylinders were tested) as retrieved from the autoclave were employed. 3. Results and discussion 3.1. Visual appearance of scCO2 exposed samples
3.3. Phenolphthalein test The visual appearance of the cement samples stored for 1 and 6 months, respectively, in scCO2 and CO2 saturated brine is displayed in Fig. 2. After one month of CO2 exposure, no major effect on the cement samples (e.g. cracking) was visible. On some specimens, salt crusts were present on their surface, as was evidenced by XRD measurement. After six months exposure, the specimens from cementing system A (both in gas and liquid phase) showed a rough surface, similar to that of porous sandstone, thus indicating substantial leaching of CaCO3 as soluble Ca(HCO3)2(aq) from the matrix (Fig. 2). For cementing system B, no impact of CO2 on the visual appearance was apparent. However, cracks were observed on specimens prepared from cementing systems C and D stored in the liquid phase, and from cementing system D stored in the gas phase. These preliminary observations suggest that cementing systems A, C and D are attacked by CO2 whereas cementing system B is more resistant to CO2.
The depth of CO2 ingress was determined by using the phenolphthalein test. Generally, no differences between samples stored in the gas phase (water saturated CO2 atmosphere) and the liquid phase (reservoir fluid containing CO2) were detected. Therefore, only photographs of samples stored in the gas phase are displayed in Fig. 4. For cementing system A, after only one month of storage the very high pH characteristic for portlandite was not present anymore, thus indicating complete carbonation of the sample. This cementing system contained a relatively low amount of binder and apparently is quickly carbonated. The slag cement/fly ash-based cementing system B showed a carbonation depth of 10 mm (~2/3 of core radius) whereas cementing systems C and D exhibited only small carbonation zones which were 3 mm for system C, and 0.5 mm for system D. Thus, it is demonstrated that after 1 month exposure, cementing systems C and D are less degraded by CO2 than the systems A and B.
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Fig. 2. Visual appearance of cement samples exposed to scCO2 in liquid phase (bottom) and gas phase (top) at 90 °C and 400 bar for 1 and 6 months, respectively (note: samples exhibiting a height of less than 50 mm had not shrunk, but were cut for other investigations).
After six months exposure, cementing systems A–C showed complete carbonation. Cementing system D maintained its alkalinity, but there, similar to the sample from cementing system C, multiple cracking was observed, apparently due to reaction with CO2. On cement sample A, the cut face had attained a rough appearance, with clearly discernible pores, as is shown in Fig. 4. The high pH characteristic for portlandite was not found anymore and only slight scratching resulted in substantial loss of a fine powder from the surface of the specimen. It appears that from this sample, most of the cementitious
matrix has been consumed by corrosion involving CO2, and the remaining CO2-resistant inorganic particles provide a poorly coherent matrix. It has been suggested that knowing the carbonation depth obtained after one month of sample exposure to CO2 allows to estimate the progression of the carbonation front after prolonged periods of time. Barlet-Gouédard et al. assume a linear correlation between the thickness of the carbonation front and the square root of exposure time [13]. Applying this model we calculated the spread
Fig. 3. Cracking of specimens prepared from cementing systems C and D after six months exposure to scCO2 at 90 °C and 400 bar.
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Fig. 4. Visual appearance of cement samples exposed to wet CO2 atmosphere at 90 °C and 400 bar for one and six months, respectively, after staining with phenolphthalein.
of the carbonation front in cementing systems B, C and D after a time period of 100 years. For cementing system B, carbonation would have moved ~35 cm while for cementing systems C and D a layer of only ~11 cm and ~2 cm would have been carbonated. According to this model, the carbonation front is moving very slowly through the cement samples tested (except for cementing system A). However, this result is contradicted by field experience from natural CO2 producing wells, as mentioned earlier [17]. One potential explanation is the occurrence of microchanneling and crack formation which is not considered in these calculations. With the aim to understand the differences in the behaviors of the cement samples, a series of analytical experiments was devised with the hope to understand the individual physico-chemical processes occurring under CO2 attack.
3.4. Quantification of CO2 uptake Utilizing thermogravimetry, the amount of CO2 which is chemically bound in the cementing systems before and after storage in CO2 was determined. For the specimens exposed for one month in the gas phase, measurements were taken from the outer zone and from the center of the sample. For the samples stored over six months, cores exposed to the gas phase as well as in the liquid phase were analyzed separately. Here, samples were taken from the carbonated zone only. The results are shown in Table 3. The reference sample of cementing system A which was cured under N2 and not exposed to CO2 contained no chemically bound CO2. After one month exposure to CO2, 5 wt.% of CO2 was taken up by the sample, both in the outer zone as well as at the center of the
Table 3 Amounts of chemically bound CO2 for different cement samples exposed to supercritical CO2 (T=90 °C, p=400 bar) over one and six months, respectively. Cementing system
A B C D
Chemically bound CO2 (wt.%) Reference sample (no CO2 exposure)
1 month CO2 gas phase (carbon. zone)
1 month CO2 gas phase (center of core)
6 months CO2 gas phase (carbon. zone)
6 months CO2 liquid phase (carbon. zone)
0 1 3 5
5 11 14 11
5 4 5 6
7 16 17 26
10 16 17 17
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sample. This signifies that carbonation had occurred throughout the entire cement specimen, as was shown before in the phenolphthalein test. Under continued exposure, carbonation proceeded further and after six months of storage, the amounts of chemically bound CO2 increased to 7 wt.% for the sample exposed in the gas phase and to 10 wt.% for the specimen stored in the liquid phase. Generally, the amount of CO2 bound by cement sample A is low. This is because cementing system A contains a relatively low amount of cement. For cementing system B, one mass percent of CO2 bound was detected in the reference sample. After one month of storage under CO2, the amount of carbon dioxide bound increased to 11 wt.% in the carbonated zone and to 4 wt.% at the center of the core. After six months exposure, a strong increase in the amounts of CO2 bound to 16 wt.% for both samples stored in the gas and liquid phase was experienced, indicating significant carbonation. The reference sample of cementing system C (no CO2 exposure) showed a high value of 3 wt.% for the amount of CO2. This was attributed to the presence of certain admixtures in this cementing system. After one month of CO2 exposure, a significant increase of CO2 bound was observed for the carbonated zone (14 wt.%), while at the center of the core only a slight increase to 5 wt.% was detected. This signifies that in this sample, carbonation progressed only slowly and had not reached the center of the core within one month. After six months of CO2 exposure, the entire cement sample was carbonated. Consequently, a high carbon dioxide content of 17 wt.% for both specimens stored in the gas and liquid phase was detected. The reference sample for cementing system D already showed elevated amounts of CO2 bound (5 wt.%) as a consequence of high loading with organic admixtures. After one month storage in CO2, the amount bound rose to 11 wt.% in the carbonated zone and to 6 wt.% at the center of the core. This indicates that also for this cementing system, carbonation proceeds rather slowly. After six months of exposure, the amounts of CO2 bound increased to 26 wt.% for the sample stored in the gas phase and to 17 wt.% for the specimen in contact with the brine, indicating massive carbonation in both cases.
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The large difference can plausibly be explained by the leaching of solid CaCO3 as soluble Ca(HCO3)2 into the reservoir fluid.
3.5. Compressive strengths For the reference samples stored under nitrogen, no differences in compressive strength after one or six months of storage time were observed. The compressive strengths measured after six month storage are shown in Fig. 5. All values obtained exceed by far the requirement for sufficient support of casing which lies around 5 MPa. The compressive strengths of cementing systems A and B were reduced drastically after exposure to CO2. No differences between samples stored in the liquid or the gas phase were observed. Obviously, the carbonates formed were already washed out either by the reservoir fluid or the water vapor present in the gas phase. Cementing systems C and D showed the opposite trend, namely an increase in compressive strength. Here, compressive strength was not measurable for the cylindrical specimens because the samples were broken into several pieces as a result of severe crack formation. When tested, these fragments showed low carbonation and therefore relatively high compressive strength values.
3.6. Cement porosity In hardened cement, pores represent channels in which CO2 can migrate from the bottom of the bore hole to the top. To ensure a low permeability of the cement seal, the hardened cement must have low porosity and small pore diameters. To investigate the effect of CO2 on porosity and pore size distribution of the hardened cement samples, mercury intrusion porosimetry experiments were conducted on specimens stored for one and six months respectively. Samples stored in the liquid as well as the gas phase were looked at separately. The results are shown in Fig. 6.
Fig. 5. Compressive strengths of cement samples exposed for six month to CO2 at 90 °C and 400 bar, stored in reservoir fluid (liquid phase) or in wet CO2 gas atmosphere; note that for cementing systems C and D, only pieces of the specimens could be tested, as a consequence of cracking.
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After one month exposure, cementing system A showed a significant increase in overall porosity from 19 vol.% to 34 vol.% (liquid phase) and 27 vol.% (gas phase) for the CO2 exposed specimens. Also, a shift to larger pore sizes was detected. This effect is plausibly due to proceeding carbonation and washout of Ca(HCO3)2. This process is not yet finished after one month of exposure. After six months, the number of large pores with sizes around 80 nm had increased further, while the overall porosity remained relatively constant at ~26 vol.%. The exposure of cementing system B to CO2 did not affect the porosity of the hardened sample which remained nearly constant at ~ 22–26 vol.% for all specimens. The pore sizes, however, showed a shift to higher diameters which signifies that soluble carbonates were formed and then washed out. Leaching was more pronounced for the samples stored in the liquid phase as is shown by the decrease of pores possessing a diameter of ~ 10 nm, compared to the samples stored in the gas phase. Cementing systems C (latex polymer cement) and D (non-modified reference system) exhibit a low porosity, even after six months of CO2 exposure (system C ~ 15 vol.%, system D ~ 14–20 vol.%). Only a very minor shift of the pore sizes to higher diameters was observed which is owed to the leaching of carbonates. To summarize, specimens prepared from cementing systems A and B showed increased porosity after CO2 exposure while samples from systems C and D exhibit low porosities. This data explains the
occurrence of cracks in cementing systems C and D while specimens from systems A and B were not affected. According to FABBRI et. al., low porosity values generally lead to increased crack formation [28]. For their growth, CaCO3 crystals need space for expansion which is provided in matrixes possessing high porosity. In cases where only limited pore space is available, the high crystallization pressure will fracture the solid matrix.
3.7. Gas permeability A key parameter for the tightness of hardened cement is the permeability against gas. Here, permeability of specimens with respect to CO2(g) was measured after exposure times of one and six months, respectively. Again, samples stored in the CO2-saturated reservoir fluid (liquid phase) and in water vapor saturated CO2 gas phase were looked at separately. The results are displayed in Table 4. The reference samples of all cementing systems showed gas permeabilities which are below the detection limit of 0.0001 mD. Such values demonstrate the initial extreme tightness of the cements against gas migration. After CO2 exposure, cementing system A showed increased permeability (0.0025 mD after one month and 0.089 mD after six months storage in the gas phase). This is due to
Fig. 6. Pore size distribution and porosity of cement samples stored under 400 bar scCO2 pressure at 90 °C for one month or six months, respectively, in synthetic reservoir fluid (liquid phase) or water vapor saturated CO2 gas phase.
M. Lesti et al. / Cement and Concrete Research 45 (2013) 45–54 Table 4 Gas permeabilities of four cementing systems after exposure to scCO2 in gas and liquid phase for 1 month and 6 months, respectively. Cementing system
Permeability (mD) Reference sample
1 month CO2 Liquid phase
1 month CO2 Gas phase
6 months CO2 Liquid phase
6 months CO2 Gas phase
A B C D
b0.0001 b0.0001 b0.0001 b0.0001
0.0083 b0.0001 0.0125 b0.0001
0.0025 b0.0001 0.109 0.307
b0.0001 0.0002 0.288 0.554
0.089 0.0016 0.0061 1.54
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shrinkage and cracking due to dehydration by cement. As a consequence, flow paths can form which allow intruded CO2 to ascend much more quickly to the surface than through carbonation of the cementitious matrix. Such channeling possibly can pose a much more severe risk for leakage of CO2 than corrosion of the cement. To control this risk, best practices must be applied when cementing CCS wells which include for example pipe rotation when cement is pumped. Also, use of highly efficient spacer fluids to clean the wellbore from residual drilling mud is compulsory. Acknowledgments
increased porosities and larger pore sizes occurring in the carbonated cement samples. Similar effects were observed for the latex based cement and the non-modified API Class G cement (systems C and D, respectively). Only the gas permeability of the fly ash containing cementing system B is not affected by CO2 exposure. Here, no increase after a storage time of one month (gas permeability b 0.0001 mD) and only a slight increase in permeability after six months (liquid phase = 0.0002 mD, gas phase = 0.0016 mD) were detected. This result correlates well with the porosity data. Apparently, carbonation proceeds slowly in this cementing system.
4. Conclusions The study demonstrates that none of the modified cementing formulations tested here was able to entirely prevent carbonation of conventional oil well cement. The best results were obtained from a slag cement (CEM III) blended with a reactive filler which can bind portlandite through the puzzolanic reaction, leading to additional C-S-H phases. This approach can prevent cracking of the cementitious matrix as a result of less CaCO3 formation, it can keep gas permeability low and thus enhance the robustness of cement against CO2. In contrast, chemical admixtures such as e.g. latex polymers or cellulose ethers did not provide a significant improvement. While unmodified, conventional API class oil well cement exhibited a surprisingly low rate of carbonation, but substantial cracking. The study suggests that perhaps the most critical phenomenon resulting from cement carbonation in a CCS well is crack formation as a consequence of expansion during CaCO3 crystallization. These cracks can immediately provide pathways for further migration and the ascent of CO2. Through this process, ascension of CO2 to the surface might be accelerated much more than through leaching of Ca(HCO3)2 or decomposition of the C-S-H matrix which both constitute relatively slow processes. In the future, it would be useful to study the speed of CO2 migration on large scale cement specimens (height ~ 30 cm) which will form cracks (e.g. cementing systems C or D) and compare them with samples such as cementing system B which exhibit no cracking. Still, as any Portland cementing system – even the one performing best here – inevitably will be subject to carbonation, the question remains whether its use on CCS wells is recommendable from the point of risk of leakage. A worst case scenario would produce a migration strata of 60 cm/year (this assumes a linear carbonation rate of 50 mm/month which was found only for cementing system A). Considering that depleted oil reservoirs typically lie at least 2000 m below surface, it would take ~3300 years until this CO2 can reach the surface. This seems to present a comfortable safety margin. A more serious threat for surface leakage appears to lie in crack formation within the cementitious matrix, and perhaps microchanneling occurring at the interface between the mud filter cake and cement. Owing to incomplete removal of the drilling fluid filter cake from the borehole well, cement always is placed on top of this filter cake which possibly may undergo
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