Tracing the movement and the fate of injected CO2 at the IEA GHG Weyburn-Midale CO2 Monitoring and Storage project (Saskatchewan, Canada) using carbon isotope ratios

International Journal of Greenhouse Gas Control 16S (2013) S177–S184

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Tracing the movement and the fate of injected CO2 at the IEA GHG Weyburn-Midale CO2 Monitoring and Storage project (Saskatchewan, Canada) using carbon isotope ratios Bernhard Mayer a,∗ , Maurice Shevalier a , Michael Nightingale a , Jang-Soon Kwon a , Gareth Johnson a , Mark Raistrick a , Ian Hutcheon a , Ernie Perkins b a b

Applied Geochemistry Group, Department of Geoscience, University of Calgary, Calgary, Alberta, Canada T2N 1N4 Carbon and Energy Management Department, Alberta Innovates Technology Futures, Edmonton, Alberta, Canada T6N 1E4

a r t i c l e

i n f o

Article history: Received 24 September 2012 Received in revised form 15 January 2013 Accepted 23 January 2013 Available online 1 March 2013 Keywords: CO2 storage Monitoring Carbon isotopes Solubility trapping Weyburn

a b s t r a c t Stable isotope data can assist in successful monitoring of the movement and the fate of injected CO2 in enhanced oil recovery and geological storage projects. This is demonstrated for the International Energy Agency Greenhouse Gas (IEA-GHG) Weyburn-Midale CO2 Monitoring and Storage Project (Saskatchewan) where fluid and gas samples from multiple wells were collected and analyzed for geochemical and isotopic compositions for more than a decade. Carbon isotope ratios of the injected CO2 (−20.4‰) were sufficiently distinct from median ␦13 C values of background CO2 (␦13 C = −12.7‰) and HCO3 − (␦13 C = −1.8‰) in the reservoir to reveal the movement and geochemical trapping of injected CO2 in the reservoir. The presented 10-year data record reveals the movement of injected CO2 from injectors to producers, dissolution of CO2 in the reservoir brines, and ionic trapping of injected CO2 in conjunction with dissolution of carbonate minerals. We conclude that carbon isotope ratios constitute an excellent and cost effective tool for tracing the fate of injected CO2 at long-term CO2 storage sites with injection rates exceeding 1 million tons per year. © 2013 Elsevier Ltd. All rights reserved.

1. Introduction Carbon capture and geological storage (CCS) is a promising technology for reducing CO2 emissions into the atmosphere from fossil fuel intensive industries. An increasing number of pilot sites have been established over the last few years and a number of CCS projects with injection rates exceeding 1 million tons (Mt) of CO2 per year have been established or are in the planning phase. For these CO2 injection sites, existing or emerging regulations will require monitoring in order to verify the movement and the fate of injected CO2 . Various approaches have been employed for tracing CO2 in engineered storage sites. At the 1MT CO2 /yr scale Sleipner project in Norway, a number of geophysical monitoring techniques have been used (Chadwick et al., 2006). At the In Salah CO2 project in Algeria (1 MT CO2 /yr), various geophysical, geochemical and other techniques have been deployed to monitor the CO2 in the reservoir (Mathieson et al., 2011; Shi et al., 2012). At smaller pilot scale sites a number of geophysical and geochemical monitoring techniques have been

∗ Corresponding author at: 2500 University Drive NW, Calgary, Alberta, Canada T2N 1N4. Tel.: +1 403 220 5389; fax: +1 403 220 8514. E-mail address: [email protected] (B. Mayer). 1750-5836/$ – see front matter © 2013 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.ijggc.2013.01.035

tested. These pilot sites include the Pembina Cardium project in Alberta (Canada) with 75,000 tons of CO2 injected between 2005 and 2008 (Hitcheon, 2009; Johnson et al., 2011b), the Otway project in Victoria (Australia) with 65,000 tons of CO2 over 15 months (Boreham et al., 2011), the German Ketzin project with 53,000 tons of CO2 after 39 months (Martens et al., 2012) and the Frio project in Texas (USA) with 1,600 tons of CO2 injected over 10 days (Hovorka et al., 2006; Hovorka and Knox, 2003). Geochemical monitoring approaches depend on the ability to sample fluids and gases at observation wells either at reservoir conditions or at the wellhead. Measuring a wide variety of geochemical parameters for the obtained fluid and gas samples has the potential to provide unique information about the fate of injected CO2 , as geochemical reactions that transform CO2 into dissolved and solid carbon compounds can be identified. CO2 dissolution leads to formation of carbonic acid followed by dissociation into bicarbonate (HCO3 − ) and protons (H+ ) resulting in a decrease of pH values (reaction (1)), a process called solubility trapping of injected CO2 : CO2 + H2 O  H2 CO3  H+ + HCO3 −

(1)

Reaction (2) typically occurs in calcite and dolomite containing reservoirs. Here, H2 CO3 reacts with carbonate minerals (e.g. CaCO3 ) resulting in dissolved Ca2+ and two HCO3 − ions (reaction (2)) in the

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reservoir brines, where half of the carbon is derived from injected CO2 and the other half from the carbonate mineral. This process is often referred to as ionic trapping of the injected CO2 as HCO3 − . H2 O + CO2 + CaCO3  Ca2+ + 2HCO3 −

(2)

Both the above reactions enhance storage security by reducing the volume of buoyant CO2 . Geochemical monitoring therefore analyzes parameters that are suitable to indicate the extent of solubility and ionic trapping of injected CO2 including pH, and concentrations of dissolved inorganic carbon (DIC), alkalinity, Ca, Mg, Fe, Cl, and Na, among others. An example of how variations of these parameters are used to assess the extent of solubility, ionic, and mineral trapping of injected CO2 in the storage reservoir at the International Energy Agency Greenhouse Gas (IEA-GHG) Weyburn-Midale CO2 Monitoring and Storage Project is provided by Shevalier et al. (2013). Where this is possible, geochemical tracers can be added to the injected CO2 stream in order to follow the movement of CO2 in the reservoir. Chemical tracers have been co-injected at some CO2 storage sites including In Salah, Otway and Frio. At In Salah perfluorocarbon tracers (PFTs) were added to the CO2 streams at individual injection wells to assist in determining CO2 breakthrough in the natural gas field (Ringrose et al., 2009). At the German Ketzin project, gas tracers such as Kr and SF6 were used for verification of the arrival of injected CO2 at observation wells (Martens et al., 2012). At the Otway project per-deuterated methane (C2 H4 ), sulfur hexafluoride (SF6 ) and krypton (Kr) were used as additional tracers, which were successfully added downhole after 1000 tons of gas was injected (Stalker et al., 2009). Similarly at Frio, PFTs, SF6 , C2 H4 , and Kr were all deployed to aid the tracing of the movement of the injected CO2 (Hovorka et al., 2006). Most of these tracer compounds are expensive in large quantities and their co-injection may be costprohibitive at CO2 injection sites where millions of tons of CO2 are injected over several years or decades. Therefore, it is desirable to identify and test cheaper tracer compounds that are suitable for tracing the movement of injected CO2 at long-term CCS sites with injection rates exceeding 1 million tons per year. It has been demonstrated that the isotopic composition of injected CO2 may provide an additional tracer when it is sufficiently different from that of baseline carbon compounds in the reservoir (Assayag et al., 2009; Gilfillan et al., 2009; Johnson et al., 2011b; Kharaka et al., 2006; Myrttinen et al., 2010; Raistrick et al., 2006). Stable isotope tracers may be highly suitable for assessing the movement and the fate of injected CO2 in the reservoir because they label the injected CO2 directly rather than a co-injected compound. They are also inherent in the injected CO2 and hence are available at no additional cost. Furthermore, the carbon isotope signature of the injected CO2 is transferred to dissolved and solid carbon compounds in the reservoir (equations (1) and (2)) with known isotope fractionation effects (Becker et al., 2011; Mook et al., 1974). Therefore, carbon isotope ratios are not only suitable for tracing the movement of injected CO2 but also for identifying the occurrence of solubility, ionic, and mineral trapping in the reservoir. In addition, it has been shown that oxygen isotope ratios of injected CO2 may change the oxygen isotope ratios of reservoir brines (Johnson et al., 2011a) thereby providing an independent indicator of pore space saturation with injected CO2 (Johnson and Mayer, 2011). However, the usefulness of the stable isotopic composition of injected CO2 has not been demonstrated for a CO2 storage project with annual injection volumes in excess of 1 million tons CO2 over time spans of a decade. The objective of this study was to test the usefulness of isotopic techniques to trace the fate of CO2 injected over a 10year period at the IEA-GHG Weyburn-Midale CO2 Monitoring and Storage project in Saskatchewan, Canada.

Fig. 1. Location of Weyburn in southern Saskatchewan. Also shown is the pipeline from the Great Plains Synfuel Plant, Beulah (North Dakota, USA) that provides the anthropogenic CO2 that has been injected into the reservoir since 2000.

2. Study site The Weyburn field is one of a number of large oilfields that are located along the Mississippian subcrop belt on the northern extent of the Williston Basin. Located approximately 130 km SE of Regina, Saskatchewan (Fig. 1), medium gravity crude oil is produced from the Midale beds of the Mississippian Charles Formation (Fig. 2a). The Weyburn reservoir is comprised of the tight dolomitic Marly zone, the underlying calcitic more permeable Vuggy Shoal, a less permeable Vuggy Intershoal zone and is sealed by the Midale Evaporite anhydrite cap (Fig. 2b). Detailed descriptions of the reservoir geology are provided elsewhere in this issue and by Burrowes and Gilboy (2000) and Wilson & Monea (2004). Beginning in September 2000, the field operators have injected CO2 along with water to enhance oil recovery. The CO2 is transported via a purpose-built pipeline from the Great Plains Synfuel Plant, Beulah, North Dakota, USA (Fig. 1), where CO2 is produced from the gasification of coal. Approximately 5 × 106 kg of gas per day with a 95% CO2 purity were injected via 27 combined water and gas injectors in the Phase 1A area of the IEA-GHG Weyburn-Midale CO2 Monitoring and Storage project (Fig. 3). Mean reservoir operating pressures and temperatures are 15.5 MPa and 60 ◦ C. Initial geochemical monitoring efforts have been described by Emberley et al. (2005) and Raistrick et al. (2006). This paper focuses on long-term geochemical and isotopic trends over one decade of CO2 injection. 3. Sampling and methods Geochemical monitoring is one of several monitoring and verification methods utilized by the IEA GHG Weyburn-Midale CO2 Monitoring and Storage project. 3.1. Sampling and field measurements Seventeen fluid and gas sampling surveys were conducted during this 10-year project. The pre-injection, or “Baseline” survey took place in August 2000 (Table 1). After commencement of CO2 injection, “Monitor” surveys were conducted initially three times a year, typically during March/April, June/July, and September from 2000 to 2004 during Phase 1 of the project. During Phase 2 of the IEA monitoring and storage project five sampling trips were conducted resulting in a sampling frequency of two events per year, typically in October and May between 2008 and 2010. There was

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Fig. 2. (a) Mississippian stratigraphy in the Weyburn area. (b) Geological cartoon of the Weyburn reservoir, showing “flow units”, as described by Burrowes (2001).

nogeochemical monitoring from 2005 to 2007 although CO2 injection continued during this period. Approximately 40–55 wells were sampled on each monitoring event and every effort was made to collect fluid and gas samples from the same wells, although this was not always possible due to periodic well servicing and production-related shutdown. Fluid and gas samples were taken at the wellheads within and immediately adjacent to the Phase 1A pilot injection area (Fig. 3). For this study, a subset of 25 wells were selected that were sampled during most monitoring events throughout the duration of the project (Baseline to Monitor 16). This ensured utmost comparability of the obtained statistical data sets avoiding biases due to infrequent and irregular sampling. The locations of the 25 wells are shown in Fig. 3 including 5 horizontal wells and 20 vertical wells. These 25 wells adequately covered the Phase 1A area. Water and gas samples were collected to either record transient variables in the field, or preserve samples for later analysis in the laboratory. Gas samples (e.g. without any water present) obtained from the production casing were collected in 1L Tedlar® bags and gas concentration analyses were conducted as quickly

as possible in the field. Gas samples were initially analyzed with a HP M200 micro gas chromatograph (phase 1) and later with a Varian 4900 portable gas chromatograph. The portable gas chromatographs allowed on-site analysis of gas samples for a variety of species including CO2 , CH4 , H2 S, N2 , He, Ar, ethane, propane, n-butane, iso-butane, n-pentane, and iso-pentane mole fractions. Reservoir brine samples obtained at the wellhead were sampled and preserved following procedures based on those developed and used by the United States Geological Survey (Lico et al., 1982). Since it was not possible to use down-hole samplers for obtaining reservoir water samples in situ, some outgassing of CO2 likely occurred during pumping of the fluids to the surface and during sampling. To minimize these effects, we used a field laboratory to immediately preserve the samples for later laboratory analyses and measure transient parameters such as well-head pH, sulfide and alkalinity in the field. Samples were collected in 9-L Nalgene® carboys and emulsions were allowed to separate. Well-head pH was immediately recorded and two 125 ml aliquots were collected for alkalinity measurement and sulfide analysis. Electrical conductivity was measured using a portable conductivity meter and alkalinity

Table 1 Fluid and gas sampling events at the IEA GHG Weyburn-Midale CO2 Monitoring and Storage Project between August 2000 and October 2010. Also listed are the ␦13 C values of injection CO2 from the source (e.g. pipeline) and of injection CO2 (includes recycled CO2 ) sampled at various occasions resulting in an overall average ␦13 C value of −20.4 ± 0.3‰ (n = 16; includes CO2 from the source and recycled CO2 ). Trip Phase 1 Baseline Monitor 1 Monitor 2 Monitor 3 Monitor 4 Monitor 5 Monitor 6 Monitor 7 Monitor 8 Monitor 9 Monitor 10 Monitor 11 Phase 2 Monitor 12 Monitor 13 Monitor 14 Monitor 15 Monitor 16 Average *

Date

Days of CO2 injection

August 22–24, 2000 March 20–22, 2001 July 16–18, 2001 September 11–13, 2001 March 19–21, 2002 June 19–21, 2002 September 17–18, 2002 April 2–3, 2003 June 18–20, 2003 September 23–24, 2003 March 10–12, 2004 September 28–29, 2004

Prior to CO2 injection* 188 289 363 552 644 732 930 1007 1104 1273 1475

October 28–29, 2008 May 5–6, 2009 October 6–7, 2009 May 18–19, 2010 October 27–28, 2010 ±Standard deviation

2966 3155 3309 3533 3696

CO2 injection began September 15, 2000.

␦13 C of source CO2 [‰]

␦13 C of injected CO2 [‰]

−20.4

−20.8

−20.7 −20.2 −20.2 −20.9 −21.0

−20.4 −20.2 −20.5 ± 0.3

−20.4 −19.9 −20.0 −20.2 −20.4

−19.9 −20.1 −20.2 ± 0.3

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University of Calgary. All isotope ratios are reported in the internationally accepted delta (␦) notation in per mil (‰):



␦sample (‰) =

Rsample Rstandard





− 1 × 1000

(3)

where R is the 2 H/1 H, 18 O/16 O or 13 C/12 C ratio of the sample and a standard respectively. Oxygen isotope measurements of water were conducted by equilibrating CO2(g) with water at 25 ◦ C (Epstein and Mayeda, 1953). The 18 O/16 O ratio of the CO2(g) was then measured on an isotope ratio mass spectrometer (IRMS) and the ␦18 O values are reported in ‰ relative to Vienna Standard Mean Ocean Water (V-SMOW) with a measurement uncertainty <0.2‰. ␦2 H of H2 O was measured following Cr-reduction (Gehre et al., 1996). The produced hydrogen gas was analyzed on an IRMS with the ␦2 H value reported in ‰ relative to V-SMOW with a measurement uncertainty <2.0‰. The carbon isotopic composition of dissolved inorganic carbon (DIC) was measured by reacting dried SrCO3 with ortho-phosphoric acid and the evolved CO2(g) was collected in glass tubes (Atekwana and Krishnamurthy, 2004). Carbon isotope ratios of reservoir calcite and dolomite were determined using the same technique. The ␦13 C value of the evolved CO2 gas was determined by isotope ratio mass spectrometry. The ␦13 C values of DIC and carbonate minerals are reported in ‰ relative to the PeeDee Belemnite (PDB) standard with a measurement uncertainty of <0.3‰. Gas samples were also subject to isotope analyses. CO2 was isolated from other compounds and its ␦13 C value was determined by IRMS with a measurement uncertainty of 0.5‰. Fig. 3. Surface locations and identification of the 25 selected wells from which fluid and gas samples were obtained during the 10-year observation period. The red lines show the approximate locations of downhole horizontal well projections. The Phase 1A area is outlined in blue.

titrations were performed in the field. The remaining water sample was filtered through a 0.45 ␮m filter using a N2 pressure-driven filtration device. Samples were preserved for various analyses using the following methods. A 125 ml aliquot for cation analyses was acidified to pH 2 using nitric acid. A Vacutainer® containing approximately 2 ml of NH4 OH solution saturated with SrCl2 (ammoniacal strontium chloride) was filled with filtered water to precipitate SrCO3 for carbon isotope analyses on dissolved inorganic carbon. This method prevented further outgassing of CO2 . Water for oxygen and hydrogen isotope ratio measurements was collected in two separate vacutainers.

4. Results Results of chemical and isotopic measurements of samples from the 25 selected wells are presented as box plots. The diagrams show data for 25 samples from each monitoring event displaying changes in the median values and upper and lower quartiles. The median values are calculated using all of the data for each sampling event. The upper quartile is the median value calculated from the upper half of the data and the lower quartile is the median value from the lower half of the data. The interquartile distance (IQ) is defined as the difference between the upper and lower quartile. The whiskers show minimum and maximum of the data excluding outliers. Close outliers (o) are 1.5 x IQ above the upper or below the lower quartile and the far outliers (*) are 3 × IQ above the upper quartile or below the lower quartile. 4.1. Chemical parameters

3.2. Laboratory methods Analyses of aqueous samples were performed by the University of Calgary Applied Geochemistry Group including dissolved cation concentrations (Na, K, Ca, Mg, Mn, Fe, Sr, among others) and dissolved anion concentrations (Cl, Br, SO4 ). Prior to analysis of ion concentrations, water samples were diluted with deionized water by factors ranging from 10 to 10,000 dependent on the analyzed compound. Cation concentrations were measured by Atomic Absorption spectrometry on a Perkin Elmer AAnalyst 100 spectrophotometer. Anion analyses (Br− , Cl− and SO4 2− ) were conducted using a Dionex ICS2000 ion column suppression chromatograph (Dionex Corporation) with an IonPac AG-18 guard column and AS-18 anion column (Dionex Corporation) and then separated by isocratic elution using a 35.0 mM potassium hydroxide solution (Dionex Corporation). The measurement uncertainty was typically better than ±5% of the amount of analyte present. For water samples, stable isotope ratios of water (18 O/16 O and 2 H/1 H) and carbon isotope ratios of dissolved inorganic carbon (13 C/12 C) were analyzed in the Isotope Science Laboratory at the

4.1.1. Reservoir fluids A detailed discussion of chemical parameters of reservoir fluids is provided by Shevalier et al. (2013). The downhole pH values calculated using SOLMINEQ88 (Kharaka et al., 1988) are shown in Fig. 4a. The median pH value for the baseline samples was 6.3. From Monitor 1 to 11, the median pH values varied between 6.9 (Monitor 2) and 5.6 (Monitor 4). By Monitor 12 the median downhole pH value had decreased to 5.2 and decreased even further to as low as 4.9 (Monitor 15) at subsequent monitoring events. Hence the median pH decreased by more than 1 unit throughout the observation period of 10 years with the major decrease occurring between 2005 and 2007 when the geochemical monitoring program was on hold between phase 1 and 2 of the IEA GHG Weyburn-Midale CO2 Monitoring and Storage project. Box plots of the total alkalinity for Baseline to Monitor 16 are shown in Fig. 4b. The median alkalinity value at baseline was 422 mg/L. By monitor 10, median alkalinity concentrations had increased to 1185 mg/L. Between Monitor 12 and 16, median total alkalinity values had further increased markedly, varying between

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Fig. 5. Box plot of CO2 concentrations in gas samples obtained from production casings as wells sampled from Baseline to Monitor 16.

4.1.2. Casing gases Fig. 5 shows a box plot of the median concentration of CO2(gas) obtained from the production casing at the wellhead over the observation period of 10 years. The baseline sampling revealed a median concentration of 4 mole% CO2 with concentrations ranging from ∼0.4 to ∼10.0 mole%. From baseline to Monitor 11, the median concentration varied from ∼3.7 to ∼6.9 mole%. The range of the first and third quartiles did not change significantly varying from 2.9 to 8.0 mole%, except for Monitor 6 and 8 to 11. There was, however, an increase in the number of wells with high CO2 concentrations, i.e. wells where CO2 breakthrough was observed. During Monitor 8–11, there was no increase in the median CO2 concentration but rather an increase in the third quartile, i.e. 25% of the samples had significantly increased CO2 concentrations. For Monitor 12–16, a marked increase in the median CO2 concentration was observed yielding values ranging from 64 to 75 mole%. This reveals that CO2 breakthrough occurred in numerous wells between 2005 and 2007 when the geochemical monitoring program was on hold between phase 1 and 2 of the IEA GHG Weyburn-Midale CO2 Monitoring and Storage project. 4.2. Carbon isotope ratios The carbon isotope ratios of CO2 and dissolved inorganic carbon (DIC) in produced fluids are important parameters in tracing the movement of injected CO2 and the dissolution of CO2 and reservoir minerals.

Fig. 4. Box plots for downhole pH (a), total alkalinity (b) and calcium concentrations (c) in the reservoir brines for all sampling events.

2006 mg/L (Monitor 14) and 2412 mg/L (Monitor 12). Hence, total alkalinity had more than quadrupled throughout the observation period of 10 years with the major increase occurring between 2005 and 2007 (Monitor 11 and 12). Box plots of the calcium concentration for Baseline to Monitor 16 are shown in Fig. 4c. The median calcium concentration at baseline was 1359 mg/L. Despite considerable variability of median calcium concentrations especially between Monitors 3 and 8, there was a general trend of increasing Ca concentrations throughout the observation period. The median calcium concentration had increased to 1797 mg/L by Monitor 11 and further to 2059 mg/L by Monitor 16, constituting an increase of circa 50% from baseline levels.

4.2.1. Injected CO2 Pure CO2 derived via pipeline from the Great Plains Synfuel Plant (Beulah, North Dakota, USA) was measured repeatedly (n = 8) and had a ␦13 C value of −20.5 ± 0.3‰ (Table 1). Throughout the observation period, injected CO2 was increasingly supplemented by recycled CO2 obtained from producing wells after CO2 breakthrough, but the average ␦13 C value of injected CO2 did not change markedly with −20.2 ± 0.3‰ (n = 8) after addition of recycled CO2 to the injection stream (Table 1). Hence the average ␦13 C value of pipeline-derived and recycled CO2 that was injected throughout the observation period was essentially constant with −20.4 ± 0.3‰ (n = 16). 4.2.2. Reservoir calcite and dolomite Several samples of reservoir calcite and dolomite were analyzed for their carbon isotope ratios. The reservoir minerals had ␦13 C values between +3 and +5‰, that are typical for primary marine carbonates of Mississippian age (Veizer et al., 1999).

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Fig. 8. Plot of ␦13 C–CO2 values versus CO2 concentrations for all gas samples and sampling events. Fig. 6. Box plot of the ␦13 C values of CO2 in gas samples obtained from production casings from wells for all sampling events.

5. Discussion 4.2.3. CO2 of casing gases at baseline and during 10 years of injection Box plots of ␦13 C values of casing gas CO2 for the entire observation period are shown in Fig. 6. At baseline, the median ␦13 C–CO2 value was −12.7‰. Throughout monitor 1–3 the median ␦13 C value of CO2 varied between −11.8 and −16.5‰. By Monitor 5, a sharp decrease in the median ␦13 C value of CO2 to −22.3‰ was observed. Thereafter, the median ␦13 C value of CO2 slowly increased to −18.4‰ by Monitor 11 and to −16.5‰ by Monitor 12, followed by a slight decrease to a final median ␦13 C–CO2 value of −17.7‰ by Monitor 16. 4.2.4. DIC in reservoir brines at baseline and during 10 years of injection Changes in the ␦13 C values of dissolved inorganic carbon (DIC) from baseline to monitor 16 are shown in Fig. 7. The baseline sampling event yielded a median ␦13 CDIC value of −1.8‰. Until Monitor 6 there was little change in the median ␦13 C values of DIC, but there was a small number of wells that yielded fluids with decreased ␦13 CDIC values. Between Monitor 6 and 11 a trend of decreasing median ␦13 C values of DIC from ∼−2‰ to −9.2‰ was observed. Between Monitor 12 and 16 the median ␦13 CDIC decreased further to values between −11.6‰ (Monitor 16) and −13.0‰ (Monitor 12). A small number of wells yielded fluids with higher ␦13 CDIC values.

Fig. 7. Box plot of the ␦13 C values of DIC in water samples for all sampling events.

A prerequisite for using stable carbon isotopes as a tracer in CCS projects is that the ␦13 C value of the injected CO2 is reasonably constant and different from the ␦13 C values of carbon compounds in the reservoir brines and the minerals comprising the reservoir rock. At the IEA-GHG Weyburn-Midale CO2 Monitoring and Storage project, injected CO2 had a very constant ␦13 C value of −20.4‰ over the 10-year observation period. Furthermore, the carbon isotope ratio of the injected CO2 was more than 18‰ lower than the average ␦13 C values of dissolved inorganic carbon in baseline reservoir brines (−1.8‰) and carbonate minerals of the reservoir rock (+4‰). This large difference in ␦13 C values is ideal for tracing the interaction of injected CO2 with reservoir brines and minerals. The average ␦13 C value of casing gas CO2 at baseline was with −12.7‰ less distinct from that of the injected CO2 (−20.4‰) and there was also considerable variability in the carbon isotope ratios of baseline CO2 (Fig. 6). This provided less favorable conditions for using carbon isotope ratios for tracing the movement of injected CO2 . Nevertheless, combining chemical and isotopic parameters provides unique information about the movement and the fate of injected CO2 in the reservoir. A cross plot of ␦13 C–CO2 values versus the concentration of casing gas CO2 is shown in Fig. 8 with different symbols for baseline, Monitor 1–11 (phase 1) and Monitor 12–16 (phase 2). Also shown is the ␦13 C value of the injection CO2 , −20.4‰. The median baseline ␦13 C–CO2 value was −12.7‰ with individual ␦13 C values ranging between −7.8 and −20.2‰, while CO2 concentrations were generally below 10 mole%. During phase 1, CO2 concentrations in samples from many wells remained in the range of baseline concentrations, while ␦13 C values varied widely from as high as −8‰ to as low as −29‰. ␦13 C–CO2 values below that of the injection CO2 indicate mobilization of petroleum derived CO2 (Fuex, 1977) and were predominantly observed during Monitor 4–6 (Figs. 8 and 9). With increasing CO2 concentrations, the ␦13 C–CO2 values approached progressively that of the injection CO2 (−20.4‰), especially for samples obtained in phase 2. This provides evidence that the increasing CO2 concentrations in the casing gas samples obtained from the observation wells are caused by the injected CO2 . Provided that the ␦13 C value of baseline casing gas CO2 is sufficiently distinct from that of injected CO2 , a two endmember mixing model can be applied to quantify the proportions of injected CO2 in the produced gas for every individual sample obtained from the production casing of the observation wells. An example is shown for well 08–23 in Fig. 9. At baseline, casing gas had ∼4 mole% CO2 and a ␦13 C value near −7‰. A doubling of the initial CO2 concentration to ∼8 mole% resulted in a decrease of the ␦13 C values to

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Fig. 9. Plot of ␦13 C–CO2 values versus CO2 casing gas concentrations for a single well (08–23). Also shown is the two endmember mixing model that enables the estimation of proportions of injected CO2 in the sampled gas stream.

∼−13.5‰ (Fig. 9) indicating that ∼50% of the casing gas CO2 was derived from the injected CO2 . Higher proportions of injected CO2 (>50%) in the casing gas samples resulted in even lower ␦13 C values approaching that of the injected CO2 (−20.4‰). Such diagrams reveal that ␦13 C values of casing gas are especially valuable as an early warning parameter indicating the arrival of injected CO2 at times when CO2 concentrations are only marginally higher than background values. At CO2 concentrations >30 mole%, the observed ␦13 C values typically plotted a few per mil above the two endmember mixing line (Fig. 9), suggesting an additional CO2 source with carbon isotope ratios higher than that of the injected CO2 . Injected CO2 will partially dissolve in the reservoir brines and may dissociate into HCO3 − dependent on pH as indicated in reaction (1). A plot of ␦13 CDIC values versus total alkalinity is shown in Fig. 10 with different symbols for baseline, Monitor 1–11 (phase 1) and Monitor 12–16 (phase 2). Dissolution of CO2 and dissociation to HCO3 − is accompanied by carbon isotope fractionation. If the pH in the reservoir brine is low (e.g. <4) so that dissolved inorganic carbon occurs predominantly as H2 CO3 then the resulting ␦13 CDIC values can be 1‰ lower than that of the injected CO2 (Clark and Fritz, 1997). At pH values >7, HCO3 − is the predominant dissolved inorganic carbon species and carbon isotope fractionation during dissociation of H2 CO3 will result in ␦13 CDIC values that are approximately 5‰ higher than that of the injected CO2 under the reservoir conditions at Weyburn (Bottinga, 1968; Mook et al., 1974). Therefore, dissolved inorganic carbon (DIC) entirely derived from and in equilibrium with injected CO2 is expected to have ␦13 CDIC values ranging from −21.4 to −15.5‰ (at 56 ◦ C) dependent on the pH of the reservoir fluids. In phase 2 of the observation period (2008–2010),

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Fig. 11. Plot of ␦13 C values of DIC versus total alkalinity in reservoir water samples from a single well (14–11). Also shown is the two endmember mixing model that enables the estimation of proportions of carbon (C) in DIC from injected CO2 in the sampled reservoir brines.

the median downhole pH values of reservoir brines had decreased to 5.2–4.9. At these low pH values less than 50% of the H2 CO3 will dissociate to HCO3 − and hence we predict that the ␦13 C value of DIC in equilibrium with injected CO2 would be circa −19 ± 2‰. It is apparent from Fig. 10 that increasing total alkalinity and hence increasing HCO3 − concentrations were accompanied by decreases in the ␦13 C values of dissolved inorganic carbon (DIC). Especially in phase 2 of the project, the ␦13 CDIC values trended toward the equilibrium value of −19 ± 2‰ while total alkalinity concentrations had quadrupled from baseline values (Fig. 4b). This indicates that dissolution of CO2 and dissociation to HCO3 − was a major cause for the decreasing ␦13 C values of DIC. The fact that the ␦13 C remained more than 3‰ above the approximate equilibrium value of −19‰ suggests that there is an additional HCO3 − source with elevated ␦13 C values. The increases of calcium (Fig. 4c) and magnesium (not shown) concentrations provide independent evidence that calcite and dolomite dissolution generated additional HCO3 − thereby contributing to ionic trapping of injected CO2 according to reaction (2). Provided that the baseline ␦13 C value of DIC is sufficiently distinct from −21.4 to −15.5‰, a two endmember mixing model can be applied to quantify the proportions of DIC derived from injected CO2 and carbonate dissolution for every individual observation well. An example is shown for well 14–11 in Fig. 11. At baseline, the total alkalinity concentration in the reservoir brine was ∼500 mg/L with a ␦13 CDIC value of +0.5‰. After Monitor 8, total alkalinity had increased to more than 2400 mg/L and ␦13 CDIC values ranged between −13 and −16‰ (Fig. 11). This suggests that increasingly acidic formation waters (Fig. 4a) due to dissolution of injected CO2 promoted carbonate dissolution in the storage reservoir resulting in an increase in total alkalinity (Fig. 4b), Ca (Fig. 4c) and Mg concentrations, while ␦13 C values of DIC decreased (Fig. 7). It is, however, important to note that in an operating oil field deviations from the patterns shown in Figs. 9 and 11 frequently occur as a result of well shutdowns and workovers, water-alternating gas injection, and other operational disruptions. 6. Conclusions

Fig. 10. Plot of ␦13 C values of DIC versus total alkalinity in water samples for all sampling events.

Regulatory and safety issues dictate that successful CCS projects will require the ability to trace the fate of CO2 in engineered storage reservoirs (IPCC, 2005). Here we demonstrate that carbon isotope ratios are an effective and inexpensive tool to trace the movement and reaction of injected CO2 at the IEA-GHG Weyburn-Midale CO2 Monitoring and Storage project, since the ␦13 C value of the injected CO2 is distinct from those of reservoir minerals and DIC, and to a lesser extent from CO2 in baseline brines. We have shown using

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aggregated results for reservoir fluids and casing gases from 25 wells sampled over 10 years that the path of injected CO2 can be traced geochemically due to the distinct isotopic signatures associated with the injected CO2 . Arrival of injected CO2 at an observation well results in decreasing ␦13 CCO2 values while CO2 concentrations in production casing gas samples increase allowing for an apportionment of injected CO2 in the produced gas. Reaction of CO2 with the formation water results in a more acidic water (i.e. lower pH) that promotes carbonate dissolution. This has resulted in increased total alkalinity concentrations while ␦13 C values of DIC asymptotically decrease toward −19 ± 2‰. The more acidic brine facilitates calcite and dolomite dissolution, resulting in a buffering of the pH and higher ␦13 C values of DIC than expected from CO2 dissolution alone. Furthermore, increased concentrations of Ca2+ , Mg2+ and total alkalinity in the reservoir brine are evidence of ionic trapping of injected CO2 , a process that enhances the storage security of injected CO2 at CCS sites. We strongly recommend to test at all large scale geological CO2 storage sites if the isotopic composition of injected CO2 is distinct enough to be used as an inherent tracer for the movement and the fate of CO2 in the reservoir. Acknowledgements The International Energy Agency (IEA) Weyburn-Midale project was coordinated by the Petroleum Technology Research Center (PTRC) of Regina, Saskatchewan, in collaboration with Cenovus (the operator of the Weyburn oilfield) and Apache Corporation (the operator of the Midale oilfield). Financial sponsorship of the project was provided by Natural Resources Canada, the U.S. Department of Energy, Alberta Energy Research Institute, Saskatchewan Industry and Resources, the European Community and 10 industrial sponsors. We thank staff from Cenovus for their support during field work at the Weyburn site. References Assayag, N., Matter, J., Ader, M., Goldberg, D., Agrinier, P., 2009. Water-rock interactions during a CO2 injection field-test: implications on host rock dissolution and alteration effects. Chemical Geology 265, 227–235. Atekwana, E.A., Krishnamurthy, R.V., 2004. Extraction of dissolved inorganic carbon (DIC) in natural waters for isotope analyses. In: de Groot, P.A. (Ed.), Handbook of Stable Isotopes Analytical Techniques. Elsevier, Amsterdam. Becker, V., Myrttinen, A., Blum, P., van Geldern, R., Barth, J.A.C., 2011. Predicting delta C-13(DIC) dynamics in CCS: a scheme based on a review of inorganic carbon chemistry under elevated pressures and temperatures. International Journal of Greenhouse Gas Control 5, 1250–1258. Boreham, C., Underschultz, J., Stalker, L., Kirste, D., Freifeld, B., Jenkins, C., EnnisKing, J., 2011. Monitoring of CO2 storage in a depleted natural gas reservoir: gas geochemistry from the CO2 CRC Otway Project, Australia. International Journal of Greenhouse Gas Control 5, 1039–1054. Bottinga, Y., 1968. Calculation of fractionation factors for carbon and oxygen isotopic exchange in the system calcite – carbon dioxide – water. Journal of Physical Chemistry 72, 800–808. Burrowes, G., 2001. Investigating CO2 storage potential of carbonate rocks during tertiary recovery from a billion barrel oil field, Weyburn, Saskatchewan: part – reservoir geology (IEA Weyburn Monitoring and Storage Project). Saskatchewan Energy & Mines. Burrowes, G., Gilboy, C., 2000. Investigating sequestration potential of carbonate rocks during tertiary recovery from a billion barrel oil field, Weyburn, Saskatchewan: the Geoscience Framework. IEA Weyburn CO2 Monitoring and Storage Project Report. Chadwick, A., Arts, R., Eiken, O., Williamson, P., Williams, G., 2006. Geophysical monitoring of the CO2 plume at Sleipner, North Sea – an outline review. In: Lombardi, S., Altunina, L.K., Beaubien, S.E. (Eds.), Advances in the Geological Storage of Carbon Dioxide: International Approaches to Reduce Anthropogenic Greenhouse Gas Emissions. , pp. 303–314. Clark, I., Fritz, P., 1997. Environmental Isotopes in Hydrogeology. Lewis Publishers, Boca Raton, New York. Emberley, S., Hutcheon, I., Shevalier, M., Durocher, K., Mayer, B., Gunter, W.D., Perkins, E.H., 2005. Monitoring of fluid-rock interaction and CO2 storage through produced fluid sampling at the Weyburn CO2 -injection enhanced oil recovery site, Saskatchewan, Canada. Applied Geochemistry 20, 1131–1157.

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