Tracing the movement of CO2 injected into a mature oilfield using carbon isotope abundance ratios: The example of the Pembina Cardium CO2 Monitoring project

International Journal of Greenhouse Gas Control 5 (2011) 933–941

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Tracing the movement of CO2 injected into a mature oilfield using carbon isotope abundance ratios: The example of the Pembina Cardium CO2 Monitoring project Gareth Johnson ∗,1 , Bernhard Mayer, Maurice Shevalier, Michael Nightingale, Ian Hutcheon Applied Geochemistry Group, Department of Geoscience, University of Calgary, 2500 University Drive NW, Calgary, Alberta, Canada T2N 1N4

a r t i c l e

i n f o

Article history: Received 22 December 2009 Received in revised form 16 January 2011 Accepted 11 February 2011 Available online 15 March 2011 Keywords: Stable isotopes CO2 storage Carbon isotopes Enhanced oil recovery Cardium formation Pembina Alberta

a b s t r a c t During CO2 storage operations in mature oilfields or saline aquifers it is desirable to trace the movement of injected CO2 for verification and safety purposes. We demonstrate the successful use of carbon isotope abundance ratios for tracing the movement of CO2 injected at the Cardium CO2 Storage Monitoring project in Alberta between 2005 and 2007. Injected CO2 had a ı13 C value of −4.6 ± 1.1‰ that was more than 10‰ higher than the carbon isotope ratios of casing gas CO2 prior to CO2 injection with average ı13 C values ranging from −15.9 to −23.5‰. After commencement of CO2 injection, ı13 C values of casing gas CO2 increased in all observation wells towards those of the injected CO2 consistent with a two-source endmember mixing model. At four wells located in a NE-SW trend with respect to the injection wells, breakthrough of injected CO2 was registered chemically (>50 mol% CO2 ) and isotopically 1–6 months after commencement of CO2 injection resulting in cumulative CO2 fluxes exceeding 100,000 m3 during the observation period. At four other wells, casing gas CO2 contents remained below 5 mol% resulting in low cumulative CO2 fluxes (<2000 m3 ) throughout the entire observation period, but carbon isotope ratios indicated contributions between <30 and 80% of injected CO2 . Therefore, we conclude that monitoring the movement of CO2 in the injection reservoir with geochemical and isotopic techniques is an effective approach to determine plume expansion and to identify potential preferential flowpaths provided that the isotopic composition of injected CO2 is constant and distinct from that of baseline CO2. © 2011 Elsevier Ltd. All rights reserved.

1. Introduction Monitoring of the fate of injected CO2 in geological storage operations is essential for both safety and verification purposes and can be used to demonstrate the effectiveness of CO2 storage and to identify potential leakage from the site (IPCC, 2005). Distribution of the CO2 in the subsurface can be monitored using a number of methods including geophysical and geochemical techniques. Globally, a number of CO2 storage projects are currently operational or have been completed that used various monitoring techniques to determine the movement and the fate of the injected CO2 . The Sleipner project has been operating in the Norwegian North Sea since 1996 injecting approximately 1 million metric tonnes of CO2 a year. At Sleipner a number of geophysical monitoring techniques have been used (e.g. Chadwick et al., 2006) but no geochemical monitoring is possible due to a lack of obser-

∗ Corresponding author. Tel.: +1 403 220 7404; fax: +1 403 220 8514. E-mail addresses: [email protected], [email protected] (G. Johnson). 1 Current address: Midland Valley Exploration Ltd, 144 West George Street, Glasgow G2 2HG, United Kingdom. Tel.: +44 (0) 141 332 2681; fax: +44 (0) 141 332 6792. 1750-5836/$ – see front matter © 2011 Elsevier Ltd. All rights reserved. doi:10.1016/j.ijggc.2011.02.003

vation wells. The Weyburn CO2 Monitoring and Storage project in Saskatchewan, Canada, commenced in 2000 injecting approximately 2 million metric tonnes of CO2 per year. Here both geophysical and geochemical monitoring techniques are used, the latter including stable isotope techniques suitable to trace the fate of injected CO2 in the storage reservoir (e.g. Emberley et al., 2005; Raistrick et al., 2006; White et al., 2004). At the In Salah CO2 project in Algeria approximately 1 million metric tones CO2 per year has been injected since 2005. Various geophysical and geochemical techniques have been deployed to monitor the CO2 in the reservoir. At a smaller pilot scale, the Otway Project in Victoria (Australia) with 65,000 tonnes of CO2 over 15 month (Stalker et al., 2009b), the Frio project in Texas (USA) with 1600 tonnes of CO2 over 10 days (Hovorka et al., 2006), and the Ketzin project in Germany with a planned total of 60,000 tonnes of CO2 (Myrttinen et al., 2010) have used extensive geophysical and geochemical monitoring techniques, with all of them also using stable isotope ratios to trace the migration of the CO2 (Kharaka et al., 2006; Myrttinen et al., 2010; Stalker et al., 2009a). This paper reports on a 3-year field experiment at the Pembina Cardium CO2 Storage Monitoring site in Alberta (Canada) during which a number of geophysical and geochemical monitoring techniques for CO2 storage were tested.

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Geochemical monitoring depends on the ability to sample fluids and gases at observation wells either at reservoir conditions or at the wellhead. Of the five projects listed above with geochemical monitoring, In Salah (Ringrose et al., 2009), Weyburn (Emberley et al., 2005) and Pembina use wellhead sample collection techniques whereas Frio (Freifeld et al., 2005), Ketzin (Myrttinen et al., 2010) and Otway (Stalker et al., 2009b) used downhole sampling techniques. Downhole sampling is preferable to wellhead sampling due to the changes in fluid and gas composition that can occur with depressurization and temperature changes as the sample travels from the reservoir to the wellhead. However, downhole sampling is more costly and requires that an observation well is used or that producing wells are shut down for the sampling to take place. An innovative down-hole sampling device called the U-tube (Freifeld et al., 2005) was developed for the Frio CO2 storage project and has subsequently been used at the Otway project. This device facilitates accurate and high frequency sampling of in situ fluids and gases at reservoir pressure and temperature conditions. However, at large operating oilfields with numerous production and observation wells, shut-in of wells for deployment of U-tubes or similar devices may be problematic. Sampling of fluids and casing gases at the wellhead is a viable alternative but requires that the chemical compositions of fluid samples are corrected for the CO2 loss via exsolution with depressurization using Henry’s Law calculations in geochemical programs such as SOLMINEQ88 (Kharaka et al., 1988). Geochemical parameters that are typically monitored in reservoir fluids and gases include pH, temperature, electrical conductivity, alkalinity, major ions (e.g. Na, K, Ca, Mg, Mn, Fe, Cl, Si, SO4 etc.), gas composition and stable isotope abundance ratios of water (ı18 O, ı2 H), dissolved constituents such as dissolved inorganic carbon (e.g. ı13 CDIC ), and gases (e.g. ı13 CCO2 ) (IPCC, 2005). The isotopic composition of the injected CO2 may provide an ideal tracer for the assessment of the movement and the fate of injected CO2 in the reservoir because it labels the injected CO2 directly rather than constituting a co-injected compound. Stable carbon isotope ratios (13 C/12 C expressed as ı13 C values) have been used successfully for more than five decades in environmental research. Applications have included tracing the fate of atmospheric CO2 in the oceans (e.g. Bauch et al., 2000; Beveridge and Schackleton, 1994), fluxes of respiration CO2 in ecosystems (e.g. Bowling et al., 2008; Pataki et al., 2003), CO2 from deep magmatic sources in geological settings (e.g. Ballentine et al., 2000; Gilfillan et al., 2009), and more recently tracing the fate of elevated atmospheric CO2 contents in forested and agricultural ecosystems in FACE experiments (e.g. Keel et al., 2006; Taneva et al., 2006), among many others. The successful application of stable isotope techniques requires that the CO2 of interest is isotopically distinct from background CO2 that occurs naturally in the system. Hence, if CO2

injected into mature oilfields or saline aquifers has carbon isotope ratios that are significantly different from those of naturally occurring CO2 or other dissolved carbon species in the reservoir, then ı13 C values constitute a suitable tracer for following the movement and reactions of injected CO2 in the reservoir (e.g. Assayag et al., 2009; Emberley et al., 2005; Myrttinen et al., 2010; Raistrick et al., 2006), provided that there are a sufficient number of monitoring wells for obtaining fluids and gases during monitoring, verification and assessment (MVA) programs. The objective of this study was to evaluate whether carbon isotope ratios of produced gases can be used to monitor the movement of injected CO2 in the subsurface at the Pembina Cardium CO2 Storage Monitoring project in Alberta, Canada. 2. Study site The study was conducted in the Pembina area west of Edmonton (Alberta, Canada) in one of the biggest and oldest onshore oilfields in Canada. The Pembina Cardium CO2 Monitoring Pilot site is located near the town of Drayton Valley (Fig. 1). It is an enhanced oil recovery (EOR) operation hosted in the Upper Cretaceous Cardium Formation of the Pembina oil field. The Cardium is a siliciclastic reservoir at approximately 1650 m depth and reservoir temperature and pressure of 50 ◦ C and 19 MPa respectively (Hitchon, 2009). The Conacian-Turonian (88.5 Ma) Cardium Formation is located near the middle of the 650 m thick Colorado Group Shale (Dashtgard et al., 2008), overlain by the First White Speckled Shale and underlain by the Blackstone Formation Shale (Fig. 2a). The Cardium Formation is sub-divided into 4 reservoir units separated by either shale or sandy-shale beds: the lower sandstone, middle sandstone, upper sandstone and conglomerate (Fig. 2b). A regionally extensive shale unit separates the lower and middle sandstones, while the middle and upper sandstones comprise a single reservoir unit separated by a zone of thin shale interbeds with little vertical barrier to flow. The conglomerate is present in all wells but is highly variable in both terms of thickness and reservoir quality. There is no barrier to flow between the upper sandstone and the conglomerate where present (Hitchon, 2009) and connectivity between all stratigraphic horizons has been enhanced by hydraulic fracturing of the reservoir prior to oil production. The three sandstone units are compositionally similar and are classified as sub-mature to mature lithic to quartz arenites while the conglomeratic unit varies from clast-supported, quartzose conglomerate to matrix-supported quartzose diamictite (Dashtgard et al., 2008). The reservoir is non-uniformly stratified with generally low permeabilities (conglomerate, 160 md, upper and middle sandstones, 17 md, lower sandstones, 2 md) (Krause et al., 1987).

Fig. 1. Location map of the Pembina Cardium CO2 Storage Monitoring Pilot in west-central Alberta. Well bottom-hole locations at dots. Blue = group 1 wells, green = group 2 wells, red = CO2 injectors with deviated well trajectories delineated. Grey outlined area shows CO2 -EOR area containing 6 of the production wells and both CO2 injectors. The distinction between the grouping of wells is based upon the response of the wells to CO2 injection. Group 1 wells are characterized by large cumulative CO2 fluxes, and large changes in ı13 C values of CO2 . Group 2 wells display very little CO2 flux and smaller changes in ı13 C values of CO2 (Johnson et al., 2011). (For interpretation of the references to color in this figure legend, the reader is referred to the web version of the article.)

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Fig. 2. (a) Stratigraphic correlation chart from the top of the Mannville (Early Cretaceous) to the Paskapoo (Tertiary) (from Dashtgard et al., 2008). (b) Core-log from a local well (100/03-07-048-08W5) in the Cardium formation (adapted from Dashtgard et al., 2008). (c) Joli Fou to Blackstone Shale (JB) top structure map (or base of Cardium Formation) showing local dip to the southwest (from Dashtgard et al., 2008). Location of 6 production wells (red) and two injection wells (black) within the CO2 -EOR area shown (see Fig. 1 for location of CO2 -EOR area). (For interpretation of the references to color in this figure legend, the reader is referred to the web version of the article.)

Porosity varies from an average of 7.4% in the conglomerate, to 16.4% in the upper sandstone, 16.2% in the middle sandstone and 14.8% in the lower sandstone (Dashtgard et al., 2008). Regional dip in the area is to the southwest (Fig. 2c) and net pay increases locally to the north (Dashtgard et al., 2008). It is important to consider the geological structure, composition, and heterogeneity when predicting fluid migration pathways, as significant control will be exerted by the geology of the reservoir. Reservoir modeling conducted for the site, for example, predicted a preferential flow pathway of the CO2 plume in a NE-SW direction based on reservoir geology with CO2 movement occurring mostly in the upper 3 units (middle and upper sandstones and conglomerate) of the reservoir (Hitchon, 2009). At the Pembina Cardium CO2 Monitoring Pilot site, approximately 75,000 tonnes of CO2 were delivered by truck and injected between 2005 and 2008 by two injector wells over two 5-spot pat-

terns (1 injector, 4 producers) with 2 production wells being shared between the patterns (Hitchon, 2009) (Fig. 1). Injection on both wells varied with time and is shown in Fig. 3. Injection wells were perforated in the conglomerate, upper and middle sands only, while production wells are either open-hole completed (10–11, 12–12) or are perforated throughout the whole stratigraphic succession (conglomerate to lower sand). Casing gas samples were obtained from the well-head at the eight production wells sampled approximately monthly between February 2005 and March 2008. The baseline data was collected repeatedly between February and April 2005 allowing estimation of natural variability of various geochemical parameters. During the first baseline sampling, no gas was produced at any of the production wells; therefore only a maximum of two baseline gas samples exist for the wells. Additionally, well 8–11 on the second baseline sampling occasion and wells 7–11 and 10–11 on the third baseline sampling event were not producing

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Fig. 3. CO2 injection rates of the two injection wells.

gas or fluids. Lastly, well 12–12 reports only one baseline sample (from sampling event 2). Following baseline sampling and the commencement of CO2 injection, 15 monitoring events took place between May 2005 and January 2007. In February 2007 the EOR operation converted to a water alternating gas (WAG) regime and a further 13 monitoring events took place until March 2008. This paper focuses on the CO2 injection phase only.

values in per mil (‰) relative to the international reference material V-PDB:

3. Methods

4. Results

Casing gas samples were collected in sealed containers and the chemical composition was analyzed either in the field or immediately upon delivery of the samples to the laboratory using a Varian CP4900 Micro GC. In addition to chemical analyses, the isotopic compositions of water, CO2 , and dissolved inorganic carbon (DIC) were determined. In this paper we report the carbon isotope ratios of CO2 (ı13 CCO2 ), which were determined from the casing gas samples using a GC coupled to an isotope ratio mass spectrometer (IRMS). Casing gas is the product of both originally free-phase CO2 and CO2 that exsolved from any fluid phase and is thus total gas. Carbon isotope abundance ratios are reported using the usual delta notation as ı13 C

Fig. 4 summarizes CO2 contents of casing gas in the 8 producing wells from prior to CO2 injection in March 2005 until January 2007. CO2 contents in casing gas at baseline were less than 2.0 mol% at all eight wells with the remainder being mainly methane (∼80%), propane (∼10%) and ethane (∼10%). In four wells, casing gas CO2 increased to more than 50 mol% after 1.5 (12–12), 3.5 (9–11), 4.5 (7–11) and 6 (8–11) months of CO2 injection respectively. In the latter two wells, casing gas CO2 contents decreased again between fall 2005 and spring 2006 due to operational issues including pump replacement thus necessitating halting production and weighting the well down with ‘kill fluids’. Throughout the remainder of the observation period CO2 contents remained at >70 mol%: these wells



ı13 Csample =

(13 C/12 C)sample (13 C/12 C)reference



− 1 × 1000 V − PDB

(1)

Accuracy and precision for the ı13 CCO2 values is better than ±0.5‰.

Fig. 4. Mole % CO2 versus sampling date for all wells.

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Fig. 5. Cumulative CO2 flux (103 m3 ) versus sampling date for all wells (Johnson et al., 2011).

will be referred to as group 1. In the four other wells (1–11, 4–12, 5–12 and 10–11), CO2 contents in casing gas remained below 5% after commencement of CO2 injection throughout the observation period. These wells will be referred to as group 2. CO2 fluxes were calculated using measured CO2 contents multiplied by production gas volumes. In group 2 wells, cumulative CO2 fluxes remained below 2000 m3 during the entire observation period (Fig. 5). In group 1 wells, where CO2 breakthrough had been observed, cumulative CO2 fluxes ranged from 123,000 (8–11) to 461,000 (12–12) m3 during the observation period (Fig. 5). The carbon isotope ratio of injection CO2 was determined repeatedly. The average ı13 C value was −4.6‰ with a standard deviation of ±1.1 (1␴, n = 23) providing evidence that the trucked-in CO2 had consistent carbon isotope abundance ratios. Fig. 6a and b summarize the measured ı13 C values of CO2 in casing gas collected at the well heads for baseline conditions and 22 months of CO2 injection. The average ı13 C values of CO2 at baseline varied between −15.9 and −23.5‰ (Table 1). After commencement of CO2 injection, ı13 C values of casing gas CO2 from group 1 wells increased rapidly from baseline values towards values near −6‰ within 4 months (Table 1, Fig. 6a) and remained near injection CO2 ı13 C values throughout the remaining observation period. In group 2 wells, carbon isotope ratios of casing gas CO2 also increased from baseline values to average ı13 C values ranging between −12.3 and −9.3‰ after 8 months remaining more or less constant throughout the remaining observation period (Table 1, Fig. 6b). 5. Discussion Average baseline ı13 C values of CO2 ranged from −15.9 to −23.5‰ with a mean value of −18.6 ± 3.6‰ (n = 12) (Table 1). The Pembina Cardium Formation is predominantly siliciclastic with minor amounts of carbonate cements (∼1.5% calcite and siderite) with ı13 Ccarbonate values that range from −4.6 to −16.8‰ and a mean value of −10.0 ± 3.5‰ (n = 21). Hence, CO2 in isotopic equilibrium with the carbonate minerals at the reservoir temperature (Bottinga, 1968) is expected to have ı13 C values between −12.0 and −24.2‰ (mean of −17.4‰), consistent with our observations. Machemer and Hutcheon (1988) reported ı13 C values for carbonate cements in the Cardium to vary even more widely from 0 to −30‰. Injected CO2 had a ı13 C value of −4.6‰ and was therefore more than 10‰ higher than the carbon isotope ratios of baseline casing

gas CO2 . Fig. 7 shows that in all 8 observation wells ı13 C values of casing gas CO2 increased towards those of the injected CO2 with increasing casing gas CO2 contents after commencement of CO2 injection. The observed trends are consistent with a simple two endmember mixing model:

 13

ı CCO2 -measured =



ı13 CCO2 -injected × CO2 injected

 

+ ı13 CCO2 -baseline × [CO2 baseline ])

[CO2 measured ]

(2) where the subscripts CO2 -injected, CO2 -baseline and CO2 measured refer to injection CO2 , baseline CO2 and the mixture created between the two respectively, and square brackets indicate fractions of the component where CO2 -measured = 1. The theoretical mixing curves shown in Fig. 7a–h were drawn using the respective average baseline ı13 C values for CO2 from the 8 observation wells (Table 1), a ı13 C value for injection CO2 of −4.6 ± 1.1‰, and the assumption of no isotope fractionation occurring during CO2 transport and exsolution in the observation wells. In group 1 wells, the two endmember mixing model revealed that injected CO2 constituted >90% of the sampled gas only a few months after injection commenced. At well 12–12, CO2 constituted >88% of the sampled gas only 1 month after injection and throughout the rest of the observation period (Fig. 7a) resulting in the highest cumulative CO2 fluxes of 461,000 m3 during the observation period (Fig. 5). At well 9–11, CO2 constituted >90% of the sampled casing gas 2 months after injection commenced and throughout the rest of the observation period (Fig. 7b) while registering the second highest cumulative CO2 fluxes with ∼300,000 m3 (Fig. 5). At wells 7–11 and 8–11, injected CO2 comprised >80% of the sampled gas 2 (Fig. 7c) and 6 months (Fig. 7d) after commencement of CO2 injection respectively. This slower response resulted also in lower cumulative CO2 fluxes of 157,000 and 123,000 m3 respectively. Hence, chemical and isotopic data clearly revealed breakthrough of injected CO2 in group 1 wells between 1 and 6 months after commencement of CO2 injection. In contrast, CO2 contents in the casing gas of group 2 wells remained comparatively low throughout the observation period (Fig. 4). The two endmember mixing model, however, revealed that injected CO2 was increasingly produced throughout the observation period. During the first 3 months after commencement of CO2 injection, injected CO2 constituted <30% of the sampled casing gas at all four group 2 wells (Fig. 7e–h). Throughout the rest of the

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Fig. 6. (a) ı13 C CO2 ‰ versus sampling date for group 1 wells. (b) ı13 C CO2 ‰ versus sampling date for group 2 wells.

observation period carbon isotope data indicated that injected CO2 constituted between <30 and 80% of the sampled CO2 (Fig. 7e–h) although CO2 contents and therefore cumulative CO2 fluxes (Fig. 5) remained very low. Nevertheless, the addition of small amounts of injected CO2 rapidly increased the ı13 C value of the sampled casing gas CO2 , providing evidence that injected CO2 had also begun to arrive at group 2 wells although only in low quantities. This demonstrates the usefulness of using stable isotope techniques to

trace CO2 movement in the injection reservoir and its sensitivity to detecting small amounts of isotopically distinct injection CO2 . Inspection of Fig. 1 reveals that group 1 wells lie in a trend NESW of the two injector wells while group 2 wells are located almost perpendicularly to this trend. The beds of the Cardium dip locally to the southwest (Fig. 2). The geographic distribution of group 1 wells that recorded significant CO2 breakthrough therefore suggests that the injected CO2 is flowing preferentially parallel to dip both in an up-dip and down-dip direction. As inferred from borehole breakout

Table 1 Mole % CO2 and ␦13 C values of CO2 at baseline and at the final monitoring event for the eight observation wells. Values in brackets are 1␴ standard deviations of the mean of the baseline (where available) and 3 final monitor values. Group

Well

No. baseline samples

Baseline ı13 C CO2 ‰

Final monitor Mole % CO2

ı13 C CO2 ‰

Mole % CO2

CO2 flux 103 m3

1

7–11 8–11 9–11 12–12

1 1 2 1

−16.9 −15.9 −23.5 (5.3) −20.8

1.8 1.7 1.4 (0.1) 0.9

−5.5(0.6) −6.1 (0.2) −6.2 (0.3) −6.0 (0.1)

83.1(0.7) 88.3 (2.0) 88.8 (0.5) 90.2 (1.2)

157.1 122.9 297.0 460.9

2

1–11 4–12 5–12 10–11

2 2 2 1

−19.1 (1.1) −16.4 (0.4) −17.2 (0.1) −17.0

0.8 (0.2) 1.7 (0.0) 1.0 (0.1) 1.0

−9.3 (1.6) −10.2 (0.2) −10.0 (1.0) −12.3 (1.0)

0.9 (0.1) 1.8 (0.1) 2.2 (0.4) 1.4 (0.7)

0.4 1.2 0.7 0.2

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Fig. 7. ı13 C CO2 ‰ versus Mole % CO2 for all wells (a–d = group 1, e–h = group 2). Black dashed line is the injection CO2 ı13 C value. Blue solid line is the theoretical two-source mixing curve with dashed blue lines signifying standard deviation of ±1.1‰. Red points are the field-measured monitor values and open black circles are the baseline values. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of the article.)

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studies of 13 wells in the area, the stress regime in the reservoir is orientated such that any intra-reservoir fractures induced by historical water flooding or enhanced oil production methods would open in a vertical plane orientated in a NE-SW direction (30–59◦ ) (Bell and Bachu, 2003; Hitchon, 2009). Thus CO2 appears to be flowing preferentially along the dip and fracture direction in the reservoir. As supercritical CO2 is less dense than both oil and water at reservoir conditions (White et al., 2004) up-dip migration is expected to be the largest control on subsurface CO2 migration (IPCC, 2005). Wells 12–12 and 9–11 are both up-dip of the injector wells and are the wells that recorded the highest CO2 flux (Fig. 5) and the earliest CO2 breakthrough (Fig. 4). Wells 7–11 and 8–11 located down-dip to the SW recorded later breakthrough (Fig. 4) and lower CO2 fluxes (Fig. 5) than wells 12–12 and 9–11. Hence, there was also a significant down-dip migration of CO2 due to the high injection pressure and likely facilitated by the fracture trend induced by 50 years of production optimization and water flooding within the reservoir. Other factors that may alter flow pathways are the net pay of the Cardium Upper Sandstone, which is locally thicker to the north (Dashtgard et al., 2008), and the pressure gradients induced in the reservoir by production at individual wells. Although general flow pathways can be estimated using ı13 C values of produced CO2 at a few observation or production wells it is acknowledged that geological heterogeneities within the reservoir mean that actual flow pathway are rather tortuous as evidenced by the rates and fluxes of CO2 produced at the individual wells. Although group 2 wells lie predominantly off dip and off fracture trends from the CO2 injectors, carbon isotope abundance ratios revealed arrival of minor amounts of injected CO2 . This is likely a result of radial flow of injected CO2 from the injector wells in addition to flow induced by pressure gradients induced by production at these wells. Based on the NE-SW fracture trends, the up dip direction of the formation to the NE, and the increased net pay thickness in the north, preferential flow of injected CO2 to producing wells north and east of the injectors was expected based on reservoir geology (Hitchon, 2009). Chemical and isotopic data revealed the earliest CO2 breakthrough and the highest cumulative CO2 fluxes at wells 12–12 and 9–11 in the northeastern direction. Therefore, the isotopic composition of the injected CO2 is a suitable tracer to assess preferential flow and migration of injected CO2 provided that a sufficient number of monitoring wells are available in the reservoir.

can be used to quantify the proportion of injected CO2 in the casing gas of an observation or production well at repeated sampling events. It was shown that the carbon isotope tracing technique is especially sensitive for detecting the early arrival of injected CO2 at a time where CO2 contents increase only marginally. The two endmember mixing model in conjunction with production data can be subsequently used to determine the magnitude of flow of injected CO2 within the reservoir to different observation wells. The ability to isotopically trace injected CO2 allows the assessment of the reservoir flow paths and can be used to validate predictive models. At the Pembina Cardium Monitoring project the location of wells that registered breakthrough of injected CO2 and the distribution of wells where little injected CO2 was observed was consistent with predictive models (Hitchon, 2009) further refining the ability to monitor the fate of the injected CO2 . We conclude that ı13 C values can be used to (a) identify injected CO2 breakthrough at individual well locations and thus assess subsurface distribution of the CO2 plume; and (b) assess the proportions of injected CO2 (versus baseline CO2 ) at repeated sampling events at observation wells. The latter information is a key component (i.e. mass of injected CO2 produced) for a quantitative assessment of CO2 storage masses. The limited number of observation wells combined with the methodological and analytical uncertainties of the carbon isotope approach make it, however, impossible to precisely quantify the total amount of injected CO2 within the reservoir. However, if the ı13 C values of injected CO2 are isotopically distinct, carbon isotope ratios constitute also an excellent tracer to monitor for potential CO2 seepage outside of the storage site. While carbon isotopes can provide unique information about the movement of injected CO2 within the reservoir and on the integrity of the CO2 storage site, further work is needed to gain a better understanding of the geochemical fate of injected CO2 (e.g. Johnson et al., 2011). The described method is insensitive to downhole CO2 phase and thus is unable to distinguish between CO2 trapping mechanisms. This insensitivity means that CO2 pore space saturation in the reservoir is unresolved. Also, the method requires multiple observation/production wells to gain spatial resolution. This resolution is greatly limited by the nature of point data collected over a field. Therefore it is recommended that monitoring methods that give greater spatial resolution should be employed (either geophysical tools or geostatistical methods applied to the chemical data) in conjunction with geochemical and isotopic methods.

6. Conclusion Monitoring the fate of CO2 in the injection reservoir may become an essential component for public and regulatory acceptance of CO2 storage projects in mature oilfields and saline aquifers as a method of greenhouse gas mitigation (e.g. de Coninck et al., 2008; European Commission, 2009; IPCC, 2005; U.S. Environmental Protection Agency, 2008). This study has shown that carbon isotope ratios in conjunction with geochemical and production data can be successfully used to monitor the movement of injected CO2 in a mature oilfield in western Canada, since the ı13 C values of injected CO2 were more than 10‰ higher than those of baseline CO2 . It was demonstrated that a difference of 10‰ or more between ı13 C values of baseline and injected CO2 is sufficient for tracing the movement of injected CO2 in the subsurface provided that the isotopic composition of the injected CO2 is constant and that ı13 C values of baseline CO2 are known. It is recommended that the content and isotopic composition of baseline CO2 should be determined repeatedly to assess natural variability within the reservoir prior to commencement of CO2 injection. Based on a solid knowledge of the chemical and isotopic properties of baseline and injected CO2 , two endmember mixing models

Acknowledgements Funding for the Pembina Cardium CO2 Monitoring project is from Penn West Energy Trust, Alberta Energy Research Institute, Western Economic Diversification Canada, Natural Resources Canada and the Alberta Government. Analytical and field services provided by the Isotope Science Laboratory and the Applied Geochemistry Laboratory at the University of Calgary are also gratefully acknowledged.

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