Pembina Cardium CO2 Monitoring Pilot: A CO2-EOR Project, Alberta, Canada
... This is particularly true in the Western Canada Sedimentary Basin (WCSB) where strata are consolidated or tightly cemented and storage reservoirs are generally thin (< 100 m thick) and may have low porosity and permeability; e.g. Pembina Cardium Field (Lawton, 2009). Also in Canada, the well-known Weyburn Project in Saskatchewan illustrates subtle traveltime and amplitude anomalies in time-lapse seismic data used to monitor a CO 2 enhanced oil recovery project hosted in relatively thin dolomite reservoir (White et al., 2004). ...
... The changes in seismic properties are manifested by changes in rock moduli and a resulting decrease in P-wave velocity which in observed in traveltime delays through the CO 2 plume and changes in reflectivity (impedance) of the horizon (e.g. Sodagar and Lawton, 2009). In these computations, the shear modulus is assumed to be unaffected by fluid substitution so the S-wave velocity is predicted to increase slightly with increasing CO 2 saturation due to the small decrease in bulk density. ...
... In the Pembina Field, sparse baseline and two repeat seismic surveys were recorded over a period of two years to monitor a CO 2 enhanced oil recovery project in the Cardium Formation (Lawton, 2009;Alshuhail et al., 2009b). Timelapse analysis of the surface seismic dataset showed no significant anomaly that could be attributed to the injected supercritical CO 2 between Phase I (March 2005) and Phase III (March 2007) of the project ( Figure 5). ...
Introduction Carbon capture and storage (CCS) involves capturing CO 2 from point-source surface facilities and injecting it into subsurface geological formations, particularly depleted oil and gas reservoirs, unmineable coal seams or deep saline aquifers. In 2008 the government of Alberta committed CDN$2B to accelerate CCS in the province, with the goal of having several > 1Mt/yr CCS projects operating by 2015. Current targets are to have 50 million tonnes of CO 2 stored annually by 2020 and 139 million tonnes annually by 2050. Of paramount importance to CCS is the ability to track CO 2 plume movement, if possible, and to assess whether the CO 2 flow is consistent with model predictions, and to optimise safeguards for possible early leak detection. These goals are vital for public acceptance of CCS, particularly during early projects as the technology becomes implemented at commer-cial scale. Comprehensive yet affordable monitoring proto-cols thus need to be established. A wide range of technologies has been developed for monitoring CO 2 injection and storage, including surface and subsurface measurements and surveys, but continued research and development is required for next generation technologies that will enable effective monitoring programs to be implemented. This represents both opportu-nities and challenges for geophysics. These will be discussed in this presentation.
... The reservoir temperature is 50 • C, and average reservoir pressure after secondary water flood recovery was approximately 19 MPa. The EOR pilot consisted of two CO 2 injectors and six producers, completed in all four units (Dashtgard et al., 2006;Hitchon, 2009). ...
... Detailed analyses of the OW were completed over the tenure of the Penn West Pembina Cardium CO 2 Monitoring Project, including completion job, cement behaviour, annular flow behaviour, integrity of downhole systems long-term pressure/temperature history, etc. (Hitchon, 2009). Synthesis and integration of these analyses helps to inform recommendations on the deployment of downhole technology in OWs used for monitoring and verification of CO 2 movement in the subsurface. ...
... All fluids during the cementing operation were circulated down the tubing and up the annulus between the tubing and casing. Details of the cement operations and downhole recorded pressure and temperature data are presented by Zambrano-Narvaez and Chalaturnyk (2007) and Hitchon (2009). Fig. 6 shows analytical results of the steps during the cementing. ...
The Pembina field was chosen from several fields within Alberta, Canada, for a geological carbon dioxide (CO2) storage pilot study, in which the injection of CO2 was combined with enhanced oil recovery (EOR). As part of the project, an existing wellbore within the study area was used as a dedicated observation well. The design and initial results during cementing of this observation well are reviewed. The experience of implementing monitoring technologies was analyzed in order to assess existing knowledge for deploying downhole instrumentation used for monitoring and verification of CO2 movements in the subsurface. Analysis indicates that the observation well allows direct monitoring and measurements at reservoir level of multiple variables through geophysical, geochemical, and geomechanical instrumentation, as well as the opportunity to carry out wellbore integrity studies under in situ conditions. A post-cement job and completion analysis that couples downhole measurements and analytical simulation was conducted to improve future installations. Results verified that equivalent circulation density profiles, and minimum and maximum flow rates during placement should be determined prior cementing operations to avoid influx or fracturing in pre-cased observation wells. Results also indicate that pressure signatures during cement circulation are dominated by fluid density, volume, and rate, and not by sensor assemble geometries used to diagnose the operation. Downhole pressure gauges captured the dynamics of cement displacement and were key elements during post-cement job review and assessments of future well integrity. The experience and analyses gained from the installation of this observation well provide valuable insight for CO2 geological storage monitoring and risk/performance assessment.
... 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 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). ...
... 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 CO 2 plume in a NE-SW direction based on reservoir geology with CO 2 movement occurring mostly in the upper 3 units (middle and upper sandstones and conglomerate) of the reservoir (Hitchon, 2009). At the Pembina Cardium CO 2 Monitoring Pilot site, approximately 75,000 tonnes of CO 2 were delivered by truck and injected between 2005 and 2008 by two injector wells over two 5-spot patterns (1 injector, 4 producers) with 2 production wells being shared between the patterns (Hitchon, 2009) (Fig. 1). ...
Injection of carbon dioxide into depleted oil fields or deep saline aquifers represents one of the most promising means of long-term storage of this greenhouse gas. While the ultimate goal of CO2 injection in the subsurface is mineral storage of CO2 as carbonates, short-term (<50 year) storage of injected CO2 is most likely to be accomplished by ionic trapping of CO2 as bicarbonate ions (HCO3-) and hydrogeological trapping of molecular CO2. Here, we demonstrate a technique for quantifying ionic trapping of injected CO2 as HCO3- using geochemical data collected prior to and during 40 months of CO2 injection into a hydrocarbon reservoir at the International Energy Agency (IEA) Weyburn CO2 Monitoring and Storage Project, Saskatchewan, Canada. As a result of injection of CO2 with a low carbon isotope ratio (delta13C value), fluid and gas samples from four selected production wells showed an increase in HCO3- concentration and a decrease in delta13C values of HCO3- and CO2 over the observation period. Isotope and mass balance calculations indicate that, after 40 months of injection, approximately 80% of the HCO3- in the reservoir brines sampled from the four wells formed via dissolution and dissociation of injected CO2. This chemical and isotopic technique should be applicable to CO2 injection and storage in oil fields and in deep saline aquifers, provided there is sufficient carbon isotopic distinction between injected CO2 and baseline aquifer HCO3- and CO2.
... During the Enhanced Oil Recovery (EOR) Pembina Cardium CO 2 Monitoring Pilot in the Pembina area west of Edmonton, Alberta (Canada), two phases of CO 2 injection (total of ∼75,000 t of liquid CO 2 trucked to the site and injected in supercritical state) were conducted between March 2005 and March 2008 into the Upper Cretaceous Cardium Formation, a siliciclastic reservoir with sandstones interbedded with shales . The measured reservoir temperature was 50°C and the pressure was ∼190 bar at a depth of ∼1650 m (Hitchon, 2009). The high purity CO 2 injected during the project was delivered by Ferus Gas Industries from three different facilities where the CO 2 was captured from waste gas streams, followed by purification, liquefaction and compression. ...
... The high purity CO 2 injected during the project was delivered by Ferus Gas Industries from three different facilities where the CO 2 was captured from waste gas streams, followed by purification, liquefaction and compression. CO 2 was injected through 2 wells, with 4 observation wells for each of the 2 injection wells (Hitchon, 2009). Two of these observation wells were shared, with an additional 2 off-pattern wells for each injection well being monitored as well. ...
Structural and residual trapping of carbon dioxide (CO2) are two key mechanisms of secure CO2 storage, an essential component of Carbon Capture and Storage technology. Estimating the amount of CO2 that is trapped by these two mechanisms is a vital requirement for accurately assessing the secure CO2 storage capacity of a formation, but remains a key challenge. Here, we review recent field and laboratory experiment studies and show that simple and relatively inexpensive measurements of oxygen isotope ratios in both the injected CO2 and produced water can provide an assessment of the amount of CO2 that is stored by residual and structural trapping mechanisms. We find that oxygen isotope assessments provide results that are comparable to those obtained by geophysical techniques. For the first time we assess the advantages and potential limitations of using oxygen isotopes to quantify CO2 pore-space saturation based on a comprehensive review of oxygen isotope measurements from reservoir waters and various global CO2 injection test sites. We further summarise the oxygen isotope composition of captured CO2 in order to establish the controls on this fingerprint.
... The Pembina Cardium CO 2 Monitoring Pilot site ( Fig. 1) is located near the town of Drayton Valley, west of Edmonton (Alberta, Canada) in the Pembina Field which is the largest individual [7], and one of the oldest onshore oilfields in Canada. The Cardium is a siliciclastic reservoir at approximately 1650 m depth and reservoir temperature and pressure of 50°C and 19MPa respectively [8]. The pilot is an enhanced oil recovery (EOR) operation hosted in the Upper Cretaceous Cardium Formation of the Pembina oil field. ...
... Approximately 75,000 tons of liquid CO 2 were delivered by truck and injected between 2005 and 2008 by two injector wells over two 5-spot patterns (1 injector, 4 producers) where 2 production wells are shared between the patterns [8] (Fig. 1). Casing gas and fluid samples were obtained from eight production wells sampled approximately monthly between February 2005 and March 2008. ...
Geochemical and isotopic monitoring allows determination of CO2 presence in the subsurface through the sampling of produced fluids and gases at production and/or monitoring wells. This is demonstrated by data from 22 months of monitoring at the Pembina Cardium CO2 Monitoring Pilot in central Alberta, Canada. Eight wells centered around two CO2 injectors were sampled monthly between February 2005 and February 2007. Stable isotope analyses of the samples revealed that changes in the δ13CCO2 values in produced gas as well as changes in the δ18O values of the produced fluids indicate CO2 presence and identify trapping mechanisms at select production wells. Using equilibrium isotope exchange relationships and CO2 solubility calculations, fluid and gas saturations in the pore space in excess of that occupied by oil were calculated. We demonstrate that stable isotope measurements on produced fluids and gases at the Pembina Cardium CO2 storage site can be used to determine both qualitatively and quantitatively the presence of CO2 around the observation well, given that the injected CO2 is isotopically distinct.
... Hall-Gurney* [27]; Cranfield* [28]; Pembina Cardium* ,X [29]. Cross-well Seismic source/receiver placed in the wellbores. ...
Jilin Oilfield is conducting a large-scale demonstration project on CO2 EOR (enhanced oil recovery) and storage in China. CO2 separated from a nearby natural gas reservoir (15-30 mol% CO2) is injected into the northern part of H59 oil block with permeability and porosity of 3.5 mD and 12.7%, respectively. After about six years of operation, nearly 0.26 million tons of CO2 (0.32 HCPV (hydrocarbon pore volume)) has been injected into the thin oil layers with well-developed natural fractures. In order to track the movement of CO2 in the oil reservoir, a microseismic monitoring program has been implemented to map the CO2 flow anisotropy and estimate its sweeping efficiency. Gas tracer testing has also been conducted to examine the inter-well connectivity. The temporal change of produced CO2 has been analyzed in a real-time mode to monitor the dynamic response in production wells. It is demonstrated that the migration of CO2 in the thin oil layers can be successfully detected by the microseismic technique, and the sweeping profiles of CO2 obtained from the inverted microseismic are in good agreement with the produced CO2 rate from production wells as well as the reservoir's petrophysical properties.
... The rock fragments were recovered from cores, two of which are associated with CO 2 storage pilot studies. These two were a relatively clean sandstone from the Cardium Formation in Alberta, Canada, associated with the Pembina-Cardium CO 2 -EOR pilot (Hitchon, 2009), and a chlorite-rich sandstone from the Tuscaloosa Formation in Mississippi originating from the target of CO 2 injection as part of the SECARB project (Hovorka, 2013). The other two samples were described as a dirty sandstone of Miocene age from a deep well in the shallow offshore off the Texas coast, and a carbonate rock from the Pembina oil field in Alberta (PTAC, 2014). ...
... In the USA, EOR started in 1973 and currently 6% of oil production is from EOR operations; CO 2 sales for EOR reached 56 Mt CO 2 /yr (~3 billion ft 3 /d) in (Moritis 2009Hovorka and Tinker 2010). In addition there are approximately 25 geologic sequestration field demonstration projects in the US at various stages of planning and deployment, and an equal number of projects in other countries (including the Minami-Nagaoka in Japan, the Otway and Gorgon in Australia, the Pembina Cardium in Canada, and the Ketzin in Germany) that are investigating the storage of CO 2 in various clastic and carbonate rock formations using different injection schemes, monitoring methods, hazards assessment protocols, and mitigation strategies ( Torp and Gale 2003;Litynski et al. 2008;Mito et al. 2008Mito et al. , 2013Cook 2009;Haszeldine 2009;Hitchon 2009;Matter et al. , 2011Michael et al. 2009;IEA 2012; Global CCS Institute 2012; Humez et al. 2013). ...
Carbon dioxide sequestration is now considered an important component of the portfolio of options for reducing greenhouse gas emissions to stabilize their atmospheric levels at values that would limit global temperature increases to the target of 2 °C by the end of the century (Pacala and Socolow 2004; IPCC 2005, 2007; Benson and Cook 2005; Benson and Cole 2008; IEA 2012; Romanak et al. 2013). Increased anthropogenic emissions of CO2 have raised its atmospheric concentrations from about 280 ppmv during pre-industrial times to ~400 ppmv today, and based on several defined scenarios, CO2 concentrations are projected to increase to values as high as 1100 ppmv by 2100 (White et al. 2003; IPCC 2005, 2007; EIA 2012; Global CCS Institute 2012). An atmospheric CO2 concentration of 450 ppmv is generally the accepted level that is needed to limit global temperature increases to the target of 2 °C by the end of the century. This temperature limit likely would moderate the adverse effects related to climate change that could include sea-level rise from the melting of alpine glaciers and continental ice sheets and from the ocean warming; increased frequency and intensity of wildfires, floods, droughts, and tropical storms; and changes in the amount, timing, and distribution of rain, snow, and runoff (IPCC 2007; Sundquist et al. 2009; IEA 2012). Rising atmospheric CO2 concentrations are also increasing the amount of CO2 dissolved in ocean water lowering its pH from 8.1 to 8.0, with potentially disruptive effects on coral reefs, plankton and marine ecosystems (Adams and Caldeira 2008; Schrag 2009; Sundquist et al. 2009). Sedimentary basins in general and deep saline aquifers in particular are being investigated as possible repositories for the large volumes of …
... At the In Salah CO 2 project in Algeria (1 Mt CO 2 /year), 3D and 4D seismic surveys, geochemical approaches, and satellite-based technologies have been deployed to monitor the CO 2 in the reservoir (Mathieson et al., 2011;Shi et al., 2012). There have also been a number of smaller CO 2 pilot injection studies conducted such as the Pembina Cardium project in Alberta (Canada) with 75,000 tonnes of CO 2 injected between 2005 and 2008 (Hitchon, 2009;Johnson et al., 2011b), the Otway project in Victoria (Australia) with 65,500 tonnes of CO 2 over 17 months (Boreham et al., 2011), the German Ketzin project with 60,000 tonnes of CO 2 between 2008 and 2012 (Martens et al., 2012) and the Frio Brine Pilot project in Texas (USA) with 1600 tonnes of CO 2 injected over 10 days (Hovorka et al., 2006;Hovorka and Knox, 2003). In all these projects, some geophysical, geochemical and/or other monitoring approaches have been employed to trace the fate of injected CO 2 in a variety of geological and hydrogeological settings. ...
Geological storage of injected CO2 is a promising technology to reduce CO2 emissions into the atmosphere. Tracer methods are an essential tool to monitor CO2 plume distribution in the target formation and to enable tracking potential leakage of CO2 outside the storage reservoir. Here, we demonstrate that the isotopic composition of CO2 can serve as a suitable tracer at large CO2 injection sites provided that the injected CO2 is isotopically distinct from background CO2 sources that are usually composed of dissolved inorganic carbon, bedrock-derived carbon, and soil CO2. Very favourable conditions for this tracer approach exist if δ13C values of injected CO2 are more than 10‰ different from those of baseline CO2 and other dissolved inorganic carbon species at the CCS site. In this case, changes in δ13C values accompanied with increasing concentrations of CO2 or DIC in samples obtained regularly at monitoring sites within or above the storage reservoir indicate arrival of injected CO2. The proportion of injected CO2 contributing to the obtained samples can be quantified when carbon isotope fractionation effects are either negligible or thoroughly known. We point out several areas where additional detailed information on carbon isotope effects during phase change, transport and geochemical reactions is desirable to refine this tracer approach for temperature, pressure and salinity conditions relevant for CO2 storage sites. Oxygen isotope ratios of injected CO2 were not found to be a conservative tracer due to oxygen isotope exchange between CO2 and water on time scales of hours to a few days. δ18O measurements on CO2 and H2O have, however, revealed pore space saturation with CO2 and hence indicate the presence of injected CO2 within CO2 storage reservoirs. We suggest that the stable isotopic composition of injected CO2 is a suitable tracer for assessing the movement and fate of injected CO2 in the target reservoir and for leakage detection at CO2 storage sites, provided that the injected CO2 is isotopically distinct from background CO2 sources. A key advantage is that this tracer approach does not depend on the co-injection of additional tracers and hence can be continuously used in large-scale commercial storage projects with CO2 injection rates exceeding 1 million tonnes per year at reasonable cost.
... The project was an enhanced oil recovery (EOR) operation hosted in the Upper Cretaceous Cardium Formation of the Pembina oil field. The Cardium is a siliciclastic reservoir with minor amounts of carbonate cement (~1.5% siderite and calcite) at approximately 1650 m depth [1]. At this site, CO 2 injection commenced in spring 2005 and ended early in 2010. ...
Geochemical and isotopic data acquired pre-, syn- and post- CO2 injection at the Pembina Cardium CO2 Monitoring Pilot in Alberta, Canada is presented. To the author's knowledge this is the first project that has collected and interpreted comprehensive geochemical data over the full life cycle of a CO2 injection project. Of the 40 parameters measured per sample changes in pH, alkalinity, Ca2+, Fe2+, δ13C of CO2 and δ18O of H2O proved to be the most useful parameters as tracers of CO2 presence and for identifying solubility and mineral trapping in the reservoirs thus demonstrating CO2 retention mechanisms.
... It can also be employed to monitor the micro-seismic events (e.g. micro-earthquakes or fractures induced by CO 2 injection) during CO 2 injection (Verdon et al., 2010), although the monitoring performance may be compromised due to the interference of noises associated with various oilfield operations (Gunter et al., 2009). During well stimulations, such as hydraulic fracturing or injection with a large rate, the fluid pressure around well will increase greatly and may lead to many cracks. ...
Jilin oilfield is conducting the first large scale demonstration project on CO2 EOR and storage in the northeast China. CO2 with high purity is produced from a nearby natural gas reservoir and injected into the tight oil reservoir of H-59 block. Up to early in 2012, more than 20×104 tons of CO2 has been injected into the reservoir through a miscible flooding scheme. In order to track the migration of CO2 in the reservoir and ensure a long-term storage safety, a monitoring program has been deployed in the field. The used monitoring techniques include wellbore integrity detecting, produced fluid sampling, CO2 gas tracer, electric spontaneous potential measurement, micro-seismic and cross-well seismic. An environmental monitoring program is also implemented for verifying CO2 leakage. Preliminary results indicate that it is effective to detect the movement of CO2 in the oil reservoir by jointly applying various monitoring techniques based on wellbores. After more than four years of operation since 2008, nearly 80% of injected CO2 has been stored in the reservoir with the rest of injected CO2 breakthrough in the production wells. CO2 storage safety needs more detailed and comprehensive monitoring data for further verification. The obtained preliminary monitoring experience can provide valuable guidance for the future enlarged Jilin project and other CO2 EOR and storage operations.
... Over the course of this project, CO 2 was injected into the Cardium Formation in the Pembina oil field near Violet Grove, Alberta. A vertical seismic profile was recorded in an observation well 1650 m deep, using eight 3-component geophones placed every 20 m starting at 1498 m depth (Hitchon, 2009). In this paper, the Phase I (acquired in March 2005) and Phase III (acquired in March 2007) walkaway VSP data are studied for a repeatability analysis. ...
Time-lapse vertical seismic profile data was obtained near Violet Grove, Alberta, using an array of eight 3-component geophones at depths between 1497 m to 1640 m. Baseline data were recorded in 2005 and the monitor recorded in 2007. Analysis of rotation angles was undertaken for both surveys, resulting in differences of less than 2° for 54.2% in Line 2 and 85.9% in Line 3. Rotation angles were found to be more consistent at offsets greater than about 500 m. NRMS analysis gave averages of 61.4% and 45.3% for horizontal components, and 42.8% and 41.4% for the vertical component. Predictability analysis showed averages of 0.72 and 0.83 for horizontal components and 0.83 and 0.86 for the vertical component. In addition, traces were examined visually, and showed good qualitative repeatability. Since the receivers were cemented into place, the greatest effect on the repeatability was judged to be from differences in noise and small differences between the source locations between surveys.
... This work presents modifications of a pre-existing historymatched reservoir model developed for a section of the Weyburn field shown as Pattern 1 in Fig. 3.12 of Wilson and Monea (2004). These modifications involve incorporating additional components in the model to simulate geochemical tracers which were monitored as part of the geochemical monitoring programme, and are similar to those reported for a CO 2 EOR pilot in the Cardium Formation of Alberta (Hitchon, 2009;Talman and Perkins, 2008). Modelling results are compared to the observed evolution of the isotopic composition of ethane, ␦ 13 C(C 2 H 6 ), and the concentration of chloride. ...
The results of integrating processes affecting selected geochemical tracers into a model of fluid flow and phase behaviour at the Weyburn CO2 EOR Field are presented. Flow patterns, and phase behaviours are obtained from a reservoir model, which had been history matched to fluid (oil and water) production rates as part of the IEA GHG Weyburn-Midale CO2 Monitoring and Storage Project. The reservoir model was updated by including tracer components with properties similar to those measured in produced fluids as part of the same project. The modelling results are compared with field values of chloride in produced water and the carbon isotope ratio of ethane, δ13C(C2H6), in produced gases. An accurate representation of the processes responsible for generating these, relatively simple, signals is a prerequisite for any future simulations incorporating reactive transport, such as would be needed to quantify rates of reactions between the injected CO2 and the host-rock. Modelling runs based on the previously developed history-matched single-porosity reservoir model failed to reproduce the variability seen in produced fluids for either a conservative major ion or δ13C(C2H6). Modifications incorporating fracture flow through use of a dual-porosity reservoir description lead to calculated chemical signals that were more compatible with the field observations.
Structured sorbents with better adsorption kinetics and lower pressure drop than packed beds of conventional adsorbents are gaining increasing attention due to the potential advantages of smaller footprint and lower energy consumption in a CO2 capture process. The aim of this computational study is to examine the potential improvement in productivity of a CO2 capture process using 3D printed, structured sorbents compared to a conventional packed bed system. The sorbents chosen in this work are silica pellets and 3D printed structures, both grafted with an amino silane. A representative flue gas/FCC regenerator off-gas containing 15 vol % CO2, 5% H2O and 80% N2 and an SMR-off gas containing 21% CO2, 5% H2O, and 74% N2 were considered as feed streams. Detailed genetic algorithm-based optimization of a 6-step vacuum swing adsorption cycle for both adsorbents was carried out to identify the minimum specific energy and maximum productivity for concentrating the CO2 to 95 vol% purity on a dry basis and capturing 90% of the CO2. The simulations indicate that use of the 3D printed adsorbent may achieve a 3-fold increase in productivity with about 25-38% reduction in energy consumption relative to the conventional packed bed. Scaling the process to a real system revealed a 1.8 times reduction in the capture footprint for a VSA process using 3D printed sorbents instead of a traditional packed bed.
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 δ13C values of background CO2 (δ13C = −12.7‰) and HCO3− (δ13C = −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.
A passive seismic monitoring campaign was carried out in the frame of a CO2-Enhanced Oil Recovery (EOR) pilot project in Alberta, Canada. Our analysis focuses on a two-week period during which prominent downhole pressure fluctuations in the reservoir were accompanied by a leakage of CO2 and CH4 along the monitoring well equipped with an array of short-period borehole geophones. We applied state of the art seismological processing schemes to the continuous seismic waveform recordings. During the analyzed time period we did not find evidence of induced micro-seismicity associated with CO2 injection. Instead, we identified signals related to the leakage of CO2 and CH4, in that seven out of the eight geophones show a clearly elevated noise level framing the onset time of leakage along the monitoring well. Our results confirm that micro-seismic monitoring of reservoir treatment can contribute towards improved reservoir monitoring and leakage detection.
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 δ13C 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 δ13C values ranging from −15.9 to −23.5‰. After commencement of CO2 injection, δ13C 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 (>50mol% CO2) and isotopically 1–6 months after commencement of CO2 injection resulting in cumulative CO2 fluxes exceeding 100,000m3 during the observation period. At four other wells, casing gas CO2 contents remained below 5mol% resulting in low cumulative CO2 fluxes (
Carbon Capture and Storage (CCS) is considered a viable option for reducing CO2 emissions into the atmosphere from point sources such as coal-fired power plants. Monitoring of CO2 storage sites is widely considered necessary for safety reasons and for verification of injected CO2 in the reservoir. The latter is crucially dependent on the ability to determine CO2 trapping mechanisms and to assess pore-space saturation of CO2. Thus far, attempts to determine CO2 pore-space saturations at CO2 injection sites have had limited success. Here, we present data from the Pembina Cardium CO2 Monitoring Project in Alberta, Canada, that demonstrate that changes in the oxygen isotope ratios (δ18O) of reservoir water can be indicative of the extent of pore-space saturation with CO2. The δ18O value of injected CO2 at the injection site was +28.6‰ (V-SMOW) and δ18O values of reservoir water at eight observation wells varied between −13.5 and −17.1‰ (V-SMOW) before CO2 injection. After commencement of CO2 injection the δ18O values of reservoir water at three observation wells increased between 1.1 and 3.9‰ due to the presence of large quantities of injected CO2 and equilibrium isotope exchange between water and CO2. Our calculations revealed that reservoir water fully saturated with CO2 would only result in increases of δ18OH2O values of 0.4‰. Hence the observed larger increases in δ18O values of reservoir water indicate free phase CO2 with estimated pore-space saturations ranging from 12% (corresponding to a δ18O increase of 1.1‰) to 64% (δ18O increase 3.9‰) of the non-oil saturated pore-space. Contributions to oxygen in the system from mineral dissolution were calculated to be less than 0.01% of total oxygen and therefore did not alter the δ18O value of the reservoir water significantly. Hence we conclude that changes in the δ18O values of reservoir water caused by the presence of injected CO2 can be used as a tracer for CO2 plume migration in the subsurface provided that the injected CO2 is isotopically distinct. Furthermore, we submit that the extent of the changes in the δ18O values of the reservoir water provides a quantitative assessment of CO2 stored in dissolved form (solubility trapping), assuming no density driven convective overturn, and as free-phase CO2 (structural, stratigraphic and hydrodynamic trapping) thereby elucidating the trapping mechanisms within the reservoir.
Global warming and resulting climate changes are arguably the most important environmental challenges facing the world in
this century. Average global temperature is now approximately 0.8°C higher than during pre-industrial times, and is projected
to increase by 2–6°C by 2100. Related climate changes with potential adverse environmental impacts may include: (i) sea-level
rise from the alpine glaciers and ice sheets melting and from the ocean thermal expansion; (ii) increased frequency and intensity
of floods, droughts, tropical storms and wildfires; and (iii) changes in the amount, timing, and distribution of rain, snow,
and runoff. Results from global simulation modeling indicate that parts of both the southwestern USA and North Africa would
experience increased drought frequency and water stress in the coming decades; model predictions indicate that precipitation
in these two regions will decrease by about 20% by 2050. There is a broad scientific consensus that global warming and related
climate changes are caused primarily by increased concentrations of atmospheric greenhouse gases (GHG), especially CO2, emitted from the burning of fossil fuels. The amount of anthropogenic CO2 currently added to the atmosphere is about 30 billion ton/year, and this could double by 2050. Capture and sequestration
of CO2 in depleted petroleum fields and saline aquifers in sedimentary basins is one plausible option to reduce GHG emissions and
mitigate global warming. Currently there are five commercial projects that capture and inject about seven million tons of
CO2 annually; data from these, from enhanced oil recovery (EOR) operations and from pilot sites provide valuable experience for
assessing the efficacy of carbon capture and sequestration. Detailed chemical and isotopic analyses of water, associated gases,
and added tracers obtained from Frio field tests, Texas, proved powerful tools in: (i) tracking the successful injection and
flow of CO2 in the “C” sandstone; (ii) detecting some leakage of CO2 into the overlying “B” sandstone; (iii) showing mobilization of metals and toxic organic compounds; (iv) showing major changes
in chemical and isotopic compositions of formation water, including a dramatic drop in calculated brine pH, from 6.3 to 3.0.
Significant isotopic and chemical changes were also observed in shallow groundwater following CO2 injection at the ZERT field site, Montana. These field tests indicate that highly sensitive chemical and isotopic tracers
can effectively monitor injection performance and provide early detection of CO2 and brine leakages into potable groundwater.
KeywordsGeologic storage-GHG-Global warming-Water resources
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