Dynamics of CO<Subscript>2</Subscript> fluxes and concentrations during a shallow subsurface CO<Subscript>2</Subscript> release

A field facility located in Bozeman, Montana provides the opportunity to test methods to detect, locate, and quantify potential CO₂ leakage from geologic storage sites. From 9 July to 7 August 2008, 0.3 t CO₂ day⁻¹ were injected from a 100-m long, ~2.5-m deep horizontal well. Repeated measurements of soil CO₂ fluxes on a grid characterized the spatio-temporal evolution of the surface leakage signal and quantified the surface leakage rate. Infrared CO₂ concentration sensors installed in the soil at 30 cm depth at 0–10 m from the well and at 4 cm above the ground at 0 and 5 m from the well recorded surface breakthrough of CO₂ leakage and migration of CO₂ leakage through the soil. Temporal variations in CO₂ concentrations were correlated with atmospheric and soil temperature, wind speed, atmospheric pressure, rainfall, and CO₂ injection rate.     

Seal integrity and feasibility of CO<Subscript>2</Subscript> sequestration in the Teapot Dome EOR pilot: geomechanical site characterization

This paper reports a preliminary investigation of CO₂ sequestration and seal integrity at Teapot Dome oil field, Wyoming, USA, with the objective of predicting the potential risk of CO₂ leakage along reservoir-bounding faults. CO₂ injection into reservoirs creates anomalously high pore pressure at the top of the reservoir that could potentially hydraulically fracture the caprock or trigger slip on reservoir-bounding faults. The Tensleep Formation, a Pennsylvanian age eolian sandstone is evaluated as the target horizon for a pilot CO₂ EOR-carbon storage experiment, in a three-way closure trap against a bounding fault, termed the S1 fault. A preliminary geomechanical model of the Tensleep Formation has been developed to evaluate the potential for CO₂ injection inducing slip on the S1 fault and thus threatening seal integrity. Uncertainties in the stress tensor and fault geometry have been incorporated into the analysis using Monte Carlo simulation. The authors find that even the most pessimistic risk scenario would require ∼10 MPa of excess pressure to cause the S1 fault to reactivate and provide a potential leakage pathway. This would correspond to a CO₂ column height of ∼1,500 m, whereas the structural closure of the Tensleep Formation in the pilot injection area does not exceed 100 m. It is therefore apparent that CO₂ injection is not likely to compromise the S1 fault stability. Better constraint of the least principal stress is needed to establish a more reliable estimate of the maximum reservoir pressure required to hydrofracture the caprock.     

Using hyperspectral plant signatures for CO<Subscript>2</Subscript> leak detection during the 2008 ZERT CO<Subscript>2</Subscript> sequestration field experiment in Bozeman,Montana

Hyperspectral plant signatures can be used as a short-term, as well as long-term (100-year timescale) monitoring technique to verify that CO₂ sequestration fields have not been compromised. An influx of CO₂ gas into the soil can stress vegetation, which causes changes in the visible to near-infrared reflectance spectral signature of the vegetation. For 29 days, beginning on July 9, 2008, pure carbon dioxide gas was released through a 100-m long horizontal injection well, at a flow rate of 300 kg day⁻¹. Spectral signatures were recorded almost daily from an unmown patch of plants over the injection with a “FieldSpec Pro” spectrometer by Analytical Spectral Devices, Inc. Measurements were taken both inside and outside of the CO₂ leak zone to normalize observations for other environmental factors affecting the plants. Four to five days after the injection began, stress was observed in the spectral signatures of plants within 1 m of the well. After approximately 10 days, moderate to high amounts of stress were measured out to 2.5 m from the well. This spatial distribution corresponded to areas of high CO₂ flux from the injection. Airborne hyperspectral imagery, acquired by Resonon, Inc. of Bozeman, MT using their hyperspectral camera, also showed the same pattern of plant stress. Spectral signatures of the plants were also compared to the CO₂ concentrations in the soil, which indicated that the lower limit of soil CO₂ needed to stress vegetation is between 4 and 8% by volume.     

Site characterisation of a basin-scale CO<Subscript>2</Subscript> geological storage system: Gippsland Basin,southeast Australia

Geological storage of CO₂ in the offshore Gippsland Basin, Australia, is being investigated by the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) as a possible method for storing the very large volumes of CO₂ emissions from the nearby Latrobe Valley area. A storage capacity of about 50 million tonnes of CO₂ per annum for a 40-year injection period is required, which will necessitate several individual storage sites to be used both sequentially and simultaneously, but timed such that existing hydrocarbon assets will not be compromised. Detailed characterisation focussed on the Kingfish Field area as the first site to be potentially used, in the anticipation that this oil field will be depleted within the period 2015–2025. The potential injection targets are the interbedded sandstones of the Paleocene-Eocene upper Latrobe Group, regionally sealed by the Lakes Entrance Formation. The research identified several features to the offshore Gippsland Basin that make it particularly favourable for CO₂ storage. These include: a complex stratigraphic architecture that provides baffles which slow vertical migration and increase residual gas trapping and dissolution; non-reactive reservoir units that have high injectivity; a thin, suitably reactive, lower permeability marginal reservoir just below the regional seal providing mineral trapping; several depleted oil fields that provide storage capacity coupled with a transient production-induced flow regime that enhances containment; and long migration pathways beneath a competent regional seal. This study has shown that the Gippsland Basin has sufficient capacity to store very large volumes of CO₂. It may provide a solution to the problem of substantially reducing greenhouse gas emissions from future coal developments in the Latrobe Valley.     

Time-lapse crosswell seismic and VSP monitoring of injected CO<Subscript>2</Subscript> in a brine aquifer

Seismic surveys successfully imaged a small scale CO₂ injection (1,600 ton) conducted in a brine aquifer of the Frio Formation near Houston, Texas. These time-lapse borehole seismic surveys, crosswell and vertical seismic profile (VSP), were acquired to monitor the CO₂ distribution using two boreholes (the new injection well and a pre-existing well used for monitoring) which are 30 m apart at a depth of 1,500 m. The crosswell survey provided a high-resolution image of the CO₂ distribution between the wells via tomographic imaging of the P-wave velocity decrease (up to 500 m/s). The simultaneously acquired S-wave tomography showed little change in S-wave velocity, as expected for fluid substitution. A rock physics model was used to estimate CO₂ saturations of 10–20% from the P-wave velocity change. The VSP survey resolved a large (∼70%) change in reflection amplitude for the Frio horizon. This CO₂ induced reflection amplitude change allowed estimation of the CO₂ extent beyond the monitor well and on three azimuths. The VSP result is compared with numerical modeling of CO₂ saturations and is seismically modeled using the velocity change estimated in the crosswell survey.     

Sealing efficiency analysis for shallow-layer caprocks in CO<Subscript>2</Subscript> geological storage

The CO₂ migrated from deeper to shallower layers may change its phase state from supercritical state to gaseous state (called phase transition). This phase transition makes both viscosity and density of CO₂ experience a sharp variation, which may induce the CO₂ further penetration into shallow layers. This is a critical and dangerous situation for the security of CO₂ geological storage. However, the assessment of caprock sealing efficiency with a fully coupled multi-physical model is still missing on this phase transition effect. This study extends our previous fully coupled multi-physical model to include this phase transition effect. The dramatic changes of CO₂ viscosity and density are incorporated into the model. The impacts of temperature and pressure on caprock sealing efficiency (expressed by CO₂ penetration depth) are then numerically investigated for a caprock layer at the depth of 800 m. The changes of CO₂ physical properties with gas partial pressure and formation temperature in the phase transition zone are explored. It is observed that phase transition revises the linear relationship of CO₂ penetration depth and time square root as well as penetration depth. The real physical properties of CO₂ in the phase transition zone are critical to the safety of CO₂ sequestration. Pressure and temperature have different impact mechanisms on the security of CO₂ geological storage.     

Depth of volcanic basalt degassing forecasted from CO2 fluid inclusions

Fluid inclusions have recorded the history of degassing in basalt. Some fluid inclusions in olivine and pyroxene phenocrysts of basalt were analyzed by micro-thermometry and Raman spectroscopy in this paper. The experimental results showed that many inclusions are present almost in a pure CO2 system. The densities of some CO2 inclusions were computed in terms of Raman spectroscopic characteristics of CO2 Fermi resonance at room temperature. Their densities change over a wide range, but mainly between 0.044 g/cm3 and 0.289 g/cm3. Their micro-thermometric measurements showed that the CO2 inclusions examined reached homogenization between 1145.5℃ and 1265℃ . The mean value of homogenization temperatures of CO2 inclusions in basalts is near 1210℃. The trap pressures (depths) of inclusions were computed with the equation of state and computer program. Distribution of the trap depths makes it know that the degassing of magma can happen over a wide pressure (depth) range, but mainly at the depth of 0.48 km to 3.85 km. This implicates that basalt magma experienced intensive degassing and the CO2 gas reservoir from the basalt magma also may be formed in this range of depths. The results of this study showed that the depth of basalt magma degassing can be forecasted from CO2 fluid inclusions, and it is meaningful for understanding the process of magma degassing and constraining the inorganogenic CO2 gas reservoir.     

Numerical modeling of the geomechanical behavior of Ghawar Arab-D carbonate petroleum reservoir undergoing CO<Subscript>2</Subscript> injection

Sedimentary porous rocks can be used for long-term subsurface containment of CO₂. Before injecting CO₂ to sedimentary reservoirs, it is necessary to perform stability analysis of the reservoir and to estimate the maximum sustainable pore fluid pressures. In order to avoid the reservoir damage during the CO₂ injection, the effective stresses in the reservoir should be evaluated. In this paper, numerical modeling techniques are used for the evaluation of stresses and deformations in a naturally fractured carbonate sedimentary reservoir. The developed numerical modeling scheme couples the behavior of the CO₂ injection and the change in the geomechanical behavior of the sedimentary carbonate reservoir for a case study from Saudi Arabia. The present investigation extends the previous studies by considering the sorption-based deformation during the injection of the compressed CO₂ fluid into the Arab-D naturally fractured carbonate reservoir. The change in permeability during the injection of CO₂ is evaluated. The adopted CO₂ injection scenario was shown to be within the safe maximum occupancy, and that the increase in the pore pressure does not result in the reservoir failure.     

Pressure transient technique to constrain CO<Subscript>2</Subscript> plume boundaries

Carbon dioxide (CO₂) has been injected in the subsurface permeable formations as a means to cut atmospheric CO₂ emissions and/or enhance oil recovery (EOR). It is important to constrain the boundaries of the CO₂ plume in the target formation and/or other formations hosting the CO₂ migrated from the target formation. Monitoring methods and technologies to assess the CO₂ plume boundaries over time within a reservoir of interest are required. Previously introduced methods and technologies on pressure monitoring to detect the extent of the CO₂ plume require at least two wells, i.e. pulser and observation wells. We introduce pressure transient technique requiring single well only. Single well pressure transient testing (drawdown/buildup/injection/falloff) is widely used to determine reservoir properties and wellbore conditions. Pressure diagnostic plots are used to identify different flow regimes and determine the reservoir/well characteristics. We propose a method to determine the plume extent for a constant rate pressure transient test at a single well outside the CO₂ plume. Due to the significant contrast between mobility and storativity of the CO₂ and native fluids (oil or brine), the CO₂ boundary causes deviation in the pressure diagnostic response from that corresponding to previously identified heterogeneities. Using the superposition principle, we develop a relationship between the deviation time and the plume boundary. We demonstrate the applicability of the proposed method using numerically generated synthetic data corresponding to homogeneous, heterogeneous, and anisotropic cases to evaluate its potential and limitations. We discuss ways to identify and overcome the potential limitations for application of the method in the field.     

Impact of CO<Subscript>2</Subscript> injection rate on heat extraction at the HDR geothermal field of Zhacanggou,China

CO₂ is now considered as a novel heat transmission fluid to extract geothermal energy. It can achieve the goal of energy exploitation and CO₂ geological sequestration. Taking Zhacanggou as research area, a “Three-spot” well pattern (one injection with two production), “wellbore–reservoir” coupled model is built, and a constant injection rate is set up. A fully coupled wellbore–reservoir simulator—T2Well—is introduced to study the flow mechanism of CO₂ working as heat transmission fluid, the variance pattern of each physical field, the influence of CO₂ injection rate on heat extraction and the potential and sustainability of heat resource in Guide region. The density profile variance resulting from temperature differences of two wells can help the system achieve “self-circulation” by siphon phenomenon, which is more significant in higher injection rate cases. The density of CO₂ is under the effect of both pressure and temperature; moreover, it has a counter effect on temperature and pressure. The feedback makes the flow process in wellbore more complex. In low injection rate scenarios, the temperature has a dominating impact on the fluid density, while in high rate scenario, pressure plays a more important role. In most scenarios, it basically keeps stable during 30-year operation. The decline of production temperature is <5 °C. However, for some high injection rate cases (75 and 100 kg/s), due to the heat depletion in reservoir, there is a dramatic decline for production temperature and heat extraction rate. Therefore, a 50-kg/s CO₂ injection rate is more suitable for “Three-spot” well pattern in Guide region.     

Physical and chemical characteristics of potential seal strata in regions considered for demonstrating geological saline CO<Subscript>2</Subscript> sequestration

Capture and geological sequestration of CO₂ from energy production is proposed to help mitigate climate change caused by anthropogenic emissions of CO₂ and other greenhouse gases. Performance goals set by the US Department of Energy for CO₂ storage permanence include retention of at least 99% of injected CO₂ which requires detailed assessments of each potential storage site’s geologic system, including reservoir(s) and seal(s). The objective of this study was to review relevant basin-wide physical and chemical characteristics of geological seals considered for saline reservoir CO₂ sequestration in the United States. Results showed that the seal strata can exhibit substantial heterogeneity in the composition, structural, and fluid transport characteristics on a basin scale. Analysis of available field and wellbore core data reveal several common inter-basin features of the seals, including the occurrence of quartz, dolomite, illite, calcite, and glauconite minerals along with structural features containing fractures, faults, and salt structures. In certain localities within the examined basins, some seal strata also serve as source rock for oil and gas production and can be subject to salt intrusions. The regional features identified in this study can help guide modeling, laboratory, and field studies needed to assess local seal performances within the examined basins.     

CO<Subscript>2</Subscript> leakage through an abandoned well: problem-oriented benchmarks

The efficiency and sustainability of carbon dioxide (CO₂) storage in deep geological formations crucially depends on the integrity of the overlying cap-rocks. Existing oil and gas wells, which penetrate the formations, are potential leakage pathways. This problem has been discussed in the literature, and a number of investigations using semi-analytical mathematical approaches have been carried out by other authors to quantify leakage rates. The semi-analytical results are based on a number of simplifying assumptions. Thus, it is of great interest to assess the influence of these assumptions. We use a numerical model to compare the results with those of the semi-analytical model. Then we ease the simplifying restrictions and include more complex thermodynamic processes including sub- and supercritical fluid properties of CO₂ and non-isothermal as well as compositional effects. The aim is to set up problem-oriented benchmark examples that allow a comparison of different modeling approaches to the problem of CO₂ leakage.     

Assessing the feasibility of CO<Subscript>2</Subscript>-enhanced oil recovery and storage in mature oil field: A case study from Cambay basin

The utilization of anthropogenic CO₂ for enhanced oil recovery (EOR) can significantly extend the production life of an oil field, and help in the reduction of atmospheric emission of anthropogenic CO₂ if sequestration is considered. This work summarizes the prospect of EOR and sequestration using CO₂ flooding from an Indian mature oil field at Cambay basin through numerical modelling, simulation and pressure study based on limited data provided by the operator. To get an insight into CO₂-EOR and safe storage process in this oil field, a conceptual sector model is developed and screening standard is proposed keeping in mind the major pay zone of the producing reservoir. To construct the geomodel, depth maps, well positions and coordinates, well data and well logs, perforation depths and distribution of petrophysical properties as well as fluid properties provided by the operator, has been considered. Based on the results from the present study, we identified that the reservoir has the potential for safe and economic geological sequestration of 15.04×10⁶ metric ton CO₂ in conjunction with a substantial increase in oil recovery of 10.4% of original oil in place. CO₂-EOR and storage in this mature field has a bright application prospect since the findings of the present work could be a better input to manage the reservoir productivity, and the pressure field for significant enhancement of oil recovery followed by safe storage.     

Site characterization for CO<Subscript>2</Subscript> geologic storage and vice versa: the Frio brine pilot,Texas, USA as a case study

Careful site characterization is critical for successful geologic storage of carbon dioxide (CO₂) because of the many physical and chemical processes impacting CO₂ movement and containment under field conditions. Traditional site characterization techniques such as geological mapping, geophysical imaging, well logging, core analyses, and hydraulic well testing provide the basis for judging whether or not a site is suitable for CO₂ storage. However, only through the injection and monitoring of CO₂ itself can the coupling between buoyancy flow, geologic heterogeneity, and history-dependent multi-phase flow effects be observed and quantified. CO₂ injection and monitoring can therefore provide a valuable addition to the site-characterization process. Additionally, careful monitoring and verification of CO₂ plume development during the early stages of commercial operation should be performed to assess storage potential and demonstrate permanence. The Frio brine pilot, a research project located in Dayton, Texas (USA) is used as a case study to illustrate the concept of an iterative sequence in which traditional site characterization is used to prepare for CO₂ injection and then CO₂ injection itself is used to further site-characterization efforts, constrain geologic storage potential, and validate understanding of geochemical and hydrological processes. At the Frio brine pilot, in addition to traditional site-characterization techniques, CO₂ movement in the subsurface is monitored by sampling fluid at an observation well, running CO₂-saturation-sensitive well logs periodically in both injection and observation wells, imaging with crosswell seismic in the plane between the injection and observation wells, and obtaining vertical seismic profiles to monitor the CO₂ plume as it migrates beyond the immediate vicinity of the wells. Numerical modeling plays a central role in integrating geological, geophysical, and hydrological field observations.     

Volatile (H<Subscript>2</Subscript>O,CO<Subscript>2</Subscript>, Cl,S) budget of the Central American subduction zone

After more than a decade of multidisciplinary studies of the Central American subduction zone mainly in the framework of two large research programmes, the US MARGINS program and the German Collaborative Research Center SFB 574, we here review and interpret the data pertinent to quantify the cycling of mineral-bound volatiles (H₂O, CO₂, Cl, S) through this subduction system. For input-flux calculations, we divide the Middle America Trench into four segments differing in convergence rate and slab lithological profiles, use the latest evidence for mantle serpentinization of the Cocos slab approaching the trench, and for the first time explicitly include subduction erosion of forearc basement. Resulting input fluxes are 40–62 (53) Tg/Ma/m H₂O, 7.8–11.4 (9.3) Tg/Ma/m CO₂, 1.3–1.9 (1.6) Tg/Ma/m Cl, and 1.3–2.1 (1.6) Tg/Ma/m S (bracketed are mean values for entire trench length). Output by cold seeps on the forearc amounts to 0.625–1.25 Tg/Ma/m H₂O partly derived from the slab sediments as determined by geochemical analyses of fluids and carbonates. The major volatile output occurs at the Central American volcanic arc that is divided into ten arc segments by dextral strike-slip tectonics. Based on volcanic edifice and widespread tephra volumes as well as calculated parental magma masses needed to form observed evolved compositions, we determine long-term (10⁵ years) average magma and K₂O fluxes for each of the ten segments as 32–242 (106) Tg/Ma/m magma and 0.28–2.91 (1.38) Tg/Ma/m K₂O (bracketed are mean values for entire Central American volcanic arc length). Volatile/K₂O concentration ratios derived from melt inclusion analyses and petrologic modelling then allow to calculate volatile fluxes as 1.02–14.3 (6.2) Tg/Ma/m H₂O, 0.02–0.45 (0.17) Tg/Ma/m CO₂, and 0.07–0.34 (0.22) Tg/Ma/m Cl. The same approach yields long-term sulfur fluxes of 0.12–1.08 (0.54) Tg/Ma/m while present-day open-vent SO₂-flux monitoring yields 0.06–2.37 (0.83) Tg/Ma/m S. Input–output comparisons show that the arc water fluxes only account for up to 40 % of the input even if we include an “invisible” plutonic component constrained by crustal growth. With 20–30 % of the H₂O input transferred into the deeper mantle as suggested by petrologic modeling, there remains a deficiency of, say, 30–40 % in the water budget. At least some of this water is transferred into two upper-plate regions of low seismic velocity and electrical resistivity whose sizes vary along arc: one region widely envelopes the melt ascent paths from slab top to arc and the other extends obliquely from the slab below the forearc to below the arc. Whether these reservoirs are transient or steady remains unknown.     

Uncertainties of geochemical modeling during CO<Subscript>2</Subscript> sequestration applying batch equilibrium calculations

One of the uncertainties in the field of carbon dioxide capture and storage (CCS) is caused by the parameterization of geochemical models. The application of geochemical models contributes significantly to calculate the fate of the CO₂ after its injection. The choice of the thermodynamic database used, the selection of the secondary mineral assemblage as well as the option to calculate pressure dependent equilibrium constants influence the CO₂ trapping potential and trapping mechanism. Scenario analyses were conducted applying a geochemical batch equilibrium model for a virtual CO₂ injection into a saline Keuper aquifer. The amount of CO₂ which could be trapped in the formation water and in the form of carbonates was calculated using the model code PHREEQC. Thereby, four thermodynamic datasets were used to calculate the thermodynamic equilibria. Furthermore, the equilibrium constants were re-calculated with the code SUPCRT92, which also applied a pressure correction to the equilibrium constants. Varying the thermodynamic database caused a range of 61% in the amount of trapped CO₂ calculated. Simultaneously, the assemblage of secondary minerals was varied, and the potential secondary minerals dawsonite and K-mica were included in several scenarios. The selection of the secondary mineral assemblage caused a range of 74% in the calculated amount of trapped CO₂. Correcting the equilibrium constants with respect to a pressure of 125 bars had an influence of 11% on the amount of trapped CO₂. This illustrates the need for incorporating sensitivity analyses into reaction pathway modeling.     

The Role of CaCO<Subscript>3</Subscript> Reactions in the Contemporary Oceanic CO<Subscript>2</Subscript> Cycle

The present analysis adjusts previous estimates of global ocean CaCO₃ production rates substantially upward, to 133 × 10¹² mol yr^?1 plankton production and 42 × 10¹² mol yr^?1 shelf benthos production. The plankton adjustment is consistent with recent satellite-based estimates; the benthos adjustment includes primarily an upward adjustment of CaCO₃ production on so-called carbonate-poor sedimentary shelves and secondarily pays greater attention to high CaCO₃ mass (calcimass) and turnover of shelf communities on temperate and polar shelves. Estimated CaCO₃ sediment accumulation rates remain about the same as they have been for some years: ~20 × 10¹² mol yr^?1 on shelves and 11 × 10¹² mol yr^?1 in the deep ocean. The differences between production and accumulation of calcareous materials call for dissolution of ~22 × 10¹² mol yr^?1 (~50 %) of shelf benthonic carbonate production and 122 × 10¹² mol yr^?1 (>90 %) of planktonic production. Most CaCO₃ production, whether planktonic or benthonic, is assumed to take place in water depths of <100 m, while most dissolution is assumed to occur below this depth. The molar ratio of CO₂ release to CaCO₃ precipitation (CO₂↑/CaCO₃↓) is <1.0 and varies with depth. This ratio, Ψ, is presently about 0.66 in surface seawater and 0.85 in ocean waters deeper than about 1000 m. The net flux of CO₂ associated with CaCO₃ reactions in the global ocean in late preindustrial time is estimated to be an apparent influx from the atmosphere to the ocean, of +7 × 10¹² mol C yr^?1, at a time scale of 10²–10³ years. The CaCO₃-mediated influx of CO₂ is approximately offset by CO₂ release from organic C oxidation in the water column. Continuing ocean acidification will have effects on CaCO₃ and organic C metabolic responses to the oceanic inorganic C cycle, although those responses remain poorly quantified.     

Simulation of CO<Subscript> <Emphasis Type="Bold">2</Emphasis> </Subscript> concentrations at Tsukuba tall tower using WRF-CO<Subscript> <Emphasis Type="Bold">2</Emphasis> </Subscript> tracer transport model

Simulation of carbon dioxide (CO₂) at hourly/weekly intervals and fine vertical resolution at the continental or coastal sites is challenging because of coarse horizontal resolution of global transport models. Here the regional Weather Research and Forecasting (WRF) model coupled with atmospheric chemistry is adopted for simulating atmospheric CO₂ (hereinafter WRF-CO₂) in nonreactive chemical tracer mode. Model results at horizontal resolution of 27 × 27 km and 31 vertical levels are compared with hourly CO₂ measurements from Tsukuba, Japan (36.05°N, 140.13 ^oE) at tower heights of 25 and 200 m for the entire year 2002. Using the wind rose analysis, we find that the fossil fuel emission signal from the megacity Tokyo dominates the diurnal, synoptic and seasonal variations observed at Tsukuba. Contribution of terrestrial biosphere fluxes is of secondary importance for CO₂ concentration variability. The phase of synoptic scale variability in CO₂ at both heights are remarkably well simulated the observed data (correlation coefficient >0.70) for the entire year. The simulations of monthly mean diurnal cycles are in better agreement with the measurements at lower height compared to that at the upper height. The modelled vertical CO₂ gradients are generally greater than the observed vertical gradient. Sensitivity studies show that the simulation of observed vertical gradient can be improved by increasing the number of vertical levels from 31 in the model WRF to 37 (4 below 200 m) and using the Mellor–Yamada–Janjic planetary boundary scheme. These results have large implications for improving transport model simulation of CO₂ over the continental sites.