Potential environmental issues of CO2 storage in deep saline aquifers: Geochemical results from the Frio-I Brine Pilot test,Texas, USA

Sedimentary basins in general, and deep saline aquifers in particular, are being investigated as possible repositories for large volumes of anthropogenic CO₂ that must be sequestered to mitigate global warming and related climate changes. To investigate the potential for the long-term storage of CO₂ in such aquifers, 1600 t of CO₂ were injected at 1500 m depth into a 24-m-thick “C” sandstone unit of the Frio Formation, a regional aquifer in the US Gulf Coast. Fluid samples obtained before CO₂ injection from the injection well and an observation well 30 m updip showed a Na–Ca–Cl type brine with ∼93,000 mg/L TDS at saturation with CH₄ at reservoir conditions; gas analyses showed that CH₄ comprised ∼95% of dissolved gas, but CO₂ was low at 0.3%. Following CO₂ breakthrough, 51 h after injection, samples showed sharp drops in pH (6.5–5.7), pronounced increases in alkalinity (100–3000 mg/L as HCO₃) and in Fe (30–1100 mg/L), a slug of very high DOC values, and significant shifts in the isotopic compositions of H₂O, DIC, and CH₄. These data, coupled with geochemical modeling, indicate corrosion of pipe and well casing as well as rapid dissolution of minerals, especially calcite and iron oxyhydroxides, both caused by lowered pH (initially ∼3.0 at subsurface conditions) of the brine in contact with supercritical CO₂.     

Geochemistry of a continental saline aquifer for CO2 sequestration: The Guantao formation in the Bohai Bay Basin,North China

The Neogene Guantao formation in the Beitang sag in the Bohai Bay Basin (BBB) of North China, a Mesozoic–Cenozoic sedimentary basin of continental origin, has been chosen as a candidate for a pilot field test of CO₂ sequestration. Hydrogeological and geochemical investigations have been carried out to assess its suitability, taking advantage of many existing geothermal wells drilled to 2000 m or greater depths. Water samples from 25 wells and drill cores of three sections of the Guantao formation were collected for measurements of mineralogy, water chemistry and isotopes (δ¹⁸O, δD, δ¹³C, ¹⁴C). Formation temperature estimated by chemical geothermometry is in the range of 60–80 °C. Geochemical modeling of water–rock–CO₂ interaction predicts a strong geochemical response to CO₂ injection. Besides the elevated porosity (33.6–38.7%) and high permeability (1150–1980 mD) of the Ng-III formation and a favorable reservoir–caprock combination, it is also found that the formation contains carbonates that will react with CO₂ after injection. The low salinity (TDS < 1.6 g/L) offers high CO₂ solubility. The ¹⁴C age of the formation water indicates a quasi-closed saline aquifer system over large time scales, the lateral sealing mechanism for CO₂ sequestration requires further investigation. The CO₂ storage capacity of the Guantao formation within the Beitang sag is estimated to be 17.03 Mt, assuming pure solubility trapping.     

Transport of perfluorocarbon tracers and carbon dioxide in sediment columns – Evaluating the application of PFC tracers for CO2 leakage detection

Perfluorocarbon compounds (PFCs) have high chemical and thermal stability, low background levels in natural systems, and easy detectability. They are proposed as tracers for monitoring potential CO₂ leakage associated with geological carbon sequestration (GCS). The fate of the PFCs in porous media, and in particular, the transport of these compounds relative to CO₂ gas in geological formations, has not been thoroughly studied. We conducted column tests to study the transport of perfluoro-methylcyclo-pentane (PMCP), perfluoro-methylcyclo-hexane (PMCH), ortho-perfluoro-dimethylcyclo-hexane (ortho-PDCH), and perfluoro-trimethylcyclo-hexane (PTCH) gas tracers in a variety of porous media. The influence of water content and sediment minerals on the retardation of the tracers was tested. The transport of PFC tracers relative to ¹³CO₂ and the conservative tracer sulfur hexafluoride (SF₆) was also investigated. Results show that at high water content, the PFCs and SF₆ transported together. In dry and low-water-content sediments, however, the PFCs were retarded relative to SF₆ with the degree of retardation increasing with the molecular weight of the PFC. When water was present in the medium, the transport of CO₂ was greatly retarded compared to SF₆ and the PFC tracers. However, in dry laboratory sediments, the migration of CO₂ was slightly faster than all the tracers. The type of minerals in the sediments also had a significant impact on the fate of the tracers. In order to use the PFC tracer data obtained from the ground surface or shallow subsurface in a GCS site to precisely interpret the extent and magnitude of CO₂ leakage, the retardation of the tracers and the interaction of CO₂ with the reservoir overlying formation water should be carefully quantified.     

The noble gas geochemistry of natural CO2 gas reservoirs from the Colorado Plateau and Rocky Mountain provinces, USA

Identification of the source of CO₂ in natural reservoirs and development of physical models to account for the migration and interaction of this CO₂ with the groundwater is essential for developing a quantitative understanding of the long term storage potential of CO₂ in the subsurface. We present the results of 57 noble gas determinations in CO₂ rich fields (>82%) from three natural reservoirs to the east of the Colorado Plateau uplift province, USA (Bravo Dome, NM., Sheep Mountain, CO. and McCallum Dome, CO.), and from two reservoirs from within the uplift area (St. John’s Dome, AZ., and McElmo Dome, CO.). We demonstrate that all fields have CO₂/³He ratios consistent with a dominantly magmatic source. The most recent volcanics in the province date from 8 to 10 ka and are associated with the Bravo Dome field. The oldest magmatic activity dates from 42 to 70 Ma and is associated with the McElmo Dome field, located in the tectonically stable centre of the Colorado Plateau: CO₂ can be stored within the subsurface on a millennia timescale.The manner and extent of contact of the CO₂ phase with the groundwater system is a critical parameter in using these systems as natural analogues for geological storage of anthropogenic CO₂. We show that coherent fractionation of groundwater ²⁰Ne/³⁶Ar with crustal radiogenic noble gases (⁴He, ²¹Ne, ⁴⁰Ar) is explained by a two stage re-dissolution model: Stage 1: Magmatic CO₂ injection into the groundwater system strips dissolved air-derived noble gases (ASW) and accumulated crustal/radiogenic noble gas by CO₂/water phase partitioning. The CO₂ containing the groundwater stripped gases provides the first reservoir fluid charge. Subsequent charges of CO₂ provide no more ASW or crustal noble gases, and serve only to dilute the original ASW and crustal noble gas rich CO₂. Reservoir scale preservation of concentration gradients in ASW-derived noble gases thus provide CO₂ filling direction. This is seen in the Bravo Dome and St. John’s Dome fields. Stage 2: The noble gases re-dissolve into any available gas stripped groundwater. This is modeled as a Rayleigh distillation process and enables us to quantify for each sample: (1) the volume of groundwater originally ‘stripped’ on reservoir filling; and (2) the volume of groundwater involved in subsequent interaction. The original water volume that is gas stripped varies from as low as 0.0005 cm³ groundwater/cm³ gas (STP) in one Bravo Dome sample, to 2.56 cm³ groundwater/cm³ gas (STP) in a St. John’s Dome sample. Subsequent gas/groundwater equilibration varies within all fields, each showing a similar range, from zero to ∼100 cm³ water/cm³ gas (at reservoir pressure and temperature).     

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.     

Tracers – Past,present and future applications in CO2 geosequestration

Chemical tracers have been used in various C capture and storage (CCS) projects worldwide primarily to provide information regarding subsurface migration of CO₂ and to verify CO₂ containment. Understanding the movement and interactions of CO₂ in the subsurface is a challenging task considering the variety of states in which it exists (i.e. gas, liquid, supercritical, dissolved in water) and the range of possible storage mechanisms (i.e. residual or capillary trapping, dissolved in water, structural trapping or incorporation into minerals). This paper critically reviews several chemical tracer applications and case studies for CCS projects. In many instances, there are parallels (e.g. tracer classes and applications) between tracers in the oil and gas industry and in CCS. It has been shown that chemical tracers can complement geophysical measurements (e.g. seismic) in understanding the formation behaviour of CO₂. Although tracers have been successfully used in many CCS projects, some fundamental information, for example partitioning and adsorption, about the behaviour of tracers is still lacking and this can be an issue when interpreting tracer data (e.g. determining leakage rates). In this paper the deployment and recovery of chemical tracers and their use on various CCS projects are described.     

Vertical equilibrium with sub-scale analytical methods for geological CO2 sequestration

Large-scale implementation of geological CO₂ sequestration requires quantification of risk and leakage potential. One potentially important leakage pathway for the injected CO₂ involves existing oil and gas wells. Wells are particularly important in North America, where more than a century of drilling has created millions of oil and gas wells. Models of CO₂ injection and leakage will involve large uncertainties in parameters associated with wells, and therefore a probabilistic framework is required. These models must be able to capture both the large-scale CO₂ plume associated with the injection and the small-scale leakage problem associated with localized flow along wells. Within a typical simulation domain, many hundreds of wells may exist. One effective modeling strategy combines both numerical and analytical models with a specific set of simplifying assumptions to produce an efficient numerical–analytical hybrid model. The model solves a set of governing equations derived by vertical averaging with assumptions of a macroscopic sharp interface and vertical equilibrium. These equations are solved numerically on a relatively coarse grid, with an analytical model embedded to solve for wellbore flow occurring at the sub-gridblock scale. This vertical equilibrium with sub-scale analytical method (VESA) combines the flexibility of a numerical method, allowing for heterogeneous and geologically complex systems, with the efficiency and accuracy of an analytical method, thereby eliminating expensive grid refinement for sub-scale features. Through a series of benchmark problems, we show that VESA compares well with traditional numerical simulations and to a semi-analytical model which applies to appropriately simple systems. We believe that the VESA model provides the necessary accuracy and efficiency for applications of risk analysis in many CO₂ sequestration problems.     

Dissolution of basalts and peridotite in seawater, in the presence of ligands, and CO2: Implications for mineral sequestration of carbon dioxide

Steady-state silica release rates (r_Si) from basaltic glass and crystalline basalt of similar chemical composition as well as dunitic peridotite have been determined in far-from-equilibrium dissolution experiments at 25 °C and pH 3.6 in (a) artificial seawater solutions under 4 bar pCO₂, (b) varying ionic strength solutions, including acidified natural seawater, (c) acidified natural seawater of varying fluoride concentrations, and (d) acidified natural seawater of varying dissolved organic carbon concentrations. Glassy and crystalline basalts exhibit similar r_Si in solutions of varying ionic strength and cation concentrations. Rates of all solids are found to increase by 0.3-0.5 log units in the presence of a pCO₂ of 4 bar compared to CO₂ pressure of the atmosphere. At atmospheric CO₂ pressure, basaltic glass dissolution rates were most increased by the addition of fluoride to solution whereas crystalline basalt rates were most enhanced by the addition of organic ligands. In contrast, peridotite does not display any significant ligand-promoting effect, either in the presence of fluoride or organic acids. Most significantly, Si release rates from the basalts are found to be not more than 0.6 log units slower than corresponding rates of the peridotite at all conditions considered in this study. This difference becomes negligible in seawater suggesting that for the purposes of in-situ mineral sequestration, CO₂-charged seawater injected into basalt might be nearly as efficient as injection into peridotite.     

Surface heat flow and CO2 emissions within the Ohaaki hydrothermal field,Taupo Volcanic Zone,New Zealand

Carbon dioxide emissions and heat flow have been determined from the Ohaaki hydrothermal field, Taupo Volcanic Zone (TVZ), New Zealand following 20 a of production (116 MW_e). Soil CO₂ degassing was quantified with 2663 CO₂ flux measurements using the accumulation chamber method, and 2563 soil temperatures were measured and converted to equivalent heat flow (W m⁻²) using published soil temperature heat flow functions. Both CO₂ flux and heat flow were analysed statistically and then modelled using 500 sequential Gaussian simulations. Forty subsoil CO₂ gas samples were also analysed for stable C isotopes. Following 20 a of production, current CO₂ emissions equated to 111 ± 6.7 T/d. Observed heat flow was 70 ± 6.4 MW, compared with a pre-production value of 122 MW. This 52 MW reduction in surface heat flow is due to production-induced drying up of all alkali–Cl outflows (61.5 MW) and steam-heated pools (8.6 MW) within the Ohaaki West thermal area (OHW). The drying up of all alkali–Cl outflows at Ohaaki means that the soil zone is now the major natural pathway of heat release from the high-temperature reservoir. On the other hand, a net gain in thermal ground heat flow of 18 MW (from 25 MW to 43.3 ± 5 MW) at OHW is associated with permeability increases resulting from surface unit fracturing by production-induced ground subsidence. The Ohaaki East (OHE) thermal area showed no change in distribution of shallow and deep soil temperature contours despite 20 a of production, with an observed heat flow of 26.7 ± 3 MW and a CO₂ emission rate of 39 ± 3 T/d. The negligible change in the thermal status of the OHE thermal area is attributed to the low permeability of the reservoir beneath this area, which has limited production (mass extraction) and sheltered the area from the pressure decline within the main reservoir. Chemistry suggests that although alkali–Cl outflows once contributed significantly to the natural surface heat flow (∼50%) they contributed little (<1%) to pre-production CO₂ emissions due to the loss of >99% of the original CO₂ content due to depressurisation and boiling as the fluids ascended to the surface. Consequently, the soil has persisted as the major (99%) pathway of CO₂ release to the atmosphere from the high temperature reservoir at Ohaaki. The CO₂ flux and heat flow surveys indicate that despite 20 a of production the variability in location, spatial extent and magnitude of CO₂ flux remains consistent with established geochemical and geophysical models of the Ohaaki Field. At both OHW and OHE carbon isotopic analyses of soil gas indicate a two-stage fractionation process for moderate-flux (>60 g m⁻² d⁻¹) sites; boiling during fluid ascent within the underlying reservoir and isotopic enrichment as CO₂ diffuses through porous media of the soil zone. For high-flux sites (>300 g m⁻² d⁻¹), the δ¹³CO₂ signature (−7.4 ± 0.3‰ OHW and −6.5 ± 0.6‰ OHE) is unaffected by near-surface (soil zone) fractionation processes and reflects the composition of the boiled magmatic CO₂ source for each respective upflow. Flux thresholds of <30 g m⁻² d⁻¹ for purely diffusive gas transport, between 30 and 300 g m⁻² d⁻¹ for combined diffusive–advective transport, and ?300 g m⁻² d⁻¹ for purely advective gas transport at Ohaaki were assigned. δ¹³CO₂ values and cumulative probability plots of CO₂ flux data both identified a threshold of ∼15 g m⁻² d⁻¹ by which background (atmospheric and soil respired) CO₂ may be differentiated from hydrothermal CO₂.     

Computer modeling of methanotrophic oxidation of hydrocarbons in the unsaturated zone from an enhanced oil recovery/sequestration project, Rangely, Colorado, USA

One of the proposals for large-scale sequestration of fossil fuel-derived CO₂ is deep geologic disposal in depleted oil/gas reservoirs or deep aquifers. Previously published scenarios for this inadequately proven technology have either ignored or dismissed the possibility of vertical migration of gases caused by overpressure. Overpressuring of a reservoir or aquifer will be necessary in order to have acceptable rates for dispersal of injected CO₂. This research describes methodology and the results of measurement of microseepage of CO₂ and CH₄ at a large-scale CO₂-enhanced oil recovery (EOR) operation at Rangely, Colorado, USA. Shallow and deep soil gas concentrations, and direct transport of CO₂ and CH₄ into the atmosphere were measured. The interpretation of the measurements was complemented by both stable and radiogenic isotopic measurements of C. The results have demonstrated an estimated microseepage to the atmosphere of approximately 400 metric tonnes of CH₄/a from the 78 km² area of the Rangely field. Preliminary estimates of deep-sourced CO₂ losses are <3800 tonnes/a, based on stable isotope measurements of soil gases. Several holes up to 10 m deep were drilled on, and off the field for nested gas sampling of composition and stable C isotopic ratios for CO₂ and CH₄. Carbon-14 measurements on CO₂ from these holes indicate that deep-sourced CO₂ microseepage losses were approximately 170 tonnes/a.     

Rate measurements and detection of gas microseepage to the atmosphere from an enhanced oil recovery/sequestration project,Rangely, Colorado,USA

One of the proposals for large-scale sequestration of fossil fuel-derived CO₂ is deep geologic disposal in depleted oil/gas reservoirs or deep aquifers. Previously published scenarios for this inadequately proven technology have either ignored or dismissed the possibility of vertical migration of gases caused by overpressure. Overpressuring of a reservoir or aquifer will be necessary in order to have acceptable rates for dispersal of injected CO₂. This research describes methodology and the results of measurement of microseepage of CO₂ and CH₄ at a large-scale CO₂-enhanced oil recovery (EOR) operation at Rangely, Colorado, USA. Shallow and deep soil gas concentrations, and direct transport of CO₂ and CH₄ into the atmosphere were measured. The interpretation of the measurements was complemented by both stable and radiogenic isotopic measurements of C. The results have demonstrated an estimated microseepage to the atmosphere of approximately 400 metric tonnes of CH₄/a from the 78 km² area of the Rangely field. Preliminary estimates of deep-sourced CO₂ losses are <3800 tonnes/a, based on stable isotope measurements of soil gases. Several holes up to 10 m deep were drilled on, and off the field for nested gas sampling of composition and stable C isotopic ratios for CO₂ and CH₄. Carbon-14 measurements on CO₂ from these holes indicate that deep-sourced CO₂ microseepage losses were approximately 170 tonnes/a.     

Economic analysis of carbon dioxide sequestration in powder river basin coal

Unminable coalbeds are potentially large storage reservoirs for the sequestration of anthropogenic CO₂ and offer the benefit of enhanced methane production, which can offset some of the costs associated with CO₂ sequestration. The objective of this paper is to study the economic feasibility of CO₂ sequestration in unminable coal seams in the Powder River Basin of Wyoming. Economic analyses of CO₂ injection options are compared. Results show that injecting flue gas to recover methane from CBM fields is marginally economical; however, this method will not significantly contribute to the need to sequester large quantities of CO₂. Separating CO₂ from flue gas and injecting it into the unminable coal zones of the Powder River Basin seam is currently uneconomical, but can effectively sequester over 86,000 tons (78,200 Mg) of CO₂ per acre while recovering methane to offset costs. The cost to separate CO₂ from flue gas was identified as the major cost driver associated with CO₂ sequestration in unminable coal seams. Improvements in separations technology alone are unlikely to drive costs low enough for CO₂ sequestration in unminable coal seams in the Powder River Basin to become economically viable. Breakthroughs in separations technology could aid the economics, but in the Powder River Basin they cannot achieve the necessary cost reductions for breakeven economics without incentives.     

A geochemical study on mud volcanoes in the Junggar Basin, China

A comprehensive study was performed to characterize, for the first time, the mud, water, and gases released from onshore mud volcanoes located in the southern margin of the Junggar Basin, northwestern China. Chemical compositions of mud, along with the geology of the basin, suggest that a source of the mud is Mesozoic or Cenozoic shale. Oxygen and H isotope compositions of the released water suggest a local meteoric origin. Combined with the positive Eu anomalies of the water, a large ¹⁸O shift of the water suggests extensive interaction with rocks. Gases discharged from the mud volcanoes are predominantly thermogenic hydrocarbons, and the high δ¹³C values (>+20‰ VPDB) for CO₂ gases and dissolved carbonate in muddy water suggest secondary methanogenesis with CO₂ reduction after oil biodegradation.The enrichments of Eu and ¹⁸O in water and the low thermal gradient of the area suggest that the water-rock interactions possibly occur deeper than 3670 ± 200 m. On the other hand, considering the relationship to the petroleum reservoir around the mud volcanoes, the depth of the gases can be derived from about 3600 m, a depth that is greater than that generally estimated for reservoirs whose gas is characterized by ¹³C-enriched CO₂. Oil biodegradation with CO₂ reduction likely occurs at a shallower depth along the seepage system of the mud volcano. The results contribute to the worldwide data set of gas genesis in mud volcanoes. Moreover, they further support the concept that most terrestrial mud volcanoes release thermogenic gas produced in very deep sediments and may be early indicators of oil biodegradation, an important problem in the petroleum industry.     

High-resolution stable carbon isotope monitoring indicates variable flow dynamic patterns in a deep saline aquifer at the Ketzin pilot site (Germany)

Stable isotopes of injected CO₂ act as useful tracers in carbon capture and storage (CCS) because the CO₂ itself is the carrier of the tracer signal and remains unaffected by sorption or partitioning effects. At the Ketzin pilot site (Germany), carbon stable isotope composition (δ¹³C) of injected CO₂ at the injection well was analyzed over a time period of 4 months. Occurring isotope variances resulted from the injection of CO₂ from two different sources (an oil refinery and a natural gas-reservoir). The two gases differed in their carbon isotope composition by more than 27‰. In order to find identifiable patterns of these variances in the reservoir, more than 250 CO₂-samples were collected and analyzed for their carbon isotope ratios at an observation well 100 m distant from the injection well. An isotope ratio mass spectrometer connected to a modified Thermo Gasbench system allowed quick and cost effective isotope analyses of a high number of CO₂ gas specimens. CO₂ gas from the oil refinery (δ¹³C = −30.9‰, source A) was most frequently injected and dominated the reservoir δ¹³C values at the injection site. Sporadic injection of the CO₂ from the natural gas-reservoir (δ¹³C = −3.5‰, source B) caused isotope shifts of up to +5‰ at the injection well. These variances provided a potential ideal tracer for CO₂ migration behavior. Based on these findings, tracer input signals that were injected during the last 2 years of injection could be reconstructed with the aid of an isotope mixing model and CO₂ delivery schedules. However, in contrast to the injection well, δ¹³C values at the observation well showed no variances and a constant value of −28.5‰ was measured at 600 m depth. This is in disagreement with signals that would be expected if the input signals from the injection would arrive at the observation well. The lack of isotope signals at the observation well suggests that parts of the reservoir are filled with CO₂ that is immobilized.     

Selection of coals of different maturities for CO2 Storage by modelling of CH4 and CO2 adsorption isotherms

CO₂ injection in unmineable coal seams could be one interesting option for both storage and methane recovery processes. The objective of this study is to compare and model pure gas sorption isotherms (CO₂ and CH₄) for well-characterised coals of different maturities to determine the most suitable coal for CO₂ storage. Carbon dioxide and methane adsorption on several coals have been investigated using a gravimetric adsorption method. The experiments were carried out using both CO₂ and CH₄ pure gases at 25 °C from 0.1 to 5 MPa (1 to 50 bar). The experimental results were fitted using Temkin's approach but also with the corrected Langmuir's and the corrected Tóth's equations. The two last approaches are more accurate from a thermodynamical point of view, and have the advantage of taking into account the fact that experimental data (isotherms) correspond to excess adsorption capacities. These approaches allow better quantification of the adsorbed gas. Determined CO₂ adsorption capacities are from 0.5 to 2 mmol/g of dry coal. Modelling provides also the affinity parameters of the two gases for the different coals. We have shown these parameters determined with adsorption models could be used for classification and first selection of coals for CO₂ storage. The affinity ratio ranges from a value close to 1 for immature coals to 41 for high rank coals like anthracites. This ratio allows selecting coals having high CO₂ adsorption capacities. In our case, the modelling study of a significant number of coals from various ranks shows that anthracites seem to have the highest CO₂ storage capacities. Our study provides high quality affinity parameters and values of CO₂ and CH₄ adsorption capacities on various coals for the future modelling of CO₂ injection in coal seams.     

Increased hydrocarbon recovery and CO2 management, a Croatian example

Enhanced oil recovery based on CO₂ injection is expected to increase recovery from Croatian oil fields. Large quantities of CO₂ are generated during hydrocarbon processing produced from gas and gas condensate fields situated in the north-western part of Croatia. First CO₂ injection project will be implemented on the Ivani? Oil Field. Numerical modelling based on Upper Miocene sandstone core samples testing results have shown the decrease of oil viscosity during CO₂ injection. Some of the characteristics of the testing samples are porosity 21.5–23.6 %, permeability 14–80 × 10^?15 m² and initial water saturation 28–38.5 %. Water alternating foam (WAF) and water alternating gas (WAG) simulations have provided satisfactory results. The WAF injection process has provided better results, but due to the process sensitivity and costs WAG is recommended for future application. During the pilot project 16 × 10⁶ m³ CO₂ and 5 × 10⁴ m³ of water were injected. Additional amounts of hydrocarbons (4,440 m³ of oil and 2.26 × 10⁶ m³ of gas) were produced which confirmed injection of CO₂ as a successful tertiary oil recovery mechanism in Upper Miocene sandstone reservoirs in the Croatian part of the Pannonian Basin System.     

Geologic factors controlling CO2 storage capacity and permanence: case studies based on experience with heterogeneity in oil and gas reservoirs applied to CO2 storage

A variety of structural and stratigraphic factors control geological heterogeneity, inferred to influence both sequestration capacity and effectiveness, as well as seal capacity. Structural heterogeneity factors include faults, folds, and fracture intensity. Stratigraphic heterogeneity is primarily controlled by the geometry of depositional facies and sandbody continuity, which controls permeability structure. The permeability structure, in turn, has implications for CO₂ injectivity and near-term migration pathways, whereas the long-term sequestration capacity can be inferred from the production history. Examples of Gulf Coast oil and gas reservoirs with differing styles of stratigraphic heterogeneity demonstrate the impact of facies variability on fluid flow and CO₂ sequestration potential. Beach and barrier-island deposits in West Ranch field in southeast Texas are homogeneous and continuous. In contrast, Seeligson and Stratton fields in south Texas, examples of major heterogeneity in fluvial systems, are composed of discontinuous, channel-fill sandstones confined to narrow, sinuous belts. These heterogeneous deposits contain limited compartments for potential CO₂ storage, although CO₂ sequestration effectiveness may be enhanced by the high number of intraformational shale beds. These field examples demonstrate that areas for CO₂ storage can be optimized by assessing sites for enhanced oil and gas recovery in mature hydrocarbon provinces.     

Hazardous gas emissions from the flanks of the quiescent Colli Albani volcano (Rome,Italy)

Gas hazard was evaluated in the three most important cold gas emission zones on the flanks of the quiescent Colli Albani volcano. These zones are located above structural highs of the buried carbonate basement which represents the main regional aquifer and the main reservoir for gas rising from depth. All extensional faults affecting the limestone reservoir represent leaking pathways along which gas rises to the surface and locally accumulates in shallow permeable horizons forming pressurized pockets that may produce gas blowout when reached by wells. The gas, mainly composed of CO₂ (>90 vol.%), contains appreciable quantities of H₂S (0.35–6 vol.%), and both represent a potentially high local hazard. Both gases are denser than air and accumulate near ground where they may reach hazardous concentrations, and lethal accidents frequently occur to animals watering at local ponds. In order to evaluate the rate of degassing and the related hazard, CO₂ and H₂S diffuse soil flux surveys have been repeatedly carried out using an accumulation chamber. The viscous gas flux of some important discrete emissions has been evaluated and the CO₂ and H₂S air concentration measured by portable devices and by Tunable Diode Laser profiles. The minimum potential lethal concentration of the two gases (250 ppm for H₂S and 8 vol.% for CO₂) is 320 times higher for CO₂, whereas the CO₂/H₂S concentration ratio in the emitted natural gas is significantly lower (15–159). This explains why H₂S reaches hazardous, even lethal, concentrations more frequently than CO₂. A relevant hazard exists for both gases in the depressed zones (channels, excavations) particularly in the non-windy early hours of the day.     

Contact angles in CO2-water-coal systems at elevated pressures

Injection of carbon dioxide into coal seams is considered to be a potential method for its sequestration away from the atmosphere. However, water present in coals may retard injection: especially if carbon dioxide does not wet the coal as well as water. Thus contact angles in the coal-water-CO₂ system were measured using CO₂ bubbles in water/coal systems at 40 °C and pressures up to 15 MPa using five bituminous coals. At low pressures, in this CO₂/water/coal system, receding contact angles for the coals ranged between 80° to 100°; except for one coal that had both high ash yield and low rank, with a contact angle of 115°, indicating that it was hydrophilic. With increasing pressure, the receding contact angles for the different coals decreased, indicating that they became more CO₂-wetting. The relationship between contact angle and pressure was approximately linear. For low ash or high rank coals, at high pressure the contact angle was reduced to 30-50°, indicating the coals became strongly CO₂-wetting; that is CO₂ fluids will spontaneously penetrate these wet coals. In the case of the coal that was both high ash and hydrophilic, the contact angle did not drop to 90° even at the highest pressures used. These results suggest that CO₂ will not be efficiently adsorbed by all wet coals equally well, even at high pressure. It was found that at high pressures (> 2 MPa) the rate of penetration of carbon dioxide into the coals increased rapidly with decreasing contact angle, independently of pressure. Injecting CO₂ into wet coals that have both low rank and high ash will not trap CO₂ as well as injecting it into high rank or low ash coals.     

Diffuse gas emissions at the Ukinrek Maars,Alaska: Implications for magmatic degassing and volcanic monitoring

Diffuse CO₂ efflux near the Ukinrek Maars, two small volcanic craters that formed in 1977 in a remote part of the Alaska Peninsula, was investigated using accumulation chamber measurements. High CO₂ efflux, in many places exceeding 1000 g m⁻² d⁻¹, was found in conspicuous zones of plant damage or kill that cover 30,000–50,000 m² in area. Total diffuse CO₂ emission was estimated at 21–44 t d⁻¹. Gas vents 3-km away at The Gas Rocks produce 0.5 t d⁻¹ of CO₂ that probably derives from the Ukinrek Maars basalt based on similar δ¹³C values (∼−6‰), ³He/⁴He ratios (5.9–7.2 R_A), and CO₂/³He ratios (1–2 × 10⁹) in the two areas. A lower ³He/⁴He ratio (2.7 R_A) and much higher CO₂/³He ratio (9 × 10¹⁰) in gas from the nearest arc-front volcanic center (Mount Peulik/Ugashik) provide a useful comparison. The large diffuse CO₂ emission at Ukinrek has important implications for magmatic degassing, subsurface gas transport, and local toxicity hazards. Gas–water–rock interactions play a major role in the location, magnitude and chemistry of the emissions.