Wettability alteration of caprock minerals by carbon dioxide

One of the critical factors that control the efficiency of CO₂ geological storage process in aquifers and hydrocarbon reservoirs is the capillary‐sealing potential of the caprock. This potential can be expressed in terms of the maximum reservoir overpressure that the brine‐saturated caprock can sustain, i.e. of the CO₂ capillary entry pressure. It is controlled by the brine/CO₂ interfacial tension, the water‐wettability of caprock minerals, and the pore size distribution within the caprock. By means of contact angle measurements, experimental evidence was obtained showing that the water‐wettability of mica and quartz is altered in the presence of CO₂ under pressures typical of geological storage conditions. The alteration is more pronounced in the case of mica. Both minerals are representative of shaly caprocks and are strongly water‐wet in the presence of hydrocarbons. A careful analysis of the available literature data on breakthrough pressure measurements in caprock samples confirms the existence of a wettability alteration by dense CO₂, both in shaly and in evaporitic caprocks. The consequences of this effect on the maximum CO₂ storage pressure and on CO₂ storage capacity in the underground reservoir are discussed. For hydrocarbon reservoirs that were initially close to capillary leakage, the maximum allowable CO₂ storage pressure is only a fraction of the initial reservoir pressure.     

Gas breakthrough experiments on pelitic rocks: comparative study with N2, CO2 and CH4

The capillary‐sealing efficiency of intermediate‐ to low‐permeable sedimentary rocks has been investigated by N₂, CO₂ and CH₄ breakthrough experiments on initially fully water‐saturated rocks of different lithological compositions. Differential gas pressures up to 20 MPa were imposed across samples of 10–20 mm thickness, and the decline of the differential pressures was monitored over time. Absolute (single‐phase) permeability coefficients (k_abs), determined by steady‐state fluid flow tests, ranged between 10^?22 and 10^?15 m². Maximum effective permeabilities to the gas phase k_eff(max), measured after gas breakthrough at maximum gas saturation, extended from 10^?26 to 10^?18 m². Because of re‐imbibition of water into the interconnected gas‐conducting pore system, the effective permeability to the gas phase decreases with decreasing differential (capillary) pressure. At the end of the breakthrough experiments, a residual pressure difference persists, indicating the shut‐off of the gas‐conducting pore system. These pressures, referred to as the ‘minimum capillary displacement pressures’ (P_d), ranged from 0.1 up to 6.7 MPa. Correlations were established between (i) absolute and effective permeability coefficients and (ii) effective or absolute permeability and capillary displacement pressure. Results indicate systematic differences in gas breakthrough behaviour of N₂, CO₂ and CH₄, reflecting differences in wettability and interfacial tension. Additionally, a simple dynamic model for gas leakage through a capillary seal is presented, taking into account the variation of effective permeability as a function of buoyancy pressure exerted by a gas column underneath the seal.     

Are rocks still water‐wet in the presence of dense CO2 or H2S?

The various modes of acid gas storage in aquifers, namely structural, residual, and local capillary trapping, are effective only if the rock remains water‐wet. This paper reports an evaluation, by means of the captive‐bubble method, of the water‐wet character in presence of dense acid gases (CO₂, H₂S) of typical rock‐forming minerals such as mica, quartz, calcite, and of a carbonate‐rich rock sampled from the caprock of a CO₂ storage reservoir in the South‐West of France. The method, which is improved from that previously implemented with similar systems by Chiquet et al. (Geofluids 2007; 7 : 112), allows the advancing and receding contact angles, as well as the adhesion behavior of the acid gas on the mineral substrate, to be evaluated over a large range of temperatures (up to 140°C), pressures (up to 150 bar), and brine salinities (up to NaCl saturation) representative of various geological storage conditions. The water‐receding (or gas‐advancing) angle that controls structural and local capillary trapping is observed to be not significantly altered in the presence of dense CO₂ or H₂S. In contrast, some alteration of the water‐advancing (or gas‐receding) angle involved in residual trapping is observed, along with acid gas adhesion, particularly on mica. A spectacular wettability reversal is even observed with mica and liquid H₂S. These results complement other recent observations on similar systems and present analogies with the wetting behavior of crude oil/brine/mineral systems, which has been thoroughly studied over the past decades. An insight is given into the interfacial forces that govern wettability in acid gas‐bearing aquifers, and the consequences for acid gas geological storage are discussed along with open questions for future work.     

Hydrogeochemical modelling of CO2 equilibria and mass transfer induced by organic–inorganic interactions in siliciclastic petroleum reservoirs

Different feldspar types control complex hydrogeochemical processes in hydrocarbon‐bearing siliciclastic reservoirs, which have undergone different degrees of degradation. To test such processes generically, carbon dioxide equilibria and mass transfers induced by organic–inorganic interactions have been modelled for different hydrogeochemical scenarios. The approach is based on and compared with data from the Norwegian continental shelf ( Smith & Ehrenberg 1989 ) and assumes local thermodynamic equilibrium among solids and fluids. Equilibrating mineral assemblages (different feldspar types, quartz, kaolinite, calcite) are based on the primary reservoir composition. Equilibration and coupled mass transfer were triggered by the addition and reaction of different amounts of CO₂, CH₄ and H₂ (plus acetic acid) at temperatures between 50 and 95°C (323 and 368 K). These components occur in oil fields as products of anaerobic bacterial degradation, hydrolytic disproportionation of hydrocarbons and/or thermal maturation of kerogen. We apply two different computer codes and two different thermodynamic data bases to calculate the results. Reaction of 0.32–0.6 mol CO₂, 0.16–0.3 mol CH₄ and 0.8–1.5 mol H₂ with K‐feldspar, quartz, kaolinite and calcite in 1 l of pore water results in modelled values of 0.3–2.3 mol% CO₂ in a multicomponent gas phase that resembles measured data (0.2–1.5 mol%). Similar CO₂ contents result from acetic acid addition (CO₂, CH₄, H₂ + 0.016 mol CH₃COOH). Equilibration with albite or anorthite reduces the release of CO₂ into the multicomponent gas phase dramatically, by 1 or 4 orders of magnitude compared with the equilibration with K‐feldspar. Minor differences in the modelled CO₂ content (0.1–0.2 mol%) result from calculations with different computer codes if the same thermodynamic data base is applied. Relevant differences (up to 1.9 mol% CO₂) result from calculations using different thermodynamic data bases.     

Study of coal gas wettability for CO2 storage and CH4 recovery

To quantify and rank gas wettability of coal as a key parameter affecting the extent of CO₂ sequestration in coal and CH₄ recovery from coal, we developed a contact angle measuring system based on a captive gas bubble technique. We used this system to study the gas wetting properties of an Australian coal from the Sydney Basin. Gas bubbles were generated and captivated beneath a coal sample within a distilled water‐filled (pH 5.7) pressurised cell. Because of the use of distilled water, and the continuous dissolution and shrinkage of the gas bubble in water during measurement, the contact angles measured correspond to a ‘transient receding’ contact angle. To take into account the mixed‐gas nature (CO₂, CH₄, and to a lesser extent N₂) of coal seam gas in the basin, we evaluated the relative wettability of coal by CH₄, CO₂ and N₂ gases in the presence of water. Measurements were taken at various pressures of up to 15 MPa for CH₄ and N₂, and up to 6 MPa for CO₂ at a constant temperature of 22°C. Overall, our results show that CO₂ wets coal more extensively than CH₄, which in turn wets coal slightly more than N₂. Moreover, the contact angle reduces as the pressure increases, and becomes < 90° at various pressures depending on the gas type. In other words, all three gases wet coal better than water under sufficiently high pressure.     

The effect of deformation on permeability development in anhydrite and implications for caprock integrity during geological storage of CO2

Geological storage of CO₂ in depleted oil and gas reservoirs is one of the most promising options to reduce atmospheric CO₂ concentrations. Of great importance to CO₂ mitigation strategies is maintaining caprock integrity. Worldwide many current injection sites and potential storage sites are overlain by anhydrite‐bearing seal formations. However, little is known about the magnitude of the permeability change accompanying dilatation and failure of anhydrite under reservoir conditions. To this extent, we have performed triaxial compression experiments together with argon gas permeability measurements on Zechstein anhydrite, which caps many potential CO₂ storage sites in the Netherlands. Our experiments were performed at room temperature at confining pressures of 3.5–25 MPa. We observed a transition from brittle to semi‐brittle behaviour over the experimental range, and peak strength could be described by a Mogi‐type failure envelope. Dynamic permeability measurements showed a change from ‘impermeable’ (<10^?21 m²) to permeable (10^?16 to 10^?19 m²) as a result of mechanical damage. The onset of measurable permeability was associated with an increase in the rate of dilatation at low pressures (3.5–5 MPa), and with the turning point from compaction to dilatation in the volumetric versus axial strain curve at higher pressures (10–25 MPa). Sample permeability was largely controlled by the permeability of the shear faults developed. Static, postfailure permeability decreased with increasing effective mean stress. Our results demonstrated that caprock integrity will not be compromised by mechanical damage and permeability development. Geofluids (2010) 10 , 369–387     

Experimental study of the effect of variation in in‐situ stress on capillary residual trapping during CO2 geo‐sequestration in sandstone reservoirs

During a geo‐sequestration process, CO₂ injection causes an increase in reservoir pore pressure, which in turn decreases the reservoir net effective stress. Changes in effective stress can change all the reservoir and cap‐rock properties including residual saturations. This article presents the results of an experimental work carried out to understand the potential change in the volumes of residually trapped CO₂, while the porous medium tested underwent change in the net effective stress under in‐situ reservoir conditions of pore pressure and temperature. The experimental results obtained show that an initial 1725 psi (11.9 MPa) decrease in the net effective pressure caused 1.4% reduction in the volumes of residually trapped CO₂, while another 1500 psi (10.3 MPa) reduction caused a further 3.2% drop in the residual saturation of CO₂.     

Modeling CO2 generation,migration, and titration in sedimentary basins

High mole fraction CO₂ gases pose a significant risk to hydrocarbon exploration in some areas. The generation and movement of CO₂ are also of scientific interest, particularly because CO₂ is an important greenhouse gas. We have developed a model of CO₂ generation, migration, and titration in basins in which a high mole fraction CO₂ gas is generated by the breakdown of siderite (FeCO₃) and magnesite (MgCO₃) where parts of the basin are being heated above approximately 330°C. The CO₂ reacts with Fe‐, Mg‐, and Ca‐silicates as it migrates upward and away from the generation zone (CO₂‐kitchen). Near the kitchen, where the Fe‐, Mg‐, and Ca‐silicates have been titrated and destroyed by previous packets of migrating CO₂, gas moves upward without lowering its CO₂ mole fraction. Further on, where Fe‐ and Mg‐silicates are still present but Ca‐silicates are absent in the sediments, the partial pressure of CO₂ is constrained to 0.1–30 bars and reservoirs contain a few mole percent CO₂ as described by Smith & Ehrenberg (1989) . Still further from the source, where Ca‐silicates have not been titrated, partial pressure of CO₂ in migrating methane gas are orders of magnitude lower. A 2D numerical model of CO₂ generation, migration, and titration quantifies these buffer relations and makes predictions of CO₂ risk in the South China Sea that are compatible with exploration experience. Reactive CO₂ transport models of the kind described could prove useful in determining how gases migrate in faulted sedimentary basins.     

Simulation of the impact of faults on CO2 injection into sandstone reservoirs

Numerical simulations of multiphase CO₂ behavior within faulted sandstone reservoirs examine the impact of fractures and faults on CO₂ migration in potential subsurface injection systems. In southeastern Utah, some natural CO₂ reservoirs are breached and CO₂‐charged water flows to the surface along permeable damage zones adjacent to faults; in other sites, faulted sandstones form barriers to flow and large CO₂‐filled reservoirs result. These end‐members serve as the guides for our modeling, both at sites where nature offers ‘successful’ storage and at sites where leakage has occurred. We consider two end‐member fault types: low‐permeability faults dominated by deformation‐band networks and high‐permeability faults dominated by fracture networks in damage zones adjacent to clay‐rich gouge. Equivalent permeability (k) values for the fault zones can range from <10^?14 m² for deformation‐band‐dominated faults to >10^?12 m² for fracture‐dominated faults regardless of the permeability of unfaulted sandstone. Water–CO₂ fluid‐flow simulations model the injection of CO₂ into high‐k sandstone (5 × 10^?13 m²) with low‐k (5 × 10^?17 m²) or high‐k (5 × 10^?12 m²) fault zones that correspond to deformation‐band‐ or fracture‐dominated faults, respectively. After 500 days, CO₂ rises to produce an inverted cone of free and dissolved CO₂ that spreads laterally away from the injection well. Free CO₂ fills no more than 41% of the pore space behind the advancing CO₂ front, where dissolved CO₂ is at or near geochemical saturation. The low‐k fault zone exerts the greatest impact on the shape of the advancing CO₂ front and restricts the bulk of the dissolved and free CO₂ to the region upstream of the fault barrier. In the high‐k aquifer, the high‐k fault zone exerts a small influence on the shape of the advancing CO₂ front. We also model stacked reservoir seal pairs, and the fracture‐dominated fault acts as a vertical bypass, allowing upward movement of CO₂ into overlying strata. High‐permeability fault zones are important pathways for CO₂ to bypass unfaulted sandstone, which leads to reduce sequestration efficiency. Aquifer compartmentalization by low‐permeability fault barriers leads to improved storativity because the barriers restrict lateral CO₂ migration and maximize the volume and pressure of CO₂ that might be emplaced in each fault‐bound compartment. As much as a 3.5‐MPa pressure increase may develop in the injected reservoir in this model domain, which under certain conditions may lead to pressures close to the fracture pressure of the top seal.     

Characteristics of CO2‐driven cold‐water geyser,Crystal Geyser in Utah: experimental observation and mechanism analyses

Geologic carbon capture and storage (CCS) is an option for reducing CO₂ emissions, but leakage to the surface is a risk factor. Natural CO₂ reservoirs that erupt from abandoned oil and gas holes leak to the surface as spectacular cold geysers in the Colorado Plateau, United States. A better understanding of the mechanisms of CO₂‐driven cold‐water geysers will provide valuable insight about the potential modes of leakage from engineered CCS sites. A notable example of a CO₂‐driven cold‐water geyser is Crystal Geyser in central Utah. We investigated the fluid mechanics of this regularly erupting geyser by instrumenting its conduit with sensors and measuring pressure and temperature every 20 sec over a period of 17 days. Analyses of these measurements suggest that the timescale of a single‐eruption cycle is composed of four successive eruption types with two recharge periods ranging from 30 to 40 h. Current eruption patterns exhibit a bimodal distribution, but these patterns evolved during past 80 years. The field observation suggests that the geyser's eruptions are regular and predictable and reflect pressure and temperature changes resulting from Joule–Thomson cooling and endothermic CO₂ exsolution. The eruption interval between multiple small‐scale eruptions is a direct indicator of the subsequent large‐scale eruption.     

Surface controls on the characteristics of natural CO2 seeps: implications for engineered CO2 stores

CO₂ injected into rock formations for deep geological storage must not leak to surface, since this would be economically and environmentally unfavourable, and could present a human health hazard. In Italy natural CO₂ degassing to the surface via seeps is widespread, providing an insight into the various styles of subsurface ‘plumbing’ as well as surface expression of CO₂ fluids. Here we investigate surface controls on the distribution of CO₂ seep characteristics (type, flux and temperature) using a large geographical and historical data set. When the locations of documented seeps are compared to a synthetic statistically random data set, we find that the nature of the CO₂ seeps is most strongly governed by the flow properties of the outcropping rocks, and local topography. Where low‐permeability rocks outcrop, numerous dry seeps occur and have a range of fluxes. Aqueous fluid flow will be limited in these low‐permeability rocks, and so relative permeability effects may enable preferential CO₂ flow. CO₂ vents typically occur along faults in rocks that are located above the water table or are low permeability. Diffuse seeps develop where CO₂ (laterally supplied by these faults) emerges from the vadose zone and where CO₂ degassing from groundwater follows a different flow path due to flow differences for water and CO₂ gas. Bubbling water seeps (characterized by water bubbling with CO₂) arise where CO₂ supply enters the phreatic zone or an aquifer. CO₂‐rich springs often emerge where valleys erode into CO₂ aquifers, and these are typically high flux seeps. Seep type is known to influence human health risk at CO₂ seeps in Italy, as well as the topography surrounding the seep which affects the rate of gas dispersion by wind. Identifying the physical controls on potential seep locations and seep type above engineered CO₂ storage operations is therefore crucial to targeted site monitoring strategy and risk assessment. The surface geology and topography above a CO₂ store must therefore be characterized in order to design the most effective monitoring strategy.     

Mineralogy and fluid inclusion gas chemistry of production well mineral scale deposits at the Dixie Valley geothermal field,USA

At the Dixie Valley geothermal field, Nevada, USA, fluid boiling triggered the precipitation of carbonate scale minerals in concentric bands around tubing inserted into production well 28–33. When the tubing was removed, this mineral scale was sampled at 44 depth intervals between the wellhead and 1227 m depth. These samples provide a unique opportunity to evaluate the effects of fluid boiling on the scale mineralogy and geochemistry of the vapor and liquid phase. In this study, the mineralogy of the scale deposits and the composition of the fluid inclusion gases trapped in the mineral scales were analyzed. The scale consists mainly of calcite from 670–1112 m depth and aragonite from 1125 to 1227 m depth, with traces of quartz and Mg‐smectite. Mineral textures, including hopper growth, twinning, and fibrous growth in the aragonite and banded deposits of fine grained calcite crystals, are the result of progressive boiling. The fluid inclusion noncondensable gas was dominated by CO₂. However, significant variations in He relative to N₂ and Ar provide evidence that the geothermal reservoir consists of mixed source deeply circulating reservoir water and shallow, air saturated meteoric water. Gas analyses for many inclusions also showed higher CH₄ and H₂ relative to CO₂ than measured in gas sampled from this well, other production wells, and fumaroles. These inclusions are interpreted to have trapped CH₄‐ and H₂‐enriched gas resulting from early stages of boiling.     

Molecular transport of methane, ethane and nitrogen and the influence of diffusion on the chemical and isotopic composition of natural gas accumulations

Laboratory experiments have been performed to determine diffusion coefficients of natural gas components (methane, ethane and nitrogen) and isotope fractionation effects under simulated in situ pressure (up to 45 MPa effective stress) and temperature conditions (50–200°C) in water‐saturated pelitic and coarse‐grained rocks. Effective diffusion coefficients of molecular nitrogen (0.39 × 10^?11 to 21.6 × 10^?11 m² sec^?1 at 90°C) are higher than those for methane (0.18 × 10^?11 to 18.2 × 10^?11 m² sec^?1 at 90°C). Diffusive flux rates expressed in mass units are generally higher for N₂ than for CH₄. Both methane and (to a lesser extent) nitrogen diffusion coefficients decrease with increasing total organic carbon (TOC) content of the rock samples because of sorption processes on the organic matter. This effect decreases with increasing temperature. Effective diffusion coefficients increase upon a temperature increase from 50 to 200°C by a factor of four. Effective diffusion coefficients and steady‐state diffusive flux decrease with effective stress. Stationary diffusive fluxes drop by 50–70% for methane and 45–62% for nitrogen while effective diffusion coefficients are reduced by 38% (CH₄) and 32–48% (N₂), respectively. Isotope fractionation coefficients of diffusive transport are higher for methane (?1.56 and ?2.77‰) than for ethane (?0.84 and ?1.62‰). Application of the experimental results to geological systems show that diffusive transport has only a low transport efficiency. Significant depletion of natural gas reservoirs by molecular diffusion is only expected in cases of very poor caprock qualities (in terms of thickness and/or porosity) and over extended periods of geological time. Under these circumstances, the chemical and isotopic composition of a gas reservoir will change and maturity estimates based on these parameters may be deceptive. To account for these potential effects, nomograms have been developed to estimate diffusive losses and apply maturity corrections.     

Experimental investigation of carbon dioxide trapping due to capillary retention in saline aquifers

Capillary trapping is a physical mechanism by which carbon dioxide (CO₂) is naturally immobilized in the pore spaces of aquifer rocks during geologic carbon sequestration operations, and thus a key aspect of estimating geologic storage potential. Here, we studied capillary trapping of supercritical carbon dioxide (scCO₂), and the effect of initial scCO₂ saturation and flow rate on the storage/trapping potential of Berea sandstone. We performed two‐phase, scCO₂‐brine displacements in two samples, each subject to four sequential drainage–imbibition core‐flooding cycles to quantify end‐point saturations of scCO₂ with the aid of micro‐ and macro‐computed tomography imaging. From these experiments, we found that between 51% and 75% of the initial CO₂ injected can be left behind after the brine injection. We also observed that the initial scCO₂ saturation influenced the residual scCO₂ saturation to a greater extent than the rate of brine injection under the experimental conditions examined. In spite of differences in the experimental conditions tested, as well as those reported in the literature, initial and residual saturations were found to follow a consistent relationship.     

Permeability evolution in sorbing media: analogies between organic‐rich shale and coal

Shale gas reservoirs like coalbed methane (CBM) reservoirs are promising targets for geological sequestration of carbon dioxide (CO₂). However, the evolution of permeability in shale reservoirs on injection of CO₂ is poorly understood unlike CBM reservoirs. In this study, we report measurements of permeability evolution in shales infiltrated separately by nonsorbing (He) and sorbing (CO₂) gases under varying gas pressures and confining stresses. Experiments are completed on Pennsylvanian shales containing both natural and artificial fractures under nonpropped and propped conditions. We use the models for permeability evolution in coal (Journal of Petroleum Science and Engineering, Under Revision) to codify the permeability evolution observed in the shale samples. It is observed that for a naturally fractured shale, the He permeability increases by approximately 15% as effective stress is reduced by increasing the gas pressure from 1 MPa to 6 MPa at constant confining stress of 10 MPa. Conversely, the CO₂ permeability reduces by a factor of two under similar conditions. A second core is split with a fine saw to create a smooth artificial fracture and the permeabilities are measured for both nonpropped and propped fractures. The He permeability of a propped artificial fracture is approximately 2‐ to 3fold that of the nonpropped fracture. The He permeability increases with gas pressure under constant confining stress for both nonpropped and propped cases. However, the CO₂ permeability of the propped fracture decreases by between one‐half to one‐third as the gas pressure increases from 1 to 4 MPa at constant confining stress. Interestingly, the CO₂ permeability of nonpropped fracture increases with gas pressure at constant confining stress. The permeability evolution of nonpropped and propped artificial fractures in shale is found to be similar to those observed in coals but the extent of permeability reduction by swelling is much lower in shale due to its lower organic content. Optical profilometry is used to quantify the surface roughness. The changes in surface roughness indicate significant influence of proppant indentation on fracture surface in the shale sample. The trends of permeability evolution on injection of CO₂ in coals and shales are found analogous; therefore, the permeability evolution models previously developed for coals are adopted to explain the permeability evolution in shales.     

Quantitative analysis of COH fluids synthesized at HP–HT conditions: an optimized methodology to measure volatiles in experimental capsules

The quantitative assessment of COH fluids is crucial in modeling geological processes. The composition of fluids, and in particular their H₂O/CO₂ ratio, can influence the melting temperatures, the location of hydration or carbonation reactions, and the solute transport capability in several rock systems. In the scientific literature, COH fluids speciation has been generally assumed on the basis of thermodynamic calculations using equations of state of simple H₂O–nonpolar gas systems (e.g., H₂O–CO₂–CH₄). Only few authors dealt with the experimental determination of high‐pressure COH fluid species at different conditions, using diverse experimental and analytical approaches (e.g., piston cylinder + capsule piercing + gas chromatography/mass spectrometry; cold seal + silica glass capsules + Raman). In this contribution, we present a new methodology for the synthesis and the analysis of COH fluids in experimental capsules, which allows the quantitative determination of volatiles in the fluid by means of a capsule‐piercing device connected to a quadrupole mass spectrometer. COH fluids are synthesized starting from oxalic acid dihydrate at P = amb and T = 250°C in single capsules heated in a furnace, and at P = 1 GPa and T = 800°C using a piston‐cylinder apparatus and the double‐capsule technique to control the redox conditions employing the rhenium–rhenium oxide oxygen buffer. A quantitative analysis of H₂O, CO₂, CH₄, CO, H₂, O₂, and N₂ along with associated statistical errors is obtained by linear regression of the m/z data of the sample and of standard gas mixtures of known composition. The estimated uncertainties are typically <1% for H₂O and CO₂, and <5% for CO. Our results suggest that the COH fluid speciation is preserved during and after quench, as the experimental data closely mimic the thermodynamic model both in terms of bulk composition and fluid speciation.     

Decreasing CO2 partial pressure triggered Mg–Fe–Ca carbonate formation in ancient Martian crust preserved in the ALH84001 Meteorite

We retrace hydrogeochemical processes leading to the formation of Mg–Fe–Ca carbonate concretions (first distinct carbonate population, FDCP) in Martian meteorite ALH84001 by generic hydrogeochemical equilibrium and mass transfer modeling. Our simple conceptual models assume isochemical equilibration of orthopyroxenite minerals with pure water at varying water‐to‐rock ratios, temperatures and CO₂ partial pressures. Modeled scenarios include CO₂ partial pressures ranging from 10.1325 to 0.0001 MPa at water‐to‐rock ratios between 4380 and 43.8 mol mol^?1 and different temperatures (278, 303 and 348 K) and enable the precipitation of Mg–Fe–Ca solid solution carbonate. Modeled range and trend of carbonate compositional variation from magnesio‐siderite (core) to magnesite (rim), and the precipitation of amorphous SiO₂ and magnetite coupled to magnesite‐rich carbonate are similar to measured compositional variation. The results of this study suggest that the early Martian subsurface had been exposed to a dynamic gas pressure regime with decreasing CO₂ partial pressure at low temperatures (approximately 1.0133 to 0.0001 MPa at 278 K or 6 to 0.0001 MPa at 303 K). Moderate water‐to‐rock ratios of ca. 438 mol mol^?1 and isochemical weathering of orthopyroxenite are additional key prerequisites for the formation of secondary phase assemblages similar to ALH84001’s ‘FDCP’. Outbursts of water and CO_2(g) from confined ground water in fractured orthopyroxenite rocks below an unstable CO₂ hydrate‐containing cryosphere provide adequate environments on the early Martian surface.     

FT-IR measurements of petroleum fluid inclusions: methane, n-alkanes and carbon dioxide quantitative analysis

A recent advancement in petroleum geochemistry is to model fossil oil composition using microthermometric and volumetric data acquired from individual fluid inclusion analysis. Fourier transform infrared (FT‐IR) microspectroscopy can record compositional information related to gas (CH₄ and CO₂) and alkane contents of petroleum inclusions. In this study, a quantitative procedure for FT‐IR microspectrometry has been developed to obtain, from individual fluid inclusions, mol percentage concentrations of methane, alkanes and carbon dioxide as constraints to thermodynamic modelling. A petroleum inclusion in a sample from the Québec City Promontory nappe area was used as standard to record a reference spectrum of methane. The analytical procedure is based on the measurement of CH₄/alkane and CH₄/CO₂ band area ratios. CH₄/alkane infrared band area ratio is obtained after spectral subtraction of the reference methane spectrum. This area ratio, affected by absolute absorption intensities of methane, methyl and methylene, provides a molar CH₄/alkane ratio. Methyl/methylene ratio (CH₂/CH₃) ratio is obtained following procedures established in previous work. CO₂/CH₄ concentration ratio is estimated from relative absolute absorption intensities. Application to natural inclusions from different environments shows good correlation between FT‐IR quantification and PIT (petroleum inclusion thermodynamic) modelling.     

Role of compressive tectonics on gas charging into the Ordovician sandstone reservoirs in the Sbaa Basin,Algeria: constrained by fluid inclusions and mineralogical data

Structure‐ and tectonic‐related gas migration into Ordovician sandstone reservoirs and its impact on diagenesis history were reconstructed in two gas fields in the Sbaa Basin, in SW Algeria. This was accomplished by petrographical observations, fluid inclusion microthermometry and stable isotope geochemistry on quartz, dickite and carbonate cements and veins. Two successive phases of quartz cementation (CQ1 and CQ2) occurred in the reservoirs. Two phase aqueous inclusions show an increase in temperatures and salinities from the first CQ1 diagenetic phase toward CQ2 in both fields. Microthermometric data on gas inclusions in quartz veins reveal the presence of an average of 92 ± 5 mole% of CH₄ considering a CH₄‐CO₂ system, which is similar to the present‐day gas composition in the reservoirs. The presence of primary methane inclusions in early quartz overgrowths and in quartz and calcite veins suggests that hydrocarbon migration into the reservoir occurred synchronically with early quartz cementation in the sandstones located near the contact with the Silurian gas source rock at 100–140°C during the Late Carboniferous period and the late Hercynian episode fracturing at temperatures between 117 and 185°C, which increased in the NW‐direction of the basin. During the fracture filling, three main types of fluids were identified with different salinities and formation temperatures. A supplementary phase of higher fluid temperature (up to 226°C) recorded in late quartz, and calcite veins is related to a Jurassic thermal event. The occurrence of dickite cements close to the Silurian base near the main fault areas in both fields is mainly correlated with the sandstones where the early gas was charged. It implies that dickite precipitation is related to acidic influx. Late carbonate cements and veins (calcite – siderite – ankerite and strontianite) occurred at the same depths resulting from the same groundwater precipitation. The absence of methane inclusions in calcite cements result from methane flushing by saline waters.     

Diffuse hydrothermal methane output and evidence of methanotrophic activity within the soils at Sousaki (Greece)

Methane soil flux measurements have been made in 38 sites at the geothermal system of Sousaki (Greece) with the closed chamber method. Fluxes range from ?47.6 to 29 150 mg m^?2 day^?1, and the diffuse CH₄ output of the system has been estimated at 19 t a^?1. Contemporaneous CO₂ flux measurements showed a moderate positive correlation between CO₂ and CH₄ fluxes. Comparison of the CO₂/CH₄ soil flux ratios with the CO₂/CH₄ ratio of the gases of the main gas manifestations provided evidence for methanotrophic activity within the soil. Laboratory CH₄ consumption experiments confirmed the presence of methanotrophic microorganisms in soil samples collected at Sousaki. Consumption was generally in the range from ?4.9 to ?38.9 pmolCH₄ h^?1 g^?1 but could sometimes reach extremely high values (?33 000 pmolCH₄ h^?1 g^?1). These results are consistent with recent studies on other geothermal systems that revealed the existence of thermoacidophilic bacteria exerting methanotrophic activity in hot, acid soils, thereby reducing methane emissions to the atmosphere.