Bernhard M. Krooss

High-pressure methane and carbon dioxide adsorption on dry and moisture-equilibrated Pennsylvanian coals

In the context of research on the reduction of CO2 emissions and the production of coalbed methane (CBM), high pressure adsorption measurements of CH4 and CO2 have been performed on dry and moisture-equilibrated Pennsylvanian coals of different rank (0.72, 1.19 and 1.56% VRr). Adsorption isotherms of the two gases were measured up to pressures of 20 MPa (200 bar), at 40, 60 and 80 °C using a volumetric method. Total excess sorption capacities for methane on dry coals ranged between 11 and 14 Std. cm3/g coal. The 40 °C sorption isotherms showed a saturation behavior while the 60 and 80 °C isotherms exhibited a monotonous increase over the entire experimental pressure range (up to 20 MPa). Methane sorption capacities of moisture-equilibrated coals were lower by ∼20–25% than those for dry coals and ranged between 7 and 11 Std. cm3/g coal. No distinct maturity effect was discernible for methane adsorption on the three samples studied, neither in the dry nor in the moist state. CO2 adsorption isotherms for dry and moist coals showed substantial differences. For dry coals the highest CO2 excess sorption capacities were observed at 40 °C with maximum values of 70 Std. cm3/g within limited pressure ranges. Carbon dioxide excess sorption for the moisture-equilibrated coals was usually lower than for the dry samples in the low pressure range. All high-pressure CO2 adsorption isotherms for moist samples were bimodal with distinct minima and even negative excess sorption values in the 8–10 MPa (80–100 bar) range. Beyond this range CO2 adsorption capacity increased with increasing pressure. High-temperature (80 °C) sorption capacities for CO2 were very low (<5 Std. cm3/g) in the low-pressure range but reached much higher levels (25–50 Std. cm3/g) above 12 MPa. The strong bimodal character of the CO2 excess isotherms on moist coals is interpreted as the result of a swelling effect caused by supercritical CO2 and enhanced by water. Some extent of swelling was also inferred for dry coals. Absolute sorption isotherms for CO2 were calculated assuming a sorbed-phase density of 1028 kg/m3 and compared with literature data. Like the excess isotherms, the absolute isotherms show a distinct decline in the 8–10 MPa pressure interval. At higher pressures, however, they increase monotonously.

Methane and CO2 sorption and desorption measurements on dry Argonne premium coals: pure components and mixtures

Abstract Sorption and desorption behaviour of methane, carbon dioxide, and mixtures of the two gases has been studied on a set of well-characterised coals from the Argonne Premium Coal Programme. The coal samples cover a maturity range from 0.25% to 1.68% vitrinite reflectance. The maceral compositions were dominated by vitrinite (85% to 91%). Inertinite contents ranged from 8% to 11% and liptinite contents around 1% with one exception (Illinois coal, 5%). All sorption experiments were performed on powdered (−100 mesh), dry coal samples. Single component sorption/desorption measurements were carried out at 22 °C up to final pressures around 51 bar (5.1 MPa) for CO 2 (subcritical state) and 110 bar (11 MPa) for methane. The ratios of the final sorption capacities for pure CO 2 and methane (in molar units) on the five coal samples vary between 1.15 and 3.16. The lowest ratio (1.15) was found for the North Dakota Beulah-Zap lignite (VR r =0.25%) and the highest ratios (2.7 and 3.16) were encountered for the low-rank coals (VR r 0.32% and 0.48%) while the ratio decreases to 1.6–1.7 for the highest rank coals in this series. Desorption isotherms for CH 4 and CO 2 were measured immediately after the corresponding sorption isotherms. They generally lie above the sorption isotherms. The degree of hysteresis, i.e. deviation of sorption and desorption isotherms, varies and shows no dependence on coal rank. Adsorption tests with CH 4 /CO 2 mixtures were conducted to study the degree of preferential sorption of these two gases on coals of different rank. These experiments were performed on dry coals at 45 °C and pressures up to 180 bar (18 MPa). For the highest rank samples of this sequence preferential sorption behaviour was “as expected”, i.e. preferential adsorption of CO 2 and preferential desorption of CH 4 were observed. For the low rank samples, however, preferential adsorption of CH 4 was found in the low pressure range and preferential desorption of CO 2 over the entire pressure range. Follow-up tests for single gas CO 2 sorption measurements consistently showed a significant increase in sorption capacity for re-runs on the same sample. This phenomenon could be due to extraction of volatile coal components by CO 2 in the first experiment. Reproducibility tests with methane and CO 2 using fresh sample material in each experiment did not show this effect.

Experimental characterisation of the hydrocarbon sealing efficiency of cap rocks

Abstract Jurassic shales and mudrocks from the Haltenbanken area offshore Norway and red claystones from Carboniferous and Permian intervals of Northern Germany were used in a study of the hydrocarbon sealing efficiency of clastic sediments. The investigations comprised geochemical and mineralogical analysis of the pelitic rocks, petrophysical characterisation by mercury porosimetry and specific surface area measurements, and laboratory experiments to assess the transport properties with respect to both molecular transport (diffusion) and volume flow (Darcy flow). Effective diffusion coefficients of methane in the water-saturated rock samples at 150°C lay between 1.4 × 10−11 and 4.5 × 10−10m2/s and showed a distinct correlation with TOC content. Permeability coefficients, measured by means of a steady-state method, ranged from The experimental data were used to calculate maximum sustainable gas and petroleum column heights, hydrocarbon leakage rates by pressure-driven volume flow (Darcy flow), and diffusive gas losses for simple, hypothetical scenarios. Computed maximum gas column heights range from 20 m up to >2000 m. Hydrocarbon column heights calculated on the basis of a rich condensate lay between 3 and 340 m. Depending on temperature, pressure, reservoir geometry and seal thickness, diffusive losses can be expected to require tens of millions of years to significantly affect the contents of commercial size natural gas reservoirs.

Quantification of loss of calcite, pyrite, and organic matter due to weathering of Toarcian black shales and effects on kerogen and bitumen characteristics

Abstract Comparison of geochemical data on Posidonia Shale (Early Toarcian) from a shallow unweathered core and from adjacent weathered exposures of the same fades was performed. Results revealed that quantitatively the most affected petrographic constituent is pyrite and that organic matter and carbonate were also altered by weathering. Due to this process of weathering, the bulk composition of organic matter, especially the molecular composition of soluble organic matter and the fluorescence colour of organic particles, are changed. Estimates of weathering rates reveal that the annual release of sulphur and organic carbon from black shales may significantly add to anthropogenic pollution.

Generation of nitrogen and methane from sedimentary organic matter: implications on the dynamics of natural gas accumulations

Nitrogen (N2) contents of natural gases in Rotliegend and Buntsandstein reservoirs of the North German basin regionally approach 100%. A review is given of the various hypotheses (primordial origin, volcanic or magmatic origin, radiogenic origin, atmospheric origin, organic origin, inorganic nitrogen in sedimentary rocks) presented to account for nitrogen anomalies in this area and other parts of the world. The objective of the present study was to investigate sedimentary organic matter, in particular coals, as a potential source of molecular nitrogen in the subsurface. Comparison of reservoir sizes and gas generation potentials indicates that Carboniferous coal measures, which are considered as the source of the natural gas in the North German basin, can readily account for the nitrogen quantities found in present-day reservoirs. Laboratory pyrolysis experiments were carried out to investigate the kinetics of generation of methane and molecular nitrogen from coals of different type and rank. Under experimental conditions nitrogen is formed at higher temperatures than methane supporting the concept of a ‘fractional generation’ of methane and nitrogen in natural systems. Based on the kinetic parameters derived from laboratory experiments methane and nitrogen generation rates from coals were calculated for geologic heating rates. Gas containing more than 50% nitrogen is generated under these conditions at temperatures in excess of 300°C. Nitrogen-rich gases are thus formed only in the final stage of gas generation after methane generation has practically ceased. It is concluded that the amounts of gas encountered in nitrogen-rich gas accumulations represent only a small fraction (possibly < 1 %) of the total gas generation potential of this area while the bulk of the generated gas has escaped to the atmosphere. The present-day composition of the reservoir gases reflects the composition of only the most recently generated gas (on a geologic time scale).

Experimental investigation on the carbon isotope fractionation of methane during gas migration by diffusion through sedimentary rocks at elevated temperature and pressure

Molecular transport (diffusion) of methane in water-saturated sedimentary rocks results in carbon isotope fractionation. In order to quantify the diffusive isotope fractionation effect and its dependence on total organic carbon (TOC) content, experimental measurements have been performed on three natural shale samples with TOC values ranging from 0.3 to 5.74%. The experiments were conducted at 90°C and fluid pressures of 9 MPa (90 bar). Based on the instantaneous and cumulative composition of the diffused methane, effective diffusion coefficients of the 12CH4 and 13CH4 species, respectively, have been calculated. Compared with the carbon isotopic composition of the source methane (δ13C1 = −39.1‰), a significant depletion of the heavier carbon isotope (13C) in the diffused methane was observed for all three shales. The degree of depletion is highest during the initial non-steady state of the diffusion process. It then gradually decreases and reaches a constant difference (Δ δ = δ13Cdiff −δ13Csource) when approaching the steady-state. The degree of the isotopic fractionation of methane due to molecular diffusion increases with the TOC content of the shales. The carbon isotope fractionation of methane during molecular migration results practically exclusively from differences in molecular mobility (effective diffusion coefficients) of the 12CH4 and 13CH4 entities. No measurable solubility fractionation was observed. The experimental isotope-specific diffusion data were used in two hypothetical scenarios to illustrate the extent of isotopic fractionation to be expected as a result of molecular transport in geological systems with shales of different TOC contents. The first scenario considers the progression of a diffusion front from a constant source (gas reservoir) into a homogeneous “semi-infinite” shale caprock over a period of 10 Ma. In the second example, gas diffusion across a 100 m caprock sequence is analyzed in terms of absolute quantities and isotope fractionation effects. The examples demonstrate that methane losses by molecular diffusion are small in comparison with the contents of commercial size gas accumulations. The degree of isotopic fractionation is related inversely to the quantity of diffused gas so that strong fractionation effects are only observed for relatively small portions of gas. The experimental data can be readily used in numerical basin analysis to examine the effects of diffusion-related isotopic fractionation on the composition of natural gas reservoirs.

Modelling isotope fractionation during primary cracking of natural gas: a reaction kinetic approach

Abstract A numerical model has been developed to compute stable carbon isotope variations in natural gas (methane) by calculating 13 CH 4 and 12 CH 4 generation as a set of parallel first-order reactions of primary cracking. The goal of this work was to combine the description of isotope fractionation with established kinetic models for gas generation. Stable carbon isotope ratios of methane from sedimentary organic matter are characterized by the initial carbon isotope ratio of methane precursors within the organic matter and by a constant difference in activation energy between 12 C - and 13 C-methane generation from corresponding precursor sites. Methane generation is calculated separately for 12 C - and 13 C-methane . A difference in activation energy automatically implies a temperature dependence of fractionation processes which has not been taken into consideration in previous works. This new model offers a theoretical explanation and mathematical description of the observed variability of δ 13 C -values of methane during open-system pyrolysis experiments. Carbon isotopes of methane within natural gas of thermogenic origin can be simulated for any geological temperature history. The application of the method to two coaly rock samples of the Pokur formation from northern West Siberia results in simulated carbon isotope values of methane which are very similar to those in the natural gas within the reservoirs of the Pokur formation (δ 13 C 1 =−42‰ to −54‰). This finding supports a thermogenic origin of the gas at an early stage of maturation.

Kinetics of Petroleum Formation and Cracking

One of the most fundamental problems in basin modeling as related to petroleum exploration is assessing the temporal and spatial limits of petroleum generation in sedimentary basins. It is well known that petroleum is generated from macromolecular sedimentary organic matter as it thermally degrades upon burial. The multitude of chemical reactions involved are unknown in detail (Philippi 1965; Welte 1965) but are recognized to be quasi-irreversible Suck and Karweil 1955; Hanbaba and Juntgen 1969; Tissot 1969). The organic components of subsiding sedimentary rocks are generally far away from thermodynamic equilibrium (Dayhoff et al. 1967; Tackach et al.1987). Consequently, the formation of oil and gas in nature is controlled by chemical reaction kinetics, in particular by non-isothermal kinetics because temperature changes as a function of time under geological conditions (Tissot and Espitalie 1975).

Geochromatography in petroleum migration: a review

Abstract Numerous works have been published during recent years discussing the occurrence and effects of chromatographic processes with respect to petroleum migration. ‘Geochromatography’ has been, and still remains, a controversial topic. Based on the principles and conventions of separation science a definition of geochromatography is proposed, followed by a discussion of the relevance and potential occurrence of chromatographic type fractionation effects during primary and secondary petroleum migration. The evaluation of the relevant literature suggests that chromatographic processes in natural systems involving liquid mobile phase can result only in compound class fractionation (saturates, aromatics, polars) whereas molecular fractionation may be expected to occur with gaseous mobile phases. Problems associated with the recognition, experimental verification and quantification of geochromatography are discussed in detail.

Petroleum Migration: Mechanisms, Pathways, Efficiencies and Numerical Simulations

Movement of petroleum from the source via carrier bed to the reservoir rocks is called migration. This is divided into primary migration, defined as the movement of oil and gas through and out of the fine-grained source rocks, and secondary migration, the movement through wider pores in carrier and reservoir rocks to the trap. (Not discussed here are the aspects of petroleum entrapment, redistribution in traps and petroleum loss from traps — generally called “dismigration” — or the various types of traps.) In addition to petroleum generation, petroleum migration is the principal process in the formation of explorable petroleum accumulations (which, however, represent only a special case of petroleum migration in which an otherwise diffuse fluid flow field is highly focussed towards a reservoir structure).