F. van Bergen

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.

CO2 enhanced coalbed methane production in the Netherlands

The technical and economical feasibility of CO2 sequestration in deep coal layers combined with enhanced coalbed methane (ECBM) production in the Netherlands has been explored. Annually, 3.4 Mtonne CO2 from chemical installations can be delivered to sequestration locations at 15 €/tonne and another 55 Mtonne from power generating facilities at 40–80 €/tonne. Four potential ECBM areas have been assessed, of which Zuid Limburg is the best location for a test site, while the Achterhoek is more suitable for future large-scale CO2 sequestration. Between 54 Mtonne and 9 Gtonne CO2 can be sequestered in the four areas together, heavily depending on available technology for accessing the coal seams. At the same time, between 0.3 and 60 EJ of coalbed methane can be produced. The optimal configuration may have 1000 m spacing between production wells, and extreme inseam drilling. The price of coalbed methane may become competitive with natural gas when a bonus for CO2 sequestration is applied of about 25 €/tonne. For the long term, on-site hydrogen or power (SOFC) production with direct injection of produced CO2 seems most attractive. Further study is required, most notably more accurate geological surveys, assessment of drilling costs in Dutch context, and environmental impacts of ECBM.

Modelling the hydrocarbon generation and migration in the West Netherlands Basin, the Netherlands

The hydrocarbon systems of the Mesozoic, inverted West Netherlands Basin have been analyzed using 2-D forward modelling. Three source rocks are considered in the modelling: Lower Jurassic oil-prone shales, Westphalian gas-prone coal deposits, and Lower Namurian oil-prone shales. The Lower Namurian hydrocarbon system of the basin is discussed for the first time. According to the modelling results of the Early Jurassic oil system, the oil accumulations were filled just after the main inversion event. Their predicted locations are in agreement with exploration results. Modelling results of the Westphalian gas system, however, show smaller and larger sized accumulations at unexplored locations. The gas reservoirs were filled during the Late Jurassic-Early Cretaceous rifting phase. Results of modelling of the Lower Namurian oil system indicate that gas formed by secondary cracking of the oils can have mixed with the Westphalian coal-derived gas. Such a mixing is inferred from geochemical analyses. The existence of a Lower Namurian hydrocarbon system in the West Netherlands Basin implies that hydrocarbons are possibly trapped in the Westphalian and Namurian successions. These potential traps in the basin have not yet been explored.

High-pressure adsorption of methane, carbon dioxideand their mixtures on coals with a special focus on the preferential sorption behaviour

Abstract During recent years, extensive studies have been undertaken at RWTH Aachen to assess the gas adsorption capacities of coals of different rank with respect to CH 4 , CO 2 and their mixtures [e.g. Int. J. Coal Geol. 51 (2002) 69; Proceedings JCOAL Workshop: Present Status and Perspective of CO 2 Sequestration in Coal Seams, Tokyo, Japan, (5 September 2002) 23–38]. Excess sorption isotherms of carbon dioxide recorded at 40, 60 and 80 °C on dry and moisture-equilibrated Carboniferouscoals from the Netherlands exhibited distinct minima and even negative values in the 8–12 MPa interval. These anomalies are indicative of a strong volumetric effect. Evaluation of the experimental results in terms of absolute sorption assuming a range of different densities for the adsorbed phase could not eliminate the observed anomalies. In consequence, substantial swelling (up to 20%) of the (powdered) coal samples must be invoked to account for the observed phenomena. This interpretation is supported by the results of field tests in Alberta, Canada [Proceedings JCOAL Workshop: Present Status and Perspective of CO 2 Sequestration in Coal Seams, Tokyo, Japan, (5 September 2002) 59–66], which resulted in a significant reduction in coal-seam permeability upon CO 2 injection. The latest research focuses on the preferential sorption behaviour of CO 2 and CH 4 of coals from the Silesian coal basin. Experiments are conducted at pressures up to 250 bar (25 MPa) at a temperature of 45 °C using the volumetric method. These measurements provide fundamental information for enhanced coalbed methane recovery (ECBM) and storage of CO 2 in deep unminable coal seams proposed as a potential means of the reduction of anthropogenic CO 2 emissions (RECOPOL-project: //www.nitg.tno.nl/recopo/ ). Preferential adsorption experiments on dry and moisture-equilibrated coals of different rank under identical conditionsshowed that adsorption is a function of coal type, moisture content and pressure. While at pressures above 50 bar, CO 2 was always adsorbed preferentially to methane, preferential sorption of methane was observed in some instances at lower pressures. The unexpected phenomenon of preferential CH 4 adsorption on natural coals is presently an issue for further investigation. In the context of a round robin project initiated by the US Department of Energy, CO 2 excess sorption isotherms have beendetermined on five US premium coals at 22 °C in the dry state. Diversities of the excess sorption behaviour of these coals under different rank can be observed. Generally, excess sorption isotherms of lignite and subbituminous coals (0.25–0.46% VRr) exhibited a monotonous increase over the entire experimental pressure range (up to ∼ 50 bar), while higher mature coals tended to approach a saturation level corresponding to a Langmuir isotherm.

Worldwide Selection of Early Opportunities for CO2-EOR and CO2-ECBM (1)

One of the technologies that have the potential to make deep reductions in CO 2 emissions is geological storage of CO 2 . Deep reductions in CO 2 emissions will most probably be needed to achieve stabilization of atmospheric greenhouse gas concentrations. There are several options for geological storage that can be divided into two groups: storage without energy benefits (for example, in aquifers or in depleted gas and oil reservoirs) and with energy benefits. The latter group can be cost effective, even without CO 2 credits or taxes, because of revenues from oil or gas production. It is, therefore, likely that these options give an added value to each ton of CO 2 prevented from emission to the atmosphere, and have the potential to be the first projects to be implemented in the near future. As a matter a fact, due to its cost effectiveness, enhanced oil recovery with CO 2 (CO 2 -EOR) is already applied by the oil and gas industry, mostly in the United States and Canada. These low costs opportunities combine high purity (100%) CO 2 gas streams, which lower capture costs, with short transmission distance and potentially profitable CO 2 enhanced fossil fuel recovery schemes such as CO 2 -EOR and CO 2 -ECBM. Such low cost opportunities should provide options for early implementation of CO 2 capture and storage projects worldwide. The study has used a Geographical Information System to link high purity CO 2 point sources to oil and gas reservoirs within 100 km of the point source.

Development of a Field Experiment of CO2 Storage in Coal Seams in the Upper Silesian Basin of Poland (Recopol)

Publisher Summary One option to reduce carbon dioxide emissions and thus control the overall levels of CO2 in the atmosphere, which has become an international priority in the wake of the Kyoto protocol, is permanent storage in subsurface coal seams, while producing methane simultaneously. The EU-funded RECOPOL project, which started in November 2001, aims at the development of the first European demonstration plant of CO2 storage in coal seams. An international consortium was formed to execute the research, design, construction, and operation within the RECOPOL project. This consortium is formed by research institutes, universities, and companies from the Netherlands, Poland, Germany, France, Australia, the United States, and by the IEA Greenhouse Gas R&D Program. Overall co-ordination of the project is in the hands of TNO-NITG. The required research, design, and operation of the pilot field test are executed by an international consortium of research institutes, universities, and industrial partners. A site was selected in the Silesian Basin in Poland where two CBM-wells are located a short distance from each other. Injection was planned to start in the Summer of 2003. Reservoir modeling shows that the distance between the injection well and the updip production well should be less than 200 m to increase the chance of breakthrough of CO2 within the test period. Breakthrough is important for a thorough understanding of the process. After and during the injection period, monitoring will be performed by direct measurements of CO2-concentration and by time lapse seismic monitoring.

Geodynamic and hydrodynamic evolution of the Broad Fourteens Basin and the development of its petroleum systems: an integrated 2D basin modelling approach.

Abstract Results of integrated 2D basin modelling indicate that both sedimentary loading and gas generation play an important role in the overpressure history of the Broad Fourteens Basin. We analysed the influence of time-dependent permeability of faults on the overpressure history and evolution of petroleum systems. We favour time-dependent permeability of faults as the most likely option to explain the present-day near-hydrostatic conditions in the basin, the known location of oil fields, and the location and characteristics of the gas occurrences. The model results further show that the difference in timing of oil charging of the P9 and Q1 Lower Cretaceous oil reservoirs, explains the observed differences in geochemical composition of the accumulated oils. The biodegraded and water-washed nature of the pre-inversion charged Q1 oil reservoir is consistent with the concentrated topography-induced groundwater flow through the Lower Cretaceous reservoir units during the Late Cretaceous inversion period. Late charging of the oil reservoir in the P9 area explains the non-biodegraded character of the accumulated oils. Present-day conditions in the Broad Fourteens Basin are near-hydrostatic. In general, this paper shows that paleohydrodynamic conditions and time-dependent permeability of the hydrogeological framework have influenced significantly the petroleum systems in the basin.

Reactive Transport Modeling of CO2 Injection into P18

Non-isothermal reactive transport modelling is carried out using TOUGHREACT for simulating the near-well behaviour of CO2 injection into compartment two of the P18 gas field. A representative model was built that contains three geological deposits with va

Interplay of Late Carboniferous Foreland Basin Formation and Early Carboniferous Stretching in NW Europe

C040 Interplay of Late Carboniferous Foreland Basin Formation and Early Carboniferous Stretching in NW Europe H. Kombrink* (TNO) K. Leever (Vrije Universiteit Amsterdam) J.D. van Wees (TNO) F. van Bergen (TNO) P. David (TNO) & T.E. Wong (TNO) SUMMARY Late Carboniferous subsidence in the Netherlands is likely to be caused by flexural foreland subsidence and a thermal sag component following an Early Carboniferous rifting event. A modelling study shows that flexural subsidence is limited to the eastern part of the Netherlands. To get insight into the amount of subsidence that can be explained by an Early Carboniferous rifting event we

Pre-screening tectonic heat flows for basin modelling - Some implications for deep water exploration in the mediterranean

Basin modelling results can be very sensitive to (paleo-)temperature uncertainties. For frontier basins, in particular for deep water settings, the thermal signature of the basin is poorly constrained, as data from wells are lacking. This may lead to wrong heat flow assumptions if these are extrapolated from the shallow offshore or onshore. Furthermore large uncertainties can exist when dealing with constructing paleo-heat flow. The potential errors in spatial and temporal extrapolations are especially large in settings with strong spatial and temporal variations in tectonic regime. This is in particular true for the Mediterranean and North Africa. Heat flow modeling can be improved considerably through numerically modeling lithospheric processes underlying basin deformation. For this purpose we have developed a probabilistic tool which is capable of calculating tectonic heat flows calibrated to observed data and which can be used as input for maturation modelling. For various basin settings we will show the effect of adopting tectonic heat flows for improving spatial and temporal constraints on the temperature and maturation history in deep water exploration settings. Case studies include the Morrocan Atlantic margin and the Valencia Through (Spain).