Injecting CO(2) into deep geological strata is proposed as a safe and economically favourable means of storing CO(2) captured from industrial point sources. It is difficult, however, to assess the long-term consequences of CO(2) flooding in the subsurface from decadal observations of existing disposal sites. Both the site design and long-term safety modelling critically depend on how and where CO(2) will be stored in the site over its lifetime. Within a geological storage site, the injected CO(2) can dissolve in solution or precipitate as carbonate minerals. Here we identify and quantify the principal mechanism of CO(2) fluid phase removal in nine natural gas fields in North America, China and Europe, using noble gas and carbon isotope tracers. The natural gas fields investigated in our study are dominated by a CO(2) phase and provide a natural analogue for assessing the geological storage of anthropogenic CO(2) over millennial timescales. We find that in seven gas fields with siliciclastic or carbonate-dominated reservoir lithologies, dissolution in formation water at a pH of 5-5.8 is the sole major sink for CO(2). In two fields with siliciclastic reservoir lithologies, some CO(2) loss through precipitation as carbonate minerals cannot be ruled out, but can account for a maximum of 18 per cent of the loss of emplaced CO(2). In view of our findings that geological mineral fixation is a minor CO(2) trapping mechanism in natural gas fields, we suggest that long-term anthropogenic CO(2) storage models in similar geological systems should focus on the potential mobility of CO(2) dissolved in water.

Identification of the source of CO 2 in natural reservoirs and development of physical models to account for the migration and interaction of this CO 2 with the groundwater is essential for developing a quantitative understanding of the long term storage potential of CO 2 in the subsurface. We present the results of 57 noble gas determinations in CO 2 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 CO 2 / 3 He 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: CO 2 can be stored within the subsurface on a millennia timescale.The manner and extent of contact of the CO 2 phase with the groundwater system is a critical parameter in using these systems as natural analogues for geological storage of anthropogenic CO 2 . We show that coherent fractionation of groundwater 20 Ne/ 36 Ar with crustal radiogenic noble gases ( 4 He, 21 Ne, 40 Ar) is explained by a two stage re-dissolution model: Stage 1: Magmatic CO 2 injection into the groundwater system strips dissolved air-derived noble gases (ASW) and accumulated crustal/radiogenic noble gas by CO 2 /water phase partitioning. The CO 2 containing the groundwater stripped gases provides the first reservoir fluid charge. Subsequent charges of CO 2 provide no more ASW or crustal noble gases, and serve only to dilute the original ASW and crustal noble gas rich CO 2 . Reservoir scale preservation of concentration gradients in ASW-derived noble gases thus provide CO 2 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 cm 3 groundwater/cm 3 gas (STP) in one Bravo Dome sample, to 2.56 cm 3 groundwater/cm 3 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 cm 3 water/cm 3 gas (at reservoir pressure and temperature).

No abstract

No abstract

Three petroleum extraction technologies offer potential for large‐scale, low‐cost, and long‐term sequestration of carbon dioxide. Enhanced oil recovery (EOR) using CO2 injection is a commercially proven process with more than 120 Gt of “value added” CO2 sequestration potential worldwide. Enhanced gas recovery (EGR) using CO2 injection is conceptually feasible but has not yet undergone testing. Depleted natural gas fields offer more than 750 Gt of moderate‐cost CO2 sequestration potential, not including EGR. Enhanced coal‐bed methane (ECBM) recovery using CO2 injection is undergoing pilot testing in the United States, with favorable early results. ECBM could be used to sequester more than 150 Gt of CO2 in coal basins worldwide. Challenges facing large‐scale application of geologic sequestration in hydrocarbon fields include: (1) high capture and processing costs of anthropogenic CO2; (2) inadequate understanding of many petroleum and coal reservoirs, particularly in frontier areas; (3) rigorous monitoring and verification to convince regulators and the public at large that sequestration is secure and long term; (4) achieving recognition and certification from emissions trading systems; and (5) resolving operational conflicts between sequestration and enhanced recovery. These challenges could be overcome by building on existing technologies from the EOR, underground gas storage, and natural CO2 production and transportation industries and by targeted basic and applied R&D.