Carbon capture and storage (CCS) is a key technology to mitigate the environmental impact of carbon dioxide (CO2) emissions. An understanding of the potential trapping and storage mechanisms is required to provide confidence in safe and secure CO2 geological sequestration1,2. Depleted hydrocarbon reservoirs have substantial CO2 storage potential1,3, and numerous hydrocarbon reservoirs have undergone CO2 injection as a means of enhanced oil recovery (CO2-EOR), providing an opportunity to evaluate the (bio)geochemical behaviour of injected carbon. Here we present noble gas, stable isotope, clumped isotope and gene-sequencing analyses from a CO2-EOR project in the Olla Field (Louisiana, USA). We show that microbial methanogenesis converted as much as 13–19% of the injected CO2 to methane (CH4) and up to an additional 74% of CO2 was dissolved in the groundwater. We calculate an in situ microbial methanogenesis rate from within a natural system of 73–109 millimoles of CH4 per cubic metre (standard temperature and pressure) per year for the Olla Field. Similar geochemical trends in both injected and natural CO2 fields suggest that microbial methanogenesis may be an important subsurface sink of CO2 globally. For CO2 sequestration sites within the environmental window for microbial methanogenesis, conversion to CH4 should be considered in site selection.
The Paradox Basin in the Colorado Plateau (USA) has some of the most iconic records of paleofluid flow, including sandstone bleaching and ore mineralization, and hydrocarbon, CO2, and He reservoirs, yet the sources of fluids responsible for these extensive fluid-rock reactions are highly debated. This study, for the first time, characterizes fluids within the basin to constrain the sources and emergent behavior of paleofluid flow resulting in the iconic rock records. Major ion and isotopic (δ18Owater; δDwater; δ18OSO4; δ34SSO4; δ34SH2S; 87Sr/86Sr) signatures of formation waters were used to evaluate the distribution and sources of fluids and water-rock interactions by comparison with the rock record. There are two sources of salinity in basinal fluids: (1) diagenetically altered highly evaporated paleo-seawater-derived brines associated with the Pennsylvanian Paradox Formation evaporites; and (2) dissolution of evaporites by topographically driven meteoric circulation. Fresh to brackish groundwater in the shallow Cretaceous Burro Canyon Formation contains low Cu and high SO4 concentrations and shows oxidation of sulfides by meteoric water, while U concentrations are higher than within other formation waters. Deeper brines in the Pennsylvanian Honaker Trail Formation were derived from evaporated paleo-seawater mixed with meteoric water that oxidized sulfides and dissolved gypsum and have high 87Sr/86Sr indicating interaction with radiogenic siliciclastic minerals. Upward migration of reduced (hydrocarbon- and H2S-bearing) saline fluids from the Pennsylvanian Paradox Formation along faults likely bleached sandstones in shallower sediments and provided a reduced trap for later Cu and U deposition. The distribution of existing fluids in the Paradox Basin provides important constraints to understand the rock record over geological time.
Enhanced oil recovery (EOR) and hydraulic fracturing practices are commonly used methods to improve hydrocarbon extraction efficiency; however, the environmental effects of such practices remain poorly understood. EOR is particularly prevalent in oil fields throughout California where water resources are in high demand and the disposal of large volumes of produced water may affect groundwater quality. Consequently, it is essential to better understand the fate of injected (EOR) fluids in California, and other subsurface petroleum systems, as well as any potential effect on nearby aquifer 2 systems. Noble gases can be used as tracers to understand hydrocarbon generation, migration, and storage conditions, as well as the relative proportions of oil and water present in the subsurface. In addition, a noble gas signature diagnostic of injected (EOR) fluids can be readily identified. We report noble gas isotope and concentration data in casing gases from oil production wells in the Lost Hills oil field, northwest of Bakersfield, California, and injectate gas data from the Fruitvale oil field, located within the city of Bakersfield. Casing and injectate gas data are used to: 1) establish pristine hydrocarbon noble-gas signatures and the processes controlling noble gas distributions, 2) characterize the noble gas signature of injectate fluids, 3) trace injectate fluids in the subsurface, and 4) construct a model to estimate EOR efficiency. Noble gas results range from pristine to significantly modified by EOR, and can be best explained using a solubility exchange model between oil and connate/formation fluids, followed by gas exsolution upon production. This model is sensitive to oil-water interaction during hydrocarbon expulsion, migration, and storage at reservoir conditions, as well as any subsequent modification by EOR.
Krypton‐81 dating provides new insights into the timing, mechanisms, and extent of meteoric flushing versus retention of saline fluids in the subsurface in response to changes in geologic and/or climatic forcings over 50 ka to 1.2 Ma year timescales. Remnant Paleozoic seawater‐derived brines associated with evaporites in the Paradox Basin, Colorado Plateau, are beyond the 81Kr dating range (>1.2 Ma) and have likely been preserved due to negative fluid buoyancy and low permeability. 81Kr dating of formation waters above the evaporites indicates topographically‐driven meteoric recharge and salt dissolution since the Late Pleistocene (0.03–0.8 Ma). Formation waters below the evaporites (up to 3 km depth), in basal aquifers, contain relatively young meteoric water components (0.4–1.1 Ma based on 81Kr) that partially flushed remnant brines and dissolved evaporites. We demonstrate that recent, rapid denudation of the Colorado Plateau (<4–10 Ma) activated deep, basinal‐scale flow systems as recorded in 81Kr groundwater age distributions.
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