Equipping for risk: Lessons learnt from the UK shale-gas experience on assessing environmental risks for the future geoenergy use of the deep subsurface

\ua9 2024 The Authors. Summary findings are presented from an investigation to improve understanding of the environmental risks associated with developing an unconventional-hydrocarbons industry in the UK. The EQUIPT4RISK project, funded by UK Research Councils, focused on investigations around Preston New Road (PNR), Fylde, Lancashire, and Kirby Misperton Site A (KMA), North Yorkshire, where operator licences to explore for shale gas by hydraulic fracturing (HF) were issued in 2016, although exploration only took place at PNR. EQUIPT4RISK considered atmospheric (greenhouse gases, air quality), water (groundwater quality) and solid-earth (seismicity) compartments to characterise and model local conditions and environmental responses to HF activities. Risk assessment was based on the source-pathway-receptor approach. Baseline monitoring of air around the two sites characterised the variability with meteorological conditions, and isotopic signatures were able to discriminate biogenic methane (cattle) from thermogenic (natural-gas) sources. Monitoring of a post-HF nitrogen-lift (well-cleaning) operation at PNR detected the release of atmospheric emissions of methane (4.2 \ub1 1.4 t CH4). Groundwater monitoring around KMA identified high baseline methane concentrations and detected ethane and propane at some locations. Dissolved methane was inferred from stable-isotopic evidence as overwhelmingly of biogenic origin. Groundwater-quality monitoring around PNR found no evidence of HF-induced impacts. Two approaches for modelling induced seismicity and associated seismic risk were developed using observations of seismicity and operational parameters from PNR in 2018 and 2019. Novel methodologies developed for monitoring include use of machine learning to identify fugitive atmospheric methane, Bayesian statistics to assess changes to groundwater quality, a seismicity forecasting model seeded by the HF-fluid injection rate and high-resolution monitoring of soil-gas methane. The project developed a risk-assessment framework, aligned with ISO 31000 risk-management principles, to assess the theoretical combined and cumulative environmental risks from operations over time. This demonstrated the spatial and temporal evolution of risk profiles: seismic and atmospheric impacts from the shale-gas operations are modelled to be localised and short-lived, while risk to groundwater quality is longer-term

420,000 year assessment of fault leakage rates shows geological carbon storage is secure

Carbon capture and storage (CCS) technology is routinely cited as a cost effective tool for climate change mitigation. CCS can directly reduce industrial CO2 emissions and is essential for the retention of CO2 extracted from the atmosphere. To be effective as a climate change mitigation tool, CO2 must be securely retained for 10,000 years (10 ka) with a leakage rate of below 0.01% per year of the total amount of CO2 injected. Migration of CO2 back to the atmosphere via leakage through geological faults is a potential high impact risk to CO2 storage integrity. Here, we calculate for the first time natural leakage rates from a 420 ka paleo-record of CO2 leakage above a naturally occurring, faulted, CO2 reservoir in Arizona, USA. Surface travertine (CaCO3) deposits provide evidence of vertical CO2 leakage linked to known faults. U-Th dating of travertine deposits shows leakage varies along a single fault and that individual seeps have lifespans of up to 200 ka. Whilst the total volumes of CO2 required to form the travertine deposits are high, time-averaged leakage equates to a linear rate of less than 0.01%/yr. Hence, even this natural geological storage site, which would be deemed to be of too high risk to be selected for engineered geologic storage, is adequate to store CO2 for climate mitigation purposes

Preferential Paths of Air-water Two-phase Flow in Porous Structures with Special Consideration of Channel Thickness Effects.

Accurate understanding and predicting the flow paths of immiscible two-phase flow in rocky porous structures are of critical importance for the evaluation of oil or gas recovery and prediction of rock slides caused by gas-liquid flow. A 2D phase field model was established for compressible air-water two-phase flow in heterogenous porous structures. The dynamic characteristics of air-water two-phase interface and preferential paths in porous structures were simulated. The factors affecting the path selection of two-phase flow in porous structures were analyzed. Transparent physical models of complex porous structures were prepared using 3D printing technology. Tracer dye was used to visually observe the flow characteristics and path selection in air-water two-phase displacement experiments. The experimental observations agree with the numerical results used to validate the accuracy of phase field model. The effects of channel thickness on the air-water two-phase flow behavior and paths in porous structures were also analyzed. The results indicate that thick channels can induce secondary air flow paths due to the increase in flow resistance; consequently, the flow distribution is different from that in narrow channels. This study provides a new reference for quantitatively analyzing multi-phase flow and predicting the preferential paths of immiscible fluids in porous structures

Dissolved noble gases and stable isotopes as tracers of preferential fluid flow along faults in the Lower Rhine Embayment, Germany

Groundwater in shallow unconsolidated sedimentary aquifers close to the Bornheim fault in the Lower Rhine Embayment (LRE), Germany, has relatively low δ2H and δ18O values in comparison to regional modern groundwater recharge, and 4He concentrations up to 1.7 × 10−4 cm3 (STP) g–1 ± 2.2 % which is approximately four orders of magnitude higher than expected due to solubility equilibrium with the atmosphere. Groundwater age dating based on estimated in situ production and terrigenic flux of helium provides a groundwater residence time of ∼107 years. Although fluid exchange between the deep basal aquifer system and the upper aquifer layers is generally impeded by confining clay layers and lignite, this study’s geochemical data suggest, for the first time, that deep circulating fluids penetrate shallow aquifers in the locality of fault zones, implying  that sub-vertical fluid flow occurs along faults in the LRE. However, large hydraulic-head gradients observed across many faults suggest that they act as barriers to lateral groundwater flow. Therefore, the geochemical data reported here also substantiate a conduit-barrier model of fault-zone hydrogeology in unconsolidated sedimentary deposits, as well as corroborating the concept that faults in unconsolidated aquifer systems can act as loci for hydraulic connectivity between deep and shallow aquifers. The implications of fluid flow along faults in sedimentary basins worldwide are far reaching and of particular concern for carbon capture and storage (CCS) programmes, impacts of deep shale gas recovery for shallow groundwater aquifers, and nuclear waste storage sites where fault zones could act as potential leakage pathways for hazardous fluids

Estimating geological CO2 storage security to deliver on climate mitigation

Carbon capture and storage (CCS) can help nations meet their Paris CO2 reduction commitments cost-effectively. However, lack of confidence in geologic CO2 storage security remains a barrier to CCS implementation. Here we present a numerical program that calculates CO2 storage security and leakage to the atmosphere over 10,000 years. This combines quantitative estimates of geological subsurface CO2 retention, and of surface CO2 leakage. We calculate that realistically well-regulated storage in regions with moderate well densities has a 50% probability that leakage remains below 0.0008% per year, with over 98% of the injected CO2 retained in the subsurface over 10,000 years. An unrealistic scenario, where CO2 storage is inadequately regulated, estimates that more than 78% will be retained over 10,000 years. Our modelling results suggest that geological storage of CO2 can be a secure climate change mitigation option, but we note that long-term behaviour of CO2 in the subsurface remains a key uncertainty

Solubility trapping in formation water as dominant CO2 sink in natural gas fields

Injecting CO2 into deep geological strata is proposed as a safe and economically favourable means of storing CO2 captured from industrial point sources1, 2, 3. It is difficult, however, to assess the long-term consequences of CO2 flooding in the subsurface from decadal observations of existing disposal sites1, 2. Both the site design and long-term safety modelling critically depend on how and where CO2 will be stored in the site over its lifetime2, 3, 4. Within a geological storage site, the injected CO2 can dissolve in solution or precipitate as carbonate minerals. Here we identify and quantify the principal mechanism of CO2 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 CO2 phase and provide a natural analogue for assessing the geological storage of anthropogenic CO2 over millennial timescales1, 2, 5, 6. 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 CO2. In two fields with siliciclastic reservoir lithologies, some CO2 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 CO2. In view of our findings that geological mineral fixation is a minor CO2 trapping mechanism in natural gas fields, we suggest that long-term anthropogenic CO2 storage models in similar geological systems should focus on the potential mobility of CO2 dissolved in wate