Stuart Gilfillan

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 sources. It is difficult, however, to assess the long-term consequences of CO2 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 CO2 will be stored in the site over its lifetime. 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 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 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 water.

Enhanced fracture permeability and accompanying fluid flow in the footwall of a normal fault: The Hurricane fault at Pah Tempe hot springs, Washington County, Utah

The Pah Tempe hot springs discharge ~260 L/s of water at ~40 °C into the Virgin River in the footwall damage zone of the Hurricane fault at Timpoweap Canyon, near Hurricane, Utah, USA. Although these are Na-Cl waters, they actively discharge CO2 gas and contain signifi cant quantities of CO2 (~34.6 mmol/kg), predominantly as H2CO3 and HCO3 –. Because of excellent exposures, Pah Tempe provides an exceptional opportunity to observe the effects of enhanced fracture permeability in an active extensional fault. Pah Tempe waters have been deeply circulated (>5 km; >150 °C) into basement rock as illustrated by the clear water-rock exchange of oxygen isotopes. Waters were probably recharged under colder climate conditions than present and therefore have a prolonged subsurface residence. Discharge of both water and gas in the springs correlates to the density of fractures in carbonate rocks above stream level. This observation suggests that clusters of high fracture density in the faultdamage zone act as pathways from the likely regional aquifer, the eolian Queantoweap Sandstone, through the overlying confining unit, the gypsiferous silty Seligman Member of the Kaibab Formation. Mass-balance modeling suggests that the majority of CO2 discharge is the product of the quantitative dissolution of CO2 gas at depth within the fault zone. Upon discharge, most of the carbon is released to the surface as dissolved species. It appears that the subsurface production rate of CO2 is relatively low because Pah Tempe waters are grossly undersaturated in CO2 at inferred minimum circulation depths and temperatures. Geological and geochemical data also suggest that the CO2 is dominated by a crustal component complemented by minor mantle contributions.

Application of Noble Gases to the Viability of CO2 Storage

Unequivocable evidence for warming of the climate system is a reality. An important factor for reducing this warming is mitigation of anthropogenic CO2 in the atmosphere. This requires us to engineer technologies for capture of our carbon emissions and identify reservoirs for storing these captured emissions. This chapter reviews advances made in understanding multiphase interactions and processes operating in a variety of subsurface reservoirs using noble gases. We begin by discussing the types of reservoir available for carbon storage and the mechanisms of viable CO2 storage, before summarising the physical chemistry involved in data interpretation and the sampling/sample storage techniques and requirements critical to successful sample collection. Theory of noble gas partitioning is interspersed with examples from a variety reservoirs to aid our knowledge of long term CO2 storage in the subsurface. These include hydrocarbon reservoir and natural CO2 reservoirs. In these examples we show how good progress has been made in using noble gases to explain the fate of CO2 in the subsurface, to quantify the extent of groundwater interaction and to understand CO2 behaviour after injection into oil fields for enhanced oil recovery. We also present recent work using noble gases for monitoring of subsurface CO2 migration and leakage in CO2 rich soils, CO2 rich springs and groundwaters. Noble gases are chemically inert, persistent and environmentally safe and they have the potential to be extremely useful in tracing migration of CO2. It is imperative that the many upcoming pilot CO2 injection studies continue to investigate the behaviour of noble gases in the subsurface and develop suitable noble gas monitoring strategies.

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.Carbon capture and storage can help reduce CO2 emissions but the confidence in geologic CO2 storage security is uncertain. Here the authors present a numerical programme to estimate leakage from wells and find that under appropriate regulation 98% of injected CO2 will be retained over 10,000 years.

Wastewater from hydraulic fracturing in the UK: assessing the viability and cost of management

The safe and effective management of wastewaters from unconventional hydrocarbon production using the hydraulic fracturing (fracking) process poses a major challenge. Exploitation of unconventional hydrocarbons, such as shale gas, remains controversial in the UK primarily due to concerns surrounding the hydraulic fracturing process required to extract the resource. The key issue of how waste fluids produced by hydraulic fracturing in the UK will be safely managed has yet to be adequately addressed, and the capacity for the specialist treatment required is currently uncertain. To address this critical knowledge gap we review, for the first time, the available management options for these waste fluids in the UK. We find that these are limited in comparison to the options available in the U.S., due to uncertainty surrounding whether wastewater injection wells will be permitted in the UK. Consequently, it is highly probable that these fluids will need to be treated and safely disposed of at the surface. In order to constrain the composition of wastewater which will require treatment in the UK, we analyse the only existing data set of returned waters from hydraulic fracturing (n = 31). We supplement this with measurements of wastewater from UK conventional onshore hydrocarbon (n = 3), and offshore hydrocarbon (n = 14), operations which produce water from similar formations as those currently targeted for shale gas exploration. Comparison of this limited UK data to the more extensive unconventional production dataset from the United States (n = 3092) provides confidence in our projected UK wastewater compositions. We find that the high level of salinity and concentration of naturally occurring radioactive material (NORM) in UK wastewaters will be problematic to treat for disposal into a freshwater environment. We use our data compilation to estimate costs of treating such wastewaters in a number of relevant scenarios. We find that the projected salinity in FP waters from UK hydraulic fracturing operations can be treated at a cost of between

Last chance for carbon capture and storage

2701 (∼£2000) and

He and Ne as tracers of natural CO2 migration up a fault from a deep reservoir

1 376 093 (∼£1 047 000) per well, requiring between 2 and 26% of expected revenue. Additional costs, specific to the UK of up to £163 450 per well, will be incurred due to the legislative requirement for disposal of NORM concentrated sludge in permitted landfill sites. We find that existing capacity to receive NORM waste at currently permitted UK treatment facilities is limited, and that this will pose management problems if wastewaters are generated from multiple unconventional wells simultaneously.