Note on the importance of hydrocarbon fill for reservoir quality prediction in sandstones

Oil emplacement retarded the rate of quartz cementation in the Brae Formation deep-water sandstone reservoirs of the Miller and Kingfisher fields (United Kingdom North Sea), thus preserving porosity despite the rocks' being buried to depths of 4 km and 120degreesC. Quartz precipitation rates were reduced by at least two orders of magnitude in the oil legs relative to the water legs. Important contrasts in quartz cement abundances and porosities have emerged between the oil and water legs where reservoirs have filled with hydrocarbons gradually over a prolonged period of time (greater than 15 m.y.). The earlier the hydrocarbon fill, the greater is the degree of porosity preservation. Failure to consider this phenomenon during field development could lead to overestimation of porosity and permeability in the water leg, potentially leading in turn to poor decisions about the need for and placement of downflank water injectors. During exploration, the retarding effect of oil on quartz cementation could lead to the presence of viable reservoirs situated deeper than the perceived regional economic basement

Fault seal controls on security of CO2 storage in aquifers

Structural traps for engineered storage of CO2 usually rely on a component of fault seal. In assessing the performance risk of storage sites, the conditions under which natural CO2 and CO2/hydrocarbon mixtures are retained by faults is poorly known. Mechanical failure can occur by flow along the fault plane due to extension, compression or shear. Geometric juxtaposition of aquifers or lack of low permeability fault gouge can enable flow across the fault plane. It is well established that faults which are close to being critically stressed have markedly different properties with respect to both their fluid flow and geomechanical characteristics. Here we examine three case studies. In the first two, the Rotliegend Sandstone reservoirs of the Oak and Fizzy Fields in the Southern North Sea, both of which are natural fault-bound gas fields with high CO2 content, we modify standard fault seal approaches to account for the different physical and chemical properties of CO2 to oil and CH4. In particular the impact of IFT and contact angle on threshold capillary pressure is investigated. Faults of both the Oak and Fizzy fields are analysed for fracture stability and slip tendency and are found to be stable (relative to present-day stresses) in all modelled scenarios and could withstand CO2 column heights in excess of trap height. However, under detailed assessment of fault seal potential for CO2-CH4 mixtures, both fields appear to be limited in column height by cross-fault leakage through carbonate layers of the overlying Zechstein Group. The third case study assessed the Captain Sandstone saline aquifer of the Inner Moray Firth. The in situ stress field was characterised using data available from hydrocarbon exploration wells. A range of potential stress fields were identified, and regional 3D geometric mapping of the major faults was then used to assess fault stability under the different potential stress regimes. Additionally, stereographic plots of fault dip angle and strike were used to deduce the pore pressure perturbation that could cause the mechanical reactivation of faults of any orientation. This accounted for unmapped faults that might truncate the storage reservoir and its overburden. In the stress scenario with the highest differential stress magnitudes low overpressures in the region of ~1.5 MPa could cause the reactivation of preferentially oriented faults, whereas higher induced pressures may be supported in lower differential stress regimes. Higher overpressure would also be required to cause the reactivation of the non-optimally oriented faults

Independent Expert Scientific Panel – Report on Unconventional Oil and Gas

No abstract available

Defining simple and comprehensive assessment units for CO2 storage in saline formations beneath the UK North Sea and continental shelf

In the UK, by far the largest CO2 storage opportunities lie offshore. The North Sea in particular has a long and complex geological history, with potential reservoirs geographically widespread and occurring at multiple stratigraphic levels. Diverse storage estimates have been made, using a range of working methods, and yielding different values, e.g. SCCS (2009); Bentham (2006). Consequently the UK Storage Appraisal Project (UKSAP), commissioned and funded by the Energy Technologies Institute (ETI), is undertaking the most comprehensive assessment to date, using abundant legacy seismic and borehole data. This study has a remit to use best current practice, consistent between locations, to calculate the CO2 storage capacity of the entire UK Continental Shelf (UKCS) within saline aquifers and hydrocarbon fields. The potential storage formations have been subdivided into units for assessment, and filtered to remove units with only a small estimated storage capacity to concentrate resources on more viable units. The size of potential storage units approximate to a power law distribution, similar to that of hydrocarbon fields, with a large number of small units and a small number of large units

Detection and Understanding of Natural CO2 Releases in KwaZulu-Natal, South Africa

Natural carbon dioxide (CO2) emanates from a number of sites along a N-S trend that coincides with a mapped fault near the village of Bongwana in KwaZulu-Natal, South Africa. In addition to the natural CO2 seeps a groundwater well drilled on a farm in Bongwana encountered CO2 and now leaks. Thus the Bongwana sites provide excellent analogues for failed CO2 storage under the two primary leakage scenarios; 1) abrupt leakage through injection well failure or leakage up an abandoned well, and 2) gradual leakage, through undetected faults, fractures or wells. Here we present results from preliminary fieldwork undertaken in September 2015

The Inherent Tracer Fingerprint of Captured CO2.

Carbon capture and storage (CCS) is the only currently available technology that can directly reduce anthropogenic CO2 emissions arising from fossil fuel combustion. Monitoring and verification of CO2 stored in geological reservoirs will be a regulatory requirement and so the development of reliable monitoring techniques is essential. The isotopic and trace gas composition - the inherent fingerprint - of captured CO2 streams is a potentially powerful, low cost geochemical technique for tracking the fate of injected gas in CCS projects; carbon and oxygen isotopes, in particular, have been used as geochemical tracers in a number of pilot CO2 storage sites, and noble gases are known to be powerful tracers of natural CO2 migration. However, the inherent tracer fingerprint in captured CO2 streams has yet to be robustly investigated and documented and key questions remain, including how consistent is the fingerprint, what controls it, and will it be retained en route to and within the storage reservoir? Here we present the first systematic measurements of the carbon and oxygen isotopes and the trace noble gas composition of anthropogenic CO2 captured from combustion power stations and fertiliser plants. The analysed CO2 is derived from coal, biomass and natural gas feedstocks, using amine capture, oxyfuel and gasification processes, from six different CO2 capture plants spanning four different countries. We find that δ13C values are primarily controlled by the δ13C of the feedstock while δ18O values are predominantly similar to atmospheric O2. Noble gases are of low concentration and exhibit relative element abundances different to expected reservoir baselines and air, with isotopic compositions that are similar to air or fractionated air. The use of inherent tracers for monitoring and verification was provisionally assessed by analysing CO2 samples produced from two field storage sites after CO2 injection. These experiments at Otway, Australia, and Aquistore, Canada, highlight the need for reliable baseline data. Noble gas data indicates noble gas stripping of the formation water and entrainment of Kr and Xe from an earlier injection experiment at Otway, and inheritance of a distinctive crustal radiogenic noble gas fingerprint at Aquistore. This fingerprint can be used to identify unplanned migration of the CO2 to the shallow subsurface or surface

Overview of the site selection, geological and engineering problems facing radioactive waste disposal at Sellafield, UK.

No abstract available

Hydrocarbon filling and leakage history of a deep geopressured sandstone, Fulmar Formation, United Kingdom North Sea

Diagenetic minerals in a water-filled borehole from the Jurassic Fulmar Formation, United Kingdom central North Sea, record two phases of hydrocarbon filling and emptying. Initial oil charge was during the Late Cretaceous, at shallow burial depths of about 1.5 km (0.9 mi). As we consider that hydrocarbon has preserved porosity during burial, this has implications for the understanding of the porosity evolution of the Fulmar Formation, which, in other locations, is an important hydrocarbon reservoir. The early oil charge, as recorded by illite K-Ar ages, progressively filled the structure from 84 to 59 Ma, and possibly precipitated bitumen because of biodegradation. The first oil predated many of the burial diagenetic reactions within the sandstone. After leak-off at ca. 60 Ma, diagenetic reactions continued in an open geochemical system, with possible import of CO2. Products of these reactions include ankerite and quartz overgrowth cements. Hydrocarbon staining postdates these phases and provides evidence of a hydrocarbon charge, probably gas condensate. The second hydrocarbon charge also leaked off, and the sandstone is now water bearing. Previous work on the Fulmar Formation has incorrectly placed all the diagenetic reactions as predating the first arrival of hydrocarbon. The present-day pore fluids are high-salinity, high-{delta}18O fluids derived from the underlying Permian Zechstein evaporates. These fluids entered the reservoir during a phase of overpressure release that caused fracturing of the framework quartz grains, possibly coincident with the second phase of hydrocarbon leak-off at 2–5 Ma

Ankerite cementation in deeply buried Jurassic sandstone reservoirs of the central North Sea

Upper Jurassic Fulmar Formation shelf sandstones of the high- temperature, high-pressure Franklin and Elgin Fields (South Central Graben, North Sea) contain abundant disseminated and concretionary ankerite. In contrast, most Jurassic North Sea reservoirs contain only minor amounts of dispersed ankerite. Disseminated ankerite cement in the Franklin and Elgin Fields has a fairly uniform isotopic composition (delta(18)O approximate to -10 to -12.5 parts per thousand PDB, delta(13)C approximate to -3 to -5 parts per thousand PDB). Ankerite concretions have delta(18)O values similar to disseminated cements but a wider range of delta(13)C values (+1 to -5.5 parts per thousand PDB). They also have highly variable intergranular volumes, which (together with the delta(13)C data) are interpreted as a combination of pore-filling cementation and in situ replacement of comminuted bioclastic debris by ankerite. Fluid-inclusion, delta(18)O, and paragenetic evidence suggests that ankerite formed during deep burial (c, 3.5 to 4.5 km, 140-170 degrees C), after the onset of overpressuring, but before hydrocarbon emplacement in the reservoirs. The regionally consistent delta(18)O data suggest that ankerite formed via a temperature-influenced mechanism, and the relatively uniform delta(13)C cement value indicates that organic matter and marine bioclastic carbonate contributed to the dissolved carbon reservoir in constant proportion, This can be explained by calcite dissolution in response to pH decrease during thermal breakdown of organic acids. Such acids were derived from adjacent mudrocks undergoing hydrocarbon maturation and clay-mineral transformations, and are likely to have been transported in pore fluids with Mg2+ and Fe2+. The presence of these cations in solution upon thermal decarboxylation is inferred to have stabilized ankerite at the expense of calcite. A relative paucity of ankerite in other Fulmar Formation reservoirs may reflect different sedimentological compositions (less bioclastic debris) and/or lower burial temperatures (less advanced decarboxylation)