Exploring seismic detection and resolution thresholds of fault zones and gas seeps in the shallow subsurface using seismic modelling

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How displacement analysis may aid fault risking strategies for CO₂ storage

AbstractDeveloping an accurate understanding of the ways in which faults have grown within a particular region and stratigraphy can aid risk management for CO2 storage sites. Areas of fault interaction lead to differences in the stress field, resulting in an increased strain, which is often accommodated by a high intensity of deformation bands and/or fracturing, dependent on host rock properties. These structures alter the permeability surrounding faults. Hence, detecting areas of interaction of structures throughout the fault growth history allows the identification of locations where high risk may occur in terms of the hydraulic properties of a fault zone. The Vette Fault Zone (VFZ), bounding the Alpha prospect within the potential CO2 Smeaheia storage site, Northern Horda Platform, is shown to have grown from a minimum of seven fault segments. By utilising a comparison with the adjacent Tusse Fault Zone (TFZ), we can identify potential areas of high risk, where fluids may have the ability to flow across or along the VFZ. The high seal strength of the TFZ holding back a large gas column is likely to be created by shale juxtaposition and smearing with cataclastic processes. The same could be assumed for the VFZ, associated with similar tectonics and displaced stratigraphy. However, rather than membrane breaching causing fluids to flow across the fault, potential areas of high risk have been identified at locations of relict breached relay zones, where the initial displacement of the intersecting faults and area of overlap was high. These areas appear to correspond with the location of hydrocarbon contact depth (spill point) along the TFZ. Using the same assumptions for the VFZ, we can observe one potential area of high risk, which lies within the area of suggested CO2 accumulation.</jats:p

Fault interpretation uncertainties using seismic data, and the effects on fault seal analysis: a case study from the Horda Platform, with implications for CO2 storage

Abstract. Significant uncertainties occur through varying methodologies when interpreting faults using seismic data. These uncertainties are carried through to the interpretation of how faults may act as baffles or barriers, or increase fluid flow. How fault segments are picked when interpreting structures, i.e. which seismic line orientation, bin spacing and line spacing are specified, as well as what surface generation algorithm is used, will dictate how rugose the surface is and hence will impact any further interpretation such as fault seal or fault growth models. We can observe that an optimum spacing for fault interpretation for this case study is set at approximately 100 m, both for accuracy of analysis but also for considering time invested. It appears that any additional detail through interpretation with a line spacing of ≤ 50 m adds complexity associated with sensitivities by the individual interpreter. Further, the locations of all seismic-scale fault segmentation identified on throw–distance plots using the finest line spacing are also observed when 100 m line spacing is used. Hence, interpreting at a finer scale may not necessarily improve the subsurface model and any related analysis but in fact lead to the production of very rough surfaces, which impacts any further fault analysis. Interpreting on spacing greater than 100 m often leads to overly smoothed fault surfaces that miss details that could be crucial, both for fault seal as well as for fault growth models. Uncertainty in seismic interpretation methodology will follow through to fault seal analysis, specifically for analysis of whether in situ stresses combined with increased pressure through CO2 injection will act to reactivate the faults, leading to up-fault fluid flow. We have shown that changing picking strategies alter the interpreted stability of the fault, where picking with an increased line spacing has shown to increase the overall fault stability. Picking strategy has shown to have a minor, although potentially crucial, impact on the predicted shale gouge ratio.</jats:p

Architecture, deformation style and petrophysical properties of growth fault systems: the Late Triassic deltaic succession of southern Edgeøya (East Svalbard)

The Late Triassic outcrops on southern Edgeøya, East Svalbard, allow a multiscale study of syn‐sedimentary listric growth faults located in the prodelta region of a regional prograding system. At least three hierarchical orders of growth faults have been recognized, each showing different deformation mechanisms, styles and stratigraphic locations of the associated detachment interval. The faults, characterized by mutually influencing deformation envelopes over space‐time, generally show SW‐ to SE‐dipping directions, indicating a counter‐regional trend with respect to the inferred W‐NW directed progradation of the associated delta system. The down‐dip movement is accommodated by polyphase deformation, with the different fault architectural elements recording a time‐dependent transition from fluidal‐hydroplastic to ductile‐brittle deformation, which is also conceptually scale‐dependent, from the smaller‐ (3rd order) to the larger‐scale (1st order) end‐member faults respectively. A shift from distributed strain to strain localization towards the fault cores is observed at the meso to microscale (<1 mm), and in the variation in petrophysical parameters of the litho‐structural facies across and along the fault envelope, with bulk porosity, density, pore size and microcrack intensity varying accordingly to deformation and reworking intensity of inherited structural fabrics. The second‐ and third‐order listric fault nucleation points appear to be located above blind fault tip‐related monoclines involving cemented organic shales. Close to planar, through‐going, first‐order faults cut across this boundary, eventually connecting with other favourable lower‐hierarchy fault to create seismic‐scale fault zones similar to those imaged in the nearby offshore areas. The inferred large‐scale driving mechanisms for the first‐order faults are related to the combined effect of tectonic reactivation of deeper Palaeozoic structures in a far field stress regime due to the Uralide orogeny, and differential compaction associated with increased sand sedimentary input in a fine‐grained, water‐saturated, low‐accommodation, prodeltaic depositional environment. In synergy to this large‐scale picture, small‐scale causative factors favouring second‐ and third‐order faulting seem to be related to mechanical‐rheological instabilities related to localized shallow diagenesis and liquidization fronts.publishedVersio

Discovery of shale gas in organic rich Jurassic successions, Adventdalen, Central Spitsbergen, Norway

Thermogenic dry gas flowed from Jurassic sections in the DH5R research well drilled onshore in Adventdalen, central Spitsbergen, Arctic Norway. The DH5R gas originates from the organic-rich units of the mudstone-dominated Middle Jurassic to Lower Cretaceous Agardhfjellet Formation, which is the onshore equivalent to the Fuglen Formation and the prolific oil and gas generating Hekkingen Formation in the southern Barents Shelf. Low-permeable, low-porosity sandstones from the Upper Triassic De Geerdalen Formation of the neighbouring DH4 well were oil-stained and gas was also collected from this interval. Gas from the two stratigraphic intervals have different compositions; the gas from the Agardhfjellet Formation is drier and isotopically heavier than the gas from the Upper Triassic succession. Both gases originated from source rocks of maturity near the end of the oil window (1.1 < Ro < 1.4% Ro). Maceral analyses of the Agardhfjellet Formation indicate that the more silty parts contain a high percentage of vitrinite-rich type III kerogen, whereas the clay-dominated parts are rich in liptinitic type II kerogen. The Agardhfjellet Formation has therefore the potential to generate both oil and gas. Several simulations based on pressure data and flow rates from the DH5R well were run to evaluate if the gas accumulation in the Agardhfjellet Formation is producible, i.e., can it be commercial shale gas. The models demonstrate how changes in the drainage area size and form, well types (vertical versus horizontal), number and length of induced fractures and thickness of the Agardhfjellet Formation affect gas production rates and producible volumes. Despite uncertainties in the input data, simulations indicate that the shale gas accumulation characterised in Adventdalen is producible. This gas can have major environmental benefits as an alternative for local power generation compared to coal.publishedVersio

Overprinted allocyclic processes by tidal resonance in an epicontinental basin: the Upper Jurassic Curtis Formation, east‐central Utah, USA

Modern, tide‐dominated and tide‐influenced coastlines are characterised by a range of environments, including deltas, estuaries, and lagoons. However, some tide‐dominated basins and related sedimentary units in the rock record, such as the semi‐enclosed, shallow, Utah‐Idaho Trough foreland basin of the Jurassic Curtis sea, do not correspond to any of these modern systems. Persistent aridity caused the characteristic severe starvation of perennial fluvial input throughout this basin, in which the informal lower, middle, and upper Curtis, as well as the underlying Entrada Sandstone, and the overlying Summerville Formation were deposited. Wave energy was efficiently dissipated by the shallow basin's elongated morphology (approximately 800x150 km), as its semi‐enclosed morphology further protected the system from significant wave impact. Consequently, the semi‐enclosed, shallow‐marine system was dominated by amplified tidal forces, resulting in a complex distribution of heterolithic deposits. Allocyclic forcing strongly impacted upon the system's intrinsic autocyclic processes as the lower Curtis was deposited. Short‐lived relative sea‐level variations, along with uplift and deformation episodes, resulted in the accumulation of three parasequences, each separated by traceable flooding and ravinement surfaces. The subsequent transgression, which defines the base of the middle Curtis, allowed for the shallow‐marine part of the system to enter into tidal resonance as a consequence of the flooded basin reaching the optimal configuration of approximately 800 km in length, corresponding to an odd multiple of the quarter of the tidal wavelength given an average minimum water depth of 20 to 25 m. This resonant system overprinted the effects of allocyclic forcing and related traceable stratigraphic surfaces. However, the contemporaneous and neighbouring coastal dune field sedimentary rocks of the Moab Member of the Curtis Formation, characterised by five stacked aeolian sequences, as well as the supratidal deposits of the Summerville Formation, lingered to record allocyclic signals, as the Curtis sea regressed. This study shows that a tide‐dominated basin can enter into tidal resonance as it reaches its optimal morphological configuration, leading to the overprinting of otherwise dominant allocyclic processes by autocyclic behaviour. It is only by considering the sedimentological relationships of neighbouring and contemporaneous depositional systems that a full understanding of the dynamic stratigraphic history of a basin alternatively dominated by autocyclic and allocyclic processes can be achieved

The Svalbard Carboniferous to Cenozoic Composite Tectono-Stratigraphic Element

The Svalbard Composite Tectono-Stratigraphic Element is located on the north-western corner of the Barents Shelf and comprises a Carboniferous to Pleistocene sedimentary succession. Due to Cenozoic uplift the succession is subaerially exposed in the Svalbard archipelago. The oldest parts of the succession consist of Carboniferous to Permian mixed siliciclastic, carbonate and evaporite and spiculitic sediments that developed during multiple phases of extension. The majority of the Mesozoic succession is composed of siliciclastic deposits formed in sag basins and continental platforms. Episodes of Late Jurassic and Early Cretaceous contraction are evident in the eastern part of the archipelago and in nearby offshore areas. Differential uplift related to the opening of the Amerasian Basin and the Cretaceous emplacement of the High Arctic Large Igneous Province created a major hiatus spanning from most of the Late Cretaceous and early Danian throughout the Svalbard Composite Tectono-Stratigraphic Element. The West Spitsbergen Fold and Thrust Belt and the associated foreland basin in central Spitsbergen (Central Tertiary Basin) formed as a response to the Eurekan orogeny and the progressive northward opening of the North Atlantic during the Palaeogene. This event was followed by formation of yet another major hiatus spanning the Oligocene to Pliocene. Multiple reservoir and source rock units are exposed in Svalbard providing analogues to the offshore prolific offshore acreages in southwest Barents Sea and are important for de-risking of plays and prospects. However, the archipelago itself is regarded as high-risk acreage for petroleum exploration. This is due to Palaeogene contraction and late Neogene uplift of particularly the western and central parts. In the east there is an absence of mature source rocks, and the entire region is subjected to strict environmental protection