Hydrodynamics and membrane seal capacity

The impact of hydrodynamic groundwater movement on the capacity of seals is currently in debate. There is an extensive record of publication on seals analysis and a similar history on petroleum hydrodynamics yet little work addresses the links between the two. Understanding and quantifying the effects of hydrodynamic flow has important implications for calibrating commonly used seal capacity estimation techniques. These are often based on measurements such as shale gouge, clay smear or mercury porosimitry where membrane sealing is thought to occur. For standard membrane seal analysis, seal capacity is estimated by quantifying capillary pressure‐related measurements and calibrating them with a large observational database of hydrocarbon column heights and measured buoyancy pressures. The seal capacity estimation process has historically been adjusted to account for a number of different generic trapping geometries. We define the characteristics of these geometries from a hydrodynamics viewpoint in order to fine‐tune the seal capacity calibration process. From theoretical analyses of several simplified trapping geometries, it can be concluded that generally, the high pressure side of the seal should be used as the water pressure gradient with which to calculate buoyancy pressure. Secondly, trap geometries where hydrocarbon is reservoired on both sides of a fault are not useful for estimating across fault seal capacity.     

Physical properties of carbonate fault rocks,fucino basin (Central Italy): implications for fault seal in platform carbonates

We documented the porosity, permeability, pore geometry, pore type, textural anisotropy, and capillary pressure of carbonate rock samples collected along basin‐bounding normal faults in central Italy. The study samples consist of one Mesozoic platform carbonate host rock with low porosity and permeability, four fractured host rocks of the damage zones, and four fault rocks of the fault cores. The four fractured samples have high secondary porosity, due to elongated, connected, soft pores that provide fluid pathways in the damage zone. We modeled this zone as an elastic cracked medium, and used the Budiansky–O'Connell correlation to compute its permeability from the measured elastic moduli. This correlation can be applied only to fractured rocks with large secondary porosity and high‐aspect ratio pores. The four fault rock samples are made up of survivor clasts embedded in fine carbonate matrices and cements with sub‐spherical, stiff pores. The low porosity and permeability of these rocks, and their high values of capillary pressure, are consistent with the fault core sealing as much as 77 and 140 m of gas and oil columns, respectively. We modeled the fault core as a granular medium, and used the Kozeny–Carmen correlation, assigning the value of 5 to the Kozeny constant, to compute its permeability from the measured porosities and pore radii. The permeability structure of the normal faults is composed of two main units with unique hydraulic characteristics: a granular fault core that acts as a seal to cross‐fault fluid flow, and an elastic cracked damage zone that surrounds the core and forms a conduit for fluid flow. Transient pathways for along‐fault fluid flow may form in the fault core during seismic faulting due to the formation of opening‐mode fractures within the cemented fault rocks.     

Faults and fault properties in hydrocarbon flow models

The petroleum industry uses subsurface flow models for two principal purposes: to model the flow of hydrocarbons into traps over geological time, and to simulate the production of hydrocarbon from reservoirs over periods of decades or less. Faults, which are three-dimensional volumes, are approximated in both modelling applications as planar membranes onto which predictions of the most important fault-related flow properties are mapped. Faults in porous clastic reservoirs are generally baffles or barriers to flow and the relevant flow properties are therefore very different to those which are important in conductive fracture flow systems. A critical review and discussion is offered on the work-flows used to predict and model capillary threshold pressure for exploration fault seal analysis and fault transmissibility multipliers for production simulation, and of the data from which the predictions derive. New flow simulation models confirm that failure of intra-reservoir sealing faults can occur during a reservoir depressurization via a water-drive mechanism, but contrary to anecdotal reports, published examples of production-induced seal failure are elusive. Ignoring the three-dimensional structure of fault zones can sometimes have a significant influence on production-related flow, and a series of models illustrating flow associated with relay zones are discussed.     

Communication between overpressured compartments

Overpressure build‐up in compartments, and communication between overpressured compartments across faults are studied with simple analytical and numerical models. It is shown that the excess pressure in a (vertical) one‐dimensional, one‐compartment model can be written as the sum of the excess pressure generated in the seal above the compartment, and a second part, which is due to the expulsion of fluid from the compartment and the rocks below. The one‐compartment model is generalized to a two‐compartment model, which accounts for the fluid communication between the compartments through a fault zone. The volume rates of flow through the seals and the fault zone are shown to be the weighted mean of the volume rates of the one‐dimensional, one‐compartment model. The normalized weights are given by dimensionless numbers, called fault–seal numbers, which control the communication between the compartments. A fault–seal number much less than unity implies that the fault is a stronger barrier for the fluid flow than the seal. A fault–seal number larger than unity implies the opposite: that the seal is a stronger barrier than the fault. The conditions for isolated compartments and other regimes are identified in terms of the fault–seal numbers. It is discussed how the compartment fault–seal numbers can be computed when the permeability is given in the fault zone. The results given by the analytical compartment models are demonstrated and validated with two‐dimensional numerical (finite element) simulations.     

Pressure distribution in a reservoir affected by capillarity and hydrodynamic drive: Griffin Field, North West Shelf, Australia

The effects of capillarity in a multilayered reservoir with flow in the aquifer beneath have characteristic signatures on pressure–elevation plots. Such signatures are observed for the Griffin and Scindian/Chinook fields of the Carnarvon Basin North West Shelf of Australia. The Griffin and Scindian/Chinook fields have a highly permeable lower part to the reservoir, a less permeable upper part, and a low permeability top seal. In the Griffin Field there is a systematic tilt of the free‐water level in the direction of groundwater flow. Where the oil–water contact occurs in the less permeable part of the reservoir, it lies above the free‐water level due to capillarity. In addition to these observable hydrodynamic and capillary effects on hydrocarbon distribution, the multi‐well pressure analysis shows that the gas–oil contacts in the Scindian/Chinook fields occur at different elevations. For both the Griffin and Scindian/Chinook fields the oil pressure gradients from each well are non‐coincident despite continuous oil saturation, and the difference is not attributable to data error. Furthermore, the shift in oil pressure gradient has a geographical pattern seemingly linked to the hydrodynamics of the aquifer. The simplest explanation for all the observed pressure trends is an oil leg that is still in the process of equilibrating with the prevailing hydrodynamic regime.     

Simulation of the impact of faults on CO2 injection into sandstone reservoirs

Numerical simulations of multiphase CO₂ behavior within faulted sandstone reservoirs examine the impact of fractures and faults on CO₂ migration in potential subsurface injection systems. In southeastern Utah, some natural CO₂ reservoirs are breached and CO₂‐charged water flows to the surface along permeable damage zones adjacent to faults; in other sites, faulted sandstones form barriers to flow and large CO₂‐filled reservoirs result. These end‐members serve as the guides for our modeling, both at sites where nature offers ‘successful’ storage and at sites where leakage has occurred. We consider two end‐member fault types: low‐permeability faults dominated by deformation‐band networks and high‐permeability faults dominated by fracture networks in damage zones adjacent to clay‐rich gouge. Equivalent permeability (k) values for the fault zones can range from <10^?14 m² for deformation‐band‐dominated faults to >10^?12 m² for fracture‐dominated faults regardless of the permeability of unfaulted sandstone. Water–CO₂ fluid‐flow simulations model the injection of CO₂ into high‐k sandstone (5 × 10^?13 m²) with low‐k (5 × 10^?17 m²) or high‐k (5 × 10^?12 m²) fault zones that correspond to deformation‐band‐ or fracture‐dominated faults, respectively. After 500 days, CO₂ rises to produce an inverted cone of free and dissolved CO₂ that spreads laterally away from the injection well. Free CO₂ fills no more than 41% of the pore space behind the advancing CO₂ front, where dissolved CO₂ is at or near geochemical saturation. The low‐k fault zone exerts the greatest impact on the shape of the advancing CO₂ front and restricts the bulk of the dissolved and free CO₂ to the region upstream of the fault barrier. In the high‐k aquifer, the high‐k fault zone exerts a small influence on the shape of the advancing CO₂ front. We also model stacked reservoir seal pairs, and the fracture‐dominated fault acts as a vertical bypass, allowing upward movement of CO₂ into overlying strata. High‐permeability fault zones are important pathways for CO₂ to bypass unfaulted sandstone, which leads to reduce sequestration efficiency. Aquifer compartmentalization by low‐permeability fault barriers leads to improved storativity because the barriers restrict lateral CO₂ migration and maximize the volume and pressure of CO₂ that might be emplaced in each fault‐bound compartment. As much as a 3.5‐MPa pressure increase may develop in the injected reservoir in this model domain, which under certain conditions may lead to pressures close to the fracture pressure of the top seal.     

Influence of fault map resolution on pore pressure distribution and secondary hydrocarbon migration; Tune area,North Sea

Pressure and hydrocarbon migration modelling was carried out in the Tune Field area, Viking Graben, offshore Norway. The pressures are considered to be controlled by compartments bounded by mapped faults. Two different interpreted fault maps at the top reservoir level (Brent Group) are used as input to the modelling. First, a low‐resolution fault map is used, with only the large faults interpreted, and next, both large and small faults are included. The simulations show high overpressures generated in the western area, in the deeper part of the Viking Graben, and hydrostatic in the eastern areas. A sharp transition zone results from using the low‐resolution fault map in the simulations. Small N–S striking faults situated in between the wells have to have higher sealing capacity than expected from juxtaposition analysis alone, to be able to match the overpressures measured in well 30/5‐2 and 30/8‐1S in the Tune Field, and well 30/8‐3 east of Tune. The intermediate pressure in the western part is probably related to flow in the deeper parts of the sedimentary column in the compartment, where well 30/8‐3 is situated. The secondary oil migration models show that overpressures have major effects on the migration pathways of hydrocarbons. The level of detail in the fault interpretation is important for simulation results, both for pressure distribution and for hydrocarbon migration.     

Effects of episodic fluid flow on hydrocarbon migration in the Newport‐Inglewood Fault Zone,Southern California

Fault permeability may vary through time due to tectonic deformations, transients in pore pressure and effective stress, and mineralization associated with water‐rock reactions. Time‐varying permeability will affect subsurface fluid migration rates and patterns of petroleum accumulation in densely faulted sedimentary basins such as those associated with the borderland basins of Southern California. This study explores the petroleum fluid dynamics of this migration. As a multiphase flow and petroleum migration case study on the role of faults, computational models for both episodic and continuous hydrocarbon migration are constructed to investigate large‐scale fluid flow and petroleum accumulation along a northern section of the Newport‐Inglewood fault zone in the Los Angeles basin, Southern California. The numerical code solves the governing equations for oil, water, and heat transport in heterogeneous and anisotropic geologic cross sections but neglects flow in the third dimension for practical applications. Our numerical results suggest that fault permeability and fluid pressure fluctuations are crucial factors for distributing hydrocarbon accumulations associated with fault zones, and they also play important roles in controlling the geologic timing for reservoir filling. Episodic flow appears to enhance hydrocarbon accumulation more strongly by enabling stepwise build‐up in oil saturation in adjacent sedimentary formations due to temporally high pore pressure and high permeability caused by periodic fault rupture. Under assumptions that fault permeability fluctuate within the range of 1–1000 millidarcys (10^?15–10^?12 m²) and fault pressures fluctuate within 10–80% of overpressure ratio, the estimated oil volume in the Inglewood oil field (approximately 450 million barrels oil equivalent) can be accumulated in about 24 000 years, assuming a seismically induced fluid flow event occurs every 2000 years. This episodic petroleum migration model could be more geologically important than a continuous‐flow model, when considering the observed patterns of hydrocarbons and seismically active tectonic setting of the Los Angeles basin.     

Gas breakthrough experiments on pelitic rocks: comparative study with N2, CO2 and CH4

The capillary‐sealing efficiency of intermediate‐ to low‐permeable sedimentary rocks has been investigated by N₂, CO₂ and CH₄ breakthrough experiments on initially fully water‐saturated rocks of different lithological compositions. Differential gas pressures up to 20 MPa were imposed across samples of 10–20 mm thickness, and the decline of the differential pressures was monitored over time. Absolute (single‐phase) permeability coefficients (k_abs), determined by steady‐state fluid flow tests, ranged between 10^?22 and 10^?15 m². Maximum effective permeabilities to the gas phase k_eff(max), measured after gas breakthrough at maximum gas saturation, extended from 10^?26 to 10^?18 m². Because of re‐imbibition of water into the interconnected gas‐conducting pore system, the effective permeability to the gas phase decreases with decreasing differential (capillary) pressure. At the end of the breakthrough experiments, a residual pressure difference persists, indicating the shut‐off of the gas‐conducting pore system. These pressures, referred to as the ‘minimum capillary displacement pressures’ (P_d), ranged from 0.1 up to 6.7 MPa. Correlations were established between (i) absolute and effective permeability coefficients and (ii) effective or absolute permeability and capillary displacement pressure. Results indicate systematic differences in gas breakthrough behaviour of N₂, CO₂ and CH₄, reflecting differences in wettability and interfacial tension. Additionally, a simple dynamic model for gas leakage through a capillary seal is presented, taking into account the variation of effective permeability as a function of buoyancy pressure exerted by a gas column underneath the seal.     

Evolution of porosity, permeability and fluid pressure in dilatant faults post-failure: implications for fluid flow and mineralization

Mineralization of brittle fault zones is associated with sudden dilation, and the corresponding changes in porosity, permeability and fluid pressure, that occur during fault slip events. The resulting fluid pressure gradients cause fluid to flow into and along the fault until it is sealed. The volume of fluid that can pass through the deforming region depends on the degree of dilation, the porosity and permeability of the fault and wall rocks, and the rate of fault sealing. A numerical model representing a steep fault cutting through a horizontal seal is used to investigate patterns of fluid flow following a dilatant fault slip event. The model is initialized with porosity, permeability and fluid pressure representing the static mechanical state of the system immediately after such an event. Fault sealing is represented by a specified evolution of porosity, coupled to changes in permeability and fluid pressure, with the rate of porosity reduction being constrained by independent estimates of the rate of fault sealing by pressure solution. The general pattern of fluid flow predicted by the model is of initial flow into the fault from all directions, followed by upward flow driven by overpressure beneath the seal. The integrated fluid flux through the fault after a single failure event is insufficient to account for observed mineralization in faults; mineralization would require multiple fault slip events. Downward flow is predicted if the wall rocks below the seal are less permeable than those above. This phenomenon could at least partially explain the occurrence of uranium deposits in reactivated basement faults that cross an unconformity between relatively impermeable basement and overlying sedimentary rocks.     

An exhumed palaeo-hydrocarbon migration fairway in a faulted carrier system, Entrada Sandstone of SE Utah, USA

The Moab Anticline, east‐central Utah, is an exhumed hydrocarbon palaeo‐reservoir which was supplied by hydrocarbons that migrated from the Moab Fault up‐dip towards the crest of the structure beneath the regional seal of the Tidwell mudstone. Iron oxide reduction in porous, high permeability aeolian sandstones records the secondary migration of hydrocarbons, filling of traps against small sealing faults and spill pathways through the Middle Jurassic Entrada Sandstone. Hydrocarbons entered the Entrada Sandstone carrier system from bends and other leak points on the Moab Fault producing discrete zones of reduction that extend for up to 400 m from these leak points. They then migrated in focused stringers, 2–5 m in height, to produce accumulations on the crest of the anticline. Normal faults on the anticline were transient permeability barriers to hydrocarbon migration producing a series of small compartmentalized accumulations. Exsolution of CO₂ as local fault seals were breached resulted in calcite cementation on the up‐dip side of faults. Field observations on the distribution of iron oxide reduction and calcite cements within the anticline indicate that the advancing reduction fronts were affected neither by individual slip bands in damage zones around faults nor by small faults with sand: sand juxtapositions. Faults with larger throws produced either sand: mudstone juxtapositions or sand: sand contacts and fault zones with shale smears. Shale‐smeared fault zones provided seals to the reducing fluid which filled the structural traps to spill points.     

Wettability alteration of caprock minerals by carbon dioxide

One of the critical factors that control the efficiency of CO₂ geological storage process in aquifers and hydrocarbon reservoirs is the capillary‐sealing potential of the caprock. This potential can be expressed in terms of the maximum reservoir overpressure that the brine‐saturated caprock can sustain, i.e. of the CO₂ capillary entry pressure. It is controlled by the brine/CO₂ interfacial tension, the water‐wettability of caprock minerals, and the pore size distribution within the caprock. By means of contact angle measurements, experimental evidence was obtained showing that the water‐wettability of mica and quartz is altered in the presence of CO₂ under pressures typical of geological storage conditions. The alteration is more pronounced in the case of mica. Both minerals are representative of shaly caprocks and are strongly water‐wet in the presence of hydrocarbons. A careful analysis of the available literature data on breakthrough pressure measurements in caprock samples confirms the existence of a wettability alteration by dense CO₂, both in shaly and in evaporitic caprocks. The consequences of this effect on the maximum CO₂ storage pressure and on CO₂ storage capacity in the underground reservoir are discussed. For hydrocarbon reservoirs that were initially close to capillary leakage, the maximum allowable CO₂ storage pressure is only a fraction of the initial reservoir pressure.     

Numerical modeling of the origin of calcite mineralization in the Refugio‐Carneros fault,Santa Barbara Basin,California

Many faults in active and exhumed hydrocarbon‐generating basins are characterized by thick deposits of carbonate fault cement of limited vertical and horizontal extent. Based on fluid inclusion and stable isotope characteristics, these deposits have been attributed to upward flow of formation water and hydrocarbons. The present study sought to test this hypothesis by using numerical reactive transport modeling to investigate the origin of calcite cements in the Refugio‐Carneros fault located on the northern flank of the Santa Barbara Basin of southern California. Previous research has shown this calcite to have low δ¹³C values of about ?40 to ?30‰PDB, suggesting that methane‐rich fluids ascended the fault and contributed carbon for the mineralization. Fluid inclusion homogenization temperatures of 80–125°C in the calcite indicate that the fluids also transported significant quantities of heat. Fluid inclusion salinities ranging from fresh water to seawater values and the proximity of the Refugio‐Carneros fault to a zone of groundwater recharge in the Santa Ynez Mountains suggest that calcite precipitation in the fault may have been induced by the oxidation of methane‐rich basinal fluids by infiltrating meteoric fluids descending steeply dipping sedimentary layers on the northern basin flank. This oxidation could have occurred via at least two different mixing scenarios. In the first, overpressures in the central part of the basin may have driven methane‐rich formation waters derived from the Monterey Formation northward toward the basin flanks where they mixed with meteoric water descending from the Santa Ynez Mountains and diverted upward through the Refugio‐Carneros fault. In the second scenario, methane‐rich fluids sourced from deeper Paleogene sediments would have been driven upward by overpressures generated in the fault zones because of deformation, pressure solution, and flow, and released during fault rupture, ultimately mixing with meteoric water at shallow depth. The models in the present study were designed to test this second scenario, and show that in order for the observed fluid inclusion temperatures to be reached within 200 m of the surface, moderate overpressures and high permeabilities were required in the fault zone. Sudden release of overpressure may have been triggered by earthquakes and led to transient pulses of accelerated fluid flow and heat transport along faults, most likely on the order of tens to hundreds of years in duration. While the models also showed that methane‐rich fluids ascending the Refugio‐Carneros fault could be oxidized by meteoric water traversing the Vaqueros Sandstone to form calcite, they raised doubts about whether the length of time and the number of fault pulses needed for mineralization by the fault overpressuring mechanism were too high given existing geologic constraints.     

Gas breakthrough pressure for hydrocarbon reservoir seal rocks: implications for the security of long-term CO2 storage in the Weyburn field

This paper reports a laboratory study of the gas breakthrough pressure for different gas/liquid systems in the Mississippian‐age Midale Evaporite. This low‐permeability rock formation is the seal rock for the Weyburn Field in southeastern Saskatchewan, Canada, where CO₂ is being injected into an oil reservoir for enhanced recovery and CO₂ storage. A technique for experimentally determining CO₂ breakthrough pressure at reservoir conditions is presented. Breakthrough pressures for N₂, CO₂ and CH₄ were measured with the selected seal‐rock samples. The maximum breakthrough pressure is over 30 MPa for N₂ and approximately 21 MPa for CO₂. The experimental results demonstrate that the Weyburn Midale Evaporite seal rock is of high sealing quality. Therefore, the Weyburn reservoir and Midale Beds can be used as a CO₂ storage site after abandonment. The measured results also show that the breakthrough pressure of a seal rock for a gas is nearly proportional to the interfacial tension of the gas/brine system. The breakthrough pressure of a CO₂/brine system is significantly reduced compared with that of a CH₄/brine system because of the much lower interfacial tension of the former. This implies that a seal rock that seals the original gas in a gas reservoir or an oil reservoir with a gas cap may not be tight enough to seal the injected CO₂ if the pressure during or after CO₂ injection is the same or higher than the original reservoir pressure. Therefore, reevaluation of the breakthrough pressure of seal rocks for a given reservoir is necessary and of highest priority once it is chosen as a CO₂ storage site.     

Changes in chemical composition caused by water–rock interactions across a strike‐slip fault zone: case study of the Atera Fault,Central Japan

In some cases, water–rock interactions in fault zones can affect radionuclide migration. Here, we analyzed the chemical compositions of well‐exposed fault rocks from the strike‐slip Atera Fault, Central Japan, in order to understand the variability and behavior of major and selected trace elements. The fault zone has a 1.2‐m‐wide, smectite‐rich fault core and paired damage zones that developed within welded tuff on one side of the core and within granite on the other side. The 30‐cm‐wide, kaolinite‐rich fault gouge is developed in granite cataclasite, and it shows indications of the latest fault activity, while the 1.2‐m‐wide fault core appears to be older. Hydrogen and oxygen isotope ratios in the clay‐rich fault gouges, and carbon and oxygen isotope ratios in carbonates indicate that the two major clay‐rich zones formed in bedrock near the surface, consistent with observed deformation structures. Based on chemical analyses, we identified (1) a slight depletion in SiO₂, Na₂O, K₂O, and light rare earth elements at the edges of the 1.2‐m‐wide fault core, (2) a clear depletion in SiO₂, Na₂O, K₂O, and all rare earth elements except Eu in the 30‐cm‐wide fault gouge, and (3) an increase in CaO, MnO, and heavy rare earth elements across the entire 1.2‐m‐wide fault core. Findings (1) and (2) reflect water–rock interactions in the 1.2‐m‐wide fault core and in the 30‐cm‐wide fault gouge that resulted in the formation of smectite and kaolinite. Finding (3) reflects carbonate precipitation caused by the addition of basalt fragments from a nearby site to the 1.2‐m‐wide fault core during faulting, and subsequent sorption reactions of heavy rare earth elements via processes such as complexation with the carbonates.     

Analytical and numerical models of hydrothermal fluid flow at fault intersections

Fault intersections are the locus of hot spring activity and Carlin‐type gold mineralization within the Basin and Range, USA. Analytical and numerical solutions to Stokes equation suggest that peak fluid velocities at fault intersections increase between 20% and 47% when fracture apertures have identical widths but increase by only about 1% and 8% when aperture widths vary by a factor of 2. This suggests that fault zone intersections must have enlarged apertures. Three‐dimensional finite element models that consider intersecting 10‐ to 20‐m wide fault planes resulted in hot spring activity being preferentially located at fault zone intersections when fault zones were assigned identical permeabilities. We found that the onset of convection at the intersections of the fault zones occurred in our hydrothermal model over a narrow permeability range between 5 × 10^?13 and 7 × 10^?13 m². Relatively high vertical fluid velocities (0.3–3 m year^?1) extended away from the fault intersections for about 0.5–1.5 km. For the boundary conditions and fault plane dimensions used, peak discharge temperatures of 112°C at the water table occurred with an intermediate fault zone permeability of 5 × 10^?13 m². When fault plane permeability differed by a factor of 2 or more, the locus of hot spring activity shifted away from the intersections. However, increasing the permeability at the core of the fault plane intersection by 40% shifted the discharge back to the intersections. When aquifer units were assigned a permeability value equal to those of the fault planes, convective rolls developed that extend about 3 km laterally along the fault plane and into the adjacent aquifer.     

Significance of large-scale sand injectites as long-term fluid conduits: evidence from seismic data

Sand injectites and related features that are interpreted to have formed by large‐scale, often sudden, fluid escape in the shallow (typically <500 m) crust are readily imaged on modern seismic data. Many of the features have geometrical similarity to igneous dykes and sills and cross‐cut the depositional stratigraphy. Sand injectites may be multiphase and form connected, high‐permeability networks that transect kilometre‐scale intervals of otherwise fine‐grained, low‐permeability strata. North Sea examples often form significant hydrocarbon reservoirs and typically contain degraded, low‐gravity crude oil. Fluid inclusion and stable isotope data from cements in sand injectites record a mixing of aqueous fluids of deep and shallow origin.     

Carbon dioxide controlled earthquake distribution pattern in the NW Bohemian swarm earthquake region,western Eger Rift,Czech Republic – gas migration in the crystalline basement

The ascent of magmatic carbon dioxide in the western Eger (Oh?e) Rift is interlinked with the fault systems of the Variscian basement. In the Cheb Basin, the minimum CO₂ flux is about 160 m³ h^?1, with a diminishing trend towards the north and ceasing in the main epicentral area of the Northwest Bohemian swarm earthquakes. The ascending CO₂ forms Ca‐Mg‐HCO₃ type waters by leaching of cations from the fault planes and creates clay minerals, such as kaolinite, as alteration products on affected fault planes. These mineral reactions result in fault weakness and in hydraulically interconnected fault network. This leads to a decrease in the friction coefficient of the Coulomb failure stress (CFS) and to fault creep as stress build‐up cannot occur in the weak segments. At the transition zone in the north of the Cheb Basin, between areas of weak, fluid conductive faults and areas of locked faults with frictional strength, fluid pressure can increase resulting in stress build‐up. This can trigger strike‐slip swarm earthquakes. Fault creep or movements in weak segments may support a stress build‐up in the transition area by transmitting fluid pressure pulses. Additionally to fluid‐driven triggering models, it is important to consider that fluids ascending along faults are CO₂‐supersaturated thus intensifying the effect of fluid flow. The enforced flow of CO₂‐supersaturated fluids in the transitional zone from high to low permeability segments through narrowings triggers gas exsolution and may generate pressure fluctuations. Phase separation starts according to the phase behaviour of CO₂‐H₂O systems in the seismically active depths of NW Bohemia and may explain the vertical distribution of the seismicity. Changes in the size of the fluid transport channels in the fault systems caused, or superimposed, by fault movements, can produce fluid pressure increases or pulses, which are the precondition for triggering fluid‐induced swarm earthquakes.     

The influence of poorly interconnected fault zone flow paths on spring geochemistry

Thermal springs commonly occur along faults because of the enhanced vertical permeability afforded by fracture zones. Field and laboratory studies of fault zone materials document substantial heterogeneities in fracture permeabilities. Modeling and field studies of springs suggest that spatial variations in permeability strongly influence spring locations, discharge rates and temperatures. The impact of heterogeneous permeability on spring geochemistry, however, is poorly documented. We present stable isotope and water chemistry data from a series of closely spaced thermal springs associated with the Hayward Fault, California. We suggest that substantial spatial variations observed in δ¹⁸O and chloride values reflect subsurface fluid transport through a poorly connected fracture network in which mixing of subsurface waters remains limited. Our measurements provide insight into the effect of fracture zone heterogeneities on spring geochemistry, offer an additional tool to intuit the nature of tectonically induced changes in fault zone plumbing, and highlight the need to consider local variations when characterizing fracture zone fluid geochemistry from spring systems with multiple discharge sites.     

Upper crustal fluid flow in the outboard region of the Southern Alps,New Zealand

The currently active fluid regime within the outboard region of the Southern Alps, New Zealand was investigated using a combination of field observations, carbon‐ and oxygen‐stable isotopes from fault‐hosted calcites and interpretation of magnetotelluric (MT) data. Active faulting in the region is dominated by NE striking and N striking, oppositely dipping thrust fault pairs. Stable isotopic analyses of calcites hosted within these fault zones range from 10 to 25‰δ¹⁸O and from ?33 to 0‰δ¹³C. These values reflect mixing of three parent fluids: meteoric water, carbon‐exchanged groundwater and minor deeper rock‐exchanged fluids, at temperatures of 10–90°C in the upper 3–4 km of the crust. A broad, ‘U‐shaped’ zone of high electrical conductivity (maximum depth c. 28 km) underlies the central Southern Alps. In the ductile region of the crust, the high‐conductivity zone is subhorizontal. Near‐vertical zones of high conductivity extend upward to the surface on both sides of the conductive zone. On the outboard side of the orogen, the conductive zone reaches the surface coincident with the trace of the active Forest Creek Faults. Near‐surface flow is shown to dominate the outboard region. Topographically driven meteoric water interacts, on a kilometre scale, with either carbon‐exchanged groundwater or directly with organic material within Pliocene gravels, resulting in a distinctive low ¹³C signal within fault‐hosted calcites of the outboard region. The high‐strain zone in the lower crust focuses the migration of deeply sourced fluids upward to the base of the brittle–ductile transition. Interconnected fluid is imaged as a narrow vertical zone of high conductivity in the upper crust, implying continuous permeability and possibly buoyancy‐driven flow of deeply sourced fluids to higher levels of the crust where they are detected by the isotopic analysis of the fault‐hosted calcites.