Modeling CO2 generation,migration, and titration in sedimentary basins

High mole fraction CO₂ gases pose a significant risk to hydrocarbon exploration in some areas. The generation and movement of CO₂ are also of scientific interest, particularly because CO₂ is an important greenhouse gas. We have developed a model of CO₂ generation, migration, and titration in basins in which a high mole fraction CO₂ gas is generated by the breakdown of siderite (FeCO₃) and magnesite (MgCO₃) where parts of the basin are being heated above approximately 330°C. The CO₂ reacts with Fe‐, Mg‐, and Ca‐silicates as it migrates upward and away from the generation zone (CO₂‐kitchen). Near the kitchen, where the Fe‐, Mg‐, and Ca‐silicates have been titrated and destroyed by previous packets of migrating CO₂, gas moves upward without lowering its CO₂ mole fraction. Further on, where Fe‐ and Mg‐silicates are still present but Ca‐silicates are absent in the sediments, the partial pressure of CO₂ is constrained to 0.1–30 bars and reservoirs contain a few mole percent CO₂ as described by Smith & Ehrenberg (1989) . Still further from the source, where Ca‐silicates have not been titrated, partial pressure of CO₂ in migrating methane gas are orders of magnitude lower. A 2D numerical model of CO₂ generation, migration, and titration quantifies these buffer relations and makes predictions of CO₂ risk in the South China Sea that are compatible with exploration experience. Reactive CO₂ transport models of the kind described could prove useful in determining how gases migrate in faulted sedimentary basins.     

Timescales for reaching steady-state fluid flow in systems perturbed by formation of highly permeable faults

We consider the case of an isothermal, fluid‐saturated, homogeneous rock layer with transverse fluid flow driven by an imposed constant fluid pressure gradient. A rupture in the centre of the rock layer generates a highly permeable fault and results in a change of the initially homogeneous permeability distribution. This leads to a perturbation of the fluid flow field and its gradual transition to a new steady‐state corresponding to the new permeability distribution. An examination of this transitional process permits us to obtain an analytical estimation of the transition stage duration. The application of the results obtained to km‐scale faults in crystalline rock bodies leads to the conclusion that the evolution of the fluid velocity field is rather rapid compared with geological timescales.     

Maintaining high fluid pressures in older sedimentary basins

High fluid pressures in old geologic basins, where the mechanisms that generate high fluid pressure have ceased to operate, pose the problem of how high fluid pressures are maintained through geologic time. Recent oil and gas exploration reveals that low permeability shales, the source beds for oil and gas, contain large quantities of gas that are now being exploited in many sedimentary basins in North America. No earlier analyses of how to maintain high fluid pressure in older sedimentary basins included a shale bed as a source of adsorbed gas; this is a new conceptual element that will fundamentally change the analysis. Such a large fluid source can compensate for a low rate of bleed off in a dynamic system. If the fluid source is large enough, as the gas within these shale source beds appears to be, there will no appreciable drop in pressure accompanying a low rate of leakage from the basin for long periods. For the dynamic school of basin analysts this may provide the missing piece in the puzzle, explaining how high fluid pressures are maintained for long periods of geologic time in a crust with finite, non-zero permeability. This is a hypothesis which needs to be tested by new basin analyses.     

Potential of palaeofluid analysis for understanding oil charge history

Fluid inclusion data, particularly the distribution of hydrocarbon fluid inclusions and their chemistry, can provide insights into oil charge in a petroleum-prospective region. Examples from the UK Atlantic margin show how we can understand thermal regime, timing and chemistry of oil charge. Data from the UK Atlantic margin based on fluid inclusion temperature profiles shows anomalously high temperatures which are highest at the top of the Triassic–Eocene sequence. This is interpreted as a product of hot fluid flow, probably reflecting hydrothermal activity related to intrusion of sills at depth. The preservation of high temperatures also implies rapid migration from depth through fracture systems. Ar–Ar analysis of oil-bearing K-feldspar cements, and petrographic studies of oil inclusion distribution help delimit timing and migration pathways for the hot fluid charge and later fluid migration events. Coupled with compositional data for oils measured destructively (organic geochemistry) or non-destructively (fluorescence), these approaches allow the development of oil charge histories based on real data rather than theoretical modelling.     

Migration of Mn-rich fluids through normal faults and fine-grained terrigenous sediments during early development of the Neogene Vallès-Penedès half-graben (NE Spain)

The Miocene siliciclastic sediments infilling the Vallès‐Penedès half‐graben are affected by two sets of structures developed during the extensional tectonics that created the basin. The first set, represented by extension fractures infilled with mud and sands, is attributed to seismically induced liquefaction. The second set, represented by normal faults, corresponds to a high‐permeability horsetail extensional fracture mesh developed near the surface in the hanging walls of normal faults. The incremental character of the vein‐fills indicates episodic changes in the tectonic stress state and fault zone permeability. Two episodes of fluid migration are recorded. The first episode occurred prior to consolidation and lithification when shallow burial conditions allowed oxidizing meteoric waters to flow horizontally through the more porous and permeable sandy layers. Development of clastic dikes allowed local upward flow and dewatering of the sandy beds. Liquefaction and expulsion of fluids were probably driven by seismic shaking. During the first episode of fluid migration there was no cementation of the sandstone or within the fractures, probably because little fluid was mobilized by the predominantly compaction‐driven flow regime. The second episode of fluid migration occurred synchronously with normal fault development, during which time the faults acted as fluid conduits. Fluids enriched in manganese, probably leached from local manganese oxyhydroxides soon after sedimentation, moved laterally and produced cementation in the sandstone layers, eventually arriving at the more porous and permeable fault pathways that connected compartments of different porosities and permeabilities. Carbonate probably precipitated in fractures saturated with meteoric water near the ground surface at a transitional redox potential. Once the faults became occluded by calcite cement, shortly after fault development, they became barriers to both vertical and horizontal fluid flow.     

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.     

Modeling fluid flow in a heterogeneous, fault-controlled hydrothermal system

Previous studies have shown that most hydrothermal systems discharging at the land surface are associated with faulting, and that the location, temperature and rate of discharge of these systems are controlled by the geometry and style of the controlling fault(s). Unfortunately, the transport of heat and fluid in fault-controlled hydrothermal systems is difficult to model realistically; although heterogeneity and anisotropy are assumed to place important controls on flow in faults, few data or observations are available to constrain the distribution of hydraulic properties within active faults. Here, analytical and numerical models are combined with geostatistical models of spatially varying hydraulic properties to model the flow of heat and fluid in the Borax Lake fault of south-east Oregon, USA. A geometric mean permeability within the fault of 7 × 10⁻¹⁴ m² with 2× vertical/horizontal anisotropy in correlation length scale is shown to give the closest match to field observations. Furthermore, the simulations demonstrate that continuity of flow paths is an important factor in reproducing the observed behavior. In addition to providing some insight into possible spatial distributions of hydraulic properties at the Borax Lake site, the study highlights one potential avenue for integrating field observations with simulation results in order to gain greater understanding of fluid flow in faults and fault-controlled hydrothermal and petroleum reservoirs.     

Downward hydrocarbon migration predicted from numerical modeling of fluid overpressure in the Paleozoic Anticosti Basin,eastern Canada

The Anticosti Basin is a large Paleozoic basin in eastern Canada where potential source and reservoir rocks have been identified but no economic hydrocarbon reservoirs have been found. Potential source rocks of the Upper Ordovician Macasty Formation overlie carbonates of the Middle Ordovician Mingan Formation, which are underlain by dolostones of the Lower Ordovician Romaine Formation. These carbonates have been subjected to dissolution and dolomitization and are potential hydrocarbon reservoirs. Numerical simulations of fluid‐overpressure development related to sediment compaction and hydrocarbon generation were carried out to investigate whether hydrocarbons generated in the Macasty Formation could migrate downward into the underlying Mingan and Romaine formations. The modeling results indicate that, in the central part of the basin, maximum fluid overpressures developed above the Macasty Formation due to rapid sedimentation. This overpressured core dissipated gradually with time, but the overpressure pattern (i.e. maximum overpressure above source rock) was maintained during the generation of oil and gas. The downward impelling force associated with fluid‐overpressure gradients in the central part of the basin was stronger than the buoyancy force for oil, whereas the buoyancy force for gas and for oil generated in the later stage of the basin is stronger than the overpressure‐related force. Based on these results, it is proposed that oil generated from the Macasty Formation in the central part of the basin first moved downward into the Mingan and Romaine formations, and then migrated laterally up‐dip toward the basin margin, whereas gas throughout the basin and oil generated in the northern part of the basin generally moved upward. Consequently, gas reservoirs are predicted to occur in the upper part of the basin, whereas oil reservoirs are more likely to be found in the strata below the source rocks. Geofluids (2010) 10 , 334–350     

Relationship between deformation bands and petroleum migration in an exhumed reservoir rock,Los Angeles Basin,California, USA

An oil‐bearing sandstone unit within the Monterey Formation is exposed in the Los Angeles Basin along the Newport‐Inglewood fault zone in southern California. The unit preserves structures, some original fluids, and cements that record the local history of deformation, fluid flow, and cementation. The structures include two types of deformation bands, which are cut by later bitumen veins and sandstone dikes. The bands formed by dilation and by shear. Both types strike on average parallel to the Newport‐Inglewood fault zone (317°–332°) and show variable dip angles and directions. Generally the older deformation bands are shallow, and the younger bands are steep. The earlier set includes a type of deformation band not previously described in other field examples. These are thin, planar zones of oil 1–2 mm thick sandwiched between parallel, carbonate‐cemented, positively weathering ribs. All other deformation bands appear to be oil‐free. The undeformed sandstone matrix also contains some hydrocarbons. The oil‐cored bands formed largely in opening mode, similar to dilation bands. The oil‐cored bands differ from previously described dilation bands in the degree of carbonate cementation (up to 36% by volume) and in that some exhibit evidence for plane‐parallel shear during formation. Given the mostly oil‐free bands and oil‐rich matrix, deformation bands must have formed largely before the bulk of petroleum migration and acted as semi‐permeable baffles. Oil‐cored bands provide field evidence for early migration of oil into a potential reservoir rock. We infer a hydrofracture mechanism, probably from petroleum leaking out of a stratigraphically lower overpressured reservoir. The deformation bands described here provide a potential field example of a mechanism inferred for petroleum migration in modern systems such as in the Gulf of Mexico.     

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.     

Factors affecting fluid flow in strike–slip fault systems: coupled deformation and fluid flow modelling with application to the western Mount Isa Inlier, Australia

Deformation and focused fluid flow within a mineralized system are critical in the genesis of hydrothermal ore deposits. Dilation and integrated fluid flux due to coupled deformation and fluid flow in simple strike–slip fault geometries were examined using finite difference analysis in three dimensions. A series of generic fault bend and fault jog geometries consistent with those seen in the western Mount Isa Inlier were modelled in order to understand how fault geometry parameters influence the dilation and integrated fluid flux. Fault dip, fault width, bend/jog angle, and length were varied, and a cross-cutting fault and contrasting rock types were included. The results demonstrate that low fault dips, the presence of contrasts in rock type, and wide faults produce highest dilation and integrated fluid flux values. Increasing fault bend lengths and angles increases dilation and integrated fluid flux, but increasing fault jog length or angle has the opposite effect. There is minimal difference between the outputs from the releasing and restraining fault bend and jog geometries. Model characteristics producing greater fluid flows and/or gradients can be used in a predictive capacity in order to focus exploration on regions with more favorable fault geometries, provided that the mineralized rocks had Mohr–Coulomb rheologies similar to the ones used in the models.     

The application of failure mode diagrams for exploring the roles of fluid pressure and stress states in controlling styles of fracture-controlled permeability enhancement in faults and shear zones

Permeability enhancement associated with deformation processes in faults and shear zones plays a key role in facilitating fluid redistribution between fluid reservoirs in the crust. Especially in high fluid flux hydrothermal systems, fracture-controlled permeability can be relatively short-lived, unless it is repeatedly regenerated by ongoing deformation. Failure mode diagrams in pore fluid factor and differential stress space, here termed λ–σ failure mode diagrams, provide a powerful tool for analysing how fluid pressure and stress states drive failure, associated permeability enhancement and vein styles during deformation in faults and shear zones. During fault-valve behaviour in the seismogenic regime, relative rates of recovery of pore fluid factor, differential stress and fault cohesive strength between rupture events impact on styles of veining and associated, fracture-controlled permeability enhancement in faults and shear zones. Examples of vein-rich fault zones are used to illustrate how constraints can be placed, not just on fluid pressure and stress states at failure, but also on the fluid pressurization and loading paths associated with failure and transitory permeability enhancement in faults and shear zones. This provides insights about when, during the fault-valve cycle, various types of veins can form. The use of failure mode diagrams also provides insights about the relative roles of optimally oriented faults and misoriented faults as hydraulically conductive structures. The analysis highlights the dynamics of competition between fluid pressures and loading rates in driving failure and repeated permeability regeneration in fracture-controlled, hydrothermal systems.     

Experimental study of the effect of variation in in‐situ stress on capillary residual trapping during CO2 geo‐sequestration in sandstone reservoirs

During a geo‐sequestration process, CO₂ injection causes an increase in reservoir pore pressure, which in turn decreases the reservoir net effective stress. Changes in effective stress can change all the reservoir and cap‐rock properties including residual saturations. This article presents the results of an experimental work carried out to understand the potential change in the volumes of residually trapped CO₂, while the porous medium tested underwent change in the net effective stress under in‐situ reservoir conditions of pore pressure and temperature. The experimental results obtained show that an initial 1725 psi (11.9 MPa) decrease in the net effective pressure caused 1.4% reduction in the volumes of residually trapped CO₂, while another 1500 psi (10.3 MPa) reduction caused a further 3.2% drop in the residual saturation of CO₂.     

Fluids and halogens at the diagenetic–metamorphic boundary: evidence from veins in continental basins, western Norway

Seven vein types are recognized in three continental Devonian molasse basins (the Hornelen, Kvamshesten and Solund basins) in western Norway. These include calcite‐, quartz‐ and epidote‐dominated veins. The salinities of fluid inclusions from quartz‐dominated veins in the Hornelen and Kvamshesten basins are close to or slightly higher than those for modern seawater, whereas the fluids from quartz‐ and calcite‐dominated veins in the Solund basin range from seawater values to 20 wt % NaCl equivalent. Minerals such as biotite, amphibole, titanite, chlorite and epidote are abundant in the latter veins, and are important constituents of the authigenic mineral assemblages. A combination of fluid inclusion and petrological data suggest that at least some of the veins formed at depths around 12–14 km. The Cl/Br ratios and the salinity of the fluid inclusions can be explained by interactions with evaporites, implying that the sedimentary environment forming the basin fill had the strongest influence upon low‐grade metamorphic fluid Cl and Br contents. Differences in the Cl/I and Na/Br ratios between the Solund basin and the Hornelen and Kvamshesten basins are best explained by local mass transfer between pore fluids and the surrounding rock matrix during burial and increasing temperatures.     

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.     

Generation and accumulation of oil and condensates in the Wenchang A Sag, western Pearl River Mouth Basin, South China Sea

The Pearl River Mouth (PRM) Basin is one of four Cenozoic basins in the South China Sea, and the Wenchang A Sag is a secondary depression in the western part of the basin. Both the Wenchang and Enping formations contain good source rocks in the western PRM Basin; however, only the latter has been considered a likely source of the discovered oil and gas. New data from fluid inclusions and the analysis of oil–source rock correlations for the WC10-3 oil and gas pools indicate two stages of petroleum charging, the earlier originating from the Wenchang Formation and the later from the Enping Formation. Kinetics of petroleum generation and structural evolution modeling were employed to further investigate the mechanism of formation of the WC10-3 oil and gas pools. It was shown that the crucial condition for the formation of pools is the time of development of the structural trap. The Wenchang Formation source rocks generated oil from 25 to 14 Ma in the possible source area of the WC10-3 oil and gas pools in the Wenchang A Sag, so that only traps formed earlier than this period could capture oil sourced by the Wenchang Formation. The Enping Formation source rock experienced its oil window from 18 Ma to the present with the main stage of oil generation from 15 to 5 Ma. During this period structural traps in the sag continued to form until movements became weak, so that most pools in the Wenchang A Sag originated from the Enping Formation source rock. The likely dissipation of oil and gas from the earlier stage of charging should be taken into account in assessing the oil potential of the Wenchang A Sag.