The application of structured‐light illumination microscopy to hydrocarbon‐bearing fluid inclusions

Structured‐light illumination (SLI)‐based microscopy offers geologists a new perspective for screening of hydrocarbon‐bearing (HCFI) and small aqueous fluid inclusion (AFI) assemblages. This optical‐sectioning technique provides rapid, confocal‐like imaging, using relatively simple and inexpensive instrumentation. The 3D fluorescent images of HCFI planes and large single HCFIs permit the visualization of the relationships between HCFI assemblages, examination of HCFI morphology, and volume estimates of the fluorescent components within HCFIs. By the use of normal white light illumination, SLI image capture, and varying acquisition time it is also possible to image AFI because of the random movements of vapour bubbles within the inclusions. This allows the near‐simultaneous visualization of hydrocarbon and AFI which is of significant importance for the study of sedimentary basins and petroleum reservoirs. SLI is a unique and accessible 3D petrographic tool, with practical advantages over conventional epifluorescence and confocal laser scanning microscopy.     

Application of fluorescence lifetime measurements on single petroleum-bearing fluid inclusions to demonstrate multicharge history in petroleum reservoirs

Petroleum-bearing fluid inclusions emit fluorescent light when excited with UV or visible light. The fluorescence decay time of the emission is dependent upon the wavelengths of the excitation and emission light, and the chemical composition of the petroleum oil. In general heavy oils have short lifetimes, whereas the emission from light oils is much longer lived. One can thus use plots of the fluorescence lifetime versus emission wavelength ( τ – λ plots), to show even subtle changes in the chemical composition of the entrapped oil. As a consequence, these τ – λ plots can be used for fluid inclusion research to discriminate different oil populations in situ . In particular, it is demonstrated that τ – λ plots discriminate two sets of inclusion oils in each of four North Atlantic basins [Jeanne d'Arc Basin (Newfoundland), Porcupine Basin (Ireland), Clair field West of Shetland (UK) and Kangerlussuaq Basin (East Greenland)] where multistage oil charge is inferred from other geological evidence.     

Diagenesis and elemental geochemistry under varying reservoir oil saturation in the Junggar Basin of NW China: implication for differentiating hydrocarbon‐bearing horizons

In this paper, we attempt to differentiate hydrocarbon‐bearing reservoir horizons of the Junggar Basin of NW China based on the characteristics of diagenesis and associated elemental geochemistry. Reservoirs at this site have varying levels of oil saturation that correlate with the degree of dissolution in minerals (e.g., calcite and feldspar). Four different horizons with varying diagenetic mineral assemblages were observed, including (i) kaolinite‐rich, oil‐dominated horizons, (ii) kaolinite–pyrite–hematite‐rich, oil–water‐dominated horizons, (iii) siderite–chlorite‐rich, water‐dominated horizons, and (iv) chlorite‐rich horizons with negligible hydrocarbon production. The mean MnO content of the representative diagenetic mineral (e.g., calcite) in each of the above horizons is >2.5, 2.0–2.5, 1.5–2.0, and <1.0 wt%, respectively. We propose that the above methodology can be used for the identification of reservoir hydrocarbon‐bearing horizons. We argue that the indicators presented here can be applied in oil exploration across the Junggar Basin.     

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.     

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     

Ancient hydrocarbon seeps from the Mesozoic convergent margin of California: carbonate geochemistry, fluids and palaeoenvironments

More than a dozen hydrocarbon seep‐carbonate occurrences in late Jurassic to late Cretaceous forearc and accretionary prism strata, western California, accumulated in turbidite/fault‐hosted or serpentine diapir‐related settings. Three sites, Paskenta, Cold Fork of Cottonwood Creek and Wilbur Springs, were analyzed for their petrographic, geochemical and palaeoecological attributes, and each showed a three‐stage development that recorded the evolution of fluids through reducing–oxidizing–reducing conditions. The first stage constituted diffusive, reduced fluid seepage (CH₄, H₂S) through seafloor sediments, as indicated by Fe‐rich detrital micrite, corroded surfaces encrusted with framboidal pyrite, anhedral yellow calcite and negative cement stable isotopic signatures (δ¹³C as low as ?35.5‰ PDB; δ¹⁸O as low as ?10.8‰ PDB). Mega‐invertebrates, adapted to reduced conditions and/or bacterial chemosymbiosis, colonized the sites during this earliest period of fluid seepage. A second, early stage of centralized venting at the seafloor followed, which was coincident with hydrocarbon migration, as evidenced by nonluminescent fibrous cements with δ¹³C values as low as ?43.7‰ PDB, elevated δ¹⁸O (up to +2.3‰ PDB), petroleum inclusions, marine borings and lack of pyrite. Throughout these early phases of hydrocarbon seepage, microbial sediments were preserved as layered and clotted, nondetrital micrites. A final late‐stage of development marked a return to reducing conditions during burial diagenesis, as implied by pore‐associated Mn‐rich cement phases with bright cathodoluminescent patterns, and negative δ¹⁸O signatures (as low as ?14‰ PDB). These recurring patterns among sites highlight similarities in the hydrogeological evolution of the Mesozoic convergent margin of California, which influenced local geochemical conditions and organism responses. A comparison of stable carbon and oxygen isotopic data for 33 globally distributed seep‐carbonates, ranging in age from Devonian to Recent, delineated three groupings that reflect variable fluid input, different tectono‐sedimentary regimes and time–temperature‐dependent burial diagenesis.     

Quantifying secondary migration efficiencies

Exploration success relies on properly risking the hydrocarbon system relevant for each prospect. Accurate risking of secondary migration efficiencies has been difficult due to lack of simple procedures that relate rock properties such as permeability and entry pressures to migration velocities, oil stringer heights and saturations. In order to achieve improved estimates of charge probabilities, equations for the secondary migration process are formulated based upon the Darcy flow and buoyancy conditions. An analytical solution of the formulated equations is shown, making it possible to construct charts for efficiently assessing the column height of secondary migration hydrocarbon stringers. The average oil (hydrocarbon) saturation of the migrating stringer can be computed, making it easy to compute the permeability related, secondary migration losses. Inputs to the chart are hydrocarbon flow‐rates and flow‐path width, hydrocarbon viscosity and density, carrier bed dip, permeability and entry pressures. Outputs are stringer heights, hydrocarbon saturation, relative permeability, migration velocities and migration losses. A procedure for including the new equations into existing basin scale fluid flow simulators is outlined and a Java applet for calculating the properties is described. The Java applet is useful for sensitivity studies, and can also be used to test results from basin simulators with the new migration efficiency equations. The analytical solution suggests that many published methods for calculating hydrocarbon migration in fluid flow simulators will over‐estimate hydrocarbon saturations and therefore losses. Calculated migration velocities will also be too low.     

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.     

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.     

The New Economics of North American Arctic Oil

Over the past five years there has been a remarkable resurgence in oil and gas exploration in the North American Arctic. From completed disinterest only a half a decade ago the region has attracted billions of dollars in new investments from a host of different international oil companies. Unlike the past booms in the region, which inevitably ended in busts, this new wave of development is different. This article examines the changes in both the Arctic itself as well as the global energy environment and concludes that the North American Arctic will see slow bust sustained development over the coming decades, ultimately becoming one of the last great oil producing regions in the world.