Hydrocarbon-bearing Fluid Inclusions Research Articles

Syn-tectonic fluid-flow and fault-fluid interaction along bedding-parallel thrust faults: Evidence from the frontal zone of the Chuandong-Xiangexi fold-and-thrust belt in central South China

Fluid-flow within tectonic belts and fault-fluid interaction are fundamental and controlling factors of large thrust belt evolutions, formation of mineral deposits in the upper crust and the ductile shear deformation in the middle crust. In central South China, a large Chuandong-Xiangexi fold-and-thrust belt and long-distance displaced thrust faulting are developed, but their formation mechanism is still in debate. In particular, the evolution of fluid-flow and fault-fluid interactions in this fold-and-thrust belt is still not well constrained. In this study, through detailed structural and microstructural observations together with stable isotope and fluid inclusion analyses, we aim to unravel the deformation characteristics and syn-tectonic fluid-flow along the detachment in the frontal zone of this fold-and-thrust belt. One approximately 30–60 m thick, NW-verging detachment thrust with brittle-ductile deformation and alternating the strongly and weakly deformed zones is identified in the Lower Permian bioclastic and argillaceous limestones. The strongly deformed zone is characterized by tectonic lenses, fault gouge, calcite veins, S–C fabric, and foliated fault rocks/gouge, while the weak deformation zone is marked by scattered fractures without calcite veins and weakly deformed tectonic lenses. The fluids within the thrust faults originate from formation waters (saline fluids or brines) in a closed system, evidenced by the δ18O values, the 87Sr/86Sr ratios, the hydrocarbon-bearing fluid inclusions characterized by moderate salinity (10–14 wt% NaClequiv.) and moderate-high homogenization temperatures (∼160–350 °C). In the hanging wall of the Huangyingshan fault, the fluids involved in the thrusting processes are most likely brines derived from Middle and Lower Triassic carbonate aquifers. While in the footwall, the fluids are likely brines derived from Cambrian evaporitic aquifers. These findings on the detachment thrust fault zone could provide valuable constraints on the conduit and distance of hydrocarbon secondary migration for exploring the potential of large-scale hydrocarbon accumulation in the Chuandong-Xiangexi fold-and-thrust belt.

Raman Spectroscopic Technique to Distinguish Constituents of Hydrocarbon-Bearing Fluid Inclusions of Kerala-Konkan Basin, Western offshore, India

Fluid inclusion studies have a great diversity of applications in exploration geology and are necessary tools in the determination of palaeotemperature and nature of fluids associated with the rocks in a basin. Using various fluid inclusion techniques such as petrography, microthermometry and Laser Raman Spectroscopy of fluid inclusions with Hydrocarbon fluid inclusions (HCFIs) help us to understand the generation potential of the basin. The representative micron sized fluid inclusions that intruded into the different geological formations of the KK-4C-A1well drilled by Oil and Natural Gas Corporation in Kerala-Konkan Basin, India has been selected for this study. Petrographic analyses confirm the presence of HCFIs with the help of Ultraviolet (UV) light. Raman spectra of HCFIs identified in different formations were examined. The temperature of homogenization (Th) obtained through microthermometric analysis of the fluid inclusions indicate the palaeotemperature of the sedimentary rock units. Coeval-aqueous inclusions associated to HCFIs show Th within the oil window range 60-140oC, indicating a temperature favourable for oil generation in Kerala-Konkan Basin (K-K Basin).Characterisation of hydrocarbon bearing fluid inclusions were carried out using Raman spectroscopy. HCFIs were observed in the annealed micro-cracks of Cannanore (Early Miocene), Calicut (Early Oligocene) formation (Type I) and Kasaragod (Palaeocene to Early Eocene) Formation (Type II), might get trapped along the micro-fracture by re-healing process. Laser Raman study could decipher hydrocarbon species such as Alkanes, SO2, COS, H2S, etc. Keywords: Hydrocarbon Fluid Inclusions, Oil Window Temperature, Raman Spectroscopy, Kerala-Konkan Basin

Fluid inclusion studies to determine the paleotemperature and hydrocarbon quality in petroliferous basins

Hydrocarbon bearing fluid inclusions (HCFIs) along with the coeval aqueous inclusions could be utilized in petroleum exploration industry for determining the paleotemperature and American Petroleum Institute's (API) gravity of oils in a basin. These parameters can indirectly yield a quick assessment on the hydrocarbon quality in a basin. Here we use fluid inclusion data as a tool to study the paleotemperature and hydrocarbon quality of two offshore basins in India (dry wells from a proven basin and non-proven basin). Towards this objective, temperature of homogenization (Th) of coeval aqueous fluid inclusion, assemblages seen associated with HCFIs and fluorescence emission features of oils in HCFIs were studied. Depthwise comparison of two basins studied are accorded with the microthermometrically obtained Th data and spectroscopically determined (fluorescence) API gravity values that gives an estimation of the paleotemperature and hydrocarbon quality. The Th and, fluorescence emission features of oils in HCFIs (leads to API gravity) presented allow us to make a qualitative assessment of oils in these basins. This study brings out the potential information stored in HCFIs/adjacent brine fluid inclusions, as a tool for determining the paleotemperature and API gravity of oils in petroliferous basins.

Calcite vein system and its importance in tracing paleowater flow and hydrocarbon migration in the Ordovician carbonates of the Tazhong area, Tarim Basin, China

It is difficult to determine flow pathways of paleofluids in sedimentary basins. Petrography, fluid inclusion, and isotopic compositions from different phases of calcite veins in the Ordovician in the Tazhong area were studied. Our results reveal a complex diagenesis process with two importantly crossformational fluid movements, coupled with three phases of calcite veins (C1, C2, and C3) precipitation and thermochemical sulfate reduction by hydrocarbons. Fluids that precipitated C2 and C3 calcites were saline and enriched in 18O and thus may have originated from underlying evaporates, whereas fluid that precipitated C3 had an additional contribution from 87Sr-rich, Ba-rich, and Zn-rich Precambrian basinal clastic units. Fluid inclusion homogenization temperatures, salinities, and δ18Owater values of C2 veins show decreasing trends with increasing distances from strike-slip faults. This may indicate that C2 fluid might migrate into Ordovician carbonate reservoirs through strike-slip faults within 6 km during late Hercynian orogeny (late Permian). The similarly decreasing trends are observed in C3 veins, indicating that the eastern part of No. 1 fault seemed to be the main fluid-flow pathway for C3 calcite precipitation during Himalayan orogeny. Hydrocarbon may have migrated along the similar pathways as supported by (1) abundant primary hydrocarbon-bearing fluid inclusions in the C2 and C3 calcites and (2) well-documented hydrocarbon migration and mixing. This is an ideal case showing how spatial variation in geochemical data from fracture fillings can be used to trace paleowater and likely hydrocarbon flows in sedimentary basins; it thus may be useful in predicting fluid flow and distribution of hydrocarbons in the Tarim Basin and other basins.

New insights into marine hydrocarbon geological conditions in the South Yellow Sea Basin: evidence from borehole CSDP-2

The South Yellow Sea Basin (SYSB) has multiple sets of proven source rocks and good hydrocarbon prospects, but no industrial oil and gas has been explored at present. To solve this puzzle for petroleum geologists, we systematically investigated the marine hydrocarbon geological conditions based on cores and testing data from borehole CSDP-2, the first exploration well with continuous coring in SYSB. The qualities of source rocks are evaluated in detail according to organic matter abundance, type, and maturity. The reservoir characterization mainly includes porosity, permeability, and reservoir space. Displacement pressure test and stratum thickness are the main foundations for defining the caprocks. Then, the oil-source rock correlation in the Permian and stratum model are analyzed to determine the favorable source-reservoir-caprock assemblages. The results show that three sets of effective source rocks (the Lower Triassic, Upper Permian, and Lower Permian), two sets of tight sandstone reservoirs (the Upper Permian and Lower Silurian-Upper Devonian), and two sets of caprocks (the Lower Triassic and Carboniferous) combine to constitute the hydrocarbon reservoir-forming assemblages of “lower-generation and upper-accumulation” and “self-generation and self-accumulation”, thus laying a solid foundation for promising petroleum prospects. The three sets of marine source rocks are characterized by successive generation and expulsion stages, which guarantees multistage hydrocarbon accumulation. Another three sets of continental source rocks distributed across the Middle Jurassic, Upper Cretaceous, and Paleogene depression areas, especially in the Northern Depression, may supplement some hydrocarbons for the Central Uplift through faults and the Indosinian unconformity. The favorable Permian exploration strata have been identified in the Central Uplift of SYSB. First, the Lower Permian and Upper Permian source rocks with high organic matter abundance and high thermal maturity supply sufficient hydrocarbons. Secondly, the interbedding relationship between the source rocks and sandstones in the Upper Permian strata ensures that hydrocarbons have been migrated into the nearby Upper Permian sandstones, reflecting near-source hydrocarbon accumulation. Finally, the good sealing property of the Lower Triassic Qinglong Formation caprocks plays an indispensable role in hydrocarbon preservation of the Permian reservoirs. This conclusion is supported by direct oil shows, gas logging anomalous layers, and hydrocarbon-bearing fluid inclusions.

Chemical and isotopic analyses of hydrocarbon-bearing fluid inclusions in olivine-rich rocks

We examined the mineralogical, chemical and isotopic compositions of secondary fluid inclusions in olivine-rich rocks from two active serpentinization systems: the Von Damm hydrothermal field (Mid-Cayman Rise) and the Zambales ophiolite (Philippines). Peridotite, troctolite and gabbroic rocks in these systems contain abundant CH4-rich secondary inclusions in olivine, with less abundant inclusions in plagioclase and clinopyroxene. Olivine-hosted secondary inclusions are chiefly composed of CH4 and minor H2, in addition to secondary minerals including serpentine, brucite, magnetite and carbonates. Secondary inclusions in plagioclase are dominated by CH4 with variable amounts of H2 and H2O, while those in clinopyroxene contain only CH4. We determined hydrocarbon abundances and stable carbon isotope compositions by crushing whole rocks and analysing the released volatiles using isotope ratio monitoring-gas chromatography mass spectrometry. Bulk rock gas analyses yielded appreciable quantities of CH4 and C2H6 in samples from Cayman (4-313 nmol g-1 CH4 and 0.02-0.99 nmol g-1 C2H6), with lesser amounts in samples from Zambales (2-37 nmol g-1 CH4 and 0.004-0.082 nmol g-1 C2H6). Mafic and ultramafic rocks at Cayman exhibit δ13CCH4 values of -16.7‰ to -4.4‰ and δ13CC2H6 values of -20.3‰ to +0.7‰. Ultramafic rocks from Zambales exhibit δ13CCH4 values of -12.4‰ to -2.8‰ and δ13CC2H6 values of -1.2‰ to -0.9‰. Similarities in the carbon isotopic compositions of CH4 and C2H6 in plutonic rocks, Von Damm hydrothermal fluids, and Zambales gas seeps suggest that leaching of fluid inclusions may provide a significant contribution of abiotic hydrocarbons to deep-sea vent fluids and ophiolite-hosted gas seeps. Isotopic compositions of CH4 and C2H6 from a variety of hydrothermal fields hosted in olivine-rich rocks that are similar to those in Von Damm vent fluids further support the idea that a significant portion of abiotic hydrocarbons in ultramafic-influenced vent fluids is derived from fluid inclusions. This article is part of a discussion meeting issue 'Serpentinite in the Earth system'.

Characteristics of fluid inclusions and implications for the timing of hydrocarbon accumulation in the cretaceous reservoirs, Kelasu Thrust Belt, Tarim Basin, China

Abstract The Kelasu Thrust Belt is a key area for oil and gas exploration within the Tarim Basin of China, an area containing abundant oil and gas resources but where the processes that controlled hydrocarbon accumulation remain unclear. This study reconstructs the accumulation history of hydrocarbons within the Kelasu Thrust Belt by studying multiple sets of fluid inclusions from the Cretaceous reservoirs using laser Raman, infrared spectroscopy, fluorescence spectroscopy, total scanning fluorescence, and PTV simulation analyses. The resulting data yield the following results. (1) Three types of Cretaceous hydrocarbon-bearing fluid inclusions are present, and they record three periods of hydrocarbon accumulation. Period I involved low-maturity medium oil as recorded by the presence of yellow–green fluorescent oil inclusions, with this accumulation occurring between the Neogene Jidike and Kangcun stages (20–5 Ma). Period II involved high-maturity light oils (or condensates) that are recorded by the presence of blue–white fluorescent oil inclusions, with this accumulation occurring during the early Kuche stage (5–2.5 Ma). Period III involved the significant accumulation of gas, as recorded by non-fluorescent gas inclusions, during and after the late Kuche stage (2.5–0 Ma). (2) Inclusion PVT simulations indicate that the pressures during the trapping of oil inclusions within the west Kelasu reservoirs increase with increasing capture temperature, suggesting that west Kelasu Cretaceous oil reservoirs formed over a short period of time. In contrast, the trapping pressures of oil inclusions within the east Kelasu area are invariant with increasing trapping temperature, indicating that the formation of east Kelasu Cretaceous oil reservoirs was a relatively slow and gradual process. This most likely relates to the fact that the east Kelasu reservoirs are close to the hydrocarbon generation centre in an area with sufficient hydrocarbon supply, with hydrocarbon accumulation processes involving all of the stages of hydrocarbon generation recorded by the source rocks in this area. In comparison, the west Kelasu reservoirs are far from the hydrocarbon generation centre and as such record only one phase of oil filling. (3) Significant tectonism associated with the uplift of the South Tianshan Mountain during the late Kuche stage caused widespread changes to Cretaceous paleo-oil reservoirs in this area. This led to some Cretaceous paleo-oils being transported to shallower traps to form secondary oil reservoirs, whereas others were transported to the surface and were lost, with residual paleo-oils were also changed to condensate gas as a result of gas washing after the addition of large amounts of late-stage gas.

The role of hydrocarbons in ore formation at the Pillara Mississippi Valley-type Zn-Pb deposit, Canning Basin, Western Australia

Hydrocarbons have been suggested previously to play a role as reducing agents for in-situ sulfate reduction — one of several key components of the model proposed for ore formation in Mississippi-Valley-Type (MVT) deposits. Here, we provide direct evidence for hydrocarbon-brine interaction occurring synchronous to ore formation at the Pillara MVT deposit, through the analysis of brine and composite brine-hydrocarbon fluid inclusions by LA-ICP-MS combined with thermodynamic and reactive transport modeling. The occurrence of coeval primary hydrocarbon and brine inclusions in ore-stage calcite and sphalerite implicates the co-existence of hydrocarbons and brine at the time of ore formation. Elevated average concentrations (± 1σ) of 147 ± 141 ppm Zn, 53 ± 64 ppm Pb, 38 ± 36 ppm Cu and 11 ± 9 ppm Ag were measured in brine end member fluid inclusions. Hydrocarbon-bearing fluid inclusions are enriched several orders of magnitude in metal concentrations compared to the brine end member fluid inclusions. The analyzed fluid inclusion assemblages combined with numerical reactive transport simulations indicate that an oxidized acid-sulfate brine, which leached its metals from feldspathic sandstones in the deeper basin, represents a thermodynamically stable ore fluid. Interaction with feldspathic sandstones, granitic basement rocks and/or carbonates, and neutralization of pH, did not affect the Pb and Zn transport capabilities of the fluid. These findings indicate that Pb and Zn can be transported over long distances through carbonate-rich rocks, even though the original ore fluid may have been an acidic brine. The controlling factor for metal deposition at Pillara and similar MVT deposits can be related to the presence of hydrocarbons, permitting in-situ sulfate reduction and precipitation of sphalerite, galena, Ag and Cu sulfides.

Advances in 3D imaging and volumetric reconstruction of fluid and melt inclusions by high resolution X-ray computed tomography

Fluid and melt inclusions are tiny pockets of fluid and melt trapped in natural and synthetic minerals. Characterizing the 3D distribution of fluid and melt inclusions within minerals, their shape and the volume fraction of their different phases is crucial for determining the conditions of crystal growth and paleostress analysis. However, their relatively small size (typically 5 to 100 μm), complex shape, heterogeneous content, the opaque nature of some host minerals and projection bias frequently hamper accurate imaging and volumetric reconstruction using conventional microscopic techniques. High resolution X-ray computed tomography (HRXCT) is a non-destructive method which uses contrasts of X-ray attenuation in a series of contiguous radiographs with different view angles to reconstruct the 3D distribution of areas of different densities within a large variety of materials. In this work, we show the capabilities of HRXCT for: (i) imaging the 3D distribution of aqueous and hydrocarbon-bearing fluid inclusions and silicate melt inclusions in a crystal; (ii) characterizing the shape of fluid and melt inclusions and (iii) reconstructing the total volume and the volume of the different phases (liquid, glass, crystal, vapor) of fluid and melt inclusions. We have used a variety of hand specimens and chips of transparent and opaque minerals (olivine, quartz, feldspar, garnet, emerald, wolframite), that we analyzed using three different HRXCT setups. When a resolution of ~1 μm3/voxel is achieved, HRXCT allows identifying >5 μm fluid inclusions, and the identification and volumetric reconstruction of the different phases can be carried out with reasonable confidence for relatively large (>25 μm) inclusions. Density contrasts are high enough to properly identify: (i) a silicate melt inclusion, and its different phases (glass, vapor and crystals such as clinopyroxene and spinel) in an olivine crystal; (ii) aqueous monophase (liquid) and two-phase (liquid + vapor) fluid inclusions in transparent and opaque minerals (quartz, garnet, emerald, wolframite). In the case of hydrocarbon-bearing fluid inclusions containing a vapor phase and two liquid phases (oil and aqueous solution), the two liquid phases could not be distinguished from each other. Volumetric reconstruction of liquid and vapor phases of aqueous and hydrocarbon-bearing fluid inclusions show compatible results with independent calculations using known pressure, temperature, molar volume and composition (P-T-V-x) conditions of trapping or imaging using confocal laser scanning microscopy respectively. Collectively, our results show that HRXCT is a promising tool for non-destructive characterization of fluid and melt inclusions.

Quartz-Amethyst Hosted Hydrocarbon-Bearing Fluid Inclusions from the Green Ridge Breccia in the Snoqualmie Granite, North Cascades, WA, USA

The Green Ridge Breccia cuts the composite Miocene Snoqualmie Batholith in King County, WA, USA. The granite was emplaced at ~5 km depth between ~17 and 20 Ma and the crosscutting NW trending breccia contains large angular blocks of the host granite (<1 m in longest dimension). The brecciated granite blocks are cemented by quartz-amethyst euhedra (<10 cm in longest dimension) bearing vugs. A notable feature is the presence of centimetric scale amber coloured oil inclusions within the quartz-amethyst crystals. Fluid inclusion studies using Transmitted Light Petrography, UV Microscopy, Microthermometry, Laser Raman Microspectroscopy and Gas Chromatography-Mass Spectrometry record the presence and the fluid composition of three fluid inclusion types hosted by the euhedra: primary Type 1 (liquid rich two-phase (L + V) aqueous inclusions) and secondary Type 2 bituminous two-phase (S + L) inclusions and Type 3 amber coloured oil bearing two-phase immiscible liquid inclusions. The Green Ridge Breccia was the locus for convective hydrothermal fluid flow that formed the quartz-amethyst vugs formed at T~390 °C assuming a trapping pressure of ~1.65 kb. Later, hydrocarbon fluids migrated downwards from the roof source rock (e.g., the Guye Sedimentary Member) and were trapped in the euhedra. This was followed by unroofing of the batholith and exposure of the Green Ridge Breccia. This study highlights the potential for other oil migrations into the Snoqualmie Batholith in areas where it forms the basement capped by the Guye Sedimentary Member.

The Use of Integrated Fluid Inclusion Studies for Constraining Petroleum Charge History at Parsons Pond, Western Newfoundland, Canada

This study, based on fluid inclusion petrography, microthermometry and ultraviolet microspectroscopy of inclusion oil, investigates the petroleum charge history at Parsons Pond, western Newfoundland. To address this matter, drill core and cuttings samples of allochthonous and autochthonous strata in the Parson’s Pond area were collected from three exploration wells. Fluid inclusions were examined from fragments of calcite and quartz veins, diagenetic cements in sandstone, and in large hydrothermal dolomite and calcite crystals. Primary aqueous inclusions in authigenic sandstone cements indicate that cementation occurred at relatively shallow depths and low temperatures (<50 °C). Hydrocarbon-bearing fluid inclusions (petroleum, wet gas and gas) are generally restricted to calcite and quartz veins, indicating that petroleum and gas migration at Parson’s Pond is fracture-controlled. No hydrocarbons were observed in the diagenetic cements of the essentially tight sandstones. Fluid inclusion microthermometry and ultraviolet microspectroscopy indicate the presence of multiple generations of hydrocarbon fluid, ranging in composition from ~33 API gravity petroleum to pure CH4. Petrographic evidence suggests that hydrocarbons were generated multiple times during progressive burial and heating. In addition, the distribution of hydrocarbon bearing inclusions with depth suggests that deeper levels are gas-prone, with petroleum confined to relatively shallow depths. Although only gas flow was encountered during the drilling of exploration wells at Parson’s Pond, the presence of petroleum-bearing fluid inclusions in calcite and quartz veins indicates that the historical production from shallow wells in the Parsons Pond area likely tapped small reservoirs of fractured petroliferous strata.

Feasibility of a 785 nm diode laser in Raman spectroscopy for characterizing hydrocarbon-bearing fluid inclusions in Mumbai Offshore Basin, India

Detection of the chemical constituents of hydrocarbons in the hydrocarbon-bearing fluid inclusions in diagenetic mineral cements, secondary fractures and overgrowths could be a useful indicator of the nature of oil in a basin. Microscope-based Raman spectroscopy is a non-destructive, optical vibrational spectroscopic technique that can precisely isolate and analyse hydrocarbon fluid inclusions (HCFIs). The main challenge with Raman spectral studies on natural HCFIs is the common presence of fluorescence emission from minerals and aromatic compounds in HCFIs leading to the masking of Raman signals. The present study is a demonstration of how best the Raman signals from natural hydrocarbon-bearing fluid inclusions could be detected using an excitation wavelength of 785 nm with suitable optical parameters and with special wafer preparation techniques to negate the background fluorescence. Using the laser Raman technique we were able to detect peaks corresponding to cyclohexane (786 and 3245 cm −1 ), benzene and bromobenzene (606, 1010, 1310, 1486 and 1580 cm −1 ), carbon monoxide (2143 cm −1 ), nitrogen (2331 cm −1 ), ethylene (1296 cm −1 ), sulphur oxide (524 cm −1 ), carbonyl sulphide (2055 cm −1 ), hydrogen sulphide in liquid form (2580 cm −1 ) along with the presence of a broad peak of liquid water at 3100–3500 cm −1 , peaks of calcium carbonate (710, 854 cm −1 ) and calcium sulphate (1135 cm −1 ). The study samples were specially prepared with fluorescence-quenching dyes added with a resin-hardener mixture to eliminate background fluorescence. Nine fluid-inclusion assemblages in minerals like quartz, feldspar and calcite from the RV-1 well of the Ratnagiri Block, Mumbai Offshore Basin, India were investigated.

UV Raman spectroscopy of hydrocarbon-bearing inclusions in rock salt from the Dongying sag, eastern China

Compositions of hydrocarbon-bearing inclusions in rock salt (halite) from the Shahejie Formation in the Dongying sag, Bohai Bay Basin, eastern China have been analysed by Raman spectroscopy coupled with a 244nm UV laser source. The fluorescence effect caused by the conventional visible laser excitation of the aromatic fractions of HC-bearing inclusions can be effectively avoided. Six types of HC-bearing inclusions belonging to two generations have been identified in halite according to their hydrocarbon types and petrographic characteristics. The presence of HC-bearing inclusions in halite provides evidence of crystal fracturing and healing, plastic deformation and dynamic recrystallization of rock salt in the Dongying sag. This proves that rock salt may have repeatedly lost and then recovered its sealing capacity during two stages of oil emplacement. Water and hydrocarbons were detected by UV Raman spectroscopy in the studied samples, in both HC-bearing inclusions and aqueous inclusions. These results are important for understanding the formation conditions of these fluid inclusions and the interactions between the formation water and petroleum in reservoirs. Our results show that UV Raman spectroscopy has a potential to become a powerful tool for analyzing hydrocarbon-bearing fluid inclusions trapped in various elements of a petroleum system.

Mineralogical signature of hydrocarbon circulation in Cretaceous red beds of the Barda Gonzalez area, Neuquen Basin, Argentina

The Portezuelo Formation is part of a red bed sequence in the Neuquen Basin assigned to the Neuquen Group (lower Cenomanian–middle Campanian). In outcrops of the Portezuelo Formation in the Barda Gonzalez region, iron oxide and hydroxide cements are only preserved in the less permeable claystone layers. Paleomigration of hydrocarbons and formation waters along the most permeable layers bleached the rocks due to partial to total dissolution of cements and grains and formation of several authigenic minerals: (1) montmorillonite and pyrite in the medium- to fine-grained sandstones and mudstones, and (2) multistage calcite and pyrite in the coarse-grained sandstones and conglomerates. The (Canyon Diablo troilite) of −24.4 to −60‰ values in pyrite point to microbial reduction of a sulfate precursor. The oxidation of hydrocarbons and fluctuations in pH and carbon dioxide pressure caused by organic acids resulted in multiple stages of dissolution and precipitation of calcite. Calcite crystals host hydrocarbon-bearing fluid inclusions (± pyrite) with variable fluorescence color, indicating that hydrocarbon composition changed with time. The intermediate (Peedee belemnite) (−8.11‰ to −8.52‰) and (−9.76 to −9.83‰) isotope composition of calcites may have resulted from mixtures of -rich after the dissolution of local calcrete with -poor from oxidizing hydrocarbons. This contribution provides for the first time key information to predict the distribution of authigenic minerals in reservoir rocks in the basin and improves understanding of the diagenetic history of the Portezuelo Formation.

Evolution of pore-fluid pressure during folding and basin contraction in overpressured reservoirs: Insights from the Madison–Phosphoria carbonate formations in the Bighorn Basin (Wyoming, USA)

Reconstructing the evolution of paleofluid (over)pressure in sedimentary basins during deformation is a challenging problem, especially when no hydrocarbon-bearing fluid inclusions are available to provide barometric constraints on the fluid system. This contribution reports the application to a natural case (the Bighorn Basin) of recent methodological advance to access fluid (over)pressure level prevailing in strata during sub-seismic fracture development. The fluid pressure evolution in the Mississippian-Permian Madison–Phosphoria limestone reservoir is tentatively reconstructed from the early Sevier Layer Parallel Shortening to the Laramide folding in two basement-cored folds: the Sheep Mountain Anticline and the Rattlesnake Mountain Anticline. Results point out that supra-hydrostatic pressure values prevail in the limestone reservoir during most of its whole Sevier–Laramide history. The comparison of the reconstructed fluid overpressure values within situ measurements in various overpressure reservoirs in other oil-producing basins highlights that the supra-hydrostatic fluid pressure gradually reaches the lithostatic value during the whole basin contraction and fold development. During most of the LPS history, however, overpressure level can be defined by a mean gradient. Among the factors that control the pressure evolution, the mechanical stratigraphy, the stress regime under which fractures developed and regional fluid flow are likely dominating in the case of the Bighorn Basin, rather than classical factors like disequilibrium compaction or fluid generation during burial. A coeval evolution between fluid overpressure and differential stress build-up is also emphasized. The approach presented in this paper also provides estimates of strata exhumation during folding.

Abiogenic hydrocarbon isotopic signatures in granitic rocks: Identifying pathways of formation

The stability and isotopic composition of hydrocarbons formed in the mantle are controversial subjects. Knowing the range in isotopic compositions of abiogenically-derived hydrocarbons is important for recognising biological signatures in ancient and extra-terrestrial materials. In an effort to enhance this database, stable isotope results are reported here for hydrocarbon-bearing fluid inclusions hosted in two peralkaline igneous complexes from Lovozero, Russia and Strange Lake, Canada. Based on the distribution of isotopic compositions, we propose three pathways for abiogenically-generated hydrocarbons. Type-1 (δ13CCH4>δ13CCO2 and δ13CC2+) represents mantle-derived hydrocarbons generated in equilibrium with hyperagpaitic magmas in the upper mantle, and suggests that mantle CH4 and C2H6δ13C and δ2H could have values of ~−5.3 and ~−112‰, and ~−10.8 and −162‰, respectively. Type-2 (δ13CCO2>δ13CCH4>δ13CC2+) represents Fischer–Tropsch-type hydrocarbon generation in quartz-bearing peralkaline rocks with CO2 as the initial magmatic gas phase. For Type-2, δ13CCO2 values are ~−2‰, whereas δ13CCH4 and δ2HCH4 values range from −32 to −20‰ and −170 and −160‰, respectively. The δ13CC2H6 values are slightly lower than associated δ13CCH4 values. Type-3 (δ13CCO2>δ13CCH4<δ13CC2+) represents an overprint of Type-2, formed during low temperature alteration of quartz-bearing peralkaline rocks. Here, δ13CCO2 values are variable, −14.0 to −9.5‰, δ13CCH4 values range from −30.8 to −20.8‰ while δ13CC2H6 values are higher than associated δ13CCH4 values. Both Type-2 and Type-3 isotopic compositions mimic patterns normally considered to be thermogenic in origin, thus demonstrating that isotopic data alone cannot be used reliably to distinguish between hydrocarbons of abiogenic versus biogenic origin.

Characterization of hydrocarbon-bearing fluid inclusion in sandstones of Jaisalmer basin, Rajasthan: A preliminary approach

The quartz grains from the sandstone of Jaisalmer, Pariwar and Goru Formations of the Jaisalmer basin, Rajasthan, India, exhibits a variety of primary and secondary fluid inclusions. Most of them are hydrocarbon bearing fluid inclusions. Laser Raman studies indicate that the primary fluid inclusions were mostly having aliphatic hydrocarbons with lower degree of maturity, while the secondary fluid inclusions were generally with aliphatic as well as aromatic hydrocarbons with higher degree of maturity. This inference was consistent with their fluorescence characteristics. The homogenization temperatures of primary monophase CH4 rich fluid inclusions varied from −80°C to −100°C, whereas the primary biphase fluid inclusions (CH4-CO2) homogenized between +80°C and +150°C. The secondary petroleum rich monophase fluid inclusions were having homogenization temperature between −80°C to −90°C, whereas the secondary biphase fluid inclusions homogenized between +130°C and +180°C. Most of the secondary biphase fluid inclusions were having the mixtures of H2O-CO2-NaCl, and were identified on the basis clathrate formation and they got homogenized between +140°C and + 250 °C. The three past events of migration of petroleum inferred in the host rock which were marked by the presence of characteristic secondary fluid inclusions. They were identified on the basis of cross-cutting relationships of different trails of fluid inclusions in the quartz. The cement generation in the basin might have been occurred in two stages as per the fluid inclusion petrography.

Hydrocarbon migration in the Porcupine Basin, offshore Ireland: evidence from fluid inclusion studies

ABSTRACT A petrographic and microthermometric study of fluid inclusions in Jurassic and Cretaceous sandstones from the Porcupine Basin, offshore Ireland was integrated with innovative fluorescence lifetime measurements of hydrocarbon-bearing fluid inclusions to determine the compositions of the fluids associated with diagenesis and post-diagenetic fluid migration and the extent of hydrocarbon and aqueous fluid migration pathways. Petrographic analyses indicate that Jurassic strata were the main fluid migration pathways for hydrocarbon fluids and that hydrocarbon migration occurred relatively late in the diagenetic history of these sandstones. UV fluorescence and fluorescence lifetime measurements have recognized at least two chemically distinct hydrocarbon groups (Types 1a and 1b) with dissimilar lifetime-wavelength (τ-λ) profiles, consistent with at least two petroleum charges derived from different sources. Primary aqueous inclusions in authigenic cements show that cementation in Cretaceous sandstones occurred at relatively shallow levels at low temperatures (

The use of palaeo-thermo-barometers and coupled thermal, fluid flow and pore-fluid pressure modelling for hydrocarbon and reservoir prediction in fold and thrust belts

AbstractBasin modelling tools are now more efficient to reconstruct palinspastic structural cross sections and compute the history of temperature, pore-fluid pressure and fluid flow circulations in complex structural settings. In many cases and especially in areas where limited erosion occurred, the use of well logs, bottom hole temperatures (BHT) and palaeo-thermometers such as vitrinite reflectance (Ro) and Rock-Eval (Tmax) data is usually sufficient to calibrate the heat flow and geothermal gradients across a section. However, in the foothills domains erosion is a dominant process, challenging the reconstruction of reservoir rocks palaeo-burial and the corresponding calibration of their past thermal evolution. Often it is not possible to derive a single solution for palaeo-burial and palaeo-thermal gradient estimates in the foothills, if based solely on maturity ranks of the organic matter.Alternative methods are then required to narrow down the error bars in palaeo-burial estimates, and to secure more realistic predictions of hydrocarbon generation. Apatite fission tracks (AFT) can provide access to time–temperature paths and absolute ages for the crossing of the 120 °C isotherm and timing of the unroofing. Hydrocarbon-bearing fluid inclusions, when developing contemporaneously with aqueous inclusions, can provide a direct access to the pore-fluid temperature and pressure of cemented fractures or reservoir at the time of cementation and hydrocarbon trapping, on line with the tectonic evolution. Further attempts are also currently made to use calcite twins for constraining reservoir burial and palaeo-stress conditions during the main deformational episodes. Ultimately, the use of magnetic properties and petrographical measurements can also document the impact of tectonic stresses during the evolution of the layer parallel shortening (LPS).The methodology integrating these complementary constraints will be illustrated using reference case studies from Albania, sub-Andean basins in Colombia and Venezuela, segments of the North American Cordillera in Mexico and in the Canadian Rockies, as well as from the Middle East.

Late Palaeozoic hydrocarbon migration through the Clair field, West of Shetland, UK Atlantic margin

Geochemical analysis of bitumen- and hydrocarbon-bearing fluid inclusions from the Devonian-Carboniferous Clair field indicates that the reservoirs contain a mixture of oils from different marine and lacustrine sources. Reconstruction of the Clair field oil-charge history using fluid inclusion petrography show that oil-charging occurred at times of K-feldspar, quartz and calcite cementation. Temperature–composition–time data yielded from the integration of fluid inclusion microthermometry with high-resolution Ar–Ar dating, date hydrocarbon-bearing K-feldspar overgrowths at 247±3.3Ma. These data show that in order for oil to be trapped within primary fluid inclusions in K-feldspar overgrowths, hydrocarbon migration throughout the UK Atlantic margin must have been taking place during the Late Palaeozoic and as such, current industry oil-play models based solely on oil charging from Jurassic-Cretaceous marine sources are clearly incomplete and need revision. Apatite fission track analysis and vitrinite reflectance data were used to reconstruct thermal burial histories and assess potential oil generation from Middle Devonian lacustrine source rocks. Thermal history data from wells along The Rona Ridge adjacent to the Clair field show that the Palaeozoic section was heated to greater than 100°C at some time between 270 and 230Ma, confirming that Devonian source rocks were mature and expelling oil during the Late Palaeozoic at the time that authigenic K-feldspar overgrowths were growing in the Clair field.