Fluid mixing induced by hydrothermal activity in the ordovician carbonates in Tarim Basin,China

Permian hydrothermal activity in the Tarim Basin may have been responsible for the invasion of hot brines into Ordovician carbonate reservoirs. Studies have been undertaken to explain the origin and geochemical characteristics of the diagenetic fluid present during this hydrothermal event although there is no consensus on it. We present a genetic model resulting from the study of δ¹³C, δ¹⁸O, δ³⁴S, and ⁸⁷Sr/⁸⁶Sr isotope values and fluid inclusions (FIs) from fracture‐ and vug‐filling calcite, saddle dolomite, fluorite, barite, quartz, and anhydrite from Ordovician outcrops in northwest (NW) Tarim Basin and subsurface cores in Central Tarim Basin. The presence of hydrothermal fluid was confirmed by minerals with fluid inclusion homogenization temperatures being >10°C higher than the paleo‐formation burial temperatures both in the NW Tarim and in the Central Tarim areas. The mixing of hot (>200°C), high‐salinity (>24 wt% NaCl), ⁸⁷Sr‐rich (up to 0.7104) hydrothermal fluid with cool (60–100°C), low‐salinity (0 to 3.5 wt% NaCl), also ⁸⁷Sr‐rich (up to 0.7010) meteoric water in the Ordovician unit was supported by the salinity of fluid inclusions, and δ¹³C, δ¹⁸O, and ⁸⁷Sr/⁸⁶Sr isotopic values of the diagenetic minerals. Up‐migrated hydrothermal fluids from the deeper Cambrian strata may have contributed to the hot brine with high sulfate concentrations which promoted thermochemical sulfate reduction (TSR) in the Ordovician, resulting in the formation of ¹²C‐rich (δ¹³C as low as ?13.8‰) calcite and ³⁴S‐rich (δ³⁴S values from 21.4‰ to 29.7‰) H₂S, pyrite, and elemental sulfur. Hydrothermal fluid mixing with fresh water in Ordovician strata in Tarim Basin was facilitated by deep‐seated faults and up‐reaching faults due to the pervasive Permian magmatic activity. Collectively, fluid mixing, hydrothermal dolomitization, TSR, and faulting may have locally dissolved the host carbonates and increased the reservoir porosity and permeability, which has significant implications for hydrocarbon exploration.     

Hydrogeochemical modelling of CO2 equilibria and mass transfer induced by organic–inorganic interactions in siliciclastic petroleum reservoirs

Different feldspar types control complex hydrogeochemical processes in hydrocarbon‐bearing siliciclastic reservoirs, which have undergone different degrees of degradation. To test such processes generically, carbon dioxide equilibria and mass transfers induced by organic–inorganic interactions have been modelled for different hydrogeochemical scenarios. The approach is based on and compared with data from the Norwegian continental shelf ( Smith & Ehrenberg 1989 ) and assumes local thermodynamic equilibrium among solids and fluids. Equilibrating mineral assemblages (different feldspar types, quartz, kaolinite, calcite) are based on the primary reservoir composition. Equilibration and coupled mass transfer were triggered by the addition and reaction of different amounts of CO₂, CH₄ and H₂ (plus acetic acid) at temperatures between 50 and 95°C (323 and 368 K). These components occur in oil fields as products of anaerobic bacterial degradation, hydrolytic disproportionation of hydrocarbons and/or thermal maturation of kerogen. We apply two different computer codes and two different thermodynamic data bases to calculate the results. Reaction of 0.32–0.6 mol CO₂, 0.16–0.3 mol CH₄ and 0.8–1.5 mol H₂ with K‐feldspar, quartz, kaolinite and calcite in 1 l of pore water results in modelled values of 0.3–2.3 mol% CO₂ in a multicomponent gas phase that resembles measured data (0.2–1.5 mol%). Similar CO₂ contents result from acetic acid addition (CO₂, CH₄, H₂ + 0.016 mol CH₃COOH). Equilibration with albite or anorthite reduces the release of CO₂ into the multicomponent gas phase dramatically, by 1 or 4 orders of magnitude compared with the equilibration with K‐feldspar. Minor differences in the modelled CO₂ content (0.1–0.2 mol%) result from calculations with different computer codes if the same thermodynamic data base is applied. Relevant differences (up to 1.9 mol% CO₂) result from calculations using different thermodynamic data bases.     

Diagenesis of the Amposta offshore oil reservoir (Amposta Marino C2 well,Lower Cretaceous,Valencia Trough,Spain)

Samples from the Amposta Marino C2 well (Amposta oil field) have been investigated in order to understand the origin of fractures and porosity and to reconstruct the fluid flow history of the basin prior, during and after oil migration. Three main types of fracture systems and four types of calcite cements have been identified. Fracture types A and B are totally filled by calcite cement 1 (CC1) and 2 (CC2), respectively; fracture type A corresponds to pre‐Alpine structures, while type B is attributed to fractures developed during the Alpine compression (late Eocene‐early Oligocene). The oxygen, carbon and strontium isotope compositions of CC2 are close to those of the host‐rock, suggesting a high degree of fluid‐rock interaction, and therefore a relatively closed palaeohydrogeological system. Fracture type C, developed during the Neogene extension and enlarged by subaerial exposure, tend to be filled with reddish (CS3r) and greenish (CS3g) microspar calcite sediment and blocky calcite cement type 4 (CC4), and postdated by kaolinite, pyrite, barite and oil. The CS3 generation records lower oxygen and carbon isotopic compositions and higher ⁸⁷Sr/⁸⁶Sr ratios than the host‐limestones. These CS3 karstic infillings recrystallized early within evolved‐meteoric waters having very little interaction with the host‐rock. Blocky calcite cement type 4 (CC4 generation) has the lowest oxygen isotope ratio and the most radiogenic ⁸⁷Sr/⁸⁶Sr values, indicating low fluid‐rock interaction. The increasingly open palaeohydrogeological system was dominated by migration of hot brines with elevated oxygen isotope ratios into the buried karstic system. The main oil emplacement in the Amposta reservoir occurred after the CC4 event, closely related to the Neogene extensional fractures. Corrosion of CC4 (blocky calcite cement type 4) occurred prior to (or during) petroleum charge, possibly related to kaolinite precipitation from relatively acidic fluids. Barite and pyrite precipitation occurred after this corrosion. The sulphur source associated with the late precipitation of pyrite was likely related to isotopically light sulphur expelled, e.g. as sulphide, from the petroleum source rock (Ascla Fm). Geofluids (2010) 10 , 314–333     

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.     

A comprehensive review of hydrocarbons and genetic model of the sandstone‐hosted Dongsheng uranium deposit,Ordos Basin,China

The Dongsheng uranium deposit, the largest in situ leach uranium mine in the Ordos Basin, geometrically forms a roll‐front type deposit that is hosted in the Middle Jurassic Zhiluo Formation. The genesis of the mineralization, however, has long been a topic of great debate. Regional faults, epigenetic alterations in surface outcrops, natural oil seeps, and experimental findings support a reducing microenvironment during ore genesis. The bulk of the mineralization is coffinite. Based on thin‐section petrography, some of the coffinite is intimately intergrown with authigenic pyrite (ore‐stage pyrite) and is commonly juxtaposed with some late diagenetic sparry calcite (ore‐stage calcite) in primary pores, suggesting simultaneous precipitation. Measured homogenization temperatures of greater than 100°C from fluid inclusions indicate circulation of low‐temperature hydrothermal fluids in the ore zone. The carbon isotopic compositions of late calcite cement (δ¹³C_VPDB = ?31.0 to ?1.4‰) suggest that they were partly derived from sedimentary organic carbon, possibly from deep‐seated petroleum fluids emanating from nearby faults. Hydrogen and oxygen isotope data from kaolinite cement (δD = ?133 to ?116‰ and δ¹⁸O_SMOW = 12.6–13.8‰) indicate that the mineralizing fluids differed from magmatic and metamorphic fluids and were more depleted in D (²H) than modern regional meteoric waters. Such a strongly negative hydrogen isotopic signature suggests that there has been selective modification of δD by CH₄±H₂S±H₂ fluids. Ore‐stage pyrite lies within a very wide range of δ³⁴S (?39.2 to 26.9‰), suggesting that the pyrite has a complex origin and that bacterially mediated sulfate reduction cannot be precluded. Hydrocarbon migration and its role in uranium reduction and precipitation have here been unequivocally defined. Thus, a unifying model for uranium mineralization can be established: Early coupled bacterial uranium mineralization and hydrocarbon oxidation were followed by later recrystallization of ore phases in association with low‐temperature hydrothermal solutions under hydrocarbon‐induced reducing conditions.     

Fluid mapping in deeply buried Ordovician paleokarst reservoirs in the Tarim Basin,western China

The storage spaces within deeply buried Ordovician paleokarst reservoirs in the Tarim Basin are mostly secondary and characterized by strong heterogeneity and some degree of anisotropy. The types of fluids that fill the spaces within these reservoirs are of great importance for hydrocarbon exploration and exploitation. However, fluid identification from seismic data is often controversial in this area because the seismic velocity for this particular reservoir could be significantly influenced by many factors, including pore shapes, porosity, fluid types, and mineral contents. In this study, we employ the differential effective medium‐Gassmann rock physics model to interpret and discuss the characteristics of conventional karstic carbonate reservoirs in the Tarim Basin that are filled with different fluids (oil, gas, and water) using logging data and thus objectively build corresponding fluid identification criteria. These criteria are subsequently evaluated by amplitude versus offset (AVO) forward analysis based on typical logging data and further applied to ascertain the reservoir fluid types in two different areas in the Tarim Basin based on prestack inversion results. For conventional carbonate reservoirs, gas can be distinguished from heavy oil and water, but heavy oil and water are broadly similar on seismic data. For condensate carbonate reservoirs, water can be differentiated from light oil (i.e., condensates) and gas, but light oil and gas demonstrate substantial similarities in terms of their seismic responses. The predicted fluid results are in good agreement with the results of drilling and oil testing. In particular, modeling the seismically resolvable reservoirs in the carbonate strata in the Tarim Basin, which have needle‐ and sphere‐shaped storage spaces (pore aspect ratio > 0.3) and clay content that is lower than 5%, indicates that fluid properties could be properly evaluated if the porosity is larger than 5% for conventional carbonate reservoirs and >7% for condensate carbonate reservoirs.     

Hydrothermal control on organic matter alteration and illite precipitation, Mt Isa Basin, Australia

Abundant illite precipitation in Proterozoic rocks from Northern Lawn Hill Platform, Mt Isa Basin, Australia, occurred in organic matter‐rich black shales rather than in sandstones, siltstones and organic matter‐poor shales. Sandstones and siltstones acted as impermeable rocks, as early diagenetic quartz and carbonate minerals reduced the porosity–permeability. Scanning and transmission electron microscopy (SEM and TEM) studies indicate a relation between creation of microporosity–permeability and organic matter alteration, suitable for subsequent mineral precipitation. K–Ar data indicate that organic matter alteration and the subsequent illite precipitation within the organic matter occurred during the regional hydrothermal event at 1172 ± 50 (2σ) Ma. Hot circulating fluids are considered to be responsible for organic matter alteration, migration and removal of volatile hydrocarbon, and consequently porosity–permeability creation. Those rocks lacking sufficient porosity–permeability, such as sandstones, siltstones and organic matter poor shales, may not have been affected by fluid movement. In hydrothermal systems, shales and mudstones may not be impermeable as usually assumed because of hydrocarbons being rapidly removed by fluid, even with relatively low total organic carbon.     

Hydrothermal palaeofluid circulation in the fracture network of the Baksa Gneiss Complex of SW Pannonian Basin,Hungary

A well‐developed fracture‐filling network is filled by dominantly Ca‐Al‐silicate minerals that can be found in the polymetamorphic rock body of the Baksa Gneiss Complex (SW Hungary). Detailed investigation of this vein network revealed a characteristic diopside→epidote→sphalerite→albite ± kfeldspar→chlorite1 ± prehnite ± adularia→chlorite2→chlorite3→pyrite→calcite1→calcite2→calcite3 fracture‐filling mineral succession. Thermobarometric calculations (two feldspar: 230–336°C; chlorites: approximately 130–300°C) indicate low‐temperature vein formation conditions. The relative succession of chlorites in the mineral sequence combined with the calculated formation temperatures reveals a cooling trend during precipitation of the different chlorite phases (T_chlorite1: 260 ± 32°C →T_chlorite2: 222 ± 20°C →T_chlorite3: 154 ± 13°C). This cooling trend can be supported by the microthermometry data of primary fluid inclusions in diopside (T_h: 276–362°C) and epidote (T_h: 181–359°C) phases. The identical chemical character (0.2–1.5 eq. wt% NaCl) of these inclusions mean that vein mineralization occurred in a same fluid environment. The high trace element content (e.g. As, Cu, Zn, Mn) and Co/Ni ratio approximately 1–5 of pyrite grains support the postmagmatic hydrothermal origin of the veins. The vein microstructure and identical fluid composition indicate that vein mineralization occurred in an interconnected fracture system where crystals grew in fluid filled cracks. Vein system formed at approximately <200 MPa pressure conditions during cooling from approximately 480°C to around 150°C. The rather different fluid characteristics (T_h: 75–124°C; 17.5–22.6 eq. wt% CaCl₂) of primary inclusions of calcite1 combining with the special δ¹⁸O signature of fluid from which this mineral phase precipitated refer to hydrological connection between the crystalline basement and the sedimentary cover.     

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.     

Hydrothermal dolomitization,mixing corrosion and deep burial porosity formation: numerical results from 1‐D reactive transport models

Major corrosion has been found at depth in carbonate hydrocarbon reservoirs from different geologic provinces. Fluid inclusion microthermometry and stable isotopic compositions of carbonate cements, predating major corrosion, constrain the interpretation of the evolution of parental fluids during progressive burial and prior to the major corrosion event. Post‐major corrosion mineral paragenesis includes pyrite (‐marcasite), anhydrite, kaolinite (dickite) and fluorite. Although the post‐corrosion mineral paragenesis represents minor volumes of rock, it may provide valuable insights into the post‐corrosion brine chemistry. Using reactive transport numerical models, the roles of cooling and/or mixing of brines on corrosion have been evaluated as controls for dolomitization, deep burial corrosion and precipitation of the post‐corrosion mineral paragenesis. Modelling results show that cooling of deep‐seated fluids moving upward along a fracture may cause minor calcite dissolution and porosity generation. Significant dolomitization along a fracture zone and nearby host‐rock only occurs when deep‐seated fluids have high salinities (4 mol Cl kg^?1 of solution) and Darcian flow rates are relatively high (1 m³ m^?2 year^?1). Only minor volumes of quartz and fluorite precipitate in the newly formed porosity. Moreover, modelling results cannot reproduce the authigenic precipitation of kaolinite (dickite at high temperatures) by cooling. As an alternative to cooling as a cause of corrosion, mixing between two brines of different compositions and salinities is represented by two main cases. One case consists of the flow up along a fracture of deep‐seated fluids with higher salinities than the fluid in the wall rock. Dolomite does not precipitate at a fracture zone. Nevertheless, minor volumes of dolomite are formed away from the fracture. The post‐corrosion mineral paragenesis can be partly reproduced, and the results are comparable to those obtained from cooling calculations. Minor volumes of quartz and fluorite are formed, and kaolinite‐dickite does not precipitate. The major outputs of this scenario are calcite dissolution and slight net increase in porosity. A second case corresponds to the mixing of low salinity deep‐seated fluids, flowing up along fractures, with high salinity brines within the wall rock. Calculations predict major dissolution of calcite and precipitation of dolomite. The post‐corrosion mineral paragenesis can be reproduced. High volumes of quartz, fluorite and kaolinite‐dickite precipitate and may even completely occlude newly formed porosity.     

Role of compressive tectonics on gas charging into the Ordovician sandstone reservoirs in the Sbaa Basin,Algeria: constrained by fluid inclusions and mineralogical data

Structure‐ and tectonic‐related gas migration into Ordovician sandstone reservoirs and its impact on diagenesis history were reconstructed in two gas fields in the Sbaa Basin, in SW Algeria. This was accomplished by petrographical observations, fluid inclusion microthermometry and stable isotope geochemistry on quartz, dickite and carbonate cements and veins. Two successive phases of quartz cementation (CQ1 and CQ2) occurred in the reservoirs. Two phase aqueous inclusions show an increase in temperatures and salinities from the first CQ1 diagenetic phase toward CQ2 in both fields. Microthermometric data on gas inclusions in quartz veins reveal the presence of an average of 92 ± 5 mole% of CH₄ considering a CH₄‐CO₂ system, which is similar to the present‐day gas composition in the reservoirs. The presence of primary methane inclusions in early quartz overgrowths and in quartz and calcite veins suggests that hydrocarbon migration into the reservoir occurred synchronically with early quartz cementation in the sandstones located near the contact with the Silurian gas source rock at 100–140°C during the Late Carboniferous period and the late Hercynian episode fracturing at temperatures between 117 and 185°C, which increased in the NW‐direction of the basin. During the fracture filling, three main types of fluids were identified with different salinities and formation temperatures. A supplementary phase of higher fluid temperature (up to 226°C) recorded in late quartz, and calcite veins is related to a Jurassic thermal event. The occurrence of dickite cements close to the Silurian base near the main fault areas in both fields is mainly correlated with the sandstones where the early gas was charged. It implies that dickite precipitation is related to acidic influx. Late carbonate cements and veins (calcite – siderite – ankerite and strontianite) occurred at the same depths resulting from the same groundwater precipitation. The absence of methane inclusions in calcite cements result from methane flushing by saline waters.     

Fracture mineralization and fluid flow evolution: an example from Ordovician–Devonian carbonates,southwestern Ontario,Canada

Petrography, geochemistry (stable and radiogenic isotopes), and fluid inclusion microthermometry of matrix dolomite, fracture‐filling calcite, and saddle dolomite in Ordovician to Devonian carbonates from southwestern Ontario, Canada, provide useful insights into fluid flow evolution during diagenesis. The calculated δ¹⁸O_fluid, ΣREE, and REE_SN patterns of matrix and saddle dolomite suggest diverse fluids were involved in dolomitization and/or recrystallization of dolomite. The ⁸⁷Sr/⁸⁶Sr ratios of dolomite of each succession vary from values in the range of coeval seawater to values more radiogenic than corresponding seawater, which indicate diagenetic fluids were influenced by significant water/rock interaction. High salinities (22.4–26.3 wt. % NaCl + CaCl₂) of Silurian and Ordovician dolomite–hosted fluid inclusions indicate involvement of saline waters from dissolution of Silurian evaporites. High fluid inclusion homogenization temperatures (>100°C) in all samples from Devonian to Ordovician show temperatures higher than maximum burial (60–90°C) of their host strata and suggest involvement of hydrothermal fluids in precipitation and/or recrystallization of dolomite. A thermal anomaly over the mid‐continent rift during Devonian to Mississippian time likely was the source of excess heat in the basin. Thermal buoyancy resulting from this anomaly was the driving force for migration of hydrothermal fluids through regional aquifers from the center of the Michigan Basin toward its margin. The decreasing trend of homogenization temperatures from the basin center toward its margin further supports the interpreted migration of hydrothermal fluids from the basin center toward its margin. Hydrocarbon‐bearing fluid inclusions in late‐stage Devonian to Ordovician calcite cements with high homogenization temperatures (>80°C) and their ¹³C‐depleted values (approaching ?32‰ PDB) indicate the close relationship between hydrothermal fluids and hydrocarbon migration.     

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.     

Geothermometry and geobarometry of overpressured environments in Qiongdongnan Basin,South China Sea*

We demonstrate the use of PVT fluid inclusion modelling in the calculation of palaeofluid formation pressures, using samples from the YC21‐1‐1 and YC21‐1‐4 wells in the YC21‐1 structural closure, Qiongdongnan Basin, South China Sea. Homogenisation temperatures and gas/liquid ratios were measured in aqueous fluid inclusions, and associated light hydrocarbon/CO₂‐bearing inclusions, and their compositions were determined using a crushing technique. The vtflinc software was used to construct P–T phase diagrams that enabled derivation of the minimum trapping pressure for each order of fluid inclusion. Through the projection of average homogenisation temperatures (155, 185.5 and 204.5°C) for three orders of fluid inclusion on the thermal‐burial history diagram of the Oligocene Yacheng and Lingshui formations, their trapping times were constrained at 4.3, 2.1 and 1.8 Ma, respectively. The formation pressure coefficient, the ratio of fluid pressure/hydrostatic pressure established by PVT modelling coupled with DST data, demonstrates that one and a half cycles of pressure increase–discharge developed in the Yacheng and Lingshui formations for about 4.3 Ma. In comparison, the residual formation pressure determined by 2D numerical modelling in the centre of LeDong depression shows two and a half pressure increase–discharge cycles for about 28 Ma. The two different methods suggest that a high fluid potential in the Oligocene reservoir of the YC21‐1 structure developed at two critical stages for regional oil and natural gas migration and accumulation (5.8 and 2.0 Ma, respectively). Natural gas exploration in this area is therefore not advisable.     

Real‐time mud gas logging and sampling during drilling

Continuous mud gas loggings during drilling as well as offline mud gas sampling are standard procedures in oil and gas operations, where they are used to test reservoir rocks for hydrocarbons while drilling. Our research group has developed real‐time mud gas monitoring techniques for scientific drilling in non‐hydrocarbon formations mainly to sample and study the composition of crustal gases. We describe in detail this technique and provide examples for the evaluation of the continuous gas logs, which are not always easy to interpret. Hydrocarbons, helium, radon and with limitations carbon dioxide and hydrogen are the most suitable gases for the detection of fluid‐bearing horizons, shear zones, open fractures, sections of enhanced permeability and permafrost methane hydrate occurrences. Off‐site isotope studies on mud gas samples helped reveal the origin and evolution of deep‐seated crustal fluids.     

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.     

Fracture-fill calcite as a record of microbial methanogenesis and fluid migration: a case study from the Devonian Antrim Shale, Michigan Basin

The Devonian Antrim Shale is an organic‐rich, naturally fractured black shale in the Michigan Basin that serves as both a source and reservoir for natural gas. A well‐developed network of major, through‐going vertical fractures controls reservoir‐scale permeability in the Antrim Shale. Many fractures are open, but some are partially sealed by calcite cements that retain isotopic evidence of widespread microbial methanogenesis. Fracture filling calcite displays an unusually broad spectrum of δ¹³C values (+34 to ?41‰ PDB), suggesting that both aerobic and anaerobic bacterial processes were active in the reservoir. Calcites with high δ¹³C values (>+15‰) record cementation of fractures from dissolved inorganic carbon (DIC) generated during bacterial methanogenesis. Calcites with low δ¹³C values (13C values between ?10 and ?30‰ can be attributed to variable organic matter oxidation pathways, methane oxidation, and carbonate rock buffering. Identification of ¹³C‐rich calcite provides unambiguous evidence of biogenic methane generation and may be used to identify gas deposits in other sedimentary basins. It is likely that repeated glacial advances and retreats exposed the Antrim Shale at the basin margin, enhanced meteoric recharge into the shallow part of the fractured reservoir, and initiated multiple episodes of bacterial methanogenesis and methanotrophic activity that were recorded in fracture‐fill cements. The δ¹⁸O values in both formation waters and calcite cements increase with depth in the basin (?12 to ?4‰ SMOW, and +21 to +27‰ PDB, respectively). Most fracture‐fill cements from outcrop samples have δ¹³C values between ?41 and ?15‰ PDB. In contrast, most cement in cores have δ¹³C values between +15 and +34‰ PDB. Radiocarbon and ²³⁰Th dating of fracture‐fill calcite indicates that the calcite formed between 33 and 390 ka, well within the Pleistocene Epoch.     

Spatial coupling between spilitization and carbonation of basaltic sills in SW Scottish Highlands: evidence of a mineralogical control of metamorphic fluid flow

In a geochemical and petrological analysis of overprinting episodes of fluid–rock interaction in a well‐studied metabasaltic sill in the SW Scottish Highlands, we show that syn‐deformational access of metamorphic fluids and consequent fluid–rock interaction is at least in part controlled by preexisting mineralogical variations. Lithological and structural channelling of metamorphic fluids along the axis of the Ardrishaig Anticline, SW Scottish Highlands, caused carbonation of metabasaltic sills hosted by metasedimentary rocks of the Argyll Group in the Dalradian Supergroup. Analysis of chemical and mineralogical variability across a metabasaltic sill at Port Cill Maluaig shows that carbonation at greenschist to epidote–amphibolites facies conditions caused by infiltration of H₂O‐CO₂ fluids was controlled by mineralogical variations, which were present before carbonation occurred. This variability probably reflects chemical and mineralogical changes imparted on the sill during premetamorphic spilitization. Calculation of precarbonation mineral modes reveals heterogeneous spatial distributions of epidote, amphibole, chlorite and epidote. This reflects both premetamorphic spilitization and prograde greenschist facies metamorphism prior to fluid flow. Spilitization caused albitization of primary plagioclase and spatially heterogeneous growth of epidote ± calcic amphibole ± chlorite ± quartz ± calcite. Greenschist facies metamorphism caused breakdown of primary pyroxene and continued, but spatially more homogeneous, growth of amphibole + chlorite ± quartz. These processes formed diffuse epidote‐rich patches or semi‐continuous layers. These might represent precursors of epidote segregations, which are better developed elsewhere in the SW Scottish Highlands. Chemical and field analyses of epidote reveal the evidence of local volume fluctuations associated with these concentrations of epidote. Transient permeability enhancement associated with these changes may have permitted higher fluid fluxes and therefore more extensive carbonation. This deflected metamorphic fluid such that its flow direction became more layer parallel, limiting propagation of the reaction front into the sill interior.     

Pyrophyllite formation in the thermal aureole of a hydrothermal system in the Lower Saxony Basin,Germany

A combined clay mineralogical, fluid inclusion, and K‐Ar study of Upper Jurassic metasediments at the Gehn (Lower Saxony Basin, Germany) provides evidence for a transient hydrothermal event during Upper Cretaceous basin inversion centered on a prominent gravimetric anomaly. Kaolinite and smectite in Oxfordian pelitic parent rocks that cap a deltaic sandstone unit were locally transformed into pyrophyllite, 2M₁ illite, R3 illite–smectite, chlorite, and berthierine at the Ueffeln quarry. The pyrophyllite‐bearing metapelites lack bedding‐parallel preferred orientation of sheet silicates and experienced peak temperatures of about 260–270°C consistent with microthermometric data on quartz veins in the underlying silicified sandstones. The presence of expandable layers in illite–smectite and high Kübler Index values indicate that the thermal event was rather short‐lived. K‐Ar dating of the <0.2 μm fraction of the pyrophyllite‐bearing Ueffeln metapelite yields a maximum illitization age of 117 ± 2 Ma. Lower trapping temperatures of aqueous fluid inclusions in quartz veins and the absence of pyrophyllite in metapelites of the Frettberg quarry in a distance of about 2.5 km from the Ueffeln quarry infer maximum paleotemperatures of only 220°C. The highly localized thermal anomaly at Ueffeln suggests fault‐controlled fluid migration and heat transfer that provided a thermal aureole for pyrophyllite formation in the metapelites rather than metamorphism due to deep burial. A pH neutral hydrothermal fluid that formed by devolatilization reactions or less likely by mixing of meteoric and marine waters that interacted at depth with shales is indicated by the low salinity (3–5 wt. % NaCl equiv.) of aqueous inclusions, their coexistence with methane–carbon dioxide‐dominated gas inclusions as well as carbon, hydrogen, and oxygen isotope data. The upwelling zone of hydrothermal fluids and the thermal maximum is centered on a gravimetric anomaly interpreted as an igneous intrusion (‘Bramsche Massif’) providing the heat source for the intrabasinal hydrothermal system.     

Hydrologic and geochemical controls on soluble benzene migration in sedimentary basins

The effects of groundwater flow and biodegradation on the long‐distance migration of petroleum‐derived benzene in oil‐bearing sedimentary basins are evaluated. Using an idealized basin representation, a coupled groundwater flow and heat transfer model computes the hydraulic head, stream function, and temperature in the basin. A coupled mass transport model simulates water washing of benzene from an oil reservoir and its miscible, advective/dispersive transport by groundwater. Benzene mass transfer at the oil–water contact is computed assuming equilibrium partitioning. A first‐order rate constant is used to represent aqueous benzene biodegradation. A sensitivity study is used to evaluate the effect of the variation in aquifer/geochemical parameters and oil reservoir location on benzene transport. Our results indicate that in a basin with active hydrodynamics, miscible benzene transport is dominated by advection. Diffusion may dominate within the cap rock when its permeability is less than 10^?19 m². Miscible benzene transport can form surface anomalies, sometimes adjacent to oil fields. Biodegradation controls the distance of transport down‐gradient from a reservoir. We conclude that benzene detected in exploration wells may indicate an oil reservoir that lies hydraulically up‐gradient. Geochemical sampling of hydrocarbons from springs and exploration wells can be useful only when the oil reservoir is located within about 20 km. Benzene soil gas anomalies may form due to regional hydrodynamics rather than separate phase migration. Diffusion alone cannot explain the elevated benzene concentration observed in carrier beds several km away from oil fields.