Infiltration of basinal fluids into high-grade basement, South Norway: sources and behaviour of waters and brines

Quartz veins hosted by the high‐grade crystalline rocks of the Modum complex, Southern Norway, formed when basinal fluids from an overlying Palaeozoic foreland basin infiltrated the basement at temperatures of c. 220°C (higher in the southernmost part of the area). This infiltration resulted in the formation of veins containing both two‐phase and halite‐bearing aqueous fluid inclusions, sometimes with bitumen and hydrocarbon inclusions. Microthermometric results demonstrate a very wide range of salinities of aqueous fluids preserved in these veins, ranging from c. 0 to 40 wt% NaCl equivalent. The range in homogenization temperatures is also very large (99–322°C for the entire dataset) and shows little or no correlation with salinity. A combination of aqueous fluid microthermometry, halogen geochemistry and oxygen isotope studies suggest that fluids from a range of separate aquifers were responsible for the quartz growth, but all have chemistries comparable to sedimentary formation waters. The bulk of the quartz grew from relatively low δ¹⁸O fluids derived directly from the basin or equilibrated in the upper part of the basement (T < 200°C). Nevertheless, some fluids acquired higher salinities due to deep wall‐rock hydration reactions leading to salt saturation at high temperatures (>300°C). The range in fluid inclusion homogenization temperatures and densities, combined with estimates of the ambient temperature of the basement rocks suggests that at different times veins acted as conduits for influx of both hotter and colder fluids, as well as experiencing fluctuations in fluid pressure. This is interpreted to reflect episodic flow linked to seismicity, with hotter dry basement rocks acting as a sink for cooler fluids from the overlying basin, while detailed flow paths reflected local effects of opening and closing of individual fractures as well as reaction with wall rocks. Thermal considerations suggest that the duration of some flow events was very short, possibly in the order of days. As a result of the complex pattern of fracturing and flow in the Modum basement, it was possible for shallow fluids to penetrate basement rocks at significantly higher temperatures, and this demonstrates the potential for hydrolytic weakening of continental crust by sedimentary fluids.     

Potential of palaeofluid analysis for understanding oil charge history

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

Producing consent: How environmental assessment enabled oil and gas extraction in the Qikiqtani region of Nunavut

There is now an extensive body of academic literature examining how the environmental movement contributed to the colonization of Indigenous peoples and development of capitalism in northern Canada. This paper contributes to these discussions by considering how environmental assessment (EA) helped enable hydrocarbon extraction in the Qikiqtani (Baffin Island) region of Nunavut in the 1970s and 1980s. When exploration activities began to threaten the Inuit harvesting economy, communities protested with letters and petitions. The federal government responded to Inuit resistance by referring proposed exploratory drilling and extraction to its new EA process. While Inuit won significant victories during some assessments of proposed exploratory drilling and extraction, federal EA ultimately helped create the conditions for Inuit to consent to oil extraction. EA helped impose material compromises between Inuit and hydrocarbon industries, including preferential hiring of Inuit, a reduction in the scope of proposed extraction, and the rejection of especially controversial proposals for offshore drilling. These concessions, combined with a collapse in the market for sealskins due to international boycotts, persuaded several Qikiqtani communities to support oil extraction in the 1980s. The ensuing extraction and export of oil from the High Arctic accelerated processes of colonial dispossession and reinforced colonial political dynamics.     

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.     

Developments in Russian Gas Production Since 1998: Russia's Evolving Gas Supply Strategy

An American geographer and prominent authority on the oil and natural gas industries and resources of Russia and other former republics of the Soviet Union reports on overall trends in Russia's natural gas production in the years following the country's ruble devaluation and financial crisis. The account—based on systematic in-country observations, discussions/interviews with industry executives, and a review of industry sources—focuses on factors affecting domestic supply and demand as well as export capacity (will Russia have enough gas to meet rising domestic demand while fulfilling its export obligations?), regional patterns of production (and performance of Gazprom regional production enterprises), obstacles to the use of associated gas derived from crude oil extraction, and major pipeline construction projects in West Siberia and the Russian Far East. The paper concludes by outlining CERA's forecast for Russian gas production to 2020, also disaggregated by region. Journal of Economic Literature, Classification Numbers: L71, O13, Q40, Q48. 7 figures, 8 tables, 51 references.     

On the geochemistry of gases and noble gas isotopes (including 222Rn) in deep crustal fluids: the 4000 m KTB-pilot hole fluid production test 2002–03

The concentrations of H₂, O₂, CO₂, and concentrations and isotopic composition of the noble gases (including ²²²Rn), N₂, CH₄, and higher hydrocarbons dissolved in 4000 m deep‐seated fluids from a 12‐month fluid production test in the KTB pilot hole were analyzed. This determination of the gas geochemistry during the test in combination with the knowledge of the hydraulic data provides relevant information about the fluid hydraulics of the deep system. All gas concentrations and isotopic signatures, except for ²²²Rn, showed constancy during the course of the test. This, in combination with large fluid flow rates at a moderate water table drawdown, imply an almost infinite fluid reservoir in 4000 m depth. From the change in ²²²Rn‐activity as a function of pump rate, the contribution of smaller and wider pores to the overall fluid flow in an aquifer can be deduced. This ²²²Rn‐activity monitoring proved therefore to be a valuable instrument for the qualitative observation of the scavenging of pore and fracture surfaces, a hydraulic feature invisible to standard hydraulic testing tools. The observance of this scavenging effect is due to (i) the continuous on‐line geochemical monitoring, (ii) the durability of the test, (iii) a change in pump rate during the course of the test, and (iv) due to the short half‐life of ²²²Rn. The fluids have a 5.9% mantle He component, and a δ²¹Ne excess of 14%, and a noble gas model age of about (5.5–6.2) ± 2.0 Myr. The mean N₂/Ar‐ratio of 516 and δ¹⁵N‐data of about +1.5‰ indicates sedimentary or metamorphic origin of N₂. The hydrocarbons, amounting to 33 vol.% in the gas phase, are derived from thermal decomposition of marine organic matter of low maturity. But a key question, the identification of the potential source region of the fluids and the migration pathway, is still unidentified.     

The Regional Dimension of Russian Oil Production: Is a Sustained Recovery in Prospect?

An American geographer and prominent authority on oil and natural gas industries and resources of Russia and other former republics of the Soviet Union presents a region-byregion account of Russia's oil production, tracing in considerable detail developments up to September 2006. The account, based on systematic and frequent field investigations since the early 1990s as well as interviews with key industry executives, covers reserves, output trends, ownership, investments, pipelines, and a variety of economic factors including exports to China. Addressing the question of whether sustained production recovery is possible, the author presents American and Russian scenarios projecting oil output through the year 2020. Journal of Economic Literature, Classification Numbers: L71, O13, Q40, Q48. 8 figures, 7 tables, 64 references.     

The link between fluids and rank variation in the South Wales Coalfield: evidence from fluid inclusions and stable isotopes

Fluid inclusion and stable isotope data from quartz and carbonate minerals in fracture fillings and ‘ironstone’ nodules from the South Wales Coalfield have been used to characterise the fluids generated during basin evolution and associated coalification. Carbonates grew first, probably at relatively shallow depths and low temperatures (<100°C). The carbonates exhibit a trend of increasing C‐isotopic values across the coalfield, ranging from δ¹³C = ?12‰ VPDB in the SE of the coalfield to 0‰ VPDB in the NW, possibly as a result of increasing methanogenesis in the deeper (NW) parts of the coalfield. Quartz formed at a later stage of basin formation, probably at temperatures between 150 and 200°C. Fluid inclusions in these minerals suggest that burial and coalification of the sediments were associated with mixed aqueous–petroleum fluids. Furthermore, the density of these petroleum fluids decreases towards the NW of the coalfield, where the rank of the associated coal increases to anthracite grade. The study confirms that the composition and temperature of these fluids closely correlate with the variations in coal rank, indicating a possible causal link. The data also give general support to models that propose regional fluid flow in the basin. and are consistent with the erosion of approximately 2 km of section which is not preserved today. A geothermal gradient (at maximum burial) of 45°C km^?1 is proposed, and thus no exceptionally anomalous thermal regime is required to explain coal rank variation.     

Unravelling the petroleum system by enhancing fluid migration paths in seismic data using a neural network based pattern recognition technique

Understanding the hydrocarbon migration system in the sub‐surface is a key aspect of oil and gas exploration. It is well known that conventional 3D seismic data contains information about hydrocarbon accumulations. Less known is the fact that 3D seismic data also contains information about hydrocarbon migration paths in the form of vertical noise trails. A method has been developed to highlight vertical noise trails in seismic data semi‐automatically, using assemblies of directive multi‐trace seismic attributes and neural network technology. The results of this detection method yield valuable information about the origin of hydrocarbons, about migration paths from source to prospect and about leakage or spillage from these prospects to shallow gas pockets or to the sea bed. Besides, the results reveal the sealing quality of faults, provide information on overpressure and whether prospects are charged or not. All these aspects are useful information for basin modelling studies and for an increased understanding of the petroleum system.     

Pliocene sand injectites from a submarine lobe fringe during hydrocarbon migration and salt diapirism: a seismic example from the Lower Congo Basin

Large‐scale conical and saucer‐shaped sand injectites have been identified in the Upper Miocene sediments of the Lower Congo Basin. These structures are evidenced on the 3D high‐resolution seismic data at about 600 ms TWT (two‐way traveltime) beneath the seabed. The conical and saucer‐shaped anomalies range from 20 to 80 m in height, 50 to 300 m in diameter, and 10 to 20 ms TWT in thickness. They are located within a sedimentary interval of about 100 m in thickness and are aligned over 20 km in dip direction (NE‐SW), above the NW margin of an underlying Upper Miocene submarine fan. We have interpreted the conical and saucer‐shaped anomalies as upward‐emplaced sand injectites sourced from the Upper Miocene fan because of their discordant character, the postsedimentary uplifting of the sediments overlying the cones and saucer‐shaped bodies, the alignment with the lateral fringe of the Upper Miocene submarine fan, and the geological context. Sand injection dates from the Miocene–Pliocene transition (approximately 5.3 Ma). The prerequisite overpressure to the sand injection process may be due to the buoyancy effect of hydrocarbons accumulated in the margins of the fan. Additionally, overpressure could have been enhanced by the lateral transfer of fluids operating in the inclined margins of the lobe. The short duration of sand injection and the presence of many sandstone intrusions suggested that the process of injection was triggered by an event, likely due to a nearby fault displacement related to diapiric movements. This is the first time that sand injectites of seismic scale have been described from the Lower Congo Basin. The localized nature of these injectites has led to a change in the migration path of fluids through the sedimentary cover. Consequently, the sand intrusions are both evidence and vectors of fluid migration within the basin fill.