Potential petroleum sources and exploration directions around the Manjar Sag in the Tarim Basin

Since the discovery of the Tahe oilfield, it has been controversial on whether the main source rock is in the Cambrian or Middle-Upper Ordovician strata. In this paper, it is assumed that the crude oil from the Wells YM 2 and TD 2 was derived from the Middle-Upper Ordovician and Cambrian source rocks, respectively. We analyzed the biomarkers of the crude oil, asphalt-adsorbed hydrocarbon and saturated hydrocarbon in bitumen inclusions from the Lunnan and Hade areas in the North Uplift of the Tarim Basin. Results show that the ratios of tricyclic terpane C₂₁/C₂₃ in the crude oil, asphalt-adsorbed hydrocarbon and saturated hydrocarbon in bitumen inclusions are less than 1.0, indicating that they might be from Upper Ordovician source rocks; the ratios of C₂₈/(C₂₇+C₂₈+C₂₉) steranes in the saturated hydrocarbon from reservoir bitumen and bitumen inclusions are higher than 25, suggesting that they might come from the Cambrian source rocks, however, the ratios of C₂₈/(C₂₇+C₂₈+C₂₉) steranes in oil from the North Uplift are less than 25, suggesting that they might be sourced from the Upper Ordovician source rocks. These findings demonstrate that the sources of crude oil in the Tarim Basin are complicated. The chemical composition and carbon isotopes of Ordovician reservoired oil in the Tarim Basin indicated that the crude oil in the North Uplift (including the Tahe oilfield) and Tazhong Depression was within mixture areas of crude oil from the Wells YM 2 and TD 2 as the end members of the Cambrian and Middle-Upper Ordovician sourced oils, respectively. This observation suggests that the crude oil in the Ordovician strata is a mixture of oils from the Cambrian and Ordovician source rocks, with increasing contribution from the Cambrian source rocks from the southern slope of the North Uplift to northern slope of the Central Uplift of the Tarim Basin. Considering the lithology and sedimentary facies data, the spatial distribution of the Cambrian, Middle-Lower Ordovician and Upper Ordovician source rocks was reconstructed on the basis of seismic reflection characteristics, and high-quality source rocks were revealed to be mainly located in the slope belt of the basin and were longitudinally developed over the maximum flooding surface during the progressive-regressive cycle. Affected by the transformation of the tectonic framework in the basin, the overlays of source rocks in different regions are different and the distribution of oil and gas was determined by the initial basin sedimentary structure and later reformation process. The northern slope of the Central Uplift-Shuntuo-Gucheng areas would be a recent important target for oil and gas exploration, since they have been near the slope area for a long time.     

Cracking conditions of crude oil under different geological environments

There are mainly 3 kinds of existing states of oil generating from source rocks, that is, dispersive liquid hydrocarbon inside of source rock, dispersive liquid hydrocarbon outside of source rock and concentrated liquid hydrocarbon outside of source rock. Because of the differences in thermal history and medium conditions around, and the interaction of organic and inorganic matter, the liquid hydrocarbon with 3 kinds of existing state has different cracking conditions. The gas generation dynamics experiments of crude oil matching different mediums indicate that the distribution of activation energy of methane changes a lot according to medium difference. The carbonate has a main influence on oil cracking conditions and can largely reduce its activation energy, which reflects the lower cracking temperature of crude oil. The mudstone takes a second place and the sandstone is the smallest. The catalytic cracking function to the oil of the carbonate, of the mudstone and of the sandstone changes weaken in turn. The corresponding R _o values of main gas generation period in different mediums are as follows: 1.5%–3.8% with pure crude oil, 1.2%–3.2% with dispersive crude oil in carbonate, 1.3%～3.4% with dispersive crude oil in mudstone and 1.4%–3.6% with dispersive crude oil in sandstone. The influence of pressure to crude oil cracking is relatively complicated. In the low heating speed condition, pressure restrains the oil cracking and gas generation, but in the high heating speed condition, pressure has an indistinctive influence to the oil cracking and gas generation. Pressure also makes a different effort in different evolvement stage. Taking the middle and lower Cambrian source rocks in the Tarim Basin as an example, primary oil generating quantity is 2232.24×10⁸t, residual oil and oil cracking gas quantity is 806.21×10⁸t and 106.95×10¹²m³ respectively.     

The distribution characteristic and its significance of compound specific isotopic composition of aromatic hydrocarbon from marine source rock and oil in the Tarim Basin,western China

Aromatic hydrocarbons are generally main distillation of crude oil and organic extract of source rocks. Bicyclic and tricyclic aromatic hydrocarbons can be purified by two-step method of chromatography on alumina. Carbon isotopic composition of individual aromatic hydrocarbons is affected not only by thermal maturity, but also by organic matter input, depositional environment, and hydrocarbon generation process based on the GC-IRMS analysis of Upper Ordovician, Lower Ordovician, and Cambrian source rocks in different areas in the Tarim Basin, western China. The subgroups of aromatic hydrocarbons as well as individual aromatic compound, such as 1-MP, 9-MP, and 2,6-DMP from Cambrian-Lower Ordovician section show more depleted 13 C distribution. The 13 C value difference between Cambrian-Lower Ordovician section and Upper Ordovician source rocks is up to 16.1‰ for subgroups and 14‰ for individual compounds. It can provide strong evidence for oil source correlation by combing the 13 C value and biomarker distribution of different oil and source rocks from different strata in the Tarim Basin. Most oils from Tazhong area have geochemical characteristics such as more negative 13C9-MP value, poor gammacerane, and abundant homohopanes, which indicate that Upper Ordovician source rock is the main source rock. In contrast, oils from Tadong area and some oils from Tazhong area have geochemical characteristics such as high 13C9-MP value, abundant gammacerane, and poor homohopanes, which suggest that the major contributor is Cambrian-Lower Ordovician source rock.     

Petroleum hydrocarbons in the arctic ocean surface water

The concentration of petroleum hydrocarbons in Arctic surface water under the ice north of Svalbard has been determined by fluorescence spectrofluorometry using three different excitation/emission wavelength combinations. With Kuwait crude oil as a reference, the concentration range is 0.1–0.6 μg l^?1 crude oil equivalents with respect to light molecular weight components and 0.05–0.2 μg l^?1 heavy molecular weight components.     

Paleo-Moho depth determined from the pressure of CO2 fluid inclusions: Raman spectroscopic barometry of mantle- and crust-derived rocks

The density, and therefore the pressure, of CO₂ fluid inclusions in minerals can be estimated from the Fermi diad splitting of Raman spectra of CO₂. An accurate determination of the pressure of CO₂ fluid inclusions enables the estimation of the depth origin of rocks from the deep Earth. A micro-Raman densimeter was applied to ultramafic–mafic xenoliths sampled along the Ohku coast of Oki-Dogo Island in the Sea of Japan (East Sea). The density of CO₂ fluid inclusions in the mafic granulite was 1.02–1.05 g/cm³, while those of lherzolites were 0.98–1.02 g/cm³. In contrast, the density of CO₂ fluid inclusions measured in olivine gabbro, clinopyroxenite, and harzburgite were lower ranging from 0.86–to 0.99 g/cm³. Taking into account the temperature condition estimated using a pyroxene thermometer, the mafic granulite originated from a depth of 27–30 km and the lherzolites from 25–29 km. The overlapping depth of 27–29 km can be interpreted as the depth including the Moho discontinuity under Oki-Dogo Island 3.3 Ma. This estimation is consistent with geophysical observations.     

The hydrothermal karstification and its effect on Ordovician carbonate reservoir in Tazhong uplift of Tarim Basin,Northwest China

With a detailed study on petrology, mineralogy and geochemistry of some important Ordovician carbonate well core samples in Tazhong uplift of Tarim Basin, the distinguishing symbols of hydrothermal karstification are first put forward as the phenomena of rock hot depigmentation, hot cataclasm and the appearance of typical hydrothermal minerals such as fluorite, barite, pyrite, quartz and sphalerite. The main homogenization temperatures of primary fluid inclusions in fluorite are from 260 to 310°C, indicating the temperature of hydrothermal fluid. The fluid affected the dissolved rocks and showed typical geochemistry features with low contents of Na and Mg, and high contents of Fe, Mn and Si. The ratio of ³He/⁴He is 0.02R _a, indicating the fluid from the typical continental crust. The hydrothermal fluid karstification pattern may be described as follows: the hot fluid is from the Permian magma, containing dissolving ingredients of CO₂ and H₂S, and shifts along fault, ruptures and unconformity, and dissolves the surrounding carbonates while it flows. The mechanism of hydrothermal karstification is that the mixture of two or more fluids, which have different ion intensity and pH values, becomes a new unsaturated fluid to carbonates. The hydrothermal karstification is an important process to form hypo-dissolved pinholes in Ordovician carbonates of Tazhong uplift of Tarim Basin, and the forming of hydrothermal minerals also has favorable influence on carbonate reservoirs.

     

The hydrothermal karstification and its effect on Ordovician carbonate reservoir in Tazhong uplift of Tarim Basin,Northwest China

With a detailed study on petrology, mineralogy and geochemistry of some important Ordovician carbonate well core samples in Tazhong uplift of Tarim Basin, the distinguishing symbols of hydrothermal karstification are first put forward as the phenomena of rock hot depigmentation, hot cataclasm and the appearance of typical hydrothermal minerals such as fluorite, barite, pyrite, quartz and sphalerite. The main homogenization temperatures of primary fluid inclusions in fluorite are from 260 to 310°C, indicating the temperature of hydrothermal fluid. The fluid affected the dissolved rocks and showed typical geochemistry features with low contents of Na and Mg, and high contents of Fe, Mn and Si. The ratio of ³He/⁴He is 0.02R _a, indicating the fluid from the typical continental crust. The hydrothermal fluid karstification pattern may be described as follows: the hot fluid is from the Permian magma, containing dissolving ingredients of CO₂ and H₂S, and shifts along fault, ruptures and unconformity, and dissolves the surrounding carbonates while it flows. The mechanism of hydrothermal karstification is that the mixture of two or more fluids, which have different ion intensity and pH values, becomes a new unsaturated fluid to carbonates. The hydrothermal karstification is an important process to form hypo-dissolved pinholes in Ordovician carbonates of Tazhong uplift of Tarim Basin, and the forming of hydrothermal minerals also has favorable influence on carbonate reservoirs.     

Geobarometry of ultramafic xenoliths from Loihi Seamount,Hawaii, on the basis of CO2 inclusions in olivine

Abundant fluid inclusions in olivine of dunite xenoliths (～1–3 cm) in basalt dredged from the young Loihi Seamount, 30 km southeast of Hawaii, are evidence for three coexisting immiscible fluid phases—silicate melt (now glass), sulfide melt (now solid), and dense supercritical CO₂ (now liquid + gas)—during growth and later fracturing of some of these olivine crystals. Some olivine xenocrysts, probably from disaggregation of xenoliths, contain similar inclusions.Most of the inclusions (2–10 μm) are on secondary planes, trapped during healing of fractures after the original crystal growth. Some such planes end abruptly within single crystals and are termed pseudosecondary, because they formed during the growth of the host olivine crystals. The “vapor” bubble in a few large (20–60 μm), isolated, and hence primary, silicate melt inclusions is too large to be the result of simple differential shrinkage. Under correct viewing conditions, these bubbles are seen to consist of CO₂ liquid and gas, with an aggregate ? = ～ 0.5–0.75 g cm^?3, and represent trapped globules of dense supercritical CO₂ (i.e., incipient “vesiculation” at depth). Some spinel crystals enclosed within olivine have attached CO₂ blebs. Spherical sulfide blebs having widely variable volume ratios to CO₂ and silicate glass are found in both primary and pseudosecondary inclusions, demonstrating that an immiscible sulfide melt was also present.Assuming olivine growth at ～ 1200°C and hydrostatic pressure from a liquid lava column, extrapolation of CO₂P-V-T data indicates that the primary inclusions were trapped at ～ 220–470 MPa (2200–4700 bars), or ～ 8–17 km depth in basalt magma of ? = 2.7 g cm^?3. Because the temperature cannot change much during the rise to eruption, the range of CO₂ densities reveals the change in pressure from that during original olivine growth to later deformation and rise to eruption on the sea floor. The presence of numerous decrepitated inclusions indicates that the inclusion sample studied is biased by the loss of higher-density inclusions and suggests that some part of these olivine xenoliths formed at greater depths.     

Carbon isotopic compositions of 1,2,3,4-tetramethylbenzene in marine oil asphaltenes from the Tarim Basin: Evidence for the source formed in a strongly reducing environment

Although 1-alkyl-2,3,6-trimethylbenzenes and a high relative amount of 1,2,3,4-tetramethylbenzene have been detected in marine oils and oil asphaltenes from Tabei uplift in the Tarim Basin, their bio-logical sources are not determined. This paper deals with the molecular characteristics of typical ma-rine oil asphaltenes from Tabei and Tazhong uplift in the Tarim Basin and the stable carbon isotopic signatures of individual compounds in the pyrolysates of these asphaltenes using flash pyrolysis-gas chromatograph-mass spectrometer (PY-GC-MS) and gas chromatograph-stable isotope ratio mass spectrometer (GC-C-IRMS), respectively. Relatively abundant 1,2,3,4-tetramethylbenzene is detected in the pyrolysates of these marine oil asphaltenes from the Tarim Basin. δ 13C values of 1,2,3,4-tetrame-thylbenzene in the pyrolysates of oil asphaltenes vary from-19.6‰ to-24.0‰, while those of n-alkanes in the pyrolysates show a range from-33.2‰ to-35.1‰. The 1,2,3,4-tetramethylbenzene in the pyro-lysates of oil asphaltenes proves to be significantly enriched in 13C relative to n-alkanes in the pyro-lysates and oil asphaltenes by 10.8‰―15.2‰ and 8.4‰―13.4‰, respectively. This result indicates a contribution from photosynthetic green sulfur bacteria Chlorobiaceae to relatively abundant 1,2,3,4-tetramethylbenzene in marine oil asphaltenes from the Tarim Basin. Hence, it can be speculated that the source of most marine oil asphaltenes from the Tarim Basin was formed in a strongly reducing water body enriched in H2S under euxinic conditions.     

Hydrocarbon concentrations in water and sediments from UK marine waters,determined by fluorescence spectroscopy

Between January 1978 and September 1979 samples of subsurface (1 m) water and surface sediment were collected from sites in the North Sea, English Channel, Irish Sea and a number of estuarine areas. These have been analysed by fluorescence spectroscopy (UVF) in order to provide information on the levels of hydrocarbons generally present in UK marine waters.Total hydrocarbon concentrations (THCs) of water samples ranged from 1.1–74 μg l.^?1 Ekofisk crude oil equivalents, all values greater than 3.5 μg l.^?1 occurring inshore. In offshore areas the mean THCs were: 1.3 μg l.^?1 in the northern North Sea, 1.5 μg l.^?1 in the western Channel, 2.5 μg l.^?1 in the eastern Channel and southern North Sea, and 2.6 μg l.^?1 in the Irish Sea.THCs of sediment samples ranged from 0.27–340 μ g^?1 dry weight Ekofisk crude oil equivalents, the highest concentration being in the Queen's Channel, the main entrance to the River Mersey.     

Analysis of snowpack dynamics during the spring melt season for a sub‐alpine site using point measurements and numerical modeling

Snowpack dynamics through October 2014–June 2017 were described for a forested, sub‐alpine field site in southeastern Wyoming. Point measurements of wetness and density were combined with numerical modeling and continuous time series of snow depth, snow temperature, and snowpack outflow to identify 5 major classes of distinct snowpack conditions. Class (i) is characterized by no snowpack outflow and variable average snowpack temperature and density. Class (ii) is characterized by short durations of liquid water in the upper snowpack, snowpack outflow values of 0.0008–0.005 cm hr^?1, an increase in snowpack temperature, and average snow density between 0.25–0.35 g cm^?3. Class (iii) is characterized by a partially saturated wetness profile, snowpack outflow values of 0.005–0.25 cm hr^?1, snowpack temperature near 0 °C, and average snow density between 0.25–0.40 g cm^?3. Class (iv) is characterized by strong diurnal snowpack outflow pattern with values as high as 0.75 cm hr^?1, stable snowpack temperature near 0 °C, and stable average snow density between 0.35–0.45 g cm^?3. Class (v) occurs intermittently between Classes (ii)–(iv) and displays low snowpack outflow values between 0.0008–0.04 cm hr^?1, a slight decrease in temperature relative to the preceding class, and similar densities to the preceding class. Numerical modeling of snowpack properties with SNOWPACK using both the Storage Threshold scheme and Richards' equation was used to quantify the effect of snowpack capillarity on predictions of snowpack outflow and other snowpack properties. Results indicate that both simulations are able to predict snow depth, snow temperature, and snow density reasonably well with little difference between the 2 water transport schemes. Richards' equation more accurately simulates the timing of snowpack outflow over the Storage Threshold scheme, especially early in the melt season and at diurnal timescales.     

The effect of volatile components in oil on evolutionary characteristics of diamondoids during oil thermal pyrolysis

On the basis of the results of simulation experiments, now we better understand the contribution of high carbon number hydrocarbons to diamondoid generation during thermal pyrolysis of crude oil and its sub-fractions(saturated, aromatic, resin, and asphalene fractions). However, little is known about the effect of volatile components in oil on diamondoid generation and diamondoid indices due to the lack of attention to these components in experiments. In this study, the effect of volatile components in oil on diamondoid generation and maturity indices was investigated by the pyrolysis simulation experiments on a normal crude oil from the HD23 well of the Tarim Basin and its residual oil after artificial volatilization, combined with quantitative analysis of diamondoids. The results indicate that the volatile components(≤n C12) in oil have an obvious contribution to the generation of adamantanes, which occurs mainly in the early stage of oil cracking(Easy Ro1.0%), and influences the variations in maturity indices of adamantanes; but they have no obvious effect on the generation and maturity indices of diamantanes. Therefore, some secondary alterations e.g., migration, gas washing, and biodegradation, which may result in the loss of light hydrocarbons in oil under actual geological conditions, could affect the identification of adamantanes generated during the late-stage cracking of crude oil, and further influence the practical application of adamantane indices.     

Effects of abnormally high heat stress on petroleum in reservoir

An igneous intrusion of 94m thick was discovered intruding into the Silurian sandstone from Tazhong 18 Well. The petroleum previously preserved in the Silurian sandstone reservoir was altered into black carbonaceous bitumen by abnormally high heat stress induced by the igneous intrusion. The reflectance of the carbonaceous bitumen reaches as high as 3.54%, indicating that the bitumen had evolved into a high thermal evolution level. Similar to the Silurian samples from the neighboring Tazhong 11, Tazhong 12, Tazhong 45 and Tazhong 47 wells, the distribution of C₂₇, C₂₈ and C₂₉ steranes of the carbonaceous bitumen is still “V”-shaped and can still be employed as an efficient parameter in oil source correlation. The “V”-shaped distribution indicates that the hydrocarbons from the Tazhong 18 and the neighboring wells were all generated from the Middle-Upper Ordovician hydrocarbon source rocks. However, the oil source correlation parameters associated with and terpanes had been changed greatly by the high heat stress and can no longer be used in oil source correlation. The δ ¹³C values of the petroleum from the neighboring wells are between −32.53%. and −33.37%., coincident with those of the Paleozoic marine petroleum in the Tarim Basin. However, the δ ¹³C values of the carbonaceous bitumen from the Tazhong 18 Well are between −27.18%. and −29.26%., isotopically much heavier than the petroleum from the neighboring wells. The content of light hydrocarbons (nC₁₄−nC₂₀) of the saturated hydrocarbon fraction in the carbonaceous bitumen is extremely higher than the content of heavy hydrocarbons. The light/heavy hydrocarbon ratios (ΣnC₂₁ ⁻/ΣnC₂₂ ⁺ are between 4.56 and 39.17. In the saturated fraction, the even numbered hydrocarbons are predominant to the odd numbered, and the OEP (Odd to Even Predominance) values are between 0.22 and 0.49. However, the content of light hydrocarbons in the petroleum from the neighboring wells is relatively low and the content of the even numbered hydrocarbons is almost equal to that of the odd numbered. Compared with the samples from the neighboring wells, the abundance of non-alkylated aromatic hydrocarbons, such as phenanthrenes, and polycyclic aromatic hydrocarbons (PAHs), such as fluoranthane, pyrene, benzo[a]anthracene and benzofluoranthene, are relatively high. Supported by the National Key Basic Research and Development Project (Grant No. 2005CB422103)     

Effects of soil compaction,rain exposure and their interaction on soil carbon dioxide emission

Soils release more carbon, primarily as carbon dioxide (CO₂), per annum than current global anthropogenic emissions. Soils emit CO₂ through mineralization and decomposition of organic matter and respiration of roots and soil organisms. Given this, the evaluation of the effects of abiotic factors on microbial activity is of major importance when considering the mitigation of greenhouse gases emissions. Previous studies demonstrate that soil CO₂ emission is significantly affected by temperature and soil water content. A limited number of studies have illustrated the importance of bulk density and soil surface characteristics as a result of exposure to rain on CO₂ emission, however, none examine their relative importance. Therefore, this study investigated the effects of soil compaction and exposure of the soil surface to rainfall and their interaction on CO₂ release. We conducted a factorial laboratory experiment with three soil types after sieving (clay, silt and sand soil), three different bulk densities (1·1 g cm^–3, 1·3 g cm^–3, 1·5 g cm^–3) and three different exposures to rainfall (no rain, 30 minutes and 90 minutes of rainfall). The results demonstrated CO₂ release varied significantly with bulk density, exposure to rain and time. The relationship between rain exposure and CO₂ is positive: CO₂ emission was 53% and 42% greater for the 90 minutes and 30 minutes rainfall exposure, respectively, compared to those not exposed to rain. Bulk density exhibited a negative relationship with CO₂ emission: soil compacted to a bulk density of 1·1 g cm^–3 emitted 32% more CO₂ than soil compacted to 1·5 g cm^–3. Furthermore we found that the magnitude of CO₂ effluxes depended on the interaction of these two abiotic factors. Given these results, understanding the influence of soil compaction and raindrop impact on CO₂ emission could lead to modified soil management practices which promote carbon sequestration. Copyright © 2012 John Wiley & Sons, Ltd.     

Results of two bilateral comparisons of the determination of hydrocarbon concentrations in coastal seawater by fluorescence spectroscopy

During two recent research cruises, comparisons were made of measurements of hydrocarbon concentrations in seawater by fluorescence spectroscopy. Participants used their own samplers and methods to collect and analyse duplicate samples of subsurface water; 21 stations were sampled during the first cruise and 15 during the second. When samples containing hydrocarbons at concentrations of 1–2 μg l⁻¹ Ekofisk crude oil equivalents were extracted using solvents of similar polarity, i.e. pentane or hexane, results on average varied by 22% and 23% in the two exercises. Use of dichloromethane as an extraction solvent gave results around 2× higher; the reasons for this are discussed.     

Three-phase measurements of oil and gas trapping in sand packs

We measure the trapped saturations of oil and gas as a function of initial saturation in water-wet sand packs. We start with a water-saturated column and inject octane (oil), while water and oil are produced from the bottom. Once water production has ceased, air (gas) then enters from the top, allowing oil and gas to drain under gravity for different times. Finally water is then injected from the bottom to trap both oil and gas. The columns are sliced and the fluids analyzed using gas chromatography. We find that for high initial gas saturations more gas can be trapped in the presence of oil than in a two-phase (gas/water) system. The residual gas saturation can be over 20% compared to 14% in two-phase flow [Al Mansoori SK, Iglauer S, Pentland CH, Bijeljic B, Blunt MJ. Measurements of non-wetting phase trapping applied to carbon dioxide storage. Energy Procedia 2009;1(1):3173–80]. This is unlike previous measurements on consolidated media, where the trapped gas saturation is either similar or lower to that reached in an equivalent two-phase experiment. For lower initial gas saturation, the amount of trapping follows the initial-residual trend seen in two-phase experiments. The amount of oil trapped is insensitive to initial gas saturation or the amount of gas that is trapped, again in contrast to measurements on consolidated media. More oil is trapped than would be predicted from an equivalent two-phase (oil/water) system, although the trapped saturation is never larger than the maximum reached in two-phase flow (around 11%) [Pentland CH, Al Mansoori SK, Iglauer S, Bijeljic B, Blunt MJ. Measurement of non-wetting phase trapping in sand packs. In: SPE 115697, proceedings of the SPE annual technical conference and exhibition, Denver, Colorado, USA; 21–24 September 2008]. These initially surprising results are explained in the context of oil layer stability and the competition between snap-off and piston-like advance. In two-phase systems, displacement is principally by cooperative piston-like advance with relatively little trapping, whereas in consolidated media snap-off is generally more significant. However, oil layer collapse events during three-phase waterflooding rapidly trap the oil which acts as a barrier to direct water/gas displacement, except by snap-off, leading to enhanced gas trapping.     

Raman characteristics of hydrocarbon and hydrocarbon inclusions

The Raman spectrograms of hydrocarbon standard samples show that: (1) the Raman spectrogram of normal paraffin has very strong peaks of methyl and methylene (from 2700 cm-1 to 2970 cm-1); (2) branch methyl has the particular peak of 748 cm-1±; (3) six cyclic has the particular peak of 804 cm-1±; (4) phenyl has two particular peaks of 988 cm-1± and 3058 cm-1± and the 988 cm-1± peak is stronger than the 3058 cm-1± peak; and (5) hexene has three alkenyl spectrum peaks of 1294 cm-1±, 1635 cm-1± and 2996 cm-1±, with the 1635 cm-1± peak being the strongest, showing that the number of carbon in hy-drocarbon does not affect its Raman spectrogram, and the hydrocarbon molecular structure and base groups affect its Raman spectrogram, the same hydrocarbons (such as normal paraffin) have the same Raman spectrogram; the types (such as CH4, C2H6, C3H8) and the content of hydrocarbon in oil inclu-sions are not estimated by their characteristic Raman peaks. According to the Raman spectrograms of hydrocarbon compositions, the Raman spectrogram of hydrocarbon inclusion can be divided into five types: saturated hydrocarbon Raman spectrogram, fluoresce Raman spectrogram, saturated hydro-carbon bitumen Raman spectrogram, bitumen Raman spectrogram, and ethane Raman spectrogram. And according to the characteristics of Raman spectrogram, hydrocarbon inclusions can be divided into five types: saturated hydrocarbon inclusion, less saturated hydrocarbon (oil or gas) inclusion, saturated hydrocarbon bitumen inclusion, bitumen inclusion, and methane water inclusion.     

A new occurrence of retrogressed eclogite from the Sanbagawa belt of southwest Japan and its significance

The present paper reports, for the first time, the occurrence of an omphacite‐bearing mafic schist from the Asemi‐gawa region of the Sanbagawa belt (southwest Japan). The mafic schist occurs as thin layers within pelitic schist of the albite–biotite zone. Omphacite in the mafic schist only occurs as inclusions in garnet, and albite is the major Na phase in the matrix, suggesting that the mafic schist represents highly retrogressed eclogite. Garnet grains in the sample show prograde‐type compositional zoning with no textural or compositional break, and contain mineral inclusions of omphacite, quartz, glaucophane, barroisite/hornblende, epidote and titanite. In addition to the petrographic observations, Raman spectroscopy and focused ion beam system–transmission electron microscope analyses were used for identification of omphacite in the sample. The omphacite in the sample shows a strong Raman peak at 678 cm^?1, and concomitant Raman peaks are all consistent with those of the reference omphacite Raman spectrum. The selected area electron diffraction pattern of the omphacite is compatible with the common P2/n omphacite structure. Quartz inclusions in the mafic schist preserve high residual pressure values of Δω₁ > 8.5 cm^?1, corresponding to the eclogite facies conditions. The combination of Raman geothermobarometries and garnet–clinopyroxene geothermometry gives peak pressure–temperature (P–T) conditions of 1.7–2.0 GPa and 440–540 °C for the mafic schist. The peak P–T values are comparable to those of the schistose eclogitic rocks in other Sanbagawa eclogite units of Shikoku. These findings along with previous age constraints suggest that most of the Sanbagawa schistose eclogites and associated metasedimentary rocks share similar simple P–T histories along the Late Cretaceous subduction zone.     

Effects of rainfall intensity and compaction on water transport from opencast coal mine soils: An experimental study

The use of heavy machinery during opencast coal mining can result in soil compaction. Severe soil compaction has a negative impact on the transport of water and gas in the soil. In addition, rainfall intensity has traditionally been related to soil surface sealing affecting water transport. To assess the effects of rainfall intensity and compaction on water infiltration and surface runoff in an opencast coal mining area, the disturbed soils from the Antaibao opencast mine in Shanxi Province, China, were collected. Four soil columns with different bulk densities (i.e., 1.4 g cm^-3, 1.5 g cm^-3, 1.6 g cm^-3, and 1.7 g cm^-3) were designed, and each column received water five times at rainfall intensities of 23.12, 28.91, 38.54, 57.81, and 115.62 mm hr^-1. The total volume of runoff, the time to start runoff, and the volumetric water contents at the depths of 5 cm, 15 cm, 25 cm, 35 cm, 45 cm, 55 cm, and 65 cm were measured. Under the same soil bulk density, high rainfall intensity reduced infiltration, increased surface runoff, and decreased the magnitude of change in the volumetric water contents at different depths. Under the same rainfall intensity, the soil column with a high bulk density showed relatively low water infiltration. Treatments 3 (1.6 g cm^-3) and 4 (1.7 g cm^-3) had very small changes in volumetric water contents of the profiles even under a lower rainfall intensity. Severe soil compaction was highly prone to surface runoff after rainfall. Engineering and revegetation measures are available to improve compacted soil quality in dumps. Our results provide a theoretical basis for the management of land reclamation in opencast coal mine areas.     

Chemical evolution of Macondo crude oil during laboratory degradation as characterized by fluorescence EEMs and hydrocarbon composition

The fluorescence EEM technique, PARAFAC modeling, and hydrocarbon composition were used to characterize oil components and to examine the chemical evolution and degradation pathways of Macondo crude oil under controlled laboratory conditions. Three major fluorescent oil components were identified, with Ex/Em maxima at 226/328, 262/315, and 244/366 nm, respectively. An average degradation half-life of ～20 d was determined for the oil components based on fluorescence EEM and hydrocarbon composition measurements, showing a dynamic chemical evolution and transformation of the oil during degradation. Dispersants appeared to change the chemical characteristics of oil, to shift the fluorescence EEM spectra, and to enhance the degradation of low-molecular-weight hydrocarbons. Photochemical degradation played a dominant role in the transformation of oil components, likely an effective degradation pathway of oil in the water column. Results from laboratory experiments should facilitate the interpretation of field-data and provide insights for understanding the fate and transport of oil components in the Gulf of Mexico.