Wenxuan Hu

Episodic petroleum fluid migration in fault zones of the northwestern Junggar Basin (northwest China): Evidence from hydrocarbon-bearing zoned calcite cement

Hydrocarbon-bearing zoned calcite cements occur widely in Jurassic–Cretaceous fault-zone cores and sandstone outcrops of the northwestern Junggar Basin (northwest China). Hydrocarbon-bearing bands alternate with nearly hydrocarbon-free bands at a micron scale. Analytical results from biomarker organic geochemistry, Fourier transform infrared microspectroscopy, and trace-element geochemistry on these zoned cements suggest that at least three different types of fluids have participated in their formation. The first fluid type is probably primary, unmodified lacustrine formation water, from which the hydrocarbon-poor bands are formed and are characterized by Mg-rich calcite. The other two types of fluids include basinal fluids (e.g., hot hydrocarbon-bearing fluids) and meteoric water. The hydrocarbon-rich bands in which the hydrocarbons have been biodegraded and the Mn content is relatively high suggest a mixture of hydrocarbon-bearing basinal fluid and meteoric water. The alternating growth of hydrocarbon-bearing and hydrocarbon-free bands of calcite cements implies that the cement formation is episodic; it is related to alternating episodes of mixed petroleum-bearing fluid and unmodified primary formation waters, respectively. The fault appears to have been a mixing zone where seismic pumping during the movement of associated regional faults occurred. Thus, in the northwestern Junggar Basin, the micron-scale hydrocarbon-bearing zoned structure of the calcite cements is likely a reflection of episodic petroleum fluid migration in fault zones.

Prediction of Nitrogen Solubility in Pure Water and Aqueous NaCl Solutions up to High Temperature, Pressure, and Ionic Strength

A thermodynamic model for the solubility of nitrogen in pure water (273–623 K, 0–600 bar) and in aqueous NaCl solutions (0–4m, 273-473 K, 0–600 bar) is presented. The model is based on a specific interaction model for the liquid phase and a highly accurate equation of state for the vapor phase. Comparison of the model predictions with experimental data indicates that the model predictions are within or close to experimental uncertainty. Most experimental data sets are consistent within errors of about 7%. Although the parameters were evaluated from data for binary and ternary systems, the model can be used to predict nitrogen solubility in much more complicated systems like seawater.

Evolution of coal structures: FTIR analyses of experimental simulations and naturally matured coals in the Ordos Basin, China

A series of coals of varying rank, from brown coal to anthracite, were studied by Fourier transform infrared spectroscopy (FTIR). Curve-fitting analysis was employed to characterize coal structural evolution during the coalification process. The study was carried out on samples of a natural evolutionary series as well as experimental simulation coals dispersed on KBr pellets throughout the Ordos Basin, China. The results showed that the infrared spectrum of coal allowed quality and even quantity identification of the degree of coalification. Oxygen-containing groups and alkyl side chains of coal cracked at different rates with increasing degree of coalification. The cracking rates were divided into three stages according to the main changes in coal structure. These stages were carboxyl groups, fat groups and aromatic rings. Carboxyl groups decreased when Ro was less than 0.5%, and these groups were maintained until the fat coal stage began. Fat groups mainly cracked at the asphaltization stage and formed abundant hydrocarbons. These groups were the main sources for the formation of immature and low maturity, coal-generating oil before asphaltization. In the high evolutionary stage, after asphaltization, all alkyl side chains in the coal had cracked, while the degree of condensed aromatic rings had increased greatly. The ratios of aromatic hydrocarbons (3000 to 3100 cm−1) to aliphatic carbons (2800 to 3000 cm−1), CH2/CH3 (2920/2950 cm−1) and carboxyl groups to aromatic carbons (1705/1620 cm−1 + 1600cm−1 + 1580 cm−1) appeared to be suitable parameters for assessing the natural maturation of coal.

A preliminary study of mantle-derived fluids and their effects on oil/gas generation in sedimentary basins

Abstract This paper presents the geochemical features of mantle-derived fluids and their activities based on previous studies. To further reveal the features of the fluids and their effects on oil/gas generation in basins, we have investigated mantle-derived fluids in the Dongying Depression of the Bohai Bay Basin by means of isotopic geochemistry, organic geochemistry and thermodynamics. We found that two types of mantle-derived fluids, those rich in CO 2 (H 2 O+CO 2 +CH 4 ) and those rich in H (H 2 O+CH 4 +H 2 ), were injected into the Dongying Depression. Quantitative studies of thermal energy transfer by mantle-derived fluids ascendance show that the mantle-derived fluids are an effective heat carrier. The thermal anomalies in the Dongying Depression demonstrate the existence of thermal effects of mantle-derived fluids. It is usually suggested that hydrocarbon generation from kerogen degradation not only needs thermal energy but also requires hydrogen. Our experimental simulations show that kerogen hydrogenation can increase hydrocarbon generation greatly. For the sapropelic kerogen, the effect of hydrogenation becomes highly evident after the peak hydrocarbon generation and the hydrocarbon production rate can be increased by up to 147%. For the humic kerogen, hydrogenation can increase hydrocarbon production rate at every stage of the organic matter evolution. It was found that hydrogenation by H-rich fluids derived from the mantle might have happened in the Dongying Depression. We believe that mantle-derived fluids have important effects on hydrocarbon generation by providing both reaction energy and materials.

New evidence of microbe origin for ferromanganese nodules from the East Pacific deep sea floor

Using a fluorescence microscope and EPMA, abundant microbe ”bodies“ and clear microbic fluorescent microstructure are determined in the ferromanganese nodules recently collected from the East Pacific deep sea floor. The microbic fluorescent structure shows a close relation to the formation of the ferromanganese nodules. According to their morphological features, the microbes are classified into two types: one is named clumpy microbe, which takes a bar-shaped manganese mineral as a pillar and grows like fasciculate coral, resulting in irregular cauliflorate nodules with rough surfaces; the other is called filamentous microbe, which grows in very thin arcuate and/or concentric circular laminae composed of a microbe layer and a metal (manganese and iron)-rich layer, leading to potato-shaped nodules with relatively smooth surfaces. It also can be seen that the two types of microbes are intergrown together, resulting in nodules complicated in compositions and shapes.

High-quality hydrocarbon source rock in the Paleogene sequence of the Ping Chau Formation, Hong Kong

Although petroleum exploration is being conducted in the Hong Kong region, high-quality hydrocarbon source rocks have never been found in this area. The Ping Chau Formation is only Mesozoic-Cenozoic sedimentary rock exposed in Hong Kong and its surrounding areas. The hydrocarbon source rock of the Ping Chau Formation is very rich in organic matters, which has an average total organic carbon (TOC) of 1.9% and chloroform bitumen “A” range from 0.14% to 0.24%. The total hydrocarbon content varies from 880 to 1800 ppm and the transformation ratio is specific from 5 to 9. The index of pyrolytic hydrogen is up to about 600 mgHC/gTOC. These data demonstrate the characteristics of the high-quality hydrocarbon source rock. The lamalginite is the major maceral of the source rock of the Ping Chau Formation, and geochemical characteristics also suggest that the organic materials of the source rock are of type I and type II1, with abundant gammacerane, γ, β-carotane and C24 tetracyclic terpane, which indicate that it was formed in the salt water and brackish water sedimentary environment, and the source rock has evolved into a mature phase. The organic inclusions are found within calcite veins in cracks of the source rock, indicating that hydrocarbon has been generated and a secondary migration has happened. The source rock in the Ping Chau Formation is about 200–300 m thick, thus having considerable hydrocarbon potential. The discovery of the high quality hydrocarbon source rock in the Ping Chau Formation will certainly provide insight on hydrocarbon resource exploration in the South China Sea area.

Identification of NW-Trending Faults in the Northwestern Junggar Basin (NW China) and its Significance of Hydrocarbon Migration

The presence of the NW-trending faults in the northwestern Junggar Basin (NW China) and their relation to hydrocarbon migration were discussed. The presence of the faults was confirmed by new seismic and stratigraphic studies. They formed a rectangular-shape fault system together with the previously and commonly acknowledged NE-trending faults. Hydrocarbon shows are present widely in the cross of the two types of faults on the basis of field survey. Representative shows were further analyzed by petrography and geochemistry, in order to understand hydrocarbon migration features. It is implied that the two types of faults are both significant for the migration. In particular, the newly identified NW-trending faults can act as the primary and ultimate pathway for migration from the petroleum source to accumulation areas. Thus a new complex fault-controlled hydrocarbon migration model was suggested. Favorable hydrocarbon exploration targets were predicted according to the model, providing new information for shaping exploration and exploitation strategies. The results also have wide implications for the study in elsewhere mountain-front piedmont areas where the hydrocarbon exploration and exploitation is generally related to fault.

Characteristics and formation mechanisms of silicified carbonate reservoirs in well SN4 of the Tarim Basin

High-yield natural gas was discovered in well SN4 in the Ordovician Yingshan Formation in the Tarim Basin. The gas is found in unusual, silicified, carbonate reservoirs. According to the degree of silicification, the silicified reservoirs can be divided into a lower section of silicified carbonates, a middle section of limestone, and an upper section of silicified carbonates. The silicified carbonates are mainly composed of quartz and calcite, in which the reservoir space mostly occurs as vugs, inter-crystalline pores of quartz, and partial fractures. Porosity varies widely, ranging from 3 to 20.5% with strong heterogeneity. The homogenization temperatures of fluid inclusions in quartz and calcite show that the silicification temperatures were 150–190°C, with characteristics of high temperature/low salinity and low temperature/high salinity. The 87Sr/86Sr ratios of secondary calcite are 0.709336–0.709732, which are significantly higher than that of concurrent seawater, indicating that the hydrothermal fluid originated from the deep clastic strata or the basement (sialic rock). The δ13C values of the secondary calcite are similar to that of the surrounding limestone, indicating that the carbon in the secondary calcite is derived from the limestone strata, and that the secondary calcite is the product of dissolution and re-precipitation resulting from interaction between the silica-bearing hydrothermal fluids and surrounding limestones. The silicification of silica-bearing hydrothermal fluid was significantly controlled by strike-slip faults. The fluids ascending along the fault zone and branch faults interacted with the surrounding limestone in the Yingshan Formation. As a result, a large amount of quartz and secondary calcite were formed together with various types of secondary pores, resulting in excellent reservoirs.

Hydrocarbon potential of the Lower Cretaceous mudstones in coastal southeastern China

The Cretaceous hosts the highest hydrocarbon potential among all geological stratigraphic sequences worldwide, and the Lower Cretaceous in coastal southeastern China, with the development of black mudstones and shales, has potential for hydrocarbon generation. This potential, therefore, is of significance to regional hydrocarbon exploration both onshore and offshore; however, it has not been investigated in detail. Here, we address this issue based on the results of integrated organic geochemistry and petrology of four representative outcrop sections in the region. Results show that there are two possible source rock sequences in the Lower Cretaceous of coastal southeastern China, that is, a lower sequence represented by the Bantou Formation black mudstones in the Fujian Province and an upper interval represented by the Guantou Formation black mudstones or calcareous mudstones in the Zhejiang Province. The organic matter abundance of these two formations reaches levels of poor to good source rocks. The kerogen is dominated by type III, whereas type II can also be found locally in the northwestern Fujian Province. Most samples are highly mature to overmature, except for the samples with less influence of volcanism in the northern Guangdong Province. Comparatively, the organic matter abundance of the early-stage source rocks is higher than for the late-stage rocks, and the kerogen type is less favorable; however, the maturity shows little correlation with age and is largely related to volcanism. Therefore, the Lower Cretaceous in coastal southeastern China seems to have hydrocarbon potential (gas in particular) in local areas, including the northern Guangdong Province and its analog in offshore basins for the early stage and the northwestern Fujian Province and its analog in offshore basins for the late stage. These results and understanding provide insights for expanding new hydrocarbon exploration targets in southeastern China both onshore and offshore and may also have implications for understanding the regional Cretaceous geology.

An Experimental Study of the Formation of Talc through CaMg(CO3)2–SiO2–H2O Interaction at 100–200°C and Vapor-Saturation Pressures

The metamorphic interaction between carbonate and silica-rich fluid is common in geological environments. The formation of talc from dolomite and silica-rich fluid occurs at low temperatures in the metamorphism of the CaO–MgO–SiO2–CO2–H2O system and plays important roles in the formation of economically viable talc deposits, the modification of dolomite reservoirs, and other geological processes. However, disagreement remains over the conditions of talc formation at low temperatures. In this study, in situ Raman spectroscopy, quenched scanning electron microscopy, micro-X-ray diffraction, and thermodynamic calculations were used to explore the interplay between dolomite and silica-rich fluids at relatively low temperatures in fused silica tubes. Results showed that talc formed at ≤200°C and low CO2 partial pressures (PCO2). The reaction rate increased with increasing temperature and decreased with increasing PCO2. The major contributions of this study are as follows: we confirmed the formation mechanism of Mg-carbonate-hosted talc deposits and proved that talc can form at ≤200°C; the presence of talc in carbonate reservoirs can indicate the activity of silica-rich hydrothermal fluids; and (3) the reactivity and solubility of silica require further consideration, when a fused silica tube is used as the reactor in high P–T experiments.