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We investigated diagenesis of the sandstones from the DN2 Gas Field of the Kuqa Foreland Basin (KFB), in order to infer the timing of fluid migration and discuss the linkage between fluids and tectonics. The textures and chemical composition of authigenic minerals, fluid evidence from fluid inclusions and formation water measurements were all used to fulfill this aim. Eodiagenesis occurred with the participation of meteoric water and connate water. Mesodiagenesis is related to high salinity fluids, which were attributed as originating from the overlying Neogene Jidike Formation evaporite (principal minerals including halite, anhydrite, glauberite, carnallite and thenardite). The onset of high salinity fluid migration is inferred to occur during the late Miocene (12.4–9.2 Ma) through the use of homogenization temperatures measured in the present study and K‐Ar dating of authigenetic illites from previous work. This period is consistent with the crucial phase (13–10 Ma) that witnessed the rapid uplift of the southern Tianshan Mts and the stage when calcite and anhydrite veins formed in the studied strata. We thus argue that diagenesis related to high salinity fluids occurred as a response to the Tianshan Mts' rapid uplift and related tectonic processes. The flow of high salinity fluids was probably driven by a density gradient and channeled and focused by fractures formed contemporaneously. [ABSTRACT FROM AUTHOR]

• A novel type of oil inclusions with solid yellow-fluorescing rings found in a deep reservoir. • The yellow rings are quite waxy and rich in polyaromatics, and have a starting-to-melt point at 46 °C. • When measured under their homogenization temperature YROIs show a distinct "blue shift" in their fluorescence spectra. • The inclusions were trapped heterogeneously in the reservoir due to gas flushing of a light waxy oil under high pressure. Gas flushing of oil has been proposed as an essential process for forming some condensate gas reservoirs based on laboratory experiments and modeling but such a process has rarely been documented in subsurface reservoirs. Here, we report a unique type of yellow-ringed oil inclusions (YROIs) discovered from a deep reservoir in the Kuqa Foreland Basin, Western China that recorded the gas flushing of oil process in the subsurface. The occurrence, composition, phase state and PVT conditions of YROIs during trapping were investigated using a suite of fluid inclusion analytical methods including fluid inclusion petrography, microthermometry, fluorescence spectroscopy, PVT modeling and molecular composition analysis. YROIs found in the reservoir are three-phase (solid–liquid-vapor) fluid inclusions at room temperature with solid rings of 2–3 μm thickness and estimated volume percentages varying between 5 % and 15 %. When heated the solid ring starts to melt at around 46 °C and homogenized with the liquid phase at or above their corresponding homogenization temperatures of coeval aqueous inclusions. YROIs have fluorescence spectral peaks between 530 nm and 550 nm and an elevated spectral shoulder around 650 nm when measured at room temperature; but most spectra show a distinct "blue shift" and an absence of the 650 nm shoulder when measured at their homogenization temperatures. Some YROIs with thick yellow rings show dual spectral peaks at 570 nm and 630 nm at room temperature and their spectral peaks do not change when remeasured at their homogenization temperatures. Molecular compositions derived from synchronous fluorescence spectra and GC-MS analysis suggest that the compositions of YROIs are rich in polyaromatic compounds. PVT modeling indicates that YROIs were trapped under high pressure conditions with a pressure exceeding 50 % of the corresponding hydrostatic pressure. YROIs are interpreted to have been trapped under an elevated temperature and overpressure condition (around 110 °C and 60 MPa) relating to an intensive (wet) gas flushing of an early-charged wax-rich oil. When light hydrocarbon components in the reservoir oil were partially removed by gas, the wax/resin components rich in polyaromatic hydrocarbon compounds may precipitate due to physio-chemical fractionation. YROIs were entrapped in subsurface from a heterogeneous hydrocarbon fluid containing variable amounts of wax/resin colloids, which subsequently coalesce to form solid rings adhering to the inner wall of oil inclusions at room temperature. The presence of yellow-ringed oil inclusions in a reservoir may be indicative of a rapid gas flushing of waxy oil under high pressure, and their minimum homogenization temperature may approximate their trapping temperature. [ABSTRACT FROM AUTHOR]

Various lines of evidence, including the occurrence of bitumen and fluid inclusions, show that oil charge once took place in the Kela-2 gas field, Kuqa foreland basin, Northwest China. However, the scale of the ancient oil reservoir remains unclear, as does the process by which the reservoir evolved into the present dry gas field. Here, using data from analyses of fluid inclusions, petrography, laser Raman spectroscopy, and quantitative fluorescence, the hydrocarbon accumulation history of the Kela-2 gas field is reconstructed. The results show that the gas field underwent three periods of hydrocarbon charging and one period of adjustment. The first oil charging occurred at about 12 Ma, as recorded by the first group of oil inclusions containing 0–8 vol.% gas with yellowish-brown fluorescence. The second charging involved mature oil charging at about 4 Ma, recorded by the second group of oil inclusions containing 15–25 vol.% gas with blue-white fluorescence. According to quantitative grain fluorescence (QGF) and rock pyrolysis analysis, an ancient oil reservoir existed with an oil-column height of about 350 m, and the paleo oil–water contact was lower than the present gas–water contact. Under intense thrusting from 3 Ma, the ancient oil reservoir was destroyed, with oil escaping through the Kashangtuokai thrust fault, which broke the salt layer, as this layer at that time lay in the brittle deformation domain. The inferred destruction of the ancient oil reservoir is supported by the numerous oil and gas shows at the surface and in shallow layers near the Kashangtuokai fault, as well as the anomalous development of authigenic kaolinite in the gas reservoir, which was enhanced by an open or semiopen system caused by the fault breaking through the salt layer. Subsequently, with increasing burial depth to more than 3000 m, the fault that had cut through the salt layer annealed because the salt layer then lay within the ductile deformation domain. The higher overpressure that occurred during the third gas charging at about 2 Ma reflected the annealing of the fault in the salt layer, favoring late gas accumulation and preservation. The evolution of the Kela-2 gas field provides an important case study for understanding the role of the salt layer crossing the brittle–plastic transition and the dynamic evolution of the salt caprock in salt-containing foreland basins. [ABSTRACT FROM AUTHOR]

The article present research on Fluid Inclusion re-equilibration in Carbonate Rock caused by freezing during Microthermometric analysis. Topic include samples of carbonate rock from the Middle Ordovician Yijianfang formation selected from Well SHB -5 and Well YJ-1X in the Tarim Basin, with burial depths ranging from 7229.30 m to 7427.30 m .

Abundant gas and condensate resources are present in the Kuqa foreland basin in the northern Tarim Basin, NW China. Most of the hydrocarbons so far discovered are located in foldbelts in the north and centre of the foreland basin, and the Southern Slope region has therefore been less studied. This paper focusses on the Yangtake area in the west of the Southern Slope. Basin modelling was integrated with fluid inclusion analyses to investigate the oil and gas charge history of the area. ID modelling at two widely spaced wells (DB‐1 and YN‐2) assessed the burial, thermal and hydrocarbon generation histories of Jurassic source rocks in the foreland basin. Results show that the source rocks began to generate hydrocarbons (Ro >0.5%) during the Miocene. In both wells, the source rocks became mature to highly mature between 12 and 1.8 Ma, and most oil and gas was generated at 5.3–1.8 Ma with peak generation at about 3 Ma. Two types of petroleum fluid inclusions were observed in Cretaceous and lower Paleocene sandstone reservoir rocks at wells YTK‐5 and YTK‐1 in the Yangtake area. The inclusions in general occur along healed microfractures in quartz grains, and have either yellowish or blueish fluorescence colours. Aqueous inclusions coexisting with both types of oil inclusions in Cretaceous sandstones in well YTK‐5 had homogenization temperatures of 96–128 °C and 115–135 °C, respectively. The integrated results of this study suggest that oil generated by the Middle Jurassic Qiakemake Formation source rocks initially charged sandstone reservoirs in the Yangtake area at about 4 Ma, forming the yellowish‐fluorescing oil inclusions. Gas, which was mainly sourced from Lower Jurassic Yangxia and Middle Jurassic Kezilenuer coaly and mudstone source rocks, initially migrated into the same reservoirs in the Yangtake area at about 3.5 Ma and interacted with the early‐formed oils forming blueish‐fluorescing oil inclusions. The migration of gas also resulted in formation of the condensate accumulations which are present at the YTK‐1 and YTK‐2 fields in the Yangtake area. [ABSTRACT FROM AUTHOR]

The reservoir diagenetic process and the petroleum charge histories of the Cretaceous Bashijiqike Formation (K 1 bs) in the Kuqa Depression, Tarim Basin were studied using an integrated petrographic, fluid inclusion, reservoir diagenesis and basin modeling approach. A suite of techniques were used in the investigation including optical microscopy, scanning electron microscope (SEM), X-ray diffraction (XRD), fluorescence spectroscopy, microthermometry, and Laser Raman microspectroscopy. The workflow comprises petrographic characterization of the reservoir sandstone, identification of fluid inclusion assemblages, and construction of the diagenetic history of the reservoir sandstone with reference to the hydrocarbon charge and emplacement. Key diagenetic events identified include quartz overgrowths, early calcite cementation, dolomite cementation, alteration of kaolinite, bitumen emplacement, micro-quartz and ankerite cementation. The first diagenetic event was characterized by quartz overgrowths and followed by calcite and dolomite cementation. Kaolinite and ankerite cementation were the last diagenetic events, coincided with hydrocarbon charge and emplacement. Three episodes of hydrocarbon charge and emplacement have been recorded by the diagenetic products and fluid inclusions in the K1bs Formations: (1) the first episode of oil charge was recorded in the early calcite cement, and were trapped around at 18 Ma; (2) the second and third episodes of hydrocarbon charge were recorded in the telo-diagenetic ankerite, and were trapped around at 4–6 Ma. The timing of oil emplacement determined from fluid inclusion homogenization temperature and basin modeling is consistent with the formation order of the diagenetic minerals. This study has thus demonstrated that integrated analysis of fluid inclusion and reservoir diagenesis can be an effective tool for determining hydrocarbon charge and emplacement history. [ABSTRACT FROM AUTHOR]

A series of fault-related folds developed in the Dabei Gas Field of the Kuqa Depression, western China form major traps for hydrocarbon accumulation. The Bashijiqike (K 1 bs) sandstone reservoirs in the different fault-related folds of the Dabei Gas Field display similar excess fluid pressure, formation water type and salinity, and as well as light oil and gas properties. The light oil and gas in the K 1 bs sandstone reservoir of the traps share the same source and were generated at a thermal maturity level of 1.4–1.6% R o and 1.7–2.3% R o , respectively. To investigate the fluid evolution in the fault-related fold traps, an integrated fluid inclusion analysis was performed including petrography, fluorescence spectroscopy, microthermometry, Laser Raman spectroscopy and thermodynamic modeling. The fluid evolution recorded by the fluid inclusions in the different fault-related folds indicates that the formation fluid was characterized by low salinity at normal hydrostatic pressure from approximately >9–5 Ma. From 5 to 3 Ma the formation water salinity and fluid pressure increased rapidly. The formation water attained the highest salinity at approximately 3 Ma to present while the pore fluid overpressure decreased with time in the reservoir. Two episodes of oil and one episode of gas charge were identified in the K 1 bs sandstone reservoir with the second episode of oil charge occurring around 5–4 Ma, while the gas charge occurred around 3–2 Ma. The injection of new fluids associated with oil and gas charge caused changes of the formation water salinity in the different fault-related fold traps within the gas field. The fluid evolution in the Dabei Gas Field can be used to indicate fault-related fluid flow as the thrust faults are suggested to be the primly pathways for fluid migration and the fluid flow was controlled by the reactivation of these thrust faults. The similarity of the oil and gas charge histories, formation water salinity and fluid pressure evolution in the K 1 bs sandstone reservoirs among the different fault-related traps in the Dabei Gas Field implies that the fault-related fluid flow process and activation of the thrust faults were concomitant since approximately 9 Ma. [ABSTRACT FROM AUTHOR]

• The Ediacaran microbial-dominated carbonate reservoir (Z 2 dn2) consists mainly of thromatolitic, stromatolitic and straticulate dolomite lithofacies. • The Z 2 dn2 reservoir developed five generations of cement during a six-stage diagenetic evolution spanning 540 million years. • High-energy deposition, supergene karsting coupling dolomitization are essential for developing favorable reservoirs in Z 2 dn2. Some of the largest gas accumulations in the central Sichuan Basin, south China are hosted in the Ediacaran microbial-dominated dolomite reservoirs. However, recent exploration of the Secondary Member of the Ediacaran Dengying Formation (Z 2 dn2) has been hampered by an overall lack of understanding of the microbial-dominated dolomite reservoir and its diagenetic evolution process due to its prolonged burial history and complex diagenetic alternation. On the basis of detailed petrographic and geochemical analysis, we have conducted an in-depth investigation on the characteristics, diagenetic sequence and pore evolution process of the microbial-dominated dolomite reservoirs. The main reservoir comprises thromatolitic dolomite, stromatolitic dolomite and straticulate dolomite. Five generations of cement are identified in the microbial dolomite lithofacies. Multiple dissolution, cementation, differential dolomitization, recrystallization and silicification are recognized. Based on elemental geochemistry, carbon and oxygen isotope characteristics, as well as fluid inclusion homogenization temperatures, cements are attributed to six diagenetic stages. The coupling of high-energy deposition, early supergene karsting and dolomitization processes are found to be essential for developing some world-class favorable high-quality microbial-dominated dolomite reservoirs in Z 2 dn2 in the central Sichuan Basin. [ABSTRACT FROM AUTHOR]

The Kelasu Thrust Belt is a favorable hydrocarbon accumulation zone in the Kuqa Sub-basin with several known giant gas fields including the Dabei and Kela-2 gas fields as well as the Dawanqi oil field. The origin and accumulation process of the hydrocarbons were investigated through an integrated petroleum geochemistry and fluid inclusion analysis, and basin modeling. Geochemical parameters indicate that the light oils from the Dawanqi oil field and Dabei gas field were generated from different sources as compared with light oils from the Kela-2 gas field. Light oils from the Dawanqi oil field and Dabei gas field are primarily derived from the terrestrial mudstones in the Jurassic Qiakemake ( J 2 q ) Formation with a maturity level of 1.4–1.6 %Ro, whereas light oils from the Kela-2 gas field are mainly derived from the terrestrial mudstones in the Triassic Huangshanjie ( T 3 h ) with a maturity level of 1.6–1.8 %Ro. Gases in the Kelasu Thrust Belt are dominated by coal-type gas and are primarily generated from the Jurassic coal measures. Carbon isotope ratios suggest that gases in the Dawanqi oil field and Dabei gas field were generated at a thermal maturity level of 1.6–2.3 %Ro , while gas in the Kela-2 gas field was generated at a thermal maturity level of 2.1–2.5 %Ro. Two episodes of oil and one episode of gas charge were delineated in the Dabei gas field. The second episode of oil charge occurred around 5–4 Ma, while gas charge occurred around 3–2 Ma. Three episodes of oil and one episode of gas charge were identified in the Kela-2 gas field. The latter two episodes of oil charge occurred around 5.5–4.5 Ma and the gas charge occurred around 3–2 Ma. The timing of the petroleum charge was also confirmed by the correlation between the maturity of the source rocks during the times of charge and the maturity levels of the light oil and gas in the reservoirs. The later oil and gas charge occurred at the same period in both the Dabei and Kela-2 gas fields, possibly relating to structural reactivation caused by regional tectonic compression, because intense tectonic compression and rapid uplift of the Tianshan Mountains occurred during the same period, which may have caused thrust fault activation and opening. Hydrocarbon expulsion from the source rocks during the period was possibly also related to the regional tectonic movement, providing hydrocarbon sources for the reservoirs. [ABSTRACT FROM AUTHOR]

The Kuqa Foreland Basin (KFB) immediately south of the South Tianshan Mountains is a major hydrocarbon producing basin in west China. The Kelasu Thrust Belt in the basin is the most favorable zone for hydrocarbon accumulations. Widespread overpressures are present in both the Cretaceous and Paleogene reservoirs with pressure coefficients up to 2.1. The tectonic compression process in KFB resulted from the South Tianshan Mountains uplift is examined from the viewpoint of the overpressure generation and evolution in the Kelasu Thrust Belt. The overpressure evolution in the reservoir sandstones were reconstructed through fluid inclusion analysis combined with PVT and basin modeling. Overpressures at present day in the mudstone units in the Kelasu Thrust Belt and reservoir sandstones of the Dabei Gas Field and the Keshen zone are believed to have been generated by horizontal tectonic compression. Both disequilibrium compaction and horizontal tectonic compression are thought to contribute to the overpressure development at present day in the reservoir of the Kela-2 Gas Field with the reservoir sandstones showing anomalously high primary porosities and low densities from wireline log and core data. The overpressure evolution for the Cretaceous reservoir sandstone in the Kelasu Thrust Belt evolved through four stages: a normal hydrostatic pressure (>12–5 Ma), a rapidly increasing overpressure (∼5–3 Ma), an overpressure release (∼3–1.64 Ma) and overpressure preservation (∼1.64–0 Ma). Overpressure developed in the second stage (∼5–3 Ma) was generated by disequilibrium compaction as tectonic compression due to the uplift of the Tianshan Mountains acted at the northern monocline of KFB from 5 Ma to 3 Ma, which provided abundant sediments for the KFB and caused the anomalously high sedimentation rate during the N 2 k deposition. From 3 Ma to 1.64 Ma, the action of tectonic compression extended from the northern monocline to the Kelasu Thrust Belt and returned to the northern monocline of KFB from 1.64 Ma to present day. Therefore, the horizontal tectonic compression was the dominant overpressure mechanism for the overpressure generation in the third stage (∼3–1.64 Ma) and overpressure caused by disequilibrium compaction from 5 Ma to 3 Ma was only preserved in the Kela-2 Gas Field until present day. [ABSTRACT FROM AUTHOR]

Abstract: The multi-stage hydrocarbon charge process of Kela-2 gas field in the Kuqa foreland basin was studied from the perspective of palaeo-fluid evidence by the analyses of fluid inclusions, fluorescence spectroscopy, FE-SEM (field emission scanning electron microscopy) observation, core micro-CT scanning, and hydrocarbon geochemistry. The result shows that the Kela-2 gas field has experienced three periods of hydrocarbon charge process: (1) charged with oil at the early-middle period of the Miocence (N1), (2) charged with high maturity oil & gas at the sedimentary period of the Pliocence Kuqa Formation (N2) and then destroyed by intense tectonic compression, and (3) charged with high- and over-maturity coal-derived gas since the Quaternary. The widely distributed residual dry bitumen, the occurrence of gas-liquid two-phase hydrocarbon inclusions, the residual oils observed in the nanopores, the higher QGF and QGF-E index, and the higher S 1, S 2 values of rock pyrolysis detected in both current gas zone and water zone, are the evidence of early oil charges. The residual dry bitumen, the occurrence of gas-oil-solid (bitumen) three-phase hydrocarbon inclusions, the loss of light n-alkanes and the relatively high content of aromatic hydrocarbons in the condense oil, and the abnormally high content of diamondoid hydrocarbons, are the strong evidence of gas flushing and deasphalting. [Copyright &y& Elsevier]

Abstract: The petroleum generation and charge history of the northern Dongying Depression, Bohai Bay Basin was investigated using an integrated fluid inclusion analysis workflow and geohistory modelling. One and two-dimensional basin modelling was performed to unravel the oil generation history of the Eocene Shahejie Formation (Es3 and Es4) source rocks based on the reconstruction of the burial, thermal and maturity history. Calibration of the model with thermal maturity and borehole temperature data using a rift basin heat flow model indicates that the upper interval of the Es4 source rocks began to generate oil at around 35 Ma, reached a maturity level of 0.7% R o at 31–30 Ma and a peak hydrocarbon generation at 24–23 Ma. The lower interval of the Es3 source rocks began to generate oil at around 33–32 Ma and reached a maturity of 0.7% R o at about 27–26 Ma. Oil generation from the lower Es3 and upper Es4 source rocks occurred in three phases with the first phase from approximately 30–20 Ma; the second phase from approximately 20–5 Ma; and the third phase from 5 Ma to the present day. The first and third phases were the two predominant phases of intense oil generation. Samples from the Es3 and Es4 reservoir intervals in 12 wells at depth intervals between 2677.7 m and 4323.0 m were investigated using an integrated fluid inclusion workflow including petrography, fluorescence spectroscopy and microthermometry to determine the petroleum charge history in the northern Dongying Depression. Abundant oil inclusions with a range of fluorescence colours from near yellow to near blue were observed and were interpreted to represent two episodes of hydrocarbon charge based on the fluid inclusion petrography, fluorescence spectroscopy and microthermometry data. Two episodes of oil charge were determined at 24–20 Ma and 4–3 Ma, respectively with the second episode being the predominant period for the oil accumulation in the northern Dongying Depression. The oil charge occurred during or immediately after the modelled intense oil generation and coincided with a regional uplift and a rapid subsidence, suggesting that the hydrocarbon migration from the already overpressured source rocks may have been triggered by the regional uplift and rapid subsidence. The expelled oil was then charged to the already established traps in the northern Dongying Depression. The proximal locations of the reservoirs to the generative kitchens and the short oil migration distance facilitate the intimate relationship between oil generation, migration and accumulation. [Copyright &y& Elsevier]

Reconstructing fluid evolution history in old sedimentary basins is extremely challenging due to the prolonged evolution, lack of exact age constraints and absence of preserved fluids. By integrating in-situ calcite U Pb dating, fluid inclusion analysis, measurements of major and trace elements and carbon‑oxygen‑strontium isotopes, and molecular composition analysis of petroleum, we have reconstructed the fluid evolution history during the Carboniferous in an Ordovician deeply-buried carbonate reservoir in the Tarim Basin, China, with unprecedented temporal resolution. Five generations of calcite cementation spanning over 37 m.y. are dated in a single calcite vein with U Pb ages ranging from ~353 Ma to ~316 Ma. The initial cement was associated with an intrusion of hyper-saline brine, enriched in REEs. This was followed by influx of meteoric water to precipitate the second and third generations of cement, which are characterized by reduced salinity, anomalously high 87Sr/86Sr ratios and extremely low concentration of REEs. The fourth generation of calcite cement was formed in a deep-fluid system accompanied by oil charge as indicated by the presence of bitumen, oil inclusions and low δ13C and 87Sr/86Sr ratios. The fifth generation of cement was precipitated from equilibrated connate water, and has the lowest salinity and a comparable REE signature to the host rock. Oil charge event occurred around 326 Ma. This study demonstrates the effectiveness of combining in-situ calcite U Pb geochronology, fluid inclusion analysis, elemental and isotopic geochemistry to elucidate high-resolution temporal fluid evolution in old sedimentary basins with a complex tectonic history, providing a new paradigm for studying geofluid evolution. [ABSTRACT FROM AUTHOR]

Numerous oil and condensate gas reservoirs have recently been discovered in the Southern Slope Region of the Kuqa Foreland Basin in the northern Tarim Basin, northwestern China. However, their hydrocarbon sources and charge history are still unclear. In this study, oil-source correlation was firstly used to ascertain the sources of oils in different tectonic belts. The hydrocarbon charge history was then investigated using an integrated fluid inclusion analysis and basin modelling approach. On the basis of a variety of oil-source correlation geochemical parameters, two distinct oil groups were delineated in this region: Group I including oils in the Yaha and Yingmai-7 tectonic belts, while Group II comprising oils from the Yangtake, Hongqi, and Yudong-2 tectonic belts and the YM-21 well. Oil-source correlations show that Group I oil is sourced from the Upper Triassic Huangshanjie Formation (T 3 h ), while Group II oil is mainly sourced from the lower part of the Middle Jurassic Qiakemake Formation (J 2 q ). Both source rocks are located in the middle and northern parts of the Kuqa Foreland Basin. Basin modelling shows that the T 3 h source rock began to generate early mature to mature oil at 34 Ma and continued until around 3 Ma. The J 2 q source rock began to generate early mature to mature oil between after 34 Ma and continued to 12 Ma, mainly in the central part of the J 2 q source rock. Oil migration modelling indicates that the T 3 h -sourced oils did not accumulate in the Southern Slope Region until 12–5 Ma, whereas the J 2 q -sourced oils began to charge into the Southern Slope Region around 5–3 Ma. Coupled with fluid inclusion analysis, the modelling shows that oils originated from the T 3 h source rock began to charge into the Yaha tectonic belt as early as 6 Ma, and subsequently to the Yingmai-7 tectonic belt which received its initial charge around 4.8 Ma. Oils sourced from the Lower J 2 q source rock began to charge into the Yangtake tectonic belt around 4 Ma, and then into the Yudong-2 tectonic belt around 3.7 Ma. Oils first charged into the Hongqi and YM-21 areas after 4 Ma. Oils from the T 3 h and the Lower J 2 q source rocks continued to charge into the Southern Slope Region until 3 Ma. [ABSTRACT FROM AUTHOR]

Abstract: An integrated approach of molecular sieve, molecular composition of fluid inclusion and compound specific isotope analysis was employed to investigate newly discovered oils reservoired in an Ordovician buried hill in the Dongying Depression of Bohai Bay Basin. The new discovered oils are characterized by high content of waxy alkanes (>40%) with an extremely low concentration of cyclic biomarkers. The alkanes-removed waxy oil and the fluid inclusion oils correlate well with the source rocks of the Paleogene Kongdian Fm (Ek2). The δ 13C values of the compound-specific isotope of the alkanes indicate that Ek2 is the primary source for the oils. This study demonstrates the existence of a new set of deeper source rocks with good oil-generation potential in the Dongying Depression. [Copyright &y& Elsevier]

The diagenetic characteristics and differences between the Eocene red-bed sandstone deposited in an arid environment and gray-bed sandstone deposited in a relatively humid environment were investigated systematically by an integrated analysis of petrography, X-ray diffraction, carbon and oxygen stable isotopes and fluid inclusion microthermometry. Strong eodiagenetic calcite and gypsum/anhydrite cementation occurred at the boundary of the Eocene red-bed sandstone, while the centre of the red-bed sandstone was characterized by relatively strong quartz dissolution and weak mesodiagenetic feldspar dissolution and ferro-carbonate cementation. Eodiagenetic calcite cementation at the boundary of the gray-bed sandstone and quartz dissolution were relatively weak, while the carbonate cemented zone at the boundary of the gray-bed sandstone was strengthened by mesodiagenetic ferro-carbonate cement. Relatively strong feldspar dissolution and ferro-carbonate cementation occurred in the centre of gray-bed sandstone beds. By comparing the diagenetic differences between the red-bed sandstones and gray-bed sandstones, it is shown that sedimentary environment had an obvious influence on reservoir diagenetic evolution and reservoir properties through influencing the chemical properties of connate water, the transformation rate and degree of clay minerals in interbedded mudstone, and the properties of diagenetic fluids during burial process. • Eodiagenetic calcite cementation and quartz dissolution in the red-bed were stronger than that in the gray-bed sandstone. • Mesodiagenetic feldspar dissolution and carbonate cementation in the red-bed were weaker than that in the gray-bed sandstone. • Reservoir space in the red-bed is mainly primary pores, while that in the gray-bed is mainly secondary pores. • Sedimentary environment had obvious influence on the reservoir diagenetic evolution. [ABSTRACT FROM AUTHOR]