Jurassic Source Rocks Research Articles

Coupling relationship between reservoir densification and hydrocarbon emplacement in the Jurassic Badaowan Formation sandstone reservoirs of the southern Junggar Basin, China

Understanding the interrelationship between diagenesis and hydrocarbon emplacement is crucially important for investigating tight sandstone reservoir‐forming processes. In this paper, efforts were made to elucidate this interrelationship in the Jurassic Badaowan Formation tight sandstone reservoirs of the southern margin of the Junggar Basin (SJB), China. Four lithofacies were clarified, including quartz cemented‐dissolution facies (QCDF), carbonate cemented facies (CCF), authigenic clay mineral facies (ACMF), and matrix‐caused tightly compacted facies (MCTF). Weak hydrocarbon migration forces and poor hydrocarbon preservation conditions were identified to be the main reasons for the limited hydrocarbon accumulation scale. The reservoir densification process, mostly before 100 Ma, was associated with four aspects, including the high matrix content, the intensive carbonate cementation, the limited dissolution and alteration, and the development of authigenic clay minerals. Hydrocarbons in the Badaowan Formation reservoir were demonstrated to be emplaced after reservoir densification. Overpressure resulting from hydrocarbon expulsion and tectonic compression should have acted as the main driver for hydrocarbon migration. Particularly, the tight sandstone in the Qigu anticline was charged with overpressurized hydrocarbons sourced from the middle‐lower Jurassic source rocks at the footwall of the Qigu north fault since the early Jurassic. The tectonic compression in the late Neogene eroded the core of the Qigu anticline, which destroyed the initially large palaeo‐oil reservoir into smaller ones. The first‐stage hydrocarbon emplacement greatly affected the diagenesis and physical properties of the reservoir. It played an important role in inhibiting cementation, promoting dissolution, and altering the petrophysical properties of the tight sandstone reservoir. The densification process controlled the wettability and capillary pressure of pores in the tight sandstone. Specifically, the high kaolinite cement raised the hydrophilia, while the ubiquitous densification increased the capillary pressure of pores.

Depositional environment and petroleum source rock potential of Mesozoic lacustrine sedimentary rocks in central Mongolia

Middle Jurassic (five samples from one location) and Lower Cretaceous (thirty-two samples from eight locations) lacustrine sedimentary rocks of central Mongolia were studied to determine their depositional environments and petroleum source rock potential. The Middle Jurassic shale contains sufficient organic matter (OM) with Type II/III kerogen to represent a mixed oil and gas potential source rock. Tmax and biomarker maturity indices suggest a thermally immature level. Pristane/phytane and the gammacerane index indicate that the shale accumulated in an oxic, freshwater environment. Terrigenous OM with input from algae and macrophytes was a major contributor as indicated by long-chain n-alkanes and the abundance of C29 regular steranes. The stable carbon and nitrogen isotope compositions and kerogen types agree with land plant derived OM. Lower Cretaceous shales are highly oil-prone but thermally immature, reflected by Rock-Eval data and biomarker parameters. Carbon preference index (CPI), n-alkane distributions, and C27/C29 ratios suggest that OM in Lower Cretaceous shales is a mixture of phytoplankton, macrophyte, and land plant. The contribution from algal OM is variable. Lower Cretaceous shales were deposited in stratified lakes with anoxic bottom waters and the salinity of paleolakes was variable, indicated by Pr/Ph and the gammacerane index, respectively. Organic geochemical characteristics and depositional environments of Middle Jurassic and Lower Cretaceous sedimentary rocks studied herein are similar to those of Jurassic source rocks in western Chinese basins and Lower Cretaceous source rocks in eastern Mongolian basins, respectively.

Jurassic-recent stratigraphy, structure, and hydrocarbon potential of the Mesozoic-Cenozoic rifted-passive margin of the Tarfaya-Dakhla basin of southern Morocco

We describe the structure, stratigraphy, and hydrocarbon potential of the 1000-km-long Tarfaya-Dakhla Basin (TDB) along the Atlantic rifted-passive margin of Morocco. Our dataset consists of a 4885-line km grid of depth-converted industry seismic data tied to three DSDP wells in the deepwater area and exploratory wells on the slope and shelf. Based on mapping of this seismic grid, the tectonostratigraphic events that have affected this margin include: 1) a Late Triassic-Early Jurassic rift phase that separated the Moroccan margin from its conjugate margin in eastern Canada began during the Late Triassic-Early Jurassic; 2) early passive margin sedimentation consists of Middle Jurassic-Early Cretaceous passive margin phase consisting of a massive, 14-km-thick, reefal-carbonate platform formed above the rifted margin during the Early Jurassic and was subsequently buried by the 6-km-thick, Early Cretaceous (Berriasian) Boujdour deltaic complex. During this period continued high rates of clastic sedimentation resulted in margin steepening and gravitational collapse during the Valanginian and formed a 480-km-long and 68-km-wide passive margin fold belt characterized by a zone of updip normal faults of 480 km in length and 30 km in width and a zone of downdip folds and thrusts of 117 km in length and 15 km in width. Geochemical data from DSDP 397 and 369 wells and two pseudo-wells were used to evaluate source rock potential and hydrocarbon prospectivity of the Jurassic to Recent section. Basin modeling reveals that the Jurassic source rocks known from DSDP drilling are presently overmature in the study area with hydrocarbon generation beginning in the Upper Jurassic-Lower Cretaceous. The Lower Cretaceous source rocks are immature except for localized areas, and the Upper Cretaceous is immature across the study area.

Pressure variations in the northern part of the Danish Central Graben, North Sea

The overpressure variation in the Cenozoic–Jurassic succession in the northern part of the Danish Central Graben may broadly be divided into three major compartments. An upper hydrostatically pressured unit comprises the post-mid Miocene–recent succession down to c . 1200 m depth in the northern and c . 700 m in the southern parts of the Danish Central Graben. The second compartment comprises the mid-Miocene smectite-rich clays down to and including the upper Cretaceous chalk. There the Paleogene–Lower Miocene succession provides the seal. The third compartment constitutes the Jurassic succession with pressure above hydrostatic that may exceed twice that seen at the upper Chalk level. Pressure levels can be estimated using the Eaton approach for the second compartment that are in agreement with pressure data. Modelling of the transient pressure development in the Cretaceous–mid-Miocene succession broadly complies with the Eaton estimates and shows that the main overpressure build-up has occurred within the last 10 myr. The overpressure in this succession may be mapped using methods that exploit correlations between fluid pressure and the degree of consolidation, while that in the Jurassic cannot. However, the lateral variation in the Upper Jurassic overpressure correlates broadly with the maturity of the Upper Jurassic source rock, allowing the pressure variation to be mapped. Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure

Jurassic Provenance System and Its Geological Implication in Altyn Piedmont, Qaidam Basin

Abstract A petroleum system originating from Jurassic source rocks exists in Altyn piedmont. However, the Jurassic formation in this system is deformed by Yanshan-Himalayan tectonic movement, and related studies about its spatial distribution and sedimentary system are still highly controversial. In general, a systematic research on the provenance system helps precisely restoring the prototype basin. Based on the methods of seismic characterization, sedimentary analysis, and detrital zircon U-Pb dating (samples from several Altyn piedmont outcrops), this paper studied the provenances of Jurassic formation in Altyn piedmont and characterized their distribution from different aspects: (1) Lacustrine rift basin developed in the study area at early Jurassic, while the formation showed a saucer shape with its thickness decreasing and vanishing towards the center of the basin in the middle Jurassic; in summary, the Jurassic formation in Altyn piedmont could be divided into several parts due to their different characteristics in different periods. (2) The south part of the Jurassic deposition (south of Qingshuigou) could come from the east Kunlun terrain; the middle part (Yueya mountain to Dongping area) however could be from several provenances, including the east Kunlun terrain, the surrounding plutons, and the Altyn fault; the north part (Niudong to north Lenghu area) is mainly related to the Altyn fault. (3) The Altyn fault, a regional fault system containing several strike-slip faults, is highly active since late Triassic and controls the current spatial distribution of the Jurassic formation; the faulted area in the piedmont could be separated into several parts with several different sources. (4) Compared to the southern and middle parts, the northern Jurassic deposition is relatively flat and contains wider and thicker source rock beds, which makes this area an important gas exploration target.

Organic Geochemistry Of The Middle To Upper Jurassic Source Rocks Succession In Balad-1 Well, Balad Oil Field, Central Iraq

Thirty four cuttings samples from the Jurassic rock succession in well Balad-1 in the Balad Oil Field, Central Iraq have been collected. Using various organic geochemical techniques, the organic matter’s quantity, quality, maturity, and their source rock’s depositional setting were determined. The samples were evaluated to determine the amount of their organic matter content, type of organic matter, δ13C carbon isotopes abundance for both saturated and aromatic, and molecular properties. The results of organic geochemistry analysis show that Sargelu, Gotnia, and Chia Gara formations contain fair to decent amounts of organic matter. Naokelekan Formation encompasses fair to excellent organic matter, while Najmah Formation comprises very high to exceptional organic matter. The analyzed samples revealed the existence of kerogen types III and II/III mainly within oil window. Thermal maturity related biomarkers are in a good agreement with Rock-Eval parameters, but did not reach equilibrium phase. Source related biomarkers show that these rock units rich in organic matter were mainly deposited in an anoxic marine depositional setting which consists of carbonate influenced by terrestrial input.

Generation potential, distribution area and maturity of the Barents-Kara Sea source rocks

Identification of the source rock potential and distribution area is the most important stage of the basin analysis and oil, and gas reserves assessment. Based on analysis of the large geochemical and geological data base of the Petroleum geology department of the Lomonosov Moscow State University and integration of different-scale information (pyrolysis results and regional palaeogeographic maps), generation potential, distribution area and maturity of the main source rock intervals of the Barents-Kara Sea shelf are reconstructed. These source rocks wide distribute on the Barents-Kara Sea shelf and are characterized by lateral variability of generation potential and type of organic matter depending on paleogeography. During regional transgressions in Late Devonian, Early Permian, Middle Triassic and Late Jurassic, deposited source rocks with marine organic matter and excellent generation potential. However in the regression periods, during the short-term transgressions, formed Lower Carboniferous, Upper Permian, Induan, Olenekian and Late Triassic source rocks with mixed and terrestrial organic matter and good potential. Upper Devonian shales contain up to 20.6% (average – 3%) of marine organic matter, have an excellent potential and is predicted on the Eastern-Barents megabasin. Upper Devonian source rocks are in the oil window on the steps, platforms and monoclines, while are overmature in the basins. Lower Permian shale-carbonate source rock is enriched with marine organic matter (up to 4%, average – 1.4%) and has a good end excellent potential. Lower Permian source rocks distribute over the entire Barents shelf and also in the North-Kara basin (Akhmatov Fm). These rocks enter the gas window in the Barents Sea shelf, the oil window on the highs and platforms and are immature in the North-Kara basin. Middle Triassic shales contain up to 11.2% of organic matter, there is a significant lateral variability of the features: an excellent generation potential and marine organic matter on the western Barents Sea and poor potential and terrestrial organic matter in the eastern Barents Sea. Middle Triassic source rocks are in the oil window; in the depocenters it generates gas. Upper Jurassic black shales are enriched with marine and mixed organic matter (up to 27,9%, average – 7.3%) and have an excellent potential. On the most Barents-Kara Sea shelf, Upper Jurassic source rock are immature, but are in the oil window in the South-Kara basin and in the deepest parts of the Barents Sea shelf.

KEROGENES KINETIC PARAMETERS INFLUENCE ON THE HYDROCARBONS GENERATION DYNAMICS AND VOLUME BY THE EXAMPLE OF THE UPPER JURASSIC SOURCE ROCKS OF THE NORTH-EASTERN PART OF WEST SIBERIA

One-dimensional modeling of four well of the North-Eastern part of West Siberia was conducted. When using kinetic parameters of II type kerogen (Menil-2) and calculated kerogen characteristics for the Upper Jurassic source rocks hydrocarbons generation volume was estimated.

Distribution and Geochemical Significance of Rearranged Hopanes in Jurassic Source Rocks and Related Oils in the Center of the Sichuan Basin, China.

Gas chromatography-mass spectrometry (GC-MS) analysis has revealed extremely high abundances of rearranged hopanes in Jurassic source rocks and related crude oils in the center of the Sichuan Basin. The detected rearranged hopanes include 17α(H)-diahopanes (C27D and C29–35D), early-eluting rearranged hopanes (C27E and C29–33E), and 18α(H)-neohopanes (C29Ts and Ts). Both the 17α(H)-diahopanes and the early-eluting rearranged hopanes exhibit a distribution pattern similar to that of the 17α(H)-hopane series, with a predominance of the C30 member and the presence of 22S and 22R epimers of hopanes in the extended series (>C30). The results of this study show that the relatively high abundance of rearranged hopanes in Jurassic source rocks in the study area is associated with their depositional environments and with clay-mediated acidic catalysis rather than, as was previously thought, thermal maturity. Shallow lacustrine facies with brackish water and a suboxic to weak reducing sedimentary environment have contributed to the enrichment of rearranged hopanes, and clay-mediated acidic catalysis may also have had a positive influence on their abundance. The distribution patterns of the diahopane series indicate that the oils from Jurassic reservoirs in the Gongshanmiao Oilfield are sourced from Jurassic source rocks. Rearranged hopanes are therefore considered to be effective biomarkers for oil-source correlation in the center of the Sichuan Basin.

Generation potential of organic matter of the Upper Jurassic deposits within the Karabash search zone

The article considers the geochemical characteristics of the rocks of the Bazhenov and Nizhnetutleim formations in the southwestern part of the West Siberian oil and gas province, or rather in the territory of the Karabash search zone. The work was carried out on the basis of the core material study of the section of 29 wells within the Karabash zone by pyrolysis on the Rock-Eval 6. The regularities of the distribution of organic carbon concentrations (Сorg, %) on the studied territory were obtained. With the help of data mapping, it was established that the maximum concentrations of organic matter are timed to the southern regions of the zone (the most submerged parts of the paleobasin). The assessment of the catagenesis degree (degree of maturity) of organic matter of the Bazhenov horizon in the study area was carried out. Level maturity of organic matter of rocks is specified in the parameter Tmax Rock-Eval. Within the study area it’s increasing from South to North, from graduation PK3 (according to the scale of N.B. Vassoevich) (Tmax < 430 0С) in the area of wells Verkhnetyumskaya 34 to MK2 (Tmax 440–445 0С) in the area of Molodezhnaya and the Zapadno-Frolovskaya square. The resulting catagenetic zoning determined the boundaries of the generation kitchen for this territory. Generation scale for the Upper Jurassic source rocks was estimated, taking into account its lithofacial structure.

On the nature of Paleozoic oil deposits and their exploratory "reflection" in the geophysical section of the Jurassic layers (southeast of Western Siberia)

Commercial significance of the majority of Western Siberian oil fields is concerned with the Senomanian, Neocomian and, above all, Upper Jurassic horizons. For now, oil fields are at the late development stage and resource potential of the Jurassic horizon is strongly expired. Commercial potential of the pre-Jurassic (Paleozoic) rocks has been brought out throughout all territory of oil and gas province. Extensive work on estimation of the pre-Jurassic rocks oil and gas potential is performed in southeast, in the territory of Tomsk Region, within which 13 hydrocarbon deposits have been discovered in the Paleozoic. Original hypothesis of anomalousness of geophysical and petrophysical characteristics of the Jurassic layers — uniqueness of «indication» the Paleozoic deposits in geophysical parameters of overlaying Mezozoic-Cenozoic section was stated as a foundation of new prospecting criterion for the Paleozoic deposits. The Paleozoic formations are accepted as a complex with its own oil generating potential, which results in upward migration of hydrocarbon fluids. Additionally, downward direction of vertical interstratal hydrocarbon migration from the Jurassic source rocks into the pre-Jurassic complex is brought out. It was accepted as a conception that as in case of upward, so in case of downward fluid migration, processes of superposed epigenesis perform and lead to secondary epigenetic transformations of rocks of transit Jurassic layers, which result in their anomalous geophysical and petrophysical characteristics. This paper analyzes and compares geophysical and petrophysical characteristics of the Jurassic layers of different field types in Tomsk Region: without oil and gas potential in pre-Jurassic section, with commercial inflows from the pre-Jurassic complex and unknown type. Results of exploration electrical resistivity and carbonatization in the Jurassic layers of 200 wells and also spontaneous potential variation, electrical resistivity and natural radioactivity in Bazhenov suite confirm anomalousness of geophysical and petrophysical parameters of Jurassic rocks in case of pre-Jurassic deposits. This paper determines 6 geophysical and petrophysical characteristics of the Jurassic layers as predictive indicators for oil and gas potential estimation in pre-Jurassic section. Efficiency analysis of using predictive indicators for bringing out fields with and without deposits in the pre-Jurassic complex was performed for different prospecting cases in the research territory with account taken of possible complexing of indicators, their rank and actual availability. This paper states preference of indicators complexing. Application of a new prospecting criterion will improve efficiency of searching in new prioritized stratigraphic horizon — the Paleozoic, which contains unconventional oil.

New equation to decipher the relationship between carbon isotopic composition of methane and maturity of gas source rocks

The identification of the origin and source of natural gas is always a difficult and hot issue. Hereinto, the maturity identification is one of the most important scientific problems. Many empirical equations have been established to decipher the relationship between the maturity of gas source rocks and the carbon isotopic composition of natural gas. However, these equations proposed often fail to identify the maturity of the source rocks correctly, which in turn prevents the identification of genetic types and source rocks of the natural gas because the petroliferous sedimentary basins in China are complex and diverse, with multiple sets of source rocks and different thermal history. In this paper, the oil-associated gas from the Permian lacustrine source rocks and the coal-derived gas from the Jurassic source rocks in Junggar and Turpan-Hami basins have been investigated to decipher the relationship between the maturity (vitrinite reflectance) of gas source rocks and the carbon isotopic composition of methane. The equations established are δ13C1=25lgRo−42.5 for oil-associated gas, and δ13C1=25lgRo−37.5 for coal-derived gas. These new equations are suitable for the maturity identification of source rocks in most petroliferous basins, and favorable for the identification of the genetic type and source of natural gas, which is very important to improve the geological theory of natural gas.

MINERALOGICAL, BIB‐SEM AND PETROPHYSICAL DATA IN SEAL ROCK ANALYSIS: A CASE STUDY FROM THE VIENNA BASIN, AUSTRIA

The Vienna Basin is a major hydrocarbon province with a long exploration history. Within the basin, secondary migration from Upper Jurassic source rocks into stacked Middle Miocene (Badenian) sandstone reservoirs was formerly considered to have occurred almost entirely along major fault zones. However recent exploration data has suggested that in areas where no major faults are present, oil may have migrated vertically through the sandy mudstone intervals separating individual reservoir units, which are therefore imperfectly sealed. In order to investigate possible secondary migration through the semi‐permeable mudstones, this study links variations in gross depositional environment (GDE) to variations in mudstone properties (e.g. mineralogy and pore size distribution). The study focussed on the mudstones which seal reservoir sandstones referred to locally as the “8.TH” and “16.TH” units. The bulk mineralogical composition of 56 mudstone and sandy mudstone (and minor intercalated muddy sandstone) samples from seal layers in 22 wells was studied by X‐ray diffraction analysis, broad ion beam – scanning electron microscopy (BIB‐SEM), mercury intrusion porosimetry (MICP) and N2 adsorption. These data are interpreted in the context of GDE maps of the Vienna Basin which were previously established using seismic and well log data.Results indicate that the gross depositional environment strongly controlled the pore space characteristics of the mudstones. The sandy mudstones in the NW part of the study area were influenced by a complex eastward‐prograding deltaic system which deposited coarse detritus into a major palaeo depression (“Zistersdorf Depression”) located in the centre of the basin. Higher overall porosity and a dominance of larger pore size classes, probably resulting in reduced seal quality, were observed for sandy mudstones from well locations within feeder channels and also from within the Zistersdorf Depression. Similarly, sandy mudstones from locations associated with the long‐term input of coarser sediments in shoreline, coastal and proximal offshore settings in the NW and central parts of the study area are considered to be of lower sealing quality compared to fine‐grained mudstones deposited in distal, open‐marine settings which prevailed in the SE part of the study area throughout the Middle Miocene.In general, pore geometries were influenced by mineralogical composition; quartz‐ and detrital carbonate‐rich samples show equidimensional pores, while more elongated pores (with a higher average aspect ratio) characterize clay‐rich samples. Furthermore, matrix mesopores (2‐50 nm) determined by N2 sorption are more abundant in clay‐rich versus quartz‐rich samples, and show a pronounced positive trend with increasing percentage of illite‐smectite mixed‐layer clay minerals.This study shows that regional‐scale mudstone seals in the Vienna Basin have been influenced by variations in sedimentation associated with lateral variations in gross depositional environment during the Middle Miocene. The observed pore characteristics will serve as input data for future models of secondary migration.

Compound-specific δ2H and δ13C values of n-alkanes as a tool to unravel complex petroleum mixtures in the South Viking Graben, Norway

In order to resolve oil mixtures and for oil-source correlation purposes, both hydrogen (δ2H) and carbon isotope compositions (δ13C) of n-alkanes and acyclic isoprenoid alkanes have been determined in petroleum mixtures and extracts from Jurassic source rocks of distinct organic matter type, depositional setting and lithology in the South Viking Graben, Norway. δ2H values vary from −80 to −140‰ for n-alkanes and from −130 to −165‰ for pristane (Pr) and phytane (Ph) in oil and condensate samples. At the same maturity level, in the main oil generative window, individual n-alkanes from most oils and condensates show a 2H-enrichment with n-alkane chain length by 15 to 50‰. With the increase in the estimated input of hydrocarbons from terrigenous source material to petroleum mixtures, the n-alkanes (>C20) exhibit a higher 2H-enrichment while n-alkanes (C10-C14) show a higher 13C-enrichment. δ2H values of n-alkanes (>C20) are useful to discriminate mixed oils that were not well differentiated by δ13C data. δ2H values of individual n-alkanes from oils suggest a possible exchange of C-bound H with other hydrogen during their generation from precursor molecules. We find that δ2H values of n-alkanes from Jurassic source rock extracts, at the onset of oil generation, were mainly controlled by the isotopic composition of biosynthetic precursors and varied from −100 to −150‰. Combination of carbon and hydrogen isotope compositions of n-alkanes proved to be a useful tool to discriminate Jurassic petroleum mixtures from distinct sources in the Norwegian South Viking Graben.

The Sureste Super Basin of southern Mexico

The Sureste Basin of southern Mexico has all the components to be classed as one of the world’s super basins for hydrocarbon exploration and production. This is because of its endowment with one of the world’s great source rock systems, namely, the Late Jurassic Edzna Formation, in combination with stacking of multiple potential reservoirs in a highly structural salt basin. This paper discusses the hydrocarbon play potential of the Sureste Basin within a tectono-stratigraphic context and outlines the key risks, uncertainties, and opportunities for future exploration. Surface oil seepage and seismic mapping clearly show that many prospective structures extend into the underexplored deeper-water basin area. Key risks are related to charge, with substantial migration required from deeply buried Late Jurassic source rocks into shallower carbonate and clastic reservoirs. In particular, “deep charge focus” and “hydrocarbon charge versus trap timing” are key risk elements. Two key uncertainties are the deep reservoir quality of the lithic sandstones in Paleogene reservoirs and column height prediction for high-relief traps. The highly structured nature of the underexplored deep-water Campeche slope in combination with extensive hydrocarbon seepage to the seabed bodes well for a prolific exploration future in expanding the proven reservoir systems further, taking advantage of established deep-water drilling practices and advanced wide-azimuth three-dimensional (3-D) seismic imaging. It is also likely that with expanding high-quality 3-D seismic coverage around shallow water and onshore existing discoveries, additional reservoir targets and additional fault blocks will become visible.

Genesis and accumulation process of deep natural gas in the Altun foreland on the northern margin of the Qaidam Basin

Deep natural gas in the northern margin of the Qaidam Basin is characterized by low exploration degree and large resource potential, but the genesis of deep gas reservoirs is complex. In particular, Jurassic source rocks do not develop in west of Altun foreland. The mechanism of deep accumulation is unknown, which restricts the exploration of deep gas reservoirs. Using gas components, isotopes and other data, combined with the geological characteristics of the Altun foreland, this study analyzes the genesis and source of deep gas in this area, and establishes the accumulation procesess of the deep gas reservoirs. Analysis shows that the gas in the Altun foreland is dominated by coal-type gas with the characteristics of oil cracking gas in deep reservoirs. The Jurassic source rocks in the Qaidam Basin are mainly lacustrine mudstones, with black mudstones and oil shale developed, which have the material basis for forming large oil reservoirs. The deep reservoir has experienced the process of long-term deep burial and high-temperature cracking, and has the conditions to form oil cracked gas. Accumulation in deep bedrock gas reservoirs is characterized by early oil filling, later high-temperature cracking into gas, and late adjustment. Reservoirs formed in early stage can be deeply cracked into gas reservoir under high temperature in the process of deep burial. The ancient uplifts along the basin margin and large anticline traps in the late tectonic zone are favorable exploration areas for deep gas. The exploration area for natural gas in the Qaidam Basin has been expanded by the discovery of deep oil cracking gas in the Altun foreland, which has crucial significance for guiding and intensifying deep gas exploration in the Qaidam Basin.

The Jurassic Oil and Gas Source Rocks of Hydrocarbon Deposits in the Eastern Part of the Fukang Depression (Junggar Oil and Gas Basin)

In recent years, significant success has been achieved in the search for and exploration of oil and gas reservoirs in the Jurassic deposits on the eastern side of the Fukang Depression, which is the least studied part of the Junggar oil and gas basin. In order to determine the hydrocarbon generation source, we have studied source rocks, oil and oil-bearing sandstones (24 samples from 13 wells), from the Badaowan, Sangonghe, Xishanyao, Toutunhe, and Qigu productive reservoirs of the Fukang Depression research area. Based on these studies, the organic matter composition of the Jurassic source rocks, the properties and molecular composition of oils, as well as the composition characteristics of biomarkers in them have been examined in detail. According to the research data and interpretation results, Badaowan mudstones were the source rocks of oil in the Gumudi zone and Fukang Depression, as well as that in the Baijiahai and Shaqi ledges.

Jurassic source rocks of hydrocarbon fluids in the Eastern part of the Fukan depression (Junggar oil and gas basin)

In recent years, significant successes have been achieved in the search and exploration of oil and gas reservoirs in the Jurassic deposits on the eastern side of the Fukang depression, which is the least studied part of the Junggar oil and gas Basin. In order to find out the source of hydrocarbon generation, we studied source rocks, oil and oil-bearing sandstones (24 samples from 13 wells) from the Badaowan, Sangonghe, Xishanyao, Toutunhe and Qigu production beds of the Fukang depression research area. Based on these studies, the composition of the organic matter of the Jurassic source rocks, the properties and molecular composition of oils, as well as the characteristics of the composition of biomarkers in them are examined in detail. The results of research and interpretation of the data showed that the mudstones of the Badaowan formation were source rocks of oil from the Gumudi zone, the Fukan depression, the Bajiahai ledge and the Shaqi ledge.

Total organic carbon (TOC) enrichment and source rock evaluation of the Upper Jurassic-Lower Cretaceous rocks (Barents Sea) by means of geochemical and log data

The Barents Sea is a typical example of a multiple sourced hydrocarbon system, with several gas and oil fields. Previous studies have suggested a gas and oil-prone character of the source rocks, but a lack of success in oil discoveries characterizes this area. In this work, the geochemical characterization of source rocks using well data from six exploration wells in the south-western part of the Barents Sea is presented. We studied the Upper Jurassic-Lower Cretaceous Knurr, Hekkingen and Fuglen Fms. mainly formed by shales and mudstones. Here, the Passey’s method is applied to characterize the geochemical properties and organic matter of these formations by estimating total organic carbon content (TOC), the quantity of thermally generated hydrocarbons (S2), and hydrogen index (HI). Shale volume was also estimated to check the reliability of the calculated parameters. High shale volume values were found in all the formations, which are generally around 0.8 (volume fraction), indicating a predominance of shaly/muddy lithologies. However, some interbedded sandstones and siltstones are present, together with thinner dolomite and limestone layers. Our results show that Upper Jurassic source rocks such as Knurr Fm., which are often not object of geochemical studies, are mature and characterized by good organic carbon content. Good and very good organic carbon content are measured in the Fuglen and Hekkingen Fms., respectively. The hydrogen index suggests that all the source rocks are mixed gas-oil prone, with the Fuglen Fm. standing out as the most gas-prone between the studied formations. This study demonstrates that the Passey’s method can be an alternative to infer geological information when geochemical data are not available.

Gas generation from Jurassic coal measures at low mature stage and potential gas accumulation in the eastern Junggar Basin, China

The increasing global demand for clean energy has made it imperative to exploit unconventional oil and gas resources. Early thermogenic gas is one of the research target of unconventional gas. The Jurassic coal measures were widely distributed in the eastern Junggar Basin with high abundance of humic organic matter and low thermal degrees, showing potential for early thermogenic gas exploration. The burial depth of Jurassic source rocks ranges between 2200 m and 4500 m, with vitrinite reflectance ranging from 0.5% to 0.9%. To study the potential and possibility of gas generation from Jurassic coal measures at low mature stage in the eastern Junggar Basin, mudstone and coal samples were selected for pyrolysis experiments. The pyrolysed temperatures setting for this study are 330 °C, 350 °C, and 370 °C. The heating times at each desired temperature are 3, 7, 14, 21, and 30 days. Parameters such as vitrinite reflectance and certain biomarker ratios indicate all the samples are still at the low mature stage when the heating process finished. Genetic correlation between δ13C1 and C1/(C2+C3) ratio reveals that the generated gas in this study is mainly sourced from Type III kerogen and at the stage of low maturity. Hydrocarbon gas yield results suggest that 370 °C is the most favorable temperature for early thermogenic gas generation, especially heating for 14 days or longer. Pyrolysis results indicate time effect plays an important role in the formation of early thermogenic gas. The results of fourier transformed infrared spectra suggest aliphatic components in macromolecular structure of kerogen provide gas generating material during low mature stage. The evolution history of the Jurassic source rocks and the pyrolysed results indicate the Jurassic coal measure strata in the eastern Junggar Basin has favorable geothermal condition for accumulation of early thermogenic gas.