Jurassic Petroleum System Research Articles

Oil and gas exploration potential in the exclusive economic zone of the Cuba's sector of the Gulf of Mexico

Based on the latest interpretation results of 2D seismic data, combined with drilling, logging, and geochemical data, the reservoir‐forming conditions of the exclusive economic zone in the Cuba's sector of the Gulf of Mexico (Hereinafter refer to GOM) are studied systematically, and the oil and gas accumulation model in the study area is predicted. The favourable exploration zones are evaluated and optimized. The results show that: ① High quality Upper Jurassic‐Lower Cretaceous and potential Middle‐Lower Jurassic source rocks are developed in the study area. ② A set of Upper Jurassic‐Lower Cretaceous petroleum system and a potential Middle‐Lower Jurassic petroleum system are mainly developed in the study area. ③ At present, the proved petroleum system are found in the Upper Jurassic‐Lower Cretaceous strata. The oil and gas mainly comes from the Upper Jurassic‐Lower Cretaceous source rocks, and the reservoirs are mainly Upper Jurassic‐Lower Cretaceous fractured carbonate. The main seals are inter‐reservoir tight limestone, marl, and Palaeocene mudstone. ④ The thrust structural traps in the footwall of the fold thrust belt on the south side of the Florida platform, the margin zones of the Florida platform and Yucatan platform, and the Middle‐Lower Jurassic structural traps on the south side of the Yucatan platform have superior source‐reservoir‐cap configuration conditions. It is suggested that these areas have good oil and gas exploration potential in GOM.

Geochemical variability of oils from Jurassic petroleum system in the east of Persian Gulf

The Late Jurassic petroleum system has created a distinct oil family in the Jurassic and Cretaceous reservoirs in the eastern part of the Persian Gulf. Although the oils in this oil family indicate genetic affinity with the Middle Surmeh source rock, some oil samples show geochemical deviation compared to others. The purpose of this study is to gain a better understanding of these geochemical differences among 23 oil samples from the Jurassic oil family in the eastern Persian Gulf. To achieve this, physical and chemical properties of oil samples, biomarker ratios, stable carbon isotope data, and multivariate statistical methods were used. The chemometric analysis of twenty source-related parameters differentiates three genetic subfamilies (Jurassic principal subfamily, Resalat-Dariyan, and Balal-Surmeh) from Jurassic petroleum system oils. The Balal-Surmeh and Resalat-Dariyan samples are distinguished from principal subfamily based on depositional environment and maturity parameters. The Balal-Surmeh samples show a more marine characteristics and a high maturity level due to the contribution of Permo-Triassic condensates or Silurian Sarchahan shales as a secondary source. It seems that the limited oil generation of the low mature organic-rich interlayers of Dariyan Formation caused a low maturity level in the Resalat-Dariyan samples.

Characteristics of Jurassic source rocks and oil and gas exploration direction in the piedmont zone between the south‐western Qaidam Basin and Altun Mountain

The Jurassic petroleum system in the piedmont zone between Qaidam Basin and Altun Mountain is rich in oil and gas resources. Based on the sedimentary environment, geochemical analysis, and distribution prediction of the Middle–Lower Jurassic source rocks in the piedmont zone between the south‐western Qaidam Basin and Altun tage region, the Jurassic oil and gas exploration potential in the area was systematically evaluated. The Jurassic source rocks in the study area are mainly coal, dark mudstone, and carbonaceous mudstone developed in the Lower Jurassic fan delta facies, as well as, oil shale, and mudstone in the Middle Jurassic of lacustrine facies, and coal measure strata of braided river delta facies. The thickness of Middle Jurassic source rocks is relatively thicker. Through restoration and weathered source rock samples analysis, the average TOC of the Middle Jurassic source rocks in the area can reach 4.19%, and the average chloroform bitumen “A” is 0.5915%, meeting the criteria for a good source stone. Every index is close to the Yuka Jurassic source rock, the highest quality found in the basin so far. At the same time, the distribution range of Jurassic source rocks in the study area is meticulously described through seismic facies identification and prediction analysis. Several Jurassic hydrocarbon generating centers in the area, such as Honggouzi ‐ Yueyashan, Nanyishan ‐ Xiaoliangshan, Pingxi, and Dafengshan, with thicknesses ranging from 200 to 400 m, indicating that the Jurassic source rocks have the material basis for large oil and gas fields formation.

TEMPORAL AND SPATIAL DISTRIBUTION OF ORIGINAL SOURCE ROCK POTENTIAL IN UPPER JURASSIC – LOWERMOST CRETACEOUS MARINE SHALES, DANISH CENTRAL GRABEN, NORTH SEA

The Danish Central Graben, North Sea, is a mature oil‐ and gas‐producing basin in which the principal source rocks are the Upper Jurassic – lowermost Cretaceous marine shales of the Farsund Formation (Kimmeridge Clay Formation equivalent), with possible additional potential in the directly underlying Lola Formation. This study investigates the initial source rock potential of the basin by evaluating the original (back‐calculated) source rock properties (TOCo, S2o, HIo) of the shales in the Farsund and Lola Formations within a temporal and spatial framework. About 4800 samples from 81 wells regionally distributed in the Danish Central Graben were included in the study. Samples for source rock analysis were in general collected with varying sampling density from the entire shale section. The shale section has been divided into seven units (referred to as pre‐FSU1 to FSU6; FSU: Farsund Seismic Unit) which are delineated by mappable, regional‐scale seismic markers. For the pre‐FSU1 and FSU2–FSU6 units, the number of available samples ranged from 608 to 1145, while 433 samples were available for FSU1. Good source rock quality varies through space and time and reflects both the structural development of the basin and the effects of the Late Jurassic transgression, with primary kitchen areas developing in the Tail End Graben, Feda Graben, Gertrud Graben and the Rosa Basin. The source rock quality of the shales increases gradually through time and reaches a maximum in FSU6 which includes the “hot shales” of the Bo Member. The maximum source rock quality appears to correspond to an original Hydrogen Index (HIo) of approximately 675 mg HC/g TOC. The proportion of oil‐prone samples per unit (with HIo >350 mg HC/g TOC) ranges from 7 to 11% in the pre‐FSU1 to FSU2 units (Lower Kimmeridgian – Lower Volgian), increasing to 18 – 22% in FSU3 and FSU4/FSU5 (Lower Volgian – Middle Volgian), and reaching a maximum of 53% in FSU6 (Upper Volgian – Ryazanian). FSU6 is the most prolific oil‐prone source rock interval, but the presence of oil‐prone intervals in older and deeper parts of the shale succession is important for assessing the generation potential of the Upper Jurassic petroleum system. The breakdown of the Upper Jurassic – lowermost Cretaceous shale section into mappable seismic units with assigned original source rock properties will contribute to a considerably improved understanding of the temporal and spatial distributions of source rock quality in the Danish Central Graben.

Pore structure characteristics and hydrocarbon generation potential of middle Jurassic lacustrine source rocks in the Yuka depression, Qaidam Basin, NW China: Implications from petrographic and organic geochemical analyses

The Yuka depression is one of the most important energy production bases in the Qaindam Basin. Although shales in the 7th member of the Dameigou Formation (J2d7) are key members of Middle Jurassic Petroleum System, organic geochemistry and petrography of different rock facies have not been fully analyzed. In this study we evaluate hydrocarbon generation potential of the J2d7 by applying integrated petrographic, geochemical and mineralogical analyses. In addition, pore structure is characterized using field emission scanning electron microscopy (SEM), CO2 and N2 physisorption. Results indicate that mudstone, carbonaceous-mudstone and siltstone have total organic carbon (TOC) values of 2.64%, 5.61% and 0.48%, respectively, as well as variations in the hydrogen index (HI). Kerogen types are mainly Type Ⅲ, with maturity varying from marginally mature to mature. Notably, excess methane adsorption capacities were higher in the carbonaceous-mudstone sample (4.66 cm3/g) than in the mudstone sample (1.78 cm3/g). Primary minerals in the mudstone were quartz and clay; kaolinite, illite and illite/smectite (I/S) were the dominant clay minerals. Clay minerals and TOC content, as well as positive correlations between illite, I/S and mesopore SSA, were factors controlling pore structure development; in contrast, kaolinite contents were negatively correlated with SSA. Liptinite is the dominant maceral composition and a high content of C29 regular sterane in the carbonaceous-mudstones suggests primary higher-plant input, associated with a low gammacerane index (0.28–0.32) and a high pristane/phytane (Pr/Ph) ratio (3.02–3.96). Petrographic and geochemical results indicate an alternating depositional environment across suboxic semi-saline to oxic fresh water changes. Higher-plants were predominant and a small quantity of algae were preserved through in-situ accumulation and migration during shale development; an oxic water column with carbonaceous-mudstone was also present. Although organic matter was marginally mature to mature, the abundance of liptinite (average of 63%) was derived from higher-plants, possibly being the primary materials producing gaseous hydrocarbons.

Contribution of well logging and seismic reflection to the Jurassic petroleum system characterization in the Chotts zone (Southern Tunisia)

In the Chotts zone central part (southern Tunisia), the Jurassic series are interesting for hydrocarbon exploration. However, these series’ composition and geometry are little studied to propose prospection programs. Using boreholes and seismic reflection data, the present study aims a better characterization of the Jurassic series in the Chotts zone central part, in view of petroleum prospects identification. The analysis of the lithological columns and their corresponding well logs highlights an interesting petroleum system: The Tithonian, Kimmeridgian and Oxfordian carbonated deposits are the main reservoirs formations, whereas the Kimmeridgian and Callovian clays constitute the source rocks. The seal rocks are composed of the Jurassic clayey intercalations. Forty-four seismic reflection profiles calibrated using the time–depth relation in petroleum wells are interpreted in this study. The reflectors corresponding to the Malm, Dogger and Lias tops are identified and picked on the different seismic profiles. The isochrone, isobath and isopach maps subsequently deduced disclose important tectonic features that affect the Jurassic series in the Chotts zone and control their geometry. They highlight two sunken zones separated by a raised structure. This structure corresponds to an anticline, overturned toward the south, limited by E–W major faults and truncated by other oriented NW–SE. It constitutes an excellent trap structure where five interesting prospects are precisely delimited. Furthermore, the determined tectonic accidents may facilitate the migration of oil from Jurassic source rocks. The findings of this study can help for better understanding of the Jurassic petroleum system in the Chotts area and guide enormously its exploration.

Geochemical characteristics and exploration potential of Jurassic coal-formed gas in northwest China

Jurassic coal-measure strata are widely developed in Northwest China and mainly distributed in the Tarim Basin, Junggar Basin, Qaidam Basin, and Tuha Basin. The Jurassic coal-formed gas resources are abundant. Although the Jurassic strata in Northwest China have similar tectonic and sedimentary environments, the geochemical characteristics of the coal-formed gas formed in Northwest China have both similarities and differences. Therefore, analyzing and summarizing the geochemical characteristics and exploration potential of the coal-formed gas in the Jurassic petroleum systems in different basins are of great significance for searching for different types of coal-formed gases. Through comprehensive comparison and analysis, it is believed that the drying coefficient of Jurassic coal-formed gases in western China present three types: namely the single peak type of wet gas, the double peak type wet gas-dry gas and the single peak type dry gas; the distribution range of δ13C1 is large, corresponding to the sequence of source rocks from low maturity to over-mature; the partial isotopic inversion of C2 and C3 is mainly caused by the mixed source and biological actions; source rock maturity is the main reason causing the geochemical differences of natural gases in different regions. The Jurassic coal-formed gas in Northwest China has large exploration potential, and the exploration degree of structural gas reservoirs is relatively high. The structural-lithological and lithological gas reservoirs, as well as the main exploration reservoir types for Jurassic coal-formed gas in Northwest China; the Jurassic system in the Kuqa Depression of Tarim Basin, Cretaceous-Jurassic system in the southern margin of the Junggar Basin, the Jurassic high maturity coal-formed gas in the Tuha Basin and the Jurassic high maturity–post-mature coal-formed gas in the Qaidam Basin have great exploration potential, which are important exploration fields for Jurassic coal-formed gas in Northwest China in the future.

Spatial and temporal associations of traps and sources: Insights into exploration in the southern Junggar foreland basin, northwestern China

Several roughly east–west-trending fold-and-thrust belts in the southern Junggar basin constitute the largest anticlinal trap zones in the entire Junggar basin, and four sets of Paleozoic–Cenozoic organic-rich shale and coal-bearing strata make up the majority of the source rocks. However, only small amount of oil and gas has been obtained from this area. Key factors controlling petroleum accumulation and potential plays are not clear. Based on seismic, drilling, and geochemical data from petroleum industry along with plentyof published research results, we investigated the geometry and timing of traps of the three fold and thrust belts, the principal phases of hydrocarbon generation in the sources, and the origins of discovered petroleum. We propose that the spatial and temporal associations of traps and sources should be the key factors of controlling petroleum accumulation in the southern Junggar Basin. Jurassic petroleum system may be the primary petroleum system in this area. Then we established a five-stage accumulation model to reveal the accumulating processes of the multiple petroleum systems in the southern Junggar basin. Our results suggest that the lower reservoir-seal assemblage (sand reservoirs sealed by Lower Cretaceous Tugulu Group mudstone) anticlinal traps in fold and thrust belt II along with lithostratigraphic traps in the foreslope have favorable geological conditions for forming large petroleum fields. This assumption was testified by a major breakthrough (GT-1 well) in southern Junggar basin, in January 6, 2019.

Organic geochemical characteristics of Jurassic petroleum system in Abadan Plain and north Dezful zones of the Zagros basin, southwest Iran

Jurassic succession has resulted in prolific oil and gas reservoirs in southwest Iran. In order to geochemically investigate the Jurassic petroleum system and assess the source rock of these hydrocarbons, 32 source rock samples (from well cutting and surface section) and 4 condensate samples were analysed using geochemical approaches. Rock-Eval pyrolysis and vitrinite reflectance measurement were done on rock samples. Then, condensate samples and source rock extracts were subjected to gas chromatography, gas chromatography–mass spectrometry and isotopic analyses in order to establish oil–oil and oil–source rock correlation. The hydrocarbon generation prediction was then confirmed by petroleum system modelling. The results indicated that the middle Jurassic Sargelu Formation with average total organic carbon (TOC) and hydrogen index values of 3.8% and 600 mg HC/g TOC, respectively, can be classified as good to excellent source rock with kerogen of type II. The maturity indicators revealed late oil to wet gas generation window for the Jurassic Sargelu Formation. Biomarker parameters showed marine carbonate source rock with advanced level of thermal maturity for the source rock of the condensates. Furthermore, there were good correlations between Jurassic Sargelu Formation and the studied oil and condensate samples which proved the Sargelu Formation as the main source rock of the Jurassic petroleum system in the study area. The basin modelling results also confirmed late oil to wet gas window maturity for the Sargelu Formation enabling it as a source rock for generating gas condensate accumulation in southwest Iran. The hydrocarbon generation from Sargelu Formation began in the late Cretaceous and its peak expulsion occurred in the Miocene time.

Provenance and depositional environment of the Middle-Late Jurassic shales, northern Iraq

The Middle–Late Jurassic formations are regarded to be an important source rock in the Jurassic petroleum system of North Iraq. The major and trace element analysis on the Middle and Late Jurassic shales in the Imbricated Zone, Iraq was analyzed. This study investigated the shales provenance and depositional environment, in addition to evaluate the intensity of weathering in the source area. The chemical index of alteration (CIA), index of compositional variability (ICV) and the Al2O3-CaO + Na2O-K2O diagram of the shales suggest increasing in the intensity of chemical weathering from the Middle to the Late Jurassic due to the climatic change and/or tectonic activity. The elemental ratios: Al2O3/TiO2, Th/Sc, La/Th, Co/Th, (Gd/Yb)n, Eu/Eu*, and REE pattern; and tectonic discrimination diagrams indicated that they were derived from felsic source rocks in the crystalline basement of the northern fringe of the Arabian Shield and Rutba Uplift. The Sargelu, Naokelekan and Barsarin formations are also supplied from the intermediate source rocks from the Mid Oceanic Ridge and deposited in an active setting. The geochemical parameters suggest the lower part of the Middle Jurassic and the shales from upper part of the Late Jurassic were deposited in an oxic shallow marine environment; and other ages were deposited in an anoxic deep marine environment.

Modelling reservoir deliverability within the Northern Beagle Sub-basin, Western Australia

Reservoir deliverability is a critical component affecting the viability of petroleum systems within a sedimentary basin. Deliverability can be described as the ability of a given rock to flow hydrocarbons to the surface. Calculating deliverability relies on estimates of reservoir pressure, permeability and thickness as well as fluid viscosity, all of which are difficult to predict in a frontier basin. Burial and erosional processes exert a fundamental control on these rock and fluid properties. If this erosion is not uniformly distributed across an area then complex variations in deliverability may result. This paper presents a novel approach to quantifying predictions of reservoir deliverability within the Northern Beagle Sub-basin of Western Australia, via the use of a 3D basin-scale model that provides spatial and temporal estimates of variations in rock and fluid properties.Active extension began in the Northern Beagle Sub-basin during the Early Jurassic and resulted in deposition of proposed source and reservoir intervals. A thick (>5km) succession of progradational Middle Jurassic deltaics overlies the early Jurassic petroleum system. During the Late Jurassic, the basin underwent a complex phase of erosion (attributed to rift flank uplift), which resulted in upwards of 3km of sediment being locally removed on footwall blocks of active faults, as well as over structural highs. In other areas, however, such as contemporaneous structural lows, amounts of erosion are minimal. This complex spatial pattern of erosion has implications for both the thermal history (affecting fluid viscosity), as well as reservoir quality (permeability).The final product generated from this workflow was an integrated, basin-scale 3D model of reservoir deliverability for the Northern Beagle Sub-basin.

Gas-condensate potential of the middle-Jurassic petroleum system in Abadan plain, Southwest Iran: Results of 2-D basin modeling

ABSTRACTThe Jurassic petroleum system has been proven as prolific oil and gas prospects in the southwestern of Iran. During this study, 2-D regional modeling was done on two selected sections (north-south and east-west); furthermore, 1-D models were reconstructed on 7 deeply drilled wells in order to evaluate petroleum generation and source rock maturity histories in the Abadan Plain area in southwest Iran. The results revealed that the Middle Jurassic Sargelu Formation with average present-time TOC and HI values of 2.65wt% and 151 mgHC/gTOC, respectively, can be classified as good to excellent type II source rock. The initial TOC and HI values regarded for modeling are 5wt% and 620 mgHC/gTOC, respectively. The geochemical maturity parameters indicate a wet gas window for the Sargelu Formation. The modeling results show that the maximum temperature and vitrinite reflectance in the Sargelu Formation has reached 150 oC and 1.3%VRo. Generation of hydrocarbon in the Sargelu commenced during the Early Cretaceous, while the main expulsion happened in the Paleogene. 2-D models show that the Jurassic source rock has already reached a high transformation ratio within the studied area and, due to lack of intense tectonic activity, the maturity is the same throughout the studied area. Oil and gas migrated mostly vertically to the overlying traps which are existed in the Jurassic and Cretaceous succession. The results predict the existence of gas-condensate in the Jurassic petroleum system of the studied area.

Geochemical characteristics of natural gases from different petroleum systems in the Longgang gas field, Sichuan Basin, China

Located in the Sichuan Basin, China, the Longgang gas field consists of three vertically developed petroleum systems with the Triassic Leikoupo Formation as a dividing interface. There is one marine petroleum system below the interface and one continental petroleum system above it. The marine petroleum system is composed of coal measures, the main source rock in the Longtan Formation, and marine reef reservoirs in the Changxing and Feixianguan formations. The continental petroleum system can also be subdivided into two sets. One is the Xujiahe petroleum system sourced from the Xujiahe coal measures in the Upper Triassic formation. The other is a Jurassic petroleum system that is sourced from Jurassic lacustrine black shales. The gas pools in the marine system contain H2S gas. The gases are very dry and the δ13C1 and δ13C2 values display less negative values with an average of −29.2 and −25.0‰, respectively. The gases are humic origin generated at highly to over mature stages from coal measures of the Longtan Formation. The natural gas in the continental petroleum system does not contain H2S. The natural gases from the Xujiahe petroleum system are mainly wet gases with a few dry gases, and belong to typical humic type sourced from coal measures of the Xujiahe Formation. All the gases from this Jurassic petroleum system are wet gases and the alkane gases show more negative carbon isotopic values typical of sapropels. These are derived from the lower Jurassic lacustrine black mudstone. The three sets of petroleum systems in the Longgang gas field are vertically well separated. Each system has its own source rock, and there are no gases from other sources despite multiple tectonic events in the past. The reservoirs had been in a relatively stable tectonic condition with excellent seals by cap rocks during the gas accumulation period.

A REVIEW OF THE COALY SOURCE ROCKS AND GENERATED PETROLEUMS IN THE DANISH NORTH SEA: AN UNDEREXPLORED MIDDLE JURASSIC PETROLEUM SYSTEM?

This paper reviews the Middle Jurassic petroleum system in the Danish Central Graben with a focus on source rock quality, fluid compositions and distributions, and the maturation and generation history. The North Sea including the Danish Central Graben is a mature oil province where the primary source rock is composed of Upper Jurassic – lowermost Cretaceous marine shales. Most of the shale‐sourced structures have been drilled and, to accommodate continued value creation, additional exploration opportunities are increasingly considered in E&P strategies. Triassic and Jurassic sandstone plays charged from coaly Middle Jurassic source rocks have proven to be economically viable in the North Sea. In the Danish‐Norwegian Søgne Basin, coal‐derived gas/condensate is produced from the Harald and Trym fields and oil from the Lulita field; the giant Culzean gas‐condensate field is under development in the UK Central North Sea; and in the Norwegian South Viking Graben, coal‐derived gas and gas‐condensate occur in several fields. The coaly source rock of the Middle Jurassic petroleum system in the greater North Sea is included in the Bryne/Lulu Formations (in Denmark), the Pentland Formation (in the UK), and the Sleipner and Hugin Formations in Norway. In the Danish Central Graben, the coal‐bearing unit is composed of coals, coaly shales and carbonaceous shales, has a regional distribution and can be mapped seismically as the ‘Coal Marker’. The coaly source rocks are primarily gas‐prone but the coals have an average Hydrogen Index value of c. 280 mg HC/g TOC and values above 300 mg HC/g TOC are not uncommon, which underpins the coals' capacity to generate liquid hydrocarbons (condensate and oil). The coal‐sourced liquids are differentiated from the common marine‐sourced oils by characteristic biomarker and isotope compositions, and in the Danish Central Graben are grouped into specific oil families composed of coal‐sourced oil and mixed oils with a significant coaly contribution. Similarly, the coal‐sourced gases are recognized by a normally heavier isotope signature and a relatively high dryness coefficient compared to oil‐associated gas derived from marine shales. The coal‐derived and mixed coaly gases are likewise assigned to well‐defined gas families. Coal‐derived liquids and gas discoveries and shows in Middle Jurassic strata suggest that the coaly Middle Jurassic petroleum system has a regional distribution. A 3D petroleum systems model was constructed covering the Danish Central Graben. The model shows that present‐day temperatures for the Middle Jurassic coal source rock ('Coal Marker') are relatively high (>150 °C) throughout most of the Danish Central Graben, and expulsion of hydrocarbons from the ‘Coal Marker’ was initiated in Late Jurassic time in the deep Tail End Graben. In the Cretaceous, the area of mature coaly source rocks expanded, and at present day nearly the whole area is mature. Hydrocarbon expulsion rates were low in the Paleocene to Late Oligocene, followed by significant expulsion in the Miocene up to the present day. High Middle Jurassic reservoir temperatures prevent biodegradation.

The diagenetic and tectonic significance of hydrocarbon accumulation in the southern Junggar Basin, NW China

The Jurassic petroleum system plays an increasingly important role in petroleum explorations in the southern Junggar Basin. To assess the hydrocarbon distribution and the accumulation history of the Jurassic reservoirs in this area, we carried out reservoir petrographic, fluorescence spectroscopic, and fluid inclusion petrographic analyses on the core and cutting samples from the QQ‐2 well in the Qigu Anticline. The oil accumulation has the partiality for high‐quality sandstone reservoirs that have the high porosity and permeability with values of 14–18% and (1–450) × 10−2 μm2, respectively, in the Middle Jurassic Toutunhe Formation (J2t) reservoirs. The pores are big with average diameters of 60–100 μm, and the pore throats are wide with values of 3.45–6.92 μm in the oil reservoirs. The intergranular pores survive thanks to the poor compaction and the poor cementation, and the dissolved and mould pores develop attributed to the strong dissolution in the oil reservoirs. Two episodes of oil charging and one episode of gas invasion were identified in the Middle Jurassic reservoirs in the southern Junggar Basin. The low‐maturity paleo‐oil charged the sandstone reservoirs at about 35 Ma when the paleo‐traps took shape during the Cretaceous–Eocene. A large number of faults and anticlinal traps was developed in the southern Junggar Basin at about 7 Ma, caused by the reactivation of the Tianshan Mountains in the late Cenozoic. Simultaneously, the leakage of the paleo‐oil, the accumulation of late oil, and the gas invasion all took place. Fault activities led to the leakage of paleo‐oil and helped the oil and gas accumulate in the Middle Jurassic reservoirs in the anticlinal trap shaping at about 7–8 Ma in the southern Junggar Basin.

Petroleum systems and results of exploration on the Atlantic margins of the UK, Faroes & Ireland: what have we learnt?

Abstract The exploratory drilling of 200 wildcat wells along the NE Atlantic margin has yielded 30 finds with total discovered resources of c. 4.1×10 9 barrels of oil equivalent (BOE). Exploration has been highly concentrated in specific regions. Only 32 of 144 quadrants have been drilled, with only one prolific province discovered – the Faroe–Shetland Basin, where 23 finds have resources totalling c. 3.7×10 9 BOE. Along the margin, the pattern of discoveries can best be assessed in terms of petroleum systems. The Faroe–Shetland finds belong to an Upper Jurassic petroleum system. On the east flank of the Rockall Basin, the Benbecula gas and the Dooish condensate/gas discoveries have proven the existence of a petroleum system of unknown source – probably Upper Jurassic. The Corrib gas field in the Slyne Basin is evidence of a Carboniferous petroleum system. The three finds in the northern Porcupine Basin are from Upper Jurassic source rocks; in the south, the Dunquin well (44/23-1) suggests the presence of a petroleum system there, but of unknown source. This pattern of petroleum systems can be explained by considering the distribution of Jurassic source rocks related to the break-up of Pangaea and marine inundations of the resulting basins. The prolific synrift marine Upper Jurassic source rock (of the Northern North Sea) was not developed throughout the pre-Atlantic Ocean break-up basin system west of Britain and Ireland. Instead, lacustrine–fluvio-deltaic–marginal marine shales of predominantly Late Jurassic age are the main source rocks and have generated oils throughout the region. The structural position, in particular relating to the subsequent Early Cretaceous hyperextension adjacent to the continental margin, is critical in determining where this Upper Jurassic petroleum system will be most effective.

Geochemical correlation of Asmari/Jahrum reservoir of Nargesi oilfield with seeps nearby

ABSTRACT In case of maintaining the reservoir pressure by gas injection, connection between the reservoir and oil seeps around the oilfield should be investigated. Existence of probable conduits from reservoir to surface would cause problems such as environmental issues and capital losses. Comprehensive geochemical analyses were performed on Nargesi oilfield and nearby seep samples in order to investigate their geochemical correlation. Biomarker and diamondoid distributions as well as stable carbon isotope analysis on selected samples were determined by GC-MS and Finnigan Delta Plus mass spectrometer, respectively. Two active petroleum systems were identified in the region. A Jurassic petroleum system charged Nargesi oilfield, whereas the seeps appear to be charged by an older petroleum system. Higher maturity of seep samples identified by methylnaphthalenes, trisnorhopanes, and triaromatic steroid ratios implied that the second petroleum system should be older than Jurassic. Biomarker ratios confirmed that Marl-Carbonate source rocks deposited under anoxic to dysoxic conditions in open marine environment were the main oil-generating facies for the oilfield. Diamondoid indexes further support the concept developed by biomarker data and reveal that the seeps should be probably charged by shaly source rock. The negative correlation implies that gas injection would be effective.

A basin modeling study of the Jafurah Sub-Basin, Saudi Arabia: Implications for unconventional hydrocarbon potential of the Jurassic Tuwaiq Mountain Formation

The Middle-Upper Jurassic organic-rich carbonate mudrocks of the Tuwaiq Mountain Formation in the Jafurah Sub-Basin of the Central Arabian Basin have long been recognized as the source of hydrocarbons trapped primarily in Upper Jurassic carbonate reservoirs of Saudi Arabia (e.g., Giant Ghawar Field). With the recent development of commercial hydrocarbon production from unconventional reservoirs in North America, these organic-rich, carbonate mudrocks are now recognized as potential shale-gas and shale oil plays.Three conventional source rock intervals (the Tuwaiq Mountain (TQMN), Hanifa and Jubaila Formations) exist within the Jurassic petroleum system of the Jafurah Sub-Basin. The TQMN formation is being evaluated for shale-gas and shale-oil potential by Saudi Aramco because the TQMN Fm. holds excellent unconventional gas characteristics, such as high total organic carbon content (TOC) and low clay content, and proper maturity window for oil and gas generation.Five wells, representing the first unconventional gas exploration wells drilled in the Jafurah Sub-Basin have been selected for 1D and 2D basin modeling work. The work was performed to investigate the burial and thermal maturity evolution of the TQMN Formation in the Jafurah Sub-Basin. The maturity of the TQMN Formation in the study wells varies from 0.8 to 1.25%VRE (covering peak oil to wet gas generation stage), despite only slight differences in present-day burial depths. The present day temperature gradients have been calculated to be higher at well locations where the source rock is at higher maturity. Modeling results suggest that higher temperature gradient areas of the basin probably has higher basement heat flow which leads to satisfactory match between measured and predicted maturity and temperature at present day. This increased basement heat flow in areas of higher temperature gradient correspond to the interpreted change in crustal composition (most likely granitic basement) generating more radiogenic heat.The modeling results suggest that TQMN source rocks started generating oil at about 100Ma and they reached the peak oil generation at about 70Ma. Present-day they are in the wet-gas generation window in the northern and eastern parts of the Jafurah Sub-Basin, where the thermal gradients are >28°C/km or higher. The central and southwestern parts of the Sub-Basin are cooler, and here, the TQMN source rocks are within the peak oil generation window. The warmer parts of the Sub-Basin have higher shale-gas potential compared to the cooler parts of the Basin. We note that proper modeling and estimation of gas content in these source rocks, and probably in unconventional resource estimation work in general, some skilled modifications in basin modeling parameters are necessary. Variation of the oil saturation threshold is necessary until a gas saturation level equal to or higher than the gas adsorption capacity of the source rock is obtained, otherwise, modeling will lead to overestimation of the oil migration out of the source rock and thus the amount of the oil that can be retained and cracked to gas at higher temperatures will be miscalculated. Therefore, the eventual gas content estimations will may be severely underestimated.Following our basin modeling study, we note that improvement of the present day subsurface temperature data will be necessary in the future to estimate the maturity and shale-gas potential of the TQMN source rocks in the Jafurah Sub-Basin.

Origins of Jurassic oil reserves in the Turpan–Hami Basin, northwest China: Evidence of admixture from source and thermal maturity

Middle–Lower Jurassic coaly shales were considered to be the source of Jurassic oil reserves in the Turpan–Hami Basin. In this study, we investigated the molecular and stable isotopic compositions of 35 gas samples and the geochemical parameters for 28 oil samples to reexamine the origin of these hydrocarbons. We show that the Jurassic natural gas reserves are derived mainly from coaly source rocks in the Middle Jurassic Xishanyao and Lower Jurassic Badaowan formations with maturities varying from 0.6% to 0.9%Ro. However, analysis of the low molecular weight hydrocarbons and diamondoid hydrocarbons shows that the maturities of the oils are clearly higher than those of the Jurassic coal measures and the natural gas generated from them. Their molecular and carbon isotopic compositions indicate that most of the Jurassic oil reserves are derived from pre-Jurassic lacustrine mudstones. The Hongtai gas/condensate field is an exception where the Jurassic coal measures are major contributors of light hydrocarbons. In contrast, the biomarker fingerprints of the Jurassic oils reveal a predominantly humic origin, which is most probably resulted from migration contamination. As such, the Jurassic petroleum system of the Turpan–Hami Basin is a mixed oil system derived from pre-Jurassic lacustrine mudstones and the Middle–Lower Jurassic coaly source rocks. This study opens pre-Jurassic structures in the Turpan–Hami Basin as favorable exploration prospects and illustrates the value of multiple correlation techniques to determine the sources of associated light and heavy hydrocarbons.

Multi-stage primary and secondary hydrocarbon migration and accumulation in lacustrine Jurassic petroleum systems in the northern Qaidam Basin, NW China

To improve the understanding on lacustrine Jurassic petroleum migration and accumulation in the northern Qaidam Basin (NW China), we conduct an integrated analysis of the petrography and geochemistry of oil-bearing fluid inclusion, including inclusion petrography, homogenization temperature combined with reservoir burial and thermal history, and reservoir sequential extraction. Results show that during the first stage of late Oligocene to early Miocene, the deep Paleogene reservoir was first charged by oils sourced from Middle Jurassic rocks (petroleum inclusion). This charge was accompanied by some oil alteration. During the second stage of early to middle Miocene, the deep Paleogene reservoir was charged by Lower-Jurassic-sourced oils (intergranular free oil) and this charging event is different from the first one in that it witnessed little hydrocarbon alteration. During the third stage in the Pliocene, widespread gas sourced from Lower and Middle Jurassic rocks occurred in both the deep Paleogene and shallow Neogene reservoirs and primary oil accumulations in deep Paleogene reservoirs migrated vertically to shallow Neogene reservoirs along faults, and formed secondary accumulations. Little alteration took place, favorable for the remigration. Thus, the lacustrine Lower and Middle Jurassic petroleum systems in the northern Qaidam Basin represent multi-stage primary and secondary hydrocarbon accumulations and mixing of hydrocarbons was very common.