Permian Source Rocks Research Articles

Combination and superimposition of source kitchens and their effects on hydrocarbon accumulation in the hinterland of the Junggar Basin, west China

In the hinterland of the Junggar Basin, there are multiple depressions with multiple sets of source rocks. Therefore, the conditions of hydrocarbon sources are complex, and the geochemical characteristics and sources of hydrocarbon vary in different structural belts. The evolution of the Che-Mo palaeohigh affected the formation of hydrocarbon source kitchens and hydrocarbon migration. We studied the combination and superimposition of hydrocarbon source kitchens, using as an example the hinterland of the Junggar Basin (including the Yongjin, Zhengshacun, Moxizhuang and Luliang uplift areas). The study was based on geochemical analyses of crude oil and fluid inclusions, and the histories of tectonic evolution and hydrocarbon generation. The results indicated that before the Paleogene there were two hydrocarbon-generating depressions: the Western Well Pen1 depression and the Changji depression on the south and north sides of the Che-Mo palaeohigh, respectively. The Permian source kitchen had been generating hydrocarbon continuously since Triassic and reached high maturity stage in the Cretaceous period. After Paleogene, the adjustment of the Che-Mo palaeohigh led to the subsidence of the Changji depression and the Jurassic source rocks reached mature stage and became the main source kitchens. However, the Jurassic source rocks in the Western Well Pen1 depression were still in a low maturity stage and did not generate oil because of the adjustment of tectonic movements. As a result, in the central and southern parts of the Junggar Basin, Jurassic source rocks generated oil, but in the Luliang uplift, the crude oil was from the Permian source rocks in the Western Well Pen1 depression and the Jurassic source rocks did not contribute. The crude oil in the central Zhengshacun-Moxizhuang belt was from the Permian source rocks in two depressions, and partially from the Jurassic source rocks. The crude oil in the Luliang uplift was from the source rocks of the lower Permian Fengcheng Formation and middle Permian Wuerhe Formation, which is characterized by superimposition of two sets of source kitchens and three accumulation stages. The crude oil in the Yongjin tectonic belt was from the lower Permian, middle Permian and Jurassic source rocks, which is characterized by superimposition of three sets of source kitchens and two accumulation stages. The crude oil in the Zhengshacun tectonic belt was from a combination of source kitchens of lower Permian and middle Permian in the Western Well Pen1 depression in the early stage and from the superimposition of Jurassic source rocks in the Changji depression in the late stage.

The Effect of Emeishan Supper Mantle Plume on the Thermal Evolution of Hydrocarbon Source Rocks in the Sichuan Basin

AbstractBoth the structural evolution and thermal history of the Middle ‐ Late Permian Sichuan Basin are closely related to activity of the Emeishan Supper Mantle Plume (ESMP). The ESMP played an important role in the thermal evolution of the pre‐Middle Permian hydrocarbon source rocks in the southwestern part of the Sichuan basin. On the basis of reconstructed thermal history of the Sichuan basin, based on vitrinite reflectance (Ro) from boreholes in the basin, using a paleo‐heat flow method, the effect of the ESMP on the evolution of the pre‐Middle Permian source rocks is studied. The results show that in the southwestern part of the Sichuan Basin (the intermediate zone of the ESMP) the organic matter of the Paleozoic source rocks became mature in middle Late Permian. This indicates that the thermal evolution of the Paleozoic source rocks was strongly affected by the ESMP. In more detail, in the region close to the ESMP, the source rocks of lower Permian were heated to peak maturity (maximum Ro > 3%) at around 260 Ma and later there was no secondary hydrocarbon generation. However, in the regions far away from the ESMP, secondary Mesozoic hydrocarbon generation of the source rocks existed. The thermal evolution of the Mesozoic source rocks was related with Mesozoic foreland basin evolutionburial history and subsequent regional denudation of the basin, rather than the ESMP. Therefore, except in the regions far away from the ESMP, the prospect of oil and gas from Paleozoic source rocks is unfavorable.

Organic geochemistry of Carboniferous and Lower Permian source rocks, Turpan-Hami Basin, NW China

Abstract Organic geochemistry characteristics of carbonate rock and mudstone samples are reported for cores in exploration wells and outcrops in the Carboniferous and Lower Permian, Turpan-Hami Basin. Extensive analyses include organic matter abundance, kerogen type, hydrocarbon generation and thermal evolution. The mudstone is higher in organic content, ranging from 0 – 4.45% TOC, suggesting relatively good source rock potential; whereas, the carbonate rock has a maximum TOC of 0.52% and is basically non-source rock. The matrix types of both carbonate rock and mudstone are grouped into Type III (dominant) and II2 (less). The carbonate rock is a bit better quality than the mudstone in organic types. The source rock from downhole samples can be early mature to highly mature. The maturity of outcrop samples range from mature to over-mature. The lower maturity of well samples is related to the shallower depth of the samples. The higher maturity of outcrop samples may be related to the tectonic movement and high geothermal gradient. Based on characteristics of thermal evolution, more effective Carboniferous-Lower Permian source rocks are distributed in the deeper location of the sag and can generate more natural gas. The igneous/volcanic rocks are better deep reservoirs in which natural gas accumulates.

Geochemical Characteristics of Oils from Chepaizi Area, Northwestern Junggar Basin, China

In recent years, great progress in petroleum exploration has been made obtained for Chepaizi Swell along the northwestern margin of Junggar Basin. But, the hydrocarbon sources of this area are still unknown, and this results in difficulty of determining the migration path system and migration trend. This also leads to difficulty in studying the oil-gas accumulation pattern of the area. In order to understand the oil sources, samples were systematically collected in the Swell and were analyzed for investigation of physical properties, chemical compositions and characteristics of bio-markers, carbon isotope and nitrogen compounds of the oils from Chepaizi. Through comparisons of physical and chemical characters, oils from different intervals of Chepaizi can be classified into two groups. One is the oils trapped in layers of Jurassic and below Jurassic (named as Lower Series of Strata oils), and another is those in layers of Cretaceous and above Cretaceous (named as Upper Series of Strata oils). Oils from the same group have similar densities, viscosities, group compositions and characteristics of saturated hydrocarbon, bio-marker and carbon isotope, while the oils from different groups are obviously different for the above-mentioned parameters. By fine oil-oil correlation, one can know that the lower-layer oils have the same oil source (from the Permian source rocks), and the upper-layer oils also have the same source (mainly from the Jurassic source rocks). In Chepaizi, the hydrocarbons stored in reservoirs originated mainly from Jurassic and Permian rocks. However, Cretaceous source rocks also have some contribution to oil-gas supply for oil pools. The oil-source division results based on nitrogen compounds (carbazoles) are completely identical with those by common geochemical indices, indicating that carbazoles are of importance in oil type division and oil-source correlation.

Accumulation Mechanisms and Evolution History of the Giant Puguang Gas Field, Sichuan Basin, China

Abstract:Solid bitumens were found throughout the carbonate reservoirs in the Puguang gas field, the largest gas field so far found in marine carbonates in China, confirming that the Puguang gas field evolved from a paleo‐oil reservoir. The fluid conduit system at the time of intensive oil accumulation in the field was reconstructed, and petroleum migration pathways were modeled using a 3‐D model and traced by geochemical parameters. The forward modeling and inversion tracing coincided with each other and both indicated that oils accumulated in the Puguang‐Dongyuezhai structure originated from a generative kitchen to the northwest of the Puguang gas field. The deposition of organic‐rich Upper Permian source rocks dominated by sapropelic organic matter in the Northeast Sichuan Basin, the development of fluid conduit system that was vertically near‐source rock and laterally near‐generative kitchen, and the focusing of oils originated from a large area of the generative kitchen, were the three requirements for the formation of the giant paleo‐oil reservoir from which the giant Puguang gas field evolved. The Puguang gas field had experienced a three‐stage evolution. The post‐accumulation processes, especially the organic‐inorganic interaction in the hydrocarbon‐water‐rock system, had not only profoundly altered the composition and characteristics of the petroleum fluids, but also obviously changed the physicochemical conditions in the reservoir and resulted in complicated precipitation and solution of carbonate minerals.

The geochemical characteristics and origin of crude oils in the Kekeya Oilfield, Xinjiang, China

GC/MS and GC/MS/MS techniques were employed to describe the characteristics of biomarker assemblages in two sets of hydrocarbon source rocks, Jurassic and Permian, in southwestern Tarim, and the parameters for the classification of the two sets of hydrocarbon source rocks have been established. It is found that diahopane and C30-unknown terpane are abundant in Permian samples, the contents of diahopane in Jurassic samples are relatively low, and terpenoids have been detected in Jurassic samples but not in Permian source rock samples. Kekeya crude oils are abundant in diahopane and C30-unknown terpane. The results of fine oil-rock correlation indicated that Kekeya crude oils were derived mainly from the Permian hydrocarbon source rocks. However, a small amount of diterpenoid was detected in the crude oils, indicating that the Jurassic hydrocarbon source rocks also made a certain contribution to Kekeya crude oils.

Source Rocks for the Giant Puguang Gas Field Sichuan Basin: Implication for Petroleum Exploration in Marine Sequences in South China

Abstract: Detailed geochemistry studies were conducted to investigate the origin of solid bitumens and hydrocarbon gases in the giant Puguang gas field. Two types of solid bitumens were recognized: low sulfur content, low reflectance (LSLR) solid bitumens in sandstone reservoirs in the Xujiahe Formation and high sulfur content, high reflectance (HSHR) solid bitumens in the carbonate reservoirs in the Lower Triassic Feixianguan and Upper Permian Changxing formations. Solid bitumens in the Upper Triassic Xujiahe Formation correlate well with extracts from the Upper Triassic to Jurassic nonmarine source rocks in isotopic composition of the saturated and aromatic fractions and biomarker distribution. Solid bitumens in the Feixianguan and Changxing formations are distinctly different from extracts from the Cambrian and Silurian rocks but display reasonable correlation with extracts from the Upper Permian source rocks both in isotopic composition of the saturated and aromatic fractions and in biomarker distribution, suggesting that the Permian especially the Upper Permian Longtan Formation was the main source of solid bitumens in the carbonate reservoirs in the Feixianguan and Changxing formations in the Puguang gas field. Chemical and isotopic composition of natural gases indicates that the majority of hydrocarbon gases originated from sapropelic organic matter and was the products of thermal cracking of accumulated oils. This study indicates that source rock dominated by sapropelic organic matter existed in the Upper Permian and had made major contribution to the giant Puguang gas field, which has important implication for petroleum exploration in marine sequences in South China.

Evidence for multiple stages of oil cracking and thermochemical sulfate reduction in the Puguang gas field, Sichuan Basin, China

The Puguang gas field is the largest gas field found in marine carbonates in China. Marine carbonate reservoirs in this field were buried to a depth of about 7000 m (22,966 ft) and experienced maximum temperature up to 220C before uplift to the present-day depth of 5000–5500 m (16,404–18,045 ft), with present-day thermal maturity between 2.0 and 3.0% equivalent vitrinite reflectance (Ro). Sulfur-rich pyrobitumens with reflectance up to 3.5% are widespread in the reservoirs and resulted from thermal cracking of crude oils most likely generated from Upper Permian source rocks and thermochemical sulfate reduction (TSR). Natural gases in the Puguang gas field have wide variations in nonhydrocarbon gas contents, with H2S contents between 5.1 and 58.3% and CO2 contents between 7.9 and 18.0%. The hydrocarbon gases originated mainly from thermal cracking of accumulated oil but were altered by TSR. Thermochemical sulfate reduction in the study area exerted different effects on the isotope compositions of different hydrocarbon gas components at different TSR stages. The differential increase of 13C values for different gas components reflects transformation from a heavy-hydrocarbon-gas–dominated TSR stage to a methane-dominated TSR stage. This caused a decrease of 13Cmethane13Cethane values and a corresponding conversion from reversed to normal isotope distributions. Thermochemical sulfate reduction in the study area appears to have been limited by sulfate concentrations in the reservoirs. A successive, three-stage TSR series, namely, liquid-hydrocarbon–involved TSR, heavy-hydrocarbon-gas–dominated TSR, and methane-dominated TSR, occurred in reservoirs with sufficient sulfate concentration. Methane can be the dominant organic reactant for TSR, but only at elevated temperature and after most C2+ hydrocarbons are exhausted.

Geobiological interpretation of the oxygen-deficient deposits of the Middle Permian marine source rocks in South China: A working hypothesis

To decipher the origin of oxygen-deficient shelfal deposits is significant for tracing the distribution of marine source rocks and interpreting the evolution of depositional environment. The origin of the Middle Permian Chihsia Formation in South China remains a puzzle for long with its evident oxygen-deficient features but diverse benthos. This paper shows a typical Chihsian depositional rhythm composed of the massive and the laminated limestones with ecological and geochemical features. Massive bioclastic limestone from the rhythm was aerobic in paleoxygenation condition indicated by both the ecological and geochemical features. However, a contradictory oxygenation was inferred for the “laminated” counterpart from the rhythm, with the ecological signal being aerobic and the geochemical one being anoxic. The difference in ecological and geochemical indications was interpreted as the instability of paleoxygenation condition in shelf environments, caused by an enhanced paleoproductivity. Rhythmic occurrence of the oxygen-deficient condition might have been stemmed from paleo-Tethyan paleocurrents flowing across South China.

The Puguang gas field: New giant discovery in the mature Sichuan Basin, southwest China

The giant Puguang gas field, with a proven original in-place gas volume of 350 109 m3 (12.36 TCFG), was discovered in 2003 in the eastern Sichuan fold-thrust belt of the mature Sichuan Basin, southwest China. The field is a combination structural-stratigraphic trap closed by lateral depositional change and fault closure. The trap evolved from a paleo-oil reservoir originating in the Triassic–Jurassic. The entrapment of thermal gas, which was derived from Lower–middle Silurian and Permian source rocks, occurred during deep burial in the Jurassic–Cretaceous. Tertiary–Quaternary compression transformed the paleotrap into the present gas reservoir. Gas is contained in the Lower Triassic Feixianguan and the Upper Permian Changxing reservoirs, which consist predominantly of dolomitized oolites deposited in shelf and platform-margin shoal and backreef environments. Reservoir quality is characterized by porosity of 1–29% and permeability of 0.01–9664 md, with buried depth greater than 5000 m (16,400 ft). The discovery of the Puguang field exemplifies the successful application of a new play concept and new technology in a mature basin. The discovery resulted from a shift in exploration strategy from structures to stratigraphic traps in reef and shoal dolomites and benefited from advanced high-resolution seismic techniques. The discovery will not only broaden the exploration scope in the Sichuan Basin, but also provide an excellent analog for exploration in other fold-thrust belts worldwide.

Sedimentary environments of organic matter from Middle Permian source rocks in northern Xinjiang, China

A systematic analysis of the inorganic and organic geochemistry of Middle Permian source rocks comprising carbonate rocks and mudstones was carried out, with samples collected from the outcrop and bore of the Junggar, Turpan and Ili basins in northern Xinjiang. This study confirmed that sedimentary parameters for an ancient water body, such as inorganic geochemistry and paleosalinity, have a close relation to the organic matter of source rocks. It is also disclosed that phytane predominance in the source rocks is mainly due to a reducing environment. Biomarkers, such as gammacerane and β-carotene, in the samples reflect a specific salinity in the sedimentary environments. Sedimentary zones with a strong reducing environment are more likely to produce deposits of primary organic matter, which will be buried and preserved contemporarily. Consequently, the source rocks are generally high in organic content and better in organic type than ordinary ones, and vice versa.

Tar sandstones in the Paraná Basin of Brazil: structural and magmatic controls of hydrocarbon charge

There are tar accumulations in Lower Triassic sandstones along the eastern margin of the Paraná Basin. The tar was derived from Permian source rocks that matured along the basic sills of the Serra Geral continental flood basalt cover. This paper exams the habitat of tar accumulation, integrating fieldwork with morphostructural data, digital elevation modelling, gravity and airborne magnetic data, remote sensing, and radiometric dates that constrain the timing of maturation and migration. The focus of this work is the Jacu structural complex, a large annular drainage anomaly, 20 km in diameter, that owes its origin to reactivation of pre-existing faults. Interpretation of the structural framework is based primarily on morphostructural analysis and the distribution of gravity anomalies. The Jacu structure consists of a central low-lying fault block that is surrounded by several structural highs, and is attributed to the interaction of NE- and NW-striking fault zones. The principal basement faults that encapsulate this structure were invaded by the dolerite dykes that fed the widespread flood basalt cover during the Early Cretaceous. An 40Ar/ 39Ar analysis directly dates this episode of magmatism to 134±2 Ma. Tar sandstones are restricted to the lower Pirambóia Formation and are present around the Jacu structure, especially near the structural highs or close to basic dikes. Morphostructural interpretation suggests the occurrence of tar sandstones at intermediate positions too, between the structural highs and lows. The most likely explanation for these tar accumulations relates oil maturation and migration to the intrusion of Lower Cretaceous Serra Geral sills into the Upper Permian black shales of the Irati Formation, and subsequent migration along faults and dyke walls into eolian sandstone reservoirs of the Triassic Pirambóia Formation. Not only did the basic dykes locally facilitate migration, but there were also places where they were barriers to lateral migration. Furthermore, the interdune and fluvial facies of the Pirambóia Formation formed local seals and barriers to vertical migration.

THE EXPLORATION POTENTIAL STUDY OF DEEP SEATED GAS IN TARIM BASIN

With the shallow natural gas exploration becoming difficult at present ,deep-seated natural gas exploration has become the hot issue. Tarim basin, which is situated in the western part of China, is the biggest sedimentary basin in China. The study result show that Tarim basin has three major better hydrocarbon source rocks, which are the Cambrian-Ordovician, Carboniferous-lower Permian and Triassic-Tertiary source rocks, and high efficiency gas reservoirs and seal rocks, forming five sets of regional associations of gas reservoir and capping bed. Therefore, the basin has better physical condition for deep-seated gas generation, storage and conservation. Based on the present condition of gas exploration, the authors point out that Kuche depression, Northern uplift, Central uplift, Bachu uplift and South-western depression in Tarim basin has wider exploration prospect for deep seated gas.

Mixed oils derived from multiple source rocks in the Cainan oilfield, Junggar Basin, Northwest China. Part I: genetic potential of source rocks, features of biomarkers and oil sources of typical crude oils

There are four generative hydrocarbon source rocks of Carboniferous, Permian, Triassic, and Jurassic age in the east of the Junggar Basin. Geochemical study of these has shown that Permian source rocks, which contain high abundances of organic matter with good genetic potential, are the best hydrocarbon source rocks in this area. Triassic source rocks are shown to be next best in these aspects. The abundance of mainly type III organic matter in Jurassic and Carboniferous source rocks varies greatly and the genetic potential of these rocks is lower than that of Permian and Triassic rocks. These four source rock units in the Fukang sag all reach a mature to highly mature stage of thermal generation, and have generated large amounts of oil. Permian extracts are isotopically light with δ 13C ratios generally less than −29‰. They have low Pr/Ph ratios, are rich in β-carotane, tricyclic terpanes, gammacerane and C 28 and C 29 steranes, contain almost no diasteranes and have a low content of C 27 steranes. The carbon isotopic composition of the Triassic extracts is similar to that of the Permian, but they are characteristically rich in Ts, C 29Ts and diahopanes, and have low gammacerane contents. The carbon isotopic composition of Jurassic extracts is noticeably heavier than that of Permian and Triassic extracts, with δ 13C being generally greater than −28‰. Jurassic source rocks have Pr/Ph ratios generally >3.0, and are rich in pentacyclic hopanes and C 29 steranes, but poor in tricyclic terpanes, gammacerane and C 27 and C 28 steranes. Using carbon isotopic and biomarker data, the crude oils in this area can be divided into five groups. The first group of crude oils (A) is derived from the Permian, the second group (B) from the Triassic, and the third group (C) from the Jurassic source rocks. The geochemical properties of the fourth group (D) of oils are intermediate between the properties of typical Permian, Triassic and Jurassic oils and they are interpreted as mixed oils derived from multiple source rocks, including the Permian, Triassic and Jurassic. The fifth group of crude oils (E) is particularly isotopically heavy and originates from Carboniferous source rocks.

Mixed oils derived from multiple source rocks in the Cainan oilfield, Junggar Basin, Northwest China. Part II: artificial mixing experiments on typical crude oils and quantitative oil-source correlation

There are five groups of crude oils in the East Junggar Basin, four of which are derived from single sources (viz. Permian, Triassic, Jurassic, and Carboniferous). The crude oils in the Cainan field are of a special type in that they have little correlation with any of the four known source rocks in the Basin. Based on their distribution in the reservoir formations, and their carbon isotopic and biomarker compositions, it is concluded that these crude oils are mixtures of hydrocarbons from Permian, Triassic and Jurassic source rocks. A mixing calculation using whole-oil stable carbon isotope ratios of typical end-member crude oils suggests that the contribution of Jurassic source rocks to the Cainan crude oils averages 50–65%. A second calculation based on absolute concentrations of biomarkers indicates that the Jurassic contribution averages 62%, while those of the Triassic and Permian source rocks average 15 and 23%, respectively. Artificial laboratory mixing of three typical Permian, Triassic and Jurassic oils indicates that the average contribution of the Jurassic source rocks is 65%, whereas those of the Triassic and Permian rocks are around 15 and 20%, respectively. In summary, using whole-oil stable carbon isotope ratios and biomarker parameters, it can be concluded that the Jurassic source makes a contribution of 55–70%, while the Triassic and Permian sources each contribute 10–30%. Therefore the crude oils in the Cainan oilfield are mainly derived from Jurassic source rocks in the Fukang Sag.

Molecular correlation of free oil and inclusion oil of reservoir rocks in the Junggar Basin, China

Free oils and inclusion oils (oil-bearing fluid inclusions) of 12 samples collected from the sandstone reservoir formations in the central, eastern and northern areas of the Junggar Basin, northwest China, were analyzed by GC and GC-MS. Analytical results indicate very similar biomarker distributions within each of the free oils and their associated inclusion oils in the two samples collected, respectively, from the northwestern and eastern border of the Junggar Basin. The free oil and inclusion oil of sample MD1-1, collected from the northwestern border, correlate well with the Permian source rock of the Fencheng Formation, while those of sample DN1-1 from the eastern border correlate with the Permian source rock of the Pingdiquan Formation. In contrast, in the central area, the free and inclusion oils vary significantly in most cases, which suggests variations of sources for oil charges during the filling process. These data, and the correlation between the free and inclusion oils, are consistent with the field and seismic data, which show that in areas where samples MD1-1 and DN1-1 are located, only one available source rock exists, while in the central area, multiple source rocks are present.

Upper Permian as a new play model on the mid-Norwegian continental shelf: Investigated by shallow stratigraphic drilling

A 750 m-thick, fully marine succession of sandstones, coarse-grained turbidites, shales, and reworked sabkha sediments has been cored on the eastern margin of the mid-Norwegian shelf. The succession has been dated as Upper Permian-Lower Triassic and is comparable to rocks of the same age exposed onshore East Greenland. These data demonstrate that the marine depositional basin between Greenland and Norway extended much farther east than previously thought. Reddish, shallow-marine sandstones in the lower 170 m of the cored succession probably represent reworking of older sedimentary rocks present to the east of the drill sites. This suggests that Upper Devonian-Lower Permian sediments were deposited on Caledonian basement east of the present-day limits of the basin. The cored succession also contains source rocks that can be stratigraphically correlated with the oil-prone source rocks of the Upper Permian Ravnefjeld Formation onshore East Greenland. Some of the cored sandstone intervals were stained with light, nonbiodegraded oil that most likely was sourced from Upper Permian or, alternatively, Lower Triassic mudstones. Reworked fragments of reef-building organisms in Upper Permian turbidites and Upper Permian carbonates encountered in an exploration well on the Nordland Ridge indicate that carbonate deposition and reef building occurred on structural highs on the Trondelag Platform. The observations from the cored successions are key elements in a new Paleozoic play model on the mid-Norwegian continental shelf and include the first evidence for the existence of an Upper Permian source rock in the area, with Upper Permian carbonates or sandstones or Triassic-Jurassic sandstones as reservoir. (Begin page 108)

Thermal regime and petroleum systems in Junggar basin, northwest China

The conversion of organic matter into oil and gas depends upon temperature and time, and the study of thermal maturation of oil-source rocks in a petroleum system is of importance for formation of a petroleum system. Based on the temperature data from 196 wells and thermal conductivity measurements of 90 core samples, altogether 35 heat flow data are obtained in the Junggar basin. The results show that the Junggar basin is a relatively “cold” basin at present, with a mean temperature gradient and heat flow of 21°C/km and 42 mW/m 2, respectively. Thermal history reconstructed from vitrinite reflectance data indicates that the Paleozoic formations experienced their maximum paleotemperature during the Permian and Triassic at higher paleoheat flow of about 85 mW/m 2 and that the basin then cooled down to the present low heat flow. The high paleoheat flow can be attributed to the Carboniferous to Permian rifting. The thermal evolution has a quite important effect on the formation and evolution of the petroleum systems in the Junggar basin, i.e. the Permian and the Jurassic systems. The Jurassic petroleum system is quite limited in space for the cooled thermal regime during the Meso-Cenozoic and the source rocks of the Middle–Lower Jurassic entered the oil window only along the North Tianshan foreland region, where the Jurassic is buried to the depth of 5–7 km at present. In contrast, the Middle–Lower Permian source rocks have experienced oil and gas generation in late Permian to Triassic, and the Permian petroleum system was formed prior to the Triassic when the upper Paleozoic formations reached their maximum paleotemperature due to higher paleoheat flow.

Hydrocarbon Potential of Kuwait

Potential reservoir and seal rocks were evaluated in onshore Kuwait based on lithological descriptions, and probable Permian, Triassic, Jurassic, and Lower Cretaceous source rocks have been identified in eastern Kuwait and along a depositional axis in central Kuwait west of the Burgan high. Time-temperature index (TTI) modeling and structural maps of selected stratigraphic horizons revealed that oil generated in these areas then migrated up-dip into the known production structural highs. Although deeper reservoirs in the known producing horizons appear to be prone to light oil-wet gas accumulations, based on thermal maturation studies, identification of these deep traps may show the greatest potential for additional hydrocarbon discoveries in Kuwait, as in the recent Kraa Al Maru discovery. The possible existence of stratigraphic traps not seen on seismic sections, but present on the oil migration pathways, is proposed.

Sequence stratigraphy of source and reservoir rocks in the Upper Permian and Jurassic of Jameson Land, East Greenland

Approximately half of the hydrocarbons discovered in the North Atlantic petroleum provinces are found in sandstones of latest Triassic – Jurassic age with the Middle Jurassic Brent Group, and its correlatives, being the economically most important reservoir unit accounting for approximately 25% of the reserves. Hydrocarbons in these reservoirs are generated mainly from the Upper Jurassic Kimmeridge Clay and its correlatives with additional contributions from Middle Jurassic coal, Lower Jurassic marine shales and Devonian lacustrine shales. Equivalents to these deeply buried rocks crop out in the well-exposed sedimentary basins of East Greenland where more detailed studies are possible and these basins are frequently used for analogue studies (Fig. 1). Investigations in East Greenland have documented four major organic-rich shale units which are potential source rocks for hydrocarbons. They include marine shales of the Upper Permian Ravnefjeld Formation (Fig. 2), the Middle Jurassic Sortehat Formation and the Upper Jurassic Hareelv Formation (Fig. 4) and lacustrine shales of the uppermost Triassic – lowermost Jurassic Kap Stewart Group (Fig. 3; Surlyk et al. 1986b; Dam & Christiansen 1990; Christiansen et al. 1992, 1993; Dam et al. 1995; Krabbe 1996). Potential reservoir units include Upper Permian shallow marine platform and build-up carbonates of the Wegener Halvø Formation, lacustrine sandstones of the Rhaetian–Sinemurian Kap Stewart Group and marine sandstones of the Pliensbachian–Aalenian Neill Klinter Group, the Upper Bajocian – Callovian Pelion Formation and Upper Oxfordian – Kimmeridgian Hareelv Formation (Figs 2–4; Christiansen et al. 1992). The Jurassic sandstones of Jameson Land are well known as excellent analogues for hydrocarbon reservoirs in the northern North Sea and offshore mid-Norway. The best documented examples are the turbidite sands of the Hareelv Formation as an analogue for the Magnus oil field and the many Paleogene oil and gas fields, the shallow marine Pelion Formation as an analogue for the Brent Group in the Viking Graben and correlative Garn Group of the Norwegian Shelf, the Neill Klinter Group as an analogue for the Tilje, Ror, Ile and Not Formations and the Kap Stewart Group for the Åre Formation (Surlyk 1987, 1991; Dam & Surlyk 1995; Dam et al. 1995; Surlyk & Noe-Nygaard 1995; Engkilde & Surlyk in press). The presence of pre-Late Jurassic source rocks in Jameson Land suggests the presence of correlative source rocks offshore mid-Norway where the Upper Jurassic source rocks are not sufficiently deeply buried to generate hydrocarbons. The Upper Permian Ravnefjeld Formation in particular provides a useful source rock analogue both there and in more distant areas such as the Barents Sea. The present paper is a summary of a research project supported by the Danish Ministry of Environment and Energy (Piasecki et al. 1994). The aim of the project is to improve our understanding of the distribution of source and reservoir rocks by the application of sequence stratigraphy to the basin analysis. We have focused on the Upper Permian and uppermost Triassic– Jurassic successions where the presence of source and reservoir rocks are well documented from previous studies. Field work during the summer of 1993 included biostratigraphic, sedimentological and sequence stratigraphic studies of selected time slices and was supplemented by drilling of 11 shallow cores (Piasecki et al. 1994). The results so far arising from this work are collected in Piasecki et al. (1997), and the present summary highlights the petroleum-related implications.