Cambrian Source Rocks Research Articles

Lower Palaeozoic source rocks in Manjiaer Sag, Tarim Basin

Abstract Considering its vertical distribution characteristics, this article argues that the Lower Palaeozoic source rock in the Manjieer Sag is composed of three sets of source rocks of Middle-Lower Cambrian, Middle-Lower Ordovician, and Upper Ordovician. The source rock of the Middle-Lower Ordovician Heituwa Formation has similar sedimentary facies and developmental features to the Middle-Lower Cambrian source rock, and has abundant organic material. The Upper Ordovician source rock is poor and limited in distribution. The source rocks have different thermal evolution histories. In central and western Manjiaer sag, Middle-Lower Cambrian source rock entered oil generation peak in Late Caledonian and Early Hercynian, Middle-Lower Ordovician source rock in Late Hercynian, and Upper Ordovician source rock in Late Yanshan and Himalayan. The threefold division of the source rock is the foundation of detailed study on the derived source and the accumulation process of marine oil in Tarim platform area.

Formation and evolution of Silurian paleo-oil pools in the Tarim Basin, NW China

The formation and evolution of Silurian sandstone reservoirs, which are characterized by the coexistence of reservoir bitumen with different types of commercial oil pools in a very extensive area around the slope and uplift areas of the Manjiaer Depression in the Tarim Basin, NW China, are still in question. In this paper we report our investigations on the geological and geochemical characteristics of this reservoir. The results show there are four types of oil shows in the reservoir: severely biodegraded solid bitumen, biodegraded heavy oil, normal oils and light oils with slight biodegradation. Three suites of petroleum inclusions were identified in the reservoir which were formed during the early Devonian, Triassic to Cretaceous and late Tertiary, respectively. Petroleum in the Silurian sandstone reservoirs mainly originated from the mid-lower Cambrian source rock and mid-upper Ordovician source rock. The thermal maturity evolution of the source rocks in slope areas has shown that there were three main stages of oil generation that controlled the formation of the above three stages of petroleum inclusions. This evidence indicates that the Silurian reservoir has experienced three petroleum charge events during its geological history. The first charge event occurred during the early Devonian and it resulted in giant paleo-pools, which gradually evolved into the presently widespread bitumen due to the combination of biodegradation and thermal alteration. The second charge covered a long period from Triassic to Cretaceous and probably was related to both the mid-lower Cambrian source rock and the mid-upper Ordovician source rock. The petroleum generated during this stage mixed and interacted with the low matured residual bitumen and eventually formed the present soft bitumen and some residual heavy oils in the reservoirs. The third charge event, mainly associated with the mid-upper Ordovician source rocks, occurred mainly during late Tertiary and accounted for most of the present commercial petroleum pools (mainly normal and light oils).

Characteristics, genesis and accumulation history of natural gas in Hetianhe gasfield, Tarim Basin, China

Hetianhe gasfield in Bachu region of the Tarim Basin is mainly composed of three reservoir-caprock assembly, namely regional caprock of upper mudstone, middle mudstone and lower mudstone of the Carboniferous and reservoir of Bachu bioclastic limestone, glutenite and the Ordovician carbonate buried hill. Natural gas in Hetianhe gasfield sourced from the Cambrian source rock. It is thought that gases in Ma4 well block in the east of Hetianhe gasfield are mainly crude-oil cracked gases, while those in Ma3 and Ma8 well blocks in the west are the mixture gases of kerogen cracked gases and crude-oil cracked gases. Natural gas is rich in H2S and accumulated in multiply stages as the result of TSR. The accumulation history is divided into three stages, namely accumulation and breakage in the late Caledonian-early Hercynian, migration and dissipation in the late Hercynian and accumulation in Himalayan. The main accumulation of reformed gas reservoir is in Himalayan.

Geochemical characteristics and accumulation of marine oil and gas around Halahatang depression, Tarim Basin, China

There exists a petroleum system rich of oil and gas around Halahatang depression, where the oil and gas possess obvious local distinctions of properties in different parts. The research proved that the discovered crude oil and natural gas in the region derived mainly from O2+3 source rock, and the differences of its properties were controlled by the oil and gas filling intensity. The comprehensive study result shows the oil and gas reservoirs of the region mainly underwent three important accumulation phases: late Caledonian-Early Hercynian epoch, late Hercynian epoch, and Yanshan-Himalayan epoch. In the first phase, the oil and gas derived mostly from Cambrian source rock, which formed the primary ancient oil reservoirs, then suffered strong degradation and remained a great quantity of pyrobitumen in the high position of Tabei uplift in the present. In the second phase, the O2+3 source rock of Manjia’er depression started its generation of hydrocarbon, which accumulated in the high position of Tabei up-lift afterwards, and then biodegradated to heavy oil in the late Hercynian epoch. In the last phase, the O2+3 source rock of southern Halahatang depression and margin of Manjia’er depression started its peak of generating liquid hydrocarbon, which mostly accumulated in the trap formed before the Indo-China and Yanshan epoch, and in somewhere the heavy oil suffered dilutions in various degrees or serious gas invading, to lead to obvious crude oil divergence.

Cracking conditions of crude oil under different geological environments

There are mainly 3 kinds of existing states of oil generating from source rocks, that is, dispersive liquid hydrocarbon inside of source rock, dispersive liquid hydrocarbon outside of source rock and concentrated liquid hydrocarbon outside of source rock. Because of the differences in thermal history and medium conditions around, and the interaction of organic and inorganic matter, the liquid hydrocarbon with 3 kinds of existing state has different cracking conditions. The gas generation dynamics experiments of crude oil matching different mediums indicate that the distribution of activation energy of methane changes a lot according to medium difference. The carbonate has a main influence on oil cracking conditions and can largely reduce its activation energy, which reflects the lower cracking temperature of crude oil. The mudstone takes a second place and the sandstone is the smallest. The catalytic cracking function to the oil of the carbonate, of the mudstone and of the sandstone changes weaken in turn. The corresponding Ro values of main gas generation period in different mediums are as follows: 1.5%–3.8% with pure crude oil, 1.2%–3.2% with dispersive crude oil in carbonate, 1.3%∼3.4% with dispersive crude oil in mudstone and 1.4%–3.6% with dispersive crude oil in sandstone. The influence of pressure to crude oil cracking is relatively complicated. In the low heating speed condition, pressure restrains the oil cracking and gas generation, but in the high heating speed condition, pressure has an indistinctive influence to the oil cracking and gas generation. Pressure also makes a different effort in different evolvement stage. Taking the middle and lower Cambrian source rocks in the Tarim Basin as an example, primary oil generating quantity is 2232.24×108t, residual oil and oil cracking gas quantity is 806.21×108t and 106.95×1012m3 respectively.

Petroleum Migration Direction of the Silurian Paleo‐pools in the Tarim Basin, Northwest China

Abstract: The results obtained in this paper indicate that carbazole‐type compounds have high thermal stability and also show stability in oxidation and bio‐degradation. This kind of compounds still has a high concentration and complete distribution in the analyzed dry asphalt samples, showing that they are particularly useful in studying petroleum migration of paleo‐pool. During the basin's first‐stage of oil‐gas pool formation in the Silurian in Tazhong and Tabei areas of Tarim Basin (at the end of Silurian period) and the second‐stage in the Awati area (in Permian), the petroleum experienced a long‐distance migration. During the formation of the Silurian paleo‐pools in Tazhong Uplift at the end of Silurian, the petroleum mainly came from the lower and middle Cambrian source rocks in the Manjiaer sag. The petroleum migrated towards the southwest‐south entering the Silurian reservoir beds in Tazhong first. Then, it further migrated within Silurian from northwest to southeast along the highs of the Structural Belts to the region of the Silurian pinchout boundary in Tazhong. In Tabei Uplift, during the first‐stage of pool formation, the petroleum was also from the lower and middle Cambrian source rocks in the Manjiaer sag. It migrated northwest entering the Silurian reservoir beds in the Tabei Uplift firstly, and then the migration continued in the same direction within the Silurian reservoirs and finally the petroleum was trapped in higher positions. During the second‐stage pool formation in the Silurian beds in the areas around Awati sag, the petroleum mainly came from the lower‐middle Cambrian source rocks in the Awati sag. The petroleum migrated from the generation center to Silurian reservoirs in all directions around the sag through major paths, and the petroleum was finally trapped in higher locations.

The distribution of the oil derived from Cambrian source rocks in Lunnan area, the Tarim Basin, China

There are great differences in biomarks between Cambrian oil and Middle-Upper Ordovician oil. In this stuty, the authors analyzed 40 oils found in Lunnan area by GC-MS and calculated the content of Cambrian oil in the 40 oils according to the steroid indexes of typical oil mixture and match experiment. The results show that it is a general phenomenon in Ordovician reservoir that the oil derived from Cambrian source rock mixed with the oil derived from Middle-Upper Ordovician source rock in Lunnan area, the mixture degree of the two oils is lower in Carboniferous reservoir than in Ordovician reservoir, and the oils kept in Triassic reservoir have single source, Middle-Upper Ordovician source rock. The mixture oils mainly composed of Cambrian oil (>50%) distributed in Sangtamu fault zone, and the oils found in Lunnan fault zone are Middle-Upper Ordovician oil. This distribution of oils in Lunnan area is owing to that Lunnan fault zone is located in anticline axis part, Lunnan fault zone underwent serious erosion, and the oils from Cambrian source rock accumulated in Lunnan fault zone were degraded completely during Caledonian-Hercynian movement. But the Cambrian oil accumulated in Sangtamu fault zone was not degraded completely and some of them were left for the location of Sangtamu fault zone is lower than Lunnan fault zone. Later, the oil derived from Middle-Upper Ordovician source rock mixed with the remained Cambrian oil, and the mixture oil formed in Sangtamu fault zone.

Two accumulation modes of marine-origin natural gas in the Tarim Basin

Hetianhe gas field, Lungudong gas field and Tazhong gas field are marine marine-origin natural gas reservoirs in the craton area in the Tarim Basin. The natural gas is generated from Cambrian source rocks. The simulation experiment indicated that the cracking of the dispersedly dissoluble organic matter remaining in the source rocks is the main origin of marine natural gas. There are two modes to form gas reservoirs, one is the dry gas reservoir such as Hetianhe gas field, in which gas accumulated on the fault belt with violent tectonic movement, the other is condensate gas reservoir formed on the inheriting uplift such as Lunnan and Tazhong gas fields. The hybrid simulation experiment of cracking gas and crude oil indicated that crude oil accumulated on a large scale in those uplift belts at the early stage, and natural gas filled the ancient oil reservoir at the late stage, and the gas reservoirs were formed after the gas mixed with the crude oil.

Relations between spatial distribution and sequence types of the Cambrian-Ordovician marine source rocks in Tarim Basin

Marine source rocks are considered to be mainly composed of the Cambrian-Ordovician deposit in Tarim Basin. Based on the previous studies made by other researchers, the authors calculated the thickness and distribution scale of these Cambrian-Ordovician source rocks by integrating sequence stratigraphy with investigations on sedimentary environments, well-shooting demarcating and calibrating the thickness of unknown source rocks with the thickness of the known ones according to characteristics of the source rocks that have “double track” seismic lineup reflectance. The results showed that the distribution area of the Lower-Cambrian Yuertusi Fm. source rock in platform inner depressions, slopes and deep basins is much bigger than that of the Middle Cambrian evaporite-lagoon source rock. Moreover, the former is superior to the latter in terms of the source rock quality. Likewise, the Middle-Ordovician Heituao Fm. source rock in the slopes and deep basins has a much wider distribution and better quality than the Upper Ordovician, and its quality is also better than those of the Shaergan and Yinggan Fms. source rock within platforms as well as the lime-mud-mound source rock along the fringe of the Upper-Ordovician platform. Most good Lower-Cambrian source rocks of the Kalpin outcrop lie on the initial ingression surface or in the condensed member of the Type I sequence. In this section, the source rock in Type II is inferior to that in Type I, even being far from an effective one (TOC: <0.5%). Likewise, the good Middle-Ordovician Heituao source rock also lies on the initial ingression surface or in the condensed member of the Type I sequence, while the poor Yinggan source rock and the lime-mud-mound along the fringe of the platform develop all in the Type II sequence. Under the condition of the same sea-level rising altitude and time, the ingression displacement (S1) at the base border in Type I is larger than S2 in Type II. Thus, the distribution of the source rock developed above the base border in Type I is wider than that in Type II. The maximal ingression range dominates the ultimate distribution of source rocks. Because S1 is greater than S2, the relative rate of ingression on the base border of Type I is obviously bigger than that of Type II. The difference in ingression rate is one of the factors that lead to the superiority of the source rock at the base border in Type I to that Type II. Therefore, it is of great significance to study the spatial distribution, developing era and quality determination of source rocks by means of sequence stratigrahpy.

KINETICS OF HYDROCARBON GAS GENERATION FROM MARINE KEROGEN AND OIL: IMPLICATIONS FOR THE ORIGIN OF NATURAL GASES IN THE HETIANHE GASFIELD, TARIM BASIN, NW CHINA

In this paper we derive kinetic parameters for the generation of gaseous hydrocarbons (C1‐5) and methane (C1) from closed‐system laboratory pyrolysis of selected samples of marine kerogen and oil from the SW Tarim Basin. The activation energy distributions for the generation of both C1‐5 (Ea = 59‐72kcal, A = 1.0×1014 s−1) and C1 (Ea = 61‐78kcal, A = 6.06×1014 s−1) hydrocarbons from the marine oil are narrower than those for the generation of these hydrocarbons from marine kerogen (Ea = 50‐74kcal, A = 1.0×1014 s−1 for C1‐5; and Ea = 48‐72kcal, A=3.9×1013 s−1 for C1, respectively). Using these kinetic parameters, both the yields and timings of C1‐5 and C1 hydrocarbons generated from Cambrian source rocks and from in‐reservoir cracking of oil in Ordovician strata were predicted for selected wells along a north‐south profile in the SW of the basin. Thermodynamic conditions for the cracking of oil and kerogen were modelled within the context of the geological framework. It is suggested that marine kerogen began to crack at temperatures of around 120°C (or 0.8 %Ro) and entered the gas window at 138°C (or 1.05 %Ro); whereas the marine oil began to crack at about 140 °C (or 1.1 %Ro) and entered the gas window at 158 °C (or 1.6%Ro).The main geological controls identified for gas accumulations in the Bachu Arch (Southwest Depression, SW Tarim Basin) include the remaining gas potential following Caledonian uplift; oil trapping and preservation in basal Ordovician strata; the extent of breaching of Ordovician reservoirs; and whether reservoir burial depths are sufficiently deep for oil cracking to have occurred.In the Maigaiti Slope and Southwest Depression, the timing of gas generation was later than that in the Bachu Arch, with much higher yields and generation rates, and hence better prospects for gas exploration. It appears from the gas generation kinetics that the primary source for the gases in the Hetianhe gasfield was the Southwest Depression.

The genesis of H2S in the Weiyuan Gas Field, Sichuan Basin and its evidence

The Sinian Dengying Formation gas pool in Weiyuan is the oldest large-scale sulfur-bearing gas field in China, which has a H2S content ranging from 0.8% to 1.4%. The Cambrian Xixiangchi Formation gas pool discovered recently above the Dengying Formation contains gas geochemical behaviors similar to those of Dengying Formation but different in sulfur isotopes of H2S. Investigations show that though these two Sinian and Cambrian gas pools are separate ones, they share the same Cambrian source rock. The higher dry coefficient, heavier carbon isotopes, sulfur isotopes of sulfide, lower filling of gas pools, formation water characteristics, reservoir properties and H2S distribution, indicate that H2S in both the Sinian and Cambrian gas pools originates from TSR. The sulfur isotopes of sulfates have shown that H2S was formed in respective pools, namely hydrocarbons charged into the pools reacted with the Dengying Formation and the Xixiangchi Formation gypsum (TSR), respectively, to form H2S. Compared with sulfur isotopes of sulfates in each pool, δ34S values of H2S are 8‰ lighter for the Dengying Formation pool and 12‰ lighter for the Xixiangchi Formation pool, respectively, which is attributed to the difference in temperatures of TSR occurrence. The reservoir temperature of the Xixiangchi Formation pool is about 40°C lower than that of the Dengying Formation pool. Temperature plays a controlling role in both the sulfur isotopic fractionation and amounts of H2S generation during TSR.

The Silurian play in the Tazhong Uplift, Tarim Basin, northwestern China

Silurian sandstone reservoirs in the Tazhong Uplift in the Tarim Basin, northwestern China are rich in bitumen and movable oil. Analysis of the biological markers indicates that the bitumen and movable oil came from two source rocks in the Cambrian and Middle/Upper Ordovician system, both of which are belong to marine facies. The Silurian system experienced three stages of oil filling, namely Late Caledonian period (400 Ma), Late Hercynian period (240 Ma) and Yanshan-Himalayan (40 Ma) period. Most of the oil emplaced in the Late Caledonian was subsequently oxidized to bitumen. The movable oil found at the present time was mainly generated from the Middle/Upper Ordovician source rocks, with only a minor contribution from the Cambrian source rocks generating in the two later periods. Bitumen and heavy crude were largely trapped below a red mudstone unit while movable oil was concentrated below an underlying gray mudstone unit (the middle sub-section of bitumen sandstone section). Lateral migration into the Silurian reservoirs took place from northwest to southeast in each stage and was controlled by an inherited palaeohigh. While individual relatively limited in extent, the tidal-flat sandstones of the main reservoir have stacking patterns that generate extensive sand sheets. Faulting can both enhance connectivity and create traps.

HYDROCARBON SOURCE ROCKS AND GENERATION HISTORY IN THE LUNNAN OILFIELD AREA, NORTHERN TARIM BASIN (NW CHINA)

In this paper we report on source rocks and maturation history at the Lunnan oilfield, northern Tarim Basin (NW China), using a combination of organic petrographic and geochemical techniques. Three separate source rock intervals are present here: Cambrian mudstones and argillaceous limestones; Middle and Upper Ordovician argillaceous limestones; and Triassic mudstones. Reservoir rocks comprise Lower Ordovician carbonates, Carboniferous sandstones, and Triassic and Jurassic sandstones. Structural traps were formed principally during the Silurian and Jurassic.The Lunnan field is located on a small‐scale palaeo uplift which developed during the Early Palaeozoic. Hydrocarbons migrated updip from source areas in surrounding palaeo‐lows along faults and unconformities. Major phases of hydrocarbon generation and migration occurred in the Early Silurian — Late Devonian, Cretaceous — Early Tertiary and Late Tertiary. Uplift and intense erosion at the end of the Devonian destroyed Early Palaeozoic oil and gas accumulations sourced from the Cambrian source rocks, but hydrocarbons generated by Middle and Upper Ordovician source rocks during the Mesozoic and Tertiary have been preserved. At the present day, accumulations are characterized by a range of crude oil compositions because source rocks from different source areas with different maturation histories are involved.

U–Pb (LA–ICP-MS) dating of detrital zircons from Cambrian clastic rocks in Avalonia: erosion of a Neoproterozoic arc along the northern Gondwanan margin

Most Neoproterozoic and Early Palaeozoic tectonic syntheses place Avalonia and related peri-Gondwanan terranes facing an open ocean along the northern margin of Gondwana, thereby providing important constraints for palaeocontinental reconstructions during that time interval. However, the precise location of Avalonia along the margin and its position relative to other peri-Gondwanan terranes is controversial. We present laser ablation–inductively coupled plasma mass spectrometry U–Pb data for detrital zircons from Cambrian clastic rocks in two localities in Avalonia: the Antigonish Highlands of Nova Scotia (62 analyses) and the British Midlands (55 analyses). The data from both samples are very similar, and taken together indicate an overwhelming dominance of Neoproterozoic ( c . 580–680 Ma) or Early Cambrian source rocks with minor older Neoproterozoic clusters at c . 710 Ma or of Mesoproterozoic age, three Palaeoproterozoic zircons and one Archaean zircon. The zircons can all be derived from local Avalonian sources. The Neoproterozoic zircons are attributed to erosion of the underlying Avalonian arc. Mesoproterozoic and Palaeoproterozoic zircons of similar ages are also found in Avalonian Neoproterozoic clastic rocks and their presence in the Cambrian clastic rocks could represent recycling of Neoproterozoic strata and do not necessarily imply the presence of Mesoproterozoic or Palaeoproterozoic basement rocks within their respective drainage basins. Comparison with the data from the Neoproterozoic arc-related clastic sequences suggests significant differences between their respective drainage systems. Whereas the Neoproterozoic data require extensive drainage systems, the Cambrian data can be attributed to localized drainage systems. The change in drainage patterns could reflect rifting and isolation of Avalonia from Amazonia between c . 585 and 540 Ma. Alternatively, it might reflect the creation of topographical barriers along the northern Gondwanan margin, in a manner analogous to the Cenozoic rise of the Andes or the creation of the Basin-and-Range topography in the Western USA.

Characteristics of carbonate gas pool and multistage gas pool formation history of Hetianhe gas field, Tarim Basin, Northwest China

Hetianhe is a big carbonate gas field which is found and demonstrated in the period of “Chinese National Ninth 5-Year Plan”. The proved reserve of Hetianhe gas field is over 600×108 m3. Its main producing layers are Carboniferous bioclastic limestone and Ordovician carbonate composed of buried hill. The former is stratified gas pool with water around its side, and the latter is massive gas pool with water in its bottom. The gases in the gas pools belong to dry gases with normal temperature and pressure systems. Based on the correlation of gas and source rock, the gases are mainly generated from Cambrian source rocks. According to the researches on source rock and structure evolution, and the observations on the thin section to reservoir bitumen and the studies on homogenization temperature of fluid inclusions, the gas pool has been identified and divided into three formation periods. The first is Late Caledonian when the oil generated from the Cambrian source rocks and migrated along faults, as a form of liquid facies into Ordovician carbonate reservoir and accumulated there. After that, the crust uplifted, the oil reservoir had been destroyed. The second is Late Hercynian when condensate gases generated from the Cambrian source rocks and migrated into Ordovician reservoir, as a form of liquid facies. Since the fractures had reached P strata, so the trap might have a real poor preservation condition, and the largescale gas pool formation had not happened. The third gas reservoir formation period occurred in Himalaya. The fractures on both sides of Hetianhe gas field developed violently under the forces of compression, and thus the present fault horst formed. The dry gases generated from Cambrian source rocks and migrated upwards as the form of gas facies into Ordovician and Carboniferous reservoirs, and the large gas pool as discovered at present was formed finally.

ABSTRACT: Anoxia vs. Bioproductivity Controls on the Cambrian and Ordovician Marine Source Rocks in Tarim Basin, China

ABSTRACT: Anoxia vs. Bioproductivity Controls on the Cambrian and Ordovician Marine Source Rocks in Tarim Basin, China

Kinetic simulating experiment on the secondary hydrocarbon generation of kerogen

The kinetic parameters of generation have been obtained for different hydrocarbon classes, including methane, C2-C5 gas hydrocarbons, C6-C13 light hydrocarbons and C13+ heavy hydrocarbons, and vitrinite reflectance (R°) by the kinetic simulating experiment of kerogen cracking. Then, combined with the detailed geology of Sichuan Basin, the effective gas-generating intensity of the Lower Cambrian source rock is approximately estimated by applying these parameters.

GEOLOGY AND HYDROCARBON POTENTIAL OF THE SOUTHERN GEORGINA BASIN, AUSTRALIA

The Georgina Basin is an intracratonic basin on the central-northern Australian craton. Its southern portion includes a highly prospective Middle Cambrian petroleum system which remains largely unexplored. A plethora of stratigraphic names plagued previous exploration but the lithostratigraphy has now been rationalised using previously unpublished electric-log correlations and seismic and core data.Neoproterozoic and Lower Palaeozoic sedimentary rocks of the southern portion of the basin cover an area of 100,000 km2 and thicken into two main depocentres, the Toko and Dulcie Synclines. In and between these depocentres, a Middle Cambrian carbonate succession comprising Thorntonia Limestone and Arthur Creek Formation provides a prospective reservoir-source/seal couplet extending over 80,000 km2. The lower Arthur Creek Formation includes world class microbial source rocks recording total organic carbon (TOC) values of up to 16% and hydrocarbon yields up to 50 kg/tonne. This blanket source/seal unconformably overlies sheetlike, platform dolostone of the Thorntonia Limestone which provides the prime target reservoir. Intra- Arthur Creek high-permeability grainstone shoals are important secondary targets.In the Toko Syncline, Middle Cambrian source rocks entered the oil window during the Ordovician, corresponding to major sediment loading at this time. The gas window was reached prior to structuring associated with the Middle Devonian-Early Carboniferous Alice Springs Orogeny, and source rocks today lie in the dry gas window. In contrast, high-temperature basement granites have resulted in overmaturity of the Arthur Creek Formation in the Dulcie Syncline area. On platform areas adjacent to both these depocentres source rocks reached peak oil generation shortly after the Alice Springs Orogeny; numerous structural leads have been identified in these areas. In addition, an important stratigraphic play occurs in the Late Cambrian Arrinthrunga Formation (Hagen Member) on the southwestern margin of the basin. Key elements of the play are the pinchout of porous oil-stained, vuggy dolostone onto basement where top seal is provided by massive anhydrite while underlying Arthur Creek Formation shale provides a potential source.

Paleozoic oil–source rock correlations in the Tarim basin, NW China

We studied a suite of 40 oils and extracts of purported source rocks from the Tarim basin in NW China. The main group of oils comes from Tazhong and Tabei wells, which sample the largest known petroleum accumulations in the basin. These oils can be statistically correlated with extracts of Ordovician rocks based upon high relative concentrations of 24-isopropylcholestanes and low relative concentrations of dinosteranes, triaromatic dinosteroids, and 24-norcholestanes. In contrast, extracts from Cambrian rocks have low relative concentrations of 24-isopropylcholestanes with high relative concentrations of dinosteranes, triaromatic dinosteroids, and 24-norcholestanes. Although some Tarim basin Cambrian rocks yield high total organic carbon contents, we see little evidence in the analyzed oil samples to suggest that they came from Cambrian source rocks.

RESERVOIR AND SOURCE‐ROCK CHARACTERISATION OF THE EARLY PALAEOZOIC INTERVAL IN THE PERIBALTIC SYNECLISE, NORTHERN POLAND

Detailed investigations have been conducted on samples from 2,750m of conventional cores from 18 wells penetrating the Cambrian siliciclastics in northern Poland. The results of sedimentological, petrological and geochemical analyses were combined with a computeraided regional evaluation of the Polish onshore sector of the Peribaltic Syneclise. Our results may help in the successful future identification of Cambrian prospects in northern Poland.The Middle Cambrian reservoir sandstones consist of quartzites in which low porosities (5% ‐ 8%) and permeabilities (5 to 24 mD) were preserved only in oil‐bearing structures in the more deeply‐buried, western part of the Peribaltic Syneclise. Isotopic studies suggest crystallisation temperatures for the pore‐plugging quartz cement of between 53d̀C and 78 d̀C. These temperatures were not reached in the shallower, eastern part of the basin, where porosities of up to 20% are present in the quartz arenites which constitute potential reservoir units.A 150‐m thick, organic‐lean (0.1‐l.0 wt. % TOC) Middle Cambrian shale below the quartzites, and an up to 20‐m thick, organic‐rich (4.5–10 wt. % TOC) Late Cambrian shale unit above the quartzites, are regarded as source rocks for the oil accumulations in the Cambrian reservoirs. The organic matter in these two shale units consists of abundant grey, lenticular particles and finely‐dispersed bituminite‐like constituents. The reflectance intensity of these bitumen particles is a useful parameter for evaluating the source rocks' maturity. Geochemical investigations have proved the (potential) source rocks to be immature in the shallower, eastern part of the Peribaltic Syneclise, and to have reached the “oil window ” in the more deeply‐buried western part of the basin.The extractable organic matter is dominated by saturated hydrocarbons. Late Cambrian extracts can be differentiated from Middle Cambrian samples by their higher content of aromatic compounds. Reservoired Cambrian oils and extracts from Cambrian source rocks could not be distinguished by triterpane “fingerprints ”. Both are characterised by a well‐developed sequence of tri‐ and pentacyclic compounds, with no variation in their relative abundances.Burial‐history modelling indicates that rapid subsidence of the Cambrian deposits to depths of more than 2,500m occurred during the Silurian in the western part of the basin. In the eastern part, however, a much more moderate burial history is inferred. Here, the Cambrian interval lies at depths of only 1,500 to 2,200m. An analysis of the basin's geothermal history indicates that porosity‐plugging quartz cementation in the Cambrian quartzites commenced in the western Peribaltic Syneclise during this rapid Silurian burial. In this western region, the source rocks reached the “oil window” during the Devonian. Hence, migration and accumulation of the generated hydrocarbons could preserve only the remaining pore space, which had already been drastically reduced. This genetic model implies that petroleum traps were formed before or during the Carboniferous.Because the thick Silurian marlstones acted as an efficient regional seal, the generated hydrocarbons must have been trapped somewhere in the underlying Early Palaeozoic sequence. Oil stains in Cambrian quartz arenites in the organic‐geochemically immature eastern part of the basin point to long‐distance, up‐dip migration towards the basin's eastern margin. A scarcity of structural traps and reduced shalyness of the eastwards‐coarsening, Early Palaeozoic sequence are adverse features, relative to a high degree of preservation of the hydrocarbons generated. The search for subtle diagenetic traps, however, may prove to be challenging.