Lacustrine Source Rocks (lacustrine + source_rock)

Distribution by Scientific Domains


Selected Abstracts


HYDROCARBON POTENTIAL OF JURASSIC SOURCE ROCKS IN THE JUNGGAR BASIN, NW CHINA

JOURNAL OF PETROLEUM GEOLOGY, Issue 3 2003
A. N. Ding
Jurassic source rocks in the Junggar Basin (NW China) include coal swamp and freshwater lacustrine deposits. Hydrocarbon-generating macerals in the coal swamp deposits are dominated by desmocollinite and exinite of higher-plant origin. In lacustrine facies, macerals consists of bacterially-altered amorphinite, algal- amorphinite, alginite, exinite and vitrinite. Coals and coaly mudstones in the Lower Jurassic Badaowan Formation generate oil at the Qigu oilfield on the southern margin of the basin. Lacustrine source rocks generate oil at the Cainan oilfield in the centre of the basin. The vitrinite reflectance (Ro) of coal swamp deposits ranges from 0.5% to 0.9%, and that of lacustrine source rocks from 0.4% to 1.2%. Biomarker compositions likewise indicate that thermal maturities are variable. These variations cause those with lighter compositions to have matured earlier. Our data indicate that oil and gas generation has occurred at different stages of source-rock maturation, an "early" stage and a "mature" stage. Ro values are 0.4%,0.7% in the former and 0.8%,1.2% in the latter. [source]


Overpressure and petroleum generation and accumulation in the Dongying Depression of the Bohaiwan Basin, China

GEOFLUIDS (ELECTRONIC), Issue 4 2001
X. Xie
Abstract The occurrence of abnormally high formation pressures in the Dongying Depression of the Bohaiwan Basin, a prolific oil-producing province in China, is controlled by rapid sedimentation and the distribution of centres of active petroleum generation. Abnormally high pressures, demonstrated by drill stem test (DST) and well log data, occur in the third and fourth members (Es3 and Es4) of the Eocene Shahejie Formation. Pressure gradients in these members commonly fall in the range 0.012,0.016 MPa m,1, although gradients as high as 0.018 MPa m,1 have been encountered. The zone of strongest overpressuring coincides with the areas in the central basin where the principal lacustrine source rocks, which comprise types I and II kerogen and have a high organic carbon content (>2%, ranging to 7.3%), are actively generating petroleum at the present day. The magnitude of overpressuring is related not only to the burial depth of the source rocks, but to the types of kerogen they contain. In the central basin, the pressure gradient within submember Es32, which contains predominantly type II kerogen, falls in the range 0.013,0.014 MPa m,1. Larger gradients of 0.014,0.016 MPa m,1 occur in submember Es33 and member Es4, which contain mixed type I and II kerogen. Numerical modelling indicates that, although overpressures are influenced by hydrocarbon generation, the primary control on overpressure in the basin comes from the effects of sediment compaction disequilibrium. A large number of oil pools have been discovered in the domes and faulted anticlines of the normally pressured strata overlying the overpressured sediments; the results of this study suggest that isolated sandstone reservoirs within the overpressured zone itself offer significant hydrocarbon potential. [source]


OILS FROM CENOZOIC RIFT-BASINS IN CENTRAL AND NORTHERN THAILAND: SOURCE AND THERMAL MATURITY

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2007
H.I. Petersen
Oil is produced from the Suphan Buri, Phitsanulok and Fang Basins onshore central and northern Thailand. Most of the Cenozoic rift-basins onshore Thailand are 2,4 km deep, but the Phitsanulok Basin is the deepest with a basin-fill up to 8 km thick. In this basin, the Sirikit field produces ,18,000,24,000 bbl/day of crude oil. In the Suphan Buri Basin, about 400 bbl/day of crude oil is produced from the U Thong and Sang Kajai fields. Approximately 800 bbl/day of crude oil is produced from the Fang field (Fang Basin), which in reality consists of a number of minor structures including Ban Thi, Pong Nok, San Sai, Nong Yao and Mae Soon. A total of eight oil samples were collected from these structures and from the Sirikit, U Thong and Sang Kajai fields. The oils were subjected to MPLC and HPLC separation and were analysed by gas chromatography (GC) and gas chromatography-mass spectrometry (GC-MS and GC-MS-MS). The U Thong oil was investigated in more detail by separating the oil into a number of fractions suited for the analysis of various specific compounds. The Sirikit oil appears to be the most mature, whereas the Suphan Buri oils and the oil from the San Sai structure (Fang Basin) are the least mature. Apart from the San Sai oil, the other oils in the Fang Basin are of similar maturity. The oils contain small amounts of asphaltenes and the asphaltene-free fractions are completely dominated by saturated hydrocarbons (generally >60%). Long-chain n-alkanes extend to at least C40 and the oils are thus highly waxy. In general the oils were generated from freshwater lacustrine source rocks containing a large proportion of algal material, as indicated by the presence of long-chain n-alkanes, low C3122R/C30 hopane ratios, the presence of 28-Nor-spergulane, T26/T25 (tricyclic triterpanes) ratios of 1.07,1.57 and tetracyclic polyprenoid (TTP) ratios close to 1. Occasional saline conditions may have occurred during deposition of the Sirikit, Ban Thi and Pong Nok source rocks. The Fang Basin oils were sourced from two different kitchens, one feeding the Ban Thi and Pong Nok structures and one feeding the Mae Soon, Nong Yao and San Sai structures. The presence ofcadalene, tetracyclic C24 compounds, oleanane, lupane, bicadinane and trace amounts ofnorpimarane or norisopimarane indicate a contribution from higher land plant organic matter to the oils. The terrestrial organic matter may occur disseminated in the lacustrine facies or concentrated in coal seams associated with the lacustrine mudstones. Thermally immature oil shales (lacustrine mudstones) and coals exposed in numerous basins in central and northern Thailand could upon maturation generate oils with a composition comparable to the investigated oils. [source]


HYDROCARBON POTENTIAL OF JURASSIC SOURCE ROCKS IN THE JUNGGAR BASIN, NW CHINA

JOURNAL OF PETROLEUM GEOLOGY, Issue 3 2003
A. N. Ding
Jurassic source rocks in the Junggar Basin (NW China) include coal swamp and freshwater lacustrine deposits. Hydrocarbon-generating macerals in the coal swamp deposits are dominated by desmocollinite and exinite of higher-plant origin. In lacustrine facies, macerals consists of bacterially-altered amorphinite, algal- amorphinite, alginite, exinite and vitrinite. Coals and coaly mudstones in the Lower Jurassic Badaowan Formation generate oil at the Qigu oilfield on the southern margin of the basin. Lacustrine source rocks generate oil at the Cainan oilfield in the centre of the basin. The vitrinite reflectance (Ro) of coal swamp deposits ranges from 0.5% to 0.9%, and that of lacustrine source rocks from 0.4% to 1.2%. Biomarker compositions likewise indicate that thermal maturities are variable. These variations cause those with lighter compositions to have matured earlier. Our data indicate that oil and gas generation has occurred at different stages of source-rock maturation, an "early" stage and a "mature" stage. Ro values are 0.4%,0.7% in the former and 0.8%,1.2% in the latter. [source]


Oil and Gas Accumulation in the Foreland Basins, Central and Western China

ACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 2 2010
Yan SONG
Abstract: Foreland basin represents one of the most important hydrocarbon habitats in central and western China. To distinguish these foreland basins regionally, and according to the need of petroleum exploration and favorable exploration areas, the foreland basins in central and western China can be divided into three structural types: superimposed, retrogressive and reformative foreland basin (or thrust belt), each with distinctive petroleum system characteristics in their petroleum system components (such as the source rock, reservoir rock, caprock, time of oil and gas accumulation, the remolding of oil/gas reservoir after accumulation, and the favorable exploration area, etc.). The superimposed type foreland basins, as exemplified by the Kuqa Depression of the Tarim Basin, characterized by two stages of early and late foreland basin development, typically contain at least two hydrocarbon source beds, one deposited in the early foreland development and another in the later fault-trough lake stage. Hydrocarbon accumulations in this type of foreland basin often occur in multiple stages of the basin development, though most of the highly productive pools were formed during the late stage of hydrocarbon migration and entrapment (Himalayan period). This is in sharp contrast to the retrogressive foreland basins (only developing foreland basin during the Permian to Triassic) such as the western Sichuan Basin, where prolific hydrocarbon source rocks are associated with sediments deposited during the early stages of the foreland basin development. As a result, hydrocarbon accumulations in retrogressive foreland basins occur mainly in the early stage of basin evolution. The reformative foreland basins (only developing foreland basin during the Himalayan period) such as the northern Qaidam Basin, in contrast, contain organic-rich, lacustrine source rocks deposited only in fault-trough lake basins occurring prior to the reformative foreland development during the late Cenozoic, with hydrocarbon accumulations taking place relatively late (Himalayan period). Therefore, the ultimate hydrocarbon potentials in the three types of foreland basins are largely determined by the extent of spatial and temporal matching among the thrust belts, hydrocarbon source kitchens, and regional and local caprocks. [source]


Geochemical Characteristics and Origin of Natural Gases in the Qaidam Basin, China

ACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 1 2003
ZHANG Xiaobao
Abstract, Sixty-five natural gas samples were collected from 19 oil-gasfields in the Qaidam basin, China. The chemical composition and carbon isotope values of the samples were measured, and the geochemical characteristics and origin of the natural gases were studied. The gases can be divided into biogenic gases, sapropelic oil-type gases, mixed type oil-type gases, coal-type gases and mixed gas. The ,13C1 values of the biogenic gases are very small and the C2+ contents of them are very low, ranging from ,68.2 to ,61.8 and 0.06% to 0.20% respectively. They have heavy ,D and ,13Cco2. showing a CO2 reduction pathway. They are distributed in the East depression region and derived from the Quaternary source rocks. The sapropelic oil-type gases have small ,13C2 values and high C2+ ranging from ,36.6 to ,28.6 and from 33.01% to 47.15% respectively. The mixed type oil-type gases have ,13C2 values and C2+ contents varying from ,28.6 to ,24.8 and from 4.81% to 26.06% respectively. Both sapropelic oil-type gases and mixed type oil-type gases are associated with oil-type oils, distributed in the West depression region and derived from the Tertiary saltwater lacustrine sapropelic source rocks and humic source rocks respectively. The ,13C2 values of the coal-type gases are extremely high and the C2+ contents are very low, changing from ,23.3 to ,12.5 and from 0.06% to 18.07% respectively. The coal-type gases in the Nanbaxian gasfield and the Lenghu oil-gasfields in the North fault block belt are derived from the Middle Jurassic coal-measures source rocks, whereas those in the West depression region are derived from the Tertiary saltwater lacustrine humic source rocks. Compared with some other basins in China, the natural gases there have obviously heavier ,13C due to the heavier ,13C of different types of kerogens of the Tertiary saltwater lacustrine source rocks in the West depression region of the basin. The mixing of natural gases is common in the West depression region, but the mixed gases are formed by sapropelic oil-type gases, mixed type oil-type gases or coal-type gases, respectively, of different levels of maturity. Most of the sapropelic oil-type gases and mixed type oil-type gases in the west part are thermally immature and low-mature, but the coal-type gases in the West depression region and the North fault block belt are mature and high- to over-mature. [source]