Distribution Of Source Rocks Research Articles

Characteristics of tight oil in Triassic Yanchang Formation, Ordos Basin

Abstract By comprehensive study of reservoir and source rock distribution, petrology and geochemistry, the tight oil and its exploration potential was analyzed in the Triassic Yanchang Formation, Ordos Basin. The Triassic Yanchang Formation is rich in low permeability reservoirs. The proved geological reserves of tight oil, with the permeability less than 2×10 −3 μm 2 , is about two billion tons by now. The tight oil mainly occurs in tight sandstone reservoirs of Chang6-Chang8 oil-bearing members which are close to or interbedded with the oil shale layers, without long-distance migration. The large-scale gravity flow sandstone reservoirs of Chang7 and Chang6 oil-bearing members in the center of the lacustrine basin are particularly tight, with the permeability less than 0.3×10 −3 μm 2 in general. The tight oil in the Yanchang Formation features large scale in sand body complex, tight reservoir, complicated pore throat structure, high content of rigid components, abundant fractures and saturation, good crude property, low fluid pressure and low oil yield. The formation of large-scale superimposed tight oil reservoirs is controlled by the interbeded lithologic combination of extensive source rocks and reservoirs and the strong hydrocarbon generation and expulsion during geological history. This type of pools is an important potential resource for future oil exploration and development.

Morphological, drainage and eolian controls on the microtidal Patara Beach sediments (eastern Mediterranean): Textural, geochemical and mineralogical investigations

The effects of dominant hydrodynamic, morphological, fluvial and hinterland geological source conditions on the texture and composition of the microtidal and dissipative Patara Beach (Mediterranean coast of SW Turkey) sediments were investigated at 47 locations. Patara Beach sediments are composed entirely of sand. Fine sand (5–94%) was more abundant in the northwestern section, while medium sand contents (2–94%) increased in the central and southeastern sections. Moderately-to well sorted (mostly 0.3–0.7 Ø) sediments tend to show overall better sorting towards the southeast, in the net longshore current direction. Terrigenous carbonate grains derived from the hinterland constituted 6–50% (as CaCO3) with varying tendencies to increase or decrease within sections alongshore. Total heavy mineral concentrations in bulk sediments (1–17%, mostly <5%) were highest in localities of offshore sandy spit formation and with intense aeolian processes. The heavy mineral concentration comprises magnetite, hematite, amphiboles, pyroxene, epidote, garnet, and chromite, a mineral assemblage reflecting mafic/ultramafic/ophiolitic and metamorphic sources and mineral deposits. The concentrations of major elements (Si, Al, Ca, K, Na, P, Fe, Ti) and others (Co, Ba) are comparable with the average composition of Earth's crust rocks, and variations can be related to the varying texture and lithologies of the sediments. Higher abundances of Mg (3.3–7.7%), Cr (0.2–6.7%) and Ni (195–588 ppm) must be contributed by particular ophiolite sources. Mn (3385–4585 ppm) indicates presently-mined mineral deposits on the coast. Wind, wave, current and fluvial drainage regimes and corresponding morphological changes together with distribution of geological source rocks have great influences on the texture and composition of Patara Beach sediments.

Distribution of subsurface fluid-flow systems in the SW Barents Sea

The SW Barents Sea is a large hydrocarbon-prone epi-continental Sea of the Norwegian Arctic region. A significant portion of the hydrocarbon gases generated in deep source rocks has leaked or migrated into the shallow subsurface and is now trapped in gas hydrate and shallow gas reservoirs. The evolution of sedimentary basins of this region has controlled the leakage of these fluids through marine sediments. Understanding the distribution of various fluid-flow systems may enhance our knowledge of the evolution of different basins in the SW Barents Sea and could help find potential targets for future hydrocarbon exploration. We analyze approximately 3000 2D multi-channel seismic profiles and data from 60 wells covering the entire SW Barents Sea, to identify and classify fluid-flow features, and study their relationship to tectonic elements and geological history. Gas chimneys are the most abundant feature among various other fluid-flow features such as fluid leakage along faults and fractures, seepage pipes, and high amplitude anomalies potentially indicating trapped fluids. Large fluid-flow features, covering areas as large as 600 km2, occur close to known hydrocarbon fields such as Snøhvit, Skrugard, and Havis. The fluid-flow features occur above major deep-seated faults in the area suggesting a close relation to it. The number of fluid-flow features in the western part of the study area is significantly higher than in the eastern part. The amount of net erosion in the study area shows no direct control over the distribution of fluid-flow features, suggesting that the faults and distribution of mature source rocks control the fluid flow. The strong correlation between the locations of fluid-flow features and structural elements indicates that extensional tectonics, uplift and glaciations could have played major roles in the timing and activity of the fluid leakage, although erosion might have had an added effect.

Marine black shale deposition and Hadley Cell dynamics: A conceptual framework for the Cretaceous Atlantic Ocean

Understanding the controls that determine the spatial distribution and internal heterogeneities of black shales in the Mesozoic ocean has been a focal point of research over many decades. The consensus is that atmosphere–land–ocean interactions influenced variations in marine biogeochemistry and sediment supply, thus exerting fundamental controls on the richness and quality of sedimentary organic matter (OM) and ultimately on petroleum source rock distribution and its generation potential. Internal, small-scale heterogeneities in black shales that have been reported from all ocean settings were often linked to orbitally-driven fluctuations in continental runoff and marine upwelling. The two processes are generically related under the ascending (tropical) and descending (subtropical) limbs of the palaeo-Hadley Cells, with fluctuations at variable time (seasonal, orbital, geological) and spatial (shelf, margin, deep basin) scales. These dynamic variations translate into characteristic patterns of OM quantity and quality, best preserved near the continents where the forcing effects are strongest. The expression of these orbital-scale interactions are not well constrained at the basin scale, however, they may hold a key to better understand the distribution of heterogeneities in black shales. This study presents a conceptual framework that links OM quality and quantity in Cretaceous Atlantic sediments with the dominant processes that operated under the Hadley Cells. Using a comprehensive compilation of bulk organic geochemical data – total organic carbon concentration (TOC), hydrogen index (HI), oxygen index (OI), and kerogen type – we explore how basic geochemical patterns can be used to identify the underlying generic processes. We utilise published and new data from deep ocean sites of the DSDP/ODP program, as well as one palaeo-shelf setting (Tarfaya), spanning a latitudinal transect from the outer subtropics to the palaeo-equator during the Albian, the Cenomanian–Turonian, and the Coniacian–Santonian. This study emphasises the potential of integrating orbital scale datasets and wide spatial coverage as a predictive tool for black shale formation across ocean basins.

Formation conditions and exploration potential of tight oil in the Permian saline lacustrine dolomitic rock, Junggar Basin, NW China

Abstract The features and exploration potential of the Permian tight oil in the Junggar Basin were analyzed and evaluated using outcrop, core and geochemical data etc. The Junggar Basin in the Early-Mid Permian is a saline lacustrine basin after the residual sea is closed, a set of hybrid sedimentation of deep-lake dark mudstone and dolomitic rock is developed, and the high-quality mudstone source rocks and the dolomite mudstone are alternated. High quality source rocks in mature stage are next to tight dolomitic rock reservoirs closely and provide good conditions for tight oil accumulation of proximal source type. Tight oil reservoirs are mainly distributed in the centre and slope region of the lake basin, and two types sweetspots of “dissolved pore” and “fracture-pore” exist locally. The enrichment of tight oil is controlled by the distribution of effective source rocks and dolomitic rocks, and the tight oil occurs in the entire strata vertically and spreads across large continuous areas horizontally. The Junggar Basin has four Permian tight oil distribution areas, Fencheng Formation in the Mahu sag, Lucaogou Formation in the Jimusaer sag, Pidiquan Formation in the Shazhang-Shishugou sag, and Lucaogou Formation in the Bogeda piedmont. A number of wells obtained oil flow in these areas, suggesting great resource potential and favorable targets for future exploration.

Identification and distribution of marine hydrocarbon source rocks in the Ordovician and Cambrian of the Tarim Basin

Abstract A process for identifying marine hydrocarbon source rocks is established based on outcrop measurement, ground-penetrating radar survey, core analysis, logging evaluation, seismic interpretation, etc. It is used to identify the Cambrian and Ordovician marine hydrocarbon source rocks and to predict their spatial distribution in the Tarim Basin. Four suites of marine hydrocarbon source rocks are identified in the Tarim Basin, and they are distributed, respectively, in the Lower-Middle Cambrian of the Awati and Manjiaer sags, the Heituao Formation of the Lower-Middle Ordovician in the Tadong region, the Saergan-Tumuxiuke-Queerqueke formations of the Middle-Upper Ordovician from the Awati Sag to the Manjiaer Sag, and the Yin'gan and Lianglitage formations of the Upper Ordovician from the Awati Sag to the Tazhong area. The development of these source rocks was controlled by the sea level rise and they are characterized by different facies in the same stage, namely, different source rocks are deposited in sedimentary facies zones at the same stage. The formation of the source rocks shifted with the carbonate basin and was interrupted when there are large quantities of siliciclastic influx.

Oil families and their inferred source rocks in the Barents Sea and northern Timan-Pechora Basin, Russia

A geochemical study of 34 oil samples was conducted to understand the types and distributions of effective source rocks and evaluate the geographic extent of the petroleum systems in the Barents Sea and northern Timan-Pechora Basin. Taxon-specific, age-related, and source-related biological markers (biomarkers) and isotope data provided information on the depositional environment of the source rock, source input, and source age of the oil samples. A relationship between biomarker and diamondoid concentration was used to identify mixed oils having both oil window and highly cracked components. Compound-specific isotope analyses of diamondoids and n-alkanes were used to deconvolute cosourced oils and identify deep source rocks in the basin. Results suggest five major source rocks in the Barents Sea and the northern Timan-Pechora Basin: Upper Jurassic shale, Lower–Middle Jurassic shale, Triassic carbonate and shale, Devonian marl, and Devonian carbonate. The Upper and Lower–Middle Jurassic source rocks are dominant in the Barents Sea. Triassic source rock consists of carbonate in the onshore part of northern Timan-Pechora Basin and marine shale in the Barents Sea. The Devonian Domanik Formation carbonate source rock extends offshore into the southern Barents Sea. The high-maturity Domanik Formation could also be a secondary source rock for most of the mixed oils in the northern Timan-Pechora Basin. This detailed geochemical study provides a new and detailed understanding of petroleum systems in the Barents Sea and northern Timan-Pechora Basin.

Sedimentary association of alternated mudstones and tight sandstones in China’s oil and gas bearing basins and its natural gas accumulation

Oil and gas resources are abundant in China’s continental sedimentary basins, where the main task of exploration has been finding oil for many years. In recent years, however, new discoveries of large-scale natural gas have been successively obtained. The natural gas mainly exists in the sedimentary association of alternated mudstones and tight sandstones and is dominantly low-permeability tight sand gas. Through the in-depth study on gas reservoir analysis, diagenetic evolution, source rock distribution and hydrocarbon-generating behavior, natural gas generation and accumulation, it is concluded that, during the major subsiding stage of large scale lake basins, the multicyclic subsiding process of the lake surface controls the development of high quality source rocks, the wide distribution of sands, and the superimposition of the two types of rocks in the vertical direction. The lacustrine muddy source rocks are developed, including mud shale, carbonaceous mudstone and coal bed which are in the medium–high evolution stage and produce mainly gas and the gas generation intensity is high. Through the analysis of the subsidence evolution processes of the Carboniferous–Permian Systems (transitional marine–continental facies) in the Ordos Basin and the Triassic Xujiahe Formation (continental facies) in the Sichuan Basin, it is concluded that the widely distributed sandbodies of delta facies, although with tight properties, are interbedded with source rocks and easy to accumulate natural gases. The natural gas is migrated and accumulated within small distance, and is characterized by large-area accumulation. Because of the strong hydrocarbon generation capacity, big thickness and stable distribution of the underlying mud shale, the potential of gas resources should not be underestimated. The geocyclicity of China’s continental sedimentary basins controls the sedimentary association of alternated mudstones and tight sandstones, resulting in superimposed accumulations of shale gas and tight sand gas.

Identification of the lower limit of high-quality source rocks and its relation to hydrocarbon accumulation—Taking the Beier Sag in the Hailaer Basin as an example

The theory of “source rock control” has evolved from source-rock-control hydrocarbon accumulation, to effective source-rock-control hydrocarbon accumulation, and to high-quality source-rock-control hydrocarbon accumulation. However, there are problems, such as whether high-quality source rocks exist or not? What high-quality source rocks are, and how to identify them, are yet to be agreed upon. Aimed at this issue of concern to explorationists, and taking the Beier Sag in the Hailaer Basin as an example, this paper defines the high-quality source rocks and the lower limit for evaluation of high-quality source rocks, by using the inflection point on the relationship curve of hydrocarbon (oil) expulsion, which is calculated by the material balance principle, versus total organic carbon (TOC). The results show that when TOC is low, all source rocks have limited hydrocarbon expulsion and slow growth rate, thus they cannot be high-quality source rocks. However, when TOC rises to some threshold, hydrocarbon expulsion increases significantly with TOC. This inflection point should be the lower limit of high-quality source rocks: those with TOC greater than the inflection-point value are high-quality source rocks. In addition, the lower limit of high-quality source rocks is also related to the type and maturity of organic matters in the source rocks, as well as the mineral components of the source rocks affecting the residual hydrocarbons. Theoretically, the lower limit of high-quality source rocks depends on geological conditions rather than being a constant value. However, for the sake of simplicity and practicability, in this paper TOC=2.0% is regarded as the lower limit of high-quality source rocks. The examination of such standard in the work area indicates that the high-quality source rocks in members K1n2 and K1n1 of the Nantun formation contribute 76% and 82% to oil generation, and 96% and 91% to oil expulsion, respectively. The distribution of high-quality source rocks is also closely related to the distribution of hydrocarbon reservoirs in the region, demonstrating that high-quality source rocks control hydrocarbon accumulation.

ITCZ controls on Late Cretaceous black shale sedimentation in the tropical Atlantic Ocean

This study presents high resolution organic and inorganic proxy records for Coniacian to Santonian black shale on the Demerara Rise (ODP Site 1261) in the western tropical Atlantic off South America. We integrate these records with approximately time equivalent geochemical data from the eastern tropical Atlantic off tropical Africa (ODP Site 959) to extract the underlying relationships of Intertropical Convergence Zone (ITCZ) dynamics and black shale formation in the tropical Cretaceous Atlantic at orbital time scales. The geochemical records from the Demerara Rise show repetitive fluctuations in productivity, ocean redox conditions, and clastic sediment supply consistent with a dynamic paleo‐upwelling regime off tropical South America. Upwelling intensity most likely was driven by shifts of the mean annual position of the ITCZ, which connects the large‐scale precipitation and wind field patterns of the Hadley cells. Upwelling was strongest off South America and burial of oil‐prone organic matter most pronounced when the ITCZ was in its southernmost position, which maximized the impact of NE trade winds on the inner, tropical part of the northern Hadley cell. Geochemical records from the Deep Ivorian Basin (equatorial Atlantic) suggest that source rock formation occurred in phase with regions north of the equator. Off tropical Africa, however, black shale formation was primarily driven by regional rainfall and nutrient export. The results of this study provide a conceptual framework that explains the formation, distribution and quality of petroleum source rocks below the tropical component of the Hadley cells on orbital time scales.

Hydrocarbon formation and accumulation of the deep Paleogene of the Jiyang Depression, Shengli Oilfield

Abstract Using geochemistry, sedimentary and petroleum geology methods, and based on the analysis of spatial distribution of deep source rocks and sedimentary organic facies, the favorable exploration prospects in the Jiyang Depression, Shengli Oilfield are studieded. There are 4 types of sedimentary organic facies (including anoxic organic facies, anaerobic organic facies, dysaerobic organic facies and aerobic organic facies) in deep source rocks of Kongdian Formation - Sha-4 Member, Paleogene. The source rocks of Anoxic facies and anaerobic facies are discovered in the Sha-4 Member and are proved as excellent source rocks, while the Kongdian Formation source rocks compose mainly of the dysaerobic facies and aerobic facies and served as common source rocks. The whole hydrocarbon expulsion process is divided into 3 stages, including free water expulsion, hydrocarbon generation and energy accumulation, and hydrocarbon expulsion from microfractures. The hydrocarbon expulsion from deep source rocks mainly occurs in the stage of hydrocarbon expulsion from microfractures, during which there are three oil and gas migration modes with different geologic conditions, including vertical migration, lateral migration and downward migration. The studies indicated that the hydrocarbons in shallow and medium formations from the Sha-4 Member excellent source rocks of anoxic and anaerobic facies are mainly accumulated through vertical migration along the faults, while the reservoirs formed by lateral migration and downward migration are still waiting to be revealed. So there is great exporation potential for the deep Paleogene of the Jiyang Depression.

Tectonic and stratigraphic evolution of the Cambrian basin of northern Northwest Territories

Abstract The Cambrian basin of the mainland Northwest Territories has been of considerable economic interest since gas was first discovered in Mount Clark Formation sandstones in 1974. A recently completed assessment by the Geological Survey of Canada has estimated that the Cambrian Clastics play contains almost a billion barrels of oil and 10.7 TCF of gas. The play’s reservoirs, seals and source rocks are all of Cambrian age, making the understanding of the basin’s evolution and contents critical to any exploration effort. The basin is a semi-enclosed, epicontinental marine basin, bordered by positive elements and open to a subsiding continental shelf and margin, and represents the eastern portion of a much larger deposystem that developed after the breakup of Laurentia. A multi-disciplinary study of a large regional reflection seismic grid, supported by borehole and potential field data, shows the basin to have evolved in three stages: 1) Early Cambrian pre-rift regional subsidence of the area lying inland of the Mahony and Bulmer arches, and a newly identified high that pre-dated the Mackenzie Trough. It was during this period that the Mount Clark Formation was deposited; 2) A middle Cambrian rift phase during which a graben system, about 50 km wide and over 400 km long, developed in the basin’s core. The grabens are deepest in south Mackenzie Trough where rifting began, and are progressively shallower and younger to the north and northeast. Mount Cap was deposited during this phase and it is expected that the grabens received finer-grained clastics than did the shallower areas on their flanks; 3) A post-rift subsidence phase that began with deposition of the Saline River Formation during the Late Cambrian and continued, with interruptions, until the middle of the Devonian. Throughout Cambrian time, sediment onlapped the basin’s flanks and its internal arches, each layer advancing further than its predecessor. It was not until the latest Cambrian that the internal arches were completely covered by beds of the lower Franklin Mountain Formation. A previously undocumented Cambrian age graben (herein named McConnell Graben) lies in the hanging wall of the unnamed Laramide thrust fault that emerges from the east flank of the McConnell Range. The fault began as a Cambrian normal fault that separated the Bulmer and Mahony arches on the east from McConnell Graben on the west. The present day ‘St. Charles’ range developed in a similar manner. A preliminary exploration risk analysis, based on the predicted distribution of reservoir, seal and source rocks, reveals two attractive areas for exploration. The larger one, centred on Lac des Bois, is about 150 km wide and extends on a NW-SE trend for about 300 km across the Aubry and Good Hope depocentres. The smaller area (less than 50 × 100 km in extent) lies within Mackenzie Plain depocentre.

Petroleum system of the Fula depression at the Muglad basin in the Central African fault zone

Petroleum system theory has been used to study characteristics of the Fula depression in the Central African fault zone. In this system, deep lacustrine facies mudstone in the Abu Gabra Formation of the Lower Cretaceous is a very good source rock, thick deltaic facies sandstone of the Abu Gabra Formation and fluvial facies sandstone of the Bentiu Formation are good reservoir beds, and the mudstone in the Upper Cretaceous Darfur Group is the regional cap rock. The oil search mode and fault block trap seal-off conditions are considered here for passive rift basins. Particularly with respect to oil source rock distribution, successive development of reverse fault block and faulted anticlinal traps on low relief structures could have accumulated hydrocarbons because of lateral sealing by downthrown mudstone along the up-dipping reservoir beds. At present, discoveries in this system are all large-duty oil fields. In 2009, proved reserves exceeded 2×108 t, and about 3×106 t annual throughput of crude oil was obtained. Risk exploration of the Fula depression is of short cycle and high benefit, which will be of great help for exploration in the Muglad basin.

Lacustrine source rock deposition in response to co-evolution of environments and organisms controlled by tectonic subsidence and climate, Bohai Bay Basin, China

Three Paleogene syn-rift intervals from the Bohai Bay Basin, the most petroliferous basin in China, were analyzed with sedimentological and geochemical techniques to characterize the lateral source rock heterogeneities, to reveal the environmental and ecological changes through geologic time and to construct depositional models for lacustrine source rocks under different tectonic and climatic conditions. The third (Es 3) and first (Es 1) members of the Eocene Shahejie Formation and the Oligocene Dongying Formation (Ed) display widely variable total organic carbon contents, hydrogen indices and visual kerogen compositions, suggesting changes in organic facies from deep to marginal sediments. Carefully selected deep-lake facies samples from any interval, however, display fairly uniform biomarker composition. These three intervals have distinctly different biomarker assemblages, which indicate weakly alkaline, freshwater lakes with a moderately deep thermocline during Es 3 deposition, alkaline-saline lakes with shallow chemocline during Es 1 deposition and acidic, freshwater lakes with deep, unstable thermocline during the deposition of the Dongying Formation. Such environmental changes corresponded to changes in subsidence rate and paleoclimate, from rapid subsidence and wet climate during Es 3 deposition, through slow subsidence and arid climate during Es 1 deposition to rapid subsidence and wet climate during Ed deposition and resulted in synchronous changes in terrigenous organic matter input, phytoplankton community and primary productivity. The co-evolution of environments and organisms controlled by tectonic subsidence and climate accounted for the deposition and distribution of high quality lacustrine source rocks with distinctly different geochemical characteristics. Most rift basins experienced changes in subsidence rates and possibly changes in climates during their syn-rift evolutions. The models constructed in this paper may have important implications for source rock prediction in other lacustrine rift basins.

Chapter 10 Tectonostratigraphy of the greater Barents Sea: implications for petroleum systems

Abstract Palaeogeographic and tectono-stratigraphic considerations in the greater Barents Sea show that the distribution of reservoirs and hydrocarbon source rocks from the Late Palaeozoic to the Palaeogene can be related to three tectonic phases. Firstly, the Palaeozoic Caledonain Orogeny caused uplift to the west, followed by eastward sediment distribution across the shelf, towards carbonate platforms to the east. Secondly the Late Palaeozoic–Mesozoic Uralide Orogeny induced uplift to the east, causing widespread clastic deposition and reversal of the sediment distribution pattern. Thirdly, major Late Mesozoic–Cenozoic rifting and crustal breakup in the western Barents Sea led to the current basin configuration. Reservoir rocks comprise Late Palaeozoic carbonates and spiculites, Mesozoic terrestrial and marine sandstones and Palaeogene deep-water sandstones. Hydrocarbon source rocks range in age from Silurian to Early Cretaceous, and are grouped into three petroleum systems derived from Late Palaeozoic, Triassic and Late Jurassic source rocks. Multiple tectonic episodes caused formation of a variety of trap types, of which extensional fault blocks and gently folded domes have been the most prospective. Volumetric considerations of generated petroleum indicate that charging is not a limiting factor, except in the western margin.

Palaeozoic source rocks in the Dniepr–Donets Basin, Ukraine

ABSTRACT The Dniepr–Donets Basin (DDB) is a major petroleum province in Eastern Europe. In order to understand the regional and stratigraphic distribution of source rocks for the dominantly gas-prone petroleum system, 676 fine-grained rocks from 30 wells were analysed for bulk parameters (total organic carbon (TOC), carbonate, sulphur, RockEval). A subset of samples was selected for maceral and biomarker analysis, pyrolysis-gas chromatography and kinetic investigations. Organic-rich sediments occur in different intervals within the basin fill. Maximum TOC contents (5.0 ± 1.9%) occur in the Rudov Beds, several tens of metres thick. The oil-prone rocks (Type III–II kerogen) were deposited in basinal settings above an unconformity separating Lower and Upper Visean sections. While maximum TOC contents occur in the Rudov Beds, high TOC contents are observed in the entire Tournaisian and Visean section. However, these rocks are mainly gas condensate-prone. Highly oil-prone black shales with up to 16% TOC and hydrogen index values up to 550 mgHC g –1 TOC occur in Serpukhovian intervals in the northwestern part of the DDB. Oil-prone Lower Serpukhovian and gas condensate-prone Middle Carboniferous coal is widespread in the southern and southeastern part of the basin. Although no source rocks with a Devonian age were detected, their presence cannot be excluded.

Carboniferous source rocks in the Ludong-Wucaiwan area, Junggar Basin, NW China

Abstract Natural gas in the Ludong-Wucaiwan area is characterized by typical source-controlled reservoirs. Combining outcrop data, well data and seismic data, this article makes a systematic research and evaluation on the abundance, type, and maturity characteristics of the Carboniferous source rocks in the Ludong-Wucaiwan area. The Carboniferous source rocks are dominantly dark grey and grey mudstones, secondarily tuffs, carbonaceous mudstones, silty mudstones and coals. The source rock abundance of the Upper Carboniferous Batamayineishan Formation (C2b) is higher than that of the Lower Carboniferous Dishuiquan Formation (C1d), while the kerogen type of the Lower Carboniferous source rock is better than that of the Upper Carboniferous. The maturity center of the Carboniferous source rocks is located in the west part of Dinan uplift to the Wucaiwan depression area, with maturity decreased towards south and north. The distributions of the Carboniferous source rocks and volcanic rocks are complementary. The source rocks are distributed in zonal shape in east-west direction, and are most developed in the west part of the Dinan uplift and its southern area.

Geometric attributes for seismic stratigraphic interpretation

The application of sequence stratigraphy to seismic interpretation has proven to be fundamentally important in basin analysis. It provides a framework for understanding strat-igraphic evolution and is a key element in predicting the spatial distribution of reservoir, seal, and source rocks. Traditional methods of seismic se-quence stratigraphy make use of observations such as stacking patterns, seismic character of facies, and their distribution to develop subsurface models. We present a set of seismically derived geometric attributes that enhance and characterize these observations, allowing a sequence stratigraphic framework to be developed in the earliest stages of interpretation.

Geodynamics of the central South Atlantic conjugate margins: implications for hydrocarbon potential

Using a new margin restoration model for the central South Atlantic we highlight margin-opposed rift basin subsidence characteristics, reconcile important facies relationships and consider the associated processes responsible for contrasting basinward transitions to oceanic crust. We interpret these parameters as diagnostic of strain evolution during rifting. Pre-salt subsidence patterns and sequence isopachs of late syn-rift and early post-rift sequences are symptomatic of these complex extension behaviours. Inherited basement fault trends partition extensional strain during stretching with resultant rift-related structural styles recording the heterogeneity of the pre-rift crust. Correspondingly the seismic and gravity expression of the transition from continental crust to oceanic crust differs systematically along the length of the 'conjugate' basins. The presence of a conspicuous coast parallel positive linear gravity anomaly, referred to as the 'terminal horst', defines the basinward extent of attenuated continental crust in the more symmetrical Campos Basin and its interpreted conjugate. In the 'asymmetrical' Santos and Benguela Basins the ocean-continent transition at the present-day OCB (ocean-continent boundary) becomes equivocal with little gravity expression. Consequently the relationship of primary salt basin edges to the basinward extent of crustal extension appears more complex. Pre-existing crustal and lithospheric mantle scale heterogeneities are considered to impart a first-order control on whole crust deformation and ultimately 'sag' basin development. These structurally defined heterogeneities are believed to partition crustal strain and juxtapose end-member mechanisms of pure-shear and simple shear deformation styles as recorded by the complex distribution of syn-rift subsidence patterns within the pre-salt basins of the central South Atlantic. These conclusions challenge the necessity for invoking dominantly depth-dependent processes as a mechanism to explain apparent pre-salt, syn-rift subsidence anomalies. The complex interplay of structure and stratigraphy with an overlay of palaeoclimatic models provides important insights into hydrocarbon play fairways along the margin. In particular the impact on reservoir and source rock distribution and heat flow are discussed.

Distribution of Carboniferous source rocks and petroleum systems in the Junggar Basin

With pre-Cambrian continental nuclei and Early Paleozoic accretionary folded belts as the collaged basement, the Junggar Basin underwent an evolution of intra-cratonic basin after the transitional period of Carboniferous to Permian. The Carboniferous Period was a critical phase for the cratonization of Junggar Terrane, with two continental passive margins developed on both the southern and northern margins, and with rifts and upswells in the basin interior. The rifts were full-filled with volcanic clastic rocks up to 2 000 to 5 000 m in thickness. Influenced by the marine transgression, the regional extended source-rocks of the Lower Carboniferous Dishuiquan Formation(C1d) and the Upper Carboniferous Batamayneishan Formation(C2b) occurred within or around the basin, with the former one as oil and gas source rocks, while the latter one as effective gas source rocks. Volcanic rocks in the Batamayneishan Formation are the main reservoirs. Two petroleum systems were formed: C1d-C (.) and C2b-C2b (!). The tectonic events in the Late Jurassic and Neogene gave rise to the formation, modification, and finalizing of the Carboniferous prospects. The difference between the evolutionary process of each structural unit resulted in the differentiation of the petroleum systems horizontally. A series of oil and gas fields have been discovered in Carboniferous, such as the Wucaiwan, Shixi, Kelameili, and Chepaizi oil and gas fields as well as the oil-bearing Block-2, 4, and 6 in the Karamay Oilfield. The exploration has proven that the Carboniferous has great potential for oil and gas discovery. 准噶尔盆地是在前寒武纪陆核和早古生代增生褶皱带的拼合基底之上经历石炭纪—二叠纪过渡阶段后形成的克拉通内坳陷盆地，石炭纪是准噶尔及邻区克拉通化过渡发展的关键时期，在准噶尔地块南、北缘发育了被动大陆边缘，地块内部断陷与凸起相间，断陷内沉积了厚度达2 000～5 000 m的火山碎屑岩系。受海侵范围控制，盆地内部及周缘发育区域展布的石炭系下统滴水泉组和上统巴塔玛依内山组两套有效烃源岩，前者可能是油、气烃源岩，后者是有效的气源岩，上石炭统巴塔玛依内山组火山岩是主要的储集体，由此形成了C1d—C(.)和C2b—C2b(!)两个含油气系统。中侏罗世晚期—晚侏罗世和新近纪以来的构造活动导致了石炭系圈闭的形成、改造与最终定型。不同构造单元后期演化历史的差异导致石炭系含油气系统在平面上产生分异。迄今在石炭系已发现了五彩湾、石西、克拉美丽、克拉玛依二/四/六井区、车排子等多个油气田，油气勘探实践表明准噶尔盆地石炭系具有较好的勘探前景。图8表3参41