Zhaoming Wang

Formation, distribution, potential and prediction of global conventional and unconventional hydrocarbon resources

Abstract Since the Neoproterozoic, two important cycles of separation and junction of the Rodinia and Pangea supercontinents controlled the formation of the Tethys, Laurasia, Gondwana and Pacifica domains, as well as the sedimentary basin types including craton, passive margin, rift, foreland, fore-arc, and back-arc basins. Sixty-eight percent of the discovered reserves are from the Tethys domain, while 49% of the undiscovered possible reserves are in passive margin basins. Six major sets of source rocks, two types of reservoirs (carbonates and clastics), and two regional seals (shale and evaporite) formed in global evolution of basins. Ten patterns are summarized from the above factors controlling the distribution of global hydrocarbon resources. (1) Conventional-unconventional hydrocarbon is accumulated “orderly”. (2) Distribution of Tethys controls the accumulation of the global hydrocarbons. (3) Foreland thrusting zones control the distribution of structural oil/gas fields; (4) Intra-craton uplifts control the distribution of giant oil/gas fields; (5) Platform margins control the banded distribution of giant organic reef and bank type oil/gas fields. (6) Passive margins control the distribution of giant marine oil/gas fields. (7) Foreland deep slopes control the occurrence of large scale heavy oil and bitumen. (8) Basin deposition slopes control the accumulation of tight oil & gas and coalbed methane. (9) Organic rich deep basin sediments control the retention of shale oil and gas. (10) Low temperature and high pressure seafloor sediments control the distribution of hydrate. The conventional/unconventional resources ratio is 2:8. The conventional resources are mainly distributed in the Middle East, Russia, North America, and Latin America. The unconventional resources are mainly distributed in North America, Asia Pacific, Latin America, and Russia. According to the ten trends of global petroleum industry, hydrocarbon exploration is mainly focused on marine deep water, onshore deep layer, and unconventional oil & gas. The peak of oil production will probably come around 2040, and the life span of petroleum industry will last another 150 years. Renewable energy will replace fossil energy, not for the exhaustion of fossil energy, but because it is cheaper and cleaner.

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 conditions and geological characteristics of deep giant gas provinces in the Kuqa foreland thrust belt

Abstract A series of seismic exploration technologies, such as “wide line and big combination” mountainous seismic acquisition, high steep structure pre-stack depth migration processing and deep tectonic modeling, were used to explore Kuqa deep structures. Pre-salt deep structures were preliminarily confirmed and a group of large structural traps were found. The research shows that the Kuqa foreland thrust belt is favorable for forming giant gas accumulations. Large-scale imbricated thrust systems can provide traps for large-scale oil and gas accumulation; excellent hydrocarbon source conditions and later intense charges of gas provide sufficient hydrocarbon reserves; the deep mass effective reservoir sandstone works as good reservoir volume for giant gas accumulations and thick gypsum deposits serve as good cap rocks. The geological characteristics of deep pre-salt structure giant gas accumulations typically have hydrocarbon distributions controlled by structural traps and structural gas reservoirs are dominant, reservoir properties of the deep thrust belts are generally poor, with fractures being the important controlling factor for hydrocarbon enrichment, oil and gas distribution is characterized by joint control of source and cap rock, stacking of multi-layer beds, and overall beds containing gas. Reserves are large, and single well productivity is high.

Classification and hydrocarbon distribution of passive continental margin basins

Abstract Sixty-six passive continental margin basins around the world were compared comprehensively from the aspect of seismogeology on the basis of plate tectonics. According to their textural and structural differences, passive continental margin basins were classified into seven subdivisions, i.e., rifted basin, non-saline faulted depression basin, saline faulted depression basin, non-saline depression basin, saline depression basin, delta reformed basin and positive reverse deformed basin. The passive continental margin basins around the world have been generated with the formation of Mesozoic and Cenozoic Atlantic and Indian Oceans and they have experienced superimposition of three prototypes, including intra-continental rift in rifting period, intercontinental rift in transitional period and passive continental margin in drifting period. In rifted basins, the petroleum systems are mainly located in the lower lacustrine/marine rift series of strata and the thinner depression series of strata at the upper part are only regional cap-rocks. Large oil and gas fields are mainly concentrated in structural traps of rift series of strata. In non-saline faulted depression basins, hydrocarbon generation and expulsion peaks occur in both upper thicker marine depression series of strata and lower rift series of strata. Reservoirs are formed in the structures of rift series of strata, and oil and gas are highly concentrated at slope fans in depression series of strata. In saline faulted depression basins, large oil and gas fields are mainly distributed in the lagoon carbonate rocks of subsalt series of strata and the deepwater slope fans of suprasalt depression series of strata. In saline depression basins, only petroleum systems in depression series of strata are active, and various traps are developed, such as slope fan, salt structure and bioherm. In non-saline depression basins, large oil and gas fields are mainly located in submarine fan groups of depression series of strata because this type of basins are of narrow continental shelf and steep continental slope. In delta reformed basins, four major ring-like structure belts (i.e., growth faulting-mud diapir-thrust nappe-foredeep gentle slope) are formed from the shore to the deepwater and large oil and gas fields can be formed in each belt. Positive reverse reformed basins are the passive continental margin basins which are influenced by global orogenesis since the Miocene. In this type of basins, oil and gas are concentrated in compressional anticlines of reverse series of strata.

Research advances and direction of hydrocarbon accumulation in the superimposed basins, China: Take the Tarim Basin as an example

Abstract The superimposed basins in the Tarim Basin are characterized by multiple source-reservoir-caprock combinations, multiple stages of hydrocarbon generation and expulsion, and multi-cycle hydrocarbon accumulation. To develop and improve the reservoir forming theory of superimposed basins, this paper summarizes the progress in the study of superimposed basins and predicts its development direction. Four major progresses were made in the superimposed basin study: (1) widely-distributed of complex hydrocarbon reservoirs in superimposed basins were discovered; (2) the genesis models of complex hydrocarbon reservoirs were built; (3) the transformation mechanisms of complex hydrocarbon reservoirs were revealed; (4) the evaluation models for superimposed and transformed complex hydrocarbon reservoirs by tectonic events were proposed. Function elements jointly controlled the formation and distribution of hydrocarbon reservoirs, and the superimposition and overlapping of structures at later stage led to the adjustment, transformation and destruction of hydrocarbon reservoirs formed at early stage. The study direction of hydrocarbon accumulation in superimposed basins mainly includes three aspects: (1) the study on modes of controlling reservoir by multiple elements; (2) the study on composite hydrocarbon-accumulation mechanism; (3) the study on hydrocarbon reservoir adjustment and reconstruction mechanism and prediction models, which has more theoretical and practical significance for deep intervals in superimposed basins.

Origin and differential accumulation of hydrocarbons in Cambrian sub-salt dolomite reservoirs in Zhongshen Area, Tarim Basin, NW China

The origin and differential accumulation of hydrocarbons in the Cambrian sub-salt dolomite reservoirs in Zhongshen Area were studied based on comprehensive geochemical analysis of core samples, crude oil samples and natural gas samples. Mass spectrometric detection shows the core samples and crude oil samples are characterized by high C28 sterane content, low diasterane content, high gammacerane content and abundant aryl-Isoprenoids, and the associated gas has a low nitrogen content of 0.24%−4.02%, so it is inferred that the oil and gas are derived from Cambrian – Lower Ordovician source rock. The natural gas in the Middle Cambrian has a methane carbon isotope value of −51.4‰ − −44.7‰ and dryness coefficient of 0.65−0.78, representing associated gas, and the natural gas in the Lower Cambrian has a methane carbon isotope value of −41.4‰ − −40.6‰, and dryness coefficient of 0.99, representing cracking gas. The deep formations in the Tarim Basin contain cracking gas with high H2S content produced by thermo-chemical sulfate reduction (TSR). Due to the poorer reservoir properties and undeveloped fracture network system, the Middle Cambrian reservoirs have low charging degree of this kind of gas, so low H2S content (0.003 8%−0.200 0%); in contrast, with good reservoir properties and developed fracture network system, the Lower Cambrian reservoirs have a higher charging degree of this kind of gas, and thus high H2S content of 3.25%−8.20%. In summary, the oil and gas of Cambrian sub-salt dolomite reservoirs in Zhongshen Area are derived from Cambrian – Lower Ordovician source rock, and the differential accumulation of gas is the joint effect of reservoir physical property and development degree of fracture network system.

Structural architecture differences and petroleum exploration of passive continental margin basins in east Africa

Abstract Based on the plate tectonic theory, and by studying seismic, geologic data and related documents, this study restored the proto-type basins and lithofacies paleogeography of East African passive margin basins in the major geological periods, and carried out analysis on the basin architecture characteristics and sedimentary filling variance. Based on the dissection of fifteen reservoirs, three hydrocarbon accumulation models were identified to find out favorable plays and the further exploration direction in this region. The East African passive continental margin basins experienced three prototype stages, Late Carboniferous-Triassic Karoo intercontinental failed rifts, Jurassic intercontinental-intracontinental rifts, and passive continental margins since the Cretaceous. The rift sequences are developed in all the basins, forming the “rift type”, “rift depression type” and “delta reconstruction type” passive continental margin basins in line with the different thicknesses of the sediment fillings during the depression period. In the “rift type” basins, the sediment thickness during the depression period was less than 3 000 m, forming “single source – structure type” hydrocarbon accumulation model, where the exploration direction will mainly focus on giant structural traps on the top of the rift sequences. In the “fault-depression type” basins, the sediment thickness during the depression period was more than 5 000 m, forming “double sources – double combinations type” hydrocarbon accumulation model, where the exploration direction will mainly focus on giant slip-collapse-debris flow deposits on the top and middle of the slope. In the “delta-reconstruction type” sediment basins, the thickness is more than 6 000 m, forming constructional delta deposits with four structural belts from onshore to offshore, unique growth faults, mud diapirs, thrust faults and fore deep gentle slope, which are named as “three sources – multi-combinations type” hydrocarbon accumulation model, and all the four structural belts can form giant oil and gas fields.

Structural characteristics and petroleum exploration of Levant Basin in Eastern Mediterranean

Abstract By using geologic and seismic data, this study restored the proto-type basins and lithofacies paleogeography of the Levant basin in Eastern Mediterranean during main geological periods, carried out comparison analysis on the basin architecture characteristics, and based on careful examination of the characteristics of discovered gas reservoirs, established the reservoir forming pattern and discussed the favorable reservoir forming combinations and future exploration direction in this region. Three structural architectures can be identified in the basin, the early-stage faults, the mid-stage faults and the late-stage faults. The early-stage faults are mainly controlled by intercontinental depression, which were less influenced by later compression stress in the southern deep water area of the basin. Controlled by the lateral structural stress and the Syrian Arc Fold Belt, the mid-stage faults became less active from north to south and from east to west. Influenced by the collision and/or Dead Sea strike-slip Fault Zone, the late-stage faults were active but did not pierce the thick Upper Miocene evaporites. Combined with the discovered reservoirs and outcrops, the Mesozoic sandstones and carbonates in deep water area near Eratosthenes seamount of Israel offshore and the Cenozoic carbonates and Tamar sands of Lebanon offshore are the main petroleum exploration targets in the next step.

Major transgression during Late Cretaceous constrained by basin sediments in northern Africa: implication for global rise in sea level

The global rise in sea level during the Late Cretaceous has been an issue under discussion by the international geological community. Despite the significance, its impact on the deposition of continental basins is not well known. This paper presents the systematic review on stratigraphy and sedimentary facies compiled from 22 continental basins in northern Africa. The results indicate that the region was dominated by sediments of continental facies during Early Cretaceous, which were replaced by deposits of marine facies in Late Cretaceous. The spatio-temporal distribution of sedimentary facies suggests marine facies deposition reached as far south as Taoudeni-Iullemmeden-Chad-Al Kufra-Upper Egypt basins during Turonian to Campanian. These results indicate that northern Africa underwent significant transgression during Late Cretaceous reaching its peak during Turonian to Coniacian. This significant transgression has been attributed to the global high sea-level during this time. Previous studies show that global rise in sea level in Late Cretaceous may have been driven by an increase in the volume of ocean water (attributed to high CO2 concentration and subsequently warm climate) and a decrease in the volume of the ocean basin (attributed to rapid production of oceanic crust and seamounts). Tectonic mechanism of rapid production of oceanic crust and seamounts could play a fundamental role in driving the global rise in sea level and subsequent transgression in northern Africa during Late Cretaceous.