The Bengal Fan is a mud-rich, deep-water sediment system. A series of recently discovered biogenic gas reservoirs in the northeastern Bay of Bengal are fine-grained. The Pliocene gas discovered in the study area accumulated in the levee element of a deep-water channel complex identified by high-resolution three-dimensional (3D) seismic interpretation integrated with well logs and sidewall cores (SWC). The thickness and porosity of the levee gas reservoir are of good quality, but the permeability is relatively low owing to the high mud content. The discovery of the levee sandstone indicates various reservoirs in this mud-rich sediment system. Moreover, gas discovery implies that the gravity-flow sediment systems “link” the source rock in the study area. Gas reservoirs were discovered in Pliocene gravity-flow sediment systems, where the palaeo-climate experienced significant changes with a dramatic increase in total organic carbon (TOC) from the Miocene to the Pliocene. TOC-rich pelagic mudstones and deep-water gravity sediments act as source rocks for petroleum systems. Therefore, gravity-flow sediment systems have developed self-accumulating petroleum plays that exhibit enormous potential for exploration. Given the structural framework in the northeastern part of the Bay of Bengal, stratigraphic or structure-stratigraphic traps could have developed in the Pliocene deep-water sediment systems in the Bengal Fan.

The history and results of petroleum exploration in the Santos Basin, Brazil are reviewed. The regularity of hydrocarbon enrichment and the key exploration technologies are summarized and analyzed using the seismic, gravity, magnetic and drilling data. It is proposed that the Santos Basin had a structural pattern of two uplifts and three depressions and the Aram-Uirapuru uplift belt controlled the hydrocarbon accumulation. It is believed that the main hydrocarbon source kitchen in the rift period controlled the hydrocarbon-enriched zones, paleo-structures controlled the scale and quality of lacustrine carbonate reservoirs, and continuous thick salt rocks controlled the hydrocarbon formation and preservation. The process and mechanism of reservoirs being transformed by CO2 charging were revealed. Five key exploration technologies were developed, including the variable-velocity mapping for layer-controlled facies-controlled pre-salt structures, the prediction of lacustrine carbonate reservoirs, the prediction of intrusive/effusive rock distribution, the detection of hydrocarbons in lacustrine carbonates, and the logging identification of supercritical CO2 fluid. These theoretical recognitions and exploration technologies have contributed to the discovery of deep-water super-large reservoirs under CNODC projects in Brazil, and will guide the further exploration of deep-water large reservoirs in the Santos Basin and other similar regions.

Research on strike-slip faults and their control on the accumulation and distribution of oil and gas in petroliferous basins plays an important role in guiding oil and gas exploration activities. Based on the interpretation and analysis of seismic and drilling logging data, the geometry, evolution process, genetic mechanism and control on the accumulation of oil and gas of strike-slip faults in the Termit Basin are studied by applying coherent techniques. The results show that the strike-slip faults in the Termit Basin are mainly developed in the Trakes Slope in the eastern margin of the basin. The principal displacement zone of these strike-slip faults extending mainly in NNW-SSE and NW-SE, their en-echelon extension fractures (T fracture) are in south-north trending with dextral movement and right-lateral stepping. Most of these strike-slip faults are transtensional faults with few transpressional faults. Negative flower structures and Y-style fault combinations are widely developed, while straightly steep faults andpositive flower structures are locally developed. These strike-slip faults are the result of Cretaceous normal faults subjected to later shear stress in Paleogene Eocene Oligocene. The strike-slip mechanism is that differentially transverse compressive stress between blocks induces shear deformation of early normal faults. Since the Paleogene, the collision accumulation effect of the Eurasian plate and the African plate has formed a near-EW compressive stress inside the African plate. The nonhomogeneous distribution of stress at the northern boundary of the African plate caused differential movement between the Northwest African block and the Northeast African block, which induced the transformation of the Early Cretaceous normal faults on the Trakes Slope into a transtensional strike-slip faults. This series of strike-slip faults formed a group of antithetic fault block traps in Paleogene Sokor1 Formation,Sokor2 Formation and the Upper Cretaceous Yogou Formation, and these strike -slip faults are also vertical migration channels for oil and gas, which are beneficial for the hydrocarbon generated by Upper Cretaceous source rocks to migrating upward and accumulating in the Paleogene reservoirs.

A comprehensive tectonic analysis of the Eratosthenes Seamount (ESM) and its surrounding domains covered by our seismic data, contributes to better understanding of the evolution of the eastern Mediterranean. Tectonic origins of the ESM and the Zohr-like sub-Messinian salt highs between the ESM and the Nile delta are both continental fragments detached from the African-Arabian plate. These continental fragments form a NE-SW striking tectonic belt acting as the western margin of the Levant basin. After the Neotethyan rift, isolated carbonate platforms grew on these continental fragments and existed until the Miocene with alternations of shallow-water and deep-water carbonates caused by sea-level variation in the eastern Mediterranean. The subduction beneath the Cyprus arc beginning in the Early Miocene triggered onset of tectonic inversion of the deep-water area of the eastern Mediterranean. The ESM shielded the Zohr-like platforms from deforming by assimilating compressional stress from the Miocene subduction and the Messinian-present collision through its own folding, which led to tectonic evolutionary discrepancy between the Eratosthenes and the Zohr-like platforms since the Early Miocene. In addition, syn-sedimentary folding deformations related to the subduction were recognized in the southern Levant basin, the Herodotus eastern sub-basin, and the Cyprus arc. These deformations were all intense in the Early Miocene, attenuated gradually in the Middle and Late Miocene, and terminated at the very beginning of the Messinian. The weakening of these deformations could be associated with an increase in the subduction angle which also induced the development of the Mid-Late Miocene normal faults in the northern Levant basin. The initial African–Eurasian collision in the Messinian terminated these subduction-related deformations. Finally, we proposed a new evolutionary model of the deep-water area of the eastern Mediterranean, consisting of four stages, i.e. the Neotethyan rift stage from the Late Permian to the Early Jurassic, the post-rift tectonic stability stage from the Middle Jurassic Bajocian to the Oligocene, the subduction-related compression stage during the Miocene, and the collision-related compression-transpression stage from the Messinian to the present.

The Lower Cretaceous AG2 Formation is the main source rock and dominant oil-bearing layer of Sufyan sag, Muglad Baisn, Sudan. This paper based on the study of lithology, log facies, seismic facies and seismic attribute, studied the AG2 depositional system of Sufyan sag. And analyzed its tectonic features, paleogeomorphology, paleoclimate and provenances, built the sedimentary model of rifting period. The Sufyan is a graben, faulted in the north and south part at the initial rift period, as the basin evolution and water level fluctuation, the north part of sag became gentle slope environment and the south was steep slope yet in AG2 Period. There are Babanusa uplift and Central Africa locate at the northern part of Sufyan sag, which are the extra-provenance of Muglad Basin, and divided with Nugara sag by Tomat small uplift in south direction, and developed the inner-provenance. From the drill data and core data, most of the sandstone is fine-grained and well sorted in northern part of the sag, we find turbidite of medium grained sandstone in the downthrow side, which means the gravity current and the long-distance sediment transportation. We built the AG2 meandering river delta depositional model of northrn part, and judge the north provenance is the dominant one. The drill data shows high sand gross ratio and fine-grained sediment of southern part, and found its near sediment supply and periodicity, we built braided-river delta model of the south sediment supply system. The depositional model of the south is similar with the fan-delta, but has weak sediment supply and subsea sediment transportation characteristics. The south and west are the secondary provenance. This paper compiled two sediment facies maps of AG2 in two periods, built three-dimensional depositional model, and suggest the middle structure area of the sag are favorable prospecting area, which have good reservoir and near the source rock.

The Silurian Tanezzuft Formation 'hot shale' in North Africa is a high-quality source rock and a major contributor to the oil and gas reserves of the Paleozoic Ghadames Basin. This hot shale has similar sedimentary characteristics to those of the Silurian Longmaxi Formation shale in the Sichuan Basin in China, which is a proven prolific source of shale gas. In this study, the oil and gas accumulation conditions and sedimentary characteristics of the Tanezzuft shale are compared with those of the commercially exploited Longmaxi shale and the Marcellus and Barnett shales (North America), and criteria for shale oil and gas potential in the Tanezzuft shale are established from these commercially exploited shales. For the Tanezzuft shale, the net pay thickness of effective source rock, total organic carbon, thermal maturity and burial depth, and the locations of faults in the Ghadames Basin are analyzed and mapped. The distributions of these variables are then used to predict the distribution of shale oil and gas with respect to the established criteria. It is shown that the Tanezzuft shale has significant potential for the production of shale oil and gas; in particular, the northeastern and southwestern slopes of the Ghadames Basin are the most favorable in terms of prospective shale oil and gas exploration.

Many mud diapirs have been recognized in southern Okinawa Trough by a multi-channel seismic surveying on R/V KEXUE I in 2001. Gas hydrates have been identified, by the seismic reflection characteristics, the velocity analysis and the impedance inversion. Geothermal heat flow around the central of the mud diapir has been determined theoretically by the Bottom Simulating Reflectors (BSRs). Comparing the BSR derived and the measured heat flow values, we infer that the BSR immediately at the top of the mud diapirs indicate the base of the saturated gas hydrate formation zone (BSGHFZ), but not, as we ordinarily know, the base of the gas hydrate stability zone (BGHSZ), which could be explained by the abnormal regional background heat flow and free gas flux associated with mud diapirs. As a result, it helps us to better understand the generation mechanism of the gas hydrates associated with mud diapirs and to predict the gas hydrate potential in the southern Okinawa Trough.

Crude oils produced from the Great Palogue Field in the Melut Basin, Sudan display unusually high total acid number values (TAN, up to 10.4mg KOH/g oil). This field was discovered in 2002 and produces oils of highly variable (15–31°) API gravity. The main production comes from the Paleogene Samma and Yabus Formations, with the Upper Cretaceous Melut Formation being a minor contributor. The effective hydrocarbon source rocks are most likely within Lower Cretaceous lacustrine shales deposited during the syn-rift stages of the basin’s evolution. This study addressed 20 crude oil samples from five exploration and appraisal wells in the Great Palogue Field and four oil samples from other oil fields in the basin to represent the various production fluids from the Upper Cretaceous and Paleogene pay zones. These oil samples were characterized using routine molecular geochemical techniques to determine the primary geological and geochemical controls on oil acidity. Based on source and maturity constraints, two genetic types of high acidity oils have been recognized from the Melut Basin. The first group of high acidity oils is likely primary high TAN oils with a TAN value of 0.5–0.99mg KOH/g oil. They are buried deeper than 2000m where the temperature is higher than 80°C. These include the oils only in the Upper Cretaceous Melut Formation of the Anbar-1 and Palogue South-2 blocks. The second group of high acidity oils show higher TAN values (>1.0mg KOH/g oil) and various levels of biodegradation. These oils represent the dominant oil type in the Melut Basin, occurring mainly in the Paleogene Yabus and Samma Formations. A multiple phase oil charging model is proposed to explain the horizontal and vertical variation in the oil TAN values across the Great Palogue Field.

This paper overviews the framework, structural and petroleum geology aspects of the Melut rift Basin in Sudan. The data base is from mainly proprietary exploration work consisting of more than 20,000km of seismic profiles, 2000km2 of 3D seismic, and more than 50 exploration wells. There have been more than 15 oil and oil and gas discoveries.The Melut Basin is a Meso-Cenozoic rift basin accompanied by the formation and development of the Central African Shear Zone (CASZ) on the pre-Cambrian crystalline and metomorphic basement of lower relief. Three stages of rift development and fracturing have been identified, stronger in the Early Cretaceous and Paleogene and weaker in the Late Cretaceous. Source rocks are the Lower Cretaceous lacustrine shales, whereas reservoirs and seals are both Paleogene and Upper Cretaceous. Dominant structural styles are large-scale anticlines in the Paleogene sequences and antithetic normal fault-blocks in the Upper Cretaceous and Paleogene. Heavy to light oils (8.87–61.5°API) and gas have been discovered in the Paleogene and only light oils and gas in the Upper Cretaceous pay zones. The primary pay zone in the Melut Basin is the Paleogene. The Great Palogue Field, with ultimate recoverable oil reserves of more than 900 million barrels, was discovered in the northern Melut Basin. The gentle slopes of each subbasin are favorable areas for petroleum accumulation and enrichment. The faulted anticlines within the Paleogene syn-rift sequences are the main trap types, whereas the antithetic fault-blocks of the Upper Cretaceous sequences are secondary.

In this paper, the authors analyzed the wave shape features from ultrasonic inspection, and put forward with a method of these inspecting and recognition with those features. It is shown that the method is efficient in this practice. An example of application is described.