During the period of the 13th Five-Year Plan, oil prices have remained continuously low and the global investment environment has become increasingly complicated. This has raised major issues for CNPC overseas oil and gas exploration, including the issue of how to adapt to complex internal and external environments as quickly as possible and how to achieve accurate deployment and benefit exploration. The company has proposed a robust deployment strategy of focusing on benefits, seeking large-scale, high-quality, rapidly-recoverable reserves, and carrying out risk exploration and fine exploration. A series of effective exploration management measures have gradually been developed. These include: innovating and implementing an integrated research organization mode of “industry-college-institute-application cooperation”, optimizing decision-making processes at headquarters level, integrating exploration-development-engineering, strengthening international cooperation in deep-water exploration, and screening large basins globally to identify new exploration projects. Between 2016 and 2019, CNPC overseas oil and gas exploration made 12 major breakthroughs and strategic discoveries as a result of implementation of these measures. Discoveries have been made in several fields in mature exploration areas through fine exploration. Cumulative proven oil and gas geological reserves are more than 10×108 t oil equivalent, the discovery cost per barrel oil is less than $2/bbl, and the average success rate of exploration wells is 76%. At present, CNPC overseas oil and gas exploration still faces challenges such as continuously low international oil prices, a sharp decrease in exploration projects, increasingly fierce competition for new blocks, the inferior quality of conventional oil and gas resources, and increasingly complex exploration objects. The company also has comparatively weak capacity for independent exploration and development of deep-water oil and gas. However, There are still rich undiscovered oil and gas resources around the world. Cross-border integration of advanced technologies will transform exploration concepts and technological innovations, so the prospects for overseas oil and gas exploration are broad and promising.

The Huizhou sag in the Pearl River Mouth Basin is the ‘cradle’ of the petroleum industry in the eastern South China Sea, and also the breakthrough area for oil and gas discoveries in the middle-deep Paleogene in the eastern Pearl River Mouth Basin. For the past 10 years, however, exploration in the Huizhou sag has been trapped in a bottleneck. In order to discover new large-medium oil and gas fields, it is necessary to hold workshops and strengthen the re-evaluation work of petroleum geological conditions to bolster confidence in the exploration idea of “new achievements in mature areas”. Now, a new exploration concept is now proposed: “taking oil-rich sub-sags as a basis, focusing on Paleogene-buried hills, and expanding to new frontiers”. With increased research, new understandings of gas exploration in oil-rich sub-sags are emerging. In the Huizhou 26 sub-sag, mixed-type kerogens of lacustrine facies are characterized by “generation of both oil and gas, and rapid gas generation in the late stage” and offer great potential for natural gas resources. The “Paleogene-buried hills” trap group around the Huizhou 26 sub-sag has a hydrocarbon accumulation model of “strong near-source hydrocarbon supply and stereoscopic network migration”, making it the preferred zone for exploration transformation and new-field breakthroughs. The recent breakthrough discovery of a large-medium oil and gas field in the “Paleogene-buried hill” area of the Huizhou 26-6 structure—confirms this new target of gas exploration in high mature oil-rich sub-sag, opens a new chapter of “Paleogene-buried hill” exploration in the Huizhou sag, and expands the new exploration field of paleo-buried hills in the eastern Pearl River Mouth Basin.

The Chengdao oilfield is an important offshore area for reserves increase for Sinopec Shengli Oilfield Company. The Dongying Formation, in the east slope of the Chengdao area, has great potential and has so far been subject to relatively little exploration. The diversity of sand body types in this area makes it difficult to predict their distribution, and hydrocarbon accumulation and enrichment patterns are also extremely varied. This study examines the sedimentary characteristics and control factors of hydrocarbon accumulation in the Dongying Formation to determine the geneses of sand bodies and the main controlling factors of oil and gas accumulation in the area. Results from mud logging, wireline logging, well test, and seismic data show that: (1) The main types of sedimentary facies are the flood sub-lacustrine fans and slump sub-lacustrine fans of the Ed4 sand group of the major oil-bearing series in the east slope of the Chengdao area. (2) The fan bodies are oriented NE along several inherited gullies, controlled by paleogeomorphology and a fault slope break belt. Multi-stage sand bodies overlap each other. Between the gullies, sand reservoirs are relatively isolated. The slope breaks are mostly sand pinch-out zones. (3) The oil reservoirs in the study area are mostly structural-lithologic and lithologic reservoirs—a result of the good configuration relationships between structural factors and sedimentary systems. Large-scale self-generating and self-storage lithologic oil reservoirs are developed in the lower parts of slope breaks towards sag areas. (4) Oil and gas enrichment in the area, and the formation of large-scale reservoirs, are the results of superimposition of multi-stage gravity-flow sand bodies in a deep water environment. Source and reservoir assemblages, faults, and overpressure have ensured that the oil reservoirs in this area benefit for superimposed and contiguous distribution, general enrichment, and high production.

Rift basins in Africa are of many types, are in many stages of geological development, and often possess rich oil and gas resources. In order to guide oil and gas exploration and strategic selection of favorable areas, this study analyzes the types and formation stages of rift basins in Africa. The hydrocarbon accumulation characteristics of a number of key rift basins are also described. The results show that: (1) there are three principal stages of rift basins in Africa: Paleozoic, Mesozoic, and Cenozoic. A number of rift systems are formed: the Karoo rift system, the intracontinental rift system in West and Central Africa, the continental margin rift system in North Africa, and the Red Sea-Gulf of Aden-East African rift system. Prototype basins can be divided into active rift basins and passive rift basins according to genesis type. Active basins are related to thermal-uplift and tension and passive basins are related to strike slip or regional extensional stress fields. Basins can be divided into intracontinental rift basins, intercontinental rift basins, aulacogen rift basins, and continental margin rift basins according to structural position and basement characteristics. (2) The basins have different petroleum geological characteristics and hydrocarbon enrichment laws as a result of variations in tectonic evolution, sedimentary filling, and structure. In North Africa, high-quality marine source rocks are developed in continental margin rift basins. The dominant petroleum system is a Mesozoic-Cenozoic system. Oil and gas are primarily accumulated in faulted horst areas formed by differential subsidence. In Central and West Africa, multi-stage superimposed rifts are developed in intracontinental rift basins with a variety of major plays. Oil and gas are distributed in Paleogene, Upper Cretaceous, and Lower Cretaceous formations. In East Africa, intracontinental rift basins formed late and are dominated by a Cenozoic petroleum system.

The right bank block of the Amu Darya River is located in the northeastern part of the Amu Darya Basin in Central Asia and has abundant gas resources. The sub-salt carbonate rocks of the Middle-Upper Jurassic are the main hydrocarbon enrichment formations. Analysis of the geological characteristics and hydrocarbon accumulation factors of sub-salt large and medium gas fields show that: ① The sub-salt large and medium carbonate gas fields can be divided into three types: gas fields of superimposed inner-platform shoals, gas reservoir groups of ramp reef shoals, and fracture-cavity type gas fields in thrust structures. Pore (vug) type inner-platform shoal reservoirs are developed in the gas fields of superimposed inner-platform shoals. They are vertically superimposed, with development of barrier layers and interlayers, forming multiple sets of gas-water systems. Fracture- pore (vug) type ramp reef shoal reservoirs are developed in the gas reservoir groups of ramp reef shoals. In the plane, this is characterized as “one reservoir in one reef”. Carbonate fracture-cavity reservoirs are developed in fracture-cavity type gas fields in thrust structures with complicated gas-water systems. The closer to the main faults, the higher the charging intensity and the lower the gas-water contact. ② Gas fields of superimposed inner-platform shoals are distributed in evaporate platform–restricted platform–open platform. The scale of this type of gas field was controlled by paleogeomorphology and structural amplitude. The gas reservoir groups of ramp reef shoals were located on upper ramp zones of platform margins, with the gas enrichment degree being closely related to the paleogeomorphic high and to the type of reef-shoal. Fracture-cavity type gas fields are distributed in piedmont thrust structural zones. The development scale of faults in the gas fields is the main controlling factor of high gas production and enrichment. ③ The deep clastic rocks of the Middle-Lower Jurassic form a hydrocarbon accumulation assemblage of self-generation and self-storage, which has the conditions required for the formation of large and medium gas fields. Successive structural traps with less reconstruction in the Himalayan and stratigraphic-lithologic traps in the sag zones are favorable exploration targets.

The Bowen Basin in Australia is a typical back-arc foreland coal-accumulation basin. The Bowen block, which lies in the basin, has complex geological conditions. A considerable amount of coalbed methane (CBM) exploration work has been carried out in the block but the CBM enrichment laws remain unclear due to many controlling geological factors. In this paper, the following CBM enrichment and high-production laws are proposed: “coal development is controlled by sedimentary facies, gas-bearing properties are controlled by structure, gas accumulation is controlled by hydrology, CBM plays are controlled by stress, and the enrichment and high-production zones are the local-high positions and the marginal slope”. For the purposes of the study, the Moranbah coal measures are taken as a representative example. Analysis was carried out on a combination of coal seam development characteristics, structural characteristics, hydrogeological characteristics, and stress characteristics, as well as other geological characteristics of coal seams in the Bowen Basin such as gas-bearing properties and permeability. Sedimentary facies control the coal seam distribution and the physical properties of reservoirs. Coal seams in river alluvial plain and upper delta plain are thicker than those in the lower delta plain. Structures control gas content and enrichment zones. Syncline structures are conducive to CBM enrichment and high production. CBM enrichment and high production zones are situated at local high positions of synclines. Hydrogeological conditions control CBM accumulation, which are generally good in weak runoff-confined areas. CBM accumulation conditions are favorable when the direction of surface runoff is consistent with that of formation dip. Stress fields control the high permeability zones of coal seams. With increasing burial depth, effective stress increases and coal seam cleats and fractures are closed, resulting in a decrease in permeability. Based on the proposed CBM enrichment laws, a three-factor evaluation index system for favorable areas is determined: CBM resource scale, gas-controlling factors, and recoverability. ‘Sweet spot’ areas, favorable areas, and unfavorable areas are delineated. Based on current CBM block management policies in Australia, different exploration strategies are proposed. For the ‘sweet spot’ areas, CBM development permissions should be applied for, and pilot production and development evaluation should be given priority. In favorable areas, exploration work should be carried out to retain potential commercial areas. In unfavorable areas, blocks should be relinquished.

Since the discovery of the giant Lula oil field in 2006, a number of large oil and gas fields have been discovered in deep-water sub-salt strata in the Great Campos Basin in Brazil, which has become one of the ‘hotspots’ of global exploration. This study examines the hydrocarbon accumulation conditions of sub-salt oil and gas systems by analyzing these exploration discoveries and their oil and gas characteristics. The results show that the hydrocarbon generation conditions of sub-salt lacustrine shales are excellent, forming multiple hydrocarbon generation centers and strong oil and gas charging systems. Extremely thick gypsum-salt strata delayed the evolution of source rocks and effectively preserved oil and gas. Large-scale development of lacustrine microbial reservoirs provided the conditions for oil and gas enrichment. Sub-salt oil and gas resource potential was re-evaluated for this study using the scale sequence method, revealing the yet-to-be-discovered recoverable oil and gas resources of around 331×108 bbl. Systematic analysis of exploration history and experience suggest that the key factors in the discovery of large sub-salt oil and gas fields are the transformation of exploration ideas, continuous investment, and technological progress. Risk in commercial oil and gas discovery is principally affected by the scale of high-quality reservoirs, the types of oil and gas reservoirs, and the scale of economic reserves. Structural traps which developed in uplifted areas during rift-periods are the most important exploration targets, followed by stratigraphic-lithologic traps. High positions in ultra-deep ocean have particular exploration potential.

Diagenesis plays an important role in the formation and evolution of sedimentary rocks. However, diagenesis has different characteristics in different basins due to variations in sedimentary and tectonic evolution. The diagenesis of Cretaceous sandstones in the Termit Basin in Niger was studied by experimental analysis of samples, clarifying the main types of diagenesis of the sandstones and their influence on reservoirs. The diagenetic stages of Cretaceous sandstone reservoirs in the basin were distinguished according to diagenesis appearance, clay mineral characteristics and transformation laws, and the homogenization temperature of inclusions. The results indicate that most of the Cretaceous sandstones in the study area are in phase A of middle diagenesis, and that the sandstones with shallower burial depth are in phase B of early diagenesis. The rock type of the sandstones is an important factor affecting diagenesis. The Cretaceous sandstones in the basin are dominated by quartz sandstones. Strong support by the quartz grains reduced the damage caused to the reservoir by compaction. Primary intergranular pore is the dominant pore type. Small numbers of other pore types—such as intragranular pores and intergranular dissolved pores—are also developed. There are some differences in the development of Cretaceous sandstone reservoirs in different zones of the Termit Basin. Reservoirs in the Fana low bulge and the Yogou slope are relatively developed, with good physical properties. However, reservoirs in the Soudana uplift belt and Dinga fault terrace are comparatively poor. There is good exploration potential in the Fana Low bulge, which has been proved by drilling results. This is accordingly the key area for future Cretaceous exploration.

Deep water areas on both sides of the Atlantic Ocean are ‘hotspots’ for oil and gas exploration, with most of the discovered large medium oil and gas fields in these areas being salt-related structures. In the Niger Delta Basin, there are no salt deposits – only mud diapirs, mud volcanoes and other mud-related structures. In this study, comprehensive geological analysis is applied to clarify the rules of hydrocarbon accumulation in the compressed deep water zone in the basin. The oil and gas accumulation model is determined on the basis of seismic, well drilling, logging, crude oil physical properties, and other data, beginning with the tectonic and sedimentary evolution of the deep water area of the Niger Delta Basin. It is concluded that the deep water area of the Niger Delta Basin has been in a deep to semi-deep marine sedimentary environment since the Late Cretaceous. The principal source rocks are marine source rocks, deposited from the Upper Cretaceous to the Paleocene, that entered the peak stage of hydrocarbon generation and expulsion in the Late Miocene. As the Niger Delta continued to prograde towards the sea, the Middle and Lower Miocene were dominated by lobe deposits, while the Upper Miocene was dominated by channel complex deposits. Faults and fractures are the main pathways for vertical migration of oil and gas. On this basis, a “tree-shaped” near-source hydrocarbon accumulation model for the deep-water area of the Niger Delta Basin is proposed, which indicates that the fetch area is the main controlling factor of hydrocarbon enrichment in the area. The mud diapir structural zone in the northern part of the deep-water area has good hydrocarbon accumulation conditions, with a large number of undrilled structural traps, offering promising exploration potential.

Study of the characteristics of transfer structures and their control of sand bodies is of great significance for lithologic reservoir exploration in steep slope zones of rift basins. This paper analyzes the development position, type, and characteristics of the transfer structures in the western steep slope zone of the Fula sag in the Muglad Basin, Sudan, and their control effect on sand bodies during the rifting period of the steep slope zone. Favorable areas for development are identified and the accumulation model of lithologic oil and gas reservoirs in the western steep slope zone of the Fula sag is described. Analysis is based on restoration of the growth process of the western boundary fault in the sag (the Fula-western fault). Results show that there are four synthetic transfer structures in the Fula-western fault from north to south, which controlled the development of sand bodies in the Abu Gabra Formation in the steep slope zone during the rifting period. The controlling modes of sand body development can be divided into two types: transfer slope mode and transfer fault mode. Three favorable zones for lithologic oil and gas reservoirs are developed in the western steep slope zone of the Fula sag. They are located close to hydrocarbon generation and expulsion centers, in the hanging walls of faults and on the up-dip direction of transverse anticlines related to the transfer structures, which are on favorable pathways for secondary hydrocarbon migration. Different types of oil and gas reservoirs are regularly distributed in different structural positions on the transverse anticlines. Faulted anticline reservoirs can form at the tops of transverse anticlines. In these anticlines, up-dip pinch-out sandstone reservoirs can form in both flanks and fluxoturbidite-lens reservoirs form easily at the bottoms.

Cretaceous strata form the main production layers of a number of large CNPC oil field projects in the Middle East. The evolution of the Neo-Tethys Ocean influenced the sedimentary pattern and accumulation laws of Cretaceous source-reservoir-cap assemblages throughout the area. Based on analysis of regional tectonic evolution in the Cretaceous, and on the structural- sedimentary characteristics of the Rub Al Khali Basin, it is believed that the area has experienced two stages of tectonic- sedimentary evolution and that there are three sets of source-reservoir-cap assemblages. (1) During a stable expansion stage in the Early-Middle Cretaceous, two stages of intra-shelf basins were developed; the Bab and the Shilaif. Influenced by faults activity and strata flexure, the sedimentary environment evolved from carbonate ramp to weakly-rimmed platform. High frequency sea level changes further controlled the spatial allocation of the geological elements-source rocks, reservoirs, and cap rocks-forming two sets of “self-generation and self-storage” plays in the Middle and Lower Cretaceous. (2) In an oceanic-crust obduction stage in the Late Cretaceous, the sedimentary environment was primarily carbonate ramp. The Oman orogeny resulted in serious denudation of the Cretaceous strata. This resulted in configurations of source rocks in the Shilaif Formation and reservoirs in the Upper Cretaceous that formed “lower generation and upper storage” plays in the Upper Cretaceous. The distribution of Cretaceous oil reservoirs is controlled by three major factors: high-quality hydrocarbon source rocks, high paleo- geomorphology, and dominant oil and gas migration pathways. In the future, non-structural traps and low-permeability oil resources will be the primary Cretaceous exploration targets.

The Precaspian Basin, which is rich in sub-salt petroleum resources, is a globally important oil and gas producing area. The controlling factors of hydrocarbon accumulation in the eastern margin of the basin are complex, where it has been affected by paleo-uplift and by the Uralian orogeny. In this paper, the principal controlling factors of oil and gas accumulation in the eastern margin of the basin are identified according to analysis of hydrocarbon accumulation factors and accumulation models. Hydrocarbon accumulation in the eastern margin of the basin is closely related to the processes of subduction, subtraction, and closure of the Ural ocean. These processes formed paleo-rifts and paleo-uplifts which controlled the formation of oil and gas reservoirs. Paleo-rifts controlled the hydrocarbon generation centers. Faults formed by rifting became the primary pathways for oil and gas migration. Paleo-uplifts controlled the formation of early carbonate platform and the development of high-quality reservoirs, which are also important directional areas for oil and gas accumulation. The Uralian orogeny controlled the formation of later carbonate platform. The Uralian and other Hercynian orogenic belts created the conditions for the evolution of the basin into a restricted marine environment, forming high-quality salt caprocks in the Kungurian stage which are distributed across the whole basin. Faults generated during the collision orogeny formed fault-related traps, improved reservoir performance, and led to secondary hydrocarbon accumulation.

Basement exploration in the Muglad Basin in Sudan has attracted a lot of attention following recent breakthroughs in the exploration of basement buried hill in several adjacent basins. This study analyzes the basement lithology and reservoir development characteristics in the basin and considers its significance as an exploration target. Analysis is based on exploration practice, using drilling, well logging, testing, and 3D seismic data from block-6 of the basin. The basement rock is composed of feldspar, quartz, hornblende, and mica. The protolith is felsic granite or granodiorite, which experienced varying degrees of regional metamorphism or dynamic metamorphism, so that the basement rocks are metamorphic rocks of low to intermediate metamorphism. Basement reservoirs in the study area have double-layer structures: shallow layers of weathering crust and middle- deep layers primarily composed of fracture zones. The weathering crusts are usually of small thickness (less than 50 m) and are mostly developed on the surfaces of uplifts (bulges). Weathering and leaching have resulted in widespread broken rocks and dissolved minerals, with vugs developed. The fracture zones are generally thick, but distribution is uneven. It is evident in the basin margin and in the transition zone between depression and uplift that fracture zones form the principal reservoir type in the basin basement. Fracture development areas such as the steep-slope zones at the edge of petroleum-rich depressions (or sags) and depression-uplift transition zones should be priority targets for basement exploration in the future.