Yanchang oilfield was founded on terrestrial oil generation theory, pioneered oil exploration and development, and witnessed the development history of China petroleum industry from scratch to prosperous and from small to large. The early exploration history of Yanchang oilfeld is reviewed with personal experiences, and the century-long exploration history of Yanchang oilfeld is reconstructed. In the course of sustainable development, Yanchang oilfeld followed the "hard-working" entrepreneurial spirit of Chinese oil workers, overthrew the conclusion of "China was oil-poor", gradually recognized the laws of geology, developed a series of drilling and production technologies for tight and low-permeability sandstone reservoirs, and realized the theoretical and technological innovations in the exploration and development of unconventional oil and gas reservoirs. This may enlighten the development of China petroleum industry in the new era.

After more than 50 years, the Jiyang depression has entered a mature exploration stage on the whole and the exploration degree is getting higher and higher. Based on the analysis of "layer unit"-based remaining resource potentials and effcient reserve increase targets in the exploration and development stage, the future exploration targets have been identifed and the future exploration plan has been proposed. The study results show that the remaining resources in the Jiyang depression are still abundant; re-recognition of previous primary reservoirs involving channel sandstone, steep-slope glutinite, beach-bar sandstone and turbidite sandstone can fnd more large-scale reserves; fne analysis of the "blank reserve area" in the main oil-bearing reservoirs formed during the fault and depression of the Sha 4 and Dongying Formation can identify a series of proftable reserves; re-understanding of new strata and zones in old exploration areas using new principles can continuously make new discoveries; and unconventional resources such as shale oil and gas and coal-formed gas are succeeding resources in middle and long terms in the Jiyang depression. The Jiyang depression will keep a long-term and stable reserve increase based on re-recognition of remaining resources, innovative theories, advanced technology and effective management.

The causes of failed wildcat wells in the eastern Pearl River Mouth Basin were analyzed comprehensively to clarify the factors influencing the exploration results and guide the following exploration in this area. It is shown that the factors leading to the failure of wildcat wells are ranked as migration-accumulation matching condition, trap condition, reservoir condition, source rock condition, caprock condition and preservation condition according to their priorities. Then, the failure factors were classifed and analyzed from three aspects of water depth, oil bearing layer and trap type. It is indicated that the failure factors of different types of wildcat wells are similar in some aspects and different in other aspects. As for their similarities, migration-accumulation matching condition is the top one factor for the failure of wildcat wells, mainly referring to migration direction and migration pathway, trap condition takes the second place, including the uncertainty of structural trap form and the sealing of fault, and the failure caused by caprock and preservation conditions is less. The differences are as follows. The failure caused by reservoir condition is obvious in deepwater area, deep layer, buried hill, lithologic trap, stratigraphic trap and combination trap, while source rock and caprock occupy a certain proportion for the failure of wildcat wells in shallow water area. Besides, the failure caused by poor fault sealing is relatively common in fault control traps, and the confrmation of lithologic trap and structural-lithologic trap is faced with larger risks. In the following exploration, it is necessary to strengthen the researches on migration-accumulation matching condition and trap condition. And for different types of targets, it is also necessary to focus on the prominent risk factors and carry out the specifc study to reduce the risks.

Overpressure is quite common and pressure structures are complex in Dongying sag. The overpressure structures are obviously diverse at different depth in different strata and different tectonic belts. The differences of overpressure structures in Dongying sag and their controlling factors were analyzed in detail by investigating the measured formation pressure, the acoustic log response characteristics of mudstone and the overpressure characteristics of seismic velocity spectrum in this sag. It is shown that the overpressure structures in Dongying sag present obvious zoning characteristics. Vertically, the overpressure is mainly developed in the depth of 2200-4500 m, and its main bodies are mainly developed in Es3 and Es4. Areally, the overpressure is mainly developed in Lijin, Niuzhuang, Boxing and Minfeng subsags. The overpressure amplitude is the highest in Lijin subsag, secondarily in Minfeng and Niuzhuang subsags and the lowest in Boxing subsag. The diversity of overpressure structures is closely related to the structural pattern, the evolution degree of source rocks and the activity of faults. The spatial variation of pressure feld is controlled by the structural pattern of salient alternating with subsag, and the distribution and amplitude of overpressure are dependent on the distribution and thermal evolution degree of source rocks, and the boundary of overpressure system is dominated by long-term inherited major faults.

Natural gas hydrates are solid, ice-like clathrates formed with hydrocarbon gases (mainly methane) and water under appropriate temperature and pressure conditions. Different from conventional hydrocarbon reservoir systems, the key factors controlling gas hydrate accumulation mainly involve stable natural gas hydrates, water source, natural gas source, fluid migration and reservoir space conditions. The accumulation factors of natural gas hydrates determine that gas hydrate production from stable gas hydrate zones is neither continuous nor stochastic, and gas hydrates in different geological settings have different distributions and geological characteristics. Natural gas hydrate accumulation and enrichment controlling factors involve the following points:Controlled by temperature and pressure, natural gas hydrates are dynamically formed, accumulated and distributed in stable gas hydrate zones; natural gas hydrates are contained in loose sediments at relatively shallow layers after the Later Miocene, generally 0-500 m below seabed; natural gas hydrates are generally of low abundance, extensive distribution and local enrichment, and with concentrated "sweet spots" zones; natural gas hydrates have microbiological and thermal genetic characteristics, and their large-area accumulation depends on favorable fluid migration; natural gas hydrates occur in solid form, and their growth and occurrence are diverse, such as in structural, stratigraphic and complex reservoirs.

The Electron Spin Resonance (ESR) dating method introduced into petroleum geology recently can detect the crystallization age of mineral grains such as the quartz hosting primary hydrocarbon inclusions, based on the correlation of paramagnetic center concentration with mineralization age and the content of radioactive elements. The hydrocarbon accumulation periods in the northern Tarim Basin were identifed based on microscopic observation of rock samples taken from the northern Tarim Basin, ESR dating results of quartz vein samples with primary hydrocarbon inclusions in different stages, and previous K-Ar dating results of authigenic illite samples. The results show that hydrocarbon accumulation in the northern Tarim Basin were developed in four periods. The frst primary hydrocarbon inclusions are liquid with brown fluorescence, and generated in 376Ma (Late Caledonian to Early Hercynian). The second are liquid with yellow fluorescence, and generated from 293.49 to 242.0Ma (Late Hercynian). The third are gas-liquid with blue fluorescence, and generated from 49 to 32.8Ma (Early Himalayan stage. The fourth are local gas inclusions in black, and generated from 24.0 to 8.5Ma(Late Himalayan).

Haian depression in the Subei Basin is a half graben-like faulted depression which is developed in the Late Cretaceous, and its early exploration mainly focuses on Paleogene Taizhou Formation. It has been deemed for a long period that Funing Formation is thick in the cover and thin inside with limited resources. As the exploration idea is innovatively transformed, three hydrocarbon bearing zones including Zhangjiaduo, Qutang and Xiangyang-Huji are discovered successively in Funing Formation in the south of Haian depression, and their submitted cumulative proved reserves during the 12th Five-Year Plan are 1353×10⁴t. The following cognitions are obtained based on the practical exploration of lithological oil reservoirs in the south of Haian depression. First, there is a "compartment" source-reservoir system with hydrocarbon generation and accumulation in the late stage in the south of Haian depression and it is characterized by effcient hydrocarbon expulsion and accumulation. The amount of resources in Qutang sub-depression of Haian depression is recalculated and it is up to 9000×10⁴t. Second, the sedimentary model of beach-bar sand in the south of Haian depression is established. The beach-bar sand is developed in Qutang sub-depression. Bar sand is distributed in the shape of EW band and it is mainly concentrated in the area of Zhangjiaduo-Qutang in the north while beach sand is mainly distributed in the south. Third, the hydrocarbon generation and expulsion periods in the south of Haian depression are well matched with the formation period of Ef₃ (Fu 3 Member) trap in time and space, and it is favorable for the formation of lithological oil reservoir of Ef3 beach bar sand. And fourth, the oil reservoirs are areally distributed around the hydrocarbon generating sags and they are controlled by sedimentary microfacies. The vertical distribution of lithological oil reservoirs are dominated by the main source-reservoircaprock assemblages. The long-term active faults are conducting faults which control the accumulation of hydrocarbon.

Mud-fluid diapir structures are developed in the Ledong-Lingshui sag in the Qiongdongnan Basin. Based on seismic interpretation result, the geometric morphology and genetic mechanism of the diapir structures in the Ledong-Lingshui sag and its periphery were analyzed, and the relation between the diapir structures and hydrocarbon accumulation was discussed. The development and evolution of the diapir structures in the Ledong-Lingshui sag is the result of the changes of regional tectonic stress feld and the formation of over pressure system. The over pressure system is the major factor controlling on the formation of the diapir structures. Two types of pressure relief modes control the types and distribution of the diapir structures; therefore,the diapir structures can be divided into two types:transportation and pressure relief through fractures, transportation and pressure relief through faults. The diapir structures formed by transportation and pressure relief through fracturesare chiefly distributed in banded style along the lower part of the central canyon channel, and the spatial coupling of the lower over pressure zone and the central canyon channel is the major element for forming this diapir belt. The diapir structures formed by transportation and pressure relief through faults are chiefly distributed along the faulted belts at northern and southern sides of the Ledong-Lingshui sag, and the centralized flowing and upwarping of plastic rock and fluid caused by the lower over pressure zone and the base fault activity are the major genesis of such diapir structures. The exploration practice in the Ledong-Lingshui sag indicates that the diapirs and faults are the major pathways for vertical hydrocarbon migration, the structural traps and lithological traps associated with diapirism are the favorable exploration targets that should be concerned in this area.

The change laws of hydrochemistry components of 11# coal seam in Hancheng coalbed methane (CBM) feld were investigated. It is determined that there are four types of coal seam water in this feld, including NaHCO₃ type water (salinity lower than 1000 mg/L) dominated by fresh water leaching, NaHCO₃ type water (salinity 1000-3000 mg/L) dominated by mixing, Na₂SO₄ type water (salinity 3000-10000 mg/L) dominated by lixivation and CaCl₂ type water (salinity higher than 10000 mg/L) dominated by concentration. Then, combined with structural characteristics, the hydrochemistry feld was divided into four zones, including HCO₃-Na Zone, HCO₃-Cl-Na zone, SO₄-Cl-Ca-Na zone and Cl-Na zone. Finally, the relationships of hydrochemistry feld of 11# coal seam vs. CBM content and CBM well productivity were studied. It is indicated that it is favorable for CBM enrichment in Cl-Na zone and the CBM well productivity is good. In HCO₃-Na zone, however, it is not favorable for CBM enrichment and the CBM well productivity is poor.

The fault and depression structures in the Lanjia-Helong-Buhai area is very complex and have not been understood comprehensively and regularly in their regional structures and gas reservoir properties for a long time. In order to reveal the relationship between the shallow gas reservoir and the deep hydrocarbon source rock in the Lanjia-Helong-Buhai area, the tectonic analysis theory for gas provinces was used to analyze the basin patterns, tectonic units, and fault evolution characteristics in the fault-depression-reversion stage, and based on which a shallow gas migration and accumulation model was built by incorporating the effects of tectonic reversal on deep faults and stratigraphic sedimentation. The results show that the continuously faulted and the sedimentarily inherited basin patterns had a stable sedimentary environment with regional tectonic subsidence and good source-reservoir-cap rocks assemblages, while the superimposedly inverted basin pattern developed deep faults, unconformities and interlayer detachments, which further communicate the shallow reservoir with the deep source rock, forming a model characterized by "deep hydrocarbon generation-vertical migration-favorable shallow reservoir accumulation". Finally, the main gas transport systems and reservoir types were revealed, and the risk-taking and favorable exploration areas were clearly identifed in different tectonic belts.

The Bongor Basin is a Meso-Cenozoic intracontinental passive rift basin. Its formation and evolution are influenced and controlled by major surrounding tectonic events. Since the Early Cretaceous, influenced by the separation of the African and the South American plates and the Atlantic extension rifting, the basin began to form and continued to extend and rift, forming a series of NW-SE high-dip steep faults; at the end of the Cretaceous, under the compressive stress caused by the forward high-speed collision in NS direction, between the African and the Eurasian plates, the basin underwent strong reversal which resulted in the strata uplifted, denuded and deformed; then at the end of the Paleogene, local compressive stress resulting from the NW-SE extension of the Red Sea led to slight reversal, and some Paleogene formations denuded; since the Neogene, the basin entered stable thermal settlement. The late Cretaceous structural inversion is an important structural event in the process of the basin formation and evolution, which profoundly affected the sedimentation and hydrocarbon accumulation in the basin. The Late Cretaceous structural inversion is characterized by folding and deforming of the strata. Section description indicates three types of fault related inversion structures:single faulted, double faulted and scattered-flowering faulted. Based on the latest research results on the fault dip and inversion stress intensity and inverted structure characteristics, it is believed that although the Late Cretaceous compressive stress is strong, structure inversion didn't occur in the Bongor Basin due to the phenomenon of "locking" resulted from the excessive dip of the basin fault.

Based on the latest oil and gas feld information and petroleum geological data of the Gabon Coastal Basin, it is divided into 6 hydrocarbon plays of two categories (i.e., suprasalt and subsalt) with reservoirs as the core. Among them, Berriasian sandstone play and Aptian sandstone play are located below salt rocks. These subsalt plays are characterized by continental reservoir, salt rock as the overlying barrier and sealing bed and fracture belt as the migration pathway. Albian-Cenomanian sandstone play, Maastrichtian clastic play, Coniacian-Campanian turbidite play and Eocene-Oligocene channel sandstone play are located above salt rocks. And these suprasalt plays are characterized by marine reservoir, salt structure controlling reservoir and salt movement connecting source rock with reservoir. Then, oil and gas resources were evaluated with the play as the unit by means of Monte Carlo method. And according to the calculation results, the resources to be discovered in the Gabon Costal Basin in the following 30 years are 6895×10⁶bbl, including oil resources of 5893×10⁶bbl, natural gas resources of 6005×10⁹ft³ and condensate oil resources of 34×10⁶bbl. It is indicated from the analysis on the characteristics of plays in the Gabon Coastal Basin and the resource evaluation results that Aptian sandstone play is the most favorable exploration target.

The connectivity of karst cave reservoirs is diffcult to identify and affects their effective development. The root causes are attributed to the unclear identifcation of the development periods and distribution rules of the karst cave reservoirs. The method of layered interpretation of karst cave reservoirs was used to predict the distribution of the karst cave reservoirs in different periods. First, on the basis of the knowledge that the cave layers are mainly controlled by underflow surfaces, the paleogeomorphology was restored, and then representative wells were selected from high to low paleogeomorphologic structures, the karst discharge datum was determined, and the cave layers were divided into single wells; second, according to the isochronal sedimentary interfaces, seismic data volumes were flattened, and the cave layers for single wells were calibrated on seismic sections; and fnally, the cave layers were fnely interpreted, the RMS amplitude was extracted, and the lateral distribution of every reservoir layer was predicted. Based on the distribution law of single-layer caves, the connectivity of karst cave reservoirs was analyzed, and 22 Ordovician fracture-cave reservoir units were identifed in the LGX area in the Tarim Basin. This may provide technical support for the effective development of the reservoirs.

Fine reservoir description is the most important foundational work and should be going on with the development of oilfield. Compared with the initial stage of oilfeld development, the research content of fne reservoir description in the middle and late stages usually changes signifcantly and reflects the characteristics of emphasis, profundity and accuracy. The key researches on fne reservoir description in the middle and late stages of development are summarized into eight aspects:fine researches on small faults and microstructures, fine stratigraphic division and comparison under the guidance of high-resolution sequence stratigraphy and other theories, reservoir architecture characterization based on sedimentary microfacies, quantitative evaluation of reservoir microscopic pore structure, reservoir fluid heterogeneity, reservoir changing laws during development, geological modeling based on multi-point geostatistics, and comprehensive remaining oil description based on multiple information. Fine reservoir description in middle and late stages should focus on targeted solutions to key bottlenecks arising out of actual oilfeld development and try to provide basic data for developing the potential of remaining oil and increasing oil recovery in old oilfelds.