Since the breakthrough was made in Well Central Tarim 1 in 2008, oil and gas exploration in the Cambrian-Ordovician dolomite buried hills has been continued in the Tarim Basin. Except that effective exploration and development was carried out in the Yaha-Yingmaili Cambrian dolomite buried hill in the northern North Tarim uplift, only two wells, Central Tarim 1 and Shan 1, revealed oil and gas in the Central Tarim uplift-Bachu uplift belt. All regional exploration operations failed, and the exploration in the dolomite buried hills in this belt almost stalled for over 20 years. In 2016, after further understanding of the structural model and analysis of the hydrocarbon accumulation conditions, two wells (Ross 2 and Zhonggu 58) were drilled in the Maigaiti slope and the eastern Central Tarim uplift, respectively, and delivered high-yield of industrial oil and gas flow from the dolomite buried hills. This recorded a new discovery in the exploration of dolomite buried hills and indicated the important exploration value in the Cambrian-Ordovician dolomite buried hills. Re-processing and re-interpretation of 2D and 3D seismic data confirmed three dolomite buried hill zones in the eastern Central Tarim uplift, the Luonan- Niaoshan structural belt and the East Mahu structural belt, covering a favorable area of 1600 km₂. Reservoirs in the dolomite buried hills are characterized by shallow depth (3500-5500 m) and high exploration efficiency, showing large exploration potentials.

In recent years, a series of progress and breakthroughs have been made in the conventional and unconventional natural gas exploration in the Sichuan Basin, and the geological cognitions and resource potentials have been updated constantly. At present, it is in urgent need to assess the natural gas resources in the Sichuan Basin comprehensively, so as to figure out the natural gas resources and provide a basis for promoting the exploration and development of natural gas in this basin. In this paper, the exploration progress in the Sichuan Basin during the past decade was analyzed, the types of assessed resources were determined, and the assessment targets and methods were defined. According to the assessment, the conventional gas in place is 20.69×10¹²m³ (recoverable: 11.20×10¹²m³), including tight gas 5.87×10¹²m³ (recoverable: 2.35×10¹²m³), and shale gas 57.46×10¹²m³ (recoverable: 10.01×10¹²m³). Moreover, the distribution laws of natural gas resources were summarized, and the reasons for the differences between the current assessment results and the previous ones were illustrated. It is indicated that the natural gas resources in the Sichuan Basin are abundant with great potentials, with promising exploration and development. It is recommended to strengthen deep and ultra-deep explorations, to promote multi-formation stereoscopic exploration, and to speed up unconventional oil and gas exploration, so as to develop the natural gas resources rapidly and sustainably. In order to keep the rapid development of natural gas exploration, it is necessary to reinforce the studies on petroleum geological theories, exploration and development technologies, resource investigation and assessment, and management system reform.

Based on various principles, the assessment methods for conventional hydrocarbon resources are divided into five categories, i.e., genetic method, volumetric method, statistical method, analogy method and expert evaluation method. The genetic method is popular in China, while the statistical method and analogy method are dominant in other countries. In this paper, all these methods were illustrated systematically in respect of applicability, advantages, disadvantages and main progress. The genetic method, statistical method and analogy method are more matured with significant progresses. The source-rock limited space method is noteworthy, for which more efforts are required on its theory and application. The expert evaluation method is less studied, for which further efforts are in urgency. It is pointed out that the future hydrocarbon resource evaluation should focus on hierarchy evaluation of hydrocarbon resources, spatial distribution prediction of remaining resources, deep-ultra-deep resource evaluation, hydrocarbon resource assessment system based on basin simulation and big data application technologies as well as the combination of multiple methods, expert decision analysis system and economic evaluation.

This paper analyzed the main factors controlling shale gas enrichment in the Wufeng Formation–Longmaxi Formation
based on the basic geological characteristics of the Jiaoshiba area in the Fuling shale gas field. The study’s results indicate both
that the high-quality shale of the deep-water continental shelf facies in the Wufeng Formation–Longmaxi Formation is beneficial
to the generation of shale gas and that the organic matter abundance of shale is positively correlated with its gas content, as it provides
the material basis for the enrichment of shale gas. A higher organic matter abundance and a moderate degree of thermal
evolution are favorable for the development of organic pores, which provide a favorable reservoir space for the accumulation of
shale gas. Good roof and floor conditions and the formation of an over-pressure separate compartment provide good preservation
conditions for shale gas enrichment, which serves as the key factor controlling the enrichment and high productivity of shale gas.

Based on the extensive investigation of related literatures in China and abroad, the latest seismic data reprocessing and interpretation results, and the latest collections of foreign geological studies, systemic summarization and analysis were completed on the tectonic evolution, sedimentary characteristics, and petroleum geological conditions in the Beikang Basin. The results show that the Beikang Basin generally experienced three tectonic evolution stages, i.e. fault depression, depression and regional subsidence, giving rise to delta facies, littoral neritic facies, and bathyal-abyssal facies, or carbonate platform in local paleo-uplifts. Three sets of source rocks are developed in the Middle Eocene, the Upper Eocene-Lower Oligocene, and the Upper Oligocene-Lower Miocene, respectively. Oil and gas reservoirs have been identified within the Paleogene sandstone and the Middle Miocene limestone/reef limestone. The Pliocene-Quaternary mudstone acts as the regional caprock. In conclusion, the Beikang Basin has huge potentials of oil and gas resources, with geological resources of oil and gas of 8.86×10⁸t and 14855×10⁸m³, respectively.

According to the systematic analysis of hydrocarbon accumulation conditions, hydrocarbon distribution and reservoir-controlling factors, the shallow-middle reservoirs in No.1 structure of the Nanpu sag are above-source reservoirs where hydrocarbons came from the third and first members of Shahejie Formation and the third member of the Dongying Formation. Laterally, hydrocarbons are mainly distributed in the major part of the structure, and abundant on both sides of the oil-migrating fault; hydrocarbons are dispersed farther from the major part of the structure. Vertically, there are many oil-bearing horizons with long oil producing intervals, and the oil-bearing intervals are concentrated; the farther from the source rocks, the less hydrocarbons are accumulated; hydrocarbons are mainly endowned in the first member of Dongying Formation and the fourth member of Guantao Formation under the thick regional volcanic cap-rocks. The characteristics of hydrocarbon distribution are closely related to several reservoir-controlling factors. First, the inherited positive structure is a favorable destination of hydrocarbon migration, and hydrocarbons may probably accumulate within the traps with conducting system. Second, oil-migrating fault is a key element for hydrocarbon accumulation, and it constitutes a complex conducting system with the sand framework, through which hydrocarbons migrate into shallow-middle favorable traps. Third, local low-relief structure, lateral volcanic sealing and overlying cap-rocks are favorable factors for the formation of structural-lithologic reservoirs. Fourth, good reservoir sand types and facies belts are favorable for hydrocarbon accumulation.

In this paper, the middle section of the third member of Shahejie Formation (middle Es₃) in the Gubei subsag was taken as an example to investigate the effects of lime mudstone on reservoir prediction. A reservoir prediction method which can eliminate such effects was proposed. Firstly, comparisons on conventional logs indicate that acoustic (AC), density (DEN), gamma-ray (GR), spontaneous potential (SP) and wave impedance (WI) logs are not sensitive in distinguishing lime mudstone from sandstone. Secondly, petrophysical characteristics and logging data were analyzed, revealing that shale content curve play a remarkable role in distinguishing lime mudstone from sandstone, so it can be used as the sensitivity curve for lime mudstone and sandstone distinguishing. Finally, it was proposed to improve the reservoir prediction precision utilizing geostatistical inversion technology based on the preferred sensitivity curve and the established isochronous stratigraphic framework. The prediction result of this method is in higher coincidence with the actual drilling result. It is demonstrated that this method can eliminate the effects of lime mudstone effectively, characterize the morphology of fans accurately and meet the requirements of exploration deployment.

The 3D geologic reservoir modeling is used to characterize the geologic characteristics of reservoir in three dimensions, and it provides the basis for revealing reservoir characteristics and searching for favorable targets in the process of exploration and development. In the Longgang gasfield, the Sichuan Basin, oolitic-beach carbonate reservoirs are strongly heterogeneous and the well pattern density of the study area is low. In view of these characteristics, a series of facies-control carbonate reservoir modeling technologies were developed with individual-well interpretation data as the hard data and seismic attribute volume data as the constraints. These technologies integrate geologic, drilling, logging, and seismic data. With this method, the advantage of small-scale vertical fine well data and the high lateral resolution of seismic data are combined effectively to improve the inter-well prediction rationality and the geologic model accuracy. The three-dimensional distribution characteristics of reservoirs are reproduced by the modeling results, thus providing a valuable basis for the detailed prospecting, formlation and adjustment of development plans.

In order to understand the origin of dolomitic tight oil reservoir of the Lower Cretaceous Arshan Formation in the Erenoar sag, the Erlian Basin, on the basis of sedimentary structure and volcanic activity analysis, the core observation, thin section identification and physical mercury analysis as well as geochemical analysis such as carbon and oxygen isotope were employed to systematically investigate the petrology, origin, distribution and reservoir space of dolomitic tight oil reservoir and to preliminarily discuss the exploration potential of this kind of reservoir. The research results show that the reservoir is mainly composed of dolomitic tuffite, dolomitic mudstone and dolomitic siltstone, with the porosity of 1%-5% and the permeability of 0.008-2.8 mD, suggesting as low-ultra low porosity and extra low-ultra low permeability type reservoir. The reservoir space comprises inter-crystalline pores and micro-fractures. The dolomite in the dolomitic rock is usually hypidiomorphic-allotriomorphic and micrite-powder crystal, with high carbon isotope (from -1.50‰ to 5.20‰) and high V/Ni (from 1.57 to 4.56), indicating terrestrial brackish-brine evaporating environment. The dolomite in the dolomitic mudstone and tuffite contains high carbon and oxygen isotopes, and the dolomite crystals exist in the tuffaceous and argillaceous matrix, mainly related to CH₄ generation. The dolomite in the dolomitic siltstone contains low carbon and oxygen isotopes, which is influenced by burial depth and hydrocarbon generation. The Mg²⁺ in the dolomitic rock came from the deep marble and granite, and also from the volcanic matter and the hydrolytic alteration of feldspar grain. In addition, during the development of dolomitic rock, the volcano eruption triggered the mass mortality of the lake organism, making organic matters endowed to facilitate the cultivation of methanogens bacteria, which provided the dynamic conditions for the dolomite growth during the early stage. The hydrocarbon generation and expulsion of the source rocks during the late stage enabled the oil and gas to preserve in the inter-crystalline pores and micro-fractures, providing good storage space for tight oil.

The Cambrian Niutitang Formation in southern Guizhou is very thick, and has well-developed floor with relatively effective sealing capacity. This formation can be divided into two sections. The first section, the primary target of shale gas, is composed of black carbonaceous shale of semi-deep and deep water continental shelf facies interbedded with siltstone, 99 m thick. The second section is composed of gray siltstone and shale of shallow-water continental shelf facies, 165m thick. Sampling analysis was made on Well MY-1, the only shale gas exploratory well drilled within the Niutitang Formation in southern Guizhou. The results show that the black shale in the first section of the Niutitang Formation reveals the TOC of 0.39%-5.35%, the vitrinite reflectance (R_o) of 1.56%-2.48% (2.06% on average), and the Type I kerogen with maceral dominated by amorphous sapropelites. The rock contains quartz and clay minerals, with higher content of brittle minerals (generally higher than 50%). Both the porosity and the permeability are low, 1.13%-2.23% and 0.0011-0.0082 mD, respectively. The total gas content is up to 1.13m³/t. Well MY-1 reveals that the Cambrian Niutitang Formation in southern Guizhou has better geological conditions for shale gas reservoirs, and large potential for further exploration of shale gas.

A lot of researches were conducted so as to systematically evaluate the geological conditions for shale gas accumulation in the lower Cambrian Qiongzhusi Formation, Yunnan province, including field surveys on 18 geological sections, TOC and Ro measurements on 110 shale samples, mineral composition measurement on 22 shale samples with X-ray diffraction technique, porosity and permeability analysis on 9 shale samples with mercury intrusion porosimetry (MIP) and nitrogen adsorption techniques, and shale pore type analysis with SEM. The results show that the Qiongzhusi outcrop is located in the northeastern, eastern and northwestern parts of Yunnan, and is deeply buried in the western and southern parts due to tectonic movements. The Qiongzhusi Formation was deposited under a broad epicontinental sea environment, where the widespread continental shelf environment was beneficial for the enrichment of organic matters. The organic-rich shale is characterized by large thickness (generally>30 m), high organic matter abundance (average TOC>2%), high thermal evolution of organic matters (mainly Type Ⅰ and Ⅱ₁ ), high content of brittle minerals (averagely>70%), well-developed pores with good connectivity, and the maximum adsorbed gas of 3.755 cm³/g on average. Compared to the shale in the Sichuan Basin and North America, the Qiongzhusi Formation in Yunnan holds good shale gas accumulation conditions and can be considered as the target for shale gas exploration.

The apparent formation water resistivity (R_wa) is an important parameter of well logging interpretation. It is usually used, together with the true formation water resistivity (R_w), to identify the properties of reservoir fluids. For low-contrast continental reservoirs, however, the properties of formation water vary greatly, thus the wrong conclusion is often reached if the same R_w is used in the same area to identify oil reservoirs. In this paper, the formation water resistivity (R_{w_sp}) was calculated layer by layer on the basis of spontaneous potential curve. Then, R_{w_sp}, as the substitute for R_w, was used for comprehensive interpretation combined with R_wa. This method is quite capable of identifying lowcontrast oil layers in continental reservoirs with remarkable practical results.

In this paper, the Eagle Ford shale play in the USA was taken as an example to discuss the logging-based shale play evaluation methods and identify the main geological factors controlling shale gas production. The logging data of this area is mainly conventional, and the core analysis data is relatively abundant. The logging data of key wells in this area were processed and interpreted by means of multivariate statistics modeling method and multi-mineral optimization method, respectively. The results indicate that the reservoir parameters calculated by the multivariate statistics modeling method are better consistent with core analysis data, presenting higher accuracy. The production is quite different in zones of the Eagle Ford shale play, and it is mainly controlled by porosity. The production sweet spot of shale gas can be predicted by using the P-wave impedance of seismic inversion.

In the North Tluwa Oilfield at the east margin of the Pre-Caspian Basin, the complex carbonate reservoirs are commonly characterized by complicated geological structure, variable boundary and thickness of target layers, and low ROP in lower highly-abrasive lime mudstone. In addition, for achieving higher production per well, the horizontal section of a horizontal well has been increased from 400 m to 1000 m, which brings great challenges to the control over borehole trajectory and quality. To cope with the challenges, integration and application of drilling technologies in a long horizontal-section well were carried out, and the optimized and fast drilling technology involving the rotary steerable drilling system, the Stinger bit and the PeriScope system was developed. This technology was firstly applied in Well H814 in the North Tluwa Oilfield with good results. Specifically, the rotary steerable drilling system made it possible for rotary drilling in the target layer and reduced drilling risks, the stinger bit realized a ROP more than doubled, and the PeriScope system provided precise localization of pay zones and improved the reservoir-encountered rate from 55% to 83.9%. The optimized and fast drilling technology can be promoted to other oilfields in the Pre-Caspian Basin where the strata are developed regularly.