In recent years, a large number of special natural gas resources including low-permeability gas reservoirs have vigorously emerged in China with increasing investments. They are expected to dominate the future development of petroleum industry. In China, however, economic evaluations for both low-permeability gas projects and conventional gas projects are conducted with the same methods and parameters. Such indiscrimination may significantly compromise the accuracy of economic evaluation for low-permeability gas projects, and eventually affect the healthy development of such projects. Under this background, geological features and changes of unit operating costs for the low-permeability gas project X in the Sichuan Basin and the conventional gas project S in the Ordos Basin were reviewed to analyse the problems in financial evaluation indicators for the economic evaluation methods currently deployed for low-permeability gas projects in China, and the inadaptability of national economic evaluation methods. Furthermore, certain improvements and reforms were proposed, aiming to make the economic evaluation for low-permeability gas projects in China more rational.

The massive marine shales in the Sichuan Basin and its periphery are one of the key targets for shale gas development in China. According to the drilling data of this region, many complexities often occur during the drilling of shale gas wells to cause wellbore instabilities. Such complexities include borehole collapse, drillpipe blocking/sticking, blowout and lost circulation, which are great challenges for shale gas exploration and development, especially for drilling of horizontal wells and cluster wells. Chongqing area in the east margin of the Sichuan Basin extends across two tectonic units (i.e. the Yangtze paraplatform and the Qinling geosyncline fold system), with complicated geological structures and diverse topography. Regardless of the engineering factors, the complexities occurred during drilling of shale gas wells in this region are found with certain regularity, namely, the wellbore instabilities are closely attributable to geological structures, in-situ stress field distribution, and physical-mechanical properties of rocks, etc. Depending on sedimentary and tectonic evolution histories, and geological conditions, the Chongqing area is divided into four zones (I, II, III, and IV). Shale gas reservoirs in these zones are analyzed for the major factors controlling wellbore instabilities, with considerations to the geological and accumulation characteristics of the reservoirs, as well as the drilling and laboratory data. The results indicate that formation pressure is the major factor for wellbore stability in the central and western Chongqing areas, the risk of wellbore instability is lower in the southeastern Chongqing area if the drilling is conducted away from natural faults, and two zones in the northeastern Chongqing area are susceptible to shear sliding along faults, joints and weak planes as a result of high dip-angle formations and stress deflection.

In recent years, two 100 million-ton class subtle reservoirs were found in the Shijiutuo uplift within the Bohai Sea. Exploration practices have proved that new geological understandings provide theoretical guidance and scientific deployment for hydrocarbon exploration discoveries. The mechanism of ternary-factor (ridge-trap-sand) coupling for controlling reservoir in low-amplitude structure guided the significant discovery of the Neogene structural-lithologic reservoir in extra-shallow water delta in the Shijiutuo uplift. The differential hydrocarbon accumulation mode of subtle reservoirs in basin-margin fault transfer zone in steep slope belt facilitated the discovery of the first 100 million-ton class the Palaeogene stratigraphic-lithologic reservoir in the medium-deep layers in the Bohai oilfield. These new geological understandings further promoted technical researches and innovations. As a result, six key technologies have been developed, including the variable-velocity mapping for shallow low-amplitude structure, the description of lithologic traps in sand-rich extra-shallow water delta, the semi-quantitative fault-sand coupling analysis, the exquisite palaeogeomorphic restoration under the tectonic-sedimentary simulation in medium-deep layers, the identification of stratigraphic-lithologic traps in medium-deep layers, and the testing of complex lithologies in medium-deep layers. These technologies provide technical support and assurance for discovering large subtle reservoirs in the Bohai Sea, playing a prospective role for future promotion and application.

Analysis on field outcrops, well data and seismic data clarifies that the Silurian Shiniulan Formation in southeastern Sichuan Basin presents as a large north-dipping gentle slope, which can be divided to (from south to north) inner gentle slope, central gentle slope and outer gentle slope-continental shelf. The second member of Shiniulan Formation (Shi 2 Member) contains central gentle slope facies belt, with clean water and high energy, and it is composed of reef-beach carbonate deposits. The lithology is mainly of shell limestone, coral limestone and bioclastic limestone. Reef beach is characterized by thickened strata and “bright spot” on seismic profile and represents NE-trending ribbon-pattern distribution along the Xuyong-Well Ximen 1-Wenshui-Well Longsheng 2 in plane. The Yuanhou-Simianshan area is located in the main part of reef-beach zone, with high micro-geomorphology, where the reef-beach dolomite reservoirs are probably developed, suggesting as the favorable exploration prospect of the Shiniulan Formation.

Microscopic pore structure of the Lower Silurian Longmaxi Formation organic matter-rich shale in the Sichuan Basin and its periphery was systematically studied by using argon-ion polishing-scanning electron microscope (SEM), low-temperature liquid nitrogen adsorption/desorption and other techniques and methods. Moreover, the main factors controlling the nano-scale microscopic pore structure were discussed. The results indicate that pores in the Longmaxi Formation organic matter-rich shale in the Sichuan Basin and its periphery are in nano-scale with diverse types, such as organic matter pore, intergranular pore, intragranular pore, intercrystal pore, dissolved pore, and micro-fractures. The organic matter pore and intergranular pore are better developed. The complex microscopic pore structure of the shale is mostly composed of open pores, including cylinder pores and parallel slate pores with open ends. The radius of microscopic pores are typically 2-80 nm, suggesting as medium pores. Analysis reveals that organic carbon content is the major factor controlling the development of nano-scale pores and the important material basis for the occurrence of shale gas.

In the recent years, more and more countries have focused on natural gas hydrate (NGH). In this paper, numerous NGH production technologies and patents at home and abroad were reviewed and the principles of NGH production were presented. Moreover, some conventional production technologies (e.g. thermal stimulation, depressurization, chemical inhibitor and CO2-CH4 exchange) were compared and analyzed for their advantages and disadvantages. Then, several innovative technologies (e.g. hot water injection with a pair of horizontal wells, hot water huff & puff with single well, partial oxidation, electrical heating assisted depressurization, and CO2 swapping depressurization) were discussed in view of principles, innovations, advantages and disadvantages. It is concluded that most of the innovative technologies are based on the thermal production technologies for heavy oil and oil sand etc., and they are usually designed with the combination of depressurization and thermal stimulation to increase the thermal contact area in reservoir and to improve the heat utilization efficiency.

Limy beach-bar reservoirs are developed in the upper part of the fourth member of the Shahejie Formation (the upper Es4) on the southern gentle slope of the Zhanhua sag, the Jiyang depression. Such reservoirs are closely associated with the provenance and hydrodynamic conditions, and their locations and sizes are affected by the sizes and scales of the fans which provide the provenance, resulting in strong reservoir heterogeneity and complex reservoir space. It is difficult to evaluate these reservoirs. In this paper, four methods (i.e. testing data analysis, comprehensive major element quantification, petrophysical facies analysis and mercury intrusion in casting thin sections) were utilized to evaluate and classify the limy beach-bar reservoirs. The results show that the comprehensive major element quantification method and the petrophysical facies analysis method (or the flow zone indicator method) are more suitable for evaluating the limy beach-bar reservoirs, whereas with defects in application. On the basis of accurate analysis of depositional settings, the comprehensive major element quantification method and the petrophysical facies analysis method could be combined to analyze the limy beach-bar reservoirs, in order to avoid the defects and thereby provide more accurate and practical results. Thus the limy beach-bar reservoirs in the upper Es4 of Zhanhua sag are divided into four types (I, II, III and IV). Type I and Type II reservoirs are biolithite, limy fine sandstone and limy siltstone of mouth bar and estuary shoal, with better reservoir conditions. Type III and Type IV reservoirs are mainly limy siltstone and muddy siltstone, with poor reservoir properties.

The North Gabon Subbasin is a composite basin with rift basin and passive continental margin basin superimposed, where a large number of salt structures are developed. Based on the distribution pattern of salt structures in seismic profiles, it is considered that the study area has very thick salt rocks deposited in the Lower Cretaceous Ezanga Formation, and multiple salt structures such as turtleback structure, wedge-shaped diaper and large diaper. Different types of salt structures correspond to different formation stress environments. Based on the distribution regularity of discovered oil and gas reservoirs, it is indicated that the presalt anticline related to salt structure and the lithological traps formed due to turbidite sealing on mudstone control hydrocarbon enrichment.

Based on the stratigraphic sequence and structural characteristics, hydrocarbon accumulation conditions and models as well as main controlling factors of the Congo Basin were studied. The Congo Basin is a depression basin formed due to thermal events and remobilization of removable basement after the Neoproterozoic Kilaran orogenic movement. There are multiple sets of stratigraphic units with hydrocarbon generation potentials in the Congo Basin, among which the Silurian-Devonian Aruwimi Group Alolo Formation shale has the greatest hydrocarbon generation potential. The reservoirs of the Congo Basin include Mesoproterozoic stromatolite reef limestone, Cambrian-Ordovician Bobwamboli Group conglomerate and glutenite, Silurian-Devonian Aruwimi Group Mamungi Formation, Galamboge Formation and Banalia Ark Formation sandstone, Upper Carboniferous-Lower Jurassic Lower Lukuga Group, Upper Lukuga Group and Haute Leuki Group sandstone and glutenite, Upper Jurassic-Lower Cretaceous Stanley Ville Group deltic and channel sandstone, and Middle Cretaceous Loia Formation fluvial-shallow lake facies sheet sand. Syn-rift cap rock is typically local cap rock with limited lateral extension and abrupt change in physical properties. Post-rift cap rock is typically regional cap rock. Preservation condition is the main controlling factor for hydrocarbon accumulation.

The exploration potential of the East Gobi Basin, Mongolia, was evaluated based on the geological features of the Cretaceous play derived from the analysis of tectonic-sedimentary evolution and hydrocarbon accumulation. According to the play division principle, the East Gobi Basin consists of one primary play (the Cretaceous play) and two secondary plays (the Tsagaantsav and the Zuunbayan structural unconformity plays). The main source rock of the Cretaceous play is the dark semi-deep to deep lacustrine shale of the lower Zuunbayan Formation and the Tsagaantsav Formation of the Lower Cretaceous, with high hydrocarbon generation potential. Class I reservoir is composed of braided river delta and fan delta lithic sandstone of the Lower Cretaceous Tsagaantsav Formation, showing good physical properties. Class II reservoir is composed of turbidite, shore-shallow lake and alluvial plain facies sandstone of the Lower Cretaceous Zuunbayan Formation. Cap rock is regional shale and mudstone and regional uncomformity surface wide distributed in the Cretaceous strata. The Cretaceous play, as a self-generating & self-preserving reservoir, mainly contains structural and lithologic traps. Based on the detailed analysis on the geological elements of each play, the undiscovered recoverable resources of the basin were estimated to be 61.7?0⁶ t with the subjective probability method. The evaluation results reveal that the main exploration strata in the East Gobi Basin are Lower Cretaceous strata in the Cretaceous play in vertical. Besides, in plane, the northeastern and central parts of the Unegt subbasin, Zuunbayan subbasin and the southwestern and central parts of the Khovsgol subbasin have sizable exploration potential.

The Cambrian Longwangmiao Formation in central Sichuan Basin contains dolomite reservoirs of grain shoal facies. Such reservoirs are characterized by large burial depth, thin formations, difficult classification of dolomite microfacies in single well, and variable lithofacies in lateral direction. On the basis of the improved Lucia rock structure component identification technology by well logging, this article discussed the lithofacies of dolomite in the Cambrian Longwangmiao Formation in the Moxi-Gaoshiti region in central Sichuan Basin by using the “sedimentary multi-parameter” seismic lithofacies identification technology. Three types of lithofacies were identified, i.e., medium-fine crystalline dolomite lithofacies in grain shoal, crystal powder dolomite lithofacies in lagoon behind the shoal, and micrite dolomite lithofacies in inter-shoal sea. Moreover, it was predicted that the predominant lithofacies (medium-fine crystalline dolomite lithofacies in grain shoal) is distributed in the south and middle parts of the study area.

In order to predict the shale gas production more accurately by typical curves and thereby to instruct and optimize the development program design, the shale gas production decline typical curve models were reviewed. These models include Arps typical curve models (incl. hyperbolic decline curve, exponential decline curve and harmonic decline curve), modified hyperbolic decline model, power law exponent model, hybrid model, and Duong’s model. These models were separately elaborated from the aspects of principles, advantages and disadvantages. These models were compared based on the data of a shale gas well. Results show that the ultimate recoverable reserves (EUR) predicted by hyperbolic decline model is the largest among the models, but the prediction results of other models should be further demonstrated depending on fluid and reservoir characteristics. With consideration to certain defects in the models revealed by the study, it is suggested to strengthen the researches on basic theories. Moreover, the probability method is recommended to define the probability range of typical curves, so that the production risk can be accurately evaluated.

Mitigation of reservoir damage during water flooding is critical for efficient development of offshore oil fields. In this paper, analysis of reservoir sensitivity and SEM analysis of suspended solids and scale samples were conducted for the water flooding process in a block, the Bohai Oilfield, during which some problems like higher injection pressure and insufficient injection exist. The experiment results indicate that the reservoir is susceptible to moderate-stronger water-sensitive damage, or plugging due to swelling and dispersion of smectite and illite/montmorillonite interlayer to various degrees. The content of suspended solids in injected water is up to 16.7 mg/L, which is much higher than the standard requirement. The size of particles in injected water are chiefly about 30 μm, which may easily cause plugging in the reservoir. After water flushing, a large amount of carbonate particles scatter in the pores and throats of the reservoir, decreasing the reservoir permeability. On the basis of the defined reservoir damage mechanism, some protective measures (e.g. optimization of doping way and acidification) were put forward. In practical operations, injection pressure at the wellhead of water flooding well dropped by 7 MPa, and daily water-injection volume increased by 6 times, revealing the obvious unplugging effect by acidification.

“Sweet points” are main exploration targets for shale oil reservoir. It is necessary to subdivide the reservoir into layers. Shale oil reservoir is characterized by multiple thin interbeds and unapparent petrophysical features. A single log can not accurately reflect its comprehensive formation, which brings challenges to automatic layering based on logs and subsequent activities. This paper proposes a new layering method with multiple information. Firstly, logs with high vertical resolution and high sensitivity to layer boundaries are selected, and the selected logs are processed by the sliding weighted filtering method to remove random noises without compromising thin-layer information. Then, the filtered logs are dimensionally reduced by classified principal component analysis, so as to remove the correlation (information overlap) and mitigate the influence of multiple correlation on dimensionality reducing results. Finally, an integrated log is obtained from the filtered logs after dimensionality reducing, which improves the signal/noise ratio (SNR) and keeps thin-layer information efficiently through compounding the information of multiple logs. The method proposed in this paper is verified by the activity method and the inflection-point method which are simple and operable. Most thin layers can be automatically divided. The good application results reveal the efficiency and feasibility of this method in complex reservoir with thin interbeds.

Based on the different logging responses in lithologic, electric, physical and radioactive properties of the seventh member of the Yanchang Formation (Chang 7 Member) in the central-western Ordos Basin, two innovative logging-lithology identification methods have been developed, i.e. cross-plot method and Vsh–TOC method. The former method can be used to identify sandstones, siltstones, mudstones and tuffs by crossing the well logs with lithology, while the latter method can be used to identify sandstones, siltstones, mudstones and high-organic shale through calculating the shale content (Vsh) and organic carbon content (TOC). By comparing the calculation results with test results and core samples, both methods are determined to have accuracy above 86%. Results of lithology identification for 240 wells within the study area were used to generate planar and cross sections. It is indicated that shales are widely and continuously developed at the top of the Chang 7 Member in the study area and reduce upwards; sandstones are distributed in the northern, eastern and northeastern parts of the study area, as well as the southern and southwestern parts. As time goes by, the isolate sand bodies in the central part of the study area increased both in area and quantity, and eventually formed the large distribution in Chang 7₁.