The Sinian-Cambrian Formation of Sichuan Basin has favorable hydrocarbon accumulation conditions, but the difficulty in exploration of large gas field is increased due to old strata and multiple tectonic movements. After 49 years of arduous exploration since the Weiyuan Sinian large gas field was found in 1964, the largest mono-block gas field (Anyue gas field) was discovered in Cambrian Longwangmiao Formation of Moxi Region in 2013, with proven geological gas reserves of 4 404×10⁸m³. The proved, probable and possible reserves totally exceed trillion cubic meters in Sinian Dengying Formation and Cambrian Longwangmiao Formation, Gaoshiti-Moxi Region. The gas components, light hydrocarbon, reservoir bitumen abundance and other evidences prove that the natural gas is dominantly constituted of oil-cracking dry gas, including methane (82.65%-97.35%), ethane (0.01%-0.29%), low nitrogen (0.44%-6.13%), low helium(0.015%-0.06%), and medium-low hydrogen sulphide(0.62-61.11 g/m³). Gas reservoir pressure is gradually increased from Sinian ordinary pressure (1.07-1.13) to high pressure (1.53-1.70) in Cambrian Longwangmiao Formation. The temperature of gas reservoir is 137.5-163℃. Gas reservoir traps are divided into three categories, i.e., structural trap, stratigraphic structural combination trap and lithologic structural combination trap. The large-scale enrichment of Sinian-Cambrian natural gas is resulted from the large stable inherited paleo-uplift during Tongwan tectonization, wide distribution of ancient hydrocarbon source rocks, vast porous high-quality reservoirs, crude oil cracking of large paleo-reservoir and favorable preservation conditions. According to the paleo-structure pattern and bitumen abundance before crude oil cracking, and distribution characteristics of current gas reservoirs, the accumulation patterns of cracking gas reservoir can be classified into three types, i.e., aggregation type, semi-aggregation and semi-dispersion type and dispersion type. The above understanding will play an important guiding role in the exploration of Sinian-Cambrian natural gas in Sichuan Basin.

Based on low-temperature samples pre-treatment technology in combination with geological analysis, the quantitative evaluation method for residual hydrocarbons in shale was built using chloroform bitumen "A" and pyrolysis parameters. Through comparison of components in the crude oil of self-generating and self-preserving reservoir and chloroform extract from source rock, this paper presents the curve of relationship between light hydrocarbon of chloroform bitumen "A" and source rock hydrocarbons in the main oil generation window of Dongying sag: the recovery coefficient of the former varies with evolution of the latter. The recovery coefficient is small when R_o is less than 0.5%, and increase significantly when R_o is greater than 0.7%; the value will be greater than 1.4 when R_o is 1.2%. Through comparison between the fresh frozen and normal temperature preserved samples, a method for measuring the lost light hydrocarbons during pyrolysis process and the losing coefficient in different evolutionary stages were established in this study. The losing coefficient changes in a similar way as the recovery coefficient of chloroform bitumen "A". Moreover, residual hydrocarbon ratios of the pyrolysis hydrocarbon S₂ in different evolution stages of source rock are obtained by contrastive pyrolytic analysis of the original samples and extraction residues. In the mature stage(R_o is 0.8%), the ratio is above 50%. Based on above methods, an objective evaluation can be made on the content of residual hydrocarbons in shale, which is of great significance for oil and gas evaluation.

Salt rock is mostly developed in Dongpu sag in Bohai Bay Basin, of which the Paleogene Shahejie Formation has mainly developed four sets of salt rocks with thickness of more than 1000 meters. However, there are many disputes on the origin of salt rock. Preliminary studies have been carried using sedimentological and geochemical methods. The salt rock has alternately developed with mud shale of layered sedimentary structure, and the average V/(V+Ni) ratio of mud shale is 0.736 (basically distributed within 0.64-0.81), which has developed halite hopper crystals mixed with sandy debris-flow massive sandstone; these features indicate the mud shale with layered sedimentary structure has been deposited in the strong reducing environment of deep to semi-deep lake. There is no exposed surface eroded between the salt rock and mud shale, and no mud crack structure in the mud shale layer; the salt rock is relatively pure with large thickness. Therefore, it can be concluded that the sedimentary environment of salt rock is the same as the adjacent mud shale, i.e., the strong reducing environment of deep to semi-deep lake. Vertically, the salt rock is developed in the lacustrine transgressive system tract and high stand system tract of sequence, and the development period of salt rock is also the main chasmic and expanding stage of Dongpu sag; horizontally, it is distributed in the center of the sag and has a reciprocal relationship with the sandstone deposited in the margin of the sag, whereas the mud shale is mainly distributed in the broad area between the sandstone and salt rock, i.e., depocenter of the salt rock is basically identical with deposition center and subsidence center of the sag. The development period of salt rock is also a peak period of the development of lake basin. Sedimentary evidences support the viewpoint of "salt deposited in deep water" for the salt rock of Dongpu sag. In the continuously deposited section of salt rock, δ³⁷Cl values is not gradually decreasing from the old strata to the new, but showing irregular changes. These illustrate the salt rock of Paleogene Shahejie Formation of Dongpu sag should have developed in an environment with deep water under warm and wet weather, i.e., "salt deposited in deep water". Moreover, it is illustrated through comparison with modern canyon lakes and artificial river reservoirs that Dongpu sag is obviously characterized by lake stratification during the development period of salt rock, providing the basis and basic form for "salt deposited in deep water", and theoretically supporting the viewpoint of "salt deposited in deep water" for salt rock of Dongpu sag.

Large scale turbidite bodies are developed in Miocene stratum in northern Lower Congo Basin, and form a number of typical stractural-lithologic combination traps. High drilling cost is caused by deep water of 500-1 500 m. Then reservoir and oil-gas detection before drilling is the main way to reduce the risk of oil and gas exploration in this area. The spatial distribution pattern of the strong amplitude in seismic data volume described using post-stack seismic attributes can be derived by analyzing the petrophysical properties and seismic response characteristics of the oil-bearing reservoir of Miocene turbidite sandstone in Mohm, KTNSM and Tomboco oilfields in northern and central Lower Congo Basin; the lithology of seismic anomaly bodies with turbidite channel distribution pattern can be predicted using P-S wave velocity ratio; and based on the description of sand reservoirs, the fluid type in sandstone pore can be effectively identified with pre-stack reconstructed Poisson impedance technique. By applying the combination of techniques above, new potential exploration targets are identified and discovered before drilling in Block H in northern and central Lower Congo Basin, and their spatial distribution scope and characteristics are also predicted and described. It is proved for some targets that the actual drilling results are completely identical with the pre-drilling prediction, achieving a good practical application effect and providing a reference for prediction of reservoirs and oil-gas resources in the turbidite sandstone of Lower Congo Basin and other coastal basins in West Africa.

Since most oil reservoirs of deepwater channel are located in abysmal area, the well spacing is large as limited by operation cost, and thus it is difficult to obtain the depositional quantitative relationship between channels through multi-well fitting in dense well pattern. Therefore, the quantitative relationship and sedimentary characteristics of deepwater channel in slope area were studied using the high-frequency seismic data of deepwater shallow sediments of Gengibre oilfield in west Africa, thus guiding the simulation of channel reservoirs in deep-buried sparse well pattern of oilfield. Then a deepwater channel simulation scheme was proposed based on depositional quantitative analysis. The results show that single channel presents an overall migration pattern, which includes migration along palaeo-current and lateral migration. The quantitative analysis results indicate there exists a relatively good positive correlation between the width and depth of single channel. The shallow-layer high-frequency seismic data compensates for the low resolution of deep-layer seismic data. Object-based simulation method is more applicable for deepwater channels in sparse well pattern, and the simulation result is consistent with geological knowledge. The integration of quantitative depositional knowledge into sedimentary facies modeling has expanded the idea of reservoir modeling and is worth to be promoted. The research result can not only improve the quantitative distributional pattern of deepwater channel, but also has a practical value for effectively developing deepwater channel reservoirs.

Lithologic reservoirs have become the important targets of onshore oil exploration in China, and studies on their formation conditions and processes provide a guide for continental hydrocarbon exploration. Since the exploration of lighologic reservoirs in western Qaidam Basin is still in the starting stage, there are insufficient researches on hydrocarbon accumulation process. Aiming at Hongliuquan oil reservoirs in the south of western Qaidam Basin, fluid inclusion, crude-oil geochemical and quantitative fluorescent analyses were conducted in this study. On this basis, the evolutionary process of Hongliuquan oil reservoir was analyzed in terms of fluid evolution. The results show that the crude oil in the lower reservoir of Lower Ganchaigou Formation of Hongliuquan is originated from the parent source rocks of saline lacustrine basin, which is homologous low-maturity crude oil with consistent characteristics. However, there exists no high-maturity crude oil. In this region, three kinds of hydrocarbon inclusions were developed, i.e., low-maturity yellow fluorescent gas-liquid hydrocarbon inclusions in the early stage, blue fluorescent gas-liquid hydrocarbon inclusions and associated gas inclusions in the late stage. This oil reservoir underwent a formation process from low-maturity oil charging in the late sedimentary stage of Ganchaigou Formation (about 26 Ma) to the sedimentary stage of upper oil sand formation (5 Ma), till current adjustment and transformation of hydrocarbon accumulation. Blue fluorescent gas-liquid hydrocarbon inclusions and gas hydrocarbon inclusions are the products of low-maturity hydrocarbon in the early stage through fractionation and degasification in the process of adjusting and migrating upwards to shallow layer along the fault translocation system formed in the late tectonism.

To clarify the stages and evolution process of hydrocarbon accumulation is presently the key issue of exploring Mesozoic-Cenozoic reservoirs in Yingmaili area of Tabei uplift, Tarim Basin. A detailed study was carried out to determine the properties of petroleum inclusions and the stages of hydrocarbon accumulation in Mesozoic-Cenozoic reservoirs using rock samples from typical wells, through a combination of microscopic examination, micro-beam fluorescence spectroscopy, and micro-thermometric technique. Results showed that petroleum inclusions in reservoirs rocks mainly emitted blue, blue-white, bright yellow, and weak yellow fluorescence. Peak wavelengths of the fluorescence spectra were mainly distributed in the ranges of 470-490 nm and 510-540 nm, corresponding to blue-white and yellow fluorescence, respectively. Of these, petroleum inclusions emitting yellow fluorescence had the red-green quotient of 0.48-0.65 and the chromaticity of 0.345-0.360 (CIE-X) and 0.358-0.375 (CIE-Y), whereas the corresponding brine inclusions had the main peak of homogeneous temperatures at 80-90°C. Differently, petroleum inclusions emitting blue-white fluorescence had the red-green quotient of 0.20-0.51, CIE-X of 0.302-0.333, and CIE-Y of 0.325-0.352, whereas the corresponding brine inclusions had the main peak of homogeneous temperatures at 120-130℃. Combined with simulation analysis of burial history and thermal evolution history, two-stage hydrocarbon accumulation was identified in Mesozoic-Cenozoic reservoirs in Yingmaili area: in the first stage (8-5 Ma), mainly normal reservoirs were formed with relatively low maturity and petroleum inclusions emitting yellow fluorescence; and in the second stage (since 3 Ma), mainly condensate reservoirs were formed with relatively high maturity and petroleum inclusions emitting blue-white fluorescence.

To accurately orient the core fracture of deviated boreholes, the research thought and corresponding algorithm was proposed based on attitude of rocks and dip-logging method, and then applied to the observation data of core fracture of Tian-33 fault block. The actual attitude of fracture can be obtained only through hole-deviation correction. Before correction, the core fracture of Tian-33 fault block is mainly near north-south trending. After correction, it is dominantly near east-west trending, which is consistent with the late-stage dynamic development data and regional tectonic stress field of this oil field. Through analysis of the correction data, it is concluded that whether hole-deviation correction is required should not be determined simply by the relative value of hole deviation angle; strata and fracture dip angle also have an impact on fracture dip. Moreover, the above correction algorithm is also applicable for observing the core of other linear and planar geological bodies.

The logging evaluation methods for fracturing performance in tight gas reservoirs were studied from two aspects, i.e., brittleness index and fracture toughness of the tight sandstone. Summarization and comparative analysis were made on the experimental determination method and the method for calculating brittleness index of the tight gas reservoir based on logging data. Then a brittleness index prediction model with favorable applicability was established in this study. To avoid the shortage due to the single use of brittleness index for fracturing evaluation, linear elastic fracture theory was adopted to create the fracturing performance index through combination of brittleness index and fracture toughness, indicating the criterion of screening favorable fracturing strata, i.e., higher brittleness index and stronger hydraulic fracturing ability. Therefore, those with higher and lower fracturing performance index can be considered as fracturing strata and fracturing barriers respectively. Taking Well S in tight sandstone strata of the Ordos Basin as a case, a model for fracturing performance index of the tight gas reservoir was built, thus forming the flows of fracturing logging evaluation technology.

Due to the presence of electric double layer at the solid-liquid interface, fluid flow in porous media can give rise to streaming potential which in turn influences the fluid flow. In this study, the impact of streaming potential on fluid flow is investigated at the micro-/nanoscale by resolving different sizes of capillary models of circular, square, and triangular cross sections using finite element numerical method. The relationships between conductivities in triangular capillaries of different sizes and their corresponding shape factors are examined by considering streaming potential. Additionally, the relationship between flow rate in capillaries of different sizes and their external pressure gradients are investigated. Results show that streaming potential strongly impacts fluid flow in capillaries when the size of the capillary is comparable to the thickness of the electric double layer. Due to the impact of streaming potential, flow resistance of the fluid increases while the conductivities in capillaries decrease. However, the relationship between flow rate and pressure gradient in capillaries remains linear.

The study area is located in Sazhong development zone of Daqing oilfield, with the maximum well density of 280 wells/km² on average in China. Taking the P1-3 thin sand layer of braided river in this area as the research object, the underground reservoir sand bodies and their internal architectures are finely explored through identification of the falling-silt seams in single well and prediction analysis of architecture interface using well-to-well correlation method based on abundant actual well data. Further, the 6-level architecture classification scheme for sand bodies is improved herein; it is also concluded that the sand bodies have a sedimentary architecture model featured by gentle down-flow progradation and multi-stage vertical accretion. On this basis, statistical analyses are conducted on geometric parameters and occurrence of the interlayers (a great majority of falling-silt seams) in braided river reservoirs, and thus a geological knowledge database about falling-silt seams is built. Finally, a three-dimensional geological model based on 3-level architecture interface is set up and provides reliable evidences for exploring reservoir sand bodies of braided river in the whole area.

Conventional water-oil two-phase thermal recovery modeling for numerical simulation of waterflooding in high pour point oil reservoir only considers the effects of changes in viscosity and relative permeability curves with varying temperatures. This approach is unable to characterize the damage of wax solid deposition to formation permeability, although such permeability changes form the premise for application of relative permeability curves at different temperatures. To address this issue, solid deposition modeling is used to simulate the development of high pour point oil reservoir, and a novel numerical simulation method of oil-water-solid three-phase thermal recovery modeling is developed. A comparison analysis of thermal modeling data between the three-and two-phase methods shows that damage to formation permeability by wax deposition is the most significant factor influencing early waterflooding in high pour point oil field. Additionally, quantitative information including the radius of wax deposition and the extent of permeability damage at different injection temperatures are obtained through thermal recovery modeling. The results have great implications for better studying and predicting the dynamic characteristics of waterflooding in high pour point oil field.

A polymer viscosifying agent with ultra-high temperature resistant ability was synthetized by the method of micellar free radical emulsion polymerization which using N-vinyl caprolactam as temperature sensitive monomer, sodium styrene sulfonate as hydrophilic monomer and N,N-methylene bis acrylamide as crosslinking agent. In order to research its viscosity and temperature sensitivity in low density drilling fluid, elemental analysis, gel permeation chromatography analysis, TG-DTA analysis and acute toxicity experiment were carried to indicate the elemental composition, molecular weight, thermal stability and EC₅₀ value of this viscosifying agent at the optimum synthetic conditions determined by orthogonal test. Based on the study of the thickening mechanism, a high temperature resistant emitted sea water-based drilling fluid with low density suitable for Bohai Bay region was built and flied test was also carried. The results showed that: this polymer viscosifying agent had excellent ultra-high temperature resistance and salt resistance viscosifying property, thermal stability and thermo sensitive characteristics. The apparent viscosity retention rate after aging were 90.81% and 95.95% respectively and the EC₅₀ value was 15.529×10⁴ mg/L at 220℃,after 16h in both fresh water based mud and salt water based mud which can satisfy the requirement of the emitted sea water-based drilling fluid technology. Field application shows that this new polymer viscosifying agent could play an effective viscosifying role even though at harsh conditions such as ultra-high temperature and low density drilling fluid system which decreasing daily performance maintenance problems at the expense of the large consumption of fluid additive including conventional sulfonate copolymer.

Unsteady flow caused by runaway/overload of mud pump can seriously damage the equipment, easily raising security risks in drilling operations. This study constructs a mathematical model for predicting surge pressure in pump suction line caused by accidents such as runaway/overload of mud pump in drilling operations. Model construction is based on considerations of drilling mud compressibility and drill string elasticity, combined with special structures of wellhead mud pump and its pipeline. The proposed model is solved using computer programming through an example study. Under standpipe pressure of 18 MPa, surge pressures caused by runaway and overload of dual mud pumps are up to 6.77 and 11.59 MPa, respectively. With increasing number of mud pumps, the inertia in high-speed operation of mud pumps is increased, thereby elevating surge pressure in the pipeline. With increasing length of the pipeline, the frictional resistance of fluctuating pressure is increased, while its conversion from kinetic to pressure energy is reduced. These changes ultimately result in a reduction in fluctuating pressure and a time lag in fluctuating pressure super imposition in the pipeline.

During the process of reservoir drilling, inaccurate pressure prediction can cause gas kicks, which will result in transient gas-liquid two-phase flow and lead to dramatic variations in wellbore pressure, significantly raising well control risks. This study aimed to reveal the evolution pattern of wellbore pressure during gas kicks. Visualization simulation was conducted using a large-scale experimental system to measure the variations in wellbore pressure and observe the physical characteristics of annular flow during gas kicks. This engineering process was then simplified into a continuous injection process at the bottom of a vertical concentric annular tube under liquid circulation. A transient two-phase flow prediction model was further developed based on transient flow theory and drift flux model to simulate the simplified process. The established model capable of tracking flow parameters (e.g., location of gas-liquid interface) was numerically solved using the semi-implicit finite difference algorithm. The experimental data show that when gas injection starts from the bottom, annular pressure first increases and then decreases. Peak pressure occurs in the lower part earlier than in the upper part of the annular tube, and the extent of pressure variation decreases with increasing depth. High coincidence between the simulation and experimental data indicates that the developed model can be used to predict the characteristics of transient flow in the wellbore during gas kicks. The results further the understanding about the evolution of wellbore pressure during gas kicks and diversify hydraulic models of drilling under complex conditions.

Deep strata is defined as the stratigraphic field with buried depth greater than 4 500 m in hydrocarbon basins. All around the world, a total of 1 477 hydrocarbon reservoirs have been discovered in deep and ultra-deep strata (with buried depth greater than 6 000 m), of which hydrocarbon reserves account for 40% and 49% of the total respectively. At present, annual hydrocarbon reserves discovered in deep Tarim Basin, China account for more than 90% of the total discovery. With the increasing demand for oil and gas resources in the world, the deep hydrocarbon exploration is sped up, thus leading to more challenges. Therefore, the research on the differences in hydrocarbon accumulation conditions, geological and distribution characteristics of hydrocarbon reservoirs between deep and mid-shallow reservoirs has important practical significance to reveal and clarify the deep hydrocarbon accumulation mechanism and distribution laws. Research results have indicated that six great differences exist in deep hydrocarbon accumulation conditions involving source rocks, reservoir, cap rocks, migration, trap and preservation from mid-shallow strata. Thus, the criteria and methods established based on researches on the geological conditions of mid-shallow hydrocarbon cannot be used to judge and evaluate the geological conditions of deep hydrocarbon and its exploration prospect. Moreover, great differences also exist in trap type, reservoir characteristics, fluid phase state, temperature and pressure environment and other aspects between deep and mid-shallow hydrocarbon reservoirs. As a result, the mid-shallow hydrocarbon accumulation mode and exploration experience could not be applied to guide the prediction and exploration of deep hydrocarbon reservoirs. In addition, deep hydrocarbon reservoirs have their own characteristics of distribution and development in different types of basins, different ages of formation and different burial depth conditions. Thus, the existing understanding of mid-shallow reservoirs cannot be completely applied to determine exploration direction and drilling target, and it is required to make a decision based on the actual geological conditions.

The analyses were carried out on carbon, oxygen and strontium isotopes and rare earth elements (REEs) of the unaltered muddy-micritic dolomites, pore-rich dolomite reservoirs altered by corrosion (including coarse crystalline sucrosic dolomite) and pore-filling coarse crystalline dolomites in Sinian Dengying Formation of the southern China, so as to identify the type, process and mechanism of fluid alternation in the development process of dolomite reservoirs. The average values of δ¹³C, δ¹⁸O and ⁸⁷Sr/⁸⁶Sr of unaltered dolomites are 3.0‰, -3.5‰ and 0.708 779 respectively. There is no significant Ce and Eu anomaly in REE composition, indicating normal dolomites formed by the action of seawater. The average values of δ¹³C, δ¹⁸O and ⁸⁷Sr/⁸⁶Sr of altered sucrosic dolomites are 1.7‰, -7.7‰ and 0.709579 respectively. The carbon and oxygen isotope compositions are slightly lighter and ⁸⁷Sr/⁸⁶Sr ratio is higher than unaltered dolomites. Moreover, altered dolomites have higher REE content and significant negative Ce anomaly (δCe average = 0.5). It is proven that pore-rich sucrosic dolomite reservoirs are the products of meteoric water and oil-bearing fluid alteration. The average values of δ¹³C, δ¹⁸O and ⁸⁷Sr/⁸⁶Sr of pore-filling coarse crystalline dolomites are 0.3‰, -11.3‰ and 0.710 334 respectively. The carbon and oxygen isotope compositions are significantly lighter, while ⁸⁷Sr/⁸⁶Sr ratio is markedly higher. Meanwhile, there is significant positive Eu anomaly (δEu average = 3.0, maximum δEu = 9.8). It is demonstrated that pore-filling dolomites were precipitated from hydrothermal fluids and affected by organically generated stratigraphic fluids.Based on the identified fluid types and geological evolution background, the fluid alteration process and mechanism of dolomite reservoirs in Dengying Formation were discussed in this study. Muddy-micritic dolomite sediments with seawater platform facies were developed in Sinian Dengying Formation of the southern China, where laminar algal structure was shown in some zones. At the end of Sinian period, the dolomites in Dengying Formation were altered by meteoric water, and then infiltrated to deep subsurface, promoting dolomite dissolution and recrystallization. In the subsequent burial process, these dolomites further underwent the dissolution and alteration of oil-bearing fluids. As a result, coarse crystalline dolomite reservoirs were formed rich in dissolution pores and bitumen. Due to alteration of hydrothermal fluids in the burial process, pores were filled by dolomites, leading to densification of dolomite reservoirs to a certain extent.

The western mid-Yangtze area has experienced multi-cycle sedimentary and tectonic evolution, where multiple sets of resource-reservoir-cap assemblages are developed. The source rocks consist of diversified lithologies, such as carbonaceous shale, carbonate rock and coal, most of which enter the over-maturity stage. The deep Sinian-Cambrian source rocks are in the late period of over-mature stage, characterized by multi-stage hydrocarbon generation and crude-oil cracking gas in the late period. In the multi-cycle tectonic evolution, marine natural gas in the western mid-Yangtze area showed a complex accumulation process of multi-source multi-stage or consanguineous multi-stage mixed aggregation, multiphase adjustment and secondary changes in the late period. Based on previous research results and analyses for geological evolution background of the study area, regional effective chief source rocks were explored, and then the geochemical characteristics of natural gas in Jiannan gasfield were analyzed according to the component content of natural gas, the correlation between component parameters, carbon isotope of alkane gas and other data. In combination with regional hydrocarbon accumulation geology and gas zones of eastern Sichuan Basin, the genesis and source of marine natural gas in Jiannan gasfield, the western mid-Yangtze area were clarified. Studies have indicated that marine natural gas in Jiannan gasfield is dry gas; alkane gas shows certain carbon isotopic reversal, and crude oil cracking has occurred for gas supply. The gas reservoirs of Permian Changxing Formation, Lower Triassic Feixianguan Formation and Jialingjiang Formation were derived from Permian source rocks. There is basically no Silurian or deeper gas-source supply. The natural gas in Jiannan gasfield is generated from mixed aggregation between crude-oil cracking gas and multi-type kerogen degradation gas, of which crude-oil cracking gas is dominant. The gas reservoirs of Silurian Hanjiadian Formation and Carboniferous Huanglong Formation are consisted of consanguineous multi-stage natural gases, of which crude-oil cracking gas is dominant. Meanwhile, the parent material for gas source is carbonaceous shale in Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation, rarely charged by natural gas of Sinian-Cambrian source rocks. Therefore, a huge potential exists in the exploration of marine natural gas in the western mid-Yangtze area, especially dominated by the western Hubei-eastern Chongqing area with good preservation condition. Moreover, Sinian, Cambrian and Silurian natural gases have a favorable exploration prospect.

Analcime-dolomite reservoir from Shahejie Formation in Well Tang10 block of Dagang oilfield is a kind of unconventional reservoir, which is characterized with unique mineral composition and fracture. This paper tried to summarize the general characteristics of this kind of reservoir and discuss the control factors of reservoir quality, using data from thin section observation, X-ray diffraction analysis, scanning electron microscope analysis, physical property analysis, high-pressure mercury porosimetry, and nitrogen adsorption analysis. The rock mainly comprises ankerite, analcime, quartz, feldspar, and illite. It is common to find that lamina associations are presented in laminated dolomite and laminated argillaceous dolomite,including analcime-rich lamina+ankerite-lamina, silt-rich lamina+ankerite-lamina, analcime-rich lamina+algae lamina+ankerite-rich lamina, and mud-rich lamina+ankerite-rich lamina association. Vug and fracture are two types of macroscopic pores, while vug in analcime-fillings, intercrystalline pore, intracrystalline pore, and micro fracture are dominantly microscopic pores. Average porosity is 12.73% for dolomite and 10.39% for argillaceous dolomite; average permeability is 0.009 3mD for dolomite and 0.143 7mD for argillaceous dolomite. There is no distinct link between porosity and permeability. The reservoir share the feature of fine pore and throat diameter as well as complicated connection. Average pore volume is 20.45 mm³/g for dolomite and 23.46 mm³/g for argillaceous dolomite; average micro-mega pore ratio is 38.32% for dolomite and 55.7% for argillaceous dolomite; average surface-volume ratio is 0.83×10⁷/m for dolomite and 0.932 5×10⁷/m for argillaceous dolomite; average threshold pressure is 4.68 MPa; average median pore diameter is 0.047 μm; average tortuosity is 83.681; average maximum pore diameter is 0.279 μm. Further analysis showed that: (1)the rocks with black organic grain texture can get porosity increased by about 2%~6%; (2) micro-mega pore predominate in reservoir space; (3) the increase of carbonate content will decrease the porosity; (4) clay minerals, quartz and feldspar have positive relation with macro pore. With these evidences at hand, we concluded that the intracrystalline pore in diagenetic analcime is the dominant reservoir space of the rocks and the sedimentary layer containing black organic grain will enhance the porosity, which make the sedimentation and diagenesis the major control factors of porosity. The diagenetic and tectonic factors were considered to be the major control factors of permeability for the following reasons: the permeability is chiefly controlled by fine diameter of pore and throat as well as complex relation between pore and throat. Microfracture, though improved the permeability also, have only limited effect.

Southwestern Tarim depression and its periphery are important strategic replacement regions of hydrocarbon exploration and new reserve growth points in Tarim Basin. Succeeding oil and gas breakthroughs in recent years have brought this region into the new spotlight of exploration frontiers. In this study, a total of 32 crude oil and oil sand samples were selected from Bashituo-Yasongdi oil and gas field, Kekeya oil and gas field, Kashi sag and Yubei area, southwestern Tarim Basin, which were used for crude oil group composition, gas chromatography, gas chromatography-mass spectrometer and carbon isotope analysis to determine typical geochemical characteristics of crude oil and oil seepage samples in southwestern Tarim Basin, precisely divide crude oil and groups as well as reveal the genetic types of crude oil. Research has indicated that Bashituo crude oil group, Kekeya crude oil group, Kelatuocrude oil group and Yubeicrude oil group are identified in the periphery of Makit slope of southwestern Tarim Basin. The Well Qiong 002, Qiong 003, Qun 5 and Qun 7 belong to Bashituo crude oil group. The Well BT4, Qu 1 and Qiong 003 are located at the footwall of Selibuya thrust fault belt, which may be influenced by the contributions of deep Cambrian source rocks, but still belong to Bashituo group though differences exist in geochemical characteristics compared with Bashituo crude oil. Located at the hanging wall of Selibuya fault belt, Well BT2 has significantly different molecular geochemical characteristics from Bashituo crude oil, which may be contributed from Cambrian source rocks. Bashituo crude oil has certain contrastive relations with typical Ordovician source rocks in craton area collected from Well LN46 and TZ30, which may be contributed from Carboniferous source rocks, and is classified as hybrid-source hydrocarbon reservoirs. Saturated hydrocarbon gas chromatography indicates that there are at least two stages of hydrocarbon charging. Well Kedong 1 belongs to Kekeyacrude oil group. Oil source correlation shows that Kekeya crude oil has a good contrastive correlation to Jurassic source rocks. Differences have been identified between crude oil and oil sands in Kashi sag, of which crude oil is sourced from Lower Jurassic source rocks in Kangsu Formation, and has a contrastive relation with source rocks in Yangye Formation. Moreover, oil sands have a comparative relation with Lower Carboniferous source rocks, while geochemical characteristics of the Well YB1 and YB1-2X in Yubei area have the same relation with those of Bashituo crude oil group. The complex genetic relation between abundant hydrocarbon and multi-set source beds shows a broad prospect in the hydrocarbon exploration of southwestern Tarim Basin.

The basins group, located at the Central Africa Shear Zone in African continent, shows diversified morphologies as controlled by the tectonism of surrounding plates, mainly presenting the tectonic styles such as strike-slip and reverse structures, etc. In recent years, a series of large and middle oil and gas fields have been found as the global hot spots for exploration. Based on the seismic and drilling data of petroliferous basins in Central Africa Shear Zone, in combination with the characteristics of planar basin morphology and tectonic geological cross profile, the genetic mechanism and tectonic types of these basins were deeply explored using the concept of tectonic stress field and structure analytical method, so as to further reveal the controlling influence of basin formation and evolution on hydrocarbon geological conditions. It is considered in this study that affected by the structure of surrounding plates, multi-stage superimposed tectonic-stratigraphic sequences were formed in the basins group since the Early Cretaceous, experiencing three episodes of rifting. Episode 1 shows the most intense rifting with right-lateral strike-slip tensile property, and is the original motive and decisive factor for basins group; the rifting of Episode 2 had less influence with the intensity weakened from east to west. The rifting period exists in Episode 3, and mainly has influences on the development of Eastern Basins. In combination with the variation characteristics of strike-slip stress field on the plane and profile, the Early Cretaceous basins group in Central Africa Shear Zone can be divided into three genetic types: T-R type basin, T-R' type basin and S/P type basin (T, R, R', S and P represent tension fissure plane, Riedel shear fracture plane, conjugate Riedel shear fracture plane, compressive plane and low-angle strike-slip fracture plane respectively). As a result, a set of complete strike-slip basin system with comprehensive support was created in the shear zone as a whole. In the three episodes of basin rifting, multiple trap types were developed due to the tectonic evolution with genetic differences. They have distinctive hydrocarbon enrichment characteristics, i.e., Eastern Basins are the most favorable hydrocarbon accumulation zones; Western Basins also have broad hydrocarbon exploration prospects; due to complex basin-controlling faults, the potential of Central Basins remains to be discovered further.

Tight oil sandstone reservoirs are characterized by low porosity, low permeability, diversified mineral components and complex pore structures, leading to a great challenge for rock physics modeling. Based on the specialty of tight oil sandstone, seismic rock physics model of tight oil sandstone was improved from two aspects, i.e., solid components and pore structures of the rocks, so as to achieve the rock physics modeling for anisotropic tight oil sandstone based on double-porosity theory. Moreover, the influences of four factors, i.e., clay content and type, pore connectivity and type, on rock physics modeling were studied systematically using the new theoretical model. The results show that the clay, pore connectivity and pore type will have great impacts on tight oil sandstone, proving the rationality of rock physics modeling.

The air flooding technology has a broad development potential because of its gas source and price advantages, but the security problem has always been a major factor limiting its application. A study was conducted on the low-temperature oxidation catalytic technology, aiming to accelerate the oxygen consumption rate, reduce oxygen content in the generated flue gas and improve the safety of air flooding. Then the catalyst and its dosage was determined by evaluating the catalytic effect of transition metal elements on low-temperature oxidation reaction. The influences of temperature, pressure, water content and rock minerals on catalytic performance were also studied. Meanwhile, multi-tube parallel experiments were carried out to study the characteristics of low-temperature oxidation reaction in different stages. The catalytic mechanism of low-temperature oxidation catalytic reaction was investigated on the basis of kinetic parameter calculation and infrared spectrum analysis. The experimental results show that the transition metal element Cu has a good catalytic effect on the low-temperature oxidation reaction of crude oil; CuCl₂ is selected as the optimal catalyst, and its optimal dosage is 0.88% of the crude oil mass; the reaction rate can be increased by nearly a double under the reservoir conditions. The rising temperature and pressure can promote the low-temperature oxidation reaction, and the low-temperature oxidation catalytic effect is significant within the designed temperature, pressure and reaction stages. The mechanism of catalyst for the low-temperature oxidation reaction of crude oil was coordination catalysis, which can reduce the reaction activation energy significantly, accelerate the low-temperature oxidation reaction rate and enhance the oxygen consumption ability of crude oil.

When water flooding reservoirs enter the ultra-high water cut stage, the relationship between the ratio of oil-water relative permeability and water saturation will deviate from a straight line, as well as the conventional water flooding characteristic curve. In the meantime, great errors will be caused by the use of conventional water flooding characteristic curve for predicting development indicators. Aiming at this phenomenon, this study puts forward a new percolation characteristic relationship, i.e., expression of the relationship between the ratio of oil-water relative permeability and water saturation. This expression can be used for high-precision fitting on the relationship between the ratio of oil-water relative permeability and water saturation in the mid-late stage. On this basis, a new water flooding characteristic curve is deduced using reservoir engineering method. A comparison is made between new and conventional water flooding characteristic curves based on numerical simulation result and field data of reservoirs. The results show that the new water flooding characteristic curve has a better adaptability for data fitting at the high and ultra-high water cut stages, thus solving the problem of upward bending curve at the ultra-high water cut stage and large prediction errors. This method is proven to have better on-site application values.

Aiming at the different fissure network stimulated patterns for stimulated reservoir volume (SRV)-fractured horizontal wells in tight oil reservoirs; a mathematic unsteady well flow model was established in consideration of the dual porosity property of matrix natural fissures and flowing characteristics of the fissure network stimulation system based on discrete-fracture mode. Galerkin weighted residual finite element method was used for numerical solution of the model, and the accuracy of this algorithm was verified by comparison with Zerzar analytical model. Then this study points out the difference in flowing patterns between dual porosity-dual permeability model and dual porosity-single permeability model, and reveals the unsteady pressure and productivity features of SRV-fractured horizontal wells in tight oil reservoirs. The research results show that in case of dual porosity and dual permeability, the horizontal-well bottom hole pressure drop changes slowly; the formation linear flow no longer appears; the pressure propagates to reservoir boundary quickly. The initial production of SRV-fractured horizontal well is large but declined quickly. Under different stimulated patterns, significant differences existed in the pressure and production of horizontal wells at the middle flow stage. The fissure network stimulated pattern with no spacing and overlapping in each fracturing segment is advantageous to increase single-well production.

Nano-pores are dominantly developed in shale. Due to microscale effect, the gas flow in nano-pores is different from that in conventional pores. Therefore, Darcy's law based on the continuous medium assumption is no longer applicable. Shale gas reservoirs are generally under a high pressure environment with denser gas, so that the ideal gas state equation is also inapplicable. However, the lattice Boltzmann method is a mesoscopic flow simulation method, which is not based on the continuum assumption, but suitable for gas flow simulation from slip zones to transition zones as considering the influences of gas denseness and non-ideal gas state equation. Based on the lattice Boltzmann method for non-ideal gas in considerations of the influences of Knudsen layer and microscale effect, as well as slip boundary conditions in mirror reflection-bounce back pattern, a two-dimensional plate model was used to study the influences of pore size, pressure and temperature on microscale effect and analyze the influence mechanisms. The results show that Knudsen number is the control parameter of microscale gas flow. The influences of various parameters on microscale effect are smaller in slip zones and free molecular flow zones, but it is opposite to the transition zones. The variation relationship between Knudsen number and the ratios of apparent permeability and intrinsic permeability, the accuracy of the commonly-used calculation model of apparent permeability in shale gas reservoirs is verified through comparison with the two-dimensional plate model.

The conventional prediction methods of borehole stability are not suitable for directional wells. Based on the rock mechanics and seismic inversion principles, a new prediction method of directional well stability while drilling is presented in two operation steps, i.e., pre-drilling prediction and while-drilling correction. According to the quantitative relationship between seismic data and rock mechanic parameters, a nonlinear model was created with seismic records and borehole stability parameters including pore pressure, geo-stress, rock strength and etc. On this basis, borehole stability parameters are directly inversed using seismic data, so as to further predict borehole stability before drilling and provide a foundation for drilling design. According to the construction situation of directional wells, real time inversion is applied in actual drilling for while-drilling correction and upgrade of pre-drilling borehole stability data model, so as to timely optimize and adjust drilling schemes with the purpose of avoiding complex engineering fault. This method has been applied in Fuling shale gas field, and constitutes the field operation scheme of borehole stability prediction together with the drilling process of "well factory". The field application shows that this method has high prediction accuracy and good performance of real time operation, advantageous to safe and fast drilling of directional wells.

External squeeze pressure of casing for creep layers should be calculated in consideration of the combined effect between creep relaxation time and cement sheath performance. However, the present calculation model takes no account of both influences, leading to large deviations in calculation results. An external squeeze pressure viscoelasticity model of casing under the creep layers was established as considering the effect of cement sheath, which aims to study the influences of relaxation time, stratum stiffness and cement sheath performance on the external squeeze pressure of casing. The results show that without consideration of cement sheath effect, the external squeeze pressure of creep-layer casing is equal to that of non-creep-layer casing; in consideration of cement sheath effect, the external squeeze pressure of creep-layer casing depends on cement sheath performance. Different from the previous understanding that the external squeeze pressure of creep casing is mainly influenced by geo-stress and creep rate, the main influential factors for external squeeze pressure of creep-layer casing also include relaxation time and stratum stiffness, which have impacts on the size and peak of external squeeze pressure as well as the changing trends of stable value. In consideration of internal pressure and cement sheath effect, the external squeeze pressure of creep-layer casing obtained in this study is rather larger than that calculated in line with the casing design standard SY/T 5724-2008. Further discussions are still required for the calculation method of external squeeze pressure of creep-layer casing in this standard. The established model and experimental results were used for comparative analysis on the external squeeze pressure of casing in creep salt-gypsum beds of Missan oilfield in Iraq and Zhongyuan Wenzhong oilfield in China. The conclusion has been achieved that in case of the same geo-stress and creep relaxation time, stratum stiffness is different and the external squeeze pressure of casing varies greatly, consistent with the onsite situation.

Based on analyses on research status of foreign conventional and unconventional hydrocarbon resource assessment methods, the key conventional hydrocarbon resource assessment methods and brand-new unconventional hydrocarbon resource assessment methods were summarized in this study. It is pointed out that knowledge fusion of multiple methods, multiple disciplines and multiple domains is the development direction of hydrocarbon assessment method, and integration of computer visualization technology with quantitative prediction for spatial distribution of hydrocarbon resources is the developing orientation of assessment technologies. The deficiencies of China's hydrocarbon resource assessment systems are analyzed based on the characteristics of all previous hydrocarbon resource assessments in China, so as to select the optimal assessment methods for current hydrocarbon exploration. On this basis, the conventional and unconventional hydrocarbon resource evaluation methodology and assessment system are developed. In this study, the structure and main function modules of assessment system are introduced, as well as five major technologies, i.e., the conventional and unconventional hydrocarbon resource assessment technology with small patch method as a core, 3D three-phase Darcy flow simulation technology, analogy assessment technology based on dissection of calibrated units, economic and environment evaluation technology, and database management technology based on WEB-GIS technology. Moreover, the popularization and application prospect of such assessment system is expected.

Crude oil is widely distributed at the southern margin of Junggar Basin, which presents different geochemical characteristics in various areas. According to carbon isotope and biomarker composition characteristics, crude oil herein can be divided into four typical types. The first type is characterized by light carbon isotope compositions, whole oil δ¹³C generally less than -29‰, gentle carbon isotopic distribution of n-alkane, δ¹³C generally less than -28‰, abundant β-carrotane, sterane dominated by regular sterane C₂₈ and C₂₉, low diasterane content, and great changes in gammacerane content. The second type is characterized by heavy carbon isotope compositions, whole oil δ¹³C generally ranged within -28‰ and -26‰, gentle carbon isotopic distribution in n-alkane, δ¹³C generally greater than -28‰, high Pr/Ph ratio, sterane dominated by regular sterane C₂₉ and diasterane, tricyclic terpane dominated by C₁₉, and very low gammacerane content. The third type is characterized by light carbon isotope compositions, whole-oil δ¹³C generally less than -29‰, carbon isotopic distribution in n-alkane (above C₉) dramatically decreased with the carbon number increasing, δ¹³C ranged within -27‰ and -34‰, Pr/Ph ratio less than 1.0, sterane C₂₇, C₂₈ and C₂₉ in "V" shaped distribution, high contents of isocholestane and diasterane, as well as Ts, C₂₉Ts and C₃₀ rearranged hopanes, Ts/Tm >1, high content of gammacerane with two isomers, and high sterane/terpane ratio. The fourth type is characterized by heavy carbon isotope compositions, whole-oil δ¹³C generally ranged within -28‰ and -26‰, carbon isotopic distribution in n-alkane (above C₉) dramatically decreased with the carbon number increasing, δ¹³C ranged within -23‰ and -29‰, sterane C₂₇, C₂₈ and C₂₉ in "V" shaped distribution and dominated by ααα-20R, low abundance of isocholestane, extremely abundant dinosteranes, tricyclic terpane dominated by C₁₉, and low content of gammacerane.

Through a comparison between geochemical data of wellhead gas in domestic and overseas shale gas wells and commonly-used identification indices of natural gas, it is considered that anomalies exist in certain characteristics of shale gas as compared with the identification indexes of conventional gas source, mainly shown as below. The rollover or reversal of ethane carbon isotope in shale gas generally exists in highly or over matured shale systems, including coal measure strata. The ethane carbon isotope presents an ability of gas source identification derived from isotopic rollover, but in the high evolution stage, the coal-derived ethane isotope may become very light and reach the oil type gas standard. In an open system, the conventional reservoirs may not inherit the ethane carbon isotope and its reversal in shale system, while the ethane carbon isotope of conventional oil type gas can also be very heavy. In the ultra-high evolution stage, a second rollover of ethane carbon isotope can be detected in oil type gas, and the methane hydrogen isotope is abnormally light, while methane carbon isotope is abnormally heavy with extremely high aridity coefficient. The light hydrocarbon shows coal-derived gas characteristics, which might be misjudged as coal-derived gas according to commonly-used Bernard diagram, Scholl diagram and C₇ light hydrocarbon triangular diagram. Conventional natural gas is derived from source rocks, and has inherited the multiple geochemical characteristics of shale gas. This geochemical "anomaly" could lead to misjudgment of gas source types, which should be paid more attentions in the identification process of conventional natural gas.