The annual output of crude oil reach 3 000×10⁴ t in the Bohai Sea, accounting for about 70% of offshore oil production in China. Bohai oildom is located at the central and eastern Cenozoic intracontinental rift basins in Bohai Bay, with an exploration area of about 4.5×10⁴km². Bohai oildom has distinctive petroleum geological characteristics; the famous Tan-Lu Fracture Belt pass through the Bohai Sea from north to south; Neogene fault activities are intensive, which accelerate the vertical oil migration, but is not conducive to the reservoir preservation; fluvial-lacustrine sediments are developed during the Miocene-Pliocene period, in the upper part of which reservoir-caprock assemblage is widely distributed, creating conditions for shallow petroleum accumulation; Paleogene source rocks are buried deep, and Neogene reservoirs and cover rocks are relatively shallow; the petroleum migration path is complicated with long vertical migration distance. According to the complicated geological conditions of the Bohai Sea, after 20 years of exploration in cognition-practice-recognition mode, 7 innovative academic ideas have been proposed as below: (1) the large fault-sandbody transfer station mode has strong migration ability; (2) the migration ability of small faults and strike slip faults is weak; (3) the formation-fault assemblage determines the place where hydrocarbon accumulates; (4) critical cover controls the formation of oil fields in the active fault belt; (5) the oil collecting area in the trap determines oil field scale; (6) the distribution of main oil fields can be divided into salient enrichment type and sag enrichment type; (7) drape anticlines on a small salient are favorable for the formation of large oil fields. These ideas constitute the shallow hydrocarbon migration and accumulation theory for guiding actual exploration. Through a comprehensive study, the Bohai exploration team found 7 large oil fields and 17 middle-scale oil fields in a short time, and the total geological reserves amount to 27×10⁸m³, laying the reserve base of the second largest oil field in China.

Geologic, geophysical and drilling data were used to prepare the thickness distribution maps of Changchengian, Jixian and Nanhuan systems in China's major craton basins, so as to preliminarily prove the distribution of Precambrian rift. The Precambrian rift centers of North China and Yangtze cratons are embodied by a set of rift sequence rapidly changing from coarse to fine. It is judged from isochronal comparison framework of the existing rifting strata that the Meso-Neoproterozic source rocks in Ordos Basin and Sichuan Basin hinterland were less developed than the rift center areas beyond the basin coverage. However, the Neoproterozoic rifts in the southern and northern Tarim Basin have different distribution patterns, formation ages and genetic evolutions. The rifting in the southern Tarim Basin was related to the mantle plume effect with South China continent (constituted by Yangtze Craton and Huaxia Craton) as the center, while the rifts in the northern Tarim Basin were mainly formed by the back-arc expanding due to Panthalassa subduction around the Rodinia supercontinent. The rifts in the southern Tarim Basin were opened later than Huanan by 20-40 Ma, but earlier than the northern Tarim Basin by 40 Ma. The Precambrian rift evolution played an important role in controlling the Early Cambrian sedimentary basins, for which the latter is characterized by "forward similarity" rather than "backward similarity". In Tarim and Yangtze areas, Precambrian basins had significant inheritances from Nanhua-Sinian rift basins. In North China, Qingbaikou rifting center migrated towards southeast, controlling the development location and transgressive direction of the Early Cambrian basin. Based on the current researches, the development location, scale and distribution characteristics of Precambrian rift in China's old cratons still show a diversity and complexity in dynamics, leading to different views and conclusions on filling evolution and exploration values. Besides enhancing seismic data processing to further pinpoint concealed rifts within the basin, recent researches should also focus on rifting sequence identification, stratigraphic correlation and filling modeling, attempting to determine the Precambrian rift types and solve evolutionary dynamic problems, so as to restore the basin prototype in the stages closely related to hydrocarbon-generation and prove the distribution laws of source rocks.

To study the formation and evolution of organic pores in shale, the thermal simulation experiments of diagenesis and hydrocarbon generating under the constraint of a whole series of immature-low mature-mature-high mature-overmature geological conditions were conducted. Using Ar-ion milling-field emission scanning electron microscopy to analyze microscopic characteristics of original samples and samples used for simulating reactions of different evolution stages, the research shows:(1) Organic pores can be formed in the process of hydrocarbon generation caused by biochemical action and low temperature heat action in the immature stage and low mature stage, and the shallow buried depth at that time may be conducive to preserving organic pores; (2) The formation and evolution of organic pores is characterized by heterogeneity, and maturity is not the decisive factor controlling the formation and development of organic pores. The difference in physical-chemical structure of organic matter plays an important role in the formation and evolution of organic pores; (3) There is an obvious correlation between the development of organic pores and retention oil. Organic pores generated in the stage of hydrocarbon generation are easy to be occupied by heat decomposed pitch; (4) Constricted fissure/marginal pore of organic matter may be an important space for shale gas occurrence, whose development is mainly controlled by the physical-chemical structure and evolution degree of organic matter when it is transformed from chemisorption-type organic to physical absorption-type organic and free organic.

Sedimentary environment and formation mode of mudstone and shale are able to control its mineral and organic matter characteristics as well as influence the hydrocarbon generation potential of rocks. The Paleogene mudstone and shale in Shanghejie Formation, Dongying sag was selected to carry out rock thin-section observation, X-ray diffusion, thermal decomposition and other detection methods, so as to study the mineral and organic matter characteristics of rocks as well as analyze the differences in genesis and hydrocarbon generation potential of various mudstone and shales. Results show that massive, layered and gypsum-bearing mudstone and shale have diversified laminated characteristics in the study area, where the content of mineral components (including clastics, clay, carbonate and gypsum minerals) show great changes and organic matter characteristics have also been diversified. Through comprehensive analysis on mineral and organic matter characteristics as well as their assemblage relationships, it was found that the fine-laminated shale and discontinuously-laminated shale were the products mainly formed by biological deposition with the highest hydrocarbon generation potential. The wide-laminated shale and homogenous-massive mudstone were the products of chemical deposition with higher hydrocarbon generation potential. The clastic-massive mudstone was mainly formed by mechanic deposition, while the gypsum-bearing mudstone was generated by chemical deposition in an evaporitic environment, and both showed weaker hydrocarbon generation potential. Comparing the mudstone and shale types in the Middle Submember of Member 3 and the Upper Submember of Member 4 of Shahejie Formation, Dongying sag, it was detected that the Middle Submember of Member 3 and Chunxia Submember of Member 4 were dominated by clastic-massive and gypsum-bearing mudstone and shale formed due to mechanic and chemical effect, leading to weaker hydrocarbon generation potential. The Lower Submember of Member 3 and Chunshang Submember of Member 4 of Shahejie Formation, Dongying sag were dominated by laminated mudstone and shale formed due to biological or chemical deposition, leading to higher hydrocarbon generation potential. Therefore, the focus on mineral-organic matter assemblage relationships of mudstone and shale as well as the changes in the genesis and hydrocarbon generation potential of various mudstone and shales from the perspectives of mechanic, chemical and biological deposition modes is able to provide a new idea for unconventional hydrocarbon exploration.

Organic geochemical characteristics of Jurassic source rocks in the eastern Jungar Basin have been studied, showing that the Jurassic source rocks in the eastern Jungar Basin have a wide distribution of TOC ranging between 0.13% and 81.06% and was evaluated as having poor-moderate oil generation potential, but its gas generation potential is high. Distribution of vitrinite reflectance R_o and biomarker compound parameters associated with thermal evolution degree (OEP value, CPI value, sterane and hopane isomerization parameters, methylphenanthrene index, etc.) indicate that a majority of source rocks are situated in immature-low-mature stage of thermal evolution. Type-III organic matter is dominant in this area, though source rocks of Badaowan Formation and Xishanyao Formation partially have type II₂ organic matter. In addition, analysis of elemental composition and carbon isotopic composition of Jurassic natural gas in the eastern Jungar Basin demonstrate that the Jurassic natural gas is dominated by hydrocarbon gases, in which methane content is 65%-98%, C₁/C_1-5 ratio is 0.62-0.98, and wet gas is predominant; carbon isotopic composition has a wide distribution, among which δ¹³C₁ values of methane range from -50.7‰ to -28.2‰, δ¹³C₂ values of ethane range from -32.5‰ to -23.7‰, and δ¹³C₃ values of propane between -30.6‰ and -21.6‰, suggesting the dominant coaliferous gas, except that natural gas of Santai-Beisantai area is characterized by petroliferous gas-coaliferous gas mixture. Based on analyses of Jurassic coal measure source rock and natural gas samples from the eastern Jungar Basin area, the study area was compared with typical low-mature gas zone of the Turpan-Hami Basin in terms of geochemical characteristics of source rock and natural gas, and it is believed that a certain scale of low-mature gas accumulation has come into being in the eastern Jungar Basin, eastern Fukang sag and Santai-Beisantai area, which have huge exploration potential and thus are key areas of the Jungar Basin expected to make a breakthrough in low-mature gas exploration.

The Paleogene Lower Ganchaigou Formation in the west of Yingxiong ridge, Qaidam Basin is originated from saline lacustrine-basin sedimentation with the development of multiphase rock salt (layered halite), of which the origin and development mode is a hot issue to be solved at present. The core data reveal that the complete salt-formation single-phase cycle is an evaporation sedimentary sequence. The lithological sequence assemblage characteristics of prospecting wells show that the lacustrine basin experienced three evolutionary stages, i.e., semi-saline, salinizing and saline lake. Through the petrography analysis, homogenization temperature test and composition research of the inclusions as well as the analyses of the sulfur, carbon and oxygen isotopes of salt-bearing strata, it is explicitly put forward that the rock salt was generated through low-temperature underwater concentration and crystallization, and formed in the confined continental environment with intense evaporation; the material source was carried by terrestrial surface water. Two kinds of salt forming modes were developed in the mid-late saline stage and euryhalinous lake stage, and each mode is divided into three evolutionary stages, i.e., initial saline stage, saline stage and salt forming stage. The comparison and analysis of joint wells indicate that five rock-salt concentration development periods existed, when the saline lake experienced three evolutionary processes, i.e., the initial stage, peak stage and shrinking stage. The saline lake center had the maximum thickness with limitations in plane distribution, and multiple secondary salt depression centers were formed due to the control of paleo-terrain. The vertical development of multiphase salt rock was caused by the frequent seasonal fluctuation of lake level in terrigenous lake basin.

As the exploration difficulty in positive structral zone increases, sub-sags have gradually become the important area to increase reserve and production in hydrocarbon-rich sag, Bohai Bay Basin. However, the special accumulation mechanism restricts further exploration in sub-sags. Taking Raoyang sag in Jizhong depression as the research object, the reservoir formation mechanism and hydrocarbon accumulation model of sub-sags in hydrocarbon-rich sag were discussed through analysis of hydrocarbon generation capacity, accumulation stage, hydrocarbon accumulation dynamics and resistance, pathway system, etc. Research shows that the hydrocarbon-rich sub-sags are characterized by a wide range of effective hydrocarbon generation and high degree of thermal evolution as well as two stages of hydrocarbon generation and accumulation, i.e., late Dongying period and Neogene Minghuazhen period. In the late depositional stage of Dongying Formation, oil and gas charging occurred on a small scale; reservoirs had good physical property and small accumulation resistance. In the charging stage of Minghuazhen period, reservoirs had poor physical property and great accumulatioin resistance, while possessing great excessive pressure and strong accumulation dynamics. Oil and gas in the center of sub-sags mainly migrate in a short distance through sand bodies, fractures, small faults, etc. in source rocks, accumulate and generally form lithologic reservoirs. Oil source faults deep cutting into source rocks are often developed on the margins of sub-sags, thus becoming an important channel for hydrocarbon vertical migration; hydrocarbon migrates along faults and mainly forms structural reservoirs. There are two accumulation models of "intrasource-two stages of accumulation-subtle pathway-short migration distance" and "extrosource-one stage of accumulation-fault pathway-vertical migration" in hydrocarbon-rich sub-sags. Meanwhile, the lower limit of physical property for hydrocarbons accumulation in effective source rocks is controlled by accumulation dynamic and resistance, while the distribution and enrichment degree of hydrocarbon outside source rocks is controlled by the distribution characteristics and effectiveness of fault-dominating pathway system.

A method for estimation of sedimentary micro-amplitude paleotopography based on structural trend surface conversion has been proposed. This method is suitable for estimating marine sedimentary micro-amplitude paleotopography of weak tectonic deformation zone in a cratonic basin. An assumption is given that multiphase uplifting-subsiding or torsional structural movement in the cratonic basin is manifested as structural trend surface variation, which does not change the pseudostructural amplitudes of local paleotopographic highs and peripheral terrain. Technical procedure of this method is as follows:firstly, calculate pseudostructural amplitude using present-day structural map and its trend surface; secondly, calculate dip direction of sedimentary structural trend surface by approximating the average strike of formation denudation line to the strike of sedimentary structural trend surface; thirdly, according to the idea of uniformitaranism, the average gradient of present-day tidal-flat facies serves as the dip angle of sedimentary structural trend surface; lastly, structural trend surface plus pseudostructural amplitude can obtain the sedimentary paleotopographic map. On this basis in conjunction with petrographic characteristics and dolomitization type of cored wells, distribution scope of each subfacies or microfacies in the marine sedimentary system can be better determined. Application of this method in Lower Ordovician carbonate strata of tidal-flat facies in Submember 5 of Member 5 of Majiagou Formation in the eastern Sulige gas field shows that structural trend surface of the study area is changed from NW-SE to NE-SW, which does not change relative height between sedimentary local paleotopography and peripheral terrain, and that this method is able to effectively depict sedimentary micro-amplitude paleotopography of tidal-flat facies. Subaqueous micro-amplitude paleotopographic uplift during sedimentation period are a key factor controlling the distribution of tidal-flat-facies carbonate grain shoals in this area, while the grain shoals are the most favorable microfacies for late dolomitization and development of high-quality reservoirs. Therefore, high-production gas wells can be discovered on the basis of accurate depiction of sedimentary micro-amplitude paleotopography. This method can provide beneficial ideas for the research on sedimentary paleotopography of weak tectonic deformation zones in other cratonic basins.

Unlike conventional oil, heavy oil exhibits Newtonian fluid state when it reaches a specified temperature. Specifically, heavy oil shows non-Newtonian fluid state at a temperature below the specified value, i.e., a threshold pressure gradient occurs. In a classical analytical model, the reservoir for cyclic steam stimulation is divided into hot zone and cold zone; the temperature of hot zone is steam temperature while that of cold zone is initial formation temperature. However, in practice, temperature transition from hot zone to cold zone is a non-isothermal gradual change process, and no abrupt change will occur at the boundary between hot zone and cold zone. Moreover, during production, heavy oil presents two states in different zones, i.e., Newtonian fluid and non-Newtonian fluid; correspondingly, heavy oil flow equations are also different. In light of the two points above, the analytical model of cyclic steam stimulation was modified on the basis of Marx-Langenheim equations. Considerations included non-isothermal distribution characteristics of hot zone during injection stage and flow coupling of heavy oil in Newtonian fluid zone and non-Newtonian fluid zone during production stage. The results of the model application shows that this model is more close to actual production situation and has better applicability.

The microorganisms for oil recovery show obvious retention characteristics in porous media during migration process. Pseudomonas aeruginosa WJ-1 and Bacillus subtilis SLY-3 were taken as the research objects to study their migration and retention laws by isothermal adsorption experiment and flow experiment. The results show that the greater the specific surface area of porous media is, the more the adsorption sites will be and the greater the bacteria adsorption capacity will be. The bacteria adsorption capacity on porous media surface is certainly influenced by the hydrophobicity of bacteria and porous medium surface. The total bacterial concentration of microorganisms for oil recovery in the porous medium environment of reservoir is generally lower than 3.5×10⁸cfu/mL. Under this condition, the adsorption of microorganisms for oil recovery in the porous medium is consistent with Freundlich adsorption isotherm model. The migration speed of larger microorganism is faster, thus proving the inaccessible pore volume of microorganisms for oil recovery during migration in the porous media. The microorganisms for oil recovery migrating in the porous media are affected by equilibrium adsorption and bridging screening, of which the bridging screening has more prominent effect than equilibrium adsorption. Based on experimental research, the migration and retention mechanism of microorganism was determined. On this basis, the mathematical model of microbial migration was modified and improved accordingly. The research results provided experimental and theoretical basis for the development and optimization of numerical simulation software for microbial oil recovery.

To solve the problems such as considerable water consumption and increasing waste fluid pollution during unconventional reservoir fracturing transformation process, a new method was studied on the use of fracturing flowback fluid for re-preparing fracturing fluid after chemical treatment. Taking the fracturing flowback fluid in Changqing Oilfield as an example, the effects of the main mineral ions Ca²⁺ and Mg²⁺, residual gel breaking agent (peroxide) and boron crosslinking agent on re-prepared fracturing fluid were analyzed. Meanwhile, three different treatment agents TR-1, TR-2 and TR-3 were formulated, and used to reduce the mineral ions in fracturing backflow fluid through complexation, remove the residual gel breaking agent by oxidation-reduction reaction, and prevent the boron-plant galactomannan gum hydroxyl crosslinking by shielding residual boron crosslinking agent, respectively. This method was applied to 15 horizontal wells and 125 horizontal members of Changqing Oilfield in 2013. Moreover, 14 000 m³ treatment fluid was recovered, which accounted for 23% of the total fracturing fluid volume, thus achieving the reutilization effect of fracturing flowback fluid and reducing environmental pollutions.

Perforating can result in local damage to wellbore integrity, especially the destruction of cement ring as well as the debonding or micro-annulus of the first interface(between casing and cement ring) and the second interface(between cement ring and surrounding rocks). In the later volume-fracturing process in shale gas horizontal well, due to the injection of high-pressure fluid, interface micro-annulus will become aggravated and even lead to fracturing propagation, which will influence the sealing performance. To solve this problem, a mathematical model of interface crack propagation was established. Nonlinear partial differential equations were obtained by the fluid continuity equation, Poiseuille law, the elastic relationship between net pressure and seam width as well as the boundary conditions. Meanwhile, the self-similar solution was solved by governing equation dimensionless method. This model was used to calculate field cases and analyze the influences of each parameter on interface crack length. The study results show that proper increase of cement ring's elastic modulus and reduction of wellhead pressure and fracturing time is beneficial to reduce the interface crack propagation length and guarantee long-term effective seal. The study can be used to evaluate and predict the cement ring sealing performance under volume fracturing in shale gas wells, and provide guidance for the optimization of adjacent perforation spacing on the premise of satisfying hydrocarbon production requirements.

For trial-produced X90 gas-transmission pipe, quasi-static tensile tests and stress triaxiality calculation were carried out on five kinds of different notched round bars. It has been found that because of sample notch, when stress triaxiality is increased by 2.43 times, fracture strain and damage strain energy will be reduced by 29% and 71% respectively. Universal material testing machine and Hopkinson bar test unit were used for tensile experiments at different strain rates. It has been discovered that strain rate has less effect on failure strain, and in a case of quasi-static state and high-rate state, the largest difference is about 10%. Based on Johnson-Cook constitutive and failure model, X90 steel pipe constitutive model with consideration of stress rate effect was established as well as the failure model considering strain rate and stress triaxiality. Meanwhile, according to damage mechanics theory, X90 pipe steel fracture criterion was obtained on a basis of plastic uniform elongation and damage strain energy. Based on the assumption of constant density critical value of material damage strain energy and test data, the relation expression was obtained between X90 pipe steel fracture characteristic length and stress triaxiality as well as specimen diameter.

Since 2006, passive continental margin basins are the main growth region for global oil and gas reserves. Through a statistical analysis on the exploration tendency of passive continental margin basins, this paper systematically summarizes the geological progress of passive continental margin basins, and describes the characteristics and exploration potential of oil and gas distribution in the main basins. Moreover, the main direction of the next stage oil and gas exploration in passive continental margin basins is proposed. The exploration in passive continental margin basins show five aspects of tendencies, i.e., from shallow water upsalt to deepwater undersalt, from tectonics to stratum-lithology, expanding from the Atlantic to the Indian Ocean, from conventional zone to polar regions and the proportion of natural gas increasing. The new development in the aspects of deepwater basin, deepwater sediment and undersalt reservoir are the important approaches to achieve a breakthrough in oil and gas exploration. The passive continental margin basins along the Atlantic coast and the Indian Ocean west coast have regular conjugate relations to certain extent, of which there are great differences in oil and gas enrichment degree, distribution and types. The principal line based on such conjugate relations offers a new exploration idea for new exploration field. For the future oil and gas exploration in passive continental margin basins, it is suggested to significantly appraise the deepwater basins with recent breakthroughs, insist on the constant exploration in the salt-bearing basin strata during the undersalt rift period, and strengthen the prospective study on the ultra-deepwater basin.

Lithofacies characteristics of fine-grained sedimentary rocks (FGSR)have impact on the hydrocarbon generation ability and reserving property of shale, and their relationship with sedimentary environment can be analyzed to enrich the research on fine-grained sediment.However, there are insufficient studies regarding the lithofacies of lacustrine FGSR. The lithofacies characteristics are less analyzed based on lithofacies genesis in combination with sedimentary environment. Accordingly, based on massive well cores, thin sections, X-ray diffraction and geochemical data, and the component as the first element, FGSR in the upper submember of Member 4 of Shahejie Formation in Dongying sag was divided into four categories and 12 lithofacies types, so as to analyze the macro, micro, component and genesis characteristics of each lithofacies type. Through analyzing mineral compositions, geochemical indexes and other parameters, it is found that the sedimentary environment in the upper submember of Member 4 of Shahejie Formation can be classified into four stages.The sedimentary environment controls the types and development of lithofacies through controlling the main components of lithofacies;the cyclicity and periodic changes of lithofacies are caused by those in sedimentary environment; the sedimentary environment controls the lithofacies development, and the lithofacies reflects the change of sedimentary environment. During the FGSR analysis, the influences of sudden events (such as transgression and turbidity flow)on lithofacies and sedimentary environment cannot be excluded.

As the most important type of pores in the grain-supported clastic reservoirs, intergranular pores can control the reservoir quality by their relative contents and mutual connectivity, especially for tight sandstones with various pore-throat structures. The intergranular pores exhibit the connective pattern of "large pores connected by narrow throats", which is significantly different from the intragranular pores with "tree-like pore network". The rate-controlled porosimetry can be used to effectively distinguish the distribution range of intergranular-dominant pores. On this basis, the contribution of intergranular pores to porosity is quantitatively assessed by nuclear magnetic resonance, while that to permeability is calculated by the joint percolation theory and throat distribution from rate-controlled porosimetry. The contribution of intergranular pores to porosity in tight sandstones varies from 9 % to 64 %, showing a significantly positive correlation with that to permeability varying from 0 to 87 % . The higher the contribution of intergranular pores to permeability is, the greater the fluid mobility in intergranular pores will be. The contribution of intergranular pores to porosity and permeability is obviously affected by the combination of the mechanical compaction and clay-dominated cementation. Based on the contribution of intergranular-pore dominant space to permeability (K_in)as a key parameter, tight sandstone reservoirs are classified into the intergranular pore-dominant type (K_in>50 % ), mixed type (10 % < K_in < 50 % )and intragranular pore-dominant type (K_in<10 % ). This classification takes into account the contribution of the space dominated by intergranular pores with high sensitivity to the process of diagenesis to the overall rock reserving and porous flow capability, fluid mobility and other aspects, effectively compensating the limitations in the single use of pore-throat or pore size parameters for classifying tight reservoirs with various pore-throat structures.

Xujiahe Formation in the fault-fold belt of central Yuanba area, Sichuan Basin is a low-porosity and low-permeability reservoir, where fractures have important influences on the accumulation and productivity of natural gas. Based on the field outcrop, core, logging, inclusion analysis, acoustic emission and (U-Th)/He dating, a comprehensive study is carried out on the formation stages of regional structural fractures. Research indicates the development of high-angle and low-angle shear fractures due to tectonic genesis, characterized by meso-scale, minor width (sealed), large spacing, low filling degree and good fracture effectivity. The structural fractures of Xujiahe Formation were formed in three stages (without considering the fractures in the diagenesis stage). Stage-1 structural fractures were formed in the middle late period of Yanshanian movement with NE (30°± 5°)and NW (315°±5°)trends; the fractures were highly filled by meso-fine-grained calcite, inclusion homogenization temperature was 75-85℃, and the maximum effective principal stress of paleogeostress was 18.8 MPa. Stage-2 fractures were formed in early-middle period of Himalaya tectonic movement with NEE (75°±10°)and SN (0°±5°)trends; the fractures were half-filled (or unfilled)with coarse-grained calcite, homogenization temperature was 150-175℃, and the maximum effective principal stress of paleogeostress was 27.9 MPa. Stage-3 fractures were formed in the late period of Himalaya tectonic movement with NWW (290°±10°)trend; the fractures underwent a low degree of filling, the fillings of Stage-1 and Stage-2 fractures were obvious before cutting, and the maximum effective principal stress of paleogeostress was 38.6 MPa. In combination with geomechanics theory, the genetic patterns for the development of three-stage fractures are established.

Cambrian carbonate rocks in North China platform are well developed reservoirs for deep hydrocarbon accumulation. It is of significance to study the Cambrian sequence stratigraphy and filling pattern for exploration of both buried hills and buried hill inner curtain hydrocarbon accumulations. Synthesizing the lithofacies and sedimentary cycles' characteristics of outcrop, typical drilling log and seismic data, three kinds of sequence boundaries are identified, including not only the types I and type II related to the exposure but also the boundary indicating the drowned unconformity. Furthermore, the 3rd order sequence stratigraphic framework of Cambrian in the middle-northern North China has been established, and the Cambrian can be divided into seven 3rd order sequences tracing regionally. Through analyzing the carbon isotope cycles of whole rock reflecting the global sea level change and sedimentary cycles implying the depositing water depth, the dominating factors for the 3rd order sequences development of Cambrian in the middle-northern North China are clarified. The paleoclimate and sedimentation rate were relatively stable, inferring the tectonic setting and global sea level were vital for sequence development. The forming of sequence CSQ1(Fujunshan Formation or Changping Formation), sequence CSQ2(Mantou Formation) and sequence CSQ5(Gushan Formation) are comprehensively controlled by global sea level changes and regional tectonic subsidence, especially the sequence CSQ5 which is dominated by the drowned unconformity. While the stably aggradated sequences CSQ3(Maozhuang Formation), CSQ4(Xuzhuang Formation or Zhangxia Formation), CSQ6(Changshan Formation) and CSQ7(Fengshan Formation) are mainly dominated by the global sea level change.

It is traditionally believed that the saline lacustrine source rocks in western Qaidam Basin have low organic matter abundance, and the hydrocarbons are mainly sourced from "soluble organic matters". In this study, a certain scale of high quality saline lacustrine source rocks with high organic matter abundance has been discovered for the first time; the TOC value is about 1 % with the maximum above 4 %, the potential of hydrocarbon generation is generally greater than 6 mg/g with the maximum up to 40 mg/g, and the hydrogen index is commonly above 500 mg/g(TOC) with the maximum above 900 mg/g(TOC). The organic matters of Type I and Type II₁ are dominant, mixed with a small amount of Type II₂, indicating, the oil-prone types. The samples with ultra-low organic matter abundance (TOC<0.5 % ) indicates the poor types, contain a less content of soluble organic matter and a small potential of hydrocarbon generation, belonging to the inactive source rocks. Among the biomarkes of high quality source rocks, the compounds rich in phytane, C₂₈-sterane, gammacerane and C₃₅-hopance revealing the saline environment; the characteristics of high sterane low hopane, high C₂₇-sterane and low C₂₉-sterane, indicating organic matters are mainly derived from hydrobiontic algae. As so-called oil algae, these algae rich in lipid compounds can be directly converted into hydrocarbons in the low mature stage. The saline environment is conductive to the preservation of liquid hydrocarbon directly converted by algae, thus forming "immature-low mature oil". The content of "soluble organic matter" contained in the saline lacustrine source rocks of western Qaidam Basin is significantly higher than that of fresh water lacustrine source rocks, which is the important material source for a batch of immature-low mature oilfields discovered in regional middle-shallow layers in western Qaidam Basin. It is validated by simulation test that organic matters also have a high potential of oil-generation in the mature stage, in accordance with the classic oil-gas generation model. Thus, the oil and gas generated in mature source rocks is the major exploration target for deep layers. In this region, there are two types of hydrocarbon accumulation models for high quality source rocks in Paleogene deep layers. One is outer-source accumulation, i.e., oil and gas migrates towards shallow tectosphere through open faults for accumulation; the other type is inner-source accumulation, i.e., oil and gas is accumulated near the source in the lithological traps adjacent to deep source rocks. So far, significant breakthroughs have been made in these two types of oil-gas reservoir exploration, and two blocks with the reserves up to a hundred million tons are discovered to confirm the enormous exploration potential of oil-gas reservoirs formed in deep high quality source rocks.

Based on analyzing thin section by microscopic observation, scanning electron microscopy, X-ray diffraction as well as constant and trace element measurement, and considering the mineral composition of fine-grained sediment, lithologic fabric, micro-palaeontological characteristics and typical minerals, 6 types of hydrocarbon source rock lithofacies have been identified in marine source rocks of Madingo Formation:the silt fine-grained lithofacies, radiolarian enriched fine-grained lithofacies, phosphatic fine-grained lithofacies, foraminiferan enriched fine-grained lithofacies, cinereal fine-grained lithofacies (lime mud)and clayey fine-grained lithofacies. As demonstrated by the comprehensive analysis of fine-grained sediment lithofacies, micro-palaeontological fossils, constant and trace elements as well as seismic data, the biogenic deposit containing biosilicon, upwelling sediment containing phosphate rock, suspension sediment enriched with silicious clastic particles and bottom current sediment with graded bedding were developed in marine source rocks from Madingo Formation. As a whole, marine source rocks in Madingo Formation of the Lower Congo Basin were deposited under a reducing environment with low-energy water medium in post-rift continental shelf, and in the early deposition stage the semi-closed-closed restricted sea environment was developed in the continental shelf and the high-quality source rocks enriched with radiolarian were accumulated; and following the Campanian period, the regional geological background was converted to a wide continental shelf where high-quality source rocks enriched with phosphate and foraminiferan were developed due to upwelling on the continental shelf.

Gravity tonguing is a common phenomenon that the displacement agent flows forward rapidly along the upper or lower core edge due to gravity action in the core displacement experiment, which directly affects the effect of displacement agent. For a long term, it is unable to directly observe the core interior in the displacement process, so it is impossible to form an intuitive image of that phenomenon. Firstly, the influence of gravity on fluid flow morphology in the process of water flooding was simulated by means of reservoir numerical simulation. Then, the conditions and influencing factors of gravity tonguing were studied using the core displacement visualization method based on magnetic resonance imaging technique. A new method was proposed to obtain the critical density difference causing gravity tonguing. Research results show that the density difference of displacement fluid and displaced fluid is the most direct reason for gravity tonguing. When the actual density difference is greater than the critical value, significant gravity tonguing will occur. The viscosity and displacement flow of displacement medium have no obvious influence on gravity tonguing. In the actual production process, the density of displacement fluid can be selected preferentially based on formation fluid property to reduce the influence of gravity tonguing on displacement effect.

Shale gas content is an important parameter for shale gas reservoir reserve estimation, which is of great significance to the evaluation of gas reservoir and the calculation of development index. Field desorption is a major method for measuring shale gas content, and the lost gas volume accounts for 40 % -80 % of shale gas content. However, the test results of such conventional method are quite questionable. In this study, based on the new test methods a new pre-pressurizing method was proposed to measure shale gas content, which could avoid calculating the lost gas volume and greatly increased the test accuracy. At well site, the cores were placed in a high-pressure container, pressurized to a given pressure by injecting methane by booster pump; under the formation temperature, the shale gas content was desorbed and tested till the pressure stabilizes. This method adopt two different processes in two cases, i.e., whether the formation pressure is known or not before experiment. If the formation pressure is known, the cores are pre-pressurized to reach formation pressure, and the desorption result is exactly the shale gas content. If the formation pressure is unknown, a theoretical model is established to calculate shale gas content. The test process is as below:firstly, a core is pressurized twice to exceed the adsorbed saturation pressure (over 20 MPa)for desorption test, then the desorption results of twice pressurizations are used to solve the theoretical equation and obtain the calculation equations of adsorbed gas volume for a unit mass of shale and the free gas volume under any pressure. When the formation pressure is tested later, the calculation equation of free gas is adopted to calculate the free gas volume under this pressure, and the sum of free gas volume and absorbed gas volume is equal to shale gas content.

The pseudo-steady state productivity equation in combination with material balance equation is always used as the traditional performance forecasting method of gas-well production. Due to low permeability, the flow of tight reservoirs is difficult to reach a pseudo-steady state, so that big errors may exist in the forecasting results. The advanced production decline analysis has been a new technology for single-well performance forecasting, but still at the analytical model stage, and thus the superposition principle is commonly used for whole-course history matching. Because of the large yield fluctuation at gas-well production stage and the multiple flow stages, history matching shows a long computation period, so the analytical method is difficult to meet the onsite demand. In view of above questions, a type of unstable porous flow mathematical model was established by taking the vertical fractured well as an example, and the numerical solutions to three kinds of production patterns including producing at a constant rate, producing at a constant bottom hole flowing pressure and variable pressure and variable rate were obtained using the mixed finite element method. The advanced production decline analysis curve was drawn based on the solution of constant rate production, the whole-course history matching was conducted by variable pressure and variable rate solutions, and the production performance forecasting of gas wells was carried out according to the combination of the constant rate production and the later constant pressure production. By comparison, the model results and the calculation results of Topaze commercial software are consistent, and the whole-course history matching rate of numerical model has significant advantages. The comparison with the results of traditional production performance forecasting method and the field-case analysis results show that the model results of this study are accurate and the used methods are practical and reliable.

The performance simulation and prediction of inflow control devices (ICD)completion and the optimization design of completion parameters are the survival foundation of ICD completion to achieve the production optimization of horizontal wells. According to semi-analytical coupling model and Eclipse 2011, a dynamic simulation method of ICD completion was established by integrating steady-state simulation and transient-state simulation. This method not only takes the completion dynamics at a specific time as design basis, but also optimizes and designs completion parameters from the view of optimal wellbore and reservoir flow dynamics throughout the whole production cycle. Aiming at the heterogeneous bottom-water reservoir, the above simulation method was used for example calculation and parameter sensitivity analysis of ICD completion. In addition, the optimization design methods of ICD completion were put forward for different arrangement patterns. The result shows that ICD completion can considerably improve the production dynamics of horizontal wells compared with conventional completion. The determination of ICD flow-restriction sizes needs to consider the production profile uniformity and horizontal well productivity index comprehensively, and ICD completion is featured with the optimal flow-restriction sizes. For a heterogeneous bottom-water reservoir, ICD completion of horizontal well is featured with the optimal packer number, which is highly related with the degree of permeability heterogeneity for a specific reservoir. Variable ICD completion design not only further improves the production profile uniformity, but also increases the horizontal well productivity index compared with uniform ICD completion design.

To effectively solve the safety problems brought by the variation of internal-external pressures on tube string in the production-injection process of underground gas storage, according to the thermodynamical and heat-transfer theories and aiming at the characteristics of fluctuations in temperature and pressure during the injection-production process of tube string in underground gas storage wells, two situations of annulus space filling with protection fluid and nitrogen column were analyzed, created the internal-external pressure equilibrium models of tube string in gas storage, and analytically calculated the internal-external pressures and the variations of tube string under two kinds of models, respectively. Meanwhile, the optimal combination chart of nitrogen column length and packer running depth was developed by focusing on the research on the optimal length of nitrogen column in annulus space. The research results show that under the same conditions, annulus nitrogen injection can reduce the annulus pressure by 50 % -90 % in the injection-production process, and the optimal length of nitrogen column is 1/20-1/15 of the packer running depth. The longer the length of nitrogen column is, the lower the value of annulus pressure will be. The analysis on the sensibility of fluid temperature and pressure in oil tube indicates the prominent influence of temperature on annulus pressure variation. The reasonable length of nitrogen column injected in tube-casing annulus can prevent the tube string destruction of gas storage and the packer failure effectively.

Two groups of NW and NNW trending Paleogene hydrocarbon-generation depressions are developed in western Qaidam Basin. These depressions were filled with thick, soft and organic-rich sediments, including gypsum, salt and argillaceous rocks, while the peripheries of depressions consist of hard basement and coarse-grained arenous sediments. Such a remarkable contrast in mechanical strength led to different deformation behaviors and quite distinct tectonic landforms inside and outside the hydrocarbon-generation depressions under the compression from Neogene to Quaternary. In this study, such phenomenon is called boundary effect, which provides an important evidence for determining and recognizing hydrocarbon-generation depression. As the largest-scale Cenozoic structural belt with the most abundant hydrocarbon accumulation in the western Qaidam Basin, Yingxiongling Range was developed above NW-trending hydrocarbon-generation depression. While the northwestern Qaidam Basin is located in the north side of this depression, a series of long axis structural belts, including the Nanyishan, Dafengshan, Jiandingshan etc., were developed due to the disappearing of gypsum, salt rocks or the thinning of argillaceous layer. Moreover, the structural deformation styles of Yingxiongling Range transformed from detachment structures in the west to basement-involved structures in the east, which may indicate that the filling components of Paleogene hydrocarbon-generation depression has changed from west to east. The hydrocarbon accumulation controlled by boundary effect is mainly distributed in three types of structural positions. The first is along the edges of depressions, where hydrocarbon accumulated in the structural high parts caused by boundary effect; the second lies in the outside of depressions, where hydrocarbon accumulated in the structural and lithological traps transiting from deltas, shores and shallow lake to semi-deep lake; and the third is sited in the depressions, where hydrocarbon accumulated in the intra-Paleogene structural and lithological traps. Therefore, the thought of "full-depression reservoir-controlling, three types, zoned accumulation" should be adopted in the western Qaidam Basin to implement the overall evaluation and exploration deployment aiming at the above three types of positions.

T he sedimentary characteristics and hydrocarbon accumulation model in the upper member of Oligocene Xiaganchaigou Formation, Western Qaidam Basin are analyzed in this paper. Comprehensively based on the petrology and mineralogy research, paleo-geomorphology analysis, carbon-oxygen isotopes and microelement geochemistry research, seismic-profile fine interpretation and "ant-tracking" fracture prediction, hydrocarbon accumulation model research and high-yield controlling factor analysis, it is put forward that the upper member of Oligocene Xiaganchaigou Formation in Yingxi area is a saline sedimentary environment of "semi open-semi closed" semi-deep lake facies, and the special hydrocarbon accumulation model in Yingxi area is resulted from oil storage in the matrix intracrystalline pore, fracture forming by under-salt stress accumulation and salt formation seal-capping. Research results show that firstly, the lithology is dominant by dark colors including dark grey or ash black with the mixed sedimentation of saline minerals, mainly controlled by sedimentary environment. Secondly, the paleo-geomorphology prior to the sedimentation in the upper member of Xiaganchaigou Formation is a limited lake "lower in the west while higher in the east" with the development of lake barrier island. Thirdly, the data points of carbon-oxygen isotopes fall between an open lake and a closed lake. Fourthly, Sr/Ba values are all greater than 1 with an average of 2.01, the average value of Sr/Cu is 109.04, far greater than 5, and U/Th values are all less than 1 with an average of 0.62, indicating a saline, arid and reducing environment. Fifthly, the average value of ∑REE is 87.67×10^-6 with the distribution range of (39.41-162.67)×10^-6, and Eu negative anomaly exists. Sixthly, the pressure coefficient of main under-salt producing formation can be up to 2.2, and the deduction of "self-originating-over-pressured system" resulting in the fracture formed by stress accumulation is completely consistent with the results of "ant-tracking" fracture prediction and core observation.

The thin interlayer of silty-fine sandstone is mostly developed in Carboniferous shale gas reservoirs of the eastern Qaidam Basin. After generation, shale gas will gather in the adjacent sandstone interlayer. Thus, the fluid inclusions in the diagenetic minerals with different stages of sandstone interlayer will become the "living fossil" for studying the fluid formation and evolution process of shale gas reservoir. In this paper, the generation and preservation conditions of shale gas in the study area were systematically investigated in terms of the geochemical characteristics of shale, the microscopic polarization/fluorescence characteristics of reservoir, as well as the temperature and composition characteristics of fluid inclusion. The research results indicate that Carboniferous mud shale in the study area has high organic abundance, dominated by the organic matter of Type Ⅱ₂-Ⅲ, and is generally in the mature-highly mature development stage. There exist two stages of hydrocarbon charging processes in shale gas reservoir. Stage 1 occurred at the end of Early Permian period, in which the hydrocarbon compositions had low maturity, consisting of heavy oil inclusions distributed inside the annular quartz-grain overgrowth edge in sandstone interlayer and residual brown-beige thin-oil asphalt in current reservoirs. Stage 2 occurs from Early Neogene till now, in which the condensate and natural gas inclusions are distributed zonally along the micro-cracks of sandstone interlayer posterior to the quartz grain digenesis period, considered as the hydrocarbon main body of current shale gas reservoirs. In partial sandstone interlayer at the east and northeast edges of the basin, gas inclusions have primary compositions such as CH₄+CO₂ and CO₂+CH₄+N₂, belonging to metamorphic fluid under magma hydrothermalism. The Carboniferous shale in the central study area has high organic carbon content with moderate maturity (R_o mean of 1.0% ±) and good hydrocarbon preservation conditions, where movable light oil and gas exist at present, indicating favorable exploration prospects for shale gas.

The discovery of buried-hill fracture reservoirs in Pre-Cambrian basement, Bongor Basin, opens a new frontier for onshore hydrocarbon exploration in Africa. The issue of buried-hill oil source is one of the factors to restrict the exploration process in this region. To solve this problem, the analytical test data of organic geochemistry from buried-hill crude oil are fully used to study the biomarker compounds and geochemical characteristics of buried-hill crude oil in M-P and B regions as well as analyze the oil-source relation of buried-hill crude oil in M-P and B regions with the source rocks in M and BN sags. In combination with thermal evolution history and structural evolution history of Bongor Basin, the hydrocarbon accumulation processes of buried-hill reservoir belts in M-P and B regions are analyzed. The research results show that the buried-hill crude oil in M-P region is mainly derived from the source rocks in M sag, and the buried-hill crude oil in B region accepts contributions from the source rocks in M and BN sags. The source rocks in M sag supplied hydrocarbons to buried hills in B region from the middle Late Cretaceous, while during the middle-late Late Cretaceous, the crude oil generated from the source rocks of M and BN sags commonly accumulated in the buried-hill belts of B region. Meanwhile, the crude oil generated from the source rocks of M sag migrated and accumulated in the buried-hill belt of M-P regions, forming buried-hill hydrocarbon reservoirs.

Based on the analysis results of the molecular biomarkers of 34 source rocks and 50 crude oil samples, the crude oil genesis types and their distribution laws of main oil fields in Langgu sag are studied. The analysis results show that the source rocks in the Lower Member 3 and Upper Member 4 of Shahejie Formation have different molecular biomarker assemblage characteristics. The inputs of terrestrial organic matters of the source rocks in Lower Member 3 of Shahejie Formation are high with abundant dinoflagellates, which deposit in a fresh-water strong reducing environment; the inputs of terrestrial organic matters of the source rocks in Upper Member 4 of Shahejie Formation are low with high inputs of lower hydrobiont, which deposit in a saline-water strong reducing environment. Based on the oil-source correlation of molecular biomarker parameters of source rocks, in combination with multi-parameter cluster analysis on the molecular biomarkers of crude oil, crude oil is divided into three genesis types. Type-I crude oil is derived from source rocks of the Upper Member 4 of Shahejie Formation, mainly distributed in the surrounding regions of Niutuozhen uplift; Type-Ⅱ crude oil is originated from source rocks of the Lower Member 3 of Shahejie Formation, mainly distributed in the Jiuzhou-Wangju region of the northern sag; Type-Ⅲ crude oil is sourced from the mixed source oil generated in source rocks of the Lower Member 3 and Upper Member 4 of Shahejie Formation, dominated by the crude oil generated in the former member, mainly distributed in Hexiwu structural belt and some parts of the southern Caojiawu-Liuquan structural belt in the eastern sag. The oil reservoirs in Langgu sag are adjacent to source rocks for oil-gas accumulation, and their distribution laws are controlled by the source-rock development distribution in different horizons. Caojiawu and Zhongchakou regions are the next favorable target regions for crude oil exploration in the source rocks of Upper Lower 4 of Shahejie Formation in Langgu sag, while Wangju region in Liuquan structural belt has a great potential to explore crude oil in source rocks of the Lower Member 3 of Shahejie Formation.

A research on the interwell connectivity of reservoirs in delta outer-front subfacies is of great importance to well pattern optimization and residual oil tapping for oilfields in a high water-cut period. Taking the eastern Naner block, Seartu oilfield, Daqing placanticline as a target region, based on the dense well pattern data of 122 time units, this study firstly establishes the quantitative evaluation model on the interwell connectivity of reservoirs in delta outer-front subfacies, followed by quantitative evaluations under different net to gross ratios and well spacing conditions. The results show that firstly, the net to gross ratio is a macro-evaluation parameter for the interwell connectivity of reservoirs, i.e., a "porous flow threshold" exists. When the net to gross radio is lower than the porous flow threshold, the interwell connectivity is no more than 20% and changed into disconnection. But when the net to gross ratio reaches the porous flow threshold, the interwell connectivity is increased sharply to over 80% and changed into complete connection. The functional image of net to gross ratio and interwell connectivity reflected in the whole process is shown as a S-shaped curve. Secondly, through analyzing the spatial coupling relationship between the well spacing and the projection of maximum sand-body cross sectional area perpendicularly to well drilling direction, the interwell connectivity probability model of reservoirs in delta outer-front subfacies is created using well spacing as a variable. Meanwhile, it is put forward that the overall variation tendency of reservoir interwell connectivity is influenced by the proportion of each microfacies sand body. Thirdly, the porous flow threshold of reservoir interwell connectivity shows a positive correlation to well spacing. As the well spacing gets smaller, the S-shaped-curve functional image of the net to gross ratio and interwell connectivity tends to be "linear". When the average well spacing is 70 m (simple well spacing), the porous flow threshold of the interwell connectivity of reservoirs in delta outer-front subfacies is 0.20; when the average well spacing is 140 m (double well spacing) and 210 m (triple well spacing), the porous flow thresholds of reservoir interwell connectivity are 0.24 and 0.30, respectively.

As an important parameter of quantitative reservoir description, saturation is a great significance for obtaining underground fluid distribution, reserve estimation and well-site settings. Based on the high-precision stratigraphic elastic parameters supplied by full waveform inversion, the seismic saturation prediction method is studied herein. Through mathematical analysis and numerical calculation, the characteristics of fluid bulk modulus and pore space bulk modulus are discussed as well as their fluid sensibility. On this basis, saturation prediction method is proposed based on the acoustic full waveform inversion of two parameters with full spectrum band and Brie formula. The influence of the inversion error of bulk modulus and density and the error of exponential factor in Brie's fluid mixing equation on saturation prediction is also analyzed by numerical calculation, which provides the basis for the reasonable and effective application of the method. The validity of this method is further verified through the actual seismic data inversion and saturation prediction of Guang'an gasfield in Sichuan province, China.

CO₂ flooding has been successfully applied on site after water flooding. But due to the existence of high water saturation, the contact mode between CO₂ and crude oil has been changed, and the development of miscible process is also restricted. Aiming at the influences of high water condition on CO₂ miscible flooding process, the microcosmic visualization models of dead ends were prepared for the microcosmic visualiation experiment of CO₂ miscible process before and after water flooding. In combination with CO₂ flooding experiment under different water cut conditions, the characteristics of CO₂ miscible flooding were clarified as well as the effects of water saturation condition on CO₂ displacement efficiency. The results show that high water saturation will generate a certain shielding effect in the process of CO₂ contacting with crude oil, and the injected CO₂ is unable to contact residual oil directly. So the CO₂-crude oil miscible process is greatly postponed, thus causing the delayed responding time of CO₂ flooding under high water condition.

As a typical representative of China's tight sandstone gas field, Sulige gasfield possesses the characteristics of poor reservoir property, small-scale effective sand bodies, low distribution frequency, strong heterogeneity and obvious difference between the blocks. It is difficult to realize the overall effective use of reserves by relying on the main development well pattern of 600 m×800 m; and the recovery efficiency is only about 30%. Thus, it is necessary to conduct reserve classification and evaluation as well as implement well pattern infilling for various types of reserves. Su 14 block in central Sulige gasfield was taken as the study area. Through the fine exploration of dense drilling zones and the interference well test analysis, the reservoir development frequency and scale were clearly identified. Constrained by sedimentary facies belt, gas field reserves were divided into five types in terms of reserve abundance, reservoir superimposed style, poor gas-reservoir effect and production performance characteristics. From Type I to Type V, reservoir thickness is reduced with the continuity worsening, the reserve grade is declining, and the yield of single well is reduced. According to the actual production data of dense well pattern, the modeling and numerical simulation results, the relationships among well pattern density, interference degree and recovery efficiency were studied for each type of reserves to demonstrate the development indexes of single well under reasonable well pattern density. Under current economic and technical conditions, the appropriate well pattern density is 2-4 wells/km² for various types of reserve areas, and the ultimate recovery efficiency of gas field is about 50%. Moreover, the reserve configuration under complex geological conditions of tight sandstone gas field was determined through systematical study, providing a geological basis for the preparation of well pattern infilling scheme during the mid-late development stage.