A series of major breakthroughs have been achieved in global deepwater oil and gas exploration since 2010, which has been the most important replaced field of conventional oil and gas discovery. The breakthroughs in new basin groups and the rediscoveries in the early discovered basin groups point out two significant exploration directions. There have been new significant discoveries of oil and gas in four deepwater basins since 2010, including Guyana Basin on the eastern continental margin of Central America, Rovuma Basin and Tanzania Basin in the deepwater area of East African continental margin, the eastern Mediterranean of the Tethys Basin Group and the deepwater area of the continental margin of eastern Canada. From 2011 to 2016, it has been confirmed that nine basin groups in global deepwaters have achieved new great oil and gas exploration discoveries, including the mid-northern deepwaters of West African continental margin, the Great Campos Basin in Brazil, the deepwater area of Gulf of Mexico Basin, the deepwaters of western continental margin of Norway and North West Shelf of Australia, the deepwaters of the South China Sea, Southeast Asia and the Bay of Bengal, and circumpolar deepwater basin group. These discoveries prove that the hydrocarbon-rich basin has the paleo-environment for the formation of high-quality source rocks with high organic matter abundance and favorable reservoirs with good properties and high productivity. The successful breakthrough in new basin is to bravely explore new areas and restricted areas. The experience gained from constant discoveries in mature basins is to break through new horizons, especially the pre-salt reservoirs. It can be seen that global deepwater hydrocarbon is always the main field of future world conventional oil and gas exploration.

In Bozhong sag as the largest sub-tectonic unit in Bohai Bay Basin, three sets of high-quality lacustrine source rocks are developed, i.e., Member 1 and 3 of Paleogene Shahejie Formation (E₃s₁ and E₂s₃) and Member 3 of Dongying Formation (E₃d₃).Accurate identification of the crude oil from E₃d₃ source rocks is of great theoretical and practical significance for petroleum exploration in Bozhong sag.According to the aromatic GC-MS analysis of crude oil and source rocks, this study proposes new biomarker parameters for distinguishing E₃d₃ and E₂s₃ source rocks, i.e., C₂₇20R/C₂₈20R tri-aromatic steroid (TAS)and C₂₈20S/C₂₇20R TAS.Source rocks with C₂₇20R/C₂₈20R TAS>1.1 and C₂₈20S/C₂₇20R TAS ≤ 1.2 are classified as E₃d₃, and those with C₂₇20R/C₂₈20R TAS ≤ 1.1 and C₂₈20S/C₂₇20R TAS>1.2 are considered to be E₂s₃.Accordingly, this study also analyzes the sources of crude oil in typical oil fields of Bozhong sag, and puts forwards that the crude oil from E₃d₃ source rocks presents the characteristics of accumulated in or near the sag.

Jurassic Da'anzhai oil reservoir in Sichuan Basin is one type of unconventional tight oil, accumulated in source or near source, which has not yet experienced a large-scale long-distance migration. Da 1, Da 2 and Da 3 sub-members are all typical near-source shell limestone tight oil distributed extensively. These reservoirs are characterized by complex lithology, multi-type strorage spaces and complicated pore structure. In them the micro-pores and micro-fractures with strong fabric selectivity are important and effective strorage space. The newest petrophysics experiments show that the average connected porosity is about 2.13%, lower than that of other tight oil fields but far higher than 0.97% which is obtained by single alcohol-saturated method previously. Practical performance shows that the reservoirs are expressed as complex pore-throat-fissure assemblage or storage-percolation modes, neither simple pore types nor fractured types. Fluid in the reservoirs is difficult to enter but easy to escape because of the developed shell-controlled micro-fractures. The movable fluid saturation and mercury removal efficiency are only slightly lower than, or even partially higher than that of Chang 7 reservoirs in Ordos Basin, though shown as fine pore-throat, poor sorting and high replacement pressure. Da'anzhai member is one of the few tight oils with high natural productivity. New researches revealed the greater development potential of Da'anzhai shell limestone tight oil but the large-scale effective development still faces challenges including large matrix seepage resistance and single development mode which is low efficiency in such a complex reservoir. Therefore, it is necessary to learn experiences of Bakken group in the North America and Chang 7 in Ordos Basin, China to develop effective developing technologies based on volume fracturing and fine construction. The technology breakthrough will lay the foundation for the high-efficient development in large scale.

Based on high-resolution seismic data and updated drilling results, this study analyzes the geological structure and evolution process of the Paleogene formation in the central anticline zone of Lufeng 13 subsag, Pearl River Mouth Basin, as well as the control effect of tectonic evolution on hydrocarbon accumulation. The research results indicate that upper and lower deformation layers are developed in the central anticline zone of Lufeng 13 subsag, of which the upper deformation layer is developed with "arched graben system", and the lower deformation layer is mainly developed with magmatic-diapiric tectonics and plastic bed flow. The formation and evolution of central anticline zone has gone through 4 stages, i.e., faulted block tilting stage, preliminary stage, enhanced stage and permanent stage. The control effect of geological structure and tectonic evolution in central anticline zone on hydrocarbon accumulation is reflected in three aspects. First, the Paleogene dual geological structures are beneficial to the development of structural trap, structural-stratigraphic and structural-lithological composite traps. Second, the high point of paleo-structure was the indicating area for hydrocarbon migration and accumulation, and the faults caused by gravity sliding is the main conduction system for vertical hydrocarbon migration. Third, the formation and distribution of favorable reservoir in Wenchang Formation are also controlled by tectonic evolution.

The research of acidizing technology for oil and gas wells always focuses on the novel acidizing corrosion inhibitor with high performance. BQC(Benzyl Quinolinium Chloride)is a common acidizing corrosion inhibitor, and its dimer derivative BQD has even higher corrosion inhibition performance. However, BQD is a dimer indolizne derivative, generated by its precursor BQC undergoing intermolecular 1, 3-dipolar cycloaddition reactions. According to the conditions of 1, 3-dipolar cycloaddition, the dimer indolizine derivative of Phenacyl Quinolinium Bromide(Di-PaQBr)and the dimer indolizine derivative of Ethyl Acetate Quinolinium Bromide(Di-EAQBr)were synthesized successfully from Phenacyl Quinolinium Bromide(PaQBr)and Ethyl Acetate Quinolinium Bromide(EAQBr)respectively. The yields of two derivatives were increased by enhancing the activity of α-H group in quaternary ammonium salts of the precursor. The structures of Di-PaQBr and Di-EAQBr were identified by high resolution mass spectrum(HRMS), magnetic resonance imaging(NMR)and other technologies, thus confirming the reaction mechanism of dimer indolizine derivative from two quaternary quinolinium moleculars via 1, 3-dipolar cycloaddition. The corrosion inhibitions of PaQBr, EAQBr, Di-PaQBr and Di-EAQBr for N80 steel were evaluated by static weight loss method. The corrosion inhibitions of the two derivatives were significantly superior to original quaternary quinolinium salts in 15% hydrochloric acid at 90℃. It is indicated that when the heterocyclic quaternary ammonium salts are transformed to their dimer indolizine derivative, the corrosion inhibition is likely to be promoted significantly.

Laminar structures of fine-grained sedimentary rocks (e.g., laminar development degree, thickness, thickness difference and continuity) are intrinsic factors affecting the mechanical properties of rocks and crack propagation. Taking the Mesozoic-Cenozoic lacustrine fine-grained sedimentary rocks of Eastern China as an example, the corresponding relationship between different laminar structures and mechanics parameters of rocks is analyzed based on the conventional triaxial test and fracture toughness experiment in combination with image analysis and processing technology. Meanwhile, this paper comprehensively evaluates the influence of the laminar structure difference of lacustrine fine-grained sedimentary rocks on the fracability. The results show that the fracability index of fine-grained sedimentary rocks is negatively correlated with the quantity and continuity of laminae, while positively correlated with the laminar thickness variance and the vertical distribution variance of grains. The developed fine-grained sedimentary rocks with strong continuity show excellent plasticity. The compressive fractures are mainly extended along the lamina interface or the laminae with certain plasticity (e.g., clay lamina or organic lamina), easy to close again in the fine-grained sedimentary rocks, thus reducing the fracability of rock. The fine-grained sedimentary rocks with large difference in thickness and high homogeneity of laminar vertical distribution have high brittleness, which is beneficial to the development of complex and effective mesh fractures in fracturing process, thus improving the fracability of rocks. In addition, the composition, particle texture and diagenesis of fine-grained sedimentary rocks also play an important role in controlling the fracability.

The coupling between the turbulent flow formed by sand-carrying fracturing fluid and particle swarm dynamics is the source of pressure loss in contraction-expansion pipe. By building experiment system, this paper studies the pressure loss of the sand-carrying guar gum fracturing fluid in the contraction-expansion pipe, and the findings are shown as follows:the resistance-reducing ratio of contraction-expansion pipe presents an exponential decrease with the increase of flow rate and variable diameter ratio, while increases linearly with the increase of proppant mass concentration (sand ratio). Through fitting, an equation is obtained to calculate the resistance-reducing ratio of the sand-carrying guar gum fracturing fluid in the contraction-expansion pipe. Considering the dynamic coupling among turbulent flow, particle swarm collisions and accumulation of non-Newtonian fluids, a numerical analysis model and corresponding calculation method are established for solid-liquid two-phase coupling of sand-carrying fracturing fluid in the contraction-expansion pipe. The errors of numerical simulation results and the experimental pressure loss are not more than 10%, thus verifying the accuracy of the above numerical model and calculation method. The numerical simulation studies indicate that fluid velocity is larger than particle velocity on the contraction-expansion pipe end face, where the particle collision rate and stagnation rate are relatively high. There is a large vortex region on the contraction pipe end face, and the vortex flow rate increases with the increasing of proppant mass concentration. When the proppant mass concentration is increased from 0 (no particles)to 700 kg/m³ (sand ratio of 56%), the pressure loss of the contraction-expansion pipe is increased by 15%, which is basically consistent with the result obtained by experiment (16%). The increment in pressure loss of the sudden contraction pipe and the sudden expansion pipe is 22% and 12%, respectively.

Oxygen corrosion is a main factor hindering the wide application of air foam flooding. Although deoxygenation can result in the decrease of corrosion rate. In this study, the high-pressure corrosion reaction kettle is used to simulate the working conditions, and the corrosion rate of N80 casing steel is measured using weight loss method under different oxygen contents (2% -21%)at various pressures (20-50 MPa)and temperatures (70-120℃). According to the experimental results, a mathematical model of the relationship between corrosion rate and partial pressure of oxygen is established. The morphology and composition of corrosion products are characterized using the scanning electron microscope, energy disperse spectroscopy and X-ray diffraction. The results show that the corrosion rate of N80 steel presents the nonlinear decrease with the decreasing oxygen contents of air in the air foam flooding process. However, the corrosion rate is impossible to be controlled below the standard value of 0.076 mm/a. The deoxygenation limit of N80 steel is 0.021% -0.054% at 120℃ when the pressure is between 50 MPa and 20 MPa, and has reached the standard of pure nitrogen. Under the working conditions, the corrosion products of N80 steel are loose and porous with different oxygen contents as well as Fe₂O₃, FeOOH and Fe₃O₄, indicating no ability to protect base metal. In addition, the morphology and composition of corrosion products vary little with the changes in the working conditions.

The foamability is a key factor for the foam drainage in liquid-producing gas wells; however, its evaluation relies on experimental means, lacking support from theoretical models. At present, there is still no foaming model for annular flow and churn flow. Based on the energy conservation law, considering the effect of surface tension on gas entrainment, it is assumed the turbulent kinetic energy of liquid film jet used for inducing gas entrainment is equal to the increase rate of surface energy of the entrained bubbles, so as to establish the forming model, and this model is verified by experimental data. On the basis of the established foaming model, the prediction formula is proposed for the interface tension required by the foaming of annular flow and churn flow, and the foamability of different flow patterns is also analyzed. The results show that with the decreasing of interface tension in annular flow and churn flow, gas is entrained if Weber number is larger than the critical value. The large gas mass flow rate ensures sufficient gas entrained into liquid film, presenting strong foamability. The gas entrainment rate increases with the decreasing of interface tension in slug flow. However, limited by the small gas mass flow rate, the foamability is weak. In bubble flow, bubbles are accumulated at the top interface of bubble flow with the decreasing of interface tension. However, the bubble accumulation rate is limited by the small gas flow rate, which results in weak foamability. The strong foamability exists in annular flow and churn flow, applicable to foam drainage. The interface tension required by foaming can be calculated by the prediction formula proposed in this paper.

Yingdong oilfield is the largest-scale reserves of a single reservoir with highest organic matter abundance, most favorable physical property and optimal development efficiencies in the Qaidam Basin. Through detailed analyses of the Yingdong oilfield, some studies, such as hydrocarbon accumulation conditions and technical challenges, are carried out, and following conclusions can be achieved. The Yingxiongling area is located in Mangya hydrocarbon-generation sag in the west part of the Qaidam Basin, its oil sources are rich; the Neogene Xiayoushashan Formation and Shangyoushashan Formation are dominated by wide and gentle delta front-shore-shallow lacustrine sediments with interbeds of sandstone and mudstone, the sandbodies are widely distributed with favorable physical condition, and the mudstone is the key caprock, combined with high-quality Paleogene hydrocarbon source rocks, a complete source-reservoir-cap assemblage can be formed. Large-scale detachment faults of the Yingdong area connect high-quality Paleogene hydrocarbon source rocks with middle-shallow buried structural traps, thus, reservoirs formed in the early stage are modified, and at the same time, hydrocarbons formed in the later stage continue to migrate and accumulate; in this way, the deep and shallow faults form a relay-style hydrocarbon transport system, and hydrocarbons are accumulated in the shallow structural traps in the later stage; in this area, the middle-shallow faults have good lateral plugging performance which is favorable for preservation of oil and gas. For complex landforms and reservoir features in the Yingdong area, the integral 3D seismic acquisition, processing and interpretation technology is developed for complex mountain areas to provide a reliable foundation for hydrocarbon exploration. For some problems in the Yingdong oilfield like long oil/gas-bearing intervals, great difficulty in identification of fluids, the development mode of multiple oil/gas/water systems in the long intervals is established, and the geologic modeling technology with constraint of multiple conditions on complex fault blocks is also developed. Thus, hydrocarbon accumulation mechanism in the Yingdong oilfield is clear, and some complex key technology of engineering are well solved, providing necessary geologic theories and technical supports for high-efficiency development and rapid production construction in the Yingdong oilfield.

The coal measure gas (CMG) development in Surat Basin, Australia has achieved great success, thus providing new inspiration for solving dilemmas faced by the coalbed methane (CBM) industry in China. The success depends on the reservoir-forming geological conditions derived from the frequent interbedding of thin coal seams and clastic rocks, and two essential aspects are as below:firstly, the single gas-bearing reservoir in this coal measures are relatively thin, but its accumulated hydrocarbon generation potential is huge, and thus can be developed into a high-quality composite gas reservoir; secondly, the thin interbedded reservoir is more conducive to the development of natural fractures, laying a key foundation for the development of high-permeability composite reservoir. In addition, the many and thin coal measures have a large contact surface with the surrounding rocks while ensuring the gas generating capacity, which is conducive to the transformation of CBM into coal measure free gas and also helpful to coal dehydration and the desorption and production of CBM. Coal-bearing strata that have the basic geological conditions similar to the coal-bearing system in Surat Basin are not uncommon in China, such as the Lower Cretaceous in the eastern Inner Mongolia, the Upper Carboniferous in the western margin of Ordos Basin, the Upper Triassic in the western Sichuan Basin, and the Upper Triassic in Chuxiong Basin. It is suggested to pay attention to the new fields and new layers of this type of CMG, and based on the specific parameters and ideas, carry out special evaluation research and special exploration for these areas and coal measures, laying a new natural gas resource foundation to guarantee the national oil and gas security strategy of "increasing reserves and production".

Due to the influence of heterogeneity and effective hydrocarbon expulsion thickness, the mechanism of hydrocarbon migration in thick source strata is still not clear, directly affecting the evaluation of petroleum resources quantity and the establishment of hydrocarbon accumulation model in the basin. The quantitative fluorescence analysis includes a series of techniques including quantitative grain fluorescence (QGF), quantitative grain fluorescence on extract (QGF-E), and total scanning fluorescence (TSF), which can accurately provide such important information as hydrocarbon saturation, maturity and migration path during the past and present geological periods in a fast, simple, economical and efficient way. Using the quantitative fluorescence technique and basin simulation technique, this paper analyzes the hydrocarbon migration characteristics and charging history in the thick source strata of Member 4 of Shahejie Formation in Langgu sag, and also reconstructs the hydrocarbon migration and accumulation process from thick source strata to reservoirs. The results show that the QGF index of sandstone interlayers in thick source strata is generally greater than 4.0, the QGF-E intensity is partially greater than 40, and the λ_max of QGF and QGF-E are quite different. It is indicated that paleo-oil layers once existed in the sand body were diluted and transferred in the later stage; the sand body played the role of "transfer station" during hydrocarbon migration and accumulation. The difference in quantitative fluorescence response indicates that the transit capacity of sand body varies at different depths. The coarser the lithology of sand body is, the more closely the sand ratio approaches to 0.25; the thicker the sand body is, the higher the migration efficiency is, and the larger the transit capacity is. The hydrocarbon generation and thermal evolution histories of source rocks, quantitative fluorescence spectra of sand strata and fault activity histories demonstrate that there are two episodic hydrocarbon transport and accumulation processes in the "transfer station". The first stage is from the end stage of Member 3 of Shahejie Formation to the early stage of Dongying Formation (35-30 Ma). The sand body was mainly filled with medium-light oil and gas. With the opening of faults, oil and gas migrated upward efficiently from the end stage of Member 1 of Shahejie Formation to the early stage of Dongying Formation. When hydrocarbon generation ceased at the end stage of Dongying Formation, the oil and gas saturation in the sand body was decreased. The second stage is from the sedimentary period of Minghuazhen Formation to the present (5-0 Ma). The sand body is mainly charged with a large amount of condensate oil and gas. Since the faults tend to be closed, the oil and gas in the sand body migrate upward by steady seepage; till the formation of better preservation conditions, oil and gas can be accumulated in the buried hill reservoir.

In order to comprehensively and effectively recognize source rocks in Yingcheng Formation of Shuangcheng area in Songliao Basin, the geochemical pyrolysis and molecular organic geochemistry characteristics of drilled core are analyzed, high-abundance mature source rocks have been found for the first time. Combining sequence stratigraphy and geophysical techniques, the distribution law of high-quality source rocks is determined. It was recognized that the average total organic carbon (TOC)content is 2.46%, the organic matter is mainly Ⅱ type, there are a plenty of aquatic algae in organic matter, and the vitrinite reflectance (R_o)is in a range of 0.8% -1.0%, so the source rocks are in the peak hydrocarbon-generating stage. A relatively stable tectonic background of fault depression conversion period is a favorable environment for source rocks deposition, low Pr/Ph ratio of nalkane proved favorable environment for the preservation of organic matter. The high-quality source rocks mainly developed in the transgressive system tract and highstand system tract of sequence SQ1 and sequence SQ2, the thickness of high-quality source rocks in SQ1 is generally 20-80 m, while the thickness of high-quality source rocks in SQ2 is generally 10-30 m. The oil source correlation shows that the high-quality source rocks in Shuangcheng area are the direct hydrocarbon source for the reservoir, and the discovery of high-quality source rocks in Shuangcheng area provides reference for other peripheral fault depression exploration.

Taking the lower submember of Member 3 of Shahejie Formation in Chezhen sag of Bohai Bay Basin as an example, and based on the analysis and testing of core rock X-ray diffraction, thin sections and fluid inclusions, this paper systematically analyzes the parent rock type, diagenetic environment and diagenetic evolution mechanism of the reservoir, so as to explore the control effect of parent rock type on diagenetic evolution of glutenite reservoir. The results show that the Chezhen sag is controlled by the differential tectonic uplift and denudation of Chengzikou uplift in the parent rock area during the sedimentary period of lower submember of Member 3 of Shahejie Formation. Three types of parent rock are successively developed in the glutenite reservoir, shown as carbonate rock-based, hybrid rock-based and felsic rock-based reservoirs from the west to the east; in the glutenite reservoirs of different parent rock types, the difference in the content of rigid particles and soluble minerals determines the compressive capacity of reservoirs and their differences in the solubility in acidic fluids. Under the alternating influence of alkaline-acid-alkaline diagenetic environment, acidic fluids can be effectively communicated by the support of rigid particles, and secondary pores can be formed through the water-rock interaction between acidic fluids and soluble minerals. Controlled by the development conditions of rigid particles and soluble minerals, various types of reservoirs present different diagenetic evolution mechanisms. The favorable reservoirs in the carbonate rock-based reservoir, felsic rock-based reservoir and hybrid rock-based reservoir are vertically located in the shallow regions of 3 200 m, 3 800 m and 4 400 m; on the horizontal level, the scale of favorable reservoirs is successively decreased, and there are differences in the exploration direction among each type of reservoirs.

The pore types of shale, quantitative characterization of pore structures and control factors of pore spaces are important topics in research of shale reservoir. The shale lithofacies of Longmaxi Formation in the southern Sichuan Basin can be classified into siliceous shale, mixed shale and argillaceous shale according to the mineral composition. The pore types, structural characteristics and control factors of pore spaces of different shale lithofacies of Longmaxi Formation in the southern Sichuan Basin were analyzed by technologies of quantitative evaluation of minerals by scanning electron microscopy (QEMSCAN), low temperature N₂ and CO₂ adsorption and high pressure mercury intrusion experiments. The results show that the argillaceous shale is mostly characterized by the sheet-like intragranular pores of clay minerals and filled with the migrated organic matters; the mixed shale is rich in organic matter pores and carbonate dissolved macropores; siliceous shale is rich in organic matter pores. The total surface porosities of shale is mainly provided by the pores with the diameter of 0-500 nm. The surface porosity of minerals (except carbonate and feldspar)and organic matters are mainly contributed by intragranular pores. The surface porosity of organic matter is up to 32.37%, 8 to 16 times higher than that of mineral particles. The mesopores of shale are the main contributors to the pore volume, while micropores make a major contribution to the specific surface area of pores. The average surface porosity, pore volume and pore specific surface area of mixed shale are similar to those of siliceous shale, which means the mixed shale has potential storage capacity. The pore space of mixed shale and siliceous shale with high TOC content is mainly controlled by organic matter pores, but the pore space of argillaceous shale with lower TOC content is mainly controlled by organic matter pores and illite mineral related pores.

Based on systematically analyzing the typical outcrop lithology and sedimentary sequence developing characteristics, further analyzing the conodonts (ancient animal fossils), carbon and oxygen isotopes of whole rocks, and rock thin sections, in combination with the comprehensive analyses of typical drilling, logging and seismic sequences, the Ordovician marine strata in the Middle-Upper Yangtze area are divided into 8 third-order sequences regionally correlated, i.e., OSQ1-OSQ8 sequences. In addition, this study establishes the mutual relationship between chronostratigraphy, conodont biostratigraphy, rock strata and sequence stratigraphy. The sequence boundaries of type Ⅱ and type Ⅲ (submerged unconformity type) have been identified. On a regional level, the type Ⅱ is dominant. Only the top of sequence OSQ7, i.e., the boundary between Linxiang Formation and Wufeng Formation, is typically show as the type Ⅲ. The Ordovician carbonate platform or ramp in the Middle-Upper Yangtze area underwent a gradual submerging process, lasting for more than 25 Ma from the late period of Early Ordovician to the Late Ordovician. Based on the comparison between the whole rock carbon isotope cycle and the sedimentary cycle reflecting the relative change of eustatic sea level and sedimentary paleo-water depth, respectively, the analysis results indicate that less affected by the paleoclimate and sedimentary filling rate, the development of the Lower Ordovician sequence OSQ1 in the Middle-Upper Yangtze area is mainly controlled by eustatic sea level change, while the OSQ2-OSQ8 sequences are mainly controlled by the regional tectonic movement, i.e., a compressive tectonic process produced by the subduction from Yangtze plate to Huaxia plate, so that they are belong to the typical foreland compressive sequences.

To make clear the sedimentary characteristics, sedimentary models, lithologic traps, and exploration fields of lithologic reservoirs from delta front to deep water area of the first sand group of Member 2 of Sangonghe Formation in the Well Pen-1 West sag of Junggar Basin, the palaeogeomorphology was reconstructed by stratum thickness method; the sedimentary microfacies, reservoir properties and hydrocarbon-bearing properties were analyzed according to core observations, heavy mineral analyses, reservoir characterizations and drilling data. The research proposes that the sand bodies of sandy debris flow developed in the deep water area are favorable for lithologic traps. The study area has been divided into three zones by two-stage circular slope breaks, i.e., the inner front delta, the outer front delta and the deep water zone. The underwater distributary channel microfacies of the inner front delta has high reservoir quality and good oil-bearing properties; the channel terminal deposits and sheet sand microfacies of the outer front delta are dominated by tight reservoirs, showing poor oil-bearing properties; in terms of the reservoir quality and oil-bearing properties of the sand bodies of sandy debris flow, the deep water zone is similar with the inner front delta, presenting good top and bottom conditions; further, shielded by tight reservoirs of the outer front delta in the lateral direction, it is conducive to the formation of lithologic traps, and thus is the most favorable oil and gas exploration area in the next step.

Based on the Nuclear Magnetic Resonance (NMR)response characteristics of capillary bond water, clay bound water, clay hydration water and kerogen in shale reservoir, this study carries out an evaluation research on the effective porosity in shale. The samples were obtained from the shale reservoir buried deeper than 3 500 m in Well Z202 and Z201, on which a NMR experiment was performed after gradient centrifugation and gradual drying of the shale samples. The results indicate that the T_2cutoff of capillary bound water, clay bound water and basement signal is within the range of 0.98-1.08 ms, 0.25-0.55 ms and 0.12-0.20 ms, respectively. The three T_2cutoff values decrease gradually, corresponding to the mobile water saturation, capillary bond water saturation and clay bound water saturation of 29.72% -48.12%, 10.25% -20.19% and 12.97% -15.68%, respectively. The T₁-T₂ Spectra for the core dried at 200℃ reveal that disconnected pores exist in shale. The pore system of shale reservoir has been subdivided using the quantitative research method. Then the mean T_2cutoff value of lower limit of effective porosity has been determined as 0.4 ms, corresponding to the lower limit of pore size (4.25 nm). On this basis, this study has established a serious of techniques and methods for evaluating effective shale reservoir, so as to identify the pore fluid type, subdivide the pore system, evaluate the pore porosity, and determine the lower limit of effective pore size.

Due to the change of flow direction and the continuous radial inflow of wall fluid, the flow law of gas and water in horizontal wellbore is quite different from that in conventional vertical well. Based on summarizing the results of previous studies, the horizontal wellbore gas-liquid two-phase prediction model is selected. After verifying the reliability of the model, considering in the wall inflow and the change of gas-liquid flow pattern, and changing multiple factors such as gas flow rate, water flow rate, pipe diameter, dip angle, trajectory fluctuation, and inflow positions for gas and water, etc., this study conducts a comprehensive predictive analysis on flow patterns, pressure distribution law and influencing factors of the horizontal section, and which can provides a theoretical basis for the production management and optimization of horizontal gas wells. The results show that there are three types of flow patterns in the horizontal wellbore under normal production conditions, i.e., stratified flow, intermittent flow and annular mist flow. The diameter and inclination of the wellbore have the most obvious influence on the gas-water flow pattern of horizontal wellbore, while the pipe wall inflow has little effect on flow pattern in the local wellbore. The pressure loss of horizontal wellbore is positively correlated with the gas flow rate, water flow rate, upward inclination angle of trajectory and trajectory fluctuation, and negatively correlated with the pipe diameter and downward inclination angle. Within the predictive range, gas flow rate, upward inclination of trajectory and pipe diameter shows the most significant influence on the pressure loss of horizontal wellbore, which are the key influencing factors of the pressure drop of horizontal wellbore. As the inclination angle of trajectory increases, the pressure drop of horizontal wellbore shows a significant reversal with the change of gas flow rate. Under the condition of low gas flow rate, the pressure drop of horizontal wellbore will increase with the decrease of gas flow rate; under the condition of high gas flow rate, it will increase with the increase of gas flow rate.

The coiled tubing drilling robot uses the differential pressure of inside and outside drilling fluid as a power source to load the weight on bit (WOB)while pulling the coiled tubing. Based on the drilling robot, this study establishes the dynamics model of coiled tubing drill string, and further derives the mathematical model of single parameter control for WOB and rate of penetration (ROP)through the control of drilling fluid displacement. A speed regulating circuit is introduced into the drilling robot to establish a dynamics model of drill string with ROP control function. When the set pressure of relief valve is greater than the differential pressure, the mathematical model is derived for the control of WOB and ROP using two parameters of drilling fluid displacement and throttle valve flow area. When the set pressure of relief valve is smaller than the differential pressure, the mathematical model is derived for the control of WOB and ROP using three parameters of drilling fluid displacement, throttle valve flow area and set pressure of relief valve. Taking the 4.5 in borehole as an example, this paper analyzes the above three mathematical models. The results show that the WOB and ROP of coiled tubing drill string linearly increase when the drilling fluid displacement increases. The drilling robot can crawl forward when the drilling fluid displacement is more than 0.005 m³/s, and the bit can drill normally when the drilling fluid displacement is more than 0.005 7 m³/s. The WOB and ROP can be adjusted steplessly within a certain range by adjusting the flow area of throttle valve and the set pressure of relief valve. The control of drilling parameters such as small displacement, large WOB, large displacement and small WOB can be realized by the combination of three control methods. Based on the control model, the expert database of drilling process can be established according to different downhole conditions. Closed-loop control and automatic drilling can be realized with the help of drilling robots and data measured while drilling.

Timely diagnosis of abnormal working conditions in drilling process is an important means of ensuring fast and secure drilling. Aiming at predicting the gas cut in advance, a self-adaptive observer is used to estimate the unknown bottom hole flow rate and pressure data by inputting the actual standpipe pressure and return pressure data into the observer. The estimated bottom hole pressure data is well consistent with the actual measured bottom hole pressure data; the difference between the estimated bottom hole flow data and the actual wellhead flow data can be obtained; an independent component analysis is performed on such a difference, the actual standpipe pressure and return pressure, and the wellhead flow data. This study extracts independent elements of the data set, determines the statistical control limit under normal working conditions, obtains the statistics of independent elements in the working state, and performs a comparison between the statistics and the statistical control limit, aiming to detect the work conditions for gas cut. Verified by the real drilling data, the above method can accurately judge the normal or abnormal working conditions; compared with traditional methods, it can more timely and precisely predict the occurrence of gas cut.

Vortex induced vibration(VIV)of marine riser is the main factor leading to accidents in offshore oil and gas wells. Based on Hamilton's variation principle, considering the combined effect of the internal fluid of marine riser and the marine environment load outside of pipe, this study establishes the coupled cross-flow and in-line vibration model of the riser. Then the wake oscillator model is used to simulate the cross-flow and in-line vortex-induced force of the riser with large length-diameter ratio. The New mark-β and 4-order Runge-Kutta coupled iteration method is used to solve the calculation model of riser vibration and vortex-induced force. The comparison with experimental data from the existing literature has proved the validity of the model. On this basis, the characteristics of cross-flow and in-line vortex-induced vibration response of the riser in case of different uniform flow sand top tensions are systematically analyzed. The results show that the cross-flow vibration has a frequency locking effect in both shear flow and uniform flow; the in-line vibration is characterized by the frequency locking effect in uniform flow and the multi-frequency locking effect in the shear flow. At the high flow rates, attention should be paid to the effects of in-line and cross-flow vortex-induced vibration.

A large area of gypsum-salt cap rocks are developed in the Cambrian strata of Tarim Basin, as well as a large scale of high-quality pre-salt source rocks and dolostone reservoirs. Depending on abundant hydrocarbon resources and good accumulation conditions, the Cambrian strata have become a successive field with important strategic significance during gas exploration in Tarim Basin. The source-reservoir-cap configuration, structural stability, fault development and preservation condition in Cambrian pre-salt exploration fields are quite different in various areas of Tarim Basin. This not only controls the pre-salt hydrocarbon accumulation and evolution in the Cambrian, but also determines whether the gas reservoirs can be preserved, and eventually points out the favorable areas and breakthrough direction for exploring the Cambrian pre-salt reservoirs. The Cambrian pre-salt source-reservoir-cap configuration can be divided into three superimposition types of source-reservoir-cap, source-reservoir and reservoir-cap. In addition, there are four types of preservation conditions including the continuously stable and intact cap rock, the intact cap rock only stable in the middle stage, the intact and continuously active cap rock, and the lack of regional cap rock with sustainable stability. There are four hydrocarbon accumulation patterns involving in-situ sustainable accumulation, in-situ accumulation after adjustment, multistage accumulation in the stable paleo-uplift, and later accumulation in the active paleo-uplift. The well-preserved area characterized with source-reservoir-cap superimposition, sustained and stable tectonic evolution, and no destroy from faults, i.e., the in-situ sustainable accumulation zone, indicates the favorable prospecting direction in the giant gas area of the Cambrian pre-salt fields. In this area, the isolated intraplatform shoal of Xiaoerbulake Formation is the most favorable target for achieving a breakthrough in giant gas reservoir exploration.

The Lower Paleozoic carbonate rocks in the platform of Tarim Basin are abundant in oil and gas resources. Early studies suggest that carbonate oil and gas reservoirs are controlled by reef flat composites and weathering crust karsts, and are distributed in quasi-layered large area. However, recent evaluation and development practices have indicated that oil and gas enrichment is closely related to fault zone. Based on the newly acquired 3D seismic data, it is clarified that the strike-slip faults in the platform are characterized by diverse structural styles, vertical and horizontal structure segmentation, multi-stage and inheritance of formation and evolution; the geological model of multiple hydrocarbon accumulation in strike-slip fault zones has been established. The latest drilling practice reveals that under the control of strike-slip faults, large carbonate fracture-cavity bodies are concentrated in the fracture zone within 1.5 km of the strike-slip faults in linear, banded and pinnate shapes. The larger the scale of the strike-slip fault is, the better the development of the fracture-cavity body is. The analyses of production performance data and hydrocarbon accumulation show that more than 90% of high-efficiency wells are distributed in the strike-slip fault zones. Oil and gas are mainly accumulated at the top of the large strike-slip faults and their branch faults as well as the transtensional zones. In the exploration and development of ultra-deep marine carbonate rocks in the platform of Tarim Basin, the integrated exploration and development approach of "focusing on fault zones, highlighting hydrocarbon-enriched sections, horizontally expanding boundary and vertically expanding horizons" is the key to promote the profitable development of oil and gas reservoirs.

The Jiuxi depression in Jiuquan Basin is a typical oil-bearing depression characterized with high exploration degree, and its oil and gas exploration potential and favorable exploration area are the key issues in strategic decision-making. Based on the detailed correlation between crude oil type and source in the Jiuxi depression, this paper clarifies the series of strata and region where different types of crude oil are distributed, summarizes the distribution of crude oil, explores the controlling factors of oil and gas migration and accumulation, reassesses the potential of oil and gas resources and predicts favorable exploration areas. The results show that there are three types of crude oils in the central part of Qingnan subsag, i.e., low-mature, medium-mature and high-mature crude oils. The low-mature crude oil is only distributed in the Upper Member of Lower Cretaceous Xiagou Formation and the Zhonggou Formation; the medium-mature crude oil is distributed in the middle and upper strata of the Lower Cretaceous Xiagou Formation; the high-mature crude oil is only reserved in the Lower Member of Xiagou Formation and the Chijinpu Formation. High-mature crude oil can only be found in the Kulongshan tectonic belt in the south and the Liubei tectonic belt in the north of Qingxi sag; medium-mature crude oil can only be found in the Paleogene at the Yaerxia-Laojunmiao-Shiyou gou tectonic belt and the western slope of Shibei subsag. The accumulation of oil and gas in the Qingnan subsag is mainly dominated by a short-range migration, where the effective source rocks in different strata control the distribution of oil pools. The Kulongshan fault and the 121 fault play key roles in controlling the hydrocarbon migration and accumulation in the sag, while the Ya-509 fault plays a key role in controlling the hydrocarbon migration from the Qingxi sag to the southern uplift. Since Neogene, the anticline tectonic belt formed by the northward thrust of Qilian Mountains has provided favorable traps for hydrocarbon accumulation, and the non-isostatic subsidence and uplift of the Qingxi sag has created favorable conditions for the efficient migration of oil and gas from west to east. The Jiuxi depression still presents good hydrocarbon resources and exploration potential. The deep layer in the central part of Qingnan subsag, the eastern section of southern Kulongshan tectonic belt and the medium-deep layer of northern Liubei tectonic belt are favorable areas for exploring high-mature crude oil; the areas of Yaxi and its south are favorable areas for exploring medium-mature and high-mature crude oil; the Paleogene in the south of Yaerxia to Laojunmiao area and the western slope of Yaerxia-Shibei subsag is favorable for exploring medium-mature crude oil; the deep layer in the central and northern part of the Shibei subsag is favorable area for exploring the mature crude oil reservoirs with self-sourced and self-reserved characteristics in Chijinpu Formation.

Through the identification of thin sections, SEM analysis, sensitivity experiment of reservoirs and other analytical methods, this paper subdivides the types of low-porosity and low-permeability reservoirs in Bohai Sea, conducts a detailed study on the reservoir sensitivity of various reservoir-developed intervals and the characteristics, content and distribution of the corresponding clay minerals, and analyzes the effects of different sedimentary conditions on reservoir sensitivity. The results show that the low-permeability reservoirs in Bohai Sea are classified into kaolinite-rich type, illite-rich type, chlorite-rich type and carbonate dense cementation type. By establishing the relation between the genesis of low-permeability reservoirs with reservoir sensitivity, it is proposed that reservoir sensitivity is mainly controlled by three factors:parent rock type, paleoclimate conditions and sedimentary microfacies. First, parent rock type has a decisive influence on the evolution of the Paleogene clastic reservoirs in the study area. There are three main types of parent rocks, i.e., clastic reservoirs with intermediate-basic volcanic rocks as parent rocks, pyroclastic-kaolinite type of clastic reservoirs with intermediate-acidic volcanic rocks as parent rocks, and illite type of clastic reservoirs with metamorphic rocks as parent rocks. Paleoclimatic conditions have a vital impact on reservoir sensitivity. Sedimentary microfacies have a direct influence on the differentiation of clay minerals is directly affected and an indirect influence on the late diagenesis.

To further analyze the characteristics of sweet spot of shale gas, aiming at two sets of ancient shale series of strata in Niutitang and Doushantuo formations drilled in Well Eyangye-2, continuous sampling while drilling was conducted in the well site; the changes of the carbon isotope values of mud gas and the carbon isotope values of cuttings head space gas with time series were measured. Based on the continuous high-density carbon isotope data, the genesis and enrichment rule of shale gas were analyzed in combination with gas composition, formation lithology and reservoir physical properties. Based on carbon isotope fractionation characteristics of the gas released from cuttings, the geologic elements of sweet spot in shale gas reservoirs were analyzed in combination with the development degree of nanopore in shale. The results show that the reversal characteristics and humidity characteristics of methane and ethane indicate that Niutitang Formation may have good potential for shale gas exploration. The variation of carbon isotope value of mud gas with true vertical depth (TVD) is related to the residual liquid hydrocarbons in the oil generation window. The light isotope at the bottom of the Niutitang Formation shale reveals that there are large quantities of residual liquid hydrocarbons, showing great resource potential. The dry component and heavy carbon isotope of the Doushantuo Formation shale gas may have certain relation with the hydrocarbon generation material and the evolution history of hydrocarbon generation and expulsion. The isotope fractionation characteristics of the gas released from cuttings are relevant with the development degree of nano pore-throat system in shale. It should be practical to use the development degree of nano pore-throat system as the judgment index of sweet spot in shale gas. This field-based, continuous, and dynamic analysis method of carbon isotope provides more valuable references for analyzing the genesis and enrichment law of shale gas and identifying geological sweet spots.

In the production process of tight gas wells, the fracture conductivity, reservoir fluid distribution and gas-water relative permeability will vary with time. However, the traditional models always ignore these effects. Based on this, the time-dependent factors, including fracture conductivity and relative permeability are introduced to construct the seepage model for gas production. Subsequently, the simulations are conducted to analyze the effects of time-dependent mechanisms on gas well productivity. Results show that time-dependent fracture conductivity will accelerate the gas production decline because the fluid flow towards the wellbore will consume more energy. In the production process, besides the expansion of rock and fluids, the pressure gradient can decrease the irreducible water saturation and promote the migration of irreducible water, resulting in the increase of water permeability and the decrease of gas permeability. This effect will reduce the period of stable gas production and increase the water production. The production of a gas well in Yan'an gasfield indicated that ignoring the time-dependent effects will severely underestimate the water production and overrate the period of table gas production. Finally, according to the development mode of Yan'an gasfield, the gas well productivity model with considering the time-dependent factors for stereoscopic well pattern should be further studied.

In the fractured tight reservoir, fractures are the channels for oil flow, and also water transfer after water flooding. Fractures may result in low sweep efficiency during water flooding, thus leading to ineffective exploitation. Moreover, the sealing of fractured reservoirs may cause many problems, such as poor sealing effect for large fractures and short-term durability. Aiming to solve those difficulties, two types of water-shutoff plugging systems have been developed:water-soluble phenol-formaldehyde resin gel and monomer polymerization breakthrough pressure plugging agent. On this basis, the authors determine the gelation performance, stability and strength of plugging agents at 70℃. Then the effects of various factors on the breakthrough pressure of water-shutoff agent have been studied by fracture simulation using a tube. The breakthrough direction of plugging agent and the influencing factors has been explored by experiments performed in a visible tube. The results show that the breakthrough pressure of water-soluble phenol-formaldehyde gel increases with the increasing of gel strength, and decreases with the increasing of tube diameter; it decreases first and then increases with the raising of water injection speed, and finally stabilizes. As for the monomer polymerization plugging agent, the breakthrough pressure increases with the increasing strength of plugging agent; it increases first and then decrease with the increasing of tube diameter. In the tube visualization experiments, the plugging agent did not break through only along the center of tube, which was related with the strength and adhesion of plugging agent.

Mineral-filled cemented natural fractures are abundantly distributed in unconventional reservoirs such as shale. The interaction mechanism between hydraulic fractures and cemented natural fractures plays a key role in controlling the generation of complex fracture network. Using the cohesive zone model based on flow-deformation coupling, this study establishes the numerical model of the interaction between hydraulic fractures and cemented natural fractures. The cementing strength of natural fracture is simply characterized using the parameter of fracture energy. The feasibility of the proposed method has been verified by comparing with the asymptotic solutions of a single hydraulic fracture propagation model in limiting regimes. Furthermore, this study investigates the effects of in-situ stress, approaching angle, cementing strength ratio, fracturing fluid viscosity, injection rate and other factors on the interaction between hydraulic fracture and natural fracture. Research results show that both the horizontal in-situ stress difference and the minimum horizontal in-situ stress jointly control the crossing behavior of hydraulic fracture. Under the same horizontal in-situ stress difference, different minimum horizontal in-situ stresses may lead to a difference in the final geometries and pressure distribution inside the hydraulic fractures. The less the approaching angle is, the more easily the hydraulic fracture will deflect into the natural fracture. The larger the cementing strength ratio is, the more difficult the hydraulic fracture will turn into the natural fracture. The same product value of the injection rate and fluid viscosity would lead to similar fracture geometry and pressure profiles at the injection point if the internal fluid leak-off is ignored. In addition, the low pore pressure zone in front of the crack tip is relevant to the size of the cohesive zone:the smaller the cohesive zone is, the lower the pore pressure will be.