Abstract:To study laws of oil and gas accumulation in K1n1 in main central depression zones of Haita basin，based on analysis of oil and gas distribution law，the control effect of fault-trap source rock，fault and potential on oil and gas accumulation in K1n1 in main central depression zones of Haita basin was evaluated comprehensively and quantitatively by analyzing the spatial relation between oil/gas distribution，source rock，fault and potential. The result indicates that the control effects of source rock，fault and potential on oil and gas accumulation in K1n1 in main central depression exist in the following three areas：①areas of source rock control faults-enclosed oil/gas accumulation and its distribution areas；②early-extensional faults provide sealing conditions for faults-enclosed oil/gas accumulation；③low potential areas control the position of faults-enclosed oil/gas accumulation. The comprehensive evaluation value for control of source rock，fault and potential on oil and gas accumulation in K1n1 of main central depression zones in Haita basin should be more than or equal to 2.63. According to this，favorable areas for oil and gas accumulation in fault trap of K1n1 in main central depression zones of Haita basin were predicted. They distribute mainly in sandbodies of fan delta front in Surennouer，Wudong slope of Wuerxun sag，Sudeerte of Beier sag，east sub-sag of south Beier sag and central sub-sag of Tanan sag；followed by the sandbodies of fan delta front in Hunouren of Beier sag，east sub-sag of Tanan sag.

Abstract:Based on the comprehensive application of core，electron microscopy and geochemical and logging data，the salinization process of the lake basin was restored to establish different sedimentary sequence at different salinization stages in order to clarify the relationship between saline environmental deposition and shale oil-gas. The properties of sedimentary rocks in different saline environments were studied such as hydrocarbon-generating ability，reservoir property，oil bearing property，mobility and so on. The results show that the paleosalinity of the upper of the fourth member of Shahejie Formation is higher than that of the lower of the third member of Shahejie Formation in Jiyang depression in the whole，but the salinization evolution is different in different sags. Salinity variation controls evolution sequence of lithology. Gypsum rock，Glauber’s salt，gypsum mudstone and dolomite lithology deposited in sequence in hypersaline water phase；limestone，argillaceous limestone/lime mudstone deposited in sequence in salt water phase，forming lime and organic matter laminae；argillaceous limestone/lime mudstone-calcareous mudstone/shale deposited in sequence in brackish water phase. Among them，the laminated shale formed in the salt water phase has strong hydrocarbon-generating ability，superior reservoir quality，high oil content and good fluid mobility，which is considered as the most favorable for the enrichment of oil and gas.

Abstract:In order to ascertain the hydrocarbon accumulation characteristics in the Sandaoqiao area of the western Yakela faulted uplift in northern Tarim Basin，based on previous achievement，the oil geochemistry features such as physical prop? erty of crude oil，steranes and terpanes biomarkers and the fluid inclusions obtained from new wells drilled in the study ar? ea have been comparatively analyzed. The results show that there are respectively continental and marine hydrocarbon sources in this area where hydrocarbons are likely to migrate into. And the main periods when the continental and the ma? rine hydrocarbon were generated are both in Himalaya period in this area. The different distributions of these oil and gas are controlled by the pre-Mesozoic geological structure. The boundary of the continental and marine oil is in the convex ridge of the Pre- Mesozoic anticline. The physical properties and geochemical characteristics of crude oil from Well Qiaogu1 and Qiaogu102 in the south convex-ridge are relatively low wax and high sulfur. GC-MS analysis results suggest that the C19-C21 tricyclic terpane is relatively high with C23 as the main peak of tricyclic terpane and the oil is also rich in sulphur fluorine. These physical properties and geochemical characteristics of crude oil from Well Qiaogu1 and Qiaogu102 show that it came from the marine hydrocarbon source of the southern carbonate. On the contrary，the physical and geo? chemical features of the crude oil obtained from Well Qiaogu3 and Well Sha53 drilled at the north of the area are different which indicate continental sourced crude oil.

Abstract:Since it is risk to implement scheme of deep water fault block reservoir development，Sangos oilfield of west Africa is taken as an example. Based on the reservoir geological modeling process，well logging，seismic and dynamic data were used comprehensively for the quantitative evaluation of fault seal. Firstly，salt diapir and salt piercing were identified here as two main fault modes which are salt related structure. Secondly，according to the characteristics of tectonic and sedimentary，shale smear was thought to be the main control factors of fault sealing and its three parameters（SSF，CSP，SGR）were analyzed and compared，and CSP and SGR were finally used step-by-step to calculate the transmission multiplier for each fault based on grid model. Finally，the concept of fault connectivity was defined as a quantitative and reasonable parameter of fault evaluation，and it was used to characterize the transmission capacity of each fault. The research shows that：the connectivity of five faults can be ordered as F5>F4>F3>F2>F1，and F1 is sealing completely. The research result is validated by the actual dynamic data of subsequent development wells.

Abstract:For the purpose of accurately forecasting development of favorable volcanic reservoirs in Chepaizi area，Junggar Basin，the pores/fractures characteristics of different lithologies of volcanic rock were observed with microscope and Computer Tomography（CT）. And then effects of secondary action on volcanic rock evolution were discussed combining with geological conditions. Moreover，the relationship between oil-bearing and reservoir characteristics of volcanic reservoir were ascertained with core analysis，log data interpretation and fluorescence slice observation. The results show that in the study area，the lithologies and lithofacies of volcanic rock control the development of primary pores/fractures of volcanic rocks，and they also affect the formation and development of secondary pore/fractures. Vesicles，contraction fractures，volcanic glasses are commonly found in rocks of andesite and andesitic breccias，which can provide initial reservoir spaces for the extension of fracture under tectonic stresses and for the infiltration，dissolution and precipitation of surface and underground water. As for the tuff，its particles were altered seriously due to the hydrolysis-dissolution of unstable minerals and the majorities of primary pores were refilled due to strong mechanical compaction underground，so the volume of reservoir space was reduced dramatically and its property became poor. Almost all of the oil-bearing volcanic rocks in the study area are relative to factures，and the oil-filling pores are only found near fractures. According to this，the pore porosity，the fracture porosity，and the fracture factors of volcanic rocks were calculated using log data，therefore the favorite reservoir areas of volcanic rocks in the study area were forecasted，which include the south area near Well Pai 674，the east area near Well Pai 66，and the northwest area near Well Pai 682.

Abstract:Lunpola basin is a Paleogene continental residual one and the only basin in Tibet with industrial oil discovery.Early exploration revealed that the thin oil distributed in the reservoirs with their buried depth more than1 500 m. However，the crude oil in new Well W1 at the depth of 1 800 m is still heavy，which indicates the complicated vertical zoning of crude oil in this basin. In order to clarify the geological origin of crude oil thickening and the favorable thin oil-enriched zone，physical properties，distribution rule and geological factors of crude oil thickening were studied comprehensively based on geological and geophysical data. The results show that the crude oil thickening in reservoirs of the Niubao Formation in Lunpola basin was mainly controlled by secondary alteration instead of low-mature oil. The reservoir of Well W1 locates under the oil-gas oxygenation level，which is 800 m below the unconformity surface. Structural interpretation and core observation show that the fractures and high-steep cracks of Well W1 are widely developed，for it locates in central fault region of central depression zone of the basin. This can lead to the loss of light components of the crude oil，so it is easy to be thickened. Thus the vertical zoning of the crude oil is clear.

Abstract:Shallow secondary gas reservoir and heavy oil reservoir mostly distribute in the periphery of source sub-sag，uplift belt and central uplift belt of in Jiyang depression. Based on the study of geology and geochemistry study in Jiyang depression，the relationship between the shallow gas reservoir and heavy oil reservoir were discussed through gas sources and genesis，thickening mechanism of heavy oil，dynamic balance between natural gas migration and accumulation and distribution pattern of shallow secondary gas reservoir and heavy oil reservoir. The results show that the shallow secondary gas reservoir is associated with the heavy oil reservoir，and the petroleum biodegradation and dissolved gas in the heavy oil reservoir provide its gas source. There are three evident distribution patterns：①Heavy oil reservoirs often develop below or along the downdip direction of shallow secondary gas reservoirs；②Shallow secondary gas reservoirs may not exist above or along the updip direction of heavy oil reservoirs；③No shallow secondary gas reservoirs exist above or along the updip direction of conventional oil reservoirs. The shallow gas reservoir and heavy oil reservoir formed a relatively independent system of hydrocarbon generation，migration and accumulation.

Abstract:The faults were divided into single-stage active fault，growth fault and multi-stage active fault according to the fault activity period in the Gao89 area of Dongying sag. The fault activity of the three types ended in the order mentioned above，so their vertical safety becomes poorer correspondingly. According to the allocation relationship between the regional seal and the vertical extension of fault，the faults were divided into embedded type，lower broken type and broken through type，and the seal completeness of them decrease in the order，so the vertical safety becomes poorer correspondingly. According to the allocation relationship between the fault throw and the thickness of the direct seal，the faults were divided into intact top seal type，seal connected type and seal apart type，and the completeness of their direct seals decrease in the order，so their vertical safety become poorer correspondingly. The comprehensive evaluation system was established to evaluate carbon dioxide flooding and the vertical safety of the fault during carbon dioxide sequestration through analyzing fault activity periods，the allocation relationship between the regional seal and the vertical extension of fault，the allocation relationship between the fault throw and the thickness of the direct seal，the bonding section thickness of the direct seal and the fault dip in the Gao89 area. The results show that the allocation relationships between the regional seals and the vertical extension of faults are mostly embedded type and lower broken type. The allocation relationships between the fault throw and the thickness of the direct seal are the intact top seal type and the seal connected type without the seal apart type. The fault dip is between 40° and 65°. According to the study result，the vertical safety of faults are high in the Gao89 area.

Abstract:The fracture development features of the Bashijiqike Formation in Keshen gasfield were studied by making full use of core observation and micro-resistivity image logging interpretation. The image logging results collected in oil-based mud for Well Keshen2-2-12 were compared with those in water-based mud，then the differences between water-and oilbased mud in the effect of fracture recognition were summarized. The results show that large aperture fractures can be identified. However，some small aperture fractures are difficult to be seen in the oil-based mud image logging. Generally，the high-angle fractures are easily to be seen，while the low-angle fractures cannot be detected，and the lost of cross bedding information are serious in the oil-based mud imaging. The oil-based mud image logging results can be calibrated with core observations，the caliper logging，acoustic logging and array acoustic logging，and the accuracy of fracture recognition and interpretation will be improved in this way.

Abstract:Gravels，with different granularities and compositions，are widely developed in continental faulted basin，which is the key factor that influences the velocity change of sandy conglomerate. It is not suitable to use rock physical model based on homogeneous medium. In order to accurately calculate compressional and shear wave velocities and analyze its influence factors，an extended time-average equation was established considering variable parameters through selecting 100 core samples from 10 wells in the northern steep slope of Dongying sag for ultrasonic measurement and data analysis. The contents of gravel，sand-sized clastic particle，matrix，cement and pore fluid were obtained through rock slice identification，and then compressional and shear wave velocities，obtained through ultrasonic test of core samples in the laboratory，were put into the extended time-average equation to obtain the compressional and shear wave velocities of sandy conglomerate. Model test and actual applications indicate that the calculation accuracy of compressional and shear wave velocities of sandy conglomerate derived from the extended time-average equation is 10% higher than that from Wyllie time-average equation，and the compressional and shear wave velocities derived from the extended time-average equation are more accurate than those derived from petrophysical model based on homogeneous medium.

Abstract:Sandstone is close to mudstone in P-wave velocity，density，P-wave impedance and other conventional parameters sometimes. So，it is difficult to solve the reservoir prediction problems and to discriminate gas-bearing sandstone from shale by using general reservoir prediction methods such as post-stack impedance inversion and single parameter prediction. Because of multiple solutions of seismic data，the result of reservoir prediction is always at risk of failure. Therefore，based on seismic rock physics analysis，combined with multi-parameter probability fusion method to fuse petrophysical parameters and geophysical parameters，pre-stack reservoir prediction was carried out，which may reduce multiple solutions and enhance prediction precision with fewer risks. It is feasible，and also reveal and characterize the uncertainties in reservoir prediction. The results of the study show that pre-stack seismic inversion parameters such as P-wave velocity and impedance，S-wave velocity and impedance，longitudinal wave velocity ratio and Poisson’s ratio may discriminate sandstone from shale and identify gas-bearing sandstone to some degree，but the precision of prediction results were not high. The method of multi-parameter probability fusion may extract as much as possible information of reservoir for prediction. Therefore，the method not only can effectively discriminate the lithology and distinguish gas-bearing formation from non-gasbearing formation，but also improve the precision of reservoir prediction. At the same time，the precision of the thickness of sand layer and gas layer predicted by multi-parameter probability fusion method is higher than that of conventional elastic inversion method.

Abstract:During the production of coal bed methane（CBM），the CBM first is desorbed from coal matrix after the reservoir pressure is dropped by pumping water，and then seepages into the wellbore from the cleat to be produced. According to the production characters of CBM，especially considering the gas diffusion，the compression effect of coal cleat and the shrinkage effect of matrix during the stage of development，a mathematics expression for a CBM material balance model was established based on CBM volumetric balance equation by which an important relation function between CBM reservoir pressure and time was set up to find the change rules of CBM production over time. The solution was achieved through programming to predict dynamic production of CBM. The calculation was done based on a case study of production wells drilled at Yanchang oil and gas field，and the results obtained show that：diffusion of CBM has a remarkable influence on CBM development，and the stronger the diffusion is，the higher the production peak is and the earlier the peak appears. CBM diffusion has a critical role to help stabilize production at later period.

Abstract:Dominant flow path tends to be formed in the low permeability reservoir after long term waterflooding in mediumhigh water cut period，which results in invalid water circulation and severe impact on the water flooding result. Low-porosity and medium-low permeability reservoirs in the Sanjianfang Formation of Wenxi1 block in Wenmi oilfield were taken as examples. Controlling factors of the formation of the dominant flow path were analyzed according to lithology，deposition and microscopic characteristics. An approach to identify the dominant flow path was proposed by use of dynamic and static data and standards suitable for the study area were given. A comprehensive evaluation index model was built up through optimizing dynamic and static parameters. The results suggest that the formation of the dominant flow path in the Sanjianfang Formation of Wenxi1 block is controlled by the lithology，sedimentary facies and microscopic characteristics. The static characteristics are concluded as coarse lithology，good physical property and deposited on the main stream line of underwater distributary channel. The dynamic characteristics include the difference of water injection profile，the sudden rise of water cut in production wells and the rapid flow and breakthrough of tracer material with thin layer. The judging criteria are as follows：permeability is larger than or equal to 40×10-3 μm2；permeability ratio is larger than or equal to 20；pore and pore throat radius is larger than or equal to 3.6 μm；monthly increase of water cut is larger than or equal to 30%；water absorption in single layer is larger than or equal to 50%.

Abstract:It is difficult for current existing micro-models to simulate and quantify displacement of residual oil film. A laboratory system was developed to model displacement of oil film in porous media，and flooding experiments on oil film were conducted with several single and composite oil displacement agents. Quantification results of displacement efficiency of oil film were presented. At the same flow conditions，the composite system of surfactant/strong alkaline has the highest displacement efficiency of 74.32% with low interfacial intension，strong emulsification and wettability change ability. Surfactant solution and its composite system consisting of weak alkaline or salt have low interfacial intension and strong emulsification and their displacement efficiencies are between 57.49% and 71.98%. The displacement efficiencies of strong base and weak base solution capable of wettability change are 56.09% and 10.14% respectively. However，the displacement efficiency of salt solution with mass fraction of 0.2% is the lowest without the above three displacement properties. Research results show that higher oil film displacement efficiency can be obtained by chemical agents with lower interfacial tension，strong emulsification and wettability change ability.

Abstract:Due to the non-Newtonian characteristics of fluid in heavy oil reservoir during cold production，conventional methods cannot be used in precisely predicting horizontal wells productivity when its dynamic production characteristic is different from that of conventional oil wells. During the cold production，the rheological behavior of heavy oil can be assumed as Bingham type. According to the percolation features of cold production in heavy oil reservoirs，threshold pressure gradient was taken into consideration. Then the seepage filed of the horizontal well was divided into inner and outer two parts while the productivity formulas were derived respectively. In addition，moving radius was obtained by the average pressure derivative method. Based on the equivalent principle of flow rates for both regions，nonlinear equations regarding to the horizontal well production rate and the moving radius were established. Eventually，the values of the oil production rate and moving radius under arbitrary time were acquired by Newton-Raphson method. Numerical results from a case manifest that the production performances of the well by cold production in the heavy oil reservoir can be characterized by high initial production，rapid decline and relatively long period of stabilized production，which can provide theoretical foundation for oil production forecast and later optimization adjustment. Sensitivity analysis results show that longer horizontal section length and larger reservoir thickness bring higher production during the same production time. And lower threshold pressure gradient and lower oil viscosity bring higher production.

Abstract:Aiming at the problems of poor adaptability and stability of the conventional profile control agents in the hightemperature and high-salinity fractured reservoirs，a new kind of temperature-resistant and salt-tolerant profile control agent particles were synthesized by solution polymerization taking ammonium persulfate as initiator，acrylamide and dimethyl acrylamide 2 sodium sulfonate as comonomers，N，N-methacrylamide as the chemical crosslinker and hectorite as the inorganic crosslinker. The micromorphology and viscoelasticity of the agent were characterized. Shear-resistance property，swelling property，plugging property and EOR ability were evaluated. The results show that the profile control agent is a kind of irregular massive particles with initial average size of 66.87 μm. The particle size could reach to about 3.53 times of the initial size after 48 hours under the condition of simulated formation water and 75 ℃. The elastic and viscous moduli are 1 600 and 150 Pa respectively. The agent has good plugging property and the plugging ratio is all above 80%. The recovery efficiency may be enhanced by 20.1% after water flooding under the permeability ratio of 4.03. The profile control agent has better adaptability in the high-temperature and high-salinity heterogeneous fractured reservoirs.

Abstract:Guided by theories of reservoir engineering，physical chemistry and organic chemistry，by means of instrumental analysis，chemical analysis and physical simulation，taking reservoir and fluid of Daqing oilfield as research object，experiments have been carried out considering evaluation indexes of viscosity，rheological property，viscoelasticity，interface property，molecular coil size，state of molecular aggregation and injection pressure of salt-resistance polymer-surfactant solution，so that polymer-surfactant can be more suitable for the reservoir. Results show that the minimum concentration of β-cyclodextrin that is needed to completely inhibit the association of polymer-surfactant molecules is 0.065% under the condition of sewage or clean water from Daqing. With the increase of the concentration of β-cyclodextrin，the association of the molecular chains of the polymer-surfactant became weaker and the branch connected each aggregation became thinner，thus the molecular configuration presented a kind of loose branching structure. This resulted in the drop of viscosity and the loss of viscoelasticity. With the increase of the concentration of β-cyclodextrin，the molecular coil size of the polymer-surfactant solution decreased as well as the compatible pore throat size，which resulted in a wider permeability scope.

Abstract:With the promotion of“existed/incremental production”management mode in oilfield，previous optimization model cannot meet the overall requirements of oilfield development planning. According to the reality of the middle-long term development planning of the oilfield，a concept for exited/incremental production suitable for the development planning was defined. An optimization model of incremental production composition was established taking new wells in developed area and undeveloped area as decision variables，actual oilfield requirements，relations and laws as constraint factors，and the maximum profit and minimum investment and cost as the goal. And then integrated optimization of reserves，workload，oil production，investment，cost and profit may be realized. The model was solved by using interior-point method，and was applied to development planning of certain waterflooding oilfield for the“13th Five-year Plan”. The application indicates that the benefits of new wells in the undeveloped areas are much more than those in the developed areas. So all remaining investments turn to new wells in the undeveloped areas，which reflects the optimization for benefit-centered planning after the minimum demands for the developed areas were met. The established model provides the ideas and methods for the optimized decision-making under“existed/incremental production”management mode.

Abstract:For the high temperature and high salinity reservoir condition in Xidaliya，surfactant system SA with low interfacial tension was selected and compound with the lab made microspheres Z10，both having good resistance to temperature and salt，in order to improve the development effect of Xidaliya oilfield by surfactant-microspheres displacement. The features of flooding pressure and resistance for the new surfactant-microspheres compound system were studied under high temperature and salinity condition. Physical simulation experiments of enhancing oil recovery using the compounded system displacement were carried out under homogeneous and heterogeneous conditions respectively. The results show that the compound system has the best flooding performance with a good injection property and an effective plugging when the core permeability is from 200×10-3 to 1 000×10-3 μm2，and the injection pressure fluctuates drastically and regularly and the resistance coefficient can be as high as above 7. Contrast experiments of oil displacement between the compound system and the surfactant show that the former has an obvious effect of increasing oil and decreasing water，brings great improvement of recovery efficiency，and the total recovery is about 14% higher than using the surfactant alone. The microsphere and the surfactant exert good performance on“adjusting”and“washing”respectively. Besides，the compound system can change the distribution of fluids and pressure making the development of low permeability layer effectively，and has a good effect on enhancing oil recovery.

Abstract:In order to reasonably allocate the acid fluid volume for staged acidizing in a horizontal well for heterogeneous carbonate reservoir，it is crucial to fully consider the permeability heterogeneity along the wellbore and to accurately evaluate the damage radius and damage permeability of each segment. Based on the Darcy’s law，a model of damage radius was deduced with consideration of drilling bottom-hole pressure difference，soak period of drilling mud and permeability distribution. Based on reservoir-wellbore coupling model and tested inflow profile，a new approach of calculating damage permeability distribution was proposed. The process of acid fluid volume optimization for heterogeneous carbonate reservoir was illustrated by a case study on real well data. Since the influence of the permeability heterogeneity and the real production data is fully considered，the proposed design procedure can improve the reasonability of acid fluid volume allocation along the horizontal well，remove the formation pollution effectively and restore oil well productivity compared to the traditional non-specific acid allocation pattern which is based on the elliptic cone damage zone model.

Abstract:For efficient recovery of offshore heavy oil，amphiphilic polymer with better emulsification and solubilization behavior for heavy oil was developed. Core physical simulation method was applied to evaluation on injectivity，mobility control，recovery efficiency of the amphiphilic polymer. The amphiphilic polymer shows good injectivity in offshore high permeability sandstone reservoir，and the best mobility control and the highest recovery efficiency：1 000 mg/L of amphiphilic polymer solution has a resistance factor of 201 and a residual resistance factor of 115. Viscosity reduction polymer has better interfacial activity，poorer mobility control，and similar displacement effect as ordinary polymer，whose recovery efficiency is 90.13% in homogenous cores and only 33.76% in heterogeneous cores. Experiment results show that the amphiphilic polymer in one-dimension homogenous core experiment is suitable for the profile control agent controlled by small-slug mobility and that in constant-pressure oil displacement experiment may slow the trend of oil production decline with water flooding. Three times of pore volume of ordinary polymer and amphiphilic polymer were injected cumulatively in oil displacement experiment with three-layer heterogeneous cores and their recovery efficiencies were 32.73% and 54.45% respectively. The amphiphilic polymer with better mobility control and emulsification ability shows great potential in chemical flooding of the heterogeneous heavy oil reservoir.

Abstract:Due to geologic and engineering factors，the number and length of the fracture in the vertical wells is various in simulated reservoir volume. Although many productivity models have been proposed for the vertical wells with branch fractures，they are all special cases of two-branch，four-branch and symmetry multi-branch with infinite flow in fractured wells.Thus their reliabilities cannot be guaranteed. Therefore，a new productivity model of the vertical wells with multiple arbitrary fractures needs to be established. Conformal transformation was applied to calculate the productivity of the vertical wells with multiple fractures under steady state flow pattern. Our model is verified by these existing models. In addition，reservoir permeability，thickness，fluid viscosity，length，conductivity，and branch number of the fractures that affect the productivity of the fractured wells were analyzed through cases. The results show that the new built model matches the commonly used models well at a selected value，so its accuracy can be verified. The productivity of the fractured vertical wells increases with the increase of the fracture length，conductivity or branch number，but its increasing range may decrease with the increase of supply radius or branch number.