Based on comprehensive analysis of core, well logging, seismic and production data, the multi-scale reservoir space, reservoir types, spatial shape and distribution of fractures and caves, and the configuration relationship with production wells in fracture-cavity carbonate reservoirs were studied systematically, the influence of them on the distribution of residual oil was analyzed, and the main controlling factors mode of residual oil distribution after water flooding was established. Enhanced oil recovery methods were studied considering the development practice of Tahe oilfield. Research shows that the main controlling factors of residual oil distribution after water flooding in fracture-cavity carbonate reservoirs can be classified into four categories: local high point, insufficient well control, flow channel shielding and weak hydrodynamic. It is a systematic project to improve oil recovery in fracture-cavity carbonate reservoirs. In the stage of natural depletion, production should be well regulated to prevent bottom water channeling. In the early stage of waterflooding, injection-production relationship should be constructed according to reservoir type, connectivity and spatial location to enhance control and producing degree of waterflooding and minimize remaining oil. In the middle and late stage, according to the main controlling factors and distribution characteristics of remaining oil after water flooding, remaining oil should be tapped precisely by making use of gravity differentiation and capillary force imbibition, enhancing well control, disturbing the flow field and so on. Meanwhile, backup technologies of reservoir stimulation, new injection media, intelligent optimization etc. should be developed, smooth shift from water injection to gas injection should be ensured to maximize oil recovery.
An innovative perforation method of interlaced fixed perforation was put forward based on the analysis of the characteristics of fractures in various periods of perforation and conventional perforation modes. By conducting a large-scale perforation shooting experiments, we investigated the morphology, propagation mechanism and propagation law of the near-wellbore fractures generated during perforating processes under different fixed angle and interlaced angle combinations, and discussed the control method of near-wellbore fractures in different types of unconventional oil and gas reservoirs. The experimental results show that: (1) The interlaced fixed perforation strengthens the connectivity between the perforation tunnels not only in the same fixed plane but also in adjacent fixed planes, making it likely to form near-wellbore connected fractures which propagate in order. (2) Three kinds of micro-fractures will come up around the perforation tunnel during perforation, namely type I radial micro-fracture, type II oblique micro-fracture and type III divergent micro-fracture at the perforation tip, which are interconnected into complex near-wellbore fracture system. (3) Different types of perforation bullets under different combinations of fixed angles and interlaced angles result in different shapes of near-wellbore fractures propagating in different patterns. (4) By using the interlaced perforation on fixed planes, arranging fixed planes according to the spiral mode or the continuous “zigzag” shape, the desired near-wellbore fractures can be obtained, which is conducive to the manual control of main fractures in the fracturing of unconventional or complex conventional reservoirs.
A great number of published data and our experimental results of interfacial tensions between hydrocarbon compounds and CO2 were collected and screened. Based on these experimental data, the changing laws of interfacial tensions between different kinds of hydrocarbon compounds and CO2 were obtained, interfacial tensions between different kinds of saturated chain hydrocarbons and CO2 were compared with each other, and interfacial tensions of three different binary system (monocyclic hydrocarbon compounds-CO2 system, hydrocarbon compounds monocyclic and chain structure-CO2 system and dicyclic hydrocarbon compounds-CO2 system) were compared with those of saturated chain hydrocarbon compounds-CO2 system. It is found that molecular structure is the main factor to affect the sizes of interfacial tensions between hydrocarbon compounds and CO2; when carbon numbers of different kinds of hydrocarbon compounds are equal, their proper order from big to small in interfacial tension is: polycyclic hydrocarbon, hydrocarbon monocyclic and chain structure, monocyclic hydrocarbon, saturated chain hydrocarbon. The comparison results at different pressure conditions were respectively used to establish the conversion relations in equivalent carbon number between interfacial tensions of cyclic hydrocarbon-CO2 systems and those of saturated chain hydrocarbon-CO2 systems.
The Silurian Longmaxi shale gas play in Jiaoshiba Structure in the southeast margin of the Sichuan Basin is studied to discuss the key controlling factors of shale gas enrichment in complex tectonic zone with high evolution. Jiaoshiba Structure is a faulted anticline which experienced multiphase tectonic movements. The Longmaxi Formation has high thermal evolution degree with Ro more than 2.2%, 35-45 meters thick high-quality shale (TOC > 2%) in its lower part. The reservoir is overpressure with a pressure coefficient of 1.55, and the shale gas production and pressure are stable. Structure type, evolution and geochemical analyses show that there are several stages of hydrocarbon generation, migration and accumulation in the Longmaxi Formation. The joint action of two groups (two stages) of fault systems and the detachment surface at the bottom of the Longmaxi Formation control the development of reticular cracks and overpressure preservation, and it is the key to the shale gas accumulation and high yield. The sealed box-like system in the Longmaxi Formation ensures the gas reservoir dynamic balance. The model of high yield and enrichment of Jiaoshiba shale gas play is “ladder migration, anticline accumulation, fault–slip plane controlling fractures, and box shape reservoiring”. Like in conventional gas plays, good preservation and tectonic conditions are also required to form high yield shale plays in areas which have complex structures, multi-stage tectonic movements, and have high evolution shale.
Since the Neoproterozoic, two important cycles of separation and junction of the Rodinia and Pangea supercontinents controlled the formation of the Tethys, Laurasia, Gondwana and Pacifica domains, as well as the sedimentary basin types including craton, passive margin, rift, foreland, fore-arc, and back-arc basins. Sixty-eight percent of the discovered reserves are from the Tethys domain, while 49% of the undiscovered possible reserves are in passive margin basins. Six major sets of source rocks, two types of reservoirs (carbonates and clastics), and two regional seals (shale and evaporite) formed in global evolution of basins. Ten patterns are summarized from the above factors controlling the distribution of global hydrocarbon resources. (1) Conventional-unconventional hydrocarbon is accumulated “orderly”. (2) Distribution of Tethys controls the accumulation of the global hydrocarbons. (3) Foreland thrusting zones control the distribution of structural oil/gas fields; (4) Intra-craton uplifts control the distribution of giant oil/gas fields; (5) Platform margins control the banded distribution of giant organic reef and bank type oil/gas fields. (6) Passive margins control the distribution of giant marine oil/gas fields. (7) Foreland deep slopes control the occurrence of large scale heavy oil and bitumen. (8) Basin deposition slopes control the accumulation of tight oil & gas and coalbed methane. (9) Organic rich deep basin sediments control the retention of shale oil and gas. (10) Low temperature and high pressure seafloor sediments control the distribution of hydrate. The conventional/unconventional resources ratio is 2:8. The conventional resources are mainly distributed in the Middle East, Russia, North America, and Latin America. The unconventional resources are mainly distributed in North America, Asia Pacific, Latin America, and Russia. According to the ten trends of global petroleum industry, hydrocarbon exploration is mainly focused on marine deep water, onshore deep layer, and unconventional oil & gas. The peak of oil production will probably come around 2040, and the life span of petroleum industry will last another 150 years. Renewable energy will replace fossil energy, not for the exhaustion of fossil energy, but because it is cheaper and cleaner.
Based on well cores and thin section observations of more than 300 wells from major exploration target areas and formations in the Tarim, Sichuan and Ordos Basins, combined with seismic, well logging and testing data, the types and characteristics of carbonate reservoirs as well as the geologic conditions for their extensive development are analyzed systematically, and their distribution features are summarized. All varieties of marine carbonate reservoirs are developed in China, including three types of large-scale effective reservoirs, which are (1) depositional reef-shoal and dolomite reservoirs, (2) epigenetic dissolution-percolation reservoirs and (3) deep burial-hydrothermal altered reservoirs. Besides sedimentary facies, paleoclimate and paleogeomorphy, other factors controlling the development of deep large-scale effective reservoirs include interstratal and intrastratal dissolution-percolation and burial dolomitization which can be impacted by hydrothermal processes. Large effective reservoirs in deep carbonate rocks are distributed along unconformities and hiatuses in sedimentation, while reservoirs of epigenetic dissolution-percolation type extend from paleohigh uplift zones to lower slope reliefs. The reservoirs are widely distributed in stratified planar forms, and are superposed by multi-stage karstification processes vertically and have obvious heterogeneity controls. Burial dolomitization is restricted by primary sedimentary facies, and can form extensive effective reservoirs in deep layers in layered or stratified shapes. Hydrothermal related reservoirs are always distributed along deep, large faults, forming effective reservoirs in the form of a bead string in vertical direction and band-rod horizontally, which are not restricted by burial depth.
The development theories of low-permeability oil and gas reservoirs are refined, the key development technologies are summarized, and the prospect and technical direction of sustainable development are discussed based on the understanding and research on developed low-permeability oil and gas resources in China. The main achievements include: (1) the theories of low-permeability reservoir seepage, dual-medium seepage, relative homogeneity, etc. (2) the well location optimization technology combining favorable area of reservoir with gas-bearing prediction and combining pre-stack with post-stack; (3) oriented perforating multi-fracture, multistage sand adding, multistage temporary plugging, vertical well multilayer, horizontal and other fracturing techniques to improve productivity of single well; (4) the technology of increasing injection and keeping pressure, such as overall decreasing pressure, local pressurization, shaped charge stamping and plugging removal, fine separate injection, mild advanced water injection and so on; (5) enhanced recovery technology of optimization of injection-production well network in horizontal wells. To continue to develop low-permeability reserves economically and effectively, there are three aspects of work to be done well: (1) depending on technical improvement, continue to innovate new technologies and methods, establish a new mode of low quality reservoir development economically, determine the main technical boundaries and form replacement technology reserves of advanced development; (2) adhering to the management system of low cost technology & low cost, set up a complete set of low-cost dual integration innovation system through continuous innovation in technology and management; (3) striving for national preferential policies.
Different from the continental layered sandstone and fracture-pore carbonate reservoirs, the fractured-vuggy carbonate reservoirs in the Tarim Basin are mainly composed of fractured-vuggy bodies of different sizes and shapes. Based on years of study on the geological features, flow mechanisms, high-precision depiction and the recovery mode of fractured-vuggy bodies, the idea of “volumetric development” is proposed and put into practice. A “body by body” production methodology is established with respect to volumetric unit of fractures and vugs based on vuggy body's spatial allocation and reserves. A variety of development wells, various technological methods, and multi-type injection media are used to develop this type of reservoirs in an all-around way. As a result, the resource and production structures of the Tahe oilfield are significantly improved and a highly efficient development is achieved.
The global mobility theory was used to evaluate the experimental results of oil displacement with water of different salinities. The results of scanning electron microscopy, X diffraction of clay minerals, nonlinear seepage and nuclear magnetic resonance experiments and particle migration inhibition experiments before and after water flooding were compared to determine the mechanisms of water sensitive damage and enhanced water flooding mechanism of low permeability sandy conglomerate reservoirs in Wushi region of Beibuwan Basin, China. A production equation of the oil-water two phase flow well considering low-speed non-Darcy seepage and reservoir stress sensitivity was established to evaluate the effect of changes in reservoir properties and oil-water two-phase seepage capacity on reservoir productivity quantitatively, and injection water source suitable for the low permeability sandy conglomerate reservoirs in Wushi region was selected according to dynamic compatibility experimental results of different types of injected water. The seepage capacity of reservoir is the strongest when the injected water is formation water of 2 times salinity. The water-sensitive damage mechanisms of the reservoirs in Wushi region include hydration of clay minerals and particle migration. By increasing the content of cations (especially K+ and Mg2+) in the injected water, the water-sensitive damage of the reservoir can be effectively inhibited. The formation water of Weizhou Formation can be used as the injection water source of low permeability sandy conglomerate reservoirs in the Wushi region.
In the Triassic Yanchang Formation, Jiyuan-Wuqi area, Ordos Basin, the Chang 6 reservoir is contacted to the Chang 7 high-quality source rock, but the oil pools are unevenly distributed, and complex in oil and water distribution. Through cores observation and fracture statistics, combined with comprehensive analyses of physical property, mercury injection, logging and geochemical data, and comparisons of the sandbodies scales, reservoir physical properties, argillaceous laminae and fractures between source and reservoir in the eastern and western oil-bearing areas and in the central water producing area, it is found that the hydrocarbon accumulation patterns are different in the eastern, central and western areas, and the characteristics of hydrocarbon migration under the background of double-provenance were sorted out. The study results show that the crude oil in the eastern area has different Pr/Ph and sterane distribution from that in the western area. The oil and gas primarily migrated vertically. The high-quality source rocks and favorable source-reservoir-cap combinations lay the foundation for large-scale oil and gas accumulations. Vertically, the oil and gas enrichment is controlled by the scale of sandbody and the difference of physical properties, while on the plane, it is controlled by the connectivity of sandbodies, the argillaceous laminae between source rock and reservoir, the reservoir physical property and the fractures. The sandbodies of oil-rich zones in the eastern and western areas have large thickness, low shale content, good physical properties, weak heterogeneity, few argillaceous laminae and abundant fractures, all of which are favorable for the vertical migration and accumulation of oil and gas. In contrast, in the middle area with converging provenances, the reservoirs, composed of thin sandbodies, features rapid variation in lithology and physical properties, strong heterogeneity, poor continuity of sandbodies, abundant argillaceous laminae between source rock and reservoir, and few fractures, makes it difficult for the oil and gas to migrate vertically, and results in low oil enrichment degree ultimately. For the exploration of continental multiple-provenance tight reservoirs, not only the good-property source rocks and reservoirs, but more importantly the source-reservoir contact relationship and the effect of fractures on the hydrocarbon migration and accumulation should be considered.
Considering the characteristics that the fracture conductivity formed by hydraulic fracturing varies across space and time, a new mathematical model was established for seepage flow in tight gas fractured vertical wells which takes into account the effects of dual variable conductivity and stress sensitivity. The Blasingame advanced production decline curves of the model were obtained using the finite element method with hybrid elements. On this basis, the effects of fracture space and time dual variable conductivity and stress sensitivity on Blasingame curve were analyzed. The study shows that the space variable conductivity mainly reduces decline curve value at the early stage; the time variable conductivity can result in drops of the production and the production integral curves, leading to a S-shaped curve; dual variable conductivity is the superposition of the effects given by the two variable conductivities; both time and space variable conductivities cannot delay the time with which the formation fluid flow reaches the quasi-steady state. The stress sensitivity reduces the curve value gradually rather than sharply, delaying the time the flow reaching the quasi-steady state. Ignoring the effects of variable conductivity and stress sensitivity will not affect the estimation on well controlled dynamic reserves. However, it can result in large errors in the interpretation of fractures and reservoir parameters. Conventional advanced production decline analyses of a tight gas fractured well in the Sulige gas field showed that the new model is more effective and reliable than the conventional model, and thus it can be widely applied in advanced production decline analysis of wells with the same characteristics in other gas fields.
The natural gas components and geochemistry of 38 ultra-deep gas wells (burial depth greater than 6 000 m) in the Sichuan Basin were analyzed to determine the genesis of ultra-deep natural gas in the basin. The ultra-deep natural gas components of the basin have the following characteristics: Methane has an absolute advantage, which can be up to 99.56% with an average of 86.6%; ethane is low, with an average of 0.13%; there is nearly no propane and butane. So it is dry gas at over-mature thermal stage. The content of H2S can be up to 25.21%, with an average of 5.45%. The alkane gas isotopes are: the carbon isotope varies from −32.3‰ to −26.7‰ for methane and from −32.9‰ to −22.1‰ for ethane. There is nearly no carbon isotopic reversal among methane and its homologues. Hydrogen isotope varies from −156‰ to −114‰ for methane, and from −103‰ to −89‰ for some ethane. The carbon isotope of CO2 varies from −17.2‰ to 1.9‰ and most of them fall within the range of 0±3‰. According to the δ13C1-δ13C2-δ13C3 plot, except some wells, all other ultra-deep gas wells are dominated by coal-derived gas. Based on the CO2 origin distinguishing plot and δ13CCO2, except some individual wells, most of the ultra-deep CO2 are of carbonate metamorphic origin. H2S in the ultra-deep layer of Longgang and Yuanba gas fields belongs to thermochemical sulfate reduction (TSR), while H2S from Well Shuangtan belongs to thermal Geochemical characteristics of ultra-deep natural gas in the decomposition of sulfides (TDS).
The Triassic Yanchang Formation Chang7 Member tight oil reservoir in Ordos Basin, featuring complex pore-throat structures, low porosity, low permeability, rich micro-fractures and low pressure coefficient, is difficult to produce by advanced water-flooding from cluster vertical wells with low individual-well producing rate. With Block A as an example, the material balance calculation, numerical simulation and field practical analysis showed that the horizontal well production would increase significantly using volumetric fracturing. But the well pattern of water injection in vertical wells and oil production in horizontal wells has high risk of injection water breakthrough in horizontal wells, and the proportion of water breakthrough wells reached 65%. In contrast, the formation energy decreased in depletion development with horizontal wells, in which the oil production kept stable in early period, but decreased quickly after 12 months, the cumulative decline of oil rate in 4 months amounted to 50.3%. Therefore, a development scheme of depletion production from volumetric fracturing horizontal wells at first and then water-flooding huff and puff after producing energy is deficient was proposed. Following this scheme, the daily oil rate of single well increased by 78.3% after the first cycle of water huff-and-puff than before the treatment, marking the initial success of the measure.
The distribution and migration characteristics of weak gel in the core were observed by combining nuclear magnetic resonance (NMR) imaging technology with the core displacement experiment, and the oil displacement features of different polymer-weak gel combinations were examined with visualization experiments. Three combination patterns of polymer and weak gel were designed: waterflooding + polymer flooding (pattern 1), waterflooding + polymer flooding + weak gel flooding (pattern 2), and waterflooding + weak gel flooding + polymer flooding (pattern 3). The pressure variations, T2 spectra, nuclear magnetic resonance images, oil displacement efficiencies under the different patterns were analyzed. The results show that the nuclear magnetic images can not only provide the direct information of weak gel distribution and migration characteristics inside the core, but also reflect the distribution characteristics of remaining oil; the T2 spectrum characteristics indicate that both polymer and weak gel have the function of profile control and oil displacement, and the pattern 2 has the best profile control effect; of the three patterns, pattern 2 has the highest oil displacement efficiency of 78.84%, which is 18.33% higher than the displacement efficiency of water flooding in the initial stage.
The main factors controlling the enrichment and high yield of shale gas were analyzed based on the recent research progress of depositional model and reservoir characterization of organic-rich shale in China. The study determines the space-time comparison basis of graptolite sequence in the Upper Ordovician Wufeng Formation–Lower Silurian Longmaxi Formation and proposes the important depositional pattern of marine organic-rich shale: stable ocean basin with low subsidence rate, high sea level, semi-enclosed water body, and low sedimentation rate. Deposited in the stage of Late Ordovician-Early Silurian, the superior shale with thickness of 20−80 m and total organic carbon (TOC) content of 2.0%−8.4% was developed in large deep-water shelf environment which is favorable for black shale development. Based on the comparison among the Jiaoshiba, Changning and Weiyuan shale gas fields, it is believed that reservoirs of scale are mainly controlled by shale rich in biogenic silica and calcium, moderate thermal maturity, high matrix porosity, and abundant fracture. The shales in the Wufeng and Longmaxi formations are characterized by porosity of 3.0%−8.4%, permeability of 0.000 2×10−3−0.500 0×10−3 μm2, stable areal distribution of matrix pore volume and their constituents, great variation in fracture and pore characteristics among different tectonic regions as well as different well fields and different intervals in the same tectonic. The Cambrian Qiongzhusi shale features poor physical properties with the porosity of 1.5%−2.9% and the permeability of 0.001×10−3−0.010×10−3 μm2, resulted from the carbonization of organic matter, high crystallinity of clay minerals and later filling in bioclastic intragranular pores. Four factors controlling the accumulation and high production of shale gas were confirmed: depositional environment, thermal evolution, pore and fracture development, and tectonic preservation condition; two special features were found: high thermal maturity (Ro of 2.0%−3.5%) and overpressure of reservoir (pressure coefficient of 1.3−2.1); and two enrichment modes were summarized: “structural sweet spots” and “continuous sweet area”.
Based on the data of regional outcrop observation, high-precision 3-D seismic detection and wellbore rock-electricity, this paper researched macro-water distribution, seismic architecture of sedimentary-filling, rock composition, heavy mineral assemblage, and zircon age. The axial channel provenance system and accumulation of natural gas of the Upper Miocene Huangliu Formation in the Qiongdongnan Basin was analyzed. The research showed that axial channels deposits were provided with two depression stages, multiple provenances, and gravity flows by bottom current rework. Early channels sandstone with small size and formation overpressure was mainly from terrigenous material of southwest drainage system in Hainan uplift, while Qiupen River in the central Kunsong uplift was the primary provenance of late channels sandstone with large scale of sediments, good continuity and normal formation pressure. There are three types of axial channel sandstone traps: litho-stratigraphic, lithologic and tectono-stratigraphic trap. Natural gas of early channels was driven by deep overpressure and vertically migrated into reservoir along fissures, while natural gas of late channels lateral migrated from west to east.
According to the comparison of biomarkers in source rocks and crude oil, fluid inclusion analysis, and basin modeling, this paper discusses the oil source, hydrocarbon accumulation period and reservoir forming model of the Chang 9 and Chang 10 oil-bearing formations, Yanchang Formation, Ordos Basin. The crude oil of Chang 9 in the Longdong and Jiyuan areas can be divided into two types, type I crude oil originated from the source rocks within Chang 7, while type I crude oil came from the source rocks within Chang 9. The crude oil of Chang 10 in Northern Shaanxi originated mainly from the source rocks of Chang 9. The Chang 9 oil reservoirs in both the Longdong and Jiyuan areas experienced two periods of hydrocarbon injection. The former reached the peak period of hydrocarbon injection in the first period (the depositional period of Middle Jurassic Zhiluo Formation), while the latter in the second period (the depositional period of Lower Cretaceous Zhidan Formation). There are two periods of continuous hydrocarbon injection in Chang 10 of Northern Shaanxi, generally from the early depositional period of the Middle Jurassic Zhiluo Formation to the middle-late depositional period of the Cretaceous Zhidan Formation. There are three types of hydrocarbon accumulation models in Chang 9 and Chang 10, i.e. “upper generation and lower storage”, “adjacent generation and lateral storage” and “self-generation and self-storage”.
To optimize production schedule and production plan of multiple gas fields with certain amount of investment and constraints and to maximize their economic benefits under the production sharing contact (PSC) mode, a quantitative relationship was applied to describe the production performance depending on the development status of multiple gas fields in China and abroad. Furthermore, with the PSC-based net present value (NPV) as the objective function, a mixed integer nonlinear programming model for gas fields with optimized production schedule and productivity was established. An adaptive layer-embedded genetic algorithm was proposed to solve this model. Through handling the variables and constraints for solving this model and improving the genetic structure, genetic operators and termination conditions of standard genetic algorithm, modeling and solving techniques were formed for integrated and efficient development of multiple gas fields. Results obtained by three methods, i.e. multi-scheme comparison without mathematical model, standard genetic algorithm which induces penalty function to treat constraints, and adaptive layer-embedded genetic algorithm, were compared. The proposed optimization model is accurate, and the proposed layer-embedded genetic algorithm provides satisfactory convergence and calculation rate, ensuring that multiple gas fields could be exploited orderly.
By analyzing affecting factors on deepwater relief well location selection, and focusing on the regional deepwater operating environment in South China Sea and different rig positioning types, a calculation method for minimum safety distance between reliefs well and blowout well was proposed. In addition to the affecting factors on shallow-water relief well location selection, difficulties which are specific for deepwater operating considerations should be considered for deepwater relief well location selection, including metocean conditions, site survey results, blowout situation and evolution, influences of relief well location on relief well trajectory design, ranging procedure, ranging tool usage and dynamic killing operation, and fire hazard heat radiation and rig positioning types. The most significant factors for deepwater relief well location selection in South China Sea are typhoon and internal solitary wave. For a mooring positioning rig, the main considerations are mooring deployment, internal solitary wave and typhoon. For a dynamic positioning rig, the main considerations are operation window and other vessels. Based on analyses of affecting factors on deepwater relief well location selection in South China Sea, the well location selection method was demonstrated through the discussion of an existing regional well.
To evaluate the effect of oilfield development measures quantitatively, based on the theory of Arps production decline, this study deduced a linear relation between the product of cumulative production with production time (Npt) and production time (t), and established the cumulative production curve method for quantitative evaluation on the effect of development measures. The nitrogen injection pilot in Yanling oilfield was taken as an example to calculate the recoverable reserves before and after the nitrogen injection, and through the variation of recoverable reserves, the effect of the nitrogen injection on actual production was quantitatively evaluated. Similarity analysis of decline curve shape in the late period shows that the method is not restricted by decline types and the relationship curve between Npt and t in the late development is always tending to a straight line. The cumulative production curve method is not only suitable for single wells but also not restricted by reservoir types. Combined with derivative curve in diagnosis, it reflects the microscopic variations of the slope in the straight line segment and the variations of recoverable reserves and the process of reserve producing. The single wells in the Yanbei nitrogen injection pilot were evaluated quantitatively using the cumulative production curve method, the results show that: the nitrogen injection causes obvious productivity increase of the oil wells in the hillside of the buried hill, productivity decrease of the oil wells at the top of buried hill, and little influence on the productivity of oil wells in the margins of burial hill.