The shale reservoir develops cracks with different scales after hydraulic fracturing. The flowback fluid stays in the reservoir and the fracture, changing the water saturation of the shale reservoir, thus affecting the flow of shale gas. In order to study the effect of water on the seepage capacity of shale reservoirs under micro-crack conditions, the black shale of the Longmaxi Formation reservoir in Sichuan Province was selected and the core experiment was carried out after the crack-making treatment via Brazilian cracking. The influencing factors of shale reservoir seepage capacity under water condition were analyzed by the experimental methods of scanning electron microscopy and the theory of seepage mechanics. The results show that clay mineral content and fracture network development determine seepage capacity of shale reservoirs. The more clay minerals, the greater the decline of reservoir seepage capacity. The opening of the main crack and the distribution pattern of the micro crack control the scope of water in the crack system. The equations of the decreasing extent and area density of seepage capacity were established by fitting experimental data, and the influence of water on shale seepage capacity under micro-crack conditions was analyzed.
The economic development of shale gas reservoirs has become the focus of current unconventional gas development. The development method of shale gas reservoirs is based on "horizontal well and hydraulic fracturing" as the core technology. In the process of hydraulic fracturing, a great amount of fracturing fluids retain in the reservoirs, which are difficult to flowback, forming water phase trap damage and hindering gas production. In addition, large-scale complex fracture networks formed by hydraulic fracturing can communicate micron-scale cracks, but it is still difficult for gas in the nano-scale pores of the matrix to enter the crack. This paper proposes a method for thermal stimulation to cause shale cracking coordinated with hydraulic fracturing technology over organic-rich shale gas reservoirs. The research progress of formation heat treatment is summarized from the aspects of laboratory experiments and field tests. In terms of the geological characteristics and engineering technologies, the advantages of this method over organic-rich shale gas reservoirs are also analyzed. It is considered that the role of hydrocarbon-generating overpressure, different thermal expansion coefficients of minerals as well as pressure compartments formed by micro-nanoscale pores provides the favorable factors. Based on the fracture network formed by application of the stimulated reservoir volume, the retaining fracturing fluids can enhance the heat transfer area of shale. Aquathermal pressuring and hydrothermal fluids at certain temperature can also contribute to thermal fracturing. By making full use of the unique geological superiorities and favorable engineering conditions of organic-shale gas reservoirs, this method will effectively transform the shale gas reservoirs after hydraulic fracturing, which can obviously alleviate or even eliminate water trapping damage, promote thermal cracking of matrix rocks on both sides of hydraulic fractures or natural fractures and finally improve the multiscale gas transport ability from matrix-natural fracture-artificial fracture network of shale. Meanwhile, with increasing temperature, the recovery and utilization of flowback fluids can be realized and it will be an environment-friendly new method for the effective development of shale gas reservoirs.
According to the study of production decline law of oil and gas fields, many researchers have proposed a variety of production decline models, such as Arps model, SEPD model, Duong model and combination model. In practical production, due to the variety of declining models and different use conditions, it is difficult to choose the optimal decline model because of the complexity of decline models and different conditions. The usual practice is to fit the actual production data by linear fitting or nonlinear fitting method, and determine the selected model by the correlation coefficient. When use those methods, you will waste time on fitting each model. Based on this, a new production decline model is proposed in this paper. Through theoretical verification, it is determined that the model includes not only Arps decline law, but also SEPD model and Duong model. Through the analysis of actual production data, the method has high fitting accuracy and wide application range, which can effectively avoid the problem of model selection and provide a basis for the selection of decline analysis method.
The macroscopic properties characterizing fluid transport in porous media are directly determined by the pore structure of the media itself. Velocity field and flow field, connecting microscopic and macroscopic theories, are particularly important, but few studies have been carried out. Based on the simulation of single-phase flow in pore network model, this paper systematically calculated the distribution of Eulerian velocity and flow in porous media, and analyzed the relationship between pore structure and the probability density function of velocity and flow. And the following research results were obtained. Firstly, with the increase of the disorder of porous media, the distribution range of velocity increases sharply, while that of flow rate does not change much. Secondly, as the disorder factor decreases, the probability density function of velocity satisfies the following distributions in turn: Gauss distribution, exponential distribution, power law with exponential cut-off distribution and power law distribution. The probability density function of the flow is mainly affected by the heterogeneity of porous media, which basically obeys Gauss distribution and power law with exponential cut-off distribution. Thirdly, the average value of the normalized fluid velocity(v*) is affected by both the coefficient of variation and the coordination number, and the relationship between v* and the coordination number obeys power law. The average value of normalized fluid flow(q*) does not change with coordination number, but decreases with the increase of the coefficient of variation.
The eastern front of the Altun Mountain in the Qaidam Basin is located in the Jurassic hydrocarbon generation depression in the south of the basin, with a long distance between source and reservoir. The evaluation of fault conductivity shows that the near-north-south fault is the main oil source fault in this area, which mainly controls the vertical migration of oil and gas, and controls the differential accumulation of oil and gas in the key period of reservoir formation. The “TR” unconformity is the most important regional angle unconformity in this area, which can be divided into two types: Bedrock unconformity and Jurassic unconformity, all of which have three layers of structure, including bottom gravel layer, weathered residual layer and semi weathered layer. Among them, the weathered eluvium and the semi weathered layer of bedrock have strong transport ability, mainly controlling the long-distance lateral migration of oil and gas. The relationship between faults and unconformity can be divided into two types and three types of combination. The combination type determines the reservoir forming mode, and the combination type controls the dominant migration channel and hydrocarbon accumulation.
Jurassic strata is the most important source rock in the center of north margin of Qaidam Basin, which was still lack of systematic research in their complex hydrocarbon evolution process. On the basis of drilling data, seismic data and testing data, the model of EASY% RO was used to recover the thermal evolution history of Jurassic source rocks in different structural units of the study area and analyze the thermal evolution difference of source rock in different hydrocarbon sag, in order to provide important evidences for the next hydrocarbon exploration in the center of northern margin of Qaidam Basin. Research shows that the thermal evolution degree of Jurassic source rock decreased gradually from west to east. The Lower Jurassic source rock of Kunteyi and Yibei sags in the southwest entered the hydrocarbon generation threshold in the Early Paleogene and reached the peak in the Late Paleogene. The Middle Jurassic source rock of Saishiteng in northeast entered the hydrocarbon generation threshold in the Late Pliocene and is still at the peak now. The center of north margin of Qaidam Basin underwent the two key accumulation periods including Late Yanshanian and Late Himalayan. According to the matching relationship between the historical hydrocarbon generation time and tectonic style, it is clear that the Lenghu No.7 area is the next favorable exploration area.
The phase behavior of near critical fluid is very complex, and the similar properties of volatile oil or condensate gas result in the difficulties to judge whether it is an oil reservoir or a gas reservoir by conventional methods. Two types of near critical formation fluids, Zhonggu 43 well area and Well Jinyue 201, Tarim Basin, are studied. By observing the near-critical "emulsion phenomenon", different methods such as gas-oil ratio, phase diagram, density and composition are used to judge the types of oil and gas reservoirs. By comparing different methods, the near-critical fluid types can be judged accurately by combining the fluid image and dimensionless pressure curve method during testing. The Zhonggu 43 well area of Tazhong 1 Gas Field is characterized by the condensate gas phase with very high condensate content, while Well Jinyue 201 is characterized by the phase of near critical volatile oil. Through gas injection experiments, the near-critical reservoirs have three-phase coexistence of dry gas, condensate gas and condensate liquid, resulting in large differences in gas-oil ratio of production wells at different locations.
Fine reservoir evaluation and classification is of great significance to the development of tight sandstone gas resources. In this paper, the development regularity and effective reservoirs distribution of tight gas reservoir in the 1st member of Quantou Formation of Helong-Lanjia inversion belt in Dehui Fault Depression were ascertained from the aspects of reservoir petrology, pore type, diagenetic evolution and reservoir classification by means of cast thin section and scanning electron microscope. The results show that the porosity of the tight gas reservoirs in the first member of Quantou Formation of the study area is mainly composed of intergranular and intragranular pores, and the porosity is mainly composed of low-porosity and low-permeability or ultra-low permeability. The diagenetic evolution sequence is as follows: (1) early diagenetic phase A-B, kaolinite precipitation and quartz secondary enlargement mark the early compaction; (2) early diagenetic phase B, a few unstable components can be metasomatized by calcite and calcite intergranular cementation occurs. Later, some calcite formed in the early period of dolomite metasomatism formed the metasomatism residue of calcite in dolomite; (3)middle diagenetic phase A, environment with acidic water will induce the precipitation of kaolinite and the dissolution of carbonate minerals; (4) middle diagenetic phase B, the precipitation of iron dolomite and calcite, and the increase of quartz will cause great pore reduction, later dissolution is weak, the compact degree of reservoir is strengthening. The k-means clustering method is used to divide the reservoirs in the study area into four categories, of which the III and IV reservoirs are dominant, and the I reservoirs are mainly located in the north and middle of the study area, accounting for about 5% of the four types of reservoirs. The distribution range of type II reservoirs is larger than that of type I reservoirs, accounting for about 10% of the four types in the northern part of the study area. Class III reservoirs have the largest distribution range, accounting for about 60% of the four types of reservoirs. The type IV reservoirs which are distributed in forms of sheet and belt-like are more developed than the type II reservoirs, accounting for about 25% of the four types of reservoirs.
Based on the study of geological background, it is considered that the main factors affecting helium enrichment in the northern margin of Qaidam Basin are widely distributed rock masses, developed fractures and groundwater system, etc. Among these factors, the rock masses provide sufficient helium gas source, while the fractures and groundwater system provide good natural gas migration channels and carriers. 4He, 20Ne and other rare gas isotopes have good linear relationship, which proves that groundwater system plays an important role in helium enrichment process and helium flux is high. Based on the theoretical understanding of helium reservoir formation formed by helium investigation in Weihe Basin and its adjacent areas, it is predicted that the northern margin of Qaidam Basin has the prospect of crustal helium resources. Through the analysis of natural gas wellhead samples in the helium prospective areas of Mabei and Dongping gas fields in this area, it is found that helium content is generally high. Isotope analysis shows that helium in this area is typically of crustal origin. 21 of the 22 samples analyzed in this paper meet or exceed the industrial standard. According to the estimation of the average helium gas integral of 16 samples in Mabei area, only Mabei area can become a large helium resource prospective area. Through further investigation and evaluation, the study area is expected to obtain super large helium resources.
Fuling shale gas field has achieved great success, but with the development of the gas field entering the middle and late stages, the production of single well is decreasing year by year, so it is necessary to find new production increasing positions. Based on organic geochemistry, X-ray diffraction, scanning electron microscopy and core observation, the analysis results show that the upper shale gas reservoir belongs to class II shale reservoir, with good geological conditions. In addition, through micro seismic monitoring and other means, most of the effective fractures formed by fracturing of the lower gas reservoir well do not extend upward to the upper gas reservoir; the formation pressure of the upper gas reservoir well before production is 21.03 MPa higher than the measured formation pressure of the adjacent well in the same period, which also proves that the upper and lower gas reservoirs are not connected, and the upper gas reservoir can be developed independently. By analyzing the production performance of the upper gas reservoir evaluation wells and calculating the technical recoverable reserves of a single well, both of them have reached high technical recoverable reserves and have good development potential.
In recent years, with the development of unconventional oil and gas, the significance of microfractures for oil and gas exploration and development has become increasingly prominent. Scholars at home and abroad have made extensive and profound discussions on the definition, classification, origin, controlling factors and prediction methods of microfractures in different reservoirs. The upper limit value for defining the length of microcracks is 50 mm, and the upper limit value for aperture varies in different reservoirs. Genesis-based classification scheme is superior to other classification schemes and is currently most widely applied. The formation of microfractures in different rocks is the superposition of single or multiple factors including tectonism, diagenesis and abnormal high pressure. The main controlling factors of different types of microfractures are quite different, and the main controlling factors of the same type of microfractures in different reservoirs are also different. The prediction of microcracks is still at an early stage, and the existing methods have problems of poor accuracy and reliability, high data requirements and high cost. Quantitative analysis techniques based on fractal and mercury intrusion curves are the main means for quantitative characterization of microcracks. The study of microfractures is of great significance to the prediction of macrofractures, the study of sedimentary diagenetic evolution and the oil and gas development. The key points of next study is the comparison of microfractures in different reservoirs, the relationship between microfractures and sedimentation and diagenesis, the prediction and quantitative characterization of microfractures, combination relationship between microfractures of different origins and pore space, and the contribution of microfractures of different origins to reservoir permeability.
Successful exploration of shale oil and gas in North America has brought new exploration ideas for oil and gas to the world. Shale oil resources in China's continental basins are abundant, however, the special complex geological and engineering conditions of China's continental basins have also brought many problems to the Chinese explorers. The concept of shale oil has been controversial in recent years. The formation conditions, occurrence forms, accumulation mechanism, resource potential and favorable development areas of China's continental shale oil have become the research hotspots in recent years. Two types of high-quality source rocks in freshwater and salt water environment have developed in China's continental lake basins. Studies have shown that high TOC shale can be developed in both freshwater and salt water environments. Micro-nano pores are important reservoirs for shale oil, mainly including intercrystalline pores, organic pores, layered joints, micro-cracks, etc. Lamellar lithofacies being a favorable lithofacies for shale oil exploration has become a consensus. The rich resources of shale oil have attracted the attention of major domestic oil companies. The related exploration and development of shale oil has also been carried out successively, which has made great progress. At present, there are still many problems in the exploration and development of shale oil in China. A series of problems such as chaotic shale oil concept, complicated geological conditions and limited engineering means need to be solved urgently. Overall, the shale oil revolution is coming.
Oil and gas discoveries of Ordovician in Sichuan Basin are mainly concentrated in the compact limestone of Nanjinguan Formation at the bottom of Ordovician and Baota Formation at the top of Ordovician, which is characterized by fractured hydrocarbon. It is difficult to obtain samples and to study the reservoir-forming condition furtherly. Recently, oil seepage has been obtained from Ordovician rock samples, which provides important evidences for the further study of Ordovician reservoir-forming conditions. Through the analysis of liquid oil seepage found in bioclastic limestone of Ordovician Baota Formation in Maobahe section of northern Sichuan Basin, saturated hydrocarbon chromatography, characteristic analysis of inclusions and carbon isotope analysis have been comprehensively applied. By comparing the Ordovician reservoir-forming conditions of Well Heshen-1 in northern Sichuan, paleo-uplift in central Sichuan and Well Dongshen-1 in southeastern Sichuan, it is clear that the hydrocarbon of Baota Formation in northern and southeastern Sichuan originated from the overlying source rocks of Wufeng Formation and Longmaxi Formation, which have the mode of generating in the underlying formation and storing in the overlying strata. Ordovician hydrocarbon, situated in paleo-uplift in central Sichuan mainly, receives hydrocarbon from the underlying Cambrian source rocks, forming a mode of generating in the overlying formation and storing in the underlying strata. These conclusions would provide a reference for Ordovician hydrocarbon exploration prospects.
At present, gas chromatography-mass spectrometry and gas chromatography-mass spectrometry-mass spectrometry are mainly used to detect diamondoids in petroleum and source rocks. There are obvious co-spillover phenomena of diamondoids by GC-MS analysis, while GC-MS-MS analysis effectively solves the co-spillover problem in GC-MS analysis through the multi-reaction monitoring. By comparing the quantitative results of GC-MS and GC-MS-MS in four different types of crude oil samples in Tarim Basin, it is found that MRM GC-MS-MS has lower detection and quantitative limits, higher sensitivity and accuracy, and can detect more diamondoids. It is a better analytical method for the determination of diamondoids in crude oil and source rocks. For crude oil samples with low contents of triamantanes and tetramantanes, clear chromatograms can be obtained by GC-MS-MS, but the response factors of all the diamondoids in crude oil samples need to be established for the accurate quantitative determination of diamondoids by GC-MS-MS.
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