The main methods of coalbed methane(CBM) development are drainage and depressurization, and a precise prediction of coal reservoir pressure is thus crucial for the evaluation of reservoir potentials and the formulation of reasonable development plans. This work established a new reservoir pressure prediction model based on the material balance equation(MBE) of coal reservoir, which considers the self-regulating effects of coal reservoirs and the dynamic change of equivalent drainage area(EDA). According to the proposed model, the reservoir pressure can be predicted based on reservoir condition data and the actual production data of a single well. Compared with traditional reservoir pressure prediction models which regard EDA as a fixed value, the proposed model can better predict the average pressure of reservoirs. Moreover, orthogonal experiments were designed to evaluate the sensitivity of reservoir parameters on the reservoir pressure prediction results of this proposed model. The results show that the saturation of irreducible water is the most sensitive parameter, followed by Langmuir volume and reservoir porosity, and Langmuir pressure is the least sensitive parameter. In addition, the pressure drop of reservoirs is negatively correlated with the saturation of irreducible water and the Langmuir volume, while it is positively correlated with porosity. This work analyzed the reservoir pressure drop characteristics of the CBM wells in the Shizhuangnan Block of the Qinshui Basin, and the results show that the CBM reservoir depressurization can be divided into three types, i.e., rapidly drop type, medium-term stability type, and slowly drop type. The drainage features of wells were reasonably interpreted based on the comprehensive analysis of the reservoir depressurization type; the latter was coupled to the corresponding permeability dynamic change characteristics, eventually proving the applicability of the proposed model. 相似文献
Gl obal recoverable resources of heavy oil and oil sands have been assessed by CNPC using a geology-based assessment method combined with the traditional volumetric method, spatial interpolation method, parametric-probability method etc. The most favourable areas for exploration have been selected in accordance with a comprehensive scoring system. The results show: (1) For geological resources, CNPC estimate 991.18 billion tonnes of heavy oil and 501.26 billion tonnes of oil sands globally, of which technically recoverable resources of heavy oil and oil sands comprise 126.74 billion tonnes and 64.13 billion tonnes respectively. More than 80% of the resources occur within Tertiary and Cretaceous reservoirs distributed across 69 heavy-oil basins and 32 oil-sands basins. 99% of recoverable resources of heavy oil and oil sands occur within foreland basins, passive continental-margin basins and cratonic basins. (2) Since residual hydrocarbon resources remain following large-scale hydrocarbon migration and destruction, heavy oil and oil sands are characterized most commonly by late hydrocarbon accumulation, the same basin types and source-reservoir conditions as for conventional hydrocarbon resources, shallow burial depth and stratabound reservoirs. (3) Three accumulation models are recognised, depending on basin type: degradation along slope; destruction by uplift; and migration along faults. (4) In addition to mature exploration regions such as Canada and Venezuela, the Volga-Ural Basin and the Pre-Caspian Basin are less well-explored and have good potential for oil-sand discoveries, and it is predicted that the Middle East will be an important region for heavy-oil development. 相似文献
Lipid biomarkers widely dotted in marine sediments, as their distribution characteristics accurately record huge information on the metabolism of the original organisms and migration and transformation of these organic components, are often used to reconstruct the paleoclimatic and paleoenvironmental conditions. This paper reviewed the progress in the study of paleoclimatic-environmental changes during the late Quaternary using abundant core lipids Glycerol Dialkyl Glyceryl Tetraethers (GDGTs) and long-chain alkyl diols in marginal sea sediments. It is pointed out that clarifying the “source-sink” process of lipid biomarkers buried in marine sediments is a prerequisite for paleoclimatic-environmental reconstruction. It is believed that the use of multiple indicators that are less affected by early diagenesis can increase the accuracy of reconstructing paleoclimatic changes. In the large-river dominated marginal seas, the mechanism of land-sea climate coupling evolution stimulated by the paleoclimatic-environmental changes can be elucidated based on paleoclimatic records reconstructed from core lipids GDGTs and long-chain alkyl diols in marine sediments. It is hoped that this paper can provide reliable technical means and a solid theoretical basis for predicting future temperature and rainfall changes. 相似文献
The Xiaojiashan tungsten deposit is located about 200 km northwest of Hami City, the Eastern Tianshan orogenic belt, Xinjiang, northwestern China, and is a quartz vein‐type tungsten deposit. Combined fluid inclusion microthermometry, host rock geochemistry, and H–O isotopic compositions are used to constrain the ore genesis and tectonic setting of the Xiaojiashan tungsten deposit. The orebodies occur in granite intrusions adjacent to the metamorphic crystal tuff, which consists of the second lithological section of the first Sub‐Formation of the Dananhu Formation (D2d12). Biotite granite is the most widely distributed intrusive bodies in the Xiaojiashan tungsten deposit. Altered diorite and metamorphic crystal tuff are the main surrounding rocks. The granite belongs to peraluminous A‐type granite with high potassic calc‐alkaline series, and all rocks show light Rare Earth Element (REE)‐enriched patterns. The trace element characters suggest that crystallization differentiation might even occur in the diagenetic process. The granite belongs to postcollisional extension granite, and the rocks formed in an extensional tectonic environment, which might result from magma activity in such an extensional tectonic environment. Tungsten‐bearing quartz veins are divided into gray quartz vein and white quartz veins. Based on petrography observation, fluid inclusions in both kinds of vein quartz are mainly aqueous inclusions. Microthermometry shows that gray quartz veins have 143–354°C of Th, and white quartz veins have 154–312°C of Th. The laser‐Raman test shows that CO2 is found in fluid inclusions of the tungsten‐bearing quartz veins. Quadrupole mass spectrometry reveals that fluid inclusions contain major vapor‐phase contents of CO2, H2O. Meanwhile, fluid inclusions contain major liquid‐phase contents of Cl?, Na+. It can be speculated that the ore‐forming fluid of the Xiaojiashan tungsten deposit is characterized by an H2O–CO2, low salinity, and H2O–CO2–NaCl system. The range of hydrogen and oxygen isotope compositions indicated that the ore‐forming fluids of the tungsten deposit were mainly magmatic water. The ore‐forming age of the Xiaojiashan deposit should to be ~227 Ma. During the ore‐forming process, the magmatic water had separated from magmatic intrusions, and the ore‐bearing complex was taken to a portion where tungsten‐bearing ores could be mineralized. The magmatic fluid was mixed by meteoric water in the late stage. 相似文献
Near-wellbore fracture tortuosity has important impacts on the productivity of fractured oil and gas wells and the injectivity of CO2 or solids disposal injectors. Previous models for simulating near-wellbore fracture tortuosity usually assume fracture growth in linear-elastic media, without considering the effects of porous features of the rock. In this paper, a 2D fully coupled model is developed to simulate near-wellbore fracturing using the XFEM-based cohesive segment method. The model takes into account a variety of crucial physical aspects, including fracture extension and turning, fluid flow in the fracture, fluid leak-off through wellbore wall and fracture surfaces, pore fluid flow, and rock deformation. The proposed model was verified against two sets of published experimental results. Numerical examples were carried out to investigate the effects of various parameters on near-wellbore fracture trajectory, injection pressure, and fracture width. Results show that near-wellbore fracture behaviors are not only dependent on rock elastic properties and field stresses, but also greatly influenced by porous properties of the rock, such as permeability and leak-off coefficient. Some field implications were provided based on the simulation results. By overcoming some limitations of the previous models, the proposed model predicts more realistic fracture evolution in the near-wellbore region and provides an attractive tool for design and evaluation of many field operations, for which near-wellbore fracture behaviors play an important role on their successes.