In the process of the tight oilfields development, it is difficult to establish an effective system of injection-production displacement because of the high seepage resistance. The seepage does not follow the linear Darcy's law. However, the reservoir simulation software has not considered this phenomenon, which leads to the numerical simulation prediction results better than actual production data. Therefore, it is necessary to establish an effective method to calculate the low velocity non-Darcy flow in tight sandstone oil reservoirs numerical simulation. This paper introduced a factor called starting pressure gradient (SPG), which can be used to describe non-Darcy seepage phenomenon. First of all, laboratory experiments of differential pressure flow method were carried out to get the relationship between core permeability and the SPG. In addition, according to the reservoir heterogeneity and exploitation degree, three methods were put forward for characterization the SPG in tight sandstone oil reservoirs numerical simulation. Finally, this numerical simulation method was used in the X tight sandstone oil reservoir history matching process to verify its accuracy. The results of the laboratory experiments showed that, SPG exists in tight sandstone oil reservoirs. Liquid starts to flow when the production pressure gradient is greater than the SPG. SPG is an additional pressure resistance for each flow unit, the existence of SPG has intensified the degree of pressure drop. Analysis of the experimental data gave a power series relationship between the SPG and the permeability. And the SPG increases with the decreases of core permeability. Reservoir heterogeneity criterion was established by introducing R and C factors. The greater R value and C values are, the higher the heterogeneity is. When the reservoir heterogeneity is weak (0< R≤0.3), we set SPG for each layer. When the reservoir heterogeneity is strong (0.3 < R≤ 1 or 0 < C≤1), we set SPG for each rock type. When the reservoir with intense heterogeneity (1<C<2), we set SPG for each gird. After considering SPG, single well history matching coincidence rate improves from 64% to 87%, and every layer oil production prediction has high coincidence with the actual production data. Therefore, SPG cannot be ignored in tight sandstone oil reservoirs numerical simulation. This paper provides a new method to describe the low velocity non-Darcy flow in tight sandstone oil reservoirs numerical simulation, and can guide the tight sandstone oil reservoirs development effectively. This method can also be applied in heavy oil reservoirs and tight gas reservoirs numerical simulation.
Hydrate formation risk is an important challenge in the development of deep-water gas field. Considering the characteristics of the Lingshui (LS) gas field in the South China Sea and the difference of well structures, a model for calculating wellbore temperature and pressure in deep-water gas production well is proposed and verified by the field data. Combining the hydrate equilibrium models with varied gas components, the prediction method of hydrate formation region in deep-water gas well in the South China Sea is obtained. The hydrate formation regions under different operating conditions for a deep-water gas well in the South China Sea were given by the proposed model. The results show that no hydrate formation risk exists in the production operation, but the risk exists in the shut-in and testing operations. Meanwhile, the determination of the hydrate inhibitor injection parameters during the testing operation is studied, and the influence of the inhibitors’ injection concentration and pressure on preventing gas hydrates is analyzed. This work provides useful advice for the prediction and prevention of hydrate formation risk in the development of deep-water gas fields, especially in the South China Sea.
In recent years, large deep-water gas fields such as Yacheng and Lingshen have been discovered successively in deep-water exploration in the South China Sea, with huge reserves. However, bottom water is ubiquitous in deep-water gas fields, which seriously affects gas reservoir recovery. Therefore, it is beneficial to improve the development effect of gas reservoirs to clarify the water invasion mechanism and law of bottom water gas reservoirs. Based on the study of water invasion law of deep water gas reservoir, the development effect of deep water gas reservoir under different water control technology conditions is evaluated by numerical simulation method in this paper. It provides a strong basis for rational and effective development of deep-water gas reservoirs and water control and waterproofing technology.
The subsea production system is presently widely adopted in deepwater oil and gas development. The throttling valve is the key piece of equipment of the subsea production system, controlling the safety of oil and gas production. There are many valves with serious throttling effect in the subsea X-tree, so the hydrate formation risk is relatively high. In this work, a 3D cage-sleeve throttling valve model was established by the numerical simulation method. The temperature and pressure field of the subsea throttling valve was accurately characterized under different prefilling pressure, throttling valve opening degree, and fluid production. During the well startup period, the temperature of the subsea pipeline is low. If the pressure difference between the two ends of the pipeline is large, the throttling effect is obvious, and low temperature will lead to hydrate formation and affect the choice of throttling valve material. Based on the analysis of simulation results, this study recommends that the prefilling pressure of the subsea pipe is 7–8 MPa, which can effectively reduce the influence of the throttling effect so that the downstream temperature can be kept above 0°C. At the same time, in regular production, a suitable choke size is opened to match the production, preventing the serious throttling effect from a small choke size. According to the API temperature rating table, the negative impact of local low temperature caused by the throttling effect on the temperature resistance of the pipe was considered, and the appropriate subsea X-tree manifold material was selected to ensure production safety. The hydrate phase equilibrium curve is used to estimate the hydrate formation risk under thermodynamic conditions. Hydrate inhibitors are injected to ensure downstream flow safety.
In evaluating the reservoir physical properties and boundary characteristics of gas wells, the well test interpretation method is mainly employed currently to obtain K, KH, S and boundary characteristics of the reservoir. This method requires a test system for gas wells and a pressure gauge to record the data of flowing bottom hole pressure (FBHP) at the middle depth of the gas reservoir, with long testing time and high cost. Therefore, productivity testing and test pressure recovery data are only performed for some gas wells, and we cannot get reservoir physical property parameters by well test interpretation. It is considered that this method can better meet the needs of practical work, and has high popularization and application value.
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