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Gas reservoirs with abnormally high pressure have been encountered all over the world. Due to unusual stress environments, a potential impact to reservoir performance is the stress-sensitive permeability. The result of skin factor will be abnormally positive if we interpret the sensitive data using traditional welltesting analysis software. Interpretation of well testing and performance prediction is a major challenge. This paper establishes a numerical well test model and develops a simulator by finite element method with consideration of stress sensitive permeability. LOG-LOG curves are obtained and their characteristics are analyzed. In the earlier period, the pressure response of sensitive reservoir is identical to that of the normal reservoir. In the latter period, the pressure reservoir reaches a semi-log straight line, but the value of the derivative curve is less than 0.5. The transitional period is controlled by sensitive permeability. For lower permeability module, the transitional period is longer. In the log-log plot, the distance between pressure and pressure derivative is larger than the normal reservoir. Permeability modulus will be obtained by log-log analysis. An evaluation method of the effect of stress sensitivity on gas deliverability is presented using the concept of permeability modulus. By combining the LIT equation with the material balance equation, the performance prediction model is also established. The tank material balance equation for gas reservoirs has been written taking into account the effective compressibility of formation. This paper presents an analysis of aflow after flow testin the Tarim abnormally, stress-sensitive gas reservoirs. The effect of stress-sensitive permeability on well test response is analyzed through numerical simulations. Permeability modulus is about 0.01MPa-1; Skin is -1.48(traditional software is 60.8; qAOF decrease is 14%; period of stabilized production decrease is 5.5 a; and, degree of reserve recovery decrease is 6.8%. The interpretation results show that numerical well test analysis can accurately identify gas reservoir parameters and acidizing effectiveness and that the decrease degree of gas deliverability is different and depends on the 'permeability modulus' in the formation on which the gas well is located. Introduction Gas reservoirs with abnormally high pressure have been encountered all over the world. In recent years, a lot of overpressured gas reservoirs were discovered in Tarim and Sichuan basins, such as Kela 2, Dina, and Dabei gas reservoirs. This overpressured gas reservoir exhibit stress-sensitive permeability characteristics. Well test analysis has been used for many years to assess well conditions as well as to obtain reservoir parameters. In many cases, the existing well test interpretation models satisfactorily describe the well pressures measured during the test. However, there are also situations when the observed pressure data does not "fit" predictions from any of the existing fluid-flow models, but rather exhibit distinctively different trends. Such trends in the pressure data can be attributed to a number of causes. One factor that can lead to inconsistencies would be that both the rock and fluid properties are stress dependent [1]. The physics of stress-dependent permeability is based on the deformation of porous rock under changing effective stress. Increasing the effective stress on rock leads to reduction in the size of pores and pore throats which is a consequence of deformation of the matrix. While the relative change of porosity is generally fairly small (within several percent), the relative change of permeability may be as large as one or two orders of magnitude [2].

Four reservoir samples under ultra-high-pressure and high-temperature conditions were collected from condensate gas fields in China. Constant-composition expansion tests were performed to determine the phase behavior and volumetric properties of reservoir fluid using an ultra-high-pressure fluid PVT test system. The compressibility factor and dewpoint pressure were obtained at four temperatures for four samples. The range of pressure was from 22.03 to 118.89 MPa. For the samples studied, the experimental results showed that the dew-point pressure decreased with increasing temperature and the compressibility factors increased with increasing pressure but decreased with increasing temperature at a given high reduced pressure. A thermodynamic model based on an equation of state was developed to describe the volumetric properties and phase behavior of the condensate gas under ultra-high-pressure conditions. The calculated results are in good accordance with the experimental data, which is important for the development of condensate gas reservoirs in ultra-high-pressure environments.

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