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The published extended-reach well (ERW) limit theory can be used to predict how far the horizontal ERW can extend. However, the use of this theory in shale formation remains poorly understood. Therefore, an open-hole extended-reach limit model of horizontal drilling in shales must be established based on the published ERW limit theory and models. First, the published models are modified for convenient practical calculation, and the core of this modified model is to predict the horizontal-section limit of horizontal ERW. The horizontal-section limit and the final open-hole extended-reach limit primarily depend on the annular pressure drop and fracture pressure in shales. Secondly, the characteristic of shale hydration swelling is considered. The stress state of the wellbore wall changes when the hydration stress is treated as a part of the effective stress. Moreover, the hydration stress can also significantly affect the horizontal-section limit and final open-hole extended-reach limit. In addition, a case study is performed, and the results indicate that the horizontal-section limit is 7292 m when there is no hydration stress, whereas it decreases by several thousand meters if the hydration swelling effect is considered. Finally, through the sensitivity analysis of the main factors in the modified model, the following results are obtained: the longer horizontal-section limit can be achieved in conditions with smaller flow behavior index, lower mud density, smaller mud flow rate, and lower temperature; meanwhile, a reasonable eccentricity range is also necessary, which is approximately 30–35 mm in this paper. The model in this paper provides a theoretical guidance for the optimization design method and operating parameters of horizontal ERW in shales to achieve a longer horizontal-section limit, which is significant for the use of shale gas. [ABSTRACT FROM AUTHOR]

The variation of pressure and temperate changes the phase behavior of the pore fluid and may affect the acoustic and geomechanical properties of shale formations. While this is not a major issue in conventional reservoirs, it may be important for shale reservoirs. Since the pore size of conventional formations is in the micrometer scale, capillary pressure is small and does not affect the phase behavior of the pore fluids. However, for shale formations with nano-scale pores, capillary pressure is very high promoting the condensation of the gas, or capillary condensation. As the result of capillary condensation, two phases may coexist in different parts within the pore space between rock grains. Understanding the effect of capillary condensation on acoustic properties of shale is essential to interpret well logging data and predict the effects of pressure, temperature, and fluids on geomechanical properties of shale formations. However, the effect of capillary condensation on acoustic properties of shale is not well investigated. In this research, we present a grain contact model to quantitatively determine the effect of capillary condensation on the geomechanical properties of the shale formations. Since reservoir fluids are in thermodynamic equilibrium at in-situ reservoir pressure and temperature conditions, thermodynamic equilibrium calculation is used to determine the properties of the fluid in the pores. The results indicate that at low frequencies, the difference is small because the thermodynamic properties of gas phase are not substantially different from those of oil phase in equilibrium with. However, at high frequencies, the difference increases considerably as the result of the mobility and compressibility difference between gas and oil phase. This causes the difference in Young's modulus of more than 10% and this difference increases with the increase of stress. Hence, capillary condensation impacts the correlations obtained between static and dynamic moduli and associated formation property determination using well logging data, seismic data. [ABSTRACT FROM AUTHOR]

Borehole instability problem is one of the key problems in drilling engineering, especially the shale formation with bedding planes and natural fractures, the failure of shale rock could be divided into two parts, shear failure across intact rock matrix and slippage failure in shale bedding, resulting in more serious borehole instability problem during drilling process. In this study, combining with rock strength anisotropy, a method of failure region around wellbore is developed for layered rocks on the basis of isotropic borehole stability model. The effect of shale bedding occurrence on failure region around wellbore, what was hardly conducted by former researchers, is examined systematically. The results show that, polar plot of critical lower mud weight with rock strength anisotropy considered reflects the actual situation of a shale formation; the shale bedding strength, pore pressure and intrinsic cohesion are the three most impact parameters on wellbore stability. Moreover, the maximum failure depth is no longer in the minimum principal stress, but locates in four corners at top and bottom of wellbore, which is induced by slippage failure in laminated formations; the collapse of wellbore will be aggravated due to the overlapping of failure in rock matrix and bedding. This proposed model not only can provide guiding suggestions for well constructions and cementations, but also can be used as an effective complement to provide richer ground stress inversion data. • Failure region model is developed considering strength anisotropy in layered rocks. • Impact of bedding occurrence on LCMW and failure region around wellbore are examined. • Quantitative risk assessment of key parameters on wellbore stability is conducted. • The overlapping of failure in rock matrix and bedding will increase unstable areas. [ABSTRACT FROM AUTHOR]