Shale gas simulation considering natural fractures, gas desorption, and slippage flow effects using conventional modified model

Yongmao Hao,Huai Shu,Wendong Wang,Yuliang Su,Bin Yuan,Jie An

doi:10.1007/s13202-017-0366-7

Abstract

This paper presents the theory and application to modify the conventional simulator to describe the effects of gas adsorption and gas slippage flow in shale gas. Because of the local desorption of gas and the assumptions of gas desorption instantaneously with the decrease in pore pressure, we define one fictitious immobile “pseudo” oil with dissolved gas. The dissolved gas–oil ratio is calculated from the Langmuir adsorption isotherm constants and shale gas properties. Additional modifications required in the input data are the porosity and relative permeability curves to account for the existence of “pseudo” oil. The input rock table considers the changes of rock permeability versus pressure to describe the gas slippage flow effects. In addition, dual-porosity dual-permeability models coupled with local grid refinement method are used to distinguish the impacts of natural fractures and hydraulic fractures on shale gas production with the comparison of vertical well, fractured vertical well, horizontal well, and multistage fractured horizontal well production. This proposed simulation approach shows enough accuracy and outstanding time efficiency. Results show that ignoring gas desorption and slippage flow effects would bring significant error in shale gas simulation The existence of natural fractures also imposes great effects on the productivity of shale gas.

Highlights

Tight gas and shale gas have achieved great attention because of advancements of horizontal well drilling and large-scale fracturing technology
This paper presents the theory and application to modify the conventional simulator to describe the effects of gas adsorption and gas slippage flow in shale gas
We present the theory and application to modify the conventional simulator to describe the effects of Langmuir gas desorption and gas slippage flow effects (Shabro et al 2011; Waqas 2012)

Summary

Introduction

Tight gas and shale gas have achieved great attention because of advancements of horizontal well drilling and large-scale fracturing technology. Due to large-scale fracturing in shale gas reservoirs with natural fractures, the conventional single porosity model is not enough to simulate the characteristics of shale gas reservoirs. As for the flow regimes of shale gas, Knudsen number (Kn), the ratio of molecular mean free path to characteristic length, is commonly used. Knudsen diffusion increases because the molecular mean free path becomes comparable with the size of pore throat; in other words, the molecule/wall collisions will dominate particle/particle collisions. We present conventional modified simulation approach to simulate the performance naturally fractured shale gas reservoirs. If the desorption of shale gas is very fast compared with the rate of flow in shale reservoirs, the shale gas production will be dominantly controlled by the flow in reservoirs but not the desorption process Based on this assumption, we define one fictitious immobile ‘‘pseudo’’ oil with dissolved gas. In this paper, we modify the definitions of parameters in conventional black oil model to mimic the functions of composition simulator for shale gas

Fracture System:

Conclusion