A New Experimental Approach for Hydraulic Fracturing Fluid Damage of Ultradeep Tight Gas Formation

Hui Li,Ben Li,Ninghong Jia,Jing Yang,Zhiliang Liu,Xu Chen,Lele Cao,Zhongwei Wu

doi:10.1155/2021/6616645

Abstract

The unconventional resources from an ultradeep tight gas reservoir have received significant attention in recent decades. Hydraulic fracturing is the main method for tight gas reservoir development because of its extremely low permeability and porosity. During hydraulic fracturing, high hydraulic fracturing fluid (HFF) that invaded the zone near the fracture face may reduce gas relative permeability significantly and impede gas production. The sources of this damage can be the high capillary pressure (HCP) and the presence of water-sensitive clays (PWC). For tight rock, it is usually infeasible to identify the primary damage mechanism using the traditional steady-state measurement method due to long measurement time and gauge accuracy. In this paper, we present a new experimental approach to identify the primary mechanism of the fracture face damage (FFD) through the application of the pressure transmission method and pressure decay method. Both rock matrix and naturally fractured tight samples (depth 18,000 ft, Tarim field, China) were tested. The experimental results showed that the average high capillary pressure damage indexes ( D HCP ) of rock matrix cores and naturally fractured cores are 94.9% and 92.4%, respectively, indicating severe damage caused by HCP. The average clay-swelling and mobilization (CSM) damage indexes ( D CSM ) of rock matrix cores and naturally fractured cores are 29.6% and 38.4%, respectively, indicating that the damage caused by CSM is lighter than that by HCP. HCP is the primary damage mechanism for the tight sandstone. And the damage degree of the rock matrix cores is higher than that of the naturally fractured core. The proposed procedures can be applied to identify the FFD mechanism of other tight and shale formation and provide insightful fundamental data for HFF optimization.

Highlights

The unconventional resources from an unconventional tight/shale reservoir have received significant attention in the past decades
Results showed that the DHCP range is from 88.4% to 99.7% and the DCSM range is from 28.6% to 43.9%
The pressure transmission method and pressure decay method were integrated to evaluate the degree of fracture face damage (FFD) caused by high capillary pressure (HCP) and clay-swelling and mobilization (CSM)

Summary

Introduction

The unconventional resources from an unconventional tight/shale reservoir have received significant attention in the past decades. The viscosity of hydraulic fracturing fluid (HFF) should be carefully optimized considering the proppant carrying ability and filtrate loss control [4,5,6]. For conventional resources such as sandstone or carbonate formation, the viscosity of HFF should be higher to achieve the proppant carrying capacity and fluid loss control purpose. For the tight/shale play, the permeability of the rock matrix range is from 10−3 to 10−8 μm; the HFF could not invade to the rock matrix of the fracture surface in a deep distance due to the micrometer-to-the-nanometer pore size of tight sandstone or shale and the presence of water sensitive clay in tight or shale plays. When immersed in fracture fluid, water molecules will enter the crystal lattice of Geofluids clay minerals, which is easy to cause volume expansion, blocking the pores of the fracture surface [7,8,9,10]

Methods

Results

Conclusion