Experimental investigation on water removal and gas flow during drainage process in tight rocks

Highlights：

• Tight core samples with the permeability in range of 0.01–1 mD were selected to perform gas displacing water experiments.

• The effects of displacing pressure, pore size distribution as well as water invasion depth on water removal were experimentally examined.

• The water removal process was mainly consisted of a piston-like gas displacement water dominant stage and followed by gas flow-through drying phase.

• It is critical to remove more water before the re-establishment of gas flow channel in order to restore high gas permeability.

Abstract

High performance water removal plays a significant role in restoring the gas production when water invasion happens to tight gas reservoirs. In this paper, core samples with the air permeability in range of 0.01–1 mD were selected to investigate water removal behavior in tight gas reservoirs. Meanwhile, the gas flow capability during the process of water removal was discussed. The water desaturation curves generally experienced two stages of water removal in a drainage process: a fast water decline stage induced by immiscible displacement, followed by a long period of slow water saturation reduction stage via the gas flow-through drying. It pointed out that the immiscible displacement mainly affects water removal during the drainage process in which period continuous gas flow channel was built. Once the generation of continuous gas flow channel was accomplished during the immiscible displacement stage, a proper increase of displacement pressure difference can efficiently enhance the gas flow-through drying rate. Normally, it was easy for high permeable tight core sample to experience a short immiscible displacement dominant stage and step into gas flow-through drying dominant stage afterwards. Besides, it was found that the enlargement in water invasion depth will weaken gas flow capacity from water removal. These findings help in understanding the physical process of water removal in tight gas reservoirs, as well as designing a better performance of water removal in a tight gas flied.

Introduction

Water drainage plays a key role in managing the urban sewage discharge, underground water flow and agricultural water recycle (Schmitt et al., 2004; Ni and Capart., 2006; Williams et al., 2015). In oil and gas industry, water drainage is geologically known as a process of forcing oil or gas phase for water removal in a reservoir (Zheng et al., 2016), and also has a positive effect on removing formation damage induced by water invasion (Liu et al., 2015). With the growing interest in unconventional tight gas exploitation worldwide, the damage to gas well caused by water invasion has become a critical problem that needs to be solved urgently (Bahrami et al., 2012; Zhang et al., 2019; Bai et al., 2020). Compared to conventional gas reservoirs, tight gas formation exhibits significant high capillary pressure and extremely low rock permeability, resulting in a very limiting water removal capability. Hence, more serious damage to gas production can be arose after water invasion in tight gas reservoirs than conventional gas reservoirs. To secure the safety of gas production from water invasion in tight formation, an effective performance of water drainage is clearly vital. Therefore, the investigation of water removal behavior and gas flow capacity during water drainage process is of significant importance to understand the mechanisms of water drainage and gas production in tight rocks.

As one of the most realistic substituted resources of natural gas, tight gas reservoirs are generally considered as low or non-natural productivity because of the extremely low matrix permeability (Zou et al., 2013; Jia., 2017). To obtain commercial production, hydraulic fracturing technology has been widely used in the development of tight gas reservoirs recently (Zou et al., 2015; Gao and Li, 2016; Bagci et al., 2017). Due to the synergistic effects of drilling differential pressure and capillary imbibition, a huge amount of fracturing fluid can invade into the formation (Bennion et al., 2000a; Xu et al., 2020). The invaded fracturing fluid will result in the high degree of water retention, which greatly alter the gas flow condition and cause formation damage issues. Consequently, it would in turn exacerbate the effect of fracturing reformation and reduce the deliverability of gas well (Xu et al., 2016; Liu et al., 2019; Zhang et al., 2019). In order to preserve the effect of fracturing reformation and maintain the safety of gas production, high efficiency of water removal will be a good solution to control the incurred formation damage and reestablish the gas flow capability once water invasion happens (Holditch., 1979; Mahadevan et al., 2005, 2007a; 2007b; Meng et al., 2016).

Water removal in a rock can be significantly affected by its state, and theory holds that there are two statuses of invaded water in a pore space: free water flows in the center space of the pore, and bounded water (water film) adsorbs on the pore wall surface (Li et al., 2017). At a case of gas displacing water (Fig. 1), the water removal phases for these two types of trapped water are different, which are immiscible displacement phase (gas is considered to be insoluble in water) and evaporation phase (Kamath and Laroche., 2003). Immiscible displacement is a piston-like drainage process, finished by the generation of continuous gas flow channel. Evaporation is a process that the mass of bounded water (water film) decreases due to the gas flow-through drying effect. Generally, the removal of water in porous media firstly occurs the immiscible displacement and then follows by the drying evaporation (Mahadevan et al., 2007). Partial removal of free water will be accomplished during the process of immiscible displacement stage. Normally, the adsorbed water film cannot be naturally removed through the immiscible displacement manner, but its water content can be reduced under the effect of gas flow-through drying. Therefore, it is meaningful to enhance the efficiency of piston-like drainage and strengthen the effect of evaporation by increasing gas flow rate in order to remove more water out.

Many efforts were conducted to study the mechanisms of water removal process and its impact on gas flow capacity. Holditch (1979) demonstrated that water removal in gas reservoirs can be influenced by the capillary pressure, and capillary pressure would not be significant when the formation drawdown pressure is sufficiently high. Bennion (1999) suggested that rock wettability and interface tension always played an important role in the process of water cleanup. Zuluaga et al. (2001) performed the water drainage experiment through dry-gas injection and concluded that the evaporation rate increased with the increasing gas flow rate and declined with the increasing water salinity. Kamath et al. (2003) experimentally investigated the effects of water removal on gas deliverability when a water phase trapping (WPT) damage happened to a gas well. Kamath pointed out that gas deliverability gets recovered in two phases which are the first phase corresponding to the water production by immiscible displacement and the second phase corresponding to the evaporation of water via gas flow. Mahadevan and Sharma (2005) comprehensively studied behaviors of reducing the damage to gas permeability through water removal, and they claimed that using surfactant to change the rock wettability can improve the efficiency of water removal. Meanwhile, their group further discussed that immiscible displacement and evaporation can be affected by capillary force and gas humidity based on the experimental results (Mahadevan and Sharma, 2007). Liu et al. (2015) found that using surfactant can improve the degree of water removal and reduce the WPT damage to gas permeability in tight rocks. Kang et al. (2016) declared that formation damage issues induced by invaded fracturing fluid can be solved through water removal by formation heat treatment (FHT). Tian et al. (2018) stated that the increment in pore pressure can compress the fluid to build high fluid pressure, thus more water can easily flow under a minor displacement differential pressure. On the other hand, some mathematical methods were developed to address the water removal process in a porous media. Kamath et al. (2003) and Mahadevan et al. (2007b) successively utilize mathematical models to describe the phases of immiscible displacement and evaporation during the process of water drainage.

The previous works mainly focused on the water removal issues in conventional gas reservoirs or low permeability gas reservoirs, rarely contain a detail discussion of water removal issues in tight gas reservoirs with the matrix air permeability less than 1 mD (0.1 mD in-situ). In addition, the pressure transfer and gas flow capability during drainage process in tight rocks still need to be further investigated. Since a high performance of water removal is of crucial importance to restore the gas productivity of a tight gas well, investigation on the physical process of water removal and gas flow behavior during water cleanup will significantly benefit the design of the countermeasures for water trapping. In order to address these water removal events for tight gas reservoirs, in this paper, water drainage experiments are performed and some common formation damage issues that can be encountered within a water removal process are discussed to attempt to explore the strategy of water removal in tight gas reservoirs.