Mechanisms of fracturing fluid spontaneous imbibition behavior in shale reservoir: A review

Highlights

• Shale reservior possessed special properties, such as mixed wettability and sub-irreducible water saturation.

• The current experimental methods for monitoring the imbibition process also have limitations.

• Water-rock interaction is an important factor, it has both good and bad sides, and its internal mechanism is still unclear.

• Micro-stimulation and the Thermal-Hydro-Mechanical-Chemistry (T-H-M-C) multifield coupling model should be focus in the future.

Abstract

Spontaneous imbibition behavior gained popularity several decades ago which led to widely exploited application in fractured reservoirs. Recently the imbibition behavior of unconventional reservoirs has attracted a good number of researchers and field engineers to pay attention and research more on how to enhance recovery through imbibition behavior. Despite the numerous studies that have been conducted in this area, it is still controversial whether spontaneous imbibition behavior is applicable on reservoir stimulation especially for shale reservoir. In this paper, the recent works on the spontaneous imbibition behavior in unconventional reservoirs particularly for shale has been reviewed. This paper is divided into four main sections, the first section presents the review of the research progress in wettability, the imbibition scale model, and the pore-throat structure with regard to the capillary force and its related influencing factors. Moreover, the shortcomings of current research methods are presented. The second section involves the water–rock interaction examination including the ion exchange between the fracture fluid and reservoir as well as the evolution of the rock physical properties during well shut-in. The third section presents the review of the numerical simulation methods that have been used to study imbibition in the recent years focusing on the flow characteristics at the micro scale. In the final section, the future research directions from the current conducted researches have been suggested. Our research proposes that the thermal-hydro-mechanical-chemistry multi-field coupling effect should be considered in numerical simulations. It can provide a basis and reference for quantifying the effect of imbibition stimulation during the shut-in time.

Introduction

In order to achieve the commercial development of unconventional resources, a large amount of slick water and proppant must be pumped into a reservoir to create hydraulic fractures and keep fractures open, thus, the reservoir is shattered and a complex fracture network is formed (Ren et al., 2018a; Zhao et al., 2019a). After the fracturing operation completed, approximately 10d of flowback is needed to perform, which can reduce the blocking effect of the fracturing fluid retained in the fracture. However, in the recent years, researchers have found out that the flowback efficiency is extremely low in most unconventional reservoir wells. Field data indicate that the average amount of fracturing fluid that can flow back from the reservoir accounts for only 6%–10% of the injection fluid in shale plays in the USA (Vandecasteele et al., 2015; Yan et al., 2015). Barnett and Eagle Ford have a flowback efficiency of 20%, compared with the Haynesville shale having 5%, 9%–53% in Pennsylvania (an average of 10%), and 5%–30% in Fuling, China (Fan et al., 2010; Nicot et al., 2012; Yang et al., 2019a, 2019b). For that case, most of the fracturing fluid retained in the reservoir through various paths such as the shale matrix, microfracture, or fracture network system (Shen et al., 2018; Yang et al., 2018a; Zeng et al., 2019). The stated case above brings about two questions: (1) where does the fracturing fluid go? (2) How does it impact the well productivity? Previous studies have suggested that water-based fracturing fluids pumped into the formation can produce water-block effect, which is detrimental to production, and it is more severe in tight reservoirs with ultralow permeability. However, researchers and field engineers found that is not always the case (Wang et al., 2012; Sharma and Agrawal, 2013; Vandecasteele et al., 2015). By contrast, a higher gas production capacity and lower water production rate can be obtained when shut-in for a period of time. In other words, low flowback efficiency does not always bring negative effect on production. However, other researchers believed that well shut-in for a few days after fracturing is not always as good as expected, there may be exist a scope of application. To investigate the mechanism underlying the influence of the fracturing fluid retained in the shale reservoir on the subsequent production, many researchers have conducted physical experiments and numerical simulations to optimize the fracturing design. From this perspective, the traditional understanding on the flowback immediately after stimulation is gradually changing.

In this paper, we reviewed the mechanisms of fracturing fluid spontaneous imbibition in shale reservoirs where by the paper is divided into four sections. In the first section, field test cases are presented. In the second section, we reviewed the mechanisms of spontaneous imbibition including capillary force, its related factors and the water–rock interaction. In the third section, the progress in imbibition numerical simulations is reviewed. In the final section, the current research challenges are presented, and directions for future research are suggested.