Abstract. The Tangshan region is one of the most seismically active areas in the North China, and the 1976 M 7.8 earthquake occurred on 28 July near the Tangshan fault zone. The Matouying enhanced geothermal system (EGS) field is located ∼90 km away from the city of Tangshan. Since late 2020, preliminary hydraulic stimulation tests have been conducted at depths of ∼3965–4000 m. Fluid injection into geothermal reservoir facilitates a heat exchanger system. However, fluid injection may also induce earthquakes. In anticipation of the EGS operation at the Matouying uplift, it is essential to assess how the fault slip potential of the nearby active and quiescent faults will change in the presence of fluid injection. In this study, we first characterize the ambient stress field in the Tangshan region by performing stress tensor inversions using 98 focal-mechanism data (ML≥2.5). Then, we estimate the principal stress magnitudes near the Matouying EGS field by analyzing in situ stress measurements at shallow depths (∼600–1000 m). According to these data, we perform a quantitative risk assessment using the Mohr–Coulomb framework in order to evaluate how the main active faults might respond to hypothetical injected-related pore pressure increases due to the upcoming EGS production. Our results mainly show that most earthquakes in the Tangshan seismic region have occurred on the faults that have relatively high fault slip potential in the present ambient stress field. At well distances of less than 15 km, the probabilistic fault slip potential on most of the boundary faults increases with continuing fluid injection over time, especially on the faults with well distances of ∼6–10 km. The probabilistic fault slip potential (fsp) increases linearly with the fluid injection rate. However, the fsp values decrease exponentially with increased unit permeability. The case study of the Matouying EGS field has important implications for deep geothermal exploitation in China, especially for Gonghe EGS (in Qinghai Province) and Xiong'an New Area (in Hebei Province) geothermal reservoirs that are close to the Quaternary active faults. Ongoing injection operations in the regions should be conducted with these understandings in mind.

The appropriate design of the operating pressure of underground gas storages (UGSs) is of great significance to their safe and profitable operation. In situ stress is basic data for determining the upper limit pressure of UGSs, analyzing fault stability in reservoir areas, and evaluating trap tightness. Generally, the design of the upper limit gas injection pressure of UGSs is a comprehensive geomechanical problem. After research and comparison of measurement methods, it is believed that the measurement of in situ stress induced by hydraulic fracturing can accurately obtain the in situ stress value near the wellbore, and having knowledge about the reservoir stress path will considerably decrease the risk of reservoir and cap rock instability during gas injection and production. Taking Well C1, an oil reservoir-type UGS in Block M, eastern China as an example, this paper introduces the use of hydraulic fracturing (HF) in situ stress testing technology to obtain the minimum principal stress values of the caprock, reservoir and floor intervals of Well C1. The measured minimum principal stress of the caprock is 32.8–36.8 MPa. Because it is an old well, the minimum principal stress of the reservoir is 33.7–34.2 MPa after correction of the in situ stress measurement according to the theory of elasticity. Based on the comprehensive analysis of the measured in situ stress data, it is believed that the safe upper limit of the reservoir-type gas storage in Block M is 27.2 MPa.

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