Analysis of Natural Hydraulic Fracture Risk of Mudstone Cap Rocks in XD Block of Central Depression in Yinggehai Basin, South China Sea

Abstract

The Yinggehai Basin is an important Cenozoic gas bearing basin in the South China Sea. With the gradual improvement of gas exploration and over-development in shallow layers, deep overpressured layers have become the main target for natural gas exploration. There are no large-scale faults in the strata above the Meishan Formation in the central depression, and hydraulic fracturing caused by overpressure in mudstone cap rocks is the key factor for the vertical differential distribution of gas. In this paper, based on the leak-off data, pore fluid pressure, and rock mechanics parameters, the Fault Analysis Seal Technology (FAST) method is used to analyze the hydraulic fracture risk of the main mudstones in the central depression. The results show that the blocks in the diapir zone have been subjected to hydraulic fracturing in the Huangliu cap rocks during the whole geological history, and the blocks in the slope zone which is a little distant from the diapirs has a lower overall risk of hydraulic fracture than the diapir zone. In geological history, the cap rocks in slope zone remained closed for a longer time than in diapir zone and being characterized by the hydraulic fracture risk decreases with the distance from the diapirs. These evaluation results are consistent with enrichment of natural gas, which accumulated in both the Yinggehai Formation and Huangliu Formation of the diapir zone, but it only accumulated in the the Huangliu Formations of the slope zone. The most reasonable explanation for the difference of the gas reservoir distribution is that the diapirs promote the development of hydraulic fractures: (1) diapirism transfers deep overpressure to shallow layers; (2) the small fault and fractures induced by diapir activities weakened the cap rock and reduced the critical condition for the natural hydraulic fractures. These effects make the diapir zone more prone to hydraulic fracturing, which are the fundamental reasons for the difference in gas enrichment between the diapir zone and the slope zone.

Fluid Charging and Paleo‐pressure Evolution in the Ledong Slope Zone of the Yinggehai Basin, South China Sea

“…Since the fault is less developed in N 1 h and N 1 m in the study area, whether the fluid migration between sand formations is related to the sealing of the caprock or not (Fan, 2018;Li X S et al, 2020;Jia et al, 2021), it is important to clarify the relationship between the evolution of the hydraulic fracture pressure of the caprock and the evolution of reservoir fluid pressure for studying the process of natural gas migration and accumulation. As the study area of Jia et al (2021) was also the Ledong Slope Zone, the strata studied were N 1 h and N 1 m and the relationship between hydraulic pressure and time also referred to Jia et al (2021), so the hydraulic fracture pressure evolution of mudstone from Jia et al ( 2021) could be used to assist in the study of the fluid charging process between sand groups.…”

“…The hydraulic fracture pressure evolution of mudstone of N 1 h and N 1 m in the Ledong Slope Zone is shown in Fig. 12 (Jia et al, 2021). Prior to 2.4 Ma, the hydraulic fracture pressure was small.…”

“…When the formation pore fluid pressure is greater than the hydraulic fracture pressure of mudstone, pressure can be relieved through hydraulic fractures (Watts, 1987). The development of hydraulic fracture depends on the pore fluid pressure, the characteristics of the in-situ stress field and the mechanical properties of the caprock (Jia et al, 2021). Among these, pore fluid Jia et al, 2021); PT = trapping pressure.…”

“…The development of hydraulic fracture depends on the pore fluid pressure, the characteristics of the in-situ stress field and the mechanical properties of the caprock (Jia et al, 2021). Among these, pore fluid Jia et al, 2021); PT = trapping pressure. CAI: coeval aqueous inclusions pressure and the mechanical parameters of caprocks can be obtained through formation tests and laboratory tests (Jia et al, 2021).…”

“…Among these, pore fluid Jia et al, 2021); PT = trapping pressure. CAI: coeval aqueous inclusions pressure and the mechanical parameters of caprocks can be obtained through formation tests and laboratory tests (Jia et al, 2021). Furthermore, the in-situ stress characteristics of the study area can be determined, including the vertical principal stress which mainly comes from the gravity of the overburden strata (Mcgarr and Gay, 1978), as well as the horizontal principal stress, which can be obtained from pumping pressure test data (White et al, 2002).…”