*2.3. Reservoir*

The carbonate rocks that constitute the basement reservoirs in the Mesoproterozoic and Neoproterozoic are mainly dolostone, while in the Lower Paleozoic are dominated by limestone [38]. In these reservoirs, a network of pores and natural fractures have provided the storage space for the economic accumulation of hydrocarbons [17–19]. The pores are mainly secondary and are formed by dissolution, and natural fractures are more frequent and have multiple genetic types. These storage spaces provide favorable conditions for oil and gas accumulation and migration in these reservoirs. The carbonate rocks have an average matrix porosity lower than 12%, while the porosity analysis from cores has shown that samples with a porosity higher than 3% account for more than 70% of all samples [29,43]. The permeability of these basement reservoirs is relatively high, and samples with an air permeability greater than 1 mD account for more than 60% of all measured samples [43].

**Figure 3.** The stratigraphic column of the Jizhong Sub-Basin, showing the major petroleum systems (source rocks, reservoirs, and cap rocks) (modified according to Wu et al., 2011, and Liu et al., 2017) [19,37]. The gray mark in the system is the target layer of this study.

#### **3. Dataset and Methodology**

In this investigation, we collected data and samples from outcrops, cores, thin sections, and borehole image logs in the basement reservoirs of carbonate rocks in the Mesoproterozoic to Lower Paleozoic in the Jizhong Sub-Basin of the Bohai Bay Basin in eastern China. The outcrops and subsurface targets are from the same formation and have experienced similar tectonic movements and diageneses [39,44]. Cores and borehole image logs from 19 wells from these basement reservoirs were analyzed as well. The length of the cores is 123.8 m (406.2 ft). Thin sections are 119 pieces coming from cores. In addition, other useful information such as lithology, fault, perforated interval, and oil production, were collected from the Renqiu Oilfield database and relevant literature. We combined these di fferent sources of data to comprehensively analyze and study the natural fractures in deep inner reservoirs of these basements from macro to micro-scale.

Natural fracture characteristics, including height, length, orientation, dip angle, density, fracture zone, spacing, aperture, and filling, were examined closely from the sources mentioned above. The fracture density in this study refers to the linear density that was measured based on the number of fractures per unit length. The fracture zone is defined as multiple sets of tectonic fractures that are developed in rocks and usually are interwoven into a network, which makes it di fficult to measure and count individually. These parameters in outcrops and cores were identified and measured on-site, while in borehole image logs, they were manually picked and interpreted [45,46]. It should be pointed out that in the cores, there are some unnatural fractures caused by the drilling activity and pressure release. Usually, the surface of fractures produced during the drilling activity is uneven, and these fractures do not have obvious directionality. However, the natural fracture surface is relatively flat or even smooth and has a strong directionality. Moreover, because there was no underground fluid flowing through, the surface of fractures produced during the drilling activity and formed by pressure release is very new. Based on these characteristics, we distinguished such unnatural fractures from natural fractures in the observation and statistics of fractures in cores, in order to minimize their influence on the real data.

Natural fractures in borehole image logs usually appear as sinusoidal curves, making it possible to quantify their orientation, dip angle, density, and aperture [47,48]. Moreover, in borehole image logs with water-based mud, opening-mode fractures are usually filled with mud filtrate or low-resistance minerals and appear as dark sinusoidal curves, while filled fractures with high resistance minerals (such as dolomite and calcite) often present as light or white sinusoidal curves [49]. Thin sections with a thickness of 30 μm were made with blue-dye resin to highlight natural fractures and pores, and some of them were impregnated with alizarin red to distinguish calcite and dolomite [50]. These thin sections are divided into two types, vertical and parallel to the wellbore. The specific directions of each thin sections are marked in the captions of Figures. Fractures in these thin sections were observed and measured by the Olycia g3 software from Olympus, Japan [51].

By studying the variation law of the characteristics and intensity of natural fractures, the factors controlling fracture development in these reservoirs were determined. Furthermore, by comparing the lithology, fracture characteristics, and oil production in six perforated intervals, we evaluated the role of natural fractures on oil production and proposed ideas to optimize development plans in the carbonate basement reservoirs to enhance production. It should be noted that, in this analysis, the fracture density refers to the linear density of opening-mode fractures, and oil production refers to the daily production of oil during the well-testing stage.
