Fig. (2a) shows that the argillite rock belongs to Es3 stratum of Paleogene is gray-black and the siltstone is gray. It can be clearly noticed that the siltstone contains oil is thick and black in the core. The fluorescent flake of Siltstone show yellow or brown colour, which indicates that it contains oil well. In contrast, the overlying argillite shows yellow or brown fluorescence, even part of this argillite shows bright yellow fluorescence, which indicates that it does not contain oil well (see Fig. 2b). The ingredients of the latter one are clay and debris particles, and its lithology is argillite rock or silty mudstone (see Fig. 2c).

Fig. (2). Argillite rock and silty mudstone, Tjs4o-y-y—2-25, Y160, 3164.85 m.

Fig. (3a) shows that the lower right side of the core contains oil well, while the upper left side of the core does not contain oil, and it is hard to see differences in lithology from the hand specimen. To analyse different relationships between oil and lithologies, oil slices and casting thin sections are taken from the oil interface. The results show that the oily part is sandstone, and the part of oil-poor is microscopic crystalline carbonate (limestone),which belongs to Es1 stratum of Paleogene (see Fig. 3b, c).

Fig. (3). Microcrystalline carbonate, J11zo, L801, 1691.43 m.

Sandstone rock of Fig. (4a) belongs to Es3 stratum of Paleogene is hard to find differences in lithology, contrastingly, easily find obvious differences in oiliness by naked eyes. The lower part appears brown containing significant amount of oil, while the upper part appears grey containing less oil. Judged from fluorescent flake, despite similarity of the lithology, the oily part shows yellow-green, and the transition zones of the oily and non-oily shows weak fluorescent colour (see Fig. 4b). In the oily and non-oily parts, the components and shapes of the debris particles are similar, while the cements are different. The oily section has less cement with pore development, the non-oily part has more cement, and majority of the base is carbonate cement (see Fig. 4c).

Fig. (4). Dense cemented sandstone, j9oo, Y99, 3150 m.

Fig. (5a) shows grey carbonate belonging to Ng stratum of Neogene. There are significant differences in oiliness. The lower part has an oil tie which approximates 6.3 cm. The oily part is brown and the non-oily part is yellow showed from the florescent slices. The components and shapes of the debris particles showed from the casting thin sections are similar in the oily and non-oily points. And the types of cements are different. The oily section has less cement with pore development, the non-oily part has less cement, majority of the base is carbonate cement (see Fig. 5b, c).

Fig. (5). Dense cemented carbonate, J6zo, CH40, 1503.4 m.

The above mentioned images just represent types of Paleogene–Neogene cap Lithology. In fact, it was found that argillite rock is the main type of Paleogene–Neogene strata in the Zhanhua sag. Because the information of other cap lithologies is incomplete, and the distribution on the plane is discontinuous, this paper focuses on the argillite rock rather than other cap rocks.

Both the porosity and permeability of the cap of argillite rock decreased and its sealing capacity was enhanced under continuously buried conditions, which demonstrates that the sealing ability is closely related to the degree of compaction [33]. If we ignore the effects of cementation on argillite porosity, the lower porosity of argillite has, the higher degree of compaction it has. According to the porosity of 62 argillite rock samples by Dunxiang Zhang (1979), we added our experimental data, and drew the graph of porosity vs. depth in Jiyang Depression, which well display the relevance between compaction and depth. Fig. (6) shows that argillite porosity decreases with increasing depth, in other words, the degree of compaction increases. According to the variation rate of porosity, the degree of compaction with depth can be classified into four stages:(1) less than 1000 m in depth, with a porosity greater than 23% and where the porosity deceases rapidly with increasing depth; (2) depth form 1000 to 2000 m, with porosity ranging from 20% to 23% and where the porosity deceases slowly with increasing depth; (3) depth from 2000 to 2700 m, with a porosity from 5% to 20% and where the porosity deceases rapidly with increasing depth; (4) deeper than 2700 m, with a porosity of less than 5% and where the porosity deceases very slowly with increasing depth.

Fig. (6). The relevance between argillite compaction and depth in Jiyang depression. (modified according to Dunxiang Zhang,1979).

Furthermore, a diagram of breakthrough pressure vs. compaction of argillite rock in the Zhanhua Sag was drawn, combined with experimental data from Xuetian Li (1992) and Zongqi Zhu (1996). The results show that the higher the degree of compaction of argillite is, the higher the breakthrough pressure it has, and the better sealing capacity it has. In the same way, the breakthrough pressure was also classified into 4 stages, which respond to the compaction of argillite rock: At stage I, the breakthrough pressure of argillite rock is low, generally 0.1-0.4 MPa. At stage II, its breakthrough pressure has increased, generally to 0.1-12 MPa. At the stage III, the breakthrough pressure is generally 4-12 MPa. At stage IV, its breakthrough pressure increases, generally to 10-25 MPa (see Fig. 7).

Fig. (7). Relationship between argillite compaction degree and breakthrough pressure in the Zhanhua Sag. (Modified according to Xuetian Li,1992, and Zongqi Zhu, 1996).

Overall, if other factors are ignored, the seal capacity of argillite rock becomes better with the depth increases.

For highly diagenetic mudstone, good physical parameters generally mean better sealing ability. In this case, two factors play an important role in the evaluating sealing capacity of mudstone, one is the mechanical properties of the cap, the other one is whether it has fractures [38]. In transformation of the latter period of tectonic movements, brittle rock can easily format micro-cracks, which weakened sealing capacity [33]. So we performed a research on the fractures through the core observation and found that the fracture is well developed in the Zhanhua sag, and then divided those fractures into three categories: horizontal fractures, nearly vertical fractures, and diagonal fractures (inclination typically greater than 45°).

4.2.1. Horizontal Fractures

Such fractures are common in the core, and those fractures can be classified into two types: level fractures and slip fractures. The former have no obvious sliding marks on the surface, and the latter refer to a fracture with obvious slippage. The horizontal fractures are of varying widths, and its lengths are generally small, from a few millimetres to more than ten centimetres. It could be observed that these fractures are filled by calcite veins, and some of them have traces of oil and bitumen. Moreover, slip fractures are also very common in the core, and mainly develop on the lithological contact surface. Its width is generally small, and most of them have sliding surface and obvious scratches. (see Fig. 8a).

Fig. (8). Fractures in argillite rocks of the Zhanhua Sag.

The fault could destroy argillite cap not only from the vertical side but also to a wide range in the plane. Fractures are well developed in the Zhanhua Sag according to the research of Shunxing Lu (2003) [39]. There are ten large faults that clearly control the deposition which are the LuoXi, GuXi, WuHaoZhuang, YiDong, ChengDong, KenDong, GuBei, GuNan, KenLi and ChengBei faults. In addition, a number of small faults are also developed inside the sag (see Fig. 1). This may have a great impact on the sealing of argillite rock. Therefore, the size of faults and the number of faults, especially the sealing of the faults have great impact on the sealing capacity [40]. This study focuses on the impact of fault-sealing on the cap.

4.3.1. Argillite Rock Mechanical Properties

We drew a diagram of argillite rock mechanical properties vs. fault sealing in the Zhanhua Sag, and classified both of them into three stages (see Fig. 9). The results indicate that argillite rock mechanical properties have a significant impact on fault sealing: At stage I (less than 1000 m in depth), when the fault is not active, it is easily closed. At this time, the fault sealing depends on argillite sealing, and its sealing is generally good. At stage II (depth form 1000 to 2000 m), when the fault is not active, it is not easy to close due to the strong rigidity of argillite. In other words, it is easy to maintain. In this case, fault sealing depends on the degree of development of the fractures, and its sealing is usually poor. At stage III (deeper than 2000 m), similarly to stage II, the fault is not easy to close when it is not active. Moreover, the argillite whose fractures are well developed will be affected by faults again, and fractures will be further developed. Thus, the sealing of the fault will become worse.

Fig. (9). Argillite rock mechanics stages and fault sealing capacity.

If we observe the faults of different strata as inactive faults, fault sealing is relevant to the mechanics stage of argillite rock. Therefore, we classified the faults into 3 stages, which respond to the argillite rock mechanics (see Fig. 9). The fault sealing capacity is good at stage I, and it becomes bad at stage II and III. At stage III, its sealing capacity is the worst.

Based on the above research, we have a clear understanding of the distribution of caprock types in each stratum. Furthermore, we put the existing oil and gas reservoir into the plane graph of cap distribution, and analyzed the relationship between cap and hydrocarbon accumulation. Similarly, the Ng and Es2 are selected. The results show that most oil and gas reservoirs of Ng stratum are located in the transfer belts of III to II. Above the transfer belt, the Nm is a Class II cap combination. However, below this transfer belt, the caps of Ed, Es1, Es2, Es3 stratum are all Class III cap combinations (see Fig. 12). Obviously, the sealing capacity of Class III cap combinations is better than that of Class II according to the previous study, thus leading to oil and gas accumulation.

Fig. (12). Relationship between cap and oil and gas reservoirs in the Ng of the Zhanhua Sag.

In the same way, we found that most oil and gas reservoirs of Es₂ stratum are located in the transfer belt of the rupture fault transformation cap to fracture transformation cap. Above the transfer belt are the Es₁ and Ed strata, where mainly Class III cap combinations are developed. Below this transfer belt is Es₃ stratum, and it is also a Class III cap combination (see Fig. 13).

Fig. (13). Relationship between cap and oil and gas reservoirs in the Es2 of the Zhanhua Sag.

Through the above analysis on the relationship between existing oil & gas reservoirs and the plane distribution characteristics of the Paleogene–Neogene cap in the Zhanhua Sag, it was found that the cap combination which is below or above the reservoir together control the hydrocarbon accumulation and preservation. The destruction of the cap below or down-dip the reservoir is a necessary condition for hydrocarbon accumulation, and only when the sealing capacity of the cap rock above or up-dip the reservoir is better than that of below or down-dip, oil & gas could be efficiently stored in reservoirs, thus could be effectively enriched.

Based on that, Fig. (14) was drawn to show the hydrocarbon accumulation and preservation of the porosity cap and fracture transformation cap. It can be seen that hydrocarbon most likely accumulates in reservoirs of the transition zone, when in the porosity cap and the fracture transformation cap composition system. However, when both above and below the reservoir is a porosity cap, oil & gas could not accumulate, and when both above and below the reservoir is fracture transformation caps, oil & gas can partly accumulate (see Fig. 14).

Fig. (14). Hydrocarbon accumulation and preservation in the porosity cap and fracture transformation cap.

Fig. (15) show that in the system of three cap types, the following combinations make it easy and effective for the reservoir to accumulate and preserve oil & gas: the transition belt of fault transformation cap and fracture transformation cap; the transition belt of fault transformation cap and porosity cap; the transition belt of rupture fault transformation cap and elastoplastic fault transformation cap; and the transition belt of elastoplastic fault transformation cap and plastic fault transformation cap (see Fig. 15).

Fig. (15). Hydrocarbon accumulation and preservation in a reservoir system consisting of a porosity cap, a fracture transformation cap, and a fault transformation cap.

In short, the cap above or up-dip the reservoir has effective sealing, that means the sealing capacity is better than that of below or down-dip the reservoir, is an important factor in controlling hydrocarbon accumulation.