Diagenetic history. Diagenetic history of the Miocene ZJ Formation sandstones is analyzed according to the types of diagenetic processes, cements, pore types and physical properties and other aspects37,38. Based on thin section and SEM observation, the diagenetic processes of studied interval consist of mechanical compaction; quartz; carbonate and clay mineral cementation; pyrite and dissolution. According to Morad et al.38, the diagenetic processes can be divided into eodiagenesis and mesodiagenesis. Eodiagenesis in this area is characterized by sediments underwent a paleogeotemperture of approximately 70°C, generally occurs at a depth less than 2 km. As the burying goes on, the diagenetic process comes to mesodiagenesis38. Based on reconstruction of burial-thermal history of well H1 in Z21 oil-gas field by Wu39, it is found the target ZJ Formation sandstones (mainly 2-3 km) has a corresponding formation temperature of 85-120°C (Figure. 9), illustrating that mesodiagenetic processes occurred.
Mechanical compaction is the bulk volume reduction result from lithostatic stress, characterized by reorientation of framework grains (Figure. 8a), deformation of ductile grains (Figure. 8b) or local fracture of brittle grains (Figure. 6c). Mechanical compaction occurs simultaneously with sediment deposition and is considered to dominate under temperatures ranging from 70°C to 80°C40, mainly corresponding to the eodiagenetic stage. No chemical compaction is observed in the microscope.
Quartz cementation occurs in the eodiagenetic process, mainly in the form of authigenic quartz. Mesodiagenetic quartz cementation in sandstones is often ascribed to intra-formational dissolution of detrital silicate phase, due to the low aqueous solubility of SiO241. However, there is minimal pressure dissolution of detrital quartz in the ZJ Formation sandstones, proved by no observation of detrital quartz dissolution in the view of thin section and SEM. the typical temperature of chlorite formation is approximately 60–70°C42, which refers to the end of the eodiagenetic stage. The photomicrographs of the SEM show that quartz overgrowth coated by authigenic chlorites indicate that authigenic chlorites occur after quartz overgrowth. The terminal of quartz overgrowth is restricted by the occurrence of pyrite (Figure. 8i), indicating that pyrite occurs prior to quartz overgrowth. Feldspar dissolution is considered as important material resources for quartz, kaolinite and illite precipitation43, therefore, it is inferred that quartz, kaolinite and illite cementations occur penecontemporaneously or kaolinite occur a little bit earlier than quartz cementations. In acidic conditions, the extensive illitization is associated with a temperature of 140°C44, indicating that illite occurs from the eodiagenetic stage, but is mainly formed in the mesodiagenetic stage.
The early calcite completely fills the intergranular pores, and the irregular shape of the calcite indicates it is formed prior or contemporary with severe mechanical compaction (Figure. 8g). In some cases, calcite together with other clay minerals such as kaolinite, usually partially fill the interparticle pores (Figure. 8d). Illite and kaolinite grow on the surface of calcite cementations, indicating that calcite precipitation occurs prior to both il-lite and kaolinite (Figure. 8d). Another kind of carbonate cementation, dawsonite, is considered as an indicator of CO245,46. CO2 stored in the ZJ Formation sandstones derived from both magmatism and organic matter evolution47. The acidic fluid, formed due to the CO2 injection into the sandstones, dissolve unstable minerals such as feldspar or rock fragment grains, producing sufficient Na+ and Al3+ for the dawsonite precipitations48,49. Therefore, dawsonite precipitations occur after dissolution (Figure. 9).
Diagenetic Controls On Reservoir Quality
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Sedimentary facies controls on reservoir quality. As mentioned above, deposits of H21 gas field were located far away from the delta front which is characterized by complex hydrodynamic conditions10, reflected by variable sedimentary structures (Figure. 5). Linking the heterogeneous porosity and permeability values (Figure. 7) to the varying lithofacies types, it is preliminarily inferred that reservoir quality of H21 gas field was significantly affected by depositional settings. As shown in Figure. 10a, statistics of different depositional elements show that both porosity and permeability values of SB are generally higher than those of SS. The SS depositional element is interpreted as sandstones deposited in low-energy environment, poorly sorted and with high matrix content51.
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Grain size controls on reservoir quality. Another factor affecting the reservoir quality is grain size. The grain size which reflects the primary texture of sandstones, may control the extent of the subsequent diagenetic events52. Statistics show that different grain-sized sandstones, namely fi-ne-grained, medium-grained, and coarse-grained sandstone have different porosity and permeability distribution centers (Figure. 10b). As the gain sizes increase, the porosity and permeability values generally become bigger (Figure. 10b). Compared to the smaller-sized sandstones, the larger-sized sandstones are usually well sorted with less matrix grains; meanwhile, rigid framework grains such as quartz are less influenced from complex compaction processes if they are larger-sized53.
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Diagenetic controls on reservoir quality.
1. Mechanical compaction. Mechanical compaction, intergranular pressure solution, cementation, framework grain dissolution, and cement dissolution have all been documented as playing significant roles in modifying porosity of various sandstones54. In the Miocene ZJ Formation sandstones, mechanical compaction is characterized by directional arrangement of grains, concave-conves contacts between the grains and plastic deformation of ductile grains. Upon burial, sediments will compact mechanically when the effective stress due to over-burden is increased, so that the porosity and the total rock volume are reduced55. As a result of increasing effective stress from the overlying strata during burial, the effect of mechanical compaction increases with the increase of burial depth in eodiagenesis56. As shown in Figure.11, as the burial depth goes deeper from approximately 2530-2570 m and from 2585 m to 2620 m, both the porosity and permeability decreases with the depth. Why the porosity and permeability values increase as the reservoir goes deeper in the 2570-2585 m interval? Probably it can be ascribed to two main aspects. Firstly, there is no sufficient sample data related to this depth range. Secondly, at burial depths greater than about 2 km (>70–80°C) quartz precipitation on clastic grains (Figure. 8f) gradually pro-duces a framework of quartz overgrowths which are strong enough to prevent further mechanical compaction55; and dissolution of feldspar enhance the porosity volume, indicated by Figure. 8j.
2. Cementation. Carbonate cements in this area are dominated by calcite. Dawsonite is ignored for quantitative statistical analysis due to limited samples encountering dawsonite cements. Calcite partially (Figure. 8d) or completely (Figure. 8g) filled intergranular pores, both reducing the pore spaces. As shown in Figure. 11, in general, both porosity and permeability values decrease as the increasing of calcite content, showing a remarkable negative relationship with R2=0.7449. However, it is noticed that when the content of calcite is less than 9%, there is no remarkable negative correlation between porosity and calcite (Figure. 12a). The sample that has a relatively higher calcite content of 18% with a permeability value of 48 mD (Figure. 12b) and a porosity value of 4% (Figure. 12a), is interpreted by the development of micro-fracture (Figure. 6c).
Typically, authigenic kaolinite, illite or other clay mineral may be found in nearby primary or secondary pores57. Precipitation of kaolinite can only occur when the K+/H+ ratio and silica concentration in the pore water are below certain values and such low K+/H+ ratios are normally only found in fresh or brackish water58. That means in intervals where CO2 concentration is high and dissolution of feldspar and debris is severe, the relative content of kaolinite precipitation could reach as high as 82% (Table. 2). However, the intercrystalline micropores within kaolinite aggregates is poorly developed. Therefore, the more kaolinites are, the more pore spaces were filled, showing a negative correlation between kaolinite and reservoir physical properties (Figure. 13a and 13b). As for illite, intercrystalline micropores within illite aggregates are generally well developed (Figure. 5d), the porosity and permeability values increase as the content of illites increase (Figure.13c and 13d). However, the convert from illite to the mixed layers of illite and smectite reduces some of pore spaces (Figure. 8e). At another hand, the pore filling illite aggregates may occupy some of pore spaces and result in a decrease in porosity and permeability (Figure.13c and 13d).
Grain-coating chlorites are generally considered as the porosity-preserving components in the sandstones42,51,58. Within ZJ Formation, as shown in Figure. 13e, the porosity increases and then decreases slightly, implying the chlorites coatings may retard quartz overgrowth within a limited content range (Figure. 8f). The relationship between chlorites and permeability is like that between chlorites and porosity (Figure. 13f). As the volume of chlorites accumulate, the porosity and permeability values decrease slightly due to the plugging of pore-filling chlorite aggregates.
In this studied area, although a single type of clay mineral may enhance the reservoir physical properties and another may weaken the congeneric properties, the porosity and permeability still display a decreasing trend with the total clay minerals, with low R2 values (0.25 and 0.5206, respectively) (Figure. 13g and 13h), indicating that clay mineral cementation is an important control factor of reservoir quality in the area.
Table 2
Relative content of the clay minerals via XRD and the porosity and permeability of the selected samples. K: kaolinite; I: illite; I/S: mixed layers of illite and smectite; C: chlorite; Ф: measured porosity; K: measured permeability.
Well
|
Depth(m)
|
Total clay (%)
|
Relative content of clay minerals (%)
|
Ф (%)
|
K (mD)
|
K
|
I
|
I/S
|
C
|
H3
|
2581
|
6
|
60
|
0
|
40
|
0
|
14.30
|
6.20
|
H3
|
2581.5
|
8
|
40
|
10
|
20
|
30
|
20.10
|
7.30
|
H3
|
2582
|
6
|
82
|
0
|
18
|
0
|
5.40
|
0.40
|
H3
|
2582.3
|
5
|
46
|
54
|
0
|
0
|
19.60
|
16.00
|
H3
|
2582.5
|
9
|
0
|
0
|
55
|
45
|
4.00
|
46.00
|
H3
|
2579.9
|
5
|
19
|
0
|
13
|
68
|
19.00
|
14.00
|
H3
|
2702.8
|
9
|
41
|
41
|
15
|
3
|
19.50
|
43.00
|
H2
|
2429.7
|
6
|
46
|
17
|
16
|
21
|
7.60
|
1.40
|
H2
|
2431.7
|
10
|
17
|
68
|
8
|
7
|
10.80
|
0.20
|
H2
|
2436.6
|
3
|
18
|
29
|
27
|
26
|
20.80
|
210.20
|
H2
|
2433.8
|
12
|
71
|
17
|
8
|
4
|
3.40
|
0.03
|
H6-1
|
2036.54
|
2
|
16
|
13
|
34
|
37
|
13.40
|
230.00
|
H6-1
|
2039.9
|
4
|
12
|
9
|
24
|
55
|
18.00
|
186.00
|
3. Dissolution. Dissolution is generally considered as a constructive factor that enhance reservoir quality51,57,58. The secondary dissolution pores are dominated by dissolution of feldspar and debris, and therefore, it is meaningful to ascertain whether dissolution is responsible for the deeper sandstones but with higher porosity and permeability values. The types of pores reflected by thin sections were analyzed by point counting and it is found that the deeper sandstones with higher porosity and permeability values usually have a greater proportion in secondary dissolution pores, whereas the shallower sandstones are dominated by residual primary intergraunar pores, which are limited in bulk volume (Figure. 14). Although influence of dissolution on reservoir quality studied in this way is not that rigorous, to some extent, dissolution enhancing the porosity and permeability is still proved in a qualitative way.
Distribution pattern of water, oil and gas in Z21 structure. Sources of oil and gas in the Z21 structure in Huizhou Depression has been studied by Zhu et al.16,50. The Z21 oil-gas field are characterized by multiple sources. Both the condensate gas in gas reservoir and solution gas in oil reservoir in the upper ZJ Formation are from the same source rocks of EP and WC Formation in HZ21 subsag, which are de-posited in shallow lacustrine to swamp, whereas the black oil in the lower ZJ Formation is from semi-deep to deep lacustrine source rocks with significant terrigenous parent organic matters in HZ26 subsag16 (Figure. 15). The gas reservoir formed earlier than that of oil reservoir in Z21 structure16. In 2014, modular formation dynamics test (MDT) was conducted in K22 set of well H1DSa and pure oil samples were collected; however, the subsequent drill stem test (DST) detected water show (not water from mud filtrate caused by drilling engineering) in the same depth of well H1DSa (location see Figure. 4)16. More interestingly, oil samples were collected in the depth lower than the interval where MDT and DST were conducted. Whether the main zone is a gas cap and the main zone is an oil ring confuse us. This problem may not be solved unless the source of collected water samples was ascertained. Zhu et al. focus on the sources of oil and gas in the Z21 structure16,50, but no interpretation of occurrences of water in the oil-bearing depth in K22 set was given. Another research published by Liu et al.14, successfully interpreted the decreasing current formation pressure coefficients data values from the wells H1D, H1DSa and H18, compared to the original formation pressure coefficient; and the reservoir connectivity between the west zone and main zone (locations of two zones see Figure. 4). However, still no answer was provided to the question that where the water comes from the oil-bearing sandstones.
In this study, a possible schematic pattern for water, oil and gas is proposed based on the sedimentary structures of cores, diagenesis, and physical properties (Figure. 16). As it has been proved that there is a low-permeability belt connecting main zone and the west zone (Figure. 16a)14. This is important foundation of the proposed water-oil-gas distribution pattern in this study. The original formation of K22 set is characterized by high water saturation (Figure.16a). As the gas begins to charge, a mass of effective pore spaces was filled with gas; meanwhile, the original formation water was forced to move to the low-pressure area by pore pressure, which is higher than the hydrostatic pressure (Figure.16b and 16c). Local sandstones (e.g., Figure. 5-C and 5-D) with low porosity and permeability were uncharged by gas and the original formation water was left behind, regarding as irreducible water (Figure.16b and 16c). Subsequently, oil begins to charge when the gas accumulation was finished16 and stops until both oil-water and oil-gas inter-faces were formed (Figure. 16d). When wells were drilled in the main zone, the formation pressure of west zone decreases, breaking the preexisting balance state of oil and water, partial irreducible water convert to movable water (Figure. 16e). As the production of the main zone goes on and the drill of well H1D, H1DSa and H18, formation of the west zone decreases severely, resulting in more irreducible water turning into movable water (Figure. 16f).