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Article

Coupling Relationship between Diagenesis and Hydrocarbon Charging in Middle Permian–Lower Triassic in the Eastern Slope of Mahu Sag in Junggar Basin, Northwest China

by
Wenlong Jiang
1,*,
Ping Song
1,
Hailei Liu
1,
Baoli Bian
1,
Xueyong Wang
1,
Wenjian Guo
1 and
Nan Wang
2
1
Research Institute of Exploration and Development, Xinjiang Oilfield Company, PethoChina, Karamay 834000, China
2
Shixi Oilfield Operation District, Xinjiang Oilfield Company, PetroChina, Karamay 834000, China
*
Author to whom correspondence should be addressed.
Processes 2023, 11(2), 345; https://doi.org/10.3390/pr11020345
Submission received: 1 November 2022 / Revised: 8 January 2023 / Accepted: 18 January 2023 / Published: 20 January 2023
(This article belongs to the Special Issue Physical, Chemical and Biological Processes in Energy Geoscience)
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Abstract

:
In this study, a variety of test and analysis methods, such as cast thin sections, fluorescent thin sections, scanning electron microscopy, fluid inclusions, etc., were comprehensively used and combined with logging data, sedimentary systems, burial history and other research results, to systematically study the diagenesis characteristics of Middle Permian Lower Wuerhe formation–Lower Triassic Baikouquan formation reservoirs and their control on hydrocarbon accumulation. The coupling relationship between the hydrocarbon accumulation process and reservoir secondary pores was established. The result shows that besides the development of primary intergranular pores, the reservoir develops secondary pores, such as particle dissolution pores, cement dissolution pores and fractures. The development of secondary dissolution pores, such as particle dissolution pores, carbonate and zeolite cement dissolution pores, is mainly controlled by the range and scale of organic acids produced by the thermal evolution of source rocks. It is considered that being located in the updip direction of source rocks, being involved in the development of the unconformity surface and the faults connecting source rocks, and being involved in the development of alkaline cements (such as laumontite) are the three dominant conditions for the development of secondary dissolution pores in the study area.

1. Introduction

The study of diagenesis is an important basis for finding different types of reservoirs. In recent years, good progress has been made in the study of diagenesis, mainly in the following three aspects: the influence of the interaction between fluid and rock on diagenesis [1,2], the relationship between hydrocarbon charging and reservoir densification [3,4], and the influence of high temperature and pressure on diagenesis evolution [5,6]. At the same time, diagenesis research also developed from qualitative to quantitative. Some scholars’ statistics show that at least 1/3 of the global clastic reservoir space is formed by mineral dissolution [7]. More and more scholars realize that a large number of secondary pores are produced by organic acid dissolution. For example, Shi et al. and Zhao et al. found that compared with other types of feldspar, the secondary pores formed by the dissolution of potassium feldspar are the largest [8,9]. Yang et al. found that the main product of potassium feldspar dissolved in organic acids is kaolinite [10].
The exploration work of the study area is dominated by fault stratum traps in the early stage, and the exploration wells are all located near the fan delta plain or the transitional zone between the fan delta plain and fan delta front. The lithology is dominated by coarse-grained thick blocky sandy conglomerates with poor sorting and poor physical properties. Therefore, although many exploration wells in the study area obtained oil and gas, the yield is generally low and no substantive breakthrough has been achieved. In recent years, through the transformation of exploration ideas, the exploration of Triassic Baikouquan formation in the western slope of the Mahu sag, which is adjacent to the study area, has achieved fruitful results and many wells obtained high-yield industrial oil and gas flow. Therefore, more and more attention has been paid to the eastern slope of Mahu sag with the same favorable conditions for oil and gas migration and accumulation.
In this article, the diagenesis characteristics of the Middle Permian Lower Wuerhe formation–Lower Triassic Baikouquan formation reservoirs and their control on hydrocarbon accumulation will be studied to establish the coupling relationship between diagenesis and hydrocarbon charging in order to provide a theoretical basis for exploration work in the study area.

2. Geological Setting

The Junggar Basin is located in the northern part of Xinjiang province. It is sandwiched between the Zaire Mountains, the Qinggelidi Mountains, the Kelameili Mountains and the Yilinhebiergen Mountains. It is slightly triangular and has an area of about 13.6 × 104 km2. It is a superimposed basin that has undergone multiple tectonic movements from Paleozoic to Quaternary. The study area is located in the northwestern margin of the Junggar Basin (Figure 1a), which is the most abundant area of oil–gas accumulation. The Carboniferous to Quaternary are well developed, and the maximum sedimentary thickness is nearly 15 km [11]. Permian and Triassic, Triassic and Jurassic, Jurassic and Cretaceous are regional unconformable contact relations (Figure 1b). The overlap and denudation of the Permian strata are obvious. Vertically, oil and gas reservoirs are distributed in 14 formations of 5 systems, i.e., Carboniferous, Permian, Triassic, Jurassic and Cretaceous [12]. The main objective strata of this study are Middle Permian Lower Wuerhe formation and Lower Triassic Baikouquan formation (Figure 1c).
The study area has undergone multi-stage tectonic movements, such as Hercynian, Indosinian, Yanshanian and Himalayan tectonic movements. The sedimentary strata were relatively stable in the Indosinian movement (Triassic–early Jurassic), where the formation thickness changes little and gradually overlaps in the direction of uplift. In the early Yanshanian movement (middle Jurassic), it was relatively stable, forming delta facies and lake facies. In the middle and late Yanshanian movements (late Jurassic–early Cretaceous), the activity was intensified. It was manifested in the strata above the middle Jurassic system, especially the Toutunhe formation, which was obviously denuded and thinned to the high part and was in angular unconformity contact with the overlying Cretaceous. The late Yanshanian and Himalayan tectonic movements had little influence on the Cretaceous, but during the Himalayan (Neogene-Quaternary), the regional southward tilting caused the strata above the Jurassic in the study area to form a monocline structural feature uplifted to the northwest [13].

3. Methodology

In this study, an Olympus CX23 optical microscope was used to observe the microscopic mineral and pore structures of samples. The resolutions of the secondary electron image of the Tescan scanning electron microscope were 1.0 nm (15 kV) and 1.5 nm (1 kV), and the resolution of the analysis mode is 3.0 nm (15 kV, 5 nA, WD = 8 mm). This microscope was used for the ultra-high resolution observation of the pore type, pore structure, mineral type, and sample structure. The CM300 overburden porosimeter was used to determine the physical properties of the samples. The effective porosity test range is 0.01–40%, the permeability test range is 0.0005 mD–15 D. The experimental analyses were conducted at the Institute of Experiment and Analysis at the Xinjiang Oilfield Company (Karamay City, Xinjiang province, China).
The fluid inclusions were investigated via mono-polarizer and fluorescent observations using an Olympus Dual Channel Fluorescent-Transmission Light Microscope equipped with a telephoto lens (8 mm, 100×). The digenetic occurrence of inclusions and the fluorescent colors of the hydrocarbon inclusions were observed. Doubly polished thin sections were prepared for fluid inclusion microthermometric analysis using a Linkam THMS-600 heating–freezing stage. The homogenization temperature (Th) of fluid inclusions were obtained by cycling to the liquid phase. The measurements were determined using a heating rate of 10 °C/min. The measured temperature precisions for the homogenization is ±1 °C. The laboratory testing temperature was 25 °C, and the humidity was 65%. The experimental analyses were conducted at the Analtical Laboratory of Beijing Research Institute of Uranium Geology.
PetroMod-1D basin modeling software was used to reconstruct the burial history, thermal history and hydrocarbon generation history.

4. Results

4.1. Compositions, Porosity and Permeability

The sandy conglomerates reservoir of the Middle Permian Lower Wuerhe formation–Lower Triassic Baikouquan formation in the study area is characterized by low porosity and permeability, and its vertical differentiation characteristics are also obvious. The reservoir properties of each formation are as follows.
The size of detrital grains in the reservoir of the Baikouquan formation is mainly distributed between 0.25–2 mm. There is also a large amount of distribution between 2–10 mm, up to 10 mm. It has the characteristics of low textural maturity and low composition maturity. The particle sorting is poor, and the roundness is mainly subangular–subround. The particles are mostly line contact and particle support. Reservoir porosity is normal distribution (Figure 2a), mainly concentrated in 6~12%, an average of 9.38%. Permeability is also of a normal distribution but relatively concentrated, mainly distributed in (0.1~1) × 10−3 μm2, except for the influence of fracture factors; the average is 2.35 × 10−3 μm2 (Figure 2b), which is a typical low porosity and low permeability reservoir. The analysis shows that the main reason for the great change of reservoir physical properties in the Baikouquan formation is the difference of facies and grain size. The high porosity sandy conglomerates reservoirs are mainly distributed in the underwater distributary channel subfacies of fan delta front, and the micro-fractures developed near the fault zone also have a great effect on the improvement of reservoir physical properties.
The sizes of detrital grains in the reservoir of the Lower Wuerhe formation are mainly larger than 2 mm, up to 20 mm. It also has the characteristics of low textural maturity and low composition maturity. The particle sorting is poor, and the roundness is mainly subrounded. The contact between particles is mainly line contact, followed by point–line contact and point contact. Compared with the Baikouquan formation, the porosity and permeability of sandy conglomerates in the Lower Wuerhe formation decrease: the porosity distribution is relatively concentrated between 6% and 10%, with an average of 8.53% (Figure 3a). Permeability distribution range is relatively wide, mainly distributed in the range of (0.01~10) × 10−3 μm2 (Figure 3b). The reservoir properties of sandy conglomerates in the Lower Wuerhe formation are greatly affected by the cementation of laumontite and the dissolution of volcanic clastic. For example, the reservoirs with porosity greater than 16% in Well YB1 are mainly laumontite-dissolved reservoirs.

4.2. Compaction

The compaction effect in the study area is obvious, which is the main pore reduction effect of the reservoir. Under the microscope, the contact relationship between the clastic particles is mainly point–line contact, and the concave–convex contact is locally developed. With the deepening of the sandy conglomerates burial, the compaction effect is enhanced so that the clastic particles are closely arranged in a certain direction (Figure 4a). The rigid particles (such as quartz and feldspar particles) are broken under pressure, and the feldspar is mostly broken along the cleavage crack. With the further strengthening of compaction, the contact mode of particles transits from point contact to line contact until the concave–convex contact (Figure 4b). Finally, the phenomenon of pressure solution appears with sutured contact, as shown in Figure 4c,d.

4.3. Cementation

Previous studies have confirmed that the initial sedimentary water of the Baikouquan formation in the study area is acidic, and the Lower Wuerhe formation is alkaline [14,15,16,17]. Therefore, the Baikouquan formation mainly develops neutral-acidic cements, such as kaolinite, quartz secondary overgrowth rims and illite. Silicate and carbonate cements can also be formed in some areas. The sandy conglomerates of the Lower Wuerhe formation mainly forms cements, such as silicate and carbonate in alkaline sedimentary environment, especially zeolite cement.

4.3.1. Carbonate Cementation

Carbonate cementation is common in the reservoir of the study area, and cements are mainly calcite, followed by iron calcite. Calcite is most widely distributed and common in the Baikouquan formation, while iron calcite basically disappears in the Lower Wuerhe formation. The volume fraction of calcite in the Baikouquan formation varies greatly, from 2.39% to 15.31%, which in the Lower Wuerhe formation is relatively stable, with a minimum of 2.64% and a maximum of 9.78%. However, there is strong iron calcite cementation (nearly 7%) in the Lower Wuerhe formation reservoir of Well YT1, and the iron calcite is blue-purple under microscopic observation due to the large amount of iron content. From the microscope, it can be seen that the calcite cement in the reservoir is granular and mosaic. When carbonate cementation is strong, reservoir properties are generally poor. However, it can provide conditions for dissolution (Figure 5a).

4.3.2. Siliceous Cementation

The volume fraction of siliceous cement in the study area is relatively low, with an average of 1.2%, which is mainly composed of quartz secondary overgrowth rims and filled in pores as automorphic granular. Under the scanning electron microscope (SEM), small automorphic quartz crystals are commonly found in intergranular pores or intragranular dissolved pores at the edge of clastic particles (Figure 5b), which play a role in reducing porosity. However, the formation of a certain number of siliceous cements can enhance the anti-compaction strength of the sandstone and prevent the destruction of residual primary intergranular pores by compaction, which has certain positive significance for reservoirs.

4.3.3. Zeolite Cementation

The zeolite cement in the study area is composed of laumontite and heulandite, mainly laumontite (Figure 5c,d). Laumontite generally is columnar; it often grows along the intergranular pores and intragranular dissolved pores. It mainly formed in the middle and late diagenesis stage. The distribution of zeolite cements is controlled by volcaniclastic materials in the source area, and they often coexist with calcite in intergranular pores to plug pores. However, the zeolite cementation is also conducive to the formation of secondary pores by later dissolution, thereby improving reservoir physical properties.

4.3.4. Authigenic Clay Mineral Cementation

According to the results of X-ray diffraction (XRD), thin section and SEM, it is found that the clay minerals of the Baikouquan formation in the study area are mainly composed of illite–smectite mixed layer, chlorite, illite and kaolinite, while the Lower Wuerhe formation is mainly composed of illite–smectite mixed layer, chlorite and illite. Kaolinite has completely disappeared. In the Baikouquan formation and Lower Wuerhe formation, the content of flaky illite is high, followed by the filamentous illite transformed from kaolinite (Figure 5b), while the honeycomb illite transformed from montmorillonite is rare. In SEM, kaolinite is a worm-like filling in the reservoir pores of the Baikouquan formation or distributed on the surface of the particles (Figure 5e); illite is a curved flake filling in the pores or distributed on the surface of the particles (Figure 5f) and chlorite is an irregular flake, filamentous filling in the pores (Figure 5g). The authigenic clay minerals mainly come from the connate water, the alteration of unstable components of clastic rocks and the transformation of clay from overlying mudstone.

4.3.5. Feldspar Cementation

The type of feldspar cement in the study area is mainly sodium feldspar, which is mostly formed by small automorphic crystals and filled in pores in fine lath or granular form (Figure 5h,i).

4.4. Dissolution

The burial depth of the Baikouquan formation and Lower Wuerhe formation in the study area is large, the overlying load compaction is strong and the cementation is common, resulting in a large volume loss of primary pores, especially in the superimposed structural compressive fault zone. As a result, the primary porosity of sandy conglomerates in the Lower Wuerhe formation is generally less than 10%, and that in the Baikouquan formation is less than 15% [18,19]. Therefore, dissolution and micro-fractures are important genetic mechanisms for the effectiveness of sandy conglomerates’ pore structure. Through the observation of cast thin sections, it is found that the dissolved materials in the study area are mainly debris, feldspar, calcite, laumontite, etc. The dissolution of debris particles usually has three characteristics: only part of the minerals in the particles have local dissolution, forming spotted, honeycomb and striped intragranular dissolution pores (Figure 6a,b); the particles are strongly dissolved, leaving only part of the residue or the entirety of it dissolved to form a mold pore (Figure 6c–e); and the edge of the particles dissolved irregularly or expanded to form intergranular enlarged dissolved pores (Figure 6f,g). In addition, intergranular interstitial materials and calcite, laumontite, sodium feldspar and other cements also exist dissolution. The laumontite dissolution pores is one of the important factors to improve reservoir physical properties in the Lower Wuerhe formation (Figure 6h,i).

4.5. Petrography and Homogeneous Temperature of Fluid Inclusion

The fluid inclusions in the Baikouquan formation and the Lower Wuerhe formation in the study area mainly occur in diagenetic microcracks of quartz grain, calcite veins and analcime veins. Two-phase hydrocarbon inclusions are common and the content is about 5–10%. Among the observed inclusions, there are many two-phase hydrocarbon inclusions in which methane bubbles are mostly elliptical and some of them are irregular in shape. The content of hydrocarbon inclusions can reach 15~20% (Figure 7).
The appearance of hydrocarbon inclusions with different fluorescence can provide strong evidence for the migration and charging of oil and gas in different periods. Microscopic fluorescence observation found that the fluorescence color of hydrocarbon inclusions in the study area is diverse, mainly light blue (Figure 8a,b), blue (Figure 8c), light yellow (Figure 8d,e) and yellow (Figure 8f), indicating the change in maturity of oil and gas. Judging from the fluorescence color, there are at least two stages of hydrocarbon charging in the reservoir in the study area. The first stage should be the yellow fluorescent inclusions representing the early charging, and the other stage should be the blue fluorescent inclusions representing the late charging.

5. Discussion

5.1. Timing of Hydrocarbon Accumulation

By studying the homogenization temperature of fluid inclusions in the reservoirs of the Baikouquan formation and the Lower Wuerhe formation in the study area, it is found that the homogenization temperature of brine inclusions associated with yellow fluorescent hydrocarbon inclusions is concentrated between 70~80 °C, and the homogenization temperature of brine inclusions associated with blue hydrocarbon inclusions is between 140~150 °C (Figure 9). Combined with the study of burial temperature history of well DT1 in the slope zone (Figure 10), it is considered that the first stage of oil charging is mature crude oil generated in the early Jurassic, which is characterized by yellow fluorescent hydrocarbons. High-intensity and large-scale migration and charging occurred in the study area, and large-scale accumulation occurred in Mahu sag and its periphery. The second stage of hydrocarbon charging is in the early–middle Cretaceous, which is blue-white fluorescent high maturity crude oil and is also widely charged and accumulated. These results are consistent with previous studies [20,21].

5.2. Organic Acid Dissolution and Its Control on Accumulation

Hydrocarbon source rocks can produce a large amount of organic acids before generating a large amount of oil. The organic acids formed have a great influence on the diagenesis of reservoirs, which has been recognized by many scholars [22,23,24,25]. The kerogen in the source rock will remove oxygen-containing functional groups (such as carboxyl and phenol) and form a large number of organic acids (such as oxalic acid and acetic acid) under the thermal action of 80~120 °C. These organic acids are easy to form complexes with Al3+, which increases the activity of Al3+ and promotes the dissolution of aluminosilicate and calcite. When the temperature rises to 120~160 °C, the carboxylic acid anion will undergo thermal decarboxylation and crack into hydrocarbons and CO2, which will increase the concentration of CO2 in the strata water and reduce the concentration of organic acids [22,25]. At the same time, the concentration of acid in strata water will increase due to the dissolution of CO2 in water to form carbonic acid. As a result, alkaline minerals will continue to be dissolved.
As shown in Figure 11, yellow fluorescent mature hydrocarbon inclusions and blue fluorescent highly mature hydrocarbon inclusions can be observed simultaneously. It is speculated that it may be due to the formation of new dissolution pores by organic acids dissolving alkaline minerals during the migration of mature oil in the first stage, which provides space for the capture of highly mature hydrocarbon in the second stage, resulting in the occurrence of yellow fluorescent inclusions and blue fluorescent inclusions in the same part of the reservoir. It provides strong evidence for organic acid dissolution minerals to improve reservoir physical properties.
A large number of dissolution pores are formed in the reservoirs of the Baikouquan formation and the Lower Wuerhe formation in the study area, which greatly improves the reservoir physical properties. There are three main favorable conditions for this phenomenon: (1) The study area is located in the upward direction of the hydrocarbon generation center, which is conducive to the migration of organic acids and makes it easier to react with alkaline minerals. (2) Development of faults and unconformable surfaces: faults connecting source rocks are developed in the study area, providing a vertical channel for the migration of organic acids. In addition, the unconformity surface between the Baikouquan formation and the Lower Wuerhe formation and stratigraphic pinch-out line are developed in the study area [26], which provides an important channel for the lateral migration of organic acids. (3) The laumontite cementation particularly developed in the study area. Previous studies on the distribution of zeolite in this area suggest that the study area is close to the ancient lake center, and the high salinity and alkalinity in the early diagenesis are the two major factors for the development of laumontite, resulting in the formation of laumontite development zone in the study area [27]. The more laumontite cement, the greater the probability of acidic fluid contacting laumontite through fractures, unconformity surfaces and residual intergranular pores, as well as being easier to form dissolution pores.
The above-mentioned studies indicate that the dissolution during diagenesis in the study area is closely related to the hydrocarbon charging process. It can be seen from Figure 12 that after the organic acid reaches the unconformity surface with hydrocarbon along the faults connecting to source rock, it will migrate to the high part of the structure, so the sandstone reservoir in the high part will first develop secondary pores. The concentration of organic acids in the high part is relatively higher and dissolution is more intense. As shown in Figure 12, there are faults connecting source rocks between wells MZ1 and MZ2. Organic acids migrate vertically with hydrocarbon through faults to the unconformity surface, and then migrate laterally along the unconformity surface (or sandstone) to the high part of the structure. Therefore, a large number of secondary pores dissolved by organic acids are developed in the reservoir of well MZ2, which is located in the high structural position. There is no fault connecting source rocks in the downdip direction of well MZ1, so there is almost no organic acid passing through. As a result, the reservoir is basically not dissolved and the physical properties is poor. In addition, the sedimentary subfacies of the Lower Wuerhe formation in well XY3 is in the fan delta plain, and the reservoir is very tight. So even if there is organic acid fluid passing through, dissolution is not easy because there is no chance for organic acids to contact with alkaline cements.
In summary, it suggests that the sandstone of fan delta front subfacies rich in alkaline cements is the basis for the formation of secondary pores, the dissolution of organic acids is the main factor controlling the development of secondary pores, and the dominant migration channel is a necessary condition for the formation of a large number of secondary pores.

6. Conclusions

(1)
The sandy conglomerates reservoirs of the Lower Wuerhe formation–Baikouquan formation in the study area are characterized by low porosity and permeability, and both of them have low textural maturity and compositional maturity and poor size classification. However, the reservoir physical properties of the Lower Wuerhe formation are more affected by laumontite cementation and volcaniclastic dissolution.
(2)
There are two stages of large-scale hydrocarbon charging in the study area: the first stage is the mature crude oil generated in the early Jurassic, which is characterized by yellow fluorescent inclusions; the second stage of hydrocarbon charging is in the early–middle Cretaceous, characterized by blue-white fluorescence inclusions.
(3)
By restoring the process of hydrocarbon accumulation in the study area, the coupling relationship between diagenesis and hydrocarbon charging is established. The sandstone of fan delta front subfacies in the study area is rich in alkaline mineral. Therefore, when organic acids enter the reservoir along the dominant migration path with hydrocarbon, it can have strong dissolution, providing more reservoir space for subsequent hydrocarbon accumulation.

Author Contributions

Conceptualization, W.J.; methodology, H.L. and W.J.; validation, P.S., H.L. and B.B.; formal analysis, P.S.; investigation, H.L.; resources, P.S. and N.W.; data curation, P.S. and W.G.; writing—original draft preparation, W.J.; writing—review and editing, W.J.; visualization, X.W. All authors have read and agreed to the published version of the manuscript.

Funding

This research was funded by Major projects of PetroChina science and technology [2021DJ0206].

Data Availability Statement

Data is unavailable due to confidentiality.

Conflicts of Interest

The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.

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Figure 1. Distribution of structural units in the northwestern Junggar Basin. (a) study area tectonic unit and exploration well distribution; (b) typical reservoir profile of study area; (c) stratigraphy histogram of study area.
Figure 1. Distribution of structural units in the northwestern Junggar Basin. (a) study area tectonic unit and exploration well distribution; (b) typical reservoir profile of study area; (c) stratigraphy histogram of study area.
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Figure 2. Distribution frequency histogram of porosity (a) and permeability (b) of Baikouquan formation.
Figure 2. Distribution frequency histogram of porosity (a) and permeability (b) of Baikouquan formation.
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Figure 3. Distribution frequency histogram of porosity (a) and permeability (b) of Lower Wuerhe formation.
Figure 3. Distribution frequency histogram of porosity (a) and permeability (b) of Lower Wuerhe formation.
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Figure 4. Cast thin sections of compaction in study area. (a) well YT1, 4821.9 m, Lower Wuerhe formation, sandy conglomerates, grains in close contact, line contact–concavo–convex contact; (b) well YT1, 4810 m, Lower Wuerhe formation, medium sandstone, grains in close contact, line contact–concavo–convex contact; (c) well MZ4, 3580 m, grains in close contact, sutured contact; (d) well M18, 3438.3 m, grains in close contact, sutured contact.
Figure 4. Cast thin sections of compaction in study area. (a) well YT1, 4821.9 m, Lower Wuerhe formation, sandy conglomerates, grains in close contact, line contact–concavo–convex contact; (b) well YT1, 4810 m, Lower Wuerhe formation, medium sandstone, grains in close contact, line contact–concavo–convex contact; (c) well MZ4, 3580 m, grains in close contact, sutured contact; (d) well M18, 3438.3 m, grains in close contact, sutured contact.
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Figure 5. Thin sections and SEM images of cementation in study area. (a) thin section of well YT1, 5044 m, Lower Wuerhe formation, strong calcite cementation; (b) SEM image of well MZ2, 4199.36 m, Baikouquan formation, intergranular filling of authigenic quartz and filamentous illite; (c) SEM image of well M217, 4000.39 m, Lower Wuerhe formation, intergranular filling of zeolite; (d) thin section of well M217, Lower Wuerhe formation, heulandite cementation; (e) SEM image of well D11, 4280.63 m, Baikouquan formation, intergranular filling of worm-like kaolinite; (f) SEM image of well D11, 4294.47 m, Baikouquan formation, intergranular filling of lineated flaky illite; (g) SEM image of well M217, 4004.56 m, Lower Wuerhe formation, intragranular dissolved pores filling of leaf-shaped chlorite; (h) cast thin section of well YT1, 4872.5 m, Lower Wuerhe formation, authigenic sodium feldspar in intergranular pores and chlorite film developed; (i) SEM image of well MZ2, 4283.04 m, Baikouquan formation, intragranular dissolved pores filling of sodium feldspar crystal.
Figure 5. Thin sections and SEM images of cementation in study area. (a) thin section of well YT1, 5044 m, Lower Wuerhe formation, strong calcite cementation; (b) SEM image of well MZ2, 4199.36 m, Baikouquan formation, intergranular filling of authigenic quartz and filamentous illite; (c) SEM image of well M217, 4000.39 m, Lower Wuerhe formation, intergranular filling of zeolite; (d) thin section of well M217, Lower Wuerhe formation, heulandite cementation; (e) SEM image of well D11, 4280.63 m, Baikouquan formation, intergranular filling of worm-like kaolinite; (f) SEM image of well D11, 4294.47 m, Baikouquan formation, intergranular filling of lineated flaky illite; (g) SEM image of well M217, 4004.56 m, Lower Wuerhe formation, intragranular dissolved pores filling of leaf-shaped chlorite; (h) cast thin section of well YT1, 4872.5 m, Lower Wuerhe formation, authigenic sodium feldspar in intergranular pores and chlorite film developed; (i) SEM image of well MZ2, 4283.04 m, Baikouquan formation, intragranular dissolved pores filling of sodium feldspar crystal.
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Figure 6. Cast thin sections of dissolution in study area. (a) Well YB4, 3913.77 m, Lower Wuerhe formation, intragranular dissolved pore; (b) Well YB4, 3915.31 m, Lower Wuerhe formation, intragranular dissolved pore; (c) Well YT1, 4538.73 m, Baikouquan formation, mold pore; (d) Well YT1, 4538.05 m, Baikouquan formation, mold pore; (e) Well YT1, 4533.83 m, mold pore; (f) Well YB4, 3692.21 m, Baikouquan formation, remaining intergranular pores; (g) Well YB4, 3693.04 m, remaining intragranular pores; (h) Well YB1, 4070.9 m, Lower Wuerhe formation, laumontite-dissolved pore; (i) well YB4, 3869.37 m, Lower Wuerhe formation, laumontite-dissolved pore.
Figure 6. Cast thin sections of dissolution in study area. (a) Well YB4, 3913.77 m, Lower Wuerhe formation, intragranular dissolved pore; (b) Well YB4, 3915.31 m, Lower Wuerhe formation, intragranular dissolved pore; (c) Well YT1, 4538.73 m, Baikouquan formation, mold pore; (d) Well YT1, 4538.05 m, Baikouquan formation, mold pore; (e) Well YT1, 4533.83 m, mold pore; (f) Well YB4, 3692.21 m, Baikouquan formation, remaining intergranular pores; (g) Well YB4, 3693.04 m, remaining intragranular pores; (h) Well YB1, 4070.9 m, Lower Wuerhe formation, laumontite-dissolved pore; (i) well YB4, 3869.37 m, Lower Wuerhe formation, laumontite-dissolved pore.
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Figure 7. Microscopic photos of multi-stage hydrocarbon inclusions in reservoir.
Figure 7. Microscopic photos of multi-stage hydrocarbon inclusions in reservoir.
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Figure 8. Microscopic photos of different fluorescent hydrocarbon inclusions in reservoir. (a) Well YB4, 3871 m, distributed along the micro-crack of analcime cement, showing blue, yellow, yellow-green or blue-green fluorescent hydrocarbon inclusions; (b) well M19, 3526.7 m, distributed in belts along microcracks after diagenesis of quartz grains, showing yellow-light blue fluorescent hydrocarbon inclusions; (c) well DT1, 5695.4 m, distributed along feldspar dissolved pores, showing blue fluorescent hydrocarbon inclusions; (d) well D13, 4207.5 m, distributed in belts along the micro-fractures after the diagenesis of quartz grains, showing light yellow fluorescent hydrocarbon inclusions; (e) well D15, 4249 m, distributed in belts along micro-fractures after diagenesis of quartz grains, showing yellow, blue or yellow-green fluorescent hydrocarbon inclusions; (f) well M19, 3534.1 m, distributed in belts along micro-fractures after diagenesis of quartz grains, showing yellow fluorescent hydrocarbon inclusions.
Figure 8. Microscopic photos of different fluorescent hydrocarbon inclusions in reservoir. (a) Well YB4, 3871 m, distributed along the micro-crack of analcime cement, showing blue, yellow, yellow-green or blue-green fluorescent hydrocarbon inclusions; (b) well M19, 3526.7 m, distributed in belts along microcracks after diagenesis of quartz grains, showing yellow-light blue fluorescent hydrocarbon inclusions; (c) well DT1, 5695.4 m, distributed along feldspar dissolved pores, showing blue fluorescent hydrocarbon inclusions; (d) well D13, 4207.5 m, distributed in belts along the micro-fractures after the diagenesis of quartz grains, showing light yellow fluorescent hydrocarbon inclusions; (e) well D15, 4249 m, distributed in belts along micro-fractures after diagenesis of quartz grains, showing yellow, blue or yellow-green fluorescent hydrocarbon inclusions; (f) well M19, 3534.1 m, distributed in belts along micro-fractures after diagenesis of quartz grains, showing yellow fluorescent hydrocarbon inclusions.
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Figure 9. Homogeneous temperature histogram of brine inclusion.
Figure 9. Homogeneous temperature histogram of brine inclusion.
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Figure 10. Burial history of well DT1.
Figure 10. Burial history of well DT1.
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Figure 11. Fluorescence photos of hydrocarbon inclusions coexisting with different maturity. (a) Well M19, 3534.1 m, distributed along the microcracks of quartz grain, showing yellow or blue-green fluorescence; (b) well M217, 4010.02 m, distributed along micro-fractures of analcime cement, showing blue-green or yellow-green fluorescence; (c) well M217, 4010.02 m, distributed in belts along micro-fractures of quartz grain, showing blue-green fluorescence; (d) well YB4, 3871 m, distributed in belts along the micro-fractures of quartz particles, showing yellow-green or bluish-green fluorescence; (e) well YB4, 3914 m, distributed in belts along micro-fractures of quartz particles, showing yellow or yellow-green fluorescence; (f) well D15, 4249 m, distributed in belts along micro-fractures of quartz particles, showing yellow, blue or yellow-green fluorescence.
Figure 11. Fluorescence photos of hydrocarbon inclusions coexisting with different maturity. (a) Well M19, 3534.1 m, distributed along the microcracks of quartz grain, showing yellow or blue-green fluorescence; (b) well M217, 4010.02 m, distributed along micro-fractures of analcime cement, showing blue-green or yellow-green fluorescence; (c) well M217, 4010.02 m, distributed in belts along micro-fractures of quartz grain, showing blue-green fluorescence; (d) well YB4, 3871 m, distributed in belts along the micro-fractures of quartz particles, showing yellow-green or bluish-green fluorescence; (e) well YB4, 3914 m, distributed in belts along micro-fractures of quartz particles, showing yellow or yellow-green fluorescence; (f) well D15, 4249 m, distributed in belts along micro-fractures of quartz particles, showing yellow, blue or yellow-green fluorescence.
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Figure 12. Relationship between diagenesis and hydrocarbon charging.
Figure 12. Relationship between diagenesis and hydrocarbon charging.
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Jiang, W.; Song, P.; Liu, H.; Bian, B.; Wang, X.; Guo, W.; Wang, N. Coupling Relationship between Diagenesis and Hydrocarbon Charging in Middle Permian–Lower Triassic in the Eastern Slope of Mahu Sag in Junggar Basin, Northwest China. Processes 2023, 11, 345. https://doi.org/10.3390/pr11020345

AMA Style

Jiang W, Song P, Liu H, Bian B, Wang X, Guo W, Wang N. Coupling Relationship between Diagenesis and Hydrocarbon Charging in Middle Permian–Lower Triassic in the Eastern Slope of Mahu Sag in Junggar Basin, Northwest China. Processes. 2023; 11(2):345. https://doi.org/10.3390/pr11020345

Chicago/Turabian Style

Jiang, Wenlong, Ping Song, Hailei Liu, Baoli Bian, Xueyong Wang, Wenjian Guo, and Nan Wang. 2023. "Coupling Relationship between Diagenesis and Hydrocarbon Charging in Middle Permian–Lower Triassic in the Eastern Slope of Mahu Sag in Junggar Basin, Northwest China" Processes 11, no. 2: 345. https://doi.org/10.3390/pr11020345

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