Impact of Differential Densification on the Pore Structure of Tight Gas Sandstone: Evidence from the Permian Shihezi and Shanxi Formations, Eastern Sulige Gas Field, Ordos Basin, China

Wang, Meng; Tang, Hongming; Tang, Haoxuan; Liu, Shu; Zhang, Liehui; Zeng, Ming; Cheng, Yulin

doi:https://doi.org/10.1155/2019/4754601

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Research Article | Open Access

Volume 2019 | Article ID 4754601 | https://doi.org/10.1155/2019/4754601

Impact of Differential Densification on the Pore Structure of Tight Gas Sandstone: Evidence from the Permian Shihezi and Shanxi Formations, Eastern Sulige Gas Field, Ordos Basin, China

Meng Wang,¹Hongming Tang,¹Haoxuan Tang,¹Shu Liu,²Liehui Zhang,¹Ming Zeng,³and Yulin Cheng¹

Academic Editor: Jaewon Jang

Received10 Oct 2018

Accepted09 Jan 2019

Published21 Mar 2019

Abstract

The tight sandstone reservoirs of the Permian Shihezi and Shanxi Formation with strong heterogeneity constitute the main producing zone of the eastern Sulige gas field. The process of differential densification results in various reservoir qualities. Mineral composition, structural characteristic, pore system, and diagenesis were investigated with analyses of well logs, thin sections, porosity, and horizontal permeability of the core plugs; environmental scanning electron microscopy (ESEM); nuclear magnetic resonance (NMR); X-ray computed tomography (X-CT); and fluid inclusion homogenization temperature. The results show that lithic sandstone reservoirs experienced complex and various diagenetic evolutions. Eight types of densification modes can be divided according to the diagenesis paths; these modes represent lithofacies with different densification times and reservoir qualities. Intense mechanical compaction is the main reason for the formation of lithofacies 1, 2, and 5. Lithofacies 4, 6, and 7 formed due to intense cementation, increasing the impermeability of the diagenetic system. The primary pore space in lithofacies 3 is preserved due to the overpressure and chlorite coatings. The dissolution and weak cementation of lithofacies 8 contribute to reservoir development. The middle-lower part of braided channel lags and channel bars, the middle part of meandering riverbed lags, and the middle part of point bars are favourable for reservoir development.

1. Introduction

Since the mid-19th century, scholars have carried out numerous studies on diagenesis, diagenetic facies, and diagenetic reservoir facies as well as the diagenetic evolution sequence problem and other problems related to the densification mechanism of sandstone reservoirs [1–3]. Diagenetic evolution is an extremely complex physicochemical process that is the result of a long period of fluid-rock interaction [4–6]. The processes of continuous, dynamic, and superimposed diagenesis in reservoirs are influenced by various factors and complex evolution processes [7–9]. Typical diagenetic sequences were extensively studied. Zhang et al. [10] proposed the classification of continuous burial diagenetic sequences and intermittent burial diagenetic sequences [10]. Gu et al. [11] suggested that there were three evolution pathways: predominant compaction and quartz overgrowth, predominantly chlorite coatings, and predominantly early calcite cementation.

Recently, some problems in the previous studies have gradually been noted: (1) different sedimentary systems, lithology, mineral compositions, and structures may lead to different sandstone diagenetic evolution sequences [12–15], and (2) the formation of authigenic minerals will take time, and therefore, different diagenetic processes will inevitably overlap during diagenetic evolution [16]. However, most researches tend to neglect these objective facts and use a typical sequence that contains all diagenetic processes as the basis for the diagenetic evolution of a single layer or whole series [7, 9, 17, 18]. Clearly, these approaches completely contradict what is observed in nature and thus cannot accurately reflect the reservoir densification process.

After understanding the different diagenetic processes, we aim to (1) clarify the compositions and structural characteristics of the eighth member of Shihezi formation (He 8) and the first (Shan 1) and second (Shan 2) members of Shanxi Formation sandstone reservoirs and classify their lithofacies; (2) evaluate the pore system, pore structure, and reservoir quality of each lithofacies; (3) illustrate the paragenetic sequence of diagenetic alteration for Permian formations; (4) based on the typical diagenetic evolution, reconstruct the diagenetic evolution pathways for various lithofacies; and (5) consider the sandstones and mudstone as one diagenetic system to analyse the formation mechanism of differential densification mode. The results are of great significance to study the genetic mechanism of the strong heterogeneity of tight sandstone reservoirs in Ordos Basin and other similar tight sandstone gas reservoirs.

2. Geological Background

2.1. Location of the Study Area

The Ordos Basin is the second largest sedimentary basin in China, with Paleozoic strata covering an area of more than 250,000 km². Regionally, it can be subdivided into six structural units, including the Yimeng uplift, Weibei uplift, Jinxi fault-fold belt, Yishan slope, Tianhuan depression, and Western margin fault belt. The structural framework of the basin is a large asymmetric syncline with a gentle dip angle of 0.5-1.0° towards the northeast and a slightly steeper dip angle of 2-3° towards the southwest [19]. The eastern Sulige gas field stretches from the Ordos district in the Inner Mongolia Autonomous Region to the Yulin district of Shaanxi Province, crossing the northern part of the Yishan slope and the southern part of the Yimeng uplift in the Ordos Basin, with a natural gas exploration area of 11,000 km² (Figures 1(a) and 1(b)).

(a)

(b)

2.2. Stratigraphy and Deposition

The upper Paleozoic strata of the Sulige gas field in the Ordos Basin are composed of transitional and continental clastic sediments. The sedimentary facies of the Sulige gas field has been controversial for a long time [20]. Li et al. [21] proposed that the depositional environment of the He 8 member and Shanxi Formation in the study area was a gently sloping braided river and low-curvature meandering river that transits into a deltaic system to the south. The reservoirs are composed of the channel bar sandbodies from areas of high-energy water and superimposed point bars (Figure 2 modified after [22]).

The average depth of the gas reservoir in the study area, from He 8 to Shan 2, is approximately 2750-3230 m, the geothermal gradient is 3.03°C/100 m, and the formation pressure is 24.188-27.804 MPa. The mean lithostatic pressure coefficient is 0.86. The He 8 member belongs to a meandering river and braided river depositional environment [19] (Figure 3) and has a thickness of 45~60 m, while the Shan 1 and Shan 2 members belong to a meandering river depositional environment and have thicknesses of 40-50 m and 45~60 m, respectively.

Four stages of stratigraphic uplift and denudation occurred since the Mesozoic; the movement during the Cretaceous was the most intensive, resulting in the erosion of 800-1200 m in the Sulige area [23]. The mudstone of the Shixianzi Formation remains uncompacted. In the middle-late Yanshanian, a tectono-thermal event occurred; as a result, the geothermal gradient of the Sulige area ranged between 3.6 and 4.0°C/100 m. However, at the end of the Early Cretaceous, the tectono-thermal event ended; as a result, the geothermal gradient decreased to 2.8~3.0°C/100 m. Since the Late Cretaceous, stratigraphic uplift and denudation has further reduced the formation temperature; as a result, the average formation temperature of the He 8 to Shan 2 members decreased by approximately 50°C from the late Early Cretaceous to the present (Figure 4).

2.3. Petroleum Systems

The Sulige gas field in the Ordos Basin is a large-scale lithic sandstone gas reservoir developed in upper Paleozoic clastic rocks, with complicated geological conditions, low porosity, low permeability, low gas reservoir pressure, and low abundance of organic matter [24]. Here, the Permian strata are an important oil-bearing gas system. The fourth and eighth members of the Shihezi formation (He 4 and He 8) and the first and second members of the Shanxi Formation (Shan 1 and Shan 2) are the main producing zones. The source rocks are the coal and mudstone of the Upper Carboniferous Benxi Formation and lower Permian Taiyuan and Shanxi formations.

3. Materials and Methods

During the study, a total of 350 core plugs and cutting samples were obtained from the sandstone reservoirs of the He 8, Shan 1, and Shan 2 members from 30 typical representative wells. Among the samples, 212 samples from Well SD 24-55 were continuously selected from the He 4 to Shan 2 members.

The porosity and permeability tests were performed on 350 core plug samples under the net pressure of 5 MPa. Using a low gas permeability measurement instrument (700, made by Sanchez Technologies), N₂ gas was used to determine the permeability. All these samples were matched with thin sections.

According to the porosity and permeability test results, three typical reservoir samples with developed lithofacies were chosen to scan and create CT images. X-ray micro-CT scanning was conducted using a MicroXCT-400 instrument at a spatial resolution of 2 μm and a source voltage of 89 kV. The 3-6 mm diameter samples allowed a high resolution to be achieved and the pore space, which contained pore throats of only a few micrometres in size, to be imaged adequately. The resultant binary images were then analysed by FEI PerGeos software to reconstruct the 3D pore structure. Mobile fluid and pore structure analyses were also performed using a MacroMR12-150H-I nuclear magnetic resonance instrument made by Niumag. Before the tests, the cores were put in a vacuum and saturated with pure water for 48 h, in order to test the spectrum of the cores at a saturated water state and at a high-speed centrifugation (2.07 MPa) state. The centrifugation speed was the optimum centrifugation speed selected during multiple tests. The test temperature was 25°C, receiver delay (RD) was 500 ms, echo time (TE) was 3.5 ms, and number of echoes was 400.

A total of 350 polished thin sections were prepared by vacuum impregnation with blue or red epoxy resin for analysing the rock mineralogy, diagenetic features, visual pore characteristics, and cements. Half of the thin sections were stained with Alizarin Red S and K-ferricyanide for carbonate cement identification. The compositional percentages of each sample were calculated based on a 300-point count modal analysis. The thin sections were analysed using a Nikon LV100POL polarized optical microscope. The environmental scanning electron microscopy (ESEM) analyses were performed on 65 pieces of gold-coated rock chips glued on stubs in order to closely observe the mineral and micropore structure characteristics. An FEI Quanta 450 ESEM was used for the analyses. The <2 μm clay fraction was separated using settling tubes and analysed by XRD to identify the main clays present in each lithofacies with clay cements. Three kinds of air-dried clay fraction samples treated with ethylene glycol at a temperature of 60°C for 12 h and heated at a temperature of 500°C for 2 h were tested. The PANalytical X’Pert PRO X-ray diffractometer was operated at 40 kV and 40 mA using Cu Kα radiation, a scan angle of 4°-30°, a step size of 0.01313°, and a scan speed of 0.164°/s.

All the samples were tested using industry-standard methods. The test equipment was provided by the State Key Laboratory of Oil and Gas Reservoir Geology and Exploration of the Southwest Petroleum University.

4. Results

4.1. Lithofacies and Features

According to the quantitative analyses of nearly 350 sandstone thin sections obtained from 30 coring wells, the lithologies of the He 4, He 8, Shan 1, and Shan 2 members are dominated by lithic sandstone, followed by feldspar lithic sandstone. The mineral components in each sandstone interval are generally similar in content. Clastic constituents are dominated by quartz (45-55%), followed by rock fragments (20-30%) and feldspar (8-15%). The rock fragments include rigid rock fragments, such as sandstone and granite rock fragments, and plastic rock fragments, such as mudstone, siltstone, slate, schist, and phyllite rock fragments. The interstitial materials consist of matrix and cements. The cements are dominated by silica, calcareous material, and clays, and the cement accounts for 1%~34% of the rock, with an average of 13.86%. The XRD tests show that the clay minerals are dominated by kaolinite and chlorite, which mainly appears in shallow sandstone (Figure 5(a)); additionally, an increase in the burial depth of the sandstone increases the content of illite (Figure 5(b)).

(a)

(b)

Based on the classification of rock types in the study area, several lithofacies can be divided according to detrital composition, cement content, and pore development [13] (Table 1).

Taking Well SD24-55 with a completed borehole and continuous coring as an example, 12 samples were divided into 3 categories and 8 types (Figure 6). The first type is an intensely compacted tight lithofacies, which is classified as plastically deforming rock fragment-rich type (lithofacies 1, Figure 7(a)) and rigidly deforming rock fragment-rich type (lithofacies 2, Figure 7(b)); according to the cutting types, they are enriched. Both of these lithofacies have an extremely low porosity and low cement content. The second type is an intensely cemented tight lithofacies. According to the type and content of the cements, the second type can be divided into quartz overgrowth (lithofacies 4, Figure 7(d)), intensively cemented calcite crystal stock (lithofacies 5, Figure 7(e)), intensively cemented authigenic quartz (lithofacies 6, Figure 7(f)), and intensively cemented ferrocalcite (lithofacies 7, Figure 7(g)). The third type is a pore-developed lithofacies. According to the origin of the pores, the third type can be divided into the primary pores formed due to the cementation of chlorite coatings (lithofacies 3, Figure 7(c)) and the secondary pores formed due to effective dissolution (lithofacies 8, Figure 7(h)).

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

Figure 7

Photomicrographs showing typical minerals and pores of representative samples for each lithologic mode. (a) High content of plastically deformed cuttings, which fill in particles after compaction, SD24-55, 2948.97 m. (b) Sandstone rich in rigidly deformed cuttings, and quartz overgrowth and calcite cements can be occasionally seen, SD24-55, 2980.43 m. (c) Tightly cemented calcite and well-preserved intergranular pores, part of the quartz developed overgrowth, SD24-55 and 2798.74 m. (d) High quartz content with common quartz overgrowth and minor calcite cements, SD24-55, 3014.56 m. (e) Calcite crystal stock cementation, Z7, 3025.31 m. (f) Chlorite rim can be seen. Authigenic quartz is generally developed in intergranular pores, with minor dissolved pores, SD24-55, 2974.32 m. (g) Low matrix content. Quartz developed overgrowth. Ferrocalcite was tightly cemented during the late stage of diagenesis, Z7, 2914.82 m. (h) Chlorite is weakly cemented, and dissolution occurred. Intergranular pores and kaolinite intercrystalline pores formed due to feldspar dissolution, Z10, 3108.926 m (Q = quartz; F = feldspar; Cln = chalcedony; Qa = authigenic quartz; Qo = quartz overgrowth; M = matrix; Ca = carbonate cementation; Cln = chalcedony; K = kaolinite; Ms = muscovite; Mqs = mica quartz schist rock debris; Sp = sericite phyllite rock debris; Ph = phyllite rock debris; Slt = siltstone rock debris; Qte = quartzite rock debris; Mqr = mica quartzite rock debris; φ = pore).

4.2. Reservoir Quality within Various Lithofacies

The physical property results of 212 samples show that the porosity is 0.08%-11.68% with an average of 3.71%. Three lithofacies types have a notably better reservoir quality than the other types. Lithofacies 3 has the highest porosity, 8.06~11.68%, with an average of 9.95%, followed by lithofacies 8, with porosity ranging from 4.7 to 8.7%, with an average of 7.1%. Some samples in lithofacies 2 also have high porosity, ranging from 1.28 to 6.35%, with an average of 4.15%. The average porosity of the sandstone of other lithofacies is less than 5%; in particular, for lithofacies 5 and 6, the average porosity of the sandstone is less than 2% (Figure 7).

The permeability is 0.004-1.929 mD, with an average of 0.071 mD, which is ultralow (). In lithofacies 8, dissolution and alteration increased the porosity and contributed to the connection of the pores, improving the permeability of the sandstone. It should be noted that although lithofacies 3 has a higher porosity, the pore throat radii are reduced to a certain extent due to the presence of chlorite coatings. Some pore throats are blocked, resulting in low permeability (Figure 8).

The lower limit of reservoir porosity is %, and the lower limit of reservoir permeability is mD [25]. According to the porosity-permeability test results of the sandstone samples (Figure 8), the sandstones of lithofacies 2, 3, and 8 are effective reservoirs. The results of the well logging, oil testing, and physical property testing show that the sandstone of lithofacies 2 is mainly medium-coarse sandstone deposited as channel bars, channel lags in a braided channel, and point bars in a meandering river. The sandstone of lithofacies 3 is mainly medium-coarse sandstone deposited as channel lags and channel bars in a braided river. The sandstone of lithofacies 8 is mainly medium-coarse sandstone deposited as channel bars in braided river facies, channel lags, and point bars in a meandering river (Figure 9).

NMR measurements of relaxation time are widely used to characterize the pore structure and pore fluids in rocks quickly and nondestructively [26, 27]. In particular, for analysing free fluid index (FFI) and immovable water (BVI), NMR measurements are the most effective [12].

The NMR results of the vacuum water-saturated cores (Table 2, Figure 10(a)) show that the spectra of the three types of lithofacies show a bimodal distribution, indicating two types of pores. The signal amplitudes of the main peak and the second peak are significantly different. As part of the porosity component, the maximum relaxation time of the spectral peak is generally 0.4~3 ms, indicating that small pores are widespread and highly concentrated in lithofacies 2, 3, and 8.

(a)

(b)

The NMR results of the cores in saturated water after centrifugation (Table 2, Figure 10(b)) show that the signal with a relaxation time of 10-100 ms basically disappears, indicating that most of the fluids in the large pores are removed, and the residual weak signal comes from the water film on the pore surface [15]. However, the signal amplitude of the spectral peak representing the small pores also decreases and the relaxation time of spectral peak shortens, indicating that while some fluids in the small pores flow under a certain centrifugal force, most of the water is irreducible water.

It is generally considered that the is the boundary between movable fluid and irreducible fluid; additionally, on the distribution spectra, the fluid represented by values smaller than this value is irreducible fluid, while the fluid represented by values larger than this value is movable fluid [28]. has the closest correlation with BVI [29]. The experimental results show that the more complicated the diagenetic model is, especially when more types of cementation are included, the more complicated the pore structure of sandstone. The higher and values are, the stronger the binding ability of the sandstone and fluid. Because the pore structure of lithofacies 2 was mainly destroyed by mechanical compaction, the influence of cementation is weak, and the seepage ability of that reservoir is relatively poor. The values before and after centrifugation are 1.065 ms and 0.64 ms (Table 2), respectively, which indicates that the fluid is significantly bound to the sandstone reservoirs. Lithofacies 3 and 8 have good connectivity due to the development of pores. is relatively low, and the irreducible water saturation is less than 50% (Table 2). Notably, for lithofacies 3, although the permeability is reduced due to chlorite cementation, the fluids within the sandstone still maintain a high mobility (Table 2).

4.3. Pore and Pore-Throat System

Pores are well developed in the sandstone of lithofacies 3 and lithofacies 8. For lithofacies 3, the pores are mainly primary pores and primary-secondary pore combinations, and the throats have mainly a curved lamellar structure (Figure 7(c)). For lithofacies 8, the pores are mainly secondary pores, with minor primary intergranular pores modified by dissolution, and the throats are lamellar and curved lamellar (Figure 7(h)). For the other lithofacies, the pores are poorly connected due to the sporadic development of secondary or primary pores, and the throats are lamellar. The kaolinite intercrystalline pores formed due to feldspar dissolution are observed in various lithofacies. The dissolution strength determined whether the pores can form effective connections.

4.4. Pore-Throat Structure Characteristics

X-ray computed tomography (CT) is a nondestructive technique, and 3D image reconstructed based on digital rock imaging enables us to directly analyse the pore structure, tortuosity, and connectivity visually [30].

The CT scanning results of the three typical reservoir samples show that the pores of the lithofacies are dominated by micropores. The most developed pores are observed in lithofacies 3, which has an effective porosity of 40.5% and a coordination number of 3.66. Lithofacies 3 has the most favourable pore-throat structure of the three lithofacies, with the highest average pore and throat radii (Table 3). The micropores of lithofacies 2 are effectively connected due to the development of microfractures and has an effective porosity of 30.2% and average pore-throat coordinate number of 4.17 (Table 3). Compared to lithofacies 2 and 3, lithofacies 8 underwent more complicated diagenetic modifications, and its pore structure was comprehensively modified by compaction, cementation, and dissolution. Although its porosity is high, the pores are dominated by micropores with poor connectivity. The average pore throat coordination number is 0.8, and the effective porosity is only 16.81% (Table 3).

As shown in Figure 11, the micropores in lithofacies 2 are well developed and are effectively connected by microfractures (Figure 11(C-1)). The pores in lithofacies 3 are also well developed and are effectively connected by pore throats. The pores of lithofacies 8 are dominated by micropores (Figure 11(C-2)). Compared to lithofacies 2, the pores of lithofacies 8 are better developed but have poorer connectivity (Figure 11(C-3)), with an average pore throat coordination number of only 0.8. It can be concluded that the preservation of primary pores and the modification of microfractures during a late stage are crucial to the connection of reservoir pores.

Figure 11

(A-1, B-1, and C-1) Greyscale image, (A-2, B-2, and C-2) dissolved pore space, and (A-3, B-3, and C-3) pore-throat connectivity structure (balls are pores, bars are throats) volumes of the tight sandstone samples. (a) Lithofacies 2, SD24-55, 2982.91 m. (b) Lithofacies 3, SD24-55, 2799.78 m (c) Lithofacies 8, 2953.89 m (to highlight the pore connectivity, the dissolved pore space and pore-throat connectivity structure of samples A and B are the 3D structure of the interconnected pores. However, the pore diameter, volume, and pore-throat connectivity of mode 8, namely, sample C are low, while C-2 and C-3 demonstrate the characteristics of all the pores and throats).

The pore-throat structure of the samples from lithofacies 3 is superior to that of the other two lithofacies, but in a vertical profile, lithofacies 3 develops in local intervals only. Lithofacies 8 is the main lithofacies for reservoir development due to its high-frequency occurrence in a vertical profile and good sandstone reservoir properties. Lithofacies 2 has the worst physical properties of the three lithofacies. However, due to the development of micropores and fractures, this sandstone also has the potential to become a good reservoir (Figure 9). The three lithofacies have significantly different reservoir properties, but all represent low permeability and ultralow permeability characteristics. The reservoir seepage capacity should be enhanced by modification during late-stage development.

5. Discussion

5.1. Diagenesis Types and Diagenetic Evolution

There are some similarities in the diagenetic evolution characteristics of sandstone: before the compaction strength peak is reached, a phase of weak carbonate cementation caused by the dissolution of reworked calcrete or dolocrete develops locally [31]; then, chlorite coatings form in local intervals, contributing to the preservation of primary intergranular pores. The quartz grains without chlorite coatings develop large quartz overgrowth. Authigenic quartz and carbonate cements are common in intergranular pores after chlorite is cemented, indicating that chlorite coatings hinder the development of quartz overgrowth to some extent [17, 32, 33], but it cannot hinder the precipitation of silica and carbonate cements in the pore spaces. The authigenic quartz, calcite, and kaolinite discovered in secondary dissolved pores indicate that the dissolution of feldspar and rock debris provides a material source for cementation while forming secondary pores [2, 34, 35]. Flaky, silk-like illite generally concomitantly appears with kaolinite. Generally, kaolinite will undergo illitization due to the loss of stability at temperatures above 130°C [1, 2]. The continuous inclusion temperature measurements confirm the possibility of this reaction (Figure 12).

The homogenization temperature of the inclusions in the quartz overgrowth, authigenic quartz and calcite cements ranges between 80 and 180°C, showing two peak intervals (Figure 12, [15, 36]). A continuous homogenization temperature indicates that the gas-reservoir-forming process of the He 8 to Shan 2 members is continuous, and a bimodal distribution reflects that there are two phases of gas charging in the study area. Dissolution occurs in the acid-drained phases of thermal evolution before hydrocarbon charging. Therefore, sandstone reservoir experiences at least two phases of dissolution (Figure 13).

5.2. Features of Differential Sandstone Densification Lithofacies

Diagenetic sequences can characterize the evolution of sandstone diagenesis and porosity to a certain extent, but have limitations in characterizing the genesis of different sand bodies and sandstone types. After understanding the limitations of conventional diagenetic evolution models, Luo et al. [37] established the diagenetic evolution sequences for different lithofacies, which were of great significance. However, the diversity of the diagenetic evolution pathways of the same lithology was still ignored. The actual study shows that the differences in the pore structures of eight kinds of lithic sandstone components actually reflect that each kind of sandstone has undergone a different diagenetic evolution sequence. The diagenetic evolution of each type is not isolated. In contrast, it is inherited and superimposed (Table 4, Figure 14).

Lithofacies 1 represents the intense compaction and densification of the sandstone rich in plastically deforming debris. When compaction is the most intense, the rock debris undergoes intense plastic deformation and expands due to water absorption. The pseudo-matrix hinders pores and throats [15]. Intense compaction leads to the significant loss of primary pores and severe damage of the pore-throat structure (Figures 7(a) and 14(1)). Sandstone enters densification phase at early stage and undergoes a weak late-stage modification.

Lithofacies 2 represents the intense compaction and densification of the sandstones rich in rigidly deforming debris. The resistance to compaction increases with the increase in the amount of rigid debris. Weak quartz overgrowth is developed during an early diagenetic stage. The particles are generally in contact under strong compaction, and the pores nearly enter the densification stage (Figures 7(b) and 14(2)). Due to the destruction of pore space by strong compaction, fluid activity space is limited and the late-stage cementation is generally weak.

Lithofacies 3 represents intense chlorite cementation and pore preservation. The development of chlorite coatings blocks the pore throat, reduces the permeability, and encloses the fluids in interior pores (Figures 7(c) and 14(3)). It is generally considered that the synergetic effect of chlorite cementation and abnormally high pore pressure preserves the primary intergranular pores. In addition, the development of chlorite coatings hinders the development of quartz overgrowth. When the chlorite coatings become thick, fluid migration becomes more restricted and cementation weakens.

Lithofacies 4 represents the intense cementation and densification of quartz overgrowth and weak cementation of chlorite. The pores and throats are not completely closed, so the fluid activity space is sufficient. The organic acids formed by the thermal evolution of organic matter promote the dissolution of soluble components. Dissolution provides a material source for cementation when pores are formed. When silica is enriched in fluids, the continuously formed quartz overgrowth will lead to the continuous reduction of pores. One or two phases of quartz overgrowth are developed, with a thickness of 0.02~0.08 mm. Tightly quartz overgrowth cementation led to the reservoir entering the densification stage (Figures 7(d) and 14(4)).

Lithofacies 5 represents the intense cementation and densification of the calcite crystal stock. After early-stage cementation and compaction, including siliceous cementation, the sandstone is not densified. When the fluid in the pores is enriched in calcareous material, calcite cements will form as a form of crystal stock under certain conditions. As a result, the pores will be mostly or even completely blocked. The reservoir properties of sandstone will be destroyed due to strong densification (Figures 7(e) and 14(5)).

Lithofacies 6 represents the intense cementation and densification of intergranular authigenic quartz. The weak development of chlorite coatings hinders the formation of quartz overgrowth at the late stage of diagenesis, but the pore throats are not destroyed. With pore fluids in low-calcium conditions, most intergranular pores are still well preserved until the middle and late stages of the mesodiagenesis phase. However, after the weak dissolution of phase 2, intergranular authigenic quartz is formed under the condition that the siliceous materials are enriched in pore fluids. The extensive development of intergranular authigenic quartz results in sandstone entering the densification stage (Figures 7(f) and 14(6)).

Lithofacies 7 represents the intense cementation and densification of ferrocalcite. The sandstone of this lithofacies has experienced the most complicated evolution. The early-stage compaction and cementation did not lead to the complete densification of the reservoirs. Intergranular pores and dissolved pores are filled due to the intense cementation of ferrocalcite during a late stage of diagenesis. The sandstone eventually enters the densification stage (Figures 7(g) and 14(7)).

Lithofacies 8 represents chlorite cementation, dissolution, and weak cementation; unlike in lithofacies 3, the formation of chlorite preserves the primary intergranular pores (Figures 7(h) and 14(8)). However, since the permeability is not destroyed, the fluid seepage capacity is maintained to some extent. Pore sizes are increased due to dissolution but decreased due to weak cementation. Although pores are destroyed, good reservoir and seepage capabilities are preserved.

It is of great significance to clarify the differences in reservoir development in the longitudinal direction for the eight types of lithic sandstone based on the path and direction of the diagenetic evolution.

5.3. Formation Mechanism of Differential Densification Lithofacies

Diagenesis occurs in fluid-rock diagenetic systems. The above eight differential densification lithofacies are formed because diagenesis can be either destructive or constructive in order to maintain the dynamic balance of the pressure, temperature, and fluid properties in the system. Therefore, there are differences between the eight types of lithofacies. Because sandstone diagenesis is not a simple reaction between sandstone and fluid and is closely related with mudstone, the mudstone in contact with the sandstone must be considered part of the diagenetic system. The genetic mechanism of densification lithofacies was revealed through the study of each microsystem.

5.3.1. Intense Mechanical Compaction Is the Main Reason for the Formation of Lithofacies 1, 2, and 5

Compaction is the first diagenetic process that affects sediments after deposition and has two effects. On the one hand, it directly results in the densification of sandstone. The average burial depth of the top of the He 8 member is 2690~3260 m. The compaction strength was evaluated based on the porosity loss ratio. The compaction of sandstone resulted in porosity reducing by 17.5~23.5%, with an average loss rate of 41-61%, which indicates moderate-intense compaction, whereas for the samples of lithofacies 1 and 2, the porosity loss rate is higher than 80%. Lithofacies 1 occurs in the margin of thin and thick sandbodies in contact with mudstone. The sandstone of lithofacies 2 is richer in rigidly deforming rock fragments compared to that of lithofacies 1. The sandstone components and development position lead to these two types of sandstone having a poor resistance capacity to strong stress. When the burial depth reaches approximately 2 km and the destruction degree of the mechanical compaction stress is maximized [1, 38, 39], these two types of sandstone enter the densification stage (Figure 15(1,2)).

On the other hand, compaction provides a material source for cementation and promotes the formation of carbonate cements. Comparing the lithology and diagenesis types of coring wells, lithofacies 5 mainly develops in the sandstone close to the junction of the mudstone and sandstone. This phenomenon has been defined as a calcified zone or calcified margin, “top calcium” or “bottom calcium,” or the calcareous thin skin and crust on a sandbody surface Wang and Zhou [40]. In the early period of burial, sandstone is poorly compacted due to mudstone compaction and porewater support, so it easily comes into contact with fluids due to good initial porosity and permeability conditions. Due to the weak ability of mudstone to resist compaction, the pore fluid pressure of mudstone increases with continuous compaction. To maintain system balance, the pore fluid in the mudstone will flow from the mudstone high-pressure zone to the sandstone [41]. Under the catalysis of various types of acidic water, a large amount of Ca²⁺ is precipitated during syngenesis, supergenesis, and deeply buried genesis; as a result, Ca²⁺ ions are rich in original pore fluids. There are various types of cations in the formation water of the Shihezi Formation in the eastern Sulige gas field; these cations include K⁺, Na⁺, Ca²⁺, and Mg²⁺ [42], among which Na²⁺ and Ca²⁺ are the most common. Under constant compaction, the partial pressure of CO₂ suddenly drops, and the chemical properties of the fluids are changed due to periodically released pressure in the mudstone overpressure system close to the normal pressure system, so the Ca²⁺, Mg²⁺, Fe²⁺, CO₃^2-, and other ions are precipitated, forming carbonate cements [43]. Compaction and the contacts between sandstone and mudstone provide adequate cementing space and cement material for lithofacies 5, so calcite cement generally formed along the sandstone-mudstone contact boundary (Figure 15(5)).

The three types of sandstone dominated by compaction play an important role in the formation of sandstone-enclosed diagenetic systems in the longitudinal direction since they mostly occur at lithologic contact boundaries and form seepage barriers between sandstone and mudstone. It should be noted that these three types of sandstone have different thicknesses since the sandstone and adjacent mudstone have different thicknesses. The stronger the compaction is, the thicker the mudstone bed, the more abundant the ions, and the wider the longitudinal distribution range of the three lithofacies.

5.3.2. Early-Stage Overpressure with the Formation of Chlorite Coatings Preserves Primary Pores (Lithofacies 3)

Extensive research results have shown that surface overpressure and chlorite are of constructive significance for the development of reservoir pores. Osborne and Swarbrick [44] concluded that disequilibrium compaction, tectonic compression, aquathermal expansion, volume expansion due to clay diagenesis, mineral transformations, kerogen maturation, gas generation, and buoyancy effects occurring in reservoirs can lead to fluid overpressures. After fluid overpressure is formed, thick mudstone can adequately seal sandstone pore fluids and form a series of vertical pressure compartments with independent fluid pressures accompanied with compaction and clay mineral conversion at a late stage of diagenesis. These compartments are not connected with the upper hydrodynamic system [45]. The pore fluids in closed overpressure systems support part of the load of the overlying strata and reduce the vertical effective stress and the pressure supported by framework particles and cements. Thereby, pore overpressure can slow or arrest mechanical compaction [31, 43, 46–50]. In addition, fluid overpressure was suggested to limit or prevent quartz cementation [31, 51, 52]. The high porosity is considered to be preserved by the pore overpressure at an early stage of diagenesis.

Many studies have shown that primary pores are well preserved in sandstone with authigenic chlorite. Scholars generally agree that chlorite-coated grains enhance the mechanical strength and compressive strength of rocks [53], restrain quartz overgrowth [54], and thus preserve abnormally high porosity. However, some scholars have questioned this point of view. [33] found that high-porosity sandstone developed with chlorite coatings was brittle and lacked rigid particles, supporting cements and fluid overpressure. Chlorite coatings generally do not increase the compressive strength of rocks. Yao et al. [55] considered that the good petrophysical properties of sandstone with chlorite clay films were determined by the petrological characteristics of the sandbodies deposited under strong hydrodynamic conditions, which was not related with the chlorite clay films; that is, chlorite is a product of high porosity.

Extensive studies focus on the effects of overpressure or chlorite on reservoir development, but few studies have focused solely on the relation between the two. As early as 1974, Heald and Larese [56] proposed that overpressure, high porosity, and chlorite coatings should have some correlation, but the complex causes of these properties were not discussed in depth. Stricker and Jones [57], studying the control factors on reservoir quality in the fluvial sandstones of the Skagerrak Formation, proposed that overpressure could hinder mechanical compaction and that chlorite detrital grain coatings would inhibit macroquartz cement overgrowth as the temperature increased during progressive burial. Their research horizon is mainly composed of continental fluvial sediments with sufficient terrigenous iron elements. Chlorite formed mostly in an iron-rich and magnesium-rich alkaline environment. In addition, during the early formation stage of the overpressure system, the formation of the Fe²⁺ and Mg²⁺ ions accompanied the dissolution of feldspar, mica, and iron-rich igneous rock fragments due to the organic matter-rich acidic water discharging from the mudstone into the sandstone. Fe²⁺ and Mg²⁺ ions provide the material basis for the formation of chlorite. Related research results confirmed that the Shihezi, Shanxi, and Taiyuan Formations accumulated overpressure during the Triassic to Early Cretaceous [58, 59]. Teng et al. [60] found that the diagenetic environment in the overpressure compartments was alkaline, which provided theoretical support for the fact that the formation of chlorite required an alkaline environment.

According to the comprehensive analysis, the formation mechanism of lithofacies 3 is as follows: under the conditions of early rapid deposition, the fluids in the mudstone are discharged into the sandstone from mudstone, forming a series of small overpressure systems under the confinement of the sandstone and thick mudstone of diagenetic lithofacies 1, 2, and 5 (pressure compartment). The alkaline environment in the overpressure system and multichannel supply of Fe²⁺ and Mg²⁺ ions promote the formation of chlorite. In addition, the formation of chlorite coatings requires the clean surface of rigid particles, such as feldspar and quartz (Figure 16(a)). The mineral compositions mainly develop under a strong hydrodynamic force, whereas the pressure in the pressure compartment concentrates in the central part. Therefore, this lithofacies is more common in the thick medium-coarse sandstone of the river channel lag and channel bar deposits. The formation of chlorite coatings reduces the pore throat radii and reduces the permeability, further trapping the overpressure fluid in the pores (Figure 15(3)). Coincidently, Zheng [61] found that chlorite dominated in the overpressure zone, but kaolinite dominated in the outer overpressure zone, objectively confirming our point of view.

(a)

(b)

(c)

(d)

Figure 16

ESEM image showing typical cement habits. (a) Chlorite rim is developed at the margins of mineral grains, and intergranular pores are well preserved, SD24-55, 2799.78 m. (b) Silica-like and flaky illite forms networks or bridge-type cementation, SD24-55, 2954.586 m. (c) Feldspar dissolution is associated with kaolinite. Kaolinite intercrystalline pores are developed, and kaolinite illitization can be seen locally, SD24-55, 2976.21 m. (d) Feldspar dissolution is associated with kaolinite. Kaolinite intergranular pores are developed, and kaolinite illitization can be seen locally. Authigenic quartz is developed in intergranular pores, SD24-55, 3043.7 m.

Chlorites and overpressure hinder the formation of quartz and carbonate cements to a certain extent and slow the conversion of clay minerals [32, 33, 45, 53, 55]. However, it is difficult to effectively inhibit the formation of authigenic quartz in intergranular pores [62]. This type of diagenesis occurs in lithofacies 6, which will be analysed in Section 5.3.4.

5.3.3. Dissolution Contributes to Reservoir Development (Lithofacies 8)

Dissolution reformation is an important factor in reservoir development. In lithofacies 3, primary pores are preserved by abnormally high pressure and chlorite, and in lithofacies 8, which underwent intense dissolution and weak cementation, reservoir development is also promoted by dissolution. The focus of dissolution research is the relevant fluids. Dissolution fluids contain organic carboxylic acids and carbonic acid [63], atmospheric freshwater [54, 64], thermal fluids, and alkaline fluids. The source rocks of the coal measure gas of the transitional facies in the upper Paleozoic strata in the Ordos Basin are dominated by terrestrial organic carbon, with humic type III kerogen [65]. The organic carboxylic acid contents produced by coal measure strata are several hundred times those of other strata, providing favourable conditions for the formation of secondary dissolved pores in the coal measure strata and adjacent strata. Organic matter can not only produce organic acids during thermal evolution but can also dissolve cements and clastic particles with associated CO₂. CO₂ becomes more stable after organic acids are produced [3].

In lithofacies 8, dissolution can form two kinds of pore combinations. The first combination is intergranular dissolved pores and intragranular dissolved pores, with minor kaolinite intercrystalline pores, and is more common in the He 4 and Shan 2 members. The second combination is intergranular dissolved pores, intragranular dissolved pores, and kaolinite intercrystalline pores. Kaolinite is associated with both types of pore combinations, indicating that acidic fluids include dissolved feldspar and rock fragments. However, the content of kaolinite in pores shows that the sandstone dissolution products of the He 8 and Shan 1 members have not been fully discharged (Figures 14(b) and 14(c)), so the two pore combinations actually represent different diagenetic characteristics. General sandstone dissolution requires a relatively open fluid flow environment that allows the entry of dissolved fluids and the release of dissolved products [66]. The sandbodies of the He 4 and Shan 2 members are not present at the top and bottom seals of lithofacies 1, 2, and 5, within which the diagenetic system is relatively open and fluids easily flow. Dissolution easily occurs, and dissolved pores are easily formed, so kaolinite easily migrates out of the pores with the fluids. In the sandstone of the He 8 and Shan 1 members, lithofacies 8 is adjacent to lithofacies 3. The diagenetic environment should be a closed system in the sandbodies of lithofacies 1, 2, and 5. Because chlorite is mainly developed in inner overpressure zones and kaolinite is mainly developed in outer overpressure zones [61], we consider that this closed system contains an overpressure zone with the development of chlorite and an outer sublevel of high-pressure zone. Dissolution occurs in the high-pressure zone. Acidic fluids require a stronger driving pressure to flow into a closed diagenetic system than an open hydrostatic pressure system. In the overpressure zone, the permeability is low since the pressure is high and pore throats are plugged by chlorite, making it difficult for external fluids to enter this zone. Even if organic acids and CO₂ enter, the alkaline fluids in the overpressure system will promptly neutralize the external acid fluids, and dissolution is generally inhibited. However, the high-pressure zone in the outer overpressure zone is weakly cemented and compacted since it is far away from the sand-mudstone boundary. As a result, this area of rock has good pore-throat structure and seepage ability. When the abnormal pressure boost formed by hydrocarbon generation sufficiently accumulates, the rocks in the sealed layer of the closed system will rupture and the fluids will rapidly flow into the sandbodies under strong abnormal pressure [67]. Under the resistance of the internal pressure in the overpressure zone, acidic fluids will accumulate in the outer overpressure zone to form a dissolution zone (Figure 15(8)).

5.3.4. Various Intense Cementation Lithofacies Increase the Impermeability of the Diagenetic System (Lithofacies 4, 6, and 7)

The material sources of the cements come from diverse pathways, including the dissolution of feldspar and rock fragments, the devitrification of volcanic materials, the diagenetic transformation of clay minerals, and thermal convection [68].

Lithofacies 4 represents the reservoir intensification due to the intense quartz overgrowth during the early stage of diagenesis, mostly occurring between the mesodiagenetic B stage and the mesodiagenetic A stage. This lithofacies is adjacent to lithofacies 5. It is considered that the organic acids that formed during the first hydrocarbon generation stage enter the interior sandstone and cause dissolution. At the same time, compaction promotes the formation of lithofacies 1, 3, and 5. Although different distributions of the three lithofacies of sandstone results in different sealing properties of the diagenetic systems, once the SiO₂ oversaturated state is formed due to dissolution, whether the diagenetic system is closed, semi-closed, or semi-open, SiO₂ will inevitably precipitate in the form of cements. In a closed system, ions tend to precipitate in low-pressure areas, but in semi-closed or semi-open systems, ions tend to form cements along the system boundary because fluid movement is hindered by the low-permeability layer at the sandbody boundary (Figure 15(4)). During the early diagenetic stage, since the mineral grains of sandstone are slightly affected by the clay minerals and other cements, quartz overgrowth forms, further enhancing the sealing property of sandstone diagenetic systems.

Lithofacies 6 represents reservoir densification due to the intense cementation of intergranular authigenic quartz. This lithofacies is rare during the late stage of first-phase dissolution and mainly develops after the second-phase dissolution, when the organic matter generates hydrocarbon and expels acids. With the increase in burial depth, compaction continuously reforms the pore structure of sandstone. As a result, porosity decreases continuously, and various types of clay minerals form different types of cement on the surface of the mineral grains. Although dissolution and clay mineral transformation provide abundant SiO₂ for siliceous cementation, siliceous materials mainly manifest as authigenic microcrystalline quartz with a high automorphic degree in intergranular pores. This lithofacies develops in different positions of different sandbodies. In semi-closed to open diagenetic systems, under the pressure of internal fluids, the oversaturated SiO₂ fluids tend to diffuse out from the dissolution zone (from the sandbody centre to the margin). Due to the shielding of the sandstone with different densification patterns at the margin, a compact layer is formed in the adjacent area of lithofacies 4. However, in the sealed sandbodies with overpressure, this lithofacies can form cements at the margin of the overpressure zone since oversaturated SiO₂ fluids break the seepage seal created by chlorite and overpressure. If early the overpressure is destroyed and the fluid seepage seal disappears, this lithofacies is more easily formed (Figure 15(6)). Large amounts of authigenic quartz will “block” the primary intergranular pores preserved by chlorites and overpressures, but scholars generally believe that chlorite cannot constrain the formation of quartz cements (Figure 16(d)). Lithofacies 6 developed at the margin of the overpressure zone and is of great significance for the preservation of overpressure. This lithofacies is often alternately associated with lithofacies 5 and 8.

Lithofacies 7 represents the reservoir densification due to the intense cementation of ferrocalcite during the late stage of diagenesis. The diagenetic path and pattern of lithofacies 7 are similar to those of lithofacies 8. Inclusion temperature measurement results show that ferrocalcite forms at a later diagenetic stage than that of the authigenic quartz of lithofacies 6. However, the formation temperature of ferrocalcite is higher than the temperature range of the feldspar dissolution reaction and corresponds to the temperature interval of the clay mineral conversion.

Carbonate cements are the product of alkaline diagenetic environments, determining whether lithofacies l can form. Su et al. [69] argue that during the dissolution process, a large amount of K⁺ is formed when H⁺ is depleted. Various types of sand bodies gradually evolve into closed diagenetic systems during burial diagenetic process. K⁺ cannot be fully removed from sandbodies, so the K⁺/H⁺ ratio will remain high in the formation water. When the formation temperature ranges between 70 and 100°C, montmorillonite will induce illitization, and a large amount of Ca²⁺, Fe²⁺, and Mg²⁺ will release [70, 71]. When the temperature is above 130°C, the K⁺ and H⁺ ion activity is below the saturation point of K-feldspar, and kaolinite and potassium are not able to coexist. The diagenetic environment gradually transitions from a weakly acidic to an alkaline environment (Figure 16(d)) [69]. Montmorillonite is not observed in the microscopic observations and X-ray diffraction analyses of the sandstone of lithofacies 7, but kaolinite is mostly associated with illite (Figures 16(c) and 16(d)). With the increase in buried depth, the content of illite increases significantly and the content of the illite/smectite mixed layer decreases to 5~10%. Montmorillonite and kaolinite undergo illitization before ferrocalcite undergoes cementation. The two reactions occur in an alkaline environment and promote an increase in pH, which provide an alkaline environment for the cementation of ferrocalcite. The carbon source is provided by the dissolution of the late stage of diagenesis. Ca²⁺, Fe²⁺, and Mg²⁺ ions are released when montmorillonite and kaolinite transition into illite, providing materials for the formation of ferrocalcite. When the ion concentration reaches a saturated state, ferrocalcite forms (Figure 15(7)).

6. Conclusions

On the basis of the above results, the following conclusions have been reached.

The Permian tight sandstone in the Ordos Basin has experienced complex diagenetic evolution. However, not all sandstones have undergone the same evolution process. Taking litharenite as an example, 8 types of differential densification modes had been divided according to the diagenesis paths of different samples; the combination relations of various modes show certain regularity in the vertical profiles.

The differential densification evolution forms the lithofacies with different densification times and reservoir qualities. Among these, lithofacies 3 and 8 are the main reservoir development lithofacies. For the former, primary pores developed under the synergistic effect of overpressure and chlorite cement; for the latter, secondary pores developed under the two stages dissolution. In addition, part samples of lithofacies 2 have a good reservoir performance and potential to become a reservoir due to its development of microfractures. These three lithofacies are mainly developed in the middle-lower part of braided channel lags and channel bars, the middle part of meandering riverbed lags, and middle part of point bars.

Data Availability

(1) The detrital and cement composition, porosity, permeability, X-ray, NMR, and X-CT data used to support the findings of this study are included within the article. (2) The detrital and cement composition, porosity, permeability data, and X-ray used to support the findings of this study are currently under embargo while the research findings are commercialized. Requests for data, 12 months after publication of this article, will be considered by the corresponding author. (3) The NMR and X-CT data used to support the findings of this study are available from the corresponding author upon request.

Conflicts of Interest

The authors declare that they have no conflicts of interest.

Acknowledgments

This work is financially supported by the National Natural Science Foundation of China (No. 51674211, No. 51534006, and No. 41702164) and Youth Software Creative Engineering from Technological Office of Sichuan Province (No. 2018058). We thank the sponsors of this project. We would like to sincerely thank the PetroChina Changqing Oilfield Company for providing samples and access to data. We also appreciate the teachers at the State Key Laboratory of Southwest Petroleum University for their assistance in sample analysis.

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Copyright © 2019 Meng Wang et al. This is an open access article distributed under the Creative Commons Attribution License, which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

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