Tight Reservoir Characteristics and Controlling Factors of Permian Lucaogou Formation in Yongfeng Sub-Sag, Chaiwopu Sag

Abstract

On the basis of the observation of rock cores and cuttings, combining the information from thin section identification, physical properties analysis, scanning electron microscopy, X-ray diffraction, etc., the characteristics and controlling factors of the tight reservoir in the Permian Lucaogou Formation of the Yongfeng sub-sag of the Chaiwopu sag have been studied. Based on the analysis, the Lucaogou Formation in the study area can be divided into two lithological sections. The tight sandstone reservoir, characterized by low porosity and low permeability, is mainly developed in the upper section of the Lucaogou Formation. The lithology of the tight reservoirs is mainly lithic sandstone with low compositional and structural maturity. The reservoir space types mainly consist of secondary pores, including intergranular dissolution pores, intragranular dissolution pores and fractures, and the primary pores are severely destroyed. The main controlling factors of reservoirs include sedimentary facies, lithology, diagenesis, later tectonic movements and fractures, and the latter two factors have a significant impact on improving reservoir physical properties and seepage capacity. The tight reservoir has high brittleness and low water sensitivity, which is very conducive to large-scale hydraulic fracturing to transform the reservoir and improve oil and gas production capacity.

1. Introduction

According to the contribution of hydrocarbon source rocks to global oil and gas reserves, global hydrocarbon source rocks are mainly distributed in six stratigraphic intervals, and as one of the six sets of source rocks, the Pennsylvanian-Permian source rocks have provided over 8% of global reserves [1]. In many regions and basins around the world, the Permian is a set of important exploration target strata, such as the Permian Basin in North America [2,3], the Junggar Basin in China [4,5], and the natural gas reservoirs in the Persian Gulf [6]. With the advancement of oil and gas accumulation theory and exploration technology, unconventional oil and gas gradually occupy an important position in global and even China’s oil and gas exploration and development [7,8], and the unconventional resources play an important role in increasing oil and gas storage and production [9,10], and the Permian system, as the main source rock series, has a more prominent position in unconventional oil and gas exploration [3,4]. In recent years, some important breakthroughs and discoveries have been made successively in the field of Permian unconventional oil and gas exploration in the Junggar Basin [11,12,13], represented in particular by the discovery of a billion-ton large oilfield in the Jimsar Sag on the northern margin of the Bogda Mountain [5,14]. The Permian Lucaogou Formation is the main source rock series and exploration target layer, whose main types of reservoirs are shale reservoirs and tight reservoirs characterized by integrated and adjacent source-reservoirs. A great deal of research has been conducted by various scholars on the sedimentary characteristics [15], rock types [16], reservoir characteristics [17,18,19,20], and source rock evaluation of the Lucaogou Formation in the Jimsar Sag [21,22]. Some scholars have made exploratory studies on the sedimentary characteristics and evolution of the Lucaogou Formation around the Bogda Mountains [23] and have done a lot of fruitful and enlightening work, playing a guiding role in the research and prediction of the planar distribution of the Lucaogou Formation. However, the exploration level at the southern edge of the Bogda Mountain front zone, especially in the Yongfeng area of the Chaiwobao Depression, is relatively low. Previous research on the reservoirs of the Lucaogou Formation in this area is rarely involved [24], and there is a lack of in-depth research on the reservoir characteristics and main control factors of the Lucaogou Formation, which restricts the recognition of hydrocarbon accumulation laws and exploration deployment work in this area. In 2019, the Oil and Gas Survey of China Geological Survey deployed well Xyd1 in the Yongfeng sub-sag of the Chaiwopu sag. This well is the first drilling in the area with the Lucaogou Formation as the main target layer, which plays an important role in evaluating the key elements of oil and gas accumulation and the potential of oil and gas resources in the area. The research focuses on the systematic study of the petrological characteristics, reservoir physical properties and major controlling factors of the upper section of the tight sandstone reservoir of the Lucaogou Formation of the Yongfeng sub-sag by means of observing rock core, thin section analysis, scanning electron microscopy, X-ray diffraction and physical property analysis, hoping to provide certain guidance for reservoir evaluation and prediction, exploration and development of tight oil and gas in this area.

2. Regional Geological Condition

Sandwiched between the Bogda Mountain in the north, the Ealing Hebergen Mountain in the south, and the Zilgustau Mountain in the east, the Chaiwopu sag is located in the foothill belt of the Tianshan Mountains on the southern margin of the Junggar Basin, whose structural characteristics and evolution are controlled by the formation of the Bogda Mountain and the Ealing Hebergen Mountain. Generally summarized as east and west blocks, the structure pattern can be divided into three sub-structural units: the Yongfeng sub-sag, the Sangezhuang sub-bulge and the Dabancheng sub-sag. Yongfeng sub-sag is located in the west of the Chaiwopu sag (Figure 1). Except for the missing Cretaceous system, both Permian and Tertiary systems of the Yongfeng sub-sag are developed, and the maximum thickness lies in the north. Affected by the uplift of the Bogda Mountain, the study area underwent five tectonic evolution stages: the Early Permian to Middle Permian extensional rift stage, the Late Permian to Triassic compressive flexure stage, the Jurassic extensional stage, the Cretaceous foreland stage, and the Cenozoic compressive foreland stage. In the study area, high-quality source rocks are developed from the salty-lacustrine facies of the Lucaogou Formation during the early to middle Permian rift basin stage, with a wide distribution range and large sedimentary thickness, providing an important material basis for oil and gas accumulation and also being the most important exploration target series.

3. Lithology of the Tight Reservoir

The lithology of the Lucaogou Formation in the foothill belt of the Bogda Mountain is complex and diverse. According to drilling and field outcrop data in the Jimsar Depression, the Lugaogou Formation is generally a set of fine-grained sedimentary rocks, mainly composed of three types of mixed lithology: black mudstone, carbonate rock, and fine clastic rock, with the development of salt sedimentary markers such as gypsum pseudo crystals and fish scale fossils, which belong to continental saline lacustrine basin sedimentation [25,26,27]. The lithology of the Lucaogou Formation in the Yongfeng sub-sag is somewhat different from that in the Jimsar Sag, with obvious upper and lower segmentation characteristics (Figure 2). The upper section is mainly composed of gray siltstone and fine sandstone, with locally visible fine conglomerate and gray mudstone, indicating a tight sandstone reservoir development section. The lower section is composed of black mudstone, shale interbedded with thin layers of siltstone, gray dolomitic sandstone and limestone locally (in the transitional part of the upper and lower sections), indicating the development of shale reservoirs.

3.1. Sample Collection and Analysis

In this study, a total of 64 core and debris samples were collected from the Lucaogou Formation of well Xyd 1, including 55 core samples and 9 core cutting samples. The principle of sample collection is mainly to collect core samples from the sandstone reservoir in the upper section of the Lucaogou Formation with good oil and gas show. The core samples are concentrated in two depths: 1714–1754 m and 1770–1780 m, and the sampling interval should be kept evenly distributed as much as possible. In order to conduct a comparative analysis of the upper and lower sections of the Lucaogou Formation, a small amount of core cutting samples was collected in the lower section of the Lucaogou Formation. 146 tests were conducted on the 64 samples mentioned above, including 30 ordinary thin section analyses, 28 cast thin section analyses, 28 porosity and permeability analyses, 21 whole rock X-ray diffraction analyses, 32 clay mineral X-ray diffraction analyses, and 7 scanning electron microscopy analyses. Except for the X-ray diffraction samples, all other test samples are located in the upper tight sandstone reservoir section of the Lucaogou Formation.

X-ray diffraction analysis is widely used in mineralogy research. It is a physical method that uses the diffraction effect generated by X-ray passing through mineral crystals to analyze mineral structure and composition and can determine mineral composition and content. Scanning electron microscopy has a wide range of applications in the study of clastic and carbonate reservoirs. It can conduct in-depth and systematic research on the mineral composition, pore structure, pore type and genesis, degree of cementation, and secondary alteration of reservoirs, and evaluate the quality of reservoirs.

3.2. Petrological Characteristics

The thin section shows that the lithology of the tight reservoirs in the upper section of the Lucaogou Formation in the Xyd 1 well is mainly lithic sandstone, with rock components mainly composed of lithic debris, followed by quartz. The composition of lithic debris is mainly neutral extrusive rock (andesitic), with a small amount of acidic extrusive rock debris. The petrological characteristics are mainly terrigenous debris (Figure 3). The rock particle size is classified as medium to fine sand and silt, with moderate deviation in sorting. The roundness is of sub-angular to angular shape, supported by particles, and has a linear concave-convex contact relationship. The main types of cementation are clay minerals and carbonates, with pore compression being the main type of cementation, and low compositional and structural maturity.

3.3. Characteristics of Mineral Composition

The thin section shows the quartz content of sandstone in the upper section of the Lucaogou Formation in well Xyd 1 is 15–23%, the feldspar content is 5–10%, and the lithic debris content is 71–77%. X-ray whole rock diffraction shows that the tight sandstone reservoir in the upper section of the Lucaogou Formation is mainly composed of quartz, plagioclase, and clay minerals. The average content of quartz and plagioclase is 33.5% and 30.2%, followed by an average content of clay minerals of 28.7%. The content of anhydrite and calcite is relatively low, with occasional potassium feldspar (Figure 4) and no dolomite. The mineral composition is characterized by terrigenous clastic mechanical transport sedimentation and mainly fan delta front sedimentation.

3.4. Physical Properties of Reservoir

According to the logging interpretation of well Xyd 1, the overall physical properties of the sandstone reservoir in the upper Lucaogou Formation are poor. The conventional logging interpretation shows porosity ranging from 4.5% to 8.3%, nuclear magnetic porosity ranging from 5.0% to 7.6%, and permeability ranging from 0.1 to 9.9 mD. According to the analysis results of core physical properties testing (Figure 5,

Table 1. Porosity and permeability for tight sandstone reservoir in the upper Lucaogou Formation of well Xyd 1.

Sample	Depth/m	Lithology	Porosity/%	Permeability/mD
1-1	1714.34	Gray Fluorescent Argillaceous Silt-stone	2.9	0.13
1-2	1715.15	Gray Oil Stained Fine Sandstone	1.9	0.019
1-3	1715.74	Gray Oil Stained Gritstone	3	0.024
2-1	1715.8	Gray Oil Stained Gritstone	4.7	0.038
2-2	1715.89	Gray Oil Stained Gritstone	4.9	0.03
1-4	1716.35	Gray Oil Stained Fine Sandstone	1.8	0.032
1-5	1716.73	Gray Fluorescent Siltstone	3.1	0.775
1-6	1717.84	Gray Oil Spotted Fine Sandstone	1.7	0.039
2-3	1718.82	Gray Oil Spotted Fine Sandstone	5.4	0.028
1-7	1719.12	Gray Oil Spotted Fine Sandstone	2	0.036
1-8	1720.04	Gray Fluorescent Fine Sandstone	3.7	—
1-9	1721.37	Gray Oil Stained Fine Sandstone	2.3	1.57
1-10	1721.63	Gray Oil Immersed Fine Sandstone	1.1	0.024
1-11	1722.33	Gray Fluorescent Fine Sandstone	1.4	0.023
1-12	1753.1	Gray Fluorescent Siltstone	1.4	0.031
1-13	1770.56	Gray Fluorescent Fine Sandstone	3.3	0.027
1-14	1772.24	Gray Oil Stained Fine Sandstone	4.9	0.686
1-15	1773.64	Gray Oil Spotted Medium Sandstone	7	—
1-16	1776.29	Gray Oil Stained Fine Sandstone	8	5.1
1-17	1777.1	Gray Oil Immersed Glutenite	11.8	—
2-4	1777.16	Gray Oil Immersed Glutenite	10.1	—
1-18	1779.2	Gray Oil Stained Fine Sandstone	7	2.09
1-19	1779.79	Gray Oil Spotted Fine Sandstone	8	15.5
1-20	1780.64	Gray Fluorescent Fine Sandstone	7.9	—
1-21	1999.32	Gray Fluorescent Siltstone	3.8	—
1-22	2000.94	Light Gray Fluorescent Dolomite Fine Sandstone	5.2	—
1-23	2004.08	Light Gray Fluorescent Dolomite Fine Sandstone	2.6	—
1-24	2008.1	Gray Fluorescent Fine Sandstone	4.9	0.524

), the porosity of the main oil and gas display intervals in the Lucaogou Formation is 1.1–11.8%, and the permeability is 0.019~15.5 mD. Overall, the reservoir is generally evaluated as a low porosity and low permeability reservoir, with local low porosity and ultra-low permeability reservoirs. The overall physical properties of the reservoir are poor, and the presence of good reservoirs in local areas is mainly affected by fractures.

3.5. Types and Characteristics of Reservoir Space

According to the casting thin sections, the reservoir space types of the tight sandstone reservoir in the upper section of the Lucaogou Formation in Xyd 1 well include primary pores, secondary dissolution pores, and fractures. Overall, secondary dissolution pores are dominant, primary pores are severely damaged, and only residual intergranular pores are developed (Figure 6).

3.5.1. Primary Pores

The primary pores are generally undeveloped and consist of residual primary intergranular pores, including skeletal intergranular pores not filled by matrix or cement, pores between organic matter and skeletal particles, and residual intergranular pores filled by clay and authigenic minerals (Figure 6a). The pores are irregularly or polygonally non-uniformly distributed, with a clear pore boundary and a pore size generally less than 50 μm.

3.5.2. Secondary Dissolution Pores

The distribution of secondary dissolution pores in the tight sandstone reservoir of the Lucaogou Formation has strong heterogeneity, mainly including intergranular dissolution pores and intragranular dissolution pores (Figure 6b,c). The intergranular dissolution pores are mainly albite dissolution pores, forming a harbor-like space that expands the intergranular pores, having good connectivity, and being mostly filled with organic matter. The intragranular dissolution pores are mainly dissolution pores within sand or rock debris, with pore diameters ranging from 20 to 50 μm, forming moldic pores locally but with poor connectivity. In the intragranular dissolution pores, quartz and dolomite with good self-forming degrees are more commonly seen. Some intragranular dissolution pores are filled with asphaltenes.

3.5.3. Fractures

The fractures in tight sandstone reservoirs in the upper Lucaogou Formation in the study area are well-developed, and the degree of fracture filling has a good correlation with oil-gas bearing property (

Table 2. Statistics of fractures for the tight reservoir in the upper Lucaogou Formation of well Xyd 1.

Top Depth/m	Bottom Depth/m	Fracture Feature			Fracture Filling Degree	Oil and Gas Show of the Corresponding Core Section
		Diagonal Fracture	Longitudinal Fracture	Cross Fracture
1714.34	1716.81	9	1	0	Full Filled to Half-Filled	Fluorescence, Oil Stained
1721.63	1725.08	14	1	0	Full Filled to Half-Filled	Oil Immersion, Fluorescence
1726.57	1729.59	12	0	0	Full Filled	No Oil and Gas Show
1730.52	1732.75	9	0	0	Full Filled	No Oil and Gas Show
1737.12	1743.26	0	2	0	Half-Filled	Intermittent escape of pinpoint bubbles
1744.62	1745.01	1	0	0	Full Filled to Half-Filled	Intermittent escape of pinpoint bubbles
1771.44	1777.51	17	5	1	Full Filled to Half-Filled	Oil Stained, Oil Spotted, Oil Immersion
1778.12	1780.76	3	0	0	Full Filled to Half-Filled	Oil Stained, Oil Spotted, Fluorescence

). By observing the cores and casting thin sections, the fractures can be divided into three types: micro-fractures, early structural fractures and late structural fractures. Micro-fractures refer to fracture-like pores that run through particles and are mainly found in argillaceous sandstone. Such pores have no obvious relationship with structural fractures and should be fluid channels formed by organic acid dissolution during the burial period and then filled with oil and gas (Figure 6d). Most of the early structural fractures were filled fractures, which were successively filled by quartz, calcite and organic matter after their formation (Figure 6e). Late structural fractures are mostly high-angle fractures (Figure 6f), which extend in a zigzag shape. According to their oil0bearing properties, they can be divided into non-oil-bearing and oil-bearing fractures. The oil-bearing fracture surfaces are contaminated by crude oil, and the fluorescence-thin sections also prove that unfilled fractures can be used as channel for hydrocarbon migration and seepage, which improve the seepage capacity of the reservoir and are conducive to increasing oil and gas production capacity.

3.6. Reservoir Brittleness and Water Sensitivity

Low-permeability reservoirs must be stimulated by fracturing in order to achieve economic development, and the compressibility of the reservoir is of great significance to the fracturing effect. At present, reservoir compressibility can be determined by parameters such as brittle mineral content, which generally includes quartz, feldspar, calcite, dolomite, etc. The whole rock mineral composition of the reservoir can be determined by diffraction, and the relative content of brittle minerals and clay mineral minerals in the reservoir can be qualitatively analyzed. The relative content of clay minerals can also be calculated by logging curves in combination with whole-rock diffraction data. By whole-rock diffraction, the brittle minerals of the tight sandstone in the upper section of the Lucaogou Formation in the study area were mainly quartz, feldspar and calcite, with a content of 49–90%, and the clay mineral content is 18–38%, with an average of 28.7%. The clay mineral content calculated by the logging curve is 25.14–41.93%, with an average value of 31%, which is in good agreement with the whole rock diffraction data. In general, the tight reservoirs of the Lucaogou Formation have better brittleness, with relatively high brittle mineral content and low clay content.

The water sensitivity of reservoirs refers to the hydration, expansion, dispersion, and migration of clay minerals caused by external fluids entering the reservoirs, resulting in a decrease in permeability. Therefore, the water sensitivity analysis has important reference significance for fracturing fluid compatibility. Among the clay minerals, montmorillonite has the greatest expansibility, while illite’s expansibility is quite weak, and kaolinite has almost no expansibility. Therefore, the content of different components of clay minerals plays an important role in evaluating the water sensitivity of reservoirs. In this study, X-ray diffraction of clay minerals and natural gamma ray spectroscopy logging thorium-potassium cross plots are mainly used to identify different clay mineral contents (

Table 3. Content of clay mineral components for the tight reservoir in the upper Lucaogou Formation.

Sample	Well Depth (m)	Lithology	Relative Content of Clay Minerals/%
			Mixed Layer Illite/Smectite	Illite	Kaolinite	Chlorite	Ratio of Mixed Layer Illite/Smectite
1-1	1714.34	Gray Fluorescent Argillaceous Siltstone	38	40	6	16	20
1-2	1715.15	Gray Oil Stained Fine Sandstone	42	39	5	14	20
1-4	1716.35	Gray Oil Stained Fine Sandstone	38	37	19	6	20
1-6	1717.84	Gray Oil Spotted Fine Sandstone	25	35	15	25	20
1-7	1719.12	Gray Oil Spotted Fine Sandstone	41	21	4	34	20
1-10	1721.63	Gray Oil Immersed Fine Sandstone	16	23	24	37	20
1-12	1753.1	Gray Fluorescent Siltstone	57	18	8	17	20
1-13	1770.56	Gray Fluorescent Fine Sandstone	25	25	15	35	20
1-15	1773.64	Gray Oil Spotted Medium Sandstone	38	45	6	11	20
1-17	1777.1	Gray Oil Immersed sand-conglomerate	24	38	16	22	20

). The results show that illite accounts for a relatively high proportion of clay minerals in the tight reservoir of the upper section of the Lucaogou Formation, containing mixed layers of illite/smectite and a small amount of mica. The water sensitivity of the reservoirs is relatively poor, which is conducive to the compatibility of the fracturing fluid and the effect of reservoir fracturing.

4. Controlling Factors of Reservoir

Research has shown that the main controlling factors of reservoirs include sedimentary facies, lithological characteristics, diagenesis, and later tectonic movements. These factors are interrelated in controlling reservoirs, but their magnitude of action varies. Sedimentary facies are the core controlling factor, directly determining the rock type, mineral composition, development degree, and stacking style of the reservoir, further affecting the diagenesis of the reservoir. Diagenesis plays an extremely important role in the formation, preservation, and destruction of reservoir pores and has a decisive impact on the physical properties of the reservoir. The impact of later tectonic movements on the reservoir is mainly manifested in the formation of fractures through rock fragmentation, providing a flow channel for fluids, and improving reservoir properties.

4.1. Impact of Sedimentary Facies on Reservoirs

The sedimentary environment, sedimentary provenance and sedimentary facies directly determine the rock type, mineral composition, developing degree and stacking style of the reservoir. During the sedimentation period of the Lucaogou Formation, the Bogda Mountain and its surrounding areas were a unified saline lake basin environment characterized by southern faulting and northern superimposition. The main provenance area is located at Ealing Hebergen Mountain in the south, where fan delta facies developed, and the northern part was a deep and semi-deep lacustrine facies, with the main depocenter located around the Bogda Mountain [23]. The study area is located on the southern margin of the Bogda Mountain, close to the provenance area of Ealing Hebergen Mountain in the south. The types of sedimentary facies in the upper and lower Lucaogou Formation are significantly different. The lower section of the Lucaogou Formation is mainly composed of black shale, sandwiched with thin-bedded dolomitic siltstone, showing a low energy and strong reducing environment, and is deep to semi-deep lacustrine facies. Affected by the decline of the base level, the fan of the upper Lucaogou Formation extends toward the northern basin, and the main body of the study area is dominated by fan delta front facies. The proportion and thickness of sandstone gradually increase, forming thick, tight sandstone reservoirs. Controlled by the distribution of sedimentary facies belts, this set of tight reservoirs is widely distributed in the study area and forms a source-reservoir configuration relationship with the lower section of the Lucaogou Formation, which is an important exploration target series in the study area.

4.2. Impact of Lithology on Reservoir

The lithology and mineral composition of the reservoir have a direct impact on the storage capacity and brittleness of the reservoir. The lithology of the tight reservoirs in the upper Lucaogou Formation in the study area is mainly lithic sandstone with low compositional and structural maturity, which is mainly characterized by the mechanical deposition of near-provenance terrigenous debris input. The characteristics of near-provenance lead to the development of unstable substances such as lithic debris and feldspar in the reservoir, which have a dual effect on the physical properties of the reservoir. On the one hand, mechanical compaction is prone to occur, leading to the reduction of primary intergranular pores and the deterioration of reservoir physical properties. On the other hand, unstable substances are prone to dissolution, improving the reservoir’s physical properties. In addition, from the perspective of mineral composition, the brittle mineral content of the tight reservoirs of the upper Lucaogou Formation in the study area is relatively high, while the clay content is low, indicating good reservoir brittleness, which is conducive to improving the effect of reservoir stimulation.

4.3. Impact of Diagenesis on Reservoir

The diagenesis in the foothill front belt of the Bogda Mountain is complex, and the diagenesis that affects the pore characteristics of low-permeability reservoirs mainly includes mechanical compaction, cementation, and dissolution.

Mechanical compaction is the main factor causing the weak development of primary intergranular pores in reservoirs. The thin sections show that the tight sandstone reservoirs of the Lucaogou Formation are mainly supported by particles, and the contact relationship between particles is mainly line- and concave-convex, with local contact in the form of a point. This indicates that as the burial depth continues to increase, the compaction effect continues to strengthen, and the debris particles develop from point contact to line contact and concave convex contact. Mineral particles such as feldspar are compressed and bent, and the porosity and permeability of the reservoirs gradually decrease.

Cementation is also an important factor leading to the reduction of primary intergranular pores and the deterioration of reservoir physical properties. The cements in the tight sandstone reservoirs of the Lucaogou Formation are calcite, pyrite and siliceous. Under the microscope, the thin sections show that the microcrystalline calcite is cemented in plaques, and medium-fine crystalline clastic calcite or metasomatic clasts can be seen. Pyrite is generally relatively developed, mainly in the form of clots, and the siliceous cement is mainly composed of microcrystalline quartz, with occasional secondary enlargement of quartz.

Dissolution plays an important and positive role in improving reservoir physical properties. The dissolution of tight sandstone reservoirs in the Lucaogou Formation is relatively developed, and the secondary dissolution pores are also the main type of reservoir space. Under the microscope and scanning electron microscope, the dissolution can be clearly observed (Figure 7). The dissolved substances in the reservoir are mainly feldspar particles, which form harbor-like spaces after dissolution, expanding intergranular pores and providing good connectivity, greatly improving the storage performance of the reservoir. In addition, some early-formed calcite and other cements also undergo dissolution, forming micro- and nano-scale dissolution pores, which can also improve the storage performance of the reservoir.

4.4. Impact of Tectonic Movements and Fractures on Reservoir

The degree of development of fractures has an important impact on reservoir porosity and permeability, which can serve as a pathway for hydrocarbon migration, improve reservoir permeability, and effectively increase oil and gas production. The type and formation time of fractures are mainly affected by tectonic movements. The structural characteristics of the study area are mainly influenced by the uplift of the Bogda Mountain, and the overall structural deformation is generally characterized as strong in the southeast and weak in the northwest. The structural styles are mainly fault-propagating folds, backthrust structures, and imbricated structures, which are controlled by three phases of fault activity. In the early and middle Permian, the study area was an intracontinental rift and a fault basin; at this time, the Bogda Mountain had not yet uplifted, and normal faults controlled the formation of the sag. In the late Permian, the stress field underwent a transformation and a structural inversion occurred, resulting in the initial uplift of the Bogda Mountains. In the Late Jurassic-Cretaceous, the Bogda Mountain underwent another uplift, forming reverse faults caused by NW-SE oblique compression. In the Himalayan period, the Bogda Mountain continued to rise strongly, forming a nearly north–south compression, and the early structure was revived, forming a thrust and strike-slip (left-lateral) structure. The fractures formed in the first two stages of fault activities were mostly filled with minerals such as quartz and calcite during the diagenetic process, which has limited contribution to the seepage capacity of the reservoir, while the fractures formed in the later stage were mostly high-angle fractures, and some of them are not filled, which can serve as pathways for hydrocarbon migration and seepage, improving the seepage capacity of the reservoir and being conducive to increasing oil and gas production capacity. At the same time, fractures can also provide a migration pathway for acidic fluids to enter the reservoir, promote the dissolution of minerals such as feldspar to form secondary dissolution pores, and further improve the physical properties of the reservoir.

5. Conclusions

• The Permian Lucaogou Formation in the study area can be divided into upper and lower lithological sections. The upper section develops a set of fan delta front facies siltstone deposits, mainly composed of lithic sandstone with low compositional maturity and poor reservoir physical properties. It is a tight sandstone reservoir with low porosity and low permeability. The reservoir space is mainly secondary pores, including intergranular dissolved pores, intragranular dissolved pores and fractures. The primary pores are severely damaged, and only residual intergranular pores are developed.
• The tight sandstone reservoir in the upper part of the Lucaogou Formation in the study area has high brittleness and low water sensitivity, which is very conducive to large-scale hydraulic fracturing to transform the reservoir and improve oil and gas production capacity.
• The development of tight reservoirs in the Lucaogou Formation in the study area is mainly controlled by sedimentary facies, lithology, diagenesis and later tectonic movement. These factors are interrelated in controlling reservoirs, but their magnitude of action varies. Sedimentary facies is the core controlling factor. Diagenesis has a decisive impact on the physical properties of the reservoir. Later tectonic movements and fractures have a significant impact on improving reservoir physical properties and seepage capacity.