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Article

Characteristics and Evolution of Tectonic Fractures in the Jurassic Lianggaoshan Formation Shale in the Northeast Sichuan Basin

by
Xuefeng Bai
1,2,
Xiandong Wang
2,*,
Zhiguo Wang
2,
Hucheng Deng
3,*,
Yong Li
3,
An Li
3,
Hongxiu Cao
3,
Li Wang
3,
Yanping Zhu
2,
Shuangfang Lu
1,
Feng Cao
3 and
Jianhua He
3
1
School of Geosciences, China University of Petroleum (East China), Qingdao 266580, China
2
Research Institute of Exploration & Development, PetroChina Daqing Oilfeld Company, Daqing 163712, China
3
College of Energy, Chengdu University of Technology, Chengdu 610059, China
*
Authors to whom correspondence should be addressed.
Minerals 2023, 13(7), 946; https://doi.org/10.3390/min13070946
Submission received: 17 May 2023 / Revised: 12 July 2023 / Accepted: 13 July 2023 / Published: 15 July 2023
(This article belongs to the Topic Reservoir Characteristics and Evolution Mechanisms of the Shale)
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Abstract

:
The features and formation stages of natural fractures have significant influences on the fracturing of shale reservoirs and the accumulation of oil and gas. The characteristics and evolution of tectonic fractures in the Lianggaoshan Formation in Northeast Sichuan were investigated based on outcrops, drill cores, geochemical data, and acoustic emission test results. Our results demonstrated that the fracture types of the Lianggaoshan Formation were mainly low-degree bedding-slip fractures, followed by high-degree through-strata shear fractures and vertical tensile fractures. The influences of strike-slip faults on the fractures were stronger than those of thrust faults; fractures in thrust faults were concentrated in the hanging wall. The densities of tensile and shear fractures were inversely proportional to the formation thickness, while the density of interlayer slip fractures was independent of the formation thickness. The density of tectonic fractures was proportional to the quartz content. The fractures of the Lianggaoshan Formation were generated in three stages during uplift: (1) Late Yanshan–Early Himalayan tectonic movement (72~55 Ma), (2) Middle Himalayan tectonic movement (48~32 Ma), (3) Late Himalayan tectonic movement (15 Ma~4 Ma). Fractures greatly improve the oil and gas storage capacity and increase the contents of free and total hydrocarbons. At the same time, they also reduce the breakdown pressure of strata. This study facilitated the prediction of the fracture distribution and oil and gas reservoirs in the Lianggaoshan Formation and provided references for the selection of favourable areas for shale oil and the evaluation of desert sections in the study area.

1. Introduction

As it is becoming increasingly difficult to stabilize the production of shale gas in the Silurian marine facies of the Sichuan Basin, it is of great significance to actively seek replacement areas for shale oil and gas exploration to ensure an increase in unconventional oil and gas reserves and production in the Sichuan Basin. The Jurassic system is the key strata for oil exploration in the Sichuan Basin, but due to the low porosity and low permeability of tight sandstone and limestone reservoirs, commercial development of conventional oil and gas is difficult, and no breakthrough in industrial production capacity has been achieved thus far [1,2]. In 2020, the daily oil and gas production rates of Well PA1, located in the Jurassic Lianggaoshan Formation in Northeast Sichuan, were 112.8 m3 and 11.45 × 104 m3, respectively. In 2021, the daily oil and gas production rates of Well TY1, located in the Jurassic Lianggaoshan Formation in East Sichuan, were 9.8 m3 and 7.5 × 104 m3, respectively. This series of explorations successfully realized the exploration breakthrough of continental shale oil gas production in the Jurassic Lianggaoshan Formation and confirmed the large reservoir of shale oil and gas in Northeast Sichuan.
Unconventional shale reservoirs are characterized by low porosity and low permeability. As shale gas has an effective storage space and an important channel for seepage, fractures are of great significance to the enrichment and high production of shale gas [3]. The commercial development of shale reservoirs at home and abroad confirmed that the development of natural fractures not only improves the storage conditions of shale reservoirs but also provides favourable conditions for the formation of large-scale volumetric fracture networks during hydraulic fracturing in the development stage [4,5,6,7,8,9], but the communication of overdeveloped fractures and large-scale fractures is extremely unfavourable to the preservation of oil and gas [10]. The characteristics, controlling factors, formation stage, characterization of natural fracture distribution, distribution prediction, and evolutionary pattern of natural fractures are fundamental issues in the exploration and development of shale reservoirs [11,12,13,14,15]. Among them, tectonic fractures are controlled by regional structural stress or local stress [16]; therefore, the formation stages of tectonic fractures reflect changes in the geomechanical environment. Determining the formation stage of tectonic fractures can not only reflect the evolution stage of the preservation conditions of shale oil and gas but also help to conduct research on the coupling of enrichment and loss of oil and gas.
The key prerequisite for the correct development of shale oil and gas resources is understanding the distribution and causes of fractures [17]. Some studies characterized the distribution of fractures based on fractal theory and micro-CT [13,14,15]. In addition, numerical simulation also developed into a key tool for assessing the distribution and geometrical features of natural fractures, fluid action in fractures, and the interaction between natural fractures and hydraulic fractures [18,19,20,21,22]. Usually, the fracture cutting relationship of outcrops, cores, and sections is an intuitive and effective way to divide fracturing stages [23,24], but the multistage tectonic movement experienced by the Northeast Sichuan Basin undoubtedly increases the difficulty of analysis, especially for the outcrop fracture zone [12]. There is a specific internal connection between tectonic activity, fracture development and palaeofluid activity, and veins in shale fractures record important information about palaeofluid activity and fracture activity [25]. The captured fluid inclusion records the ancient temperature and pressure information [26], but part of the fluid inclusion phase transition is difficult to observe during temperature measurement; the carbon and oxygen isotopes of the filler can determine the fracture formation stage, but it is affected by the initial isotope composition of the hydrothermal fluid, the temperature of the mineral crystallization and precipitation, and the type of dissolved carbon in the hydrothermal fluid [27]. In addition, fractures usually have the characteristics of multistage genesis, reactivation, and filling. Each method or technology has limitations or multiple solutions [28]. Therefore, they are used to comprehensively assess the formation stage of fractures [12,17,29,30,31,32]. Although some research results indicate that it is difficult to use fracture examination as a method, it does provide valuable evidence that reveals previous strata deformation, stress orientations, and tectonic movements [32,33,34,35].
However, fractures exhibit characteristics that correspond to different tectonic movement periods, and studies on the development of fractures in multistage tectonic superposition states as well as their effects on oil and gas accumulation and production are still lacking. Here, we investigated the fracture characteristics of the Liangshan Formation in the Northeast Sichuan Basin through outcrops, cores, and thin sections, combined with fluid inclusion tests, carbon and oxygen isotope analysis, and the acoustic emission (AE) Kaiser effect. Afterwards, we investigated the genetic cause of multiperiod fractures and determined the period of fracture formation. Finally, multiphase genesis mechanisms were given, with matching regional burial history and tectonic evolutionary history. We also discussed the impact of fractures on the accumulation and production of oil and gas. This study contributes to a comprehensive understanding of the fracture evolution in the northeast Sichuan Basin and provides a theoretical basis for the exploration and development of shale oil and gas.

2. Geological Setting

Northeast Sichuan experienced the thrust and nappe of Micang Mountain and Daba Mountain towards the basin during the Mesozoic–Cenozoic period. Under this tectonic background, the Micang Mountain–Daba Mountain foreland basin was formed. The main body of the study area is located in the Northeast Sichuan foreland basin, which is part of a piedmont sag controlled by the Daba Mountain nappe belt and the Micang Mountain nappe belt. The western part of the sag is controlled by the northern section of the Longmenshan Fault, the southern part is blocked by the gentle structural belt in the central Sichuan Basin, and the southwestern part is connected with the western Sichuan depression (Figure 1a). Its structural trend is mainly northwest, with compressive and compressive reverse faults and a structural pattern of “two uplifts and one depression” in plan view [2].
In the Middle–Late Triassic period, with the closure of the Mianlue Ocean and the uplift of the Qinling orogenic belt, the marine sedimentary history ended in the main body of the Sichuan Basin, and the basin began to receive continental clastic deposition in the Late Triassic [36]. Among these deposits, the Jurassic system is widely distributed, and the strata are well developed. The system is a set of typical terrigenous clastic rock deposits dominated by delta-lake phases, with thicknesses of 1500 m–4000 m [37]. In the Northeast Sichuan Basin, the Jurassic system is in parallel unconformity with the underlying Triassic strata, gradually transitions to an angular unconformity towards the basin margin and is in unconformable contact with the overlying Lower Cretaceous strata; the Cretaceous and above strata in the region are severely eroded and less preserved. The Jurassic system contains the Ziliujing Formation (J1z), the Lianggaoshan Formation (J1l), the Shaximiao Formation (J2s), the Suining Formation (J3s), and the Penglaizhen Formation (J3p) sequentially from bottom to top. Herein, the Lianggaoshan Formation is mainly a set of fine-grained deposits with thicknesses of 50–150 m. According to lithological characteristics, it can be divided into an upper segment and a lower segment (Figure 1b). During the sedimentary period of the lower segment, the lake basin was in a wide-basin shallow-water oxidative environment, the depositional centre was located in the central–eastern part, and the lithology was mainly purple-red mudstone interbedded with grey-green siltstone; during the same period of the upper segment, the depositional centre gradually migrated to the northwest from bottom to top, developing multiple sets of organic-rich shale [2].

3. Samples and Experiments

3.1. Sample Source

We observed 645 sets of fractures (including fracture types, fracture strikes, fracture dip angles, fracture lengths, fracture densities, and cutting relationships between fractures) from seven large outcrops in the northeastern Sichuan Basin. The premise of our measurements and observations of outcrop fractures was to use the fresh surface of fractures to avoid natural weathering. For the fracture measurement results to accurately reflect the direction of multistage tectonic stress, the locations of the seven outcrops were scattered around the drillings (Figure 1a). We made similar observations about the fracture characteristics of seven drill cores in the northeastern Sichuan Basin, and the aperture and filling of fractures were also supplemented. The fracture strike parameters on the cores were derived from imaging logging. All experimental test samples were from cores.

3.2. Experimental Analyses

Microfracture characteristics were examined using a Leica polarizing microscope at the State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation in China (SKL) at a temperature of 24 °C and a relative humidity (RH) of 60%.
With a THMS600 heating stage installed on a Leica microscope, fluid inclusions were analysed at the Sichuan Coalfield Geology Bureau, and the uncertainty of temperature detection of the THMS600 heating stage was ±0.1 °C. During the temperature measurement process, the rate of temperature change in the THMS600 heating stage was controlled to within 0.1~5 °C/min, and the temperature when the inclusions were completely homogenized was observed and recorded. To ensure the reliability of the test results, the homogenization temperatures (Th) of each inclusion were tested three times, with each Th having absolute deviations of no more than 2 °C. The experimental test refers to the China oil and gas industry standards of Micro Temperature Measurement Methods of Fluid Inclusion in Sedimentary Basins (SY/T6010-2011).
The stable carbon and oxygen isotope experimental apparatus was the Delta V isotope ratio mass spectrometer (IRMS) from the Sichuan Coalfield Geology Bureau. The fracture fill sample material (approximately 0.1 mg) was placed into a reaction vessel to react with 100% orthophosphoric acid at 90 ± 1 °C in the Multi-Prep® system. The collected carbon dioxide was purified, and its δ13C and δ18O isotopic compositions were then determined by a gas isotope mass spectrometer, with precision exceeding ±0.2‰. Note that the isotopic analysis followed the Chinese oil and gas industry standards of the Analysis Method for Carbon and Oxygen Isotopes in Organic Matter and Carbonate (SY/T5238—2019). The O and C isotope compositions were represented as standard δ-notation relative to SMOW and PDB, respectively.
X-ray diffraction (XRD) was used to quantitatively analyse the mineral composition at the Sichuan Coalfield Geology Bureau. The samples were all pulverized into a fine powder (200 mesh) and then analysed with an Ultima IV X-ray diffraction with Cu Kα radiation (40 kV, 40 mA) at a scanning speed of 2 °/min and a testing angle range from 0° to 90°. The experimental test referred to the China oil and gas industry standards of Quantitative Analysis of Total Contents of Clay Minerals and Common Nonclay Minerals in Sedimentary Rocks by X-ray Diffraction (SY/T6201-1996).
The acoustic emission experiment adopted an MTS815 rock mechanics tester at the SKL. Selecting experimental samples from nonfractured sections and developed nonbedded sections prevented the influence of nontectonic stress factors on the results. The samples were placed on a rigid testing machine for uniaxial loading, and the loading speed was 15 kN/min. At the same time, the SAEU2S full waveform channel analyser was used to collect and obtain the relevant parameters. The test standards were GB/T 23561.7-2009, GB/T 23561.8-2009, and GB/T 23561.9-2009.

4. Results

4.1. Developmental Properties of Tectonic Fractures

4.1.1. Fracture Types

The results of core drilling and field tests revealed that fractures in the study area are dominantly tectonic fractures. When regional or local structural stress exceeds the rock strength, tectonic fractures are formed [16]. Shear fractures, tensile fractures, and interlayer slip fractures were the most prevalent tectonic fractures in the study area, according to mechanical characteristics.
The shear fractures had a specific direction and regularity (Figure 2a and Figure 3a,b). Meanwhile, the angles of fractures mostly intersected with the rock bedding at high degrees or perpendicular to the bedding, with obvious penetration (Figure 2b). For shear fractures with multiple series and conjugate intersections in the stratigraphic plane (Figure 2b), its acute bisector usually indicates the direction of maximum principal stress.
Affected by tensile stress, the tensile fractures were nearly vertical, and the seam surface was uneven and terminated at the bedding plane, forming intraformational fractures (<100 cm) (Figure 2c and Figure 3c,d). Additionally, low-degree and near-horizontal interlayer slip fractures, which are fractures parallel to layers formed under the action of shearing or sliding during tectonic extrusion, were widely formed in the shale. The surfaces of the fractures had obvious scratches, steps and other characteristics (Figure 3e,f), as well as weak or partial filling.
Tensile and shear fractures associated with larger faults in outcrops were visible near faults (Figure 2c–e). Their strikes were not unified, they intersected the section at a large angle or perpendicularly, and they were mostly filled with calcite or quartz. These fractures next to the fault were directly affected by local stress in the fault within a specific range and had nothing to do with the regional tectonic stress field [38,39].

4.1.2. Fracture Characterization

The measured results of seven fractures in outcrop showed that the shale fractures of the Lianggaoshan Formation had strong penetration ability, the lengths of fractures were mainly 0–200 cm, accounting for 69%, and the length of local fractures exceeded 500 cm (Figure 4a). The angles were mainly high-degree (>45°), accounting for 73% (Figure 4b), and the types of fractures were mostly high-degree shear fractures. The high-degree shear fractures in the study area had many cutting layers and were of large scale, which easily led to the loss of shale oil and gas, which was not conducive to its preservation and high yield.
The observation results of core fractures showed that the tectonic fractures in the study area had obvious developmental differences in the vertical and horizontal directions. Taking well PA1 as an example, the fracture density was vertically uneven, mainly concentrated in the upper segment, and mainly distributed in the thinner rocks (Figure 5). It was mainly related to the rock mineral composition in the vertical direction, and the quartz content generally had a good correspondence with the linear density of fractures.
The observation results of core-scale fractures in eight wells showed that the extension lengths of fractures were mainly in the range of 5 cm–15 cm, and there were a small number of fractures with a length of approximately 25 cm (Figure 6a). The angle of fractures was generally low, resulting in mainly interlayer slip fractures, which effectively reduced the penetration of fractures; these fractures were followed by high-degree fractures (Figure 6b). The aperture distribution of fractures was stable, with values mainly in the range of 0~2 mm. A total of 85.53% of the filler was filled by calcite, asphalt, pyrite, argillite and quartz, and calcite was the main filler (Figure 6d). Fractures that were fully filled with brittle minerals were conducive to the preservation of shale gas. Moreover, in the subsequent fracturing process, the brittle minerals that were filled in the fractures increased the brittleness of the shale, making the fractures easy to reactivate and fracture, thereby improving the fracturing effect [40], and 14.5% of the unfilled fractures were beneficial to the artificial fractures in the later stage of communication.

4.2. Fracture Formation Stages

4.2.1. Fracture Intersection Relationship and Strike Analysis

Fractures are in contact with each other, and their cutting relationship and geometry can be used to determine the formation stage of each other [41]. According to the fracture cutting of the field outcrop observation point and its restricted relationship, at least three phases of fractures were present in the study area (Figure 7), and the existence of X-shaped conjugate shear fractures in outcrops also helps to better evaluate the direction of the ancient stress field [42] (Figure 7c). We calculated statistics on the occurrence of more than 645 sets of tectonic fractures measured in the field, and the results showed that the strikes of the dominant fractures on the rock bedding plane of the outcrops were as follows: (1) WNW- and NNW-trending fractures, (2) ENE- and NNE-trending fractures, and (3) NW-trending fractures (Figure 8a). The fractures in (1) and (2) were all high-degree fractures perpendicular to the rock bedding, and they were X-shaped conjugate shear fractures. Additionally, the outcrop fracture results showed that the NW-trending fractures cut the fractures of other lineages, showing obvious characteristics of late formation. The staging results of fractures and the acute-angle bisector of X-shaped conjugate shear fractures reflected the characteristics of maximum horizontal stress. Therefore, our preliminary analysis suggested that the formation of the tectonic fractures in the study area corresponded to the formation of two sets of conjugate shear fractures under two phases of structural stress and, finally, the formation of NW shear fractures and cutting of the previously formed fractures.
The mutual cutting relationship of different fractures in the core and section can also reveal the formation stage of the corresponding fractures. The core from the study area contained at least three mutually cutting fractures, and the fractures that formed in the early stage were all interrupted in the late stage (Figure 9a). Sliding scratches along the layer in two directions were visible on the adjacent core (Figure 9b). According to the results of fractures interpreted by imaging logs in the study area, Lianggaoshan Formation shale fractures mainly developed in four groups, among which the NNE, ENE, and NW fractures were the most developed, followed by nearly SN fractures (Figure 8b). Compared with those in outcrops, the natural lines present in cores were fewer, but the dominant lines were consistent, and the natural fracture system of the core indicated at least three phases. Additionally, the microfractures of the Lianggaoshan Formation shale were mainly shear fractures, and there were at least two phases of fracture cutting and interlacing. Therefore, based on the comprehensive analysis of core and section fractures by stage, we concluded that the shale of the Lianggaoshan Formation in the Northeast Sichuan Basin should have developed at least three stages of fractures.

4.2.2. Fluid Inclusion Analysis

As the homogenization temperature of fluid inclusions in gas-liquid two-phase brine can usually represent the capture temperature of fluid inclusions, the homogenization temperature of fluid inclusions that formed was also measured, as the fracture filler can reveal the period of fracture formation. The samples of fluid inclusions that filled minerals in this study came from quartz and calcite veins that filled in tectonic fractures. Abundant fluid inclusions are visible in all samples, and the types were mainly hydrocarbon fluid inclusions and gas-liquid two-phase brine fluid inclusions. Hydrocarbon fluid inclusions were abundant in the samples, accounting for approximately 75% of the total fluid inclusions. The sizes of single-phase liquid hydrocarbon fluid inclusions were 4–22 μm; the shapes were ellipse, strip, triangle, etc. The fluid inclusions were mainly distributed in lines or bands along the healed mineral fractures, and they were blue and blue-white under fluorescence (UV) (Figure 10). The gas-liquid two-phase brine fluid inclusions were composed of gaseous hydrocarbons and brine solution, the overall development was less, and they accounted for approximately 25% of the total fluid inclusions. The sizes of fluid inclusions were 3~10 μm; the shapes were square, irregular, etc.; they were produced together with hydrocarbon fluid inclusions (Figure 10). We carried out microthermometry on the gas-liquid two-phase brine fluid inclusions in the quartz and calcite minerals in the veins of 10 sample fractures in the study area. The results showed that the homogenization temperatures of the associated two-phase brine fluid inclusions trapped in the quartz and calcite veins had three distribution intervals (Figure 11), i.e., 55–70 °C, 80–105 °C, and 110–140 °C, indicating that there were three phases of fluid activity and that the fractures were formed in three phases. In addition, the homogenization temperatures of inclusions from quartz cement were 5~15 °C lower than those from calcite.

4.2.3. Stable Carbon and Oxygen Isotope Analysis

Carbon and oxygen isotopes are significantly different in different subsurface environments. Through the determination of carbon and oxygen isotopes in the fracture filler, we calculated the formation stages of fractures [23]. We combined the fracture-filler stable isotope data from different well intervals in the Lianggaoshan Formation in the Northeast Sichuan Basin to analyse the fracture stages in the study area. The results of carbon and oxygen isotope measurements on 18 samples of tectonic fracture filler showed that the δ18O (PDB‰) values were between −13.3‰ and −6.65‰, the δ13C (PDB‰) values were between −19‰ and 4.53‰, and the δ18O (PDB‰) and δ13C (PDB‰) values in the filling minerals were quite different, showing the characteristics of multistage filling (Figure 12). We used the oxygen isotope thermometry equation proposed by Fritz and Smith (1970) to calculate the temperature at which the fractures formed in each sample [43]:
T = 31.9 − 5.55(δ18O − δ18Ow) + 0.7(δ18O − δ18Ow)2
where T is the temperature when the filling minerals formed, in °C; δ18O is the oxygen isotope value; δ18Ow is the oxygen isotope value of the water medium when minerals formed; the Northeast Sichuan Basin was a lacustrine sedimentary system, which is a freshwater environment, and the oxygen isotope value of the water medium is generally −10 ‰. By considering the surface temperature and geothermal gradient, we estimated the ancient burial depth of the fractures and, combined with the stratigraphic burial evolution of the basin, further limited the formation time of the tectonic fractures in each period. We calculated the burial depth of the fractures based on the study area’s perennial average surface temperature of 20 °C and a geothermal gradient of 2.2 °C/100 m. There are three partitions in the carbon-oxygen stable isotope distribution of the fracture filler (Figure 12). The δ18O values of partition I range from −18.37 to −17.5 ‰, and the equivalent depths are 4223 to 4882 m, with an average of 4553 m; the δ18O values of partition II range from −16.32 to −15.32 ‰, and the equivalent depths are 2784 to 3512 m, with an average of 3184 m; the δ18O values of partition III range from −14.5 to −13.4 ‰, the equivalent depths are 1584 to 2320 m, and the average is 1883 m.

4.2.4. Acoustic Emission Analysis

The main principle of acoustic emission is that the rock has a memory of the ground stress, and in a specific geological period, when the loading stress exceeds the rock stress, an acoustic emission effect occurs. The inflection point at the cumulative acoustic emission curve suddenly increases to become the Kaiser point. The Kaiser point can show the damage and deformation of the rock and corresponds to the palaeostress stage [43]. We can use the number of Kaiser points on the acoustic emission curve to determine the number of tectonic movements and fracture development stages experienced by rocks [43]. According to the characteristic parameters, such as the number of acoustic emission rings, event rate, and energy intensity received by the acoustic emission detection system, we established the relationship between the loading time and the characteristic parameters of acoustic emission (Figure 13). The acoustic emission curve and calculation test result table show that the sample had four obvious Kaiser effect points, excluding the influence of in situ stress, which shows that the Lianggaoshan Formation experienced three major tectonic movements since its deposition (Figure 13). Therefore, the formation of shale fractures in the Lianggaoshan Formation in Northeast Sichuan mainly underwent three stages.

5. Discussion

5.1. Factors Controlling Fracture Development

5.1.1. Structural Factors

Different structural locations are the key factors leading to the differential development of tectonic fractures, and there are specific differences in the distribution of stress in different parts, which makes the development of tectonic fractures in different parts different. For the parts where the structural stress is concentrated, the scale and development of tectonic fractures are larger. The statistical results of strike-slip faults, inverse faults, and fracture density near the core of the anticline in the study area show that as the distance from the fracture and the core of the anticline increased, the fracture density gradually decreased, and when a specific distance was reached, the fracture density changed steadily (Figure 14). Strike-slip faults have a larger control over fracture size than thrust faults. The former had a more obvious control on the formation of tectonic fractures in Jurassic shale. In addition, the fracture density of the hanging wall of the thrust fault was much higher than that of the footwall; the average fracture density of the hanging wall was 11.7 fracs/m, and the average fracture density of the footwall was 6.4 fracs/m (Figure 14a). In addition, the study of microfractures in the Jurassic Ziliujing Formation showed that the microfractures in the fault–fold zone and the high–steep zone accounted for 40%–90% of the total pore volume, and the microfractures in the underdeveloped areas accounted for approximately 10% of the total pore volume [44].

5.1.2. Nonstructural Factors

The layered characteristics of shale were obvious because there were specific differences in rock mechanical properties between adjacent layers of layered shale. Tensile fractures are mainly developed in shale formations with relatively high brittleness, and the fractures are perpendicular to the bedding, have good equidistance in the same layer, and terminate on the bedding plane [44,45]. According to the statistical analysis of the densities of tensile fractures, shear fractures and bedding-slip fractures and formation thickness in the study area, it can be concluded that the formation thickness has a significant impact on the development of tensile fractures. Within a specific thickness range, the greater the thickness of the rock mechanical layer is, the lower the density of tensile and shear fractures (Figure 15a). However, bedding-slip fractures had no obvious relationship with formation thickness (Figure 15a). Bedding-slip fractures are caused by horizontal structural stress and formed on the weak plane between layers; therefore, the thickness of the mechanical layer has little effect on these fractures. The optimum shale formation thickness is conducive to the preservation of Jurassic shale oil and gas. However, if the shale formation thickness is too thick and fracture development is low, it is not favourable for the migration and preservation of oil and gas or hydraulic fracturing in the development stages. In contrast, if the shale formation thickness is too thin, fracture development results in unfavourable preservation conditions [46].
The mineral composition of shale is different, and its rock mechanical properties and brittleness are different, which, in turn, affects the development of tectonic fractures in shale. For shale, the higher the content of brittle minerals is, the greater the brittleness [47]. The brittle minerals in the Lianggaoshan Formation shale reservoir were mainly clay and quartz, followed by clay, feldspar, and carbonate minerals (Table 1). Quartz is usually more important than carbonate for shale brittleness, and if the content of carbonate minerals is very low, the mechanical properties of rocks are mainly reflected by the quartz content [48]. Therefore, the effect of minerals on the fractures of the Lianggaoshan Formation mainly depends on the quartz content. The tectonic fracture statistics and mineral composition analysis of the core from the study area showed that the density of tectonic fractures in the Lianggaoshan Formation shale was positively correlated with the quartz content (Figure 15b). Under the same structural stress, shale with a higher degree of brittleness bears less strain before rupture, and so, it is more favourable for shale to rupture and form tectonic fractures [45]. Note that Dong et al. (2017) suggested that not all quartz can affect shale brittleness, and only authigenic quartz has a significant positive correlation with brittleness [49]. We did not effectively distinguished between authigenic quartz and terrigenous clastic quartz, and so, whether there are differences in the effects of different types of quartz on fractures in the Lianggaoshan Formation still needs further study.

5.2. Matching the Development Stages of Tectonic Fractures with the Tectonic Evolutionary History

When rocks were fractured due to structural stress, formation water entered the fractures, and crystalline minerals were separated from the fluid and precipitated between the fracture walls. Therefore, the fluid inclusion and isotope features of the fracture filler can be used to efficiently analyse the fracture phase [29]. Through the fracture cutting relationship of outcrops, cores, and sections, combined with fluid inclusions that had a uniform temperature as part of fill minerals, carbon and oxygen isotope analysis of the filler and acoustic emission stage experimental results matching the burial evolutionary history, we can determine the formation period of the fractures of the Lianggaoshan Formation in Northeast Sichuan. The first stage was the Late Yanshan–Early Himalayan tectonic movement (72~55 Ma), and the Late Cretaceous Xuefeng intracontinental orogeny system was part of the NW-trending extension deformation tectonic activity [50]. The study area was affected by far-field compressive stress and SE extrusion and structural stress, from a maximum depth to uplift and denudation; this activity formed the first phase of WNW-NNW-trending conjugate shear fractures, filler-captured fluid inclusions had normalized temperatures within 110~140 °C, and the depths of the Lianggaoshan Formation in this stage were 4223~4882 m (Figure 16). The second stage was Himalayan tectonic movement (48~32 Ma), and the extrusion from the NE that extended to the horizontal structure of the Micang–Daba Mountain thrust nappe zone resulted in local dextral shearing characteristics [51,52]. During this stage, the study area was continuously affected by the compressive stress from the NE to form ENE and NNE conjugate shear fractures, and the filler-captured fluid inclusion normalized temperatures were within 80~105 °C. The depths of the Lianggaoshan Formation in this stage were 2784~3512 m (Figure 16). The third stage was late Himalayan tectonic movement (15 Ma~4 Ma). The study area continued to be affected by the continuous structural stress from NE of the Dabashan arcuate structural belt [51,52,53], leading to local fold deformation in the Lianggaoshan Formation and NW shear fractures approximately perpendicular to the principal stress direction at the local structural high, with filler-captured fluid inclusion normalized temperatures within 55~70 °C. The depths of the Lianggaoshan Formation in this stage were 1584~2320 m (Figure 16).

5.3. Effect of Fractures on Hydrocarbon Accumulation or Production

The fractures of the Lianggaoshan Formation have a positive impact on the enrichment and production of shale oil and gas. Figure 17a,b show that if the fracture was in a suitable range, the fracture density had a good positive correlation with the total hydrocarbon and light hydrocarbon contents of gas logging, and their correlations were 0.76 and 0.86, respectively. Obvious pale yellow fluorescence was visible in the areas with fractures, and oil film was also visible in the areas with fractures. These areas had better oil-bearing properties. In addition, Figure 18 shows that there was obvious crude oil enrichment at microfractures, and the oil and gas enrichment was much higher than the enrichment in shale pores. At the same time, they greatly improved the connectivity of shale. In terms of oil and gas production, the existence of fractures reduced the tensile strength of the rock itself [54]. Thus, the shale section was more likely to break during hydraulic fracturing. Therefore, there was a good negative correlation between fracture density and breakdown pressure (Figure 18).

5.4. Research Prospects

Our comprehensive geomechanics and geochemical research methods limit the formation period of Jurassic tectonic fractures and preliminarily evaluate the factors influencing tectonic fractures. This study provides theoretical guidance for subsequent fracture prediction and shale oil and gas enrichment process research. However, nontectonic fractures, such as hydrocarbon-generating overpressure fractures and hydraulic fractures, have not been further studied. It is not clear what role these fractures play in oil and gas enrichment and production. U–Pt dating can be used to more accurately determine the formation time of fractures and fluid activities and the relationship between them. Our fracture sampling was obtained from a limited number of drillings and outcrops in a specific area, and it was impossible to directly measure all fractures in the reservoir. Therefore, the distribution characterization of natural fractures was the focus of subsequent research, which is helpful for fracture prediction.

6. Conclusions

  • Three types of tectonic fractures were developed in the Lianggaoshan Formation in the northeastern Sichuan Basin: shear fractures, tensile fractures, and slip fractures. The tectonic fractures were mainly angular interlayer slip fractures. Fractures were filled by calcite, asphalt, pyrite, argillite, and quartz, and only 14.5% were not filled.
  • The fractures of the Lianggaoshan Formation were mainly affected by the structure, thickness, and mineral composition. The density of fracture growth rapidly decreases as the distance between the fault and the fold core increased, while the fracture density changed steadily over a particular distance. In addition, strike-slip faults had a stronger effect on fractures than thrust faults. With an increase in layer thickness, the density of tensile fractures and shear fractures decreased, while that of interlayer slip fractures was not significantly impacted. Quartz was conducive to the formation of fractures, but the influence of different quartz types on fractures still needs further study.
  • The fractures of the Lianggaoshan Formation were generated in three stages during uplift: (1) Late Yanshan–Early Himalayan tectonic movement (72~55 Ma), wherein WNW-NNW conjugate shear fractures were generated, the normalized temperatures of filler-captured fluid inclusions were 110~140 °C, and the depths of the Lianggaoshan Formation in this stage were 4223~4882 m; (2) Middle Himalayan tectonic movement (48~32 Ma), wherein ENE-NNE conjugate shear fractures were generated, the normalized temperatures of filler-captured fluid inclusions were 80~105 °C, and the depths of the Lianggaoshan Formation in this stage were 2784~3512 m; (3) Late Himalayan tectonic movement (15 Ma~4 Ma), wherein a set of NW shear fractures were generated alone, the normalized temperature of filler-captured fluid inclusions were 55~70 °C, and the depths of the Lianggaoshan Formation in this stage were 1584~2320 m.
  • The existence of fractures greatly improved the oil and gas storage capacity and increased the contents of free and total hydrocarbons. At the same time, they also reduced the rock strength and further reduce the breakdown pressure of the strata.

Author Contributions

Conceptualization, X.B. and H.D.; writing—original draft preparation, Y.L., A.L. and S.L.; writing—review and editing, H.C., L.W. and F.C.; supervision, J.H.; resources, Z.W.; data curation, X.W.; investigation, Y.Z. All authors have read and agreed to the published version of the manuscript.

Funding

This research was supported by the National Natural Science Foundation of China (42072182): study on the mechanical mechanism of particle deformation and displacement alignment during shale page rationalization.

Data Availability Statement

Not applicable.

Conflicts of Interest

The authors declare no conflict of interest.

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Figure 1. Location and stratigraphic histogram of the Northeast Sichuan Basin. (a) Regional location, LMFTB = Longmen Mountain fold-and-thrust belt, DBFTB = Daba Mountain fold-and-thrust belt, QUFTB = Qiyue Mountain fault–fold belt, MCU = Micang Mountain Uplift, NSD = North Sichuan Depression, CSGFB = Central Sichuan Gentle Structural Belt, ESHFB = Eastern Sichuan High and Steep Structural Belt, RS = Rongshan Profile, JX = Jinxi Profile, QT = Qiaoting Profile, TX = Tiexi Profile; GJ = Gujun Profile; QLX = Qilixia Profile; SH = Sanhui Profile; (b) Lianggaoshan Formation stratigraphic histogram.
Figure 1. Location and stratigraphic histogram of the Northeast Sichuan Basin. (a) Regional location, LMFTB = Longmen Mountain fold-and-thrust belt, DBFTB = Daba Mountain fold-and-thrust belt, QUFTB = Qiyue Mountain fault–fold belt, MCU = Micang Mountain Uplift, NSD = North Sichuan Depression, CSGFB = Central Sichuan Gentle Structural Belt, ESHFB = Eastern Sichuan High and Steep Structural Belt, RS = Rongshan Profile, JX = Jinxi Profile, QT = Qiaoting Profile, TX = Tiexi Profile; GJ = Gujun Profile; QLX = Qilixia Profile; SH = Sanhui Profile; (b) Lianggaoshan Formation stratigraphic histogram.
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Figure 2. Characteristics of the tectonic fractures of the Lianggaoshan Formation indicated by outcrops: (a) vertical through-strata shear fractures in the Qiaoting Profile of the Lianggaoshan Formation; (b) conjugate shear fractures in the Jinxi Profile; (c) positive flower-shaped strike-slip faults, which control fracture development, in the Rongshan Profile of the Lianggaoshan Formation (Red solid line: fault; Yellow dotted line: fractures); (d) low-degree thrust faults, which control fracture development, in the Gujun Profile of the Lianggaoshan Formation (Red solid line: fault; Yellow dotted line: fractures); (e) high-degree thrust faults, which control fracture development, in the Gujun Profile of the Lianggaoshan Formation (Red solid line: fault; Dotted lines of different colors: fractures with different strikes).
Figure 2. Characteristics of the tectonic fractures of the Lianggaoshan Formation indicated by outcrops: (a) vertical through-strata shear fractures in the Qiaoting Profile of the Lianggaoshan Formation; (b) conjugate shear fractures in the Jinxi Profile; (c) positive flower-shaped strike-slip faults, which control fracture development, in the Rongshan Profile of the Lianggaoshan Formation (Red solid line: fault; Yellow dotted line: fractures); (d) low-degree thrust faults, which control fracture development, in the Gujun Profile of the Lianggaoshan Formation (Red solid line: fault; Yellow dotted line: fractures); (e) high-degree thrust faults, which control fracture development, in the Gujun Profile of the Lianggaoshan Formation (Red solid line: fault; Dotted lines of different colors: fractures with different strikes).
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Figure 3. Characteristics of tectonic fractures of the Lianggaoshan Formation, as indicated by the core: (a) high-degree shear fractures semifilled with calcite, well YS6, 1752.11 m; (b) high-degree unfilled shear fractures, well YS6, 1650.41 m; (c) tensile fractures semifilled with calcite, well YY1, 2009.76 m; (d) tensile fractures semifilled with calcite, well YS1, 2006.41 m; (e) interlayer slip fractures, with obvious scratches, well YS6, 1718.18 m; (f) interlayer slip fractures with smooth, mirror-like surfaces on the seam surface, well YS6, 1658.31 m.
Figure 3. Characteristics of tectonic fractures of the Lianggaoshan Formation, as indicated by the core: (a) high-degree shear fractures semifilled with calcite, well YS6, 1752.11 m; (b) high-degree unfilled shear fractures, well YS6, 1650.41 m; (c) tensile fractures semifilled with calcite, well YY1, 2009.76 m; (d) tensile fractures semifilled with calcite, well YS1, 2006.41 m; (e) interlayer slip fractures, with obvious scratches, well YS6, 1718.18 m; (f) interlayer slip fractures with smooth, mirror-like surfaces on the seam surface, well YS6, 1658.31 m.
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Figure 4. Outcrop-scale fracture parameter distribution.(a) Length distribution histogram; (b) Dip-angle distribution histogram.
Figure 4. Outcrop-scale fracture parameter distribution.(a) Length distribution histogram; (b) Dip-angle distribution histogram.
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Figure 5. Longitudinal distribution characteristics of fractures (linear density, dip angle, length, and fracture strike) in the PA1 well.
Figure 5. Longitudinal distribution characteristics of fractures (linear density, dip angle, length, and fracture strike) in the PA1 well.
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Figure 6. Drill core-scale fracture parameter distribution. (a) Length distribution frequency of fractures; (b) dip angle distribution of fractures; (c) aperture distribution of fractures; (d) filling and proportion of fractures.
Figure 6. Drill core-scale fracture parameter distribution. (a) Length distribution frequency of fractures; (b) dip angle distribution of fractures; (c) aperture distribution of fractures; (d) filling and proportion of fractures.
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Figure 7. Characteristics of fracture development in Lianggaoshan Formation outcrops: (a) Tiexi Profile (The fractures represented by Roman number I were first formed, followed by II, and finally by III); (b) Jinxi Profile; (c) Qiaoting Profile; (d) Gujun Profile.
Figure 7. Characteristics of fracture development in Lianggaoshan Formation outcrops: (a) Tiexi Profile (The fractures represented by Roman number I were first formed, followed by II, and finally by III); (b) Jinxi Profile; (c) Qiaoting Profile; (d) Gujun Profile.
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Figure 8. Fractures identified in the field (a) and by image logs (b) on rosette diagrams. (Roman numerals and black and red arrows represent the compression direction, they are inversed by conjugate shear fractures).
Figure 8. Fractures identified in the field (a) and by image logs (b) on rosette diagrams. (Roman numerals and black and red arrows represent the compression direction, they are inversed by conjugate shear fractures).
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Figure 9. Cutting relationship of core- and section-scale fractures: (a) three phases of fractures cut each other, and the late fractures are broken by early fractures, well PY1, 3087.57 m (The fractures represented by Roman number I were first formed, followed by II, and finally by III); (b) bedding-slip fractures, with scratches in both directions, well YS6, 1660.57 m; (c) two phases of fractures cut each other, and the late cuts the early, well PY1, 3084.12 m (orientation of the thin sections: vertical; the fractures represented by Roman number I were first formed, followed by II); (d) two phases of fractures cut each other, and the early fractures are broken by late fractures, well YY1, 2002 m (orientation of the thin sections: vertical; the fractures represented by Roman number I were first formed, followed by II).
Figure 9. Cutting relationship of core- and section-scale fractures: (a) three phases of fractures cut each other, and the late fractures are broken by early fractures, well PY1, 3087.57 m (The fractures represented by Roman number I were first formed, followed by II, and finally by III); (b) bedding-slip fractures, with scratches in both directions, well YS6, 1660.57 m; (c) two phases of fractures cut each other, and the late cuts the early, well PY1, 3084.12 m (orientation of the thin sections: vertical; the fractures represented by Roman number I were first formed, followed by II); (d) two phases of fractures cut each other, and the early fractures are broken by late fractures, well YY1, 2002 m (orientation of the thin sections: vertical; the fractures represented by Roman number I were first formed, followed by II).
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Figure 10. Micrographs of fluid inclusions captured by veins in the Lianggaoshan Formation in the Northeast Sichuan Basin: (a) hydrocarbon-bearing brine inclusions distributed in calcite, 1699 m, well YY1, single polarized light; (b) hydrocarbon-bearing brine inclusions distributed in calcite, 3077.57 m, well PY1, single polarized light; (c) hydrocarbon-containing brine fluid inclusions distributed in quartz, 3089.93 m, well PY1, single polarized light; (d) densely distributed hydrocarbon inclusions in calcite, 1699 m, well YY1, fluorescence; (e) densely distributed hydrocarbon inclusions in calcite, 3077.57 m, well PY1, fluorescence; (f) densely distributed hydrocarbon inclusions in quartz, 3089.93 m, well PY1, fluorescence.
Figure 10. Micrographs of fluid inclusions captured by veins in the Lianggaoshan Formation in the Northeast Sichuan Basin: (a) hydrocarbon-bearing brine inclusions distributed in calcite, 1699 m, well YY1, single polarized light; (b) hydrocarbon-bearing brine inclusions distributed in calcite, 3077.57 m, well PY1, single polarized light; (c) hydrocarbon-containing brine fluid inclusions distributed in quartz, 3089.93 m, well PY1, single polarized light; (d) densely distributed hydrocarbon inclusions in calcite, 1699 m, well YY1, fluorescence; (e) densely distributed hydrocarbon inclusions in calcite, 3077.57 m, well PY1, fluorescence; (f) densely distributed hydrocarbon inclusions in quartz, 3089.93 m, well PY1, fluorescence.
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Figure 11. Homogenization temperature distribution of fluid inclusions captured by the tectonic fracture filler in the Lianggaoshan Formation in the Northeast Sichuan Basin.
Figure 11. Homogenization temperature distribution of fluid inclusions captured by the tectonic fracture filler in the Lianggaoshan Formation in the Northeast Sichuan Basin.
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Figure 12. Stable carbon and oxygen isotopes of tectonic fracture filler in the Lianggaoshan Formation in the Northeast Sichuan Basin (I, II, and III represent the partitions of stable carbon and oxygen isotopes).
Figure 12. Stable carbon and oxygen isotopes of tectonic fracture filler in the Lianggaoshan Formation in the Northeast Sichuan Basin (I, II, and III represent the partitions of stable carbon and oxygen isotopes).
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Figure 13. Rock acoustic emission events of the Lianggaoshan Formation in the Northeast Sichuan Basin (I, II, III, IV are the Kaiser points corresponding to the samples).
Figure 13. Rock acoustic emission events of the Lianggaoshan Formation in the Northeast Sichuan Basin (I, II, III, IV are the Kaiser points corresponding to the samples).
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Figure 14. Fracture density controlled by different structural positions. (a) The relationship between fracture density and the distance from the fault plane, the histogram in the Figure 14 (a) is the comparison of fracture density between the hanging wall and the footwall of the reverse fault; (b) the relationship between fracture density and the distance from the axial plane.
Figure 14. Fracture density controlled by different structural positions. (a) The relationship between fracture density and the distance from the fault plane, the histogram in the Figure 14 (a) is the comparison of fracture density between the hanging wall and the footwall of the reverse fault; (b) the relationship between fracture density and the distance from the axial plane.
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Figure 15. (a) Fracture densities under different formation thicknesses; (b) Fracture densities under different quartz contents.
Figure 15. (a) Fracture densities under different formation thicknesses; (b) Fracture densities under different quartz contents.
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Figure 16. The outcrop burial history of the Lianggaoshan Formation in the Northeast Sichuan Basin (Red-dotted lines: Temperature of the strata; Blue lines: The horizontal and vertical blue lines determine the average formation time and buried depth of the three-stage fractures).
Figure 16. The outcrop burial history of the Lianggaoshan Formation in the Northeast Sichuan Basin (Red-dotted lines: Temperature of the strata; Blue lines: The horizontal and vertical blue lines determine the average formation time and buried depth of the three-stage fractures).
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Figure 17. (a) Relationship between fracture density and light hydrocarbons; (b) relationship between fracture density and total hydrocarbons in gas logging; (c) relationship between fracture density and fracture pressure.
Figure 17. (a) Relationship between fracture density and light hydrocarbons; (b) relationship between fracture density and total hydrocarbons in gas logging; (c) relationship between fracture density and fracture pressure.
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Figure 18. (a) Fracture surface after fluorescence irradiation, YQ1 well, 1420.70 m; (b) fracture surface after fluorescence irradiation, YQ1 well, 1421.10 m; (c) core slices containing fractures, Well PA1, 3002.9 m (orientation of the thin sections: bed-parallel); (d) three-dimensional distribution characteristics of oil and gas components in figure panel c; (e) thin core with fractures, YQ1 well, 1418.95 m (orientation of the thin sections: vertical); (f) distribution characteristics of oil and gas components in the plane of figure panel f; (g) three-dimensional oil and gas distribution characteristics of figure panel e; (h) thin core with fractures, well YQ1, 1421.65 m (orientation of the thin sections: vertical); (i) distribution characteristics of plane oil and gas components in figure panel h; (j) three-dimensional oil and gas distribution characteristics of figure panel h. (Red in the figures is the light hydrocarbon component, blue is the heavy hydrocarbon component, and grey is the particle skeleton).
Figure 18. (a) Fracture surface after fluorescence irradiation, YQ1 well, 1420.70 m; (b) fracture surface after fluorescence irradiation, YQ1 well, 1421.10 m; (c) core slices containing fractures, Well PA1, 3002.9 m (orientation of the thin sections: bed-parallel); (d) three-dimensional distribution characteristics of oil and gas components in figure panel c; (e) thin core with fractures, YQ1 well, 1418.95 m (orientation of the thin sections: vertical); (f) distribution characteristics of oil and gas components in the plane of figure panel f; (g) three-dimensional oil and gas distribution characteristics of figure panel e; (h) thin core with fractures, well YQ1, 1421.65 m (orientation of the thin sections: vertical); (i) distribution characteristics of plane oil and gas components in figure panel h; (j) three-dimensional oil and gas distribution characteristics of figure panel h. (Red in the figures is the light hydrocarbon component, blue is the heavy hydrocarbon component, and grey is the particle skeleton).
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Table
Table 1. The mineral composition of the Lianggaoshan Formation in the northeastern Sichuan Basin (Above each line is the range of mineral content, and below is the average value of mineral content).
Table 1. The mineral composition of the Lianggaoshan Formation in the northeastern Sichuan Basin (Above each line is the range of mineral content, and below is the average value of mineral content).
Well
(Number)		Quartz (%)Feldspar
(%)		Calcite (%)Dolomite (%)Pyrite (%)Clay
(%)
PA122.4–60.17.2–28.80.4–13.71.1–3.20.9–2.212.2–52.1
(92)44.312.24.91.81.334.2
YS528.9–40.72–120–21.90–2.80–3.636.3–58.1
(15)33.66.210.20.72.147.2
YS128.4–57.72.1–21.30–8.7/0.7–1.837.9–62.5
(23)36.19.53.51.248.1
YS524.6–58.20–2.70–23.80–2.6/29.3–48.6
(17)42.51.2170.735.3
YS825.8–62.30.2–8.72.1–27.60–2.70–1.326.8–52.1
(19)47.54.612.30.30.332.2
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Bai, X.; Wang, X.; Wang, Z.; Deng, H.; Li, Y.; Li, A.; Cao, H.; Wang, L.; Zhu, Y.; Lu, S.; et al. Characteristics and Evolution of Tectonic Fractures in the Jurassic Lianggaoshan Formation Shale in the Northeast Sichuan Basin. Minerals 2023, 13, 946. https://doi.org/10.3390/min13070946

AMA Style

Bai X, Wang X, Wang Z, Deng H, Li Y, Li A, Cao H, Wang L, Zhu Y, Lu S, et al. Characteristics and Evolution of Tectonic Fractures in the Jurassic Lianggaoshan Formation Shale in the Northeast Sichuan Basin. Minerals. 2023; 13(7):946. https://doi.org/10.3390/min13070946

Chicago/Turabian Style

Bai, Xuefeng, Xiandong Wang, Zhiguo Wang, Hucheng Deng, Yong Li, An Li, Hongxiu Cao, Li Wang, Yanping Zhu, Shuangfang Lu, and et al. 2023. "Characteristics and Evolution of Tectonic Fractures in the Jurassic Lianggaoshan Formation Shale in the Northeast Sichuan Basin" Minerals 13, no. 7: 946. https://doi.org/10.3390/min13070946

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