Abstract
Tight sand is an important unconventional reservoir. Aiming at the problem of large unused reserves and the poor development effect of Chang 63 reservoir, this paper researches reunderstanding reservoir and evaluating unused reserves. Employing rock slice and scanning electron microscope (SEM), the experiment of low-field nuclear magnetic resonance (NMR), water-oil relative permeability experiment, reservoir space, movable fluid, and oil-water seepage characteristics was studied. The factors affecting NMR cutoff, controlling factors of movable fluids, and controlling factors of displacing efficiency in tight sandstone reservoirs are discussed. The study demonstrates that (1) the mean pore volume and permeability are 4.4% and 0.068 mD, respectively. The reservoir pertains to tight sandstone, mainly intergranular pore and dissolution pore, and the intercalated materials are mainly chlorite and illite. (2) The characteristic of the NMR spectrum has bimodal characteristics and can be subdivided into two classes: left peak dominant and right peak dominant. The mean value of mobile fluid saturation was 17.9%. (3) According to the relative permeability curve pattern, it is divided into four categories, and the mean bound water saturation is 29.9%. The average irreducible oil saturation was 40.6%. The mean oil flooding efficiency was 40.2%. (4) The better the pore-throat relationship, the lower the cutoff, the stronger ability of the fluid migration ability, and the higher of a percentage of active fluid. The percentage of active fluid in a low-permeability reservoir is affected by the reservoir’s physical property and pore structure.
1. Introduction
With the quick increase in gas and oil energy consumption, conventional oil and gas energy sources are gradually depleted, and exploration and development are also increasing from usual reservoirs to low-permeability storage layers and then to compact sandstone reservoirs [1–5]. Compact sandstone reservoirs, as unconventional reservoirs, have gradually changed into a vital target for increasing gas-oil reserves and production [6–10]. Tight sandstone reservoirs are characterized by variable reservoir space types, complex pore structures, and mainly micro- and nanoscale pore throats, resulting in relatively complex fluid occurrence characteristics. The quantity and occurrence characteristics of active fluid are important for the evaluation of pore tortuosity-connectivity and calculation of the available reserves. This serious conditions the accurate evaluation and efficient exploitation of such reservoirs [11–16].
Through the investigation of domestic and foreign literature, it is found that there are many methods to study the porosity texture of compact sandstone reservoirs; meanwhile, by mercury penetration experiment and NMR test, the multiscale pore-porous distribution in compact sandstone reservoirs can be better obtained [17–28]. In recent years, researches on movable fluids in compact sandstone reservoirs are mainly focused on the evaluation of the saturation of movable fluids [17], while few studies on their occurrence characteristics in pores [12–21]. NMR and centrifugal tests can be utilized to better explore the content and reserve of movable fluid in compact sandstone reservoirs [22–32]. The study of compact sandstone reservoirs mainly focuses on pore structure and movable fluid. Compared with the study of these two aspects, the oil-water permeability experiment can reflect the flow situation under the coexistence of oil-water two phases; the obtained relative coefficient of permeability, bound water content, and irreducible oil content are more accessible to the real producing specificity [19, 32–35].
The exploration and development of the Baibao area have gone through three stages: a Jurassic reservoir, an upper reservoir of the Yanchang Formation, and a middle lower reservoir of the Yanchang group. Among them, the prospection and exploitation of the Chang 6 layer have become essential for the development of the Changqing Petroleum Enterprise. The production of the Chang 63 reservoir in the Baibao oilfield varies greatly, and the fluid distribution is complex. Therefore, the movable fluid of the Chang 63 reservoir in the Baibao oilfield is studied.
Therefore, this paper chose the Chang 63 reservoir as the research object in the Baibao oilfield of Ordos Basin based on a detailed study of reservoir geological characteristics using the instrumentation of rock slice, SEM, low-field NMR, and water-oil relative coefficient of permeability. The reservoir micropore structure, movable fluid distribution law, oil-water percolation, and oil flushing efficiency were studied, which provided a basis for comprehensive evaluation of the reservoir. Meanwhile, this research guides oil-gas investigation and exploitation in compact sandstone reservoirs.
2. Geology Setting
The Erdos Basin belongs to a Mesozoic-Cenozoic basin, distributed in five prefectures, with a total acreage of km2. Baibao is located in Wuqi prefecture, Shaanxi Province, and Huachi prefecture, Gansu Province, and is subordinate to the loess plateau landform (Figure 1(a)). Lie in the south of Yishan clivus, with gentle west-dip monoclinic, is the dip angle of which is less than one degree. The nose-shaped uplift formed by differential compaction is locally developed, and its axis is near the east-west or northeast [6–8]. The stratum from top to bottom in this area includes Quaternary, Tertiary, Lower Cretaceous (Zhidan Formation), Jurassic (Anding, Zhiluo, Yan’an, and Fuxian Formations), and Triassic Yanchang Formation (Figure 1(b)). The main oil-bearing stratum is the Triassic Yanchang Formation, which is further divided into 10 oil formations. The main oil-bearing layers are Chang 8, Chang 6, Chang 4+5, etc., among which Chang 6 reservoir is a major oil-producing stratum of Baibao area of Changqing oilfield, and its sedimentary environment is an inland lacustrine delta sedimentary environment dominated by clastic rocks (Figure 1(b)) [15, 19, 31, 32]. The data of developed blocks show that the sand bodies in this area are widely distributed, the thickness of oil reservoirs is large, there is a strong reservoir heterogeneity and poor physical properties, the oil level is different, the horizontal change is fast, the oil production is low, the oil output decreases quickly after the oil output is put into operation, and the influencing factors of the production are complex. Compared with other developed dense reservoirs in the Ordos Basin, they have more compact lithology and finer pore throats. Feldspar sandstone and lithic feldspar sandstone are the main clay minerals in the reservoir, and rock bump constituents are mainly feldspar and quartz. The study of the reservoir and active fluid features has an important meaning for sustainable exploitation in the oilfield.
(a)
(b)
3. Methods
A series of analytical tests was performed on a 63-stage plug sample (diameter 2.5 cm and length 3 cm) drilled from coring wells in the study area. These test analyses mainly include conventional porosity-permeability measurement, casting slice identification, back-scatter electron microscope test, oil-water phase permeability test, and low-field NMR test.
The measurement instrument is the CM-300, porosity measurement is the volume method, and permeability is the measurement of air permeability, mainly to evaluate the accumulated ability and seepage characteristic; the test criterion is SY/T5336-2006.
3.1. Casting Thin Section
The rock mineral composition and pore configuration characteristics of the reservoir can be observed by casting thin slices. First, the core samples are ground to 0.03 mm and then fixed on the slide, and the rock pores are filled with red or blue resin. The pore space class and sizes of the reservoir are studied under the microscope, and the distribution and combination features of each class of pores are analyzed.
3.2. Scanning Electron Microscope
To investigate the composition of clay minerals in the rock and its distribution characteristics in pores, 20 blocks were elected for SEM analysis. Firstly, the fresh section of the specimen was plated with gold, and then, the experiment was carried out by a scanning electron microscope (JSM-5500LV) and an X-ray energy spectrometer (QUANTAX400) according to SY/T5162-2014 standard. Analyze the distribution characteristics of different types of clay minerals.
3.3. Nuclear Magnetic Resonance
The relaxation characteristics of low-field NMR can be applied to calculate the reservoir porosity, permeability, and content of bound fluid and active fluid and study the characteristics of pore texture of the reservoir strata. The detailed experimental process is as follows: the diameter of the plunger sample is 25 mm, and a length of 40 mm is drilled from the core. Wash the sample with oil and salt, and measure the permeability of the standard core after drying. Use a vacuum pump to vacuum the core sample, and then saturate the core sample with formation water. spectra of saturated formation water and centrifuged cores are measured to obtain the cutoff value and movable fluid characteristics. The equipment is Niumay mini-NMR, with an echo interval of 0.1 ms, waiting time of 2 s, temperature of 25°C, field strength of 0.5 T, scanning times of 128 times, and echo times of 10,000 times.
3.4. Relative Permeability Experiment
The permeability of the oil-water phase is measured by the unsteady-state method and tested according to the industry standard SY/T5345-2007. Micropumps select 100DX high-accuracy and high-pressure volumetric pumps. Firstly, the sample is vacuumed and dried, and then, the porosity and permeability are measured to calculate the efficient pore cubage. The plunger sample is first vacuumed and then saturated with the original formation water, and the salinity is 60,000 mg/L. Load the core into the core clamper and connect it to the test system. When the temperature rises to 65°C, the simulated oil (viscosity 51.6 MPa·s) is infused into the samples, measuring the volume of discharged water and calculating water saturation. Water displacement is carried out with a fixed rate of flow of 0.05 mL/min. During the displacement process, measure the content of oil and water at the outlet until no oil flows out at the outlet, end the experiment, and calculate the remaining oil saturation in the core sample.
4. Results
4.1. Characteristics of Reservoir Physical Property
Figure 2 shows the analysis results of porosity and permeability of about 60 cores, with the porosity distribution from 1 to 9.9%, with a mean of 4.4%. The permeability distribution is 0.004-0.677 mD, with a mean of 0.068 mD. The reservoir is mainly depicted by small porosity and extremely poor permeability. The permeability increases with the increase of porosity, but the correlation coefficient is low. Under the same porosity, permeability varies greatly, and the pore structure is complex (Figure 2).
4.2. Feature of Reservoir Pore Structure
According to the observation of the rock thin section, the red and blue filling parts are pore spaces. In Figure 3(a), the compaction in a reservoir is strong, and the rock granules are mainly in linear contact, mainly in dissolution pores and mainly in the dissolution of feldspar particles. In Figure 3(b), the reservoir is mainly characterized by line contact and mainly contains residual intergranular pores. Figure 3(c) is mainly characterized by residual intergranular pores, and the surrounding particles are wrapped by chlorite film. Figures 3(d) and 3(e) show the dissolution of feldspar particles under SEM. Figure 3(f) shows intergranular pores filled with kaolinite and calcite. The average face rate of the reservoir is 3.12%, mainly intergranular pores and dissolution pores (Figure 4).
(a)
(b)
(c)
(d)
(e)
(f)
The content of reservoir interstitials in the research area is 15.15%, and the contents of various interstitials are different, mainly chlorite and illite, which are 4.1% and 4.8%, respectively. A small amount of carbonate mineral components was developed, with 1.1% of calcite, 2.1% of iron interpretation, and 1.2% of iron dolomite (Figure 5). The high content of reservoir interstitials fills voids and throats and affects pore structure and physical properties.
4.3. Nuclear Magnetic Resonance Characteristics of the Reservoir
The attenuation of the NMR signal is the superposition of the decay of the fluid signal in the pore, corresponding to the long attenuation time of the big aperture and the short attenuation time of the small aperture. Select 15 samples for NMR experiments. Figure 6(a) shows the spectrum of saturated underwater nuclear magnetic resonance. The spectrum was distributed between 0.1 and 100 ms, which could be classified as bimodal form and unimodal form according to the morphology of the spectrum. The unimodal type mainly developed a small pore throat, and the spectral peak was concentrated between 0.1 and 1 ms with a peak value of 0.5 ms. According to spectral peak characteristics, the bimodal is further divided into the left apex bigger than the right and the right apex bigger than the left. There are two types of porous throat in the reservoir: small pore throats are mainly distributed in 0.1~1 ms with a peak value of 0.5 ms, and large pore throats are distributed in 2~100 ms with a peak value of 10 ms. Figure 6(b) shows the spectrum of immobile water. Compared with the spectrum distribution in the saturated original formation water state and immobile water state, the site of the spectral peak did not change, but the peak height became smaller, especially the right peak changed greatly, reflecting the movable fluids mainly occurring in macropore throat.
(a)
(b)
A line parallel to the -axis is drawn from the endpoint value of the accumulated curve of the centrifuged spectrum, and it has an intersection with the mass curve of the impregnated water state, and the corresponding to the crossover point value is defined as the cutoff value (Figures 7(a), 7(c), and 7(e)). cutoff values ranged from 4.2 ms to 150 ms, with an average of 34.2 ms. The cutoff value of the reservoir is not fixed, and the size is associated with the pore texture. The higher the ratio of large pores and throats, the smaller the cutoff. The cutoff divides the spectrum into two parts for water-saturated states. Those above the cutoff are movable fluids, and those below the cutoff are bound fluids. The movable fluid saturation ranges from 3.1% to 46.6%, and the average value is 17.9%. The porosity of movable fluid ranges from 0.1% to 5.5%, and the average value is 1.6%. The geometric mean value of ranged from 0.615 ms to 2.711 ms, and the mean value was 1.607 (Table 1). According to the position of the separation point on the pore size distribution curve after water saturation condition and centrifugation, the corresponding least radius of pore active fluid was determined to be 4 nm (Figures 7(b), 7(d), and 7(f)).
By comparing the spectra of impregnated and bound water states, the active fluid is mainly distributed in bigger pore throat, and the pore-throat size is concentrated in 0.001 μm~2 μm. In Figure 7(a), the porosity of No. 30 is 4.9%, the permeability of No. 30 is 0.0004 mD, and the porous-throat size ranges from 0.001 μm to 1 μm. The porous throat is mainly small and less macropore development, and the mobile fluid saturation is 7.6% (Figure 7(b)). In Figure 7(c), the porosity of sample No. 9 is 7.6%, the permeability of No. 9 is 0.0239 mD, and the porous-throat size ranges from 0.001 μm to 1 μm. The left apex is slightly bigger than the right apex. Both small and large porous throat are developed, and the saturation of active fluid of sample 30# is 21% (Figure 7(d)). In Figure 7(e), the porosity of sample No. 47 is 10.9%, the permeability is 0.191 mD, the radius of pore size ranges from 0.001 μm to 1 μm, the right apex is slightly bigger than the left apex, the macropore throat is developed than the small hole, and the mobile fluid saturation is 27.7% (Figure 7(f)).
The distribution of pore throat radius in the reservoir is between 0.001 and 2 μm. The pore throat of nanopore is smaller than 0.1 μm; the pore throat of micropores is between 0.1 and 2.5 μm; the pore throat of mesoporous is between 0.5 and 0.5 μm; the pore throat of macroholes is between 2.5 and 10 μm; and the pore throat of giant hole is larger than 10 μm. The pore volume of a nanopore in the study area is 1.74-6.51%, the average value is 4.58%, and the proportion is 55.8%-90.3%, with a mean of 71.3%. The pore volume of micropores is 0.08-3.74%, the average value is 1.52%, and the proportion is between 4 and 33.2%, with an average value of 18.7%. The pore volume of mesoporous pores was 0.04-2.02%, the average value is 0.64%, and the proportion was 1-25.8%, with an average value of 8.5% (Figures 8(a) and 8(b)). Macroholes and giant holes are relatively small. The reservoir is dominated by nanopores, controlling 48% of the movable fluid, while micropores and mesopores control 50.6% of the active fluid, and the active fluid is major affected by macropores and throats. The proportion of the movable fluid in nanopores in the research area is high, which is mainly because of the high proportion of nanopore volume (Figure 8(c)).
(a)
(b)
(c)
4.4. Reservoir Relative Permeability Results
Oil-water phase permeability experiment can truly reflect how the oil phase migrates in the reservoir when there are both oil and water fluids in reservoir pores. Irreducible oil saturation and immobile water saturation obtained by the oil-water relative permeability experiment may be closer to the real production data, and the water breakthrough characteristics in the production process are judged by the feature of the relative infiltration rate curve.
Statistical results of the relative infiltration rate experiment of 8 samples show that the bound water saturation ranges from 22.3% to 38%, and the mean value is 29.9%. Irreducible oil saturation ranged from 37% to 44.6%, and the mean value is 40.6%. The oil saturation of isotonic points is distributed in 39.9%~ 59.5%, and the mean value is 49.6%. The reservoir is mainly hydrophilic or neutral wetting. The relative permeability of isotonic points ranged from 0.068 mD to 0.158 mD, with an average of 0.124 mD. The width of the oil-water two-phase band ranges from 21.1% to 37.2%, with a mean value of 29.5%. The oil displacement efficiency ranges from 34.1% to 48.7%, with an average of 40.2 (Table 2).
Based on the curve of oil-phase and liquid-phase relative seepage, it is divided into four classes. In Figure 9(a), the porosity of No. 29 is 3.24%, the permeability is 0.065 mD, the bound water saturation of No. 29 is 31.2%, and the irreducible oil saturation of No. 29 is 44.6%. With water saturation going up, oil-phase permeability declines stably, and the water percolation capacity grows tardy in the beginning and later grows faster. The seepage capacity of the oil-water intersection point is high. In Figure 9(b), the porosity of No. 35 is 4.1%, the permeability of No. 35 is 0.139 mD, the bound water saturation of No. 35 is 38%, and the irreducible oil saturation of No. 35 is 40.8%. With water saturation going up, the oil phase relative permeability begins to decrease stably, then the decrease rate becomes slow, and the water phase begins to grow rapidly; then, the growth rate becomes slow. In Figure 9(c), the porosity of No. 47 is 3.35%, the permeability of No. 47 is 0.242 mD, the bound water saturation of No. 47 is 35.7%, and the irreducible oil saturation of No. 47 is 37.4%. Following water saturation going up, the initial decrease rate of the oil phase is fast, and then, the decrease rate is gradually slow. Figure 9(d) shows that the porosity of No. 49 is 5.61%, the permeability of No. 49 is 0.09 mD, the binding water content of No. 49 is 25.8%, and the remnant oil saturation is 37.1%. Following water saturation going up, the oil phase initially decreases faster and then decreases slowly, and the water phase begins to grow slowly, then grows faster, and then grows slowly. The better the reservoir seepage capacity, the wider of the width of the copermeability zone, the smaller the residual oil saturation, and the bigger the oil displacement efficiency.
(a)
(b)
(c)
(d)
Figure 10(a) shows the variation feature of oil flooding efficiency of the four samples with the raise of injected water multiples. No. 49 has good porosity-permeability and the fastest growth of oil flooding efficiency. Water injection times reach 0.7, and the oil flooding efficiency reaches the peak and then remains unchanged as the raise of water injection. For the 35# sample, the oil flooding efficiency reaches the peak when the injection water multiple reaches 0.95 times, and the oil flooding efficiency slowly rises with the continuous water injection. The oil flooding efficiency of No. 29 reaches the peak when water injection times reach 1.7 and changes little with the continued water injection. Combined with Figure 8(a), for low seepage capacity reservoirs, the larger the permeability, the larger the percentage contents of large pore throats, the bigger the recovery efficiency during the injection of water, and the less injected water consumption to achieve the same recovery degree. The 47# sample has a double peak structure, the right peak is bigger than the left, and the injected water first enters into the bigger pore volume. Along with the raise during the water injection, the water gradually injects into the small pore throat, and the oil flooding efficiency gradually rises. As the water injection volume reaches 3 times, the flooding capacity of oil gradually gets stable; moreover, the oil flooding efficiency is the highest.
(a)
(b)
Figure 10(b) shows the variation characteristics between water injection multiple and water production rates in about four samples. The water production rate curve of sample 29# increases stably with the raise of the volume of water infused, and the water production rate of the other three samples all shows multistage characteristics. In the early water injection, the 49# sample has a relatively long stable production, while the water content of the other three samples rises rapidly. As the raise of the water infusion multiple, when the water infusion multiple is 0.18, the water content of the 47# sample quickly reaches the first inflection point of 62%; when the water injection multiple is 0.20, the water content of the 35# sample reaches the first inflection point 73%; when the water injection multiple is 0.23, the water content of 49# reaches the first inflection point 86%. The moisture content of the 29# sample slowly increases with the raise of water injection times. The stable production time is relatively short. It can be seen from Figure 6 that 29# is a double peak type with the same left and right peaks, and the reservoir permeability is poor, so the injected water is difficult to burst and water is seen slowly. The right peak of both 35# and 47# samples is bigger than that of the left peak, the reservoir permeability is better, and the water appears faster. The micropore texture in a low seepage capacity reservoir has a strong control effect on oil flooding efficiency and water content.
5. Discussion
5.1. Controlling Factors of Cutoff Value
The cutoff of the reservoir is very important for calculating permeability and movable fluid by NMR logging. Based on the test results of NMR, the cutoff value of the reservoir is not a definite value and is controlled by the pore structure of the reservoir. The variation characteristics between cutoff and porosity, permeability, reservoir quality index, and geometric mean were statistically analyzed, and the influencing factors of cutoff value were studied. cutoff and porosity have a negative correlation; that is, the higher the porosity, the smaller the cutoff (Figure 11(a)). cutoff and permeability have a negative correlation; as the permeability increases, the cutoff value decreases (Figure 11(b)). The reservoir quality index was minus connection with the cutoff, and the better pore structure, the smaller the cutoff (Figure 11(c)). cutoff and geometric mean of T2 spectral have a negative correlation; with the decrease in geometric mean of spectral, the cutoff value also decreases (Figure 11(d)). If the pore texture of the reservoir is better, the lower the cutoff, the better the fluid migration ability, and possibly the bigger the fluid saturation. The calculation model of the variable cutoff value was established according to the macroscopic and microscopic parameters of reservoirs.
(a)
(b)
(c)
(d)
5.2. Controlling Factors of Movable Fluid
Movable fluid in reservoir has a very important meaning in reservoir development. Through analyzing the variation characteristic between porosity, permeability, geometric mean, cutoff value, and active fluid saturation, the controlling effect of active fluid saturation is analyzed. A positive connection is active fluid saturation and porosity. The larger the pore space, the lower the fluid migration resistance, and the higher the mobile fluid saturation (Figure 12(a)). There is a positive connection between active fluid saturation and permeability; that is, the better the seepage capacity of the reservoir, the higher the active fluid saturation (Figure 12(b)). There is a positive connection in active fluid saturation geometric mean. The higher the geometric mean is, the more percentage contents the macropore throat of the specimen, and the higher the active fluid saturation (Figure 12(c)). There is a negative connection in mobile fluid saturation and the cutoff. The lower the cutoff was, the bigger the percentage contents of the macropore throat were, and the higher the mobile fluid saturation was (Figure 12(d)). The active fluid percentage contents of a tight reservoir are controlled by the reservoir physical property and pore structure. The better the reservoir pore-throat connectivity, the higher the active fluid percentage contents.
(a)
(b)
(c)
(d)
5.3. Controlling Factors of Oil Flooding Efficiency
Low-permeability oil flooding efficiency plays a vital parameter in the economic recovery of the oil field. The relationship between porosity, permeability, reservoir quality index, cutoff value, geometric mean, movable fluid saturation, and oil flooding efficiency is analyzed, and the controlling effect on reservoir recovery degree is discussed. There is a weak positive correlation between oil flooding efficiency and porosity, and porosity has a weak control effect on oil flooding efficiency in compact reservoirs (Figure 13(a)). There is a weak positive correlation in oil flooding efficiency and permeability, and permeability has a certain control effect on oil flooding efficiency of compact reservoirs (Figure 13(b)). There is a positive connection in oil flooding ability and reservoir quality index. If the reservoir pore structure is better, the higher the oil flooding ability (Figure 13(c)). The cutoff value of the reservoir is minus connection with oil displacement efficiency. The bigger the cutoff value, the worse the development of a large porous throat, and the smaller the oil flooding ability (Figure 13(d)). Oil flooding efficiency has negatively correlated with the geometric mean value. The larger the geometric mean value of , the more macropores are developed, and the bigger the oil flooding efficiency is (Figure 13(e)). There is a positive connection between oil flooding efficiency and movable fluid percentage contents. The larger the active fluid percentage contents, the better the pore space size and connectivity, and the bigger the oil flooding efficiency (Figure 13(f)). The displacement efficiency of oil in a tight reservoir is major influenced by pore structure and connected large pore throat.
(a)
(b)
(c)
(d)
(e)
(f)
6. Conclusion
(1)The mean value of porosity is 4.4%. The permeability is 0.068 mD. The reservoir is mainly characterized by micropores and extremely extralow permeability. The main pore types are intergranular pores and dissolution pores(2)The NMR of reservoir specimens mainly developed bimodal type. The mean value of mobile fluid saturation was 17.9%. The active fluid controlled by nanopores reached 48%. The minimum aperture of the movable fluid is 4 nm(3)The relative permeability curve is separated into four classes, and the average bound water saturation is 29.9%. The average irreducible oil saturation was 40.6%. The average width of the oil and water two-phase band is 29.5%. The mean oil flooding efficiency was 40.2%. The microscopic pore texture in extralow permeability storage layers has a strong control effect on oil flooding efficiency and water cut(4)The active fluid percentage contents of low-permeability storage layers are controlled by reservoir physical property and pore structure. The better the storage layers’ pore-throat connectivity, the higher the active fluid percentage contents. The final displacement efficiency is also germane to the pore system of the reservoir
Data Availability
The data applied to support the conclusions of this research are involved in the paper.
Conflicts of Interest
The authors proclaim that they have no benefit conflicts.
Acknowledgments
This paper was supported by the Scientific Research Program funded by the Shaanxi Provincial Education Department (Program No. 22JK0504) and Natural Science Basic Research Plan in Shaanxi Province of China (Program No. 2023JCQN0314).