Pore-Throat Structure, Fractal Characteristics, and Main Controlling Factors in Extremely Low-Permeability Sandstone Reservoirs: The Case of Chang 3 Section in Huachi Area, Ordos Basin

Abstract

The pore-throat structure of the extremely low-permeability sandstone reservoir in the Huachi area of the Ordos Basin is complex and highly heterogeneous. Currently, there are issues such as unclear understanding of the micro-pore-throat structural characteristics, primary controlling factors of reservoir quality, and classification boundaries of the reservoir in the study area, which seriously restricts the exploration and development effectiveness of the reservoir in this region. It is necessary to use a combination of various analytical techniques to comprehensively characterize the pore-throat structure and establish reservoir classification evaluation standards in order to better understand the reservoir. This study employs a suite of analytical and testing techniques, including cast thin sections (CTS), scanning electron microscopy (SEM), cathodoluminescence (CL), X-ray diffraction (XRD), as well as high-pressure mercury injection (HPMI) and constant-rate mercury injection (CRMI), and applies fractal theory for analysis. The research findings indicate that the extremely low-permeability sandstone reservoir of the Chang 3 section primarily consists of arkose and a minor amount of lithic arkose. The types of pore-throat are diverse, with intergranular pores, feldspar dissolution pores, and clay interstitial pores and microcracks being the most prevalent. The throat types are predominantly sheet-type, followed by pore shrinkage-type and tubular throats. The pore-throat network of low-permeability sandstone is primarily composed of nanopores (pore-throat radius r < 0.01 μm), micropores (0.01 < r < 0.1 μm), mesopores (0.1 < r < 1.0 μm), and macropores (r > 1.0 μm). The complexity of the reservoir pore-throat structure was quantitatively characterized by fractal theory. Nanopores do not exhibit ideal fractal characteristics. By splicing high-pressure mercury injection and constant-rate mercury injection at a pore-throat radius of 0.12 μm, a more detailed characterization of the full pore-throat size distribution can be achieved. The average fractal dimensions for micropores (Dh2), mesopores (Dc3), and macropores (Dc4) are 2.43, 2.75, and 2.95, respectively. This indicates that the larger the pore-throat size, the rougher the surface, and the more complex the structure. The degree of development and surface roughness of large pores significantly influence the heterogeneity and permeability of the reservoir in the study area. Dh2, Dc3, and Dc4 are primarily controlled by a combination of pore-throat structural parameters, sedimentary processes, and diagenetic processes. Underwater diversion channels and dissolution are key factors in the formation of effective storage space. Based on sedimentary processes, reservoir space types, pore-throat structural parameters, and the characteristics of mercury injection curves, the study area is divided into three categories. This classification provides a theoretical basis for predicting sweet spots in oil and gas exploration within the study area.

1. Introduction

Extremely low-permeability sandstone reservoirs generally experience destructive diagenetic processes such as compaction and cementation, which lead to a reduction in pore and throat radius, and a decrease in porosity and permeability. The pore-throat structure becomes more complex, with irregular shapes, poorer connectivity, and increased heterogeneity of the sandstone. These factors collectively increase the difficulty of oil and gas exploration and development [1,2]. Under the condition of similar porosity, there is a significant difference in permeability, which is an important factor affecting the exploration and development of this type of reservoir [3,4,5]. The pore-throat is the primary storage space and migration pathway for oil and gas, and they are the key factor determining the development of “sweet spots” in extremely low-permeability sandstone reservoirs. Therefore, an accurate understanding of the pore-throat structure of such reservoirs is of great significance for clarifying reservoir quality, oil saturation, and predicting oil well production. Currently, mercury injection and fractal theory are commonly used to quantitatively characterize the complexity of reservoir pore-throat structures [6,7,8]. Previous studies have predominantly employed either high-pressure mercury injection (HPMI) or constant rate mercury injection (CRMI) individually to investigate the fractal characteristics of reservoir pore-throat structures. However, HPMI has a shielding effect on larger pores and is more suitable for characterizing smaller pores. The high-pressure mercury injection curve is a composite curve of pores and throats, making it difficult to distinguish between them [9,10,11]. The maximum pressure of CRMI is 6.2 MPa, which is unable to characterize pores smaller than 0.12 μm, but it can separate pores and throats, allowing for the determination of their respective quantities and pore sizes [12,13,14]. Therefore, a single technique can only reflect the structural characteristics of part of the pore-throat system. This study combines HPMI with CRMI, and applies fractal theory. It also integrates direct observation methods of pore-throat structures, such as cast thin sections and scanning electron microscopy, to conduct a full-size pore-throat structure evaluation of the extremely low-permeability sandstone reservoirs in the Huachi area [15].

The Triassic Yanchang Formation sandstones in the Ordos Basin serve as a typical example for the study of extremely low-permeability sandstone reservoirs. Many scholars have successively conducted research on the characteristics of extremely low-permeability sandstone reservoirs, diagenetic processes, mechanisms of tightness, and factors influencing the formation and distribution of high-quality reservoirs [16,17,18,19]. It has been recognized that the sedimentary environment and petrological characteristics control the original pore features, while diagenesis modifies these original pores. Both of them jointly control the development of sweet spots [20,21]. The pore-throat structure includes several aspects such as the geometry, size, connectivity, and distribution characteristics of pores and throats. Sedimentary environment and diagenetic processes are the primary factors that determine the grain composition, size, sorting, cements, and maturity in clastic rocks, thereby influencing the heterogeneity of the reservoir. High-energy depositional environments typically form thick-bedded sandstones (>1 m) characterized by coarse-grained, well-sorted sediments, favorable reservoir properties, and relatively weak heterogeneity. In contrast, low-energy depositional environments often develop sand–mud interbedded lithofacies with finer-grained particles. These vertically intercalated mudstone layers act as flow barriers, significantly reducing permeability and resulting in strong heterogeneity. Additionally, sandstone composition directly influences reservoir fluid flow behavior and heterogeneity. Quartz grains exhibit strong compaction resistance, which helps preserve pore spaces. In contrast, lithic sandstones are more susceptible to compaction and diagenetic alterations, leading to modified pore-throat structures and enhanced heterogeneity [22,23]. Strong compaction is the most significant factor in destroying the pore-throat structure of the reservoir, significantly increasing the degree of heterogeneity. The impact of different cements and dissolution processes on reservoir heterogeneity is more complex [24]. The Yanchang Formation is the main oil-producing horizon of tight sandstone oil in the Ordos Basin. Among them, the Chang 3 oil layer group in the Huachi area is an important productive layer, characterized by a large oil-bearing area, thick oil layers, and tight reservoirs, and it belongs to a typical low-permeability tight oil reservoir [25]. Due to the overall low development degree of the Chang 3 section strata in the Yanchang Formation of the Ordos Basin, there has been very little research on the Chang 3 section by predecessors. This has led to an unclear understanding of the heterogeneity and micro-pore-throat structural characteristics of the Chang 3 reservoir in the Huachi area, which seriously restricts the exploration and development of oil and gas in this region.

This paper takes the extremely low-permeability sandstone of the Chang 3 section in the southern part of the Huachi area in the Ordos Basin as the research object. By employing analytical techniques such as CTS, SEM, XRD, HPMI, and CRMI, this study quantitatively characterizes the pore-throat size distribution, fractal characteristics, and their controlling factors of the reservoirs in the study area [26,27,28,29,30]. Integrating sedimentary characteristics and diagenetic processes, the Chang 3 reservoirs in the study area are classified. The research findings will provide effective methods and a theoretical basis for the evaluation of extremely low-permeability sandstone reservoirs and the prediction of favorable zones.

2. Geological Setting

The Ordos Basin is a multi-cycle sedimentary basin characterized by stable subsidence and migrating depressions. It is part of the North China Basin. In the late Mesozoic era, it gradually separated from the North China Basin and evolved into a large inland basin. The Triassic system forms an asymmetric north–south oriented rectangular basin with a steep and narrow western flank and a broad and gentle eastern flank. The basin margins are marked by well-developed faults and folds, while the internal structure is relatively simple, with gently dipping strata (generally with a dip angle of less than 1°) (Figure 1a). Based on the current tectonic morphological characteristics of the basin, it can be divided into six first-order tectonic units, namely: the Yimeng Uplift, the Weibei Uplift, the Tianhuan Syncline, the Yishan Slope, the Jinxi Torsion Fold, and the Western Margin Thrust Belt. Overall, the basin’s tectonics have been long-term stable, characterized by overall uplift, continuous subsidence, broad and gentle slopes, and low uplifts. The formation and evolution of the Ordos Basin, as well as the sedimentary characteristics of the Yanchang Formation, are mainly influenced by the surrounding Yinshan and Qinling orogenic belts, as well as the ancient uplifts of Lvliang, Longxi, Haiyuan, and Qianlisshan. The sediments within the basin primarily originate from three directions: northeast, southwest, and northwest, with significant differences in the types of parent rock assemblages. The lake basin’s sedimentary evolution has gone through the entire process of formation, development, climax, decline, and extinction. Starting in the early Late Triassic, the basin began to subside and accept sediments, forming the Yanchang Formation, a lake-delta facies oil-bearing strata sequence over 1000 m thick. Based on sedimentary cycles and oil-bearing properties, the Yanchang Formation can be divided from bottom to top into 10 oil-bearing groups [31,32,33]. Among them, during the Chang 3 sedimentation period, the lake water rapidly receded and became shallower, with a large accumulation and progradation of clastic materials at the basin margins, resulting in a sedimentary body thickness of 90–110 m (Figure 1c) (modified by Lv, 2023) [34]. The lake basin is characterized by this oscillatory uplift and subsidence evolution, which has led to the development of multiple reservoir-cap rock assemblages in the vertical direction within the Yanchang Formation, facilitating the formation of large deltaic lithologic oil reservoirs [35,36].

The Huachi area is located in the middle to southwestern part of the Yishan Slope in the Ordos Basin. During the Yanchang period, it was situated in the central part of the lake basin and represents the region with the largest sedimentary area during the Chang 3 period in the Ordos Basin. The surface topography of the area is characterized by typical loess plateau landforms with undulating terrain. The sandstone types of the Chang 3 reservoir in the study area are mainly lithic feldspar sandstone and feldspar lithic sandstone, with a high content of feldspar in the clastic components. The reservoirs are characterized by complex lithic and matrix compositions, low compositional maturity of rock components, moderate structural maturity, and a high degree of diagenesis.

3. Materials and Methods

3.1. Sampling and Processing

A total of over 50 representative core samples were evenly collected from the extremely low-permeability sandstones of the Triassic Yanchang Formation in the southern part of the Huachi area. The sampling depth ranged from 1493 to 1840 m (

Table 1. Sample location and lithology.

Sample	Well Name	Depth/m	Lithology
B125	B125	1742.5	Fine-grained arkose
B127-1	B127	1584.9	Medium-fine-grained arkose
B137	B137	1598.4	Medium-fine-grained arkose
B269-1	B269	1699.7	Fine-grained arkose
B269-2	B269	1699.8	Fine-grained arkose
B269-3	B269	1700	Fine-grained arkose
B269-4	B269	1700.2	Fine-grained arkose
B270	B270	1801.12	Very fine, fine-grained arkose
B270-1	B270	1741	Very fine, fine-grained arkose
B270-2	B270	1741.1	Fine-grained arkose
B270-4	B270	1800.7	Fine-grained arkose
B270-6	B270	1801.8	Fine-grained arkose
B280	B280	1714.02	Fine-grained arkose
B282	B282	1802.4	Fine-grained lithic arkose
B283-1	B283	1704.9	Fine-grained arkose
B283-3	B283	1705.6	Fine-grained arkose
B283-4	B283	1705.9	Fine-grained arkose
B283-6	B283	1718.6	Fine-grained arkose
B478	B478	1837	Fine-grained arkose
B478-3	B478	1837.7	Fine-grained arkose
B483-1	B483	1812.5	Fine-grained arkose
B483-2	B483	1812.9	Fine-grained arkose
B483-3	B483	1814	Medium fine-grained arkose
B483-4	B483	1816.1	Fine-grained arkose
B511	B511	1832.1	Fine-grained arkose
B511-2	B511	1833	Very fine. fine-grained arkose
B511-3	B511	1833.1	Very fine, fine-grained arkose
B512-1	B512	1761.2	Very fine, fine-grained arkose
B512-2	B512	1762.7	Medium-grained arkose
B521-1	B521	1600.8	Fine-grained feldspathic siltstone
B521-2	B521	1601.5	Fine-grained feldspathic siltstone
B522	B522	1652.3	Very fine, fine-grained arkose
B523-1	B523	1820.6	Very fine, fine-grained arkose
B523-2	B523	1821	Fine-medium grained arkose
B523-3	B523	1822.3	Argillaceous very fine, fine-grained lithic arkose
B523-5	B523	1822.7	Fine-grained arkose
H172-1	H172	1797.5	Fine-grained arkose
H172-2	H172	1801.5	Medium fine-grained arkose
H172-3	H172	1803.5	Medium-grained arkose
H184	H184	1815.6	Fine-grained arkose
H620	H620	1813.5	Very fine, fine-grained arkose
H620-1	H620	1820.8	Fine-grained arkose
H620-2	H620	1821.6	Medium fine-grained arkose
H620-3	H620	1822.6	Medium fine-grained arkose
L486	L486	1622.8	Argillaceous very fine, fine-grained lithic arkose
P28-021	P28-021	1750.4	Fine-grained arkose
P38-71	P38-71	1679.8	Fine-grained arkose
Y220-1	Y220-1	1705.9	Fine-grained lithic arkose
Y238	Y238	1757.13	Medium fine-grained feldspathic litharenite
Y53-1	Y53	1493	Fine-grained feldspathic litharenite

). The samples covered all sandstone types in the target formation. These samples were processed into thin sections and cylindrical specimens with a diameter of 2.5 cm and a length of approximately 7 cm. Since rock samples may be contaminated or contain impurities during sampling, they must be cleaned and dried to ensure the accuracy of the results. Using gentle cleaning methods, vacuum drying, and controlled drying temperatures can effectively prevent the sample pre-treatment process from affecting the rock’s pore-throat structure. Prior to the experiments, all samples were cleaned with dichloromethane (Tianjin Fuyu Fine Chemical Co., Ltd., Tianjin, China) to achieve the volatilization and dissolution of organic compounds. Subsequently, the samples were placed in a Memmert UN 110 constant temperature drying oven (Schwabach, Bavaria, Germany) for vacuum drying for 24 h at 120 °C. The effect of the pre-treatment process on the samples was verified by measuring differences in sample quality and observing changes in the pore-throat structure before and after treatment using CT scans.

Thin sections were prepared for cast thin section (CTS) analysis (45 samples), X-ray diffraction (XRD) (35 samples), scanning electron microscopy (SEM) (27 samples), and cathodoluminescence (CL) (27 samples). Cylindrical samples were used for physical property measurements (50 samples) and heavy mineral analysis (12 samples). Given the extremely high heterogeneity of the reservoir in the study area, the goal was to facilitate the accurate characterization of the full-size pore-throat structure of the same rock sample by combining the results of high-pressure mercury injection (HPMI) and constant-rate mercury injection (CRMI) experiments. Rock core samples were evenly selected from 12 wells within the study area for mercury intrusion analysis (sample names are designated by well numbers (Figure 1b). After being cut in half, these samples were respectively used for the two types of mercury injection experiments.

3.2. Experimental Measurements

CTS analysis can determine the mineral composition, matrix material, pore types, and cement types. It can also achieve quantitative characterization of pore size, throat size, and grain size [37]. XRD can directly analyze the mineral composition and relative content of rocks, thereby determining the lithology of the rocks [38]. SEM is widely used to identify and authenticate different types of rocks and minerals, and to observe and analyze the microstructure of samples [39]. CL can detect minerals that are not easily observed by other optical microscopes [40]. Mercury injection experiments can determine the corresponding pore size and pore volume by measuring the amount of mercury entering the pores under different external pressures, thereby calculating the pore size distribution, which can effectively characterize the size, shape, and structural features of pores [41].

The CTSs of 45 samples were examined using an Olympus-cx21 polarizing microscope (Olympus, Tokyo, Japan) according to the Chinese Oil and Gas Industry Standard (SY/T) 5368-2000 [42]. According to standard SY/T 5163-2018 [43], XRD testing of whole rock was accomplished using the basic intensity contrast method with an X-ray diffractometer model AL-Y3500 (Aolong, Dandong, China). According to standard SY/T 5162-2014 [44], SEM observations were performed using a Tescan S-3200N field emission electron microscope. According to standard SY/T 5916-2013 [45], CL testing of rock flakes was accomplished using a CL8200 MK5 cathodoluminescence instrument (Cambridge Image Technology Ltd., Hatfield, UK). According to standard SY/T 5336-2006 [46], the helium porosity and pulse permeability were measured by using CMS-300 overburden pore penetrometer (Core Lab, Houston, TX, USA). This type of testing is particularly suitable for low-permeability samples that do not obey Darcy’s law.

According to the standard SY/T 5346-2005 [47], HPMI experiments was conducted using the Autopore IV 9505 mercury injection instrument (Micromeritics, Atlanta, GA, USA). The experiment includes both the mercury injection under pressure and the mercury withdrawal under depressurization, with the maximum pressure reaching 200 MPa. The smallest identifiable pore-throat radius is approximately 3.6 nm. CRMI experiment was conducted using an ASPE730 constant-rate mercury injection instrument (Raykol, Xiamen, China), with a maximum injection pressure of 6.21 MPa and the smallest identifiable pore-throat radius being about 0.12 μm. Considering the high salinity of formation water in the study area, residual salt particles after the evaporation of moisture in natural cores may clog pore-throats. In accordance with the requirements of the standard SY/T 5336-2006 (Practices for core analysis), all rock samples were subjected to salt-washing treatment with methanol prior to mercury injection testing. The samples were then dried at 105 °C until a constant weight was achieved. Subsequently, the samples were placed in a sealed dilatometer, evacuated, and then tested.

CTS, XRD, SEM, CL, and pore-permeability tests were conducted at the State Key Laboratory of Continental Dynamics, Northwest University, P. R. China. HPMI and CRMI tests were completed at Beijing Qingchen Huanyu Petroleum Geological Technology Co. Ltd. (Beijing, China).

3.3. Fractal Theory

Fractal theory is widely used to quantitatively characterize the pore-throat structural features of rocks that exhibit self-similarity [48,49]. The ideal fractal dimension typically ranges from 2 to 3. A higher fractal dimension indicates a more complex pore-throat structure, while a lower fractal dimension indicates a more homogeneous structure [50]. This study, based on fractal theory, utilizes the mercury injection/withdrawal curves obtained from high-pressure mercury injection (HPMI) and constant rate mercury injection (CRMI) analyses of extremely low-permeability sandstone samples. It calculates the fractal dimension for each sample by integrating the characteristics of the pore size distribution. Fractal theory indicates that the number of pore-throats N(>r) with a radius greater than r can be expressed as follows [51,52]:

$$\mathrm{N}(>\mathrm{r})={\int }_{\mathrm{r}}^{{\mathrm{r}}_{\mathrm{m}\mathrm{a}\mathrm{x}}}\mathrm{P}\left(\mathrm{r}\right)\mathrm{d}\mathrm{r}={\mathrm{a}\mathrm{r}}^{-\mathrm{D}}$$

(1)

where “r_max” represents the maximum of the pore-throat radius, “P(r)” denotes the distribution density function of pore-throat radius, “a” is a proportionality constant, and “D” represents the fractal dimension.

By taking the derivative with respect to “r”, the distribution density function of pore-throat radius “P(r)” is derived.

$$\mathrm{P}\left(\mathrm{r}\right)={\displaystyle \frac{\mathrm{d}\mathrm{N}(>\mathrm{r})}{\mathrm{d}\mathrm{r}}}={\mathrm{a}}^{\prime }{\mathrm{r}}^{-\mathrm{D}-1}$$

(2)

where “a′” is a proportionality constant, which is equivalent to -D×a.

By converting Equation (2) to Equation (3), the total volume “V(<r)” of pores with a radius less than “r” can be represented:

$$\mathrm{V}(<\mathrm{r})={\int }_{{\mathrm{r}}_{\mathrm{s}}}^{\mathrm{r}}\mathrm{P}\left(\mathrm{r}\right)\mathrm{a}{\mathrm{r}}^3\mathrm{d}\mathrm{r}={\displaystyle \frac{-{\mathrm{a}}^2\mathrm{D}}{3-\mathrm{D}}}\left({\mathrm{r}}^{3-\mathrm{D}}-{\mathrm{r}}_{\mathrm{m}\mathrm{i}\mathrm{n}}^{3-\mathrm{D}}\right)$$

(3)

The total pore volume (V) can be listed as follows:

$$\mathrm{V}={\displaystyle \frac{{-\mathrm{a}}^2\mathrm{D}}{3-\mathrm{D}}}\left({\mathrm{r}}_{\mathrm{m}\mathrm{a}\mathrm{x}}^{3-\mathrm{D}}-{\mathrm{r}}_{\mathrm{m}\mathrm{i}\mathrm{n}}^{3-\mathrm{D}}\right)$$

(4)

By converting Equations (3) and (4) into Equation (5), one can derive the cumulative volume fraction V(c) of pore-throats with radius less than “r(s)”.

$$\mathrm{V}\left(\mathrm{c}\right)={\displaystyle \frac{\mathrm{V}(<\mathrm{r})}{\mathrm{V}}}={\displaystyle \frac{{\mathrm{r}}^{3-\mathrm{D}}-{\mathrm{r}}_{\mathrm{m}\mathrm{i}\mathrm{n}}^{3-\mathrm{D}}}{{\mathrm{r}}_{\mathrm{m}\mathrm{a}\mathrm{x}}^{3-\mathrm{D}}-{\mathrm{r}}_{\mathrm{m}\mathrm{i}\mathrm{n}}^{3-\mathrm{D}}}}$$

(5)

Because “rmin” is far less than “rmax” Equation (5) can be simplified as follows:

$$\mathrm{V}\left(\mathrm{c}\right)={\left({\displaystyle \frac{\mathrm{r}}{{\mathrm{r}}_{\mathrm{m}\mathrm{a}\mathrm{x}}}}\right)}^{3-\mathrm{D}}$$

(6)

Taking a logarithm on both sides of Equation (6), the formula is changed as follows:

$$\mathrm{l}\mathrm{o}\mathrm{g}\mathrm{V}\left(\mathrm{c}\right)=\mathrm{l}\mathrm{o}\mathrm{g}\left(1-{\mathrm{S}}_{\mathrm{H}\mathrm{g}}\right)=\left(3-\mathrm{D}\right)\mathrm{l}\mathrm{o}\mathrm{g}\mathrm{r}-\left(3-\mathrm{D}\right)\mathrm{l}\mathrm{o}\mathrm{g}{\mathrm{r}}_{\mathrm{m}\mathrm{a}\mathrm{x}}$$

(7)

In the mercury injection experiment, the wetting phase is air, and the non-wetting phase is mercury, so logV(c) can be expressed as lg(1 − S_Hg), where S_Hg is mercury saturation. If the pore size distribution conforms to fractal theory, a linear relationship exists between log(1 − S_Hg) and logr. The Hurst exponent (H) can then be determined as the slope of this straight line. Then the fractal dimension (D) is equal to 3-H.

4. Results

4.1. Mineral Composition and Petrophysical Characteristics

Core observations and grain size analyses indicate that the Chang 3 reservoir in the study area mainly consists of grey and light grey fine-grained sandstones and siltstones. The primary grain sizes range from 0.05 mm to 0.45 mm, with an average of 0.24 mm. The grain size frequency curve is unimodal with a sharp peak, indicating a relatively simple composition of the sediments in the study area. The steep shape of the probability cumulative curve suggests a narrow grain size distribution range and moderate to good sorting. The probability cumulative curve mainly forms two subpopulations of jumps and suspensions, indicating poor rounding, predominantly sub-angular (Figure 2a). Based on the thin-section identification and the sandstone classification ternary diagram, the sandstone types of the Chang 3 reservoir in the study area are mainly arkose and a small amount of lithic arkose (Figure 2b). Feldspar is commonly found in potash feldspar. The total content of clastic materials ranges from 80.5% to 91.5%, with an average of 86.1%. The average proportions of feldspar, quartz, and lithic fragments are 51.0%, 24.5%, and 10.7%, respectively (Figure 2c).

The clastic components are predominantly feldspar, followed by quartz and lithic fragments (Figure 3a,b). The types of rock fragments are primarily metamorphic rock (average 6.23%), followed by volcanic rock (average 2.79%) and sedimentary rock (average 1.69%) (Figure 2d). Metamorphic rock fragments consist of quartzite, schist, phyllite, slate, and metamorphic sandstone. Igneous rock fragments mainly include effusive rocks and aphanitic rocks. Sedimentary rock fragments are mainly dolomite. According to the quantitative analysis by X-ray diffraction, the highest content of clay minerals is chlorite, with an average relative content of 57.7%. The second most abundant is the illite-montmorillonite interlayer, with an average relative content of 26.9%. Illite has the smallest proportion, with an average relative content of 15.4%. No illite zone was observed in the sandstone reservoir of the study area. Cementation is strongly developed, mainly consisting of clay mineral and carbonate cementation, with a small amount of siliceous cementation. SEM images reveal intergranular chlorite cementation (Figure 3c) and mixed illite-montmorillonite and micritic calcite cementation (Figure 3d). The main types of cementation include pore-lining, overgrowth-pore, and pore-lining-pore cementation.

Physical property analysis indicates that the porosity of the Chang 3 section in the Huachi area mainly ranges from 10% to 18%, with an average of 12.01% (Figure 4a). Permeability is primarily distributed between 0.2 and 2 mD, with a secondary range of 1.5 to 5 mD, and an average value of 1.54 mD (Figure 4b). Due to the high content of chlorite in the reservoir, it can block pores and throats. This leads to poor reservoir connectivity and reduced permeability. The reservoir in the study area exhibits extremely strong heterogeneity and generally poor physical properties. However, due to the development of dissolution pores and micro-fractures, some local areas have high porosity and high permeability characteristics. During the Chang 3 period, the sedimentary environment of the study area was a delta front subfacies, characterized by the development of underwater distributary channels, underwater levees, and interdistributary bays. The average porosity and permeability of the underwater distributary channels are 13.6% and 1.45 mD, respectively. For the underwater levees, the average porosity and permeability are 10.4% and 0.35 mD, respectively. The interdistributary bays have average porosity and permeability values of 9.9% and 0.31 mD, respectively. Sedimentary processes are key factors influencing the distribution of sand bodies and controlling the porosity and permeability of the reservoir. Within different sedimentary facies, porosity and permeability show a clear exponential positive correlation (Figure 4c), indicating that the reservoir’s permeability is significantly influenced by pore-throat size. The weaker correlation between porosity and permeability in underwater distributary channels suggests that the pore-throat structure in this type of reservoir is more complex and heterogeneous. Overall, the sandstone reservoir of the Chang 3 section in the Huachi area is a typical low-porosity, extremely low-permeability sandstone reservoir.

4.2. Characteristics of the Pore-Throat Network

Based on the comprehensive analysis of CTS and SEM images from 27 cored wells in the study area, the extremely low-permeability sandstone reservoir of the Chang 3 section mainly develops three types of pores: intergranular pores, intragranular dissolution pores, clay interstitial pores, and microcracks (Figure 5).

The predominant pore type in the Chang 3 reservoir of the study area is residual intergranular pores, which exist between the framework grains. Their pore sizes are primarily concentrated in the range of 50 to 70 μm. These pores vary in size and have relatively regular shapes, often appearing as nearly triangular, quadrangular, and irregular forms (Figure 5a). Dissolution pores mainly include feldspar and lithic dissolution pores (Figure 5b). Feldspar dissolution occurs along unstable joints and twin seams, with some dissolution pores being filled with micritic calcite (Figure 5d). These dissolution pores often exhibit irregular reticulate, honeycomb, or elongated shapes, and in some cases, complete dissolution leads to the formation of moldic pores. Chlorite cementation can be observed on grain surfaces and between grains (Figure 5e). The pore sizes of these dissolution pores generally range from 10 to 30 μm. Lithic dissolution pores are relatively common in the Chang 3 section of the study area. They are mainly formed by the selective dissolution of soluble components within lithic grains, resulting in honeycomb-like dissolution pores, with lithic grains often being partially dissolved. The pore sizes generally range from 5 to 20 μm, with large dissolution pores visible locally, and their distribution is uneven (Figure 5f). Intergranular pores are well-developed in the reservoir, mainly consisting of kaolinite and halite intergranular pores (Figure 5g). The pore diameters typically range from 1 to 5 μm, with good sorting. These pores make a certain contribution to the reservoir’s permeability.

Based on the size and shape of throats, the predominant throat type identified in the sandstone reservoir of the study area is sheet-type throats (Figure 5h), followed by pore shrinkage-type throats and bundled throats (Figure 5i).

4.3. Characteristics of the Pore-Throat Distribution

In the study area, 12 samples were selected for HPMI and CRMI tests. The reservoir properties and pore-throat structural parameters in the study area exhibit a wide range of variations, and the mercury withdrawal efficiency is relatively low. These characteristics indicate that the reservoir in the study area has strong heterogeneity. The rock samples were classified into three types (Figure 6) based on an integrated analysis of high-pressure mercury injection curve trends (Figure 7a), pore-throat radius distribution patterns (Figure 7b), pore-throat structural parameters, and rock physical properties (

Table 2. Parameters from the CRMI experiment.

Sample	Porosity (%)	Permeability (mD)	Sorting Coefficient	Skewness	Structural Coefficient (φ)	HMIP		CMIP
						Entry Pressure (MPa)	Maximum Mercury Saturation (%)	Entry Pressure (MPa)	Maximum Mercury Saturation (%)
B522	15.297	1.080	1.62	0.30	1100.96	0.30	98.56	0.30	50.95
B270	18.100	4.360	1.08	0.58	1252.07	0.18	97.92	0.18	63.95
B478	16.400	1.700	2.43	0.23	383.55	0.34	96.60	0.34	51.67
P38-71	17.200	2.390	0.75	0.41	534.49	0.21	96.85	0.21	58.46
H620	15.886	1.594	1.52	0.18	357.57	0.30	96.48	0.30	66.85
B511	13.000	0.532	1.82	0.10	372.36	0.28	96.68	0.68	53.11
P28-021	13.105	0.828	1.26	0.16	161.94	0.30	98.74	0.30	62.59
Y220-1	12.300	0.500	2.46	0.36	17.45	1.36	93.15	0.36	57.63
B137	7.905	0.062	2.04	0.28	11.85	1.26	94.95	1.26	53.37
Y238	8.109	0.060	1.94	0.15	16.52	1.12	95.93	1.12	50.95
B125	4.608	0.010	2.04	−0.07	0.15	3.51	91.44	3.51	16.37
L486	4.096	0.040	2.23	−0.33	7.93	2.99	90.17	1.99	32.55

).

Figure 6. Sample classification results based on high-pressure mercury injection test parameters.

Figure 6. Sample classification results based on high-pressure mercury injection test parameters.

Figure 7. Capillary pressure curves, pore-throat size distribution curves for sandstone samples in the study area. (a) Typical high-pressure mercury injection experiment curves. (b) The characteristics of the pore radius of the high-pressure mercury injection experiment.

Figure 7. Capillary pressure curves, pore-throat size distribution curves for sandstone samples in the study area. (a) Typical high-pressure mercury injection experiment curves. (b) The characteristics of the pore radius of the high-pressure mercury injection experiment.

Type I samples are characterized by capillary pressure curves that are low, flat, and elongated. The average maximum mercury injection saturation is 97.4%. The entry pressure is less than 1 MPa, with an average value of 0.28 MPa. The predominant storage space consists of intergranular pores, which account for 69% of the total porosity. Feldspar dissolution pores are the second most abundant, making up 27% of the total porosity. Throat types are predominantly pore-shrinkage type. Porosity is greater than 12%, with an average value of 15.6%. Permeability is greater than 0.5 mD, with an average value of 1.8 mD. The average skewness is 0.28, indicating a positively skewed distribution of pore-throat sizes. This suggests that the reservoir has good storage and permeability capabilities. The sorting coefficient mostly ranges from 1 to 2.5, with an average value of 1.5, indicating good sorting. The structural coefficient varies significantly and is always greater than 100. This indicates that the pore-throat tortuosity is high and the pore-throat structure is complex in this type of reservoir. The pore-throat radius distribution curve of type I samples exhibits a weak bimodal shape, with the main peak at 0.54 μm and the secondary peak at 1.57 μm.

The angle between the mercury injection and withdrawal curves of type II samples is small. The average maximum mercury injection saturation is 94.7%. The entry pressure is high, ranging from 1 to 2 MPa, with an average value of 1.25 MPa. The pore space of this type of reservoir is dominated by open and semi-closed pores. The pore sizes are medium, with fine-microfine throats being predominant. Porosity ranges from 7% to 12%, with an average value of 9.44%. Permeability ranges from 0.05 to 0.5 mD, with an average value of 0.21 mD. The average skewness is 0.27, indicating a positively skewed distribution of pore-throat sizes. The sorting coefficient mostly ranges from 1 to 2.5, with an average value of 2.15, indicating good sorting. The structural coefficient ranges from 10 to 100, indicating that this type of reservoir has moderate pore-throat tortuosity and good connectivity. The pore-throat radius distribution of type II samples is relatively broad and exhibits a multi-modal shape, mainly distributed between 0.04 and 0.18 μm.

The capillary pressure curves of type III samples are characterized by being high, steep, and short, with an average maximum mercury injection saturation of 90.8%. The entry pressure is greater than 2 MPa, with an average value of 3.25 MPa. The sorting is medium-good, and the pore-throat sizes exhibit a negatively skewed distribution. This indicates poor storage and permeability capabilities of the reservoir. The structural coefficient is less than 10, indicating that this type of reservoir has low pore-throat tortuosity and typically develops isolated micro- and nanopores and microfine throats. The pore-throat connectivity is poor. Porosity is less than 7%, with an average value of 4.35%. Permeability is less than 0.05 mD, with an average value of 0.03 mD. The pore-throat radius distribution of type III samples shows a distinct bimodal pattern, with the primary peak at 0.009 μm and the secondary peak at 0.036 μm.

CRMI experiments can effectively distinguish between pores and throats [53]. Figure 8 shows the CRMI curves of typical samples with three types of pore-throat structures. In the early stages of mercury injection, the amount of mercury entering the throat increased rapidly, while the amount of mercury entering the pore was minimal. The shape of the throat capillary pressure curve coincided with that of the total capillary pressure curve. Subsequently, the pore mercury injection increased, and the total capillary pressure curve deviated from the throat capillary pressure curve. When the pore mercury feed no longer increases, the pore mercury feed curve steepens and completely deviates from the total capillary pressure curve. This stage is the pore-throat transition zone. As the mercury injection pressure continues to increase further, the mercury saturation in throats increases continuously, while the mercury saturation in pores no longer changes. The trend of the capillary pressure curve for throats becomes consistent with that of the total capillary pressure curve. This indicates that the pores in the rock sample have been completely filled with mercury, and any subsequent increase in mercury is entirely from the throats. This stage is referred to as the throat zone [16]. The mercury injection curves of all three types feature both the pore-throat transition zone and the throat zone. The mercury saturation in throats is significantly higher than that in pores, indicating that there are many isolated pores surrounded by extremely narrow throats [15].

For type I samples, the average entry pressure, maximum mercury injection saturation, and maximum connected pore-throat radius are 0.33 MPa, 58.23%, and 2.59 μm, respectively. In these samples, there is a large difference between the mercury saturation in pores and throats (Figure 8a). For type II samples, the average entry pressure, maximum mercury injection saturation, and maximum connected pore-throat radius are 0.91 MPa, 53.98%, and 1.08 μm, respectively (Figure 8b). For type III samples, these values are 2.75 MPa, 24.46%, and 0.48 μm, respectively. The difference in mercury saturation between pores and throats in these samples is smaller than in the other two types (Figure 8c). This indicates that, given similar pore radii and porosity, the larger the throats, the higher the mercury saturation. Throats have a significant impact on extremely low-permeability sandstone reservoirs.

The pore radius distribution range of the three types of samples is basically consistent, all falling between 100 and 250 μm. The throat radius distribution of different samples shows significant differences, with no obvious pattern in the peak values, and the average throat radius ranges from 0.38 to 8.0 μm. The strong variability in throat distribution leads to abnormally large pore-throat ratios, with the average pore-throat radius ratio ranging from 17.25 to 489.01 (Figure 9). This further indicates that the pore-throat distribution in the extremely low-permeability sandstone reservoirs of the study area is complex and highly heterogeneous.

4.4. Fractal Features

4.4.1. Fractal Characteristics of HPMI and CRMI

In this study, the pore-throat types were classified into four categories using the Xoaoth classification standard: nanopores (r < 0.01 μm), micropores (0.01 < r < 0.1 μm), mesopores (0.1 < r < 1 μm), and macropores (r > 1 μm) [54]. The high-pressure mercury pressing and constant velocity mercury pressing data of 12 samples were processed to plot scatter plots of lg(1 − S_Hg)(>r) and lg(r). Superimposed pore-throat radius distribution curves were fitted to the segmented pore-throat fractal curves for different sizes. Fractal curves of three typical samples are shown, respectively (Figure 10). The fractal dimensions of different sizes of the pore-throats were calculated by substituting the fitted slopes into Equation (7). The fractal dimensions based on high-pressure mercury compression tests were defined as Dh1 (micropores), Dh2 (nanopores), Dh3 (mesopores), and Dh4 (macropores). The fractal dimension based on the constant velocity mercury pressure test is defined as Dc3 (mesopores) and Dc4 (macropores).

By comparing the fractal dimension fitting curves of HPMI and CRMI, it is evident that HPMI characterizes mesopores and macropores with fewer data points and lower accuracy relative to CRMI. This indicates that HPMI has a shielding effect on larger pores and is more suitable for characterizing smaller pores (Figure 10a,c,e). The maximum pressure for CRMI is 6.2 MPa, with a constant injection rate, which can eliminate the “hempskin effect” and compensate for the shortcomings caused by high pressure, such as mineral compaction and wetting hysteresis. It is more suitable for characterizing the distribution of larger pore-throats. However, mercury cannot enter the storage space with a radius less than 0.12 μm, and therefore cannot characterize the pore-throat structure at the micronano scale (Figure 10b,d,f) [55]. For instance, the correlation of the fractal dimension fitting curve for macropores obtained by HPMI for type I sample B522 (R² = 0.54) (Figure 10a) is significantly lower than that obtained by CRMI (R² = 0.95) (Figure 10b).

Therefore, combining HPMI for characterizing nanopores and micropores with CRMI for characterizing mesopores and macropores can provide a detailed characterization of the full-scale pore-throat structural features of extremely low-permeability sandstone reservoirs.

4.4.2. Combined HPMI and CRMI for Full-Size Pore-Throat Fractal Characterisation

The pore-throat radius distribution curves with a radius less than 0.12 μm obtained by HPMI were spliced with those with a radius greater than 0.12 μm obtained by CRMI. That is, the pore-throat radius distribution and fractal characteristics of nanopores and micropores are characterized by HPMI curves, while those of mesopores and macropores are characterized by CRMI curves. The full-size pore-throat radius distribution curves of 12 samples were plotted. In order to quantitatively characterise the complexity of the pore-throat structure and the microhomogeneity of the extremely low-permeability sandstone reservoir, scatter plots of lg(r) and lg(1 − S_Hg) were drawn based on the full-size pore-throat radius distribution curves (Figure 11). As can be seen from the figure, the pore-throat radius splicing curves of the 12 samples are complete, with smooth splicing points, which can accurately characterize the pore-throat structural features of the reservoir. The fractal dimensions of pore-throats of various sizes were calculated by segmental curve fitting (

Table 3. Fractal dimension calculation results of the Chang 2 sandstone samples in the Haojiaping area.

Sample	Dh1	R2	Dh2	R2	Dc3	R2	Dc4	R2
B522	1.732	0.944	2.323	0.981	2.726	0.999	2.954	0.950
B270	1.732	0.944	2.323	0.981	2.777	0.998	2.845	0.844
B478	1.990	0.975	2.504	0.985	2.725	0.995	2.959	0.981
P38-71	2.260	0.973	2.285	0.999	2.771	0.999	2.905	0.707
H620	2.195	0.982	2.268	0.980	2.636	0.997	2.927	0.738
B511	1.990	0.974	2.331	0.922	2.693	0.992	2.960	0.987
P28-021	0.967	0.900	2.380	0.988	2.679	0.998	2.928	0.830
Y220-1	1.957	0.923	2.722	0.995	2.711	0.999	2.935	0.935
B137	2.018	0.995	2.377	0.992	2.626	0.931	2.990	0.972
Y238	1.731	0.951	2.307	0.995	2.825	0.994	2.984	0.965
B125	1.323	0.969	2.688	0.927	2.971	0.823	2.972	0.966
L486	1.886	0.969	2.614	0.877	2.805	0.987	2.984	0.954

).

Fractal dimensions can quantitatively reflect the complexity and heterogeneity of pore-throat structures. The fractal dimensions of porous rocks typically range between 2 and 3. When the fractal dimension is closer to 2, it indicates that the reservoir pore surfaces are smoother and more uniformly distributed. Conversely, when the fractal dimension is closer to 3, it suggests that the reservoir pore-throat structure is more complex and the surfaces are rougher. The fractal dimension of nanopores (Dh1) is mostly less than 2, with an average value of 1.82. This suggests that the nanopore surfaces are smooth and approximate two-dimensional planes, exhibiting relatively simple structures. The pore-throat system demonstrates high structural homogeneity, being primarily composed of isolated pores. This indicates that nanopores do not exhibit ideal fractal characteristics.

The pore-throat fractal dimensions of the 12 samples are shown in Table 2 (Table 2). The fractal dimension of micropores (Dh2) ranges from 2.268 to 2.722, with an average value of 2.43. The fractal dimension of mesopores (Dc3) ranges from 2.626 to 2.971, with an average value of 2.75. The fractal dimension of macropores (Dc4) ranges from 2.845 to 2.990, with an average value of 2.95. Dc4 is the highest, followed by Dc3, while Dh2 is the lowest. This indicates that the larger the pore-throat size, the rougher the surface, and the more complex the structure. It can be attributed to the large-scale pore-throats having a larger reservoir space due to the influence of solvation. The pore-throat spaces are deformed, resulting in stronger heterogeneity and higher fractal dimensions.

5. Discussion

5.1. Relationships Between Fractal Dimension and Pore-Throat Structure Parameters

In order to study the extent to which reservoir pore-throat structural parameters are affected by fractal dimension, scatter plots were used to represent the variation of pore-throat structural parameters under fractal dimension for different sizes of pore-throat. The correlation between fractal dimension and pore structure parameters was analysed (Figure 12).

Entry pressure refers to the capillary pressure of the largest connected pore in the pore system. The magnitude of entry pressure reflects the concentration and size of the reservoir pore-throat. It is one of the main parameters for distinguishing the quality of rock storage performance [56]. Entry pressure shows a significant positive correlation with Dc3 and Dc4, with correlation coefficients of 0.5 and 0.6, respectively. It has a weak positive correlation with Dh2 (Figure 12a). The development of mesopores and macropores is a key factor influencing the pore-throat structure of the reservoir. Changes in the fractal dimension indicate alterations in the complexity of the reservoir’s pore-throat structure. The higher the fractal dimension of mesopores and macropores, the more irregular the pore-throat structure of the reservoir, the greater the tortuosity, and the stronger the heterogeneity. The smaller the maximum connected throat radius of the reservoir, the lower the permeability, which leads to an increase in displacement pressure.

Skewness is a measure of asymmetry in the distribution of pore-throat sizes, with Skp ranging from −1 to 1. Skp = 0 indicates a symmetrical pore-throat distribution curve; Skp < 0 is a fine skewness; Skp > 0 is a coarse skewness. Skewness showed a clear negative correlation with the Dc4 with a correlation coefficient of 0.5, and a weak negative correlation with the Dc3 and Dh2 (Figure 12b). It indicates that the symmetry of the distribution of micropores and mesopores has a certain influence on the fractal characteristics of the reservoir pore-throat structure. The asymmetry of the size distribution of macropores has a greater influence on the physical properties of the reservoir. The larger the fractal dimension, the more it reduces the effective reservoir space and permeation capacity of the reservoir. The pore-throat size distribution tends to be smaller, and the skewness decreases.

The maximum mercury injection saturation refers to the cumulative mercury saturation at the highest pressure during the experiment, which can reflect the storage capacity and heterogeneity of the reservoir. The maximum mercury injection saturation shows a negative correlation with micropores, mesopores, and macropores. Among them, the correlation with micropores and mesopores is more significant (Figure 12c). This indicates that the more complex the pore-throat structure, the weaker the storage capacity and homogeneity of the reservoir. The heterogeneity of micropores and mesopores is stronger, and, therefore, the connectivity of smaller pores and throats has a greater impact on the storage capacity of the reservoir.

The sorting coefficient indicates the uniformity of reservoir particle sizes and reflects the concentration of pore-throat distribution. The smaller the sorting coefficient, the more uniform the pore-throat distribution. The sorting coefficient shows a significant positive correlation with micropores and macropores. There is no obvious correlation with mesopores (Figure 12d). This indicates that the better the sorting, the more regular the pore-throat structure and the stronger the homogeneity. Micropores and macropores play a decisive role in the uniformity of extremely low-permeability sandstone reservoirs. The larger the fractal dimension, the stronger the heterogeneity of the reservoir, the more complex the pore-throat structure, and the poorer the sorting.

In summary, the fractal dimension of macropores shows a significant correlation with displacement pressure, skewness, sorting coefficient, and maximum mercury injection saturation. The fractal dimension of mesopores is only significantly correlated with displacement pressure and maximum mercury injection saturation. The fractal dimension of micropores only has a clear correlation with maximum mercury injection saturation and sorting coefficient. The analysis results indicate that the heterogeneity and permeability of the reservoir in the study area are more significantly influenced by the development degree and surface roughness of macropores. The connectivity of micropores and mesopores has a certain impact on the storage capacity of the reservoir.

5.2. The Main Controls on the Fractal Dimension

5.2.1. Sedimentation

Sedimentary processes control the distribution of reservoir sand bodies and the characteristics of sand-mud combinations. Different sedimentary facies exhibit distinct features in lithology, grain structure, and composition, which directly affect the microscopic pore-throat structure of the reservoir. During the Chang 3 period of the Yanchang Formation in the study area, the sedimentary environment was a delta front subfacies, characterized mainly by the development of underwater distributary channels, underwater levees, and interdistributary bays. By studying the distribution characteristics of sedimentary facies during the Chang 3 period in the study area, it can be found that type I samples are mainly distributed in the underwater distributary channel microfacies. Type II samples are primarily found in the underwater levee microfacies. Type III samples are predominantly developed in the interdistributary bay microfacies (Figure 13). Therefore, sedimentary facies have a certain controlling effect on the pore-throat structure of low-permeability sandstones.

This study quantitatively describes the relationship between sedimentary facies and fractal dimensions from the perspective of heavy mineral maturity. Heavy mineral maturity can be used to analyze the transportation distance of sediments, commonly represented by the proportion of zircon, tourmaline, and rutile in heavy minerals (ZTR = (zircon content + tourmaline content + rutile content)/heavy mineral content × 100). As the transportation distance increases, the content of stable heavy minerals relatively rises. The higher the maturity, the larger the ZTR value [57]. The average ZTR value of the reservoir in the study area is 54%, indicating a relatively low compositional maturity. The scatter plot of fractal dimensions versus mineral maturity shows a significant positive correlation between the fractal dimension of large pores and throats (D4) and ZTR (Figure 14). Micropores and mesopores show no obvious correlation with ZTR. Zircon, rutile, and other stable heavy minerals have strong resistance to weathering, leading to complex compositions, poor sorting, and complex pore-throat structures in sandstone reservoirs. The complexity of large pore-throat structures is more significantly influenced by the content of heavy minerals.

Figure 13. Characteristics of sedimentary microphase spreading in the long 3 section of the study area.

Figure 13. Characteristics of sedimentary microphase spreading in the long 3 section of the study area.

Figure 14. Correlation of fractal dimension with component maturity (ZTR).

Figure 14. Correlation of fractal dimension with component maturity (ZTR).

5.2.2. Diagenesis

Based on thin-section and scanning electron microscope observations, the extremely low-permeability sandstone reservoirs in the study area are primarily influenced by compaction, cementation, and dissolution processes (Figure 3 and Figure 5). Among these, compaction and cementation are destructive diagenetic processes and are the main controlling factors for the reduction of reservoir storage space.

(1)

Compaction

The study area has a low content of rigid particles such as quartz and barite. The reservoir is susceptible to plastic deformation, has relatively weak resistance to compaction, and exhibits distinct point-to-line contacts of particles (Figure 5h,i). These factors result in a complex pore-throat structure with poor connectivity, thereby increasing the heterogeneity and fractal dimension of the reservoir [58].

(2)

Cementation

The predominant cementation type is clay mineral filling cementation (Figure 3c,d). Different types and contents of clay minerals have different effects on pore-throat structure. In the study area, the development of chlorite coatings can effectively inhibit the secondary enlargement of quartz and compaction, thereby protecting the pore-throat structure. However, when the chlorite content is high, it can block pores, leading to reduced porosity and permeability, as well as increased reservoir heterogeneity and fractal dimension [59].

(3)

Dissolution

Dissolution, on the other hand, is a constructive diagenetic process and is the primary means of forming secondary porosity. Solubility phenomena are widely observed in feldspar and rock fragments, as evidenced by thin sections and scanning electron microscopy. This improves reservoir connectivity, enhances pore space, and reduces fractal dimension. The study area reservoirs contain a relatively high amount of unstable feldspar minerals, and the dissolution of feldspar can generate a variety of different types, sizes, and complex structures of pores and throats (Figure 5d,e). If dissolution is intense, the pores formed are larger, resulting in a greater disparity in pore and throat radius within the reservoir, increased heterogeneity, and a larger fractal dimension.

Smaller pores and throats in the reservoir, due to their smaller radius, are less affected by diagenetic processes, and their pore-throat structures remain almost undeformed (Figure 5g). Therefore, smaller pore-throats have similar shapes, weaker heterogeneity, higher self-similarity, and correspondingly smaller fractal dimensions. Larger storage spaces in the reservoir, such as residual intergranular pores and feldspar dissolution pores, are strongly affected by diagenetic processes. Consequently, larger pores and throats undergo significant structural deformation, exhibit stronger heterogeneity, and have larger fractal dimensions.

5.3. Reservoir Type Classification

Based on sedimentary characteristics and reservoir space types, combined with pore-throat structural parameters and the characteristics of mercury injection curves, the extremely low-permeability sandstone reservoirs in the study area are divided into three categories (

Table 4. Fractal characteristics of the pore-throat structure.

Parameters	Type I	Type II	Type III
Sedimentation	Underwater distributary channel	Underwater levee	Interdistributary
Pore types	Large intergranular pores, dissolution pores	Small-medium intergranular pores, dissolution pores	Intercrystalline pores, intraparticle pores
Throat types	Pore shrinkage-type, wide sheet-type throats	Narrow sheet-type, neck-shaped throats	Tubular throats
Permeability (mD)	>0.5	0.05~0.5	<0.05
Porosity (%)	>12	7~12	<7
Entry pressure (MPa)	<1	1~2	>2
Maximum mercury saturation (%)	>96	92~96	<92
Full-size pore-throat distribution characteristics and fractal dimension fitting curves
Typical HPMI curve
Typical CRMI curve

). Type I reservoirs are mainly found in the underwater distributary channel microfacies, with pore-throat structures dominated by large intergranular pores, dissolution pores, and pore-shrinkage-type throats. The maximum mercury injection saturation is greater than 96%. Type II reservoirs are primarily developed in the underwater levee microfacies, with pore-throat structures dominated by small to medium intergranular pores, a small number of dissolution pores, narrow sheet-type, and neck-shaped throats. The maximum mercury injection saturation ranges from 92% to 96%. Type III reservoirs are mainly developed in the interdistributary microfacies, with pore-throat structures dominated by intragranular pores, intergranular pores, and bundled throats. The maximum mercury injection saturation is less than 92%. Among them, type I and type II reservoirs are considered sweet spots for oil and gas exploration. By combining the full-size pore-throat fractal dimension characteristics to study the heterogeneity of pore-throat structures and to conduct quantitative evaluations, a more precise basis for reservoir classification is provided.

6. Conclusions

(1)

The lithology of the Chang 3 reservoir in the study area mainly consists of arkose and a small amount of lithic arkose. It is characterized by simple sediment composition, medium to good sorting, poor rounding, intense diagenesis, and strong heterogeneity. The porosity of the reservoir ranges from 10% to 18%, with an average value of 12%. Permeability ranges from 0.2 to 2 mD, with an average value of 1.54 mD, making it a typical low-porosity, extremely low-permeability reservoir. Common pore types in the study area include intergranular pores, intragranular dissolution pores, and micropores. The main fillings are chlorite and illite. Throat types are predominantly tabular, followed by constricted and bundled throats.

(2)

By splicing the pore-throat sizes obtained from high-pressure mercury injection (HPMI) and constant rate mercury injection (CRMI), the full-size pore radius distribution characteristics were derived. This method addresses the technical shortcomings of CRMI, which cannot characterise pores smaller than 0.12 μm in radius, and HPMI, which cannot finely characterise larger pore-throats. Based on fractal theory, the segmented fractal dimensions were calculated for each sample. The average fractal dimensions for micropores (Dh2), mesopores (Dc3), and macropores (Dc4) are 2.43, 2.75, and 2.95, respectively. This indicates that the larger the pore-throat size, the rougher the surface, and the more complex the structure.

(3)

Dc4 shows significant correlation with displacement pressure, skewness, sorting coefficient, and maximum mercury injection saturation. Dh2 and Dc3 only have a clear correlation with maximum mercury injection saturation. This indicates that the heterogeneity and permeability of the reservoir are more significantly influenced by the development degree and surface roughness of macropores. The connectivity of micropores and mesopores has a certain impact on the storage capacity of the reservoir. Therefore, modifying larger pore-throats helps to increase the storage space and flow capacity of the reservoir.

(4)

The sedimentary environment and diagenetic processes directly control the pore-throat structure of the reservoir, thereby influencing its fractal dimension. The fractal dimension of large pores and throats (Dc4) shows a positive correlation with compositional maturity (ZTR). As the transportation distance increases, the content of heavy minerals such as zircon, tourmaline, and rutile rises, further enhancing the complexity of the large pore-throat structure. The study area is subjected to compaction, cementation, and dissolution. Smaller pores and throats are less affected by diagenetic processes, with their structures remaining almost undeformed and having smaller fractal dimensions. Large pores and throats, on the other hand, are strongly influenced by diagenetic processes, resulting in significant deformation of their structures and larger fractal dimensions.

(5)

The extremely low-permeability sandstone reservoirs in the study area are classified based on sedimentary characteristics, reservoir space types, pore-throat structural parameters, and the characteristics of mercury injection curves. Type I, type II, and type III reservoirs show distinct differences in physical properties, pore-throat size distribution, and mercury injection curve morphology. A classification basis for the Chang 3 reservoir in the Huachi area has been established, providing a theoretical basis for predicting sweet spots in oil and gas exploration in the study area. In addition, it will be necessary to further clarify and validate the basis for reservoir classification by combining fractal theory with full-pore-size analysis of a large number of samples.