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Article

Effects of Clay Mineral Content and Types on Pore-Throat Structure and Interface Properties of the Conglomerate Reservoir: A Case Study of Baikouquan Formation in the Junggar Basin

by
Bowen Li
1,2,*,
Linghui Sun
1,3,*,
Xiangui Liu
1,3,
Chun Feng
1,2,
Zhirong Zhang
1,2 and
Xu Huo
1,2
1
Institute of Porous Flow and Fluid Mechanics, Chinese Academy of Sciences, Langfang 065007, China
2
University of Chinese Academy of Sciences, Beijing 100190, China
3
Research Institute of Petroleum Exploration and Development, Petrochina, Beijing 100083, China
*
Authors to whom correspondence should be addressed.
Minerals 2023, 13(1), 9; https://doi.org/10.3390/min13010009
Submission received: 10 November 2022 / Revised: 10 December 2022 / Accepted: 11 December 2022 / Published: 21 December 2022
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Abstract

:
Many factors need to be considered in the evaluation of tight conglomerate reservoirs, including the microscopic pore-throat structure, pore connectivity, lithology, porosity, permeability, and clay mineral content. The contents and types of clay minerals reflect the mineral evolution process during the deposition of the reservoir and can reflect the reservoir’s physical properties to a certain extent. In this study, cores from the Baikouquan Formation in Mahu were used to comprehensively analyze the effects of the clay mineral content on the physical properties of a tight conglomerate reservoir, including field emission scanning electron microscopy (FE-SEM), casting thin section observations, X-ray diffraction (XRD), interface property testing, high-pressure mercury injection, low temperature N2 adsorption, and nuclear magnetic resonance (NMR)-movable fluid saturation testing. The results revealed that differences in different lithologies lead to differences in clay mineral content and pore structure, which in turn lead to differences in porosity and permeability. The interface electrification, adsorption, and specific surface area of the reservoir are positively correlated with the clay mineral content, which is mainly affected by the smectite content. As the clay mineral content increases, the proportion of nanoscale pore throats increases, and the core becomes denser. The saturation of the movable fluid controlled by the >50 nm pore throats in the tight conglomerate ranges from 8.7% to 33.72%, with an average of 20.24%. The clay mineral content, especially the I/S (mixed layer of Illite and montmorillonite) content, is negatively correlated with the movable fluid. In general, the research results clarified the relationship between the lithology and physical properties of clay minerals and the microscopic pore structure of the tight conglomerate reservoirs in the Baikouquan Formation in the Mahu area.

1. Introduction

The oil and gas resources in tight conglomerate reservoirs, as a type of tight oil and gas, are becoming an increasingly important unconventional fossil fuel resource [1,2,3,4,5,6]. Due to the unique mud-sand-gravel structure of conglomerate reservoirs, the sedimentary facies and lithofacies change rapidly in the vertical and horizontal directions with a poor distribution regularity [7,8,9,10,11,12,13,14,15]. As a result, the nanoscale pore structure of tight conglomerate reservoirs is characterized by various types, a wide distribution, and poor consistency between the porosity and permeability [4,10,11,12,13,14,15,16]. At the nanoscale, the particle size, argillaceous mineral content, and mineral type of the reservoir cementation gravel also play a decisive role in the types and pore throat size of the nanoscale pores [17,18,19]. The type of nanoscale pore structure, pore throat size, and pore throat connectivity directly determine the degree of oil and gas enrichment and the effectiveness of the tight reservoir development [20,21,22,23]. The pore throat characteristics of reservoir rocks play a decisive role in the reservoir seepage capacity [24,25,26]. Therefore, quantitative characterization of the nanoscale pore structure of a tight conglomerate reservoir plays an important role in reservoir development and enhanced oil recovery.
The microscopic pore throat structure of the reservoir is largely influenced by diagenesis and deposition [17,27,28,29]. Quartz accretion and carbonate cements reduce reservoir quality, but dissolution of calcite cements and skeletal grains (feldspar, volcanic fragments, and mud intraclasts) significantly enhances the reservoir quality within the Paleocene deep-water marine sandstones in the Shetland-Faroes Basin [27]. Based on the quantitative study of lacustrine sandstone in Dongying Sag, Bohai Bay Basin, Yuan et al., believed that the dissolution of feldspar and the precipitation of clay and quartz cement had little effect on absolute porosity, but reduced permeability [29]. Rosenbrand et al., observed the fibrous structure of illite through electron microscopy and believed that the enrichment of illite leads to lower saline permeability [30]. Clay minerals in tight reservoirs can fill pore-throat systems and block fluid migration channels [17,18,19]. Therefore, the content of clay minerals can be the main controlling factor for the physical properties of tight sandstone reservoirs [17,31,32]. Previous studies have emphasized the influence of clay minerals on porosity, permeability, pore throat type and their size distribution [18,31,33,34,35]. However, a detailed analysis of clay minerals of different lithofacies, especially their potentially different effects on pore-throat connectivity, size distribution and reservoir properties, is needed. There are still few studies on tight conglomerate.
There are many methods for characterizing the reservoir nanoscale pore structure, including constant velocity mercury injection, high pressure mercury injection, scanning electron microscopy, field emission scanning electron microscopy, cryogenic N2 adsorption, computed tomography (CT) scanning, and nuclear magnetic resonance analysis [36,37]. These methods can significantly improve the characterization of the reservoir’s nanoscale pore structure and the quantification of the pore-throat scale parameters. Due to the unique complexity of the mineral composition and the strong heterogeneity of tight conglomerate reservoirs, various research methods are needed to analyze the nanoscale pore structure and the genesis of the reservoir. At present, abundant research has been carried out in the target area, but the influences of the clay mineral content and lithology on the physical properties of the tight conglomerate reservoir have not been reported and explored.
In this study, the tight glutenite reservoir in the Lower Triassic Baikouquan Formation in the M18 and M131 blocks in the Mahu Sag, northwest Junger Basin, which are typical representative blocks, was taken as the research object. At present, the characterization of the tight conglomerate reservoir in the Mahu Depression is still in the preliminary stage. In this study, scanning electron microscopy (SEM), high-pressure mercury injection (HPMI), nuclear magnetic resonance (NMR), field emission scanning electron microscopy (FE-SEM), X-ray diffraction (XRD), interfacial property testing, and movable fluid degree testing were conducted. The effects of the types and contents of the clay minerals on the types, sizes, genesis, and movable fluid of the nanoscale pore structures in the tight conglomerate in the Baikouquan Formation were studied. The pore-throat scale distribution and pore-throat types of tight conglomerate reservoirs were explored by high-pressure mercury intrusion injection, scanning electron microscopy, and core slices. Combined with XRD and interface property test data, the effect of clay mineral type and content on pore-throat scale distribution was analyzed. Finally, the effect of clay mineral type and content on the mobile fluid saturation of tight conglomerate was studied by means of centrifugation and NMR.

2. Geologic Setting

The Junggar Basin is located in the northern part of the Xinjiang Uygur Autonomous Region in northwestern China, between the Altai Mountains and the Tianshan Mountains. It contains rich oil and gas reserves in the western Junggar Mountains to the west and the Beita Mountains to the east (Figure 1A). The Mahu area is bounded by the Xiazijie oilfield to the north; the Xiazijie oilfield, Wuerhe oilfield, Fengcheng oilfield, Baikouquan oilfield, and Jinlong 7 oilfield to the south; the Kebai fault to the west; and the axial line of the Dabasong Uplift to the east, covering an area of about 7300 km2. The Carboniferous-Permian Jiamuhe, Fengcheng, Xiazijie, and Lower Wuerhe formations; the Triassic Baikouquan, Karamay, and Baijiantan formations; the Jurassic Badaowan, Sangonghe, Xishanyao, and Toutunhe formations; and the Cretaceous strata are developed from bottom to top. Among them, the Permian and Triassic, Triassic and Jurassic, Jurassic and Cretaceous strata are bounded by regional unconformities. In most areas, the Upper Wuerhe Formation is absent between the Triassic Baikouquan Formation and the Permian Lower Wuerhe Formation, forming an angular unconformity. The reservoirs in the Triassic Baikouquan, Karamay, and Lower Wuerhe formations are located near this unconformity. The target layer is divided into three members of the Triassic Baikouquan Formation from bottom to top: Member 100 (T1b1), Member 122 (T1b2), and Member 103 (T1b3) (Figure 1B).
The main body of the Triassic Baikouquan Formation in Mahu is a monocline with a southeast dip angle of 3–9°. Two sets of NE-SW and NW-SE trending thrust faults are developed, with distances of 10–50 m, generally within 30 m. The burial depth of the reservoir is deep, generally greater than 3000 m. The Baikouquan Formation is a fan-delta deposit, and the favorable reservoirs are developed in the front facies belt. The reservoir in the Baikouquan Formation in the Mahu area is mainly composed of gray and gray-green sandy fine-grained conglomerate, conglomerate with small/medium/large pebbles, and pebbly coarse sandstone, followed by gray sandy conglomerate and (pebbly) medium-coarse sandstone. The gravel size generally varies from 2 mm to 16 mm, and the largest particle size is >64 mm. The logging interpretation of the major reservoirs indicates that the porosity is 8.37%–9.96% and the permeability is 0.83–3.95 mD.

3. Data and Methods

The materials used in this study included 79 regular core samples from T1b1, T1b2, and T1b3, which were collected during drilling, as well as 1992 pore-permeability-porosity data from the Research Institute of Exploration and Development of the Petrochina Xinjiang Oilfield. The core samples were mainly composed of fine-grained conglomerate (FGC), conglomerate with medium pebbles (MPC), conglomerate with small pebbles (SPC), pebbly sandstone (PS), and sandy conglomerate (SC). The porosity and permeability of the one-inch standard core samples were measured at 25 °C using a helium porosity meter and a low-pressure helium pycnometer.
In this study, the cores of the Baikouquan Formation in Mahu were used to comprehensively analyze the effects of the clay mineral content on the physical properties of the tight conglomerate reservoir, including Fe-SEM, casting thin section observations, XRD, interface property testing, high-pressure mercury injection, low temperature N2 adsorption, and NMR-movable fluid saturation testing. The core samples used for the NMR-movable fluid saturation testing were soaked in formation water and saturated for approximately 48 h to ensure that the cores are fully saturated. Six samples were cut and polished according to the lithology and were analyzed using FE-SEM (Zeiss Crossbeam 550, Munich, Germany). Casting thin sections of six samples were observed. The XRD and interfacial properties of the bulk minerals were measured, and the clay mineral types were analyzed. After the samples were naturally dried, the samples were ground to below a 200 mesh with a three-head agate grinder. After the sample is extracted from the suspension by the Stokes sedimentation method, it is made into natural slices (N), ethylene glycol slices (EG), and high-temperature slices (T) for testing on the machine. Test conditions: Cu-Ka radiation; working voltage and current are 40 Kv and 40 mA respectively; the divergence slit and scattering slit are both 1°, the receiving slit is 0.3 mm; step-scanning method is adopted, and the detector is 1D defluorescence model. Scanning range: 1. Natural slice (N) 3–15°(2θ), scanning speed is 2° min, step width is 0.02°. 2. Ethylene glycol sheet (EG) 3–30° (2θ), scanning speed 2° min, step width 0.02°. 3. High temperature slice (T) (EG) 3–15°(2θ), scanning speed is 2° min, step width is 0.02°. Eight samples were analyzed to determine the movable fluid saturation. Twelve samples from different lithologies were selected for high-pressure mercury injection analysis.
The capillary force of the brine corresponding to the control radius of 1 μm, 0.5–1 μm, 0.1–0.5 μm, and 0.05–0.1 μm was calculated by the capillary force of the brine under the different pore size. The calculated capillary forces corresponding to different pore diameters are 21 psi, 42 psi, 208 psi, and 417 psi, respectively. The core is centrifuged with the capillary force as the corresponding centrifugal force. In this way, controlled mobile fluid saturation at different pore sizes can be obtained by centrifugation. The movable fluid saturation testing involved centrifuging and NMR analysis of water-saturated core samples at centrifugal forces of 21 psi, 42 psi, 208 psi, and 417 psi using a high-speed centrifuge. The movable fluid saturations controlled-throat radii of >1 μm, 0.5–1 μm, 0.1–0.5 μm, and 0.05–0.1 μm were obtained. The NMR instrument (Niumag MacroMR, Suzhou, China) was an OXFORD GeoSpec with a high temperature and high pressure nuclear magnetic resonance core analyzer. The analysis was carried out at 25 °C. The main magnetic field frequency was 2 MHz. Other parameters are: TW = 4000 ms, RG1 = 20 db, DRG1 = 2, PRG = 1, SW = 250 KHz, NECH = 10,000, TE = 0.15 ms, P1 = 5.8 us, P2 = 9.84 us, and NS = 32. The parameter settings are summarized through a large number of core nuclear magnetic resonance experiments in the early stage, and the real situation in the pore throat is restored to the greatest extent on the basis of this equipment. After obtaining the relaxation time (T2) of each sample, the change in the fluid saturation was obtained from the relaxation time and the semaphore.
A Micromeritics-9500 (Micromeritics, Shanghai, China) high-pressure mercury injection instrument was used to conduct the high-pressure mercury injection experiments, and the specific experimental procedure was conducted according to standards ISO 15901-3:2007 and ISO 15901-2:2006. Based on the capillary bundle model, when the injection pressure is higher than the capillary force of the pore-throat, the mercury enters the pore-throat, that is, the injection pressure is the capillary force, and the corresponding capillary radius is the pore-throat radius. The capillary pressure curve and pore distribution curve can be obtained by constantly changing the injection pressure.
The interfacial properties of the reservoir were mainly determined via XRD, cation exchange capacity (CEC), zeta potential, and low temperature N2 adsorption experiments. X-ray diffractometer (Rigaku New-Smart, Tokyo, Japan) was used for the XRD analysis, with a test temperature of 25 °C. For the CEC test, the sample was ground into powder (200 mesh) and was used to form a suspension in water. Then, a uVVIS-752 N was used to conduct the analysis according to standard ISO 23470-2018. The test temperature was 25 °C. For the zeta potential test, the sample was ground into powder (about 200 mesh) and was used to form a suspension in water. A Malvin laser (Malvern Zetasizer Nano ZS90, Shanghai, China) particle size analyzer and the electrophoretic light scattering method were used to test the zeta potential. The test temperature was 25 °C. The specific surface area was determined by grinding the sample into powder (36–60 mesh) and using an AUTOSORB-6B instrument (Quantachrome, Beijing, China) to adsorb nitrogen at a low temperature.

4. Results

4.1. Porosity and Permeability

The porosity and permeability data for the core samples collected from Baikouquan Formation in blocks M18 and M131 in the Mahu area since 2017 show that the overall porosity is low (2%–16%) and is mainly concentrated between 6% and 10%, with an average porosity of 8% (Figure 2A). The permeability ranges from 0.0001 mD to 1000 mD, mainly between 0.1 mD and 10 mD, with an average permeability of 2.2 mD (Figure 2B). High permeability cores generally contain large grain margin fractures and nanoscale fractures, and the matrix permeability is generally low. In terms of the blocks, the average permeability of block Ma18 is higher (3.57 mD) than the average permeability of block Ma131 (1.28 mD). The apparent density of the core is positively correlated with the gravel content and gravel size, and the apparent density of the reservoir is 2.11–2.66 g/cm3, mainly between 2.45 g/cm3 and 2.52 g/cm3. In terms of the porosity and permeability data, it was found that the correlation between the porosity and permeability of the conglomerate reservoir in the Mahu area is very poor, with an R2 value of less than 0.3 (Figure 3). However, there is a positive correlation overall. By comparing the correlation between the porosities and permeabilities of the different lithologies, it was found that only the PS has a relatively good exponential correlation between its porosity and permeability, and the data for the other lithologies are scattered. The correlation of the porosity and permeability of the different lithologies increases as the gravel size of the conglomerate increases. The content of the large gravel in FGC leads to an overall poorer sand cement bond strength. The FGC contains abundant grains with flange joint microcracks, resulting in a relatively high permeability compared to the other lithologies.

4.2. Mineral Compositions and Interfacial Properties

The mineral composition (Table 1) shows that the tight conglomerate in the Mahu area is mainly composed of sandy argillaceous cements and gravel, which contain a large amount of clay minerals, such as illite, kaolinite, and chlorite, I/S, as well as a small amount of debris filling. I/S (Illite-smectite mixed layer) is the transition product in the process of transformation from smectite to illite, which is composed of smectite crystal layer and illite crystal layer alternately distributed. S(I/S) refers to the percentage of smectite content in the illite-smectite mixed layer, which represents the conversion degree of smectite to illite [38]. The XRD results of the core samples revealed that quartz is the main mineral in the Mahu area, with an average content of 52.23%, followed by feldspar (average of 27.0%). The feldspar content is 5% higher in block Ma18 than in block Ma131 on average. According to the clay mineral content in block Ma18, the total amount of clay minerals is 4.9%–30.9%, with an average of 19.22%. Among them, the relative content of the I/S is the highest, (15%–70%), with an average of 39.18%. The relative chlorite content is 9%–40%, with an average of 25.76; and the illite and kaolinite contents are 11–37% and 4%–20%, respectively, with average values of 23.59% and 11.47%, respectively. According to the clay mineral content of the reservoir in block Ma131, the total amount of clay is 8.4%–28.9%, with an average of 18%. Chlorite has the highest relative content, mainly ranging from 30% to 54%, with an average of 46.71%. The relative contents of illite, I/S, and kaolinite are 9%–29%, 8%–32%, and 10%–25%, with average values of 17.38%, 16.67%, and 19.24%, respectively.
The zeta potentials (Table 2) for the Mahu conglomerate reservoir samples range from −1.54 to −8.8 mV, with an average value of −5.99 mV. The cation exchange capacity ranges from 1.34 to 12.14 cmol/kg, with an average value of 6.08 cmol/kg. The specific surface area ranges from 1.75 to 6.69 m2/g, with an average of 3.53 m2/g.

4.3. Morphology of Pore Throats and Clay Minerals

The cast thin section observations revealed that the pore types in the Mahu area mainly include dissolved pores in feldspar grains, intergranular pores, and structural fractures (Figure 4). Due to the strong deformation of the soft plastic debris, the intergranular pores are squeezed (Figure 4E), which makes the rock tighter, but the boundary fractures between the rigid particles are clear (Figure 4B and Figure 5C). Chlorite is developed at the pore margins, and the intergranular pores are well preserved. The intergranular dissolved pores occupy the intergranular space, which is larger than the intergranular dissolved pores in the mineral particles (Figure 4A). The intergranular pores and intragranular dissolved pores account for 54.7% and 40.1% of the total pore volume, respectively. In the samples, strong hydromica is evenly distributed among the grains (Figure 4D and Figure 5B). The dissolved pores are developed in the feldspar clasts. Some of the feldspar grains contain dissolved pores (Figure 5B,D), and the cuttings of the dissolved pores and the argillaceous hybrid shrinkage pores are filled with asphalt (Figure 5A). Intergranular micro/nanopores are developed in the rock matrix of the samples, and intergranular nanopores are present in the I/S and chlorite (Figure 5E). The material filling the pore-throat system is mainly composed of autogenic clay minerals, such as chlorite (Figure 5C), vermicular and scattered kaolinite (Figure 5F), and honeycombed I/S (Figure 5A,D). Due to the formation of intergranular pore-edge fractures and an intergranular pore-intergranular pore-edge fracture network, the interpore connectivity is good.

4.4. Pore and Throat Size Distribution

One-inch cores with different lithologies from blocks Ma131 and Ma18, which are typical blocks in the Mahu area, were selected for the high-pressure mercury injection experiments. The distribution range of the porosity of Mahu ultra-low permeability reservoir and the tight reservoir is 7.1%–13.3%. The permeability ranges from 0.066 to 0.86 mD (Table 3), and the corresponding average pore throat radius ranges from 0.15 to 1.51 μm, with an average of 0.49 μm. The maximum radius is 0.04 μm. The median radius data were not measured for the individual cores because the mercury saturation did not reach 50% at the maximum mercury intake pressure, indicating that the overall pore-throat radius of the Mahu reservoir was small. The throat sorting coefficient and experimental results show that the pore-throat size distribution of blocks Ma131 and Ma18 exhibits a bimodal distribution (Figure 6A,B). The different lithology has resulted in different nanoscale pore structures, which are correlated with the pore throat size distribution. The bimodal characteristic of the pore throat size distribution of the pebbly sandstone is not obvious, mainly containing 10 nm pore throats, and the porosity is relatively low (8%–10%). The pore throat size distribution of the sandy conglomerate’s is concentrated at 10 nm and 100 nm, and the porosity is low. The pore size distribution peaks of the fine-grained conglomerate are located at about 10 nm and 400 nm, and the porosity is low. The pore size distribution of the conglomerate with small/medium/large pebbles is mainly 10 nm and 500 nm–1 μm, with an average porosity of about 12%.

4.5. Saturation of Movable Fluid

Eight one-inch core was used for the movable fluid saturation experiments. The mineral compositions of the samples were analyzed. The results are presented in Table 1. The results of the movable fluid saturation experiments (Figure 7, Table 4) show that the movable fluid saturation varies greatly among the different core samples, and the pore and throat structures used are also different. In the entire Mahu area, the average movable fluid saturation controlled by the >50 nm throats is 20.24%, the maximum value is 33.72%, and the minimum value is 8.7%. There are also differences in the movable fluid saturations of the different lithologies. The pebbly sandstone is mainly sandy, while the intragranular dissolved pores between the gravel are less abundant and are controlled by the throats. Therefore, the fluid in part of the micropores cannot be used effectively, and the movable fluid saturation of this lithology is the lowest. This also results in poor connectivity of the samples. The sandy conglomerate and fine-grained conglomerate have relatively high fluid saturations, and their pore throat types are mainly connected by structural fractures and intergranular pores, resulting in good connectivity.

5. Discussion

5.1. Effects of Lithology on Clay Mineral Content and Reservoir Physical Properties

The sedimentary facies in the Mahu area are mainly fan-delta sedimentary facies, including the fan-delta front sedimentary facies in block Ma18 and the fan-delta sedimentary system in block Ma131. The overall positive correlation between the porosity and permeability indicates that the primary pore throats are relatively well preserved and the pore throats are evenly distributed in the samples. The secondary pores, fracture development, and gravel are the reasons for the weak correlation [39,40,41]. The SEM images (Figure 4) show that the clay minerals mainly exist in the intergranular dissolved pores, intragranular dissolved pores, and structural fractures. Therefore, the contents and types of the clay minerals have significant influences on the properties of the pore-throat interface. It should be noted that the clay mineral content of the reservoirs in the Mahu area is 4.9%–30.9% (Table 1). In addition, it is widely distributed and is characterized by a complex reservoir lithology and rapid changes. There are differences in the permeabilities of the different lithologies (Figure 8), and the apparent density and porosity are basically negatively correlated. The average permeability of the fine-grained conglomerate is higher than those of the other lithologies. The SEM images show that intergranular fractures and nanoscale fractures are developed and are mainly filled with lamellar kaolinite and chlorite, while the I/S and illite contents are low (Figure 5E,F and Figure 9). In addition, the lower sand content, less filling of the primary intergranular pores, and the poor cementation strength result in a higher permeability compared to those of the other lithologies. The average apparent density and permeability of the pebbly sandstone are relatively low due to the development of dissolved pores and interparticle dissolved pores (Figure 5D). Intergranular dissolved pores are widely distributed in the feldspar grains, and some of the intergranular dissolved pores are developed near structural fractures, which is also the reason for the relatively high porosity and relatively low apparent density of this lithology. Although the intergranular dissolved pores and structural fractures can be connected to form seepage channels, the honeycombed I/S nearly fills the intergranular dissolved pores and structural fractures, resulting in reduced fluidity between the actual pores and fractures, which is reflected in the low permeability of this lithology. The pebbly sandstone has the highest average illite and I/S contents compared to the other lithologies, which also proves this. Compared with the conglomerate with small pebbles (3.015 mD) and the sandy conglomerate (4.079 mD), the fine-grained conglomerate has a higher sand content and contains a large number of structural fractures, as well as some intragranular solution pores, intergranular solution pores, and residual intergranular pores, with soft plastic sand and argillaceous filling, resulting in reduced intergranular pore and fracture spaces. Therefore, the fine-grained conglomerate (8.28 mD) has a higher permeability. The relative clay mineral contents of the conglomerate with medium pebbles and the conglomerate with large pebbles are higher (Figure 9A), and the number of dissolved pores in the feldspar and quartz is significantly lower, resulting in a higher apparent density compared to the other lithologies. However, the structural and intergranular fractures are more developed in these lithologies. The fractures are mainly filled by chlorite and kaolinite, which has a small influence on the seepage channels; thus, the permeability is higher, and it is positively correlated with the gravel size.
In general, although the fine-grained conglomerate has the highest clay mineral content, chlorite and kaolinite are the dominant minerals. The filling of the intergranular pores and microfractures has little influence on the seepage capacity, so the permeability is relatively high. During diagenesis, kaolinite is mainly formed through the dissolution of feldspar [42]. The higher the I/S content is, the greater the degree of filling of the microfractures and the intergranular pores is, and the greater the influence on the seepage capacity is. In addition, as the sand content increases, the numbers of intergranular pores and structural fractures decrease, and the rock becomes tighter.
The clay minerals mainly fill the intergranular pores and secondary pores, leading to plugging of the primary intergranular pores and secondary pores and a decrease in the permeability. The negative correlation between the I/S content and the porosity is due to the hydration and expansion of the I/S when it encounters water and the phenomenon of particle migration (Figure 8). In addition, the filling of the pores with I/S occupies the reservoir space and destroys the pore structure, so the I/S content is negatively correlated with the porosity. The crystal shape of the kaolinite is relatively stable, so it can retain intergranular pores well, and some dissolution pores form during its generation. Intergranular pores and dissolution pores are important contributors to the reservoir space, so the kaolinite content is positively correlated with the porosity. Several scholars have studied the occurrence state of chlorite in the Baikouquan Formation reservoir in the Mahu Depression [26,43]. Their results show that chlorite exists in the form of chlorite film in the early stage and granular chlorite directly fills the pores in the late stage. The chlorite film is generally formed before the compaction stage, which inhibits the cementation of the quartz and thus protects the pore structure of the reservoir. However, the granular chlorite filling the pores occupies the original reservoir space and reduces the reservoir seepage capacity. Due to the coexistence of these two forms of chlorite in the Mahu conglomerate reservoir, there is no obvious correlation between the chlorite content and the porosity (Figure 10).

5.2. Effects of Clay Mineral Content on Interface Properties

The zeta potential is an indicator of the electrification of the reservoir surface and the stability of the clay colloidal dispersion system. Clays are colloids, and the charged colloidal particles repel each other, loosening the colloidal dispersion system of clays. The structural layers of clay minerals consist of silicon-oxygen tetrahedron and aluminum-oxygen octahedron, and the Si4+ and Al3+ in the centers of the tetrahedrons and octahedrons can be replaced by other ions, resulting in a charge. Si4+ and Al3+ are usually replaced by ions with lower charges. For example, Si4+ is often replaced by Al3+, and Al3+ is often replaced by Fe2+ and Mg2+, resulting in the clay minerals having a negative charge. Except for the fact that clay minerals may be positively charged under strong acidic conditions, usually clay minerals are negatively charged. The cation exchange capacity is the mole number of all of the exchangeable cations (e.g., K+, Na+, Ca2+, Mg2+, NH4+, H+, and Al3+) contained in the rock or soil per kilogram at pH = 7. Based on the definitions of the zeta potential and the cation exchange capacity (CEC), there is a certain relationship between them. The experimental results show that the CEC is positively correlated with the amount of negative charge carried by the clay minerals (Figure 11D), but the overall correlation is not strong. The lithologies with strong correlations include PS and SC, which have higher relative sandy contents, a stronger homogeneity, and a relatively more uniform spatial distribution of clay minerals. The main minerals in the MPC, SPC, and FGC are gravel, and the clay minerals are mainly concentrated in the gravel. Due to differences in the size and shape of the gravel and the uneven distribution of the gravel in the samples, the clay minerals are unevenly distributed in the samples. The clays that actually affect the effective porosity and flow channels are distributed outside of the gravel. This is also the reason why the correlations between the clay mineral content and the effective porosity and flow channels are poor. This leads to a poorer representativeness of the samples used in the experiments, which in turn leads to a weaker correlation between the two.
Similarly, the clay mineral content is positively correlated with the amount of negative charge carried by the sample (Figure 11A), but the correlation is poor. Through comparison of the various clay minerals, it was found that the smectite content is the most important factor affecting the amount of negative charge carried by the samples (Figure 11B). There is a logarithmic correlation between them overall, and the lithologies with the best correlation are also the PS and SC. The cations in the smectite crystal layer have exchangeable properties, that is, not only can the plasma exchange with K+, Na+, Ca2+, Mg2+, NH4+, H+, and Al3+, but it can also exchange with polynuclear metal cations and the organic cations between the crystal layer cations. The clay mineral content is the most important factor affecting the specific surface area of the samples (Figure 11C). The main pores of the PS are filled with a large amount of clay minerals, so the specific surface area is primarily affected by the clay mineral content, with a strong linear correlation. In the other lithologies, there are a large number of unfilled intragranular pores, intergranular pores, and intergranular fractures filled with clay. The specific surface area is affected not only by the clay mineral content but also by the proportion of dissolved pores in the grains. A large number of intra-granular dissolved pores have a poor connectivity with the flow channel. The larger the proportion of the dissolved pores in the grains is, the worse the correlation between the specific surface and the clay mineral content is. It is important to note that the CEC, zeta potential, and specific surface jointly affect the reservoir’s ability to adsorb fluids. As the clay mineral content increases, the CEC, zeta potential, and specific surface area increase. This increases the sample’s adsorption capacity, and thus, a greater adsorption force must be overcome to remove the oil from the rock surfaces. In other words, the seepage resistance increases.

5.3. Effects of Clay Mineral Content and Lithology on Pore-Throat Scale Distribution

The proportion of <100 nm pore throats was obtained by processing the high-pressure mercury injection data, and the correlation between the proportion of <100 nm pore throats (by volume) and clay mineral content was obtained by combining the mineral contents of each sample (Table 1, Figure 12). A linear relationship was found between the clay mineral content and the volume fraction of <100 nm pore-throats. The overall clay mineral content is higher in block Ma131 than in block Ma18, that is, the average proportion of >100 nm pore throats is higher in block Ma131 (37.21%) than in block Ma18 (31.82%). It was found that the lithology also exhibits a certain correlation with the proportion of <100 nm pore throats. The FGC has a high proportion of <100 nm pore throats due to its high clay mineral content (Figure 9). Although the SC, SPC, and MPC all contain <100 nm intragranular dissolved pores (Figure 4A,E,F; Figure 5A–C), they contain different volume proportions of nanopores. Due to the development of microfractures, in the SC and SPC, the dissolved pores in the nanoscale particles have a good connectivity, so a large number of dissolved pores can be connected. In addition, the high clay mineral content of the SPC results in a large number of the <100 nm intergranular pores and intergranular fractures being filled with clay minerals. Due to the lack of microfracture communication, the connectivity of the <100 nm dissolved pores in the MPC grains is poor. In addition, the larger gravel occupies a large volume, leading to a relatively lower clay mineral content, which is also the reason for the relatively small proportion of <100 nm pore throats.

5.4. Effects of Clay Mineral Content on Pore Connectivity

The bimodal shape of the high-pressure mercury injection curve reflects the range of the pore-throat radius domains (Figure 6), indicating that the pore-throat types and the multiscale porosity of the clays are complex [44,45]. The overall amount of movable fluid controlled by the <50 nm throats is lower (less than 40%) (Figure 13A). Most of the movable fluids are controlled by the <50 nm throats. The SPC, FGC, and MPC contain movable fluid controlled by the >1 μm pores, and cores No. 3, No. 4, and No. 6 mainly contain movable fluid that is controlled by the >1 μm pores, indicating the development of intergranular fractures. However, the total movable fluid saturation is low, the overall connectivity is poor, and there are a large number of <50 nm throats. The 50 nm to 1 μm throats control an average of 16.74% of the movable fluid saturation in the SC, FGC, and SPC reservoirs. However, the movable fluid differs within the same lithology and is mainly affected by the sedimentary facies and clay mineral content. It was found that the clay mineral content is negatively correlated with the movable fluid saturation (Figure 13B), with strong correlation. There is a large deviation in core No. 7. Based on the contents of the clay minerals (Table 1), it was found that the clay minerals in core No. 7 are mainly kaolinite and chlorite. The surface of the seepage channel is occupied by chlorite. This is helpful for maintaining the stability of the seepage channel. The kaolinite is mainly formed through chemical reactions during feldspar dissolution [46,47,48,49]. The crystal shape of kaolinite is relatively stable, and the intergranular pores can be retained well. Therefore, despite the low porosity of core No. 7, the permeability is high, and the saturation of the movable fluid controlled by the >50 nm throats is high. There is also a strong negative correlation between the I/S mineral content and the movable fluid saturation (Figure 13C). The honeycombed I/S can severely block the intergranular pores and fractures (Figure 5A), resulting in poor reservoir connectivity [18,34]. The deviation of core No. 2 is caused by the high chlorite content, which is mainly in the form of fine sand. Chlorite edging exists in the form of filling in the small pore throats, which results in the dense pore throats becoming tighter. Therefore, No. 2 core has a low movable fluid saturation in controlled by the >50 nm throats. The linear correlations between the kaolinite and chlorite contents and the movable fluid saturation controlled by the >50 nm throats are poor (Figure 13D), but the unique quadratic correlation is strong. When the kaolinite and chlorite contents are low, the overall clay content is relatively low, the primary pore throats is relatively well preserved and are intact, and the amount of movable fluid is large. When the kaolinite and chlorite contents are high (Figure 7, Figure 8 and Figure 13A), the cementation of the quartz by illite and smectite is inhibited, and the residual intergranular pores and fractures are retained. Due to chlorite edging, some of the throats are reduced in size, resulting in an increase in the movable fluid saturation controlled by the 50–500 nm throats.

6. Conclusions

The conclusions of this study are as follows.
(a) The average porosity and permeability of the tight conglomerate in the Mahu area are 8% and 2.2 mD, respectively, and the correlation between them is not significant. The conglomerate mainly consists of quartz, feldspar, clay minerals, and a small amount of calcite. The differences in the lithofacies are influenced by the sedimentary environment, resulting in differences in the clay mineral content among the different lithofacies. The clay mineral contents of the fine-grained conglomerate, the conglomerate medium pebbles the pebbly sandstone, the conglomerate with small pebbles, and the sandy conglomerate are 20.4%, 19.0%, 18.7%, 17.8%, and 13.7%, respectively. The clay minerals mainly include kaolinite, I/S, chlorite, and illite.
(b) There are significant positive correlations between the charge in the interface zone and the contents of the clay minerals, especially smectite, and the strength of the correlation has a certain relationship with the gravel content. The pebbly sandstone interface has the strongest correlation with the smectite content. The higher the charge is, the stronger the interface adsorption is, and the greater the seepage resistance is.
(c) The main types of pores in the tight conglomerate in the Mahu area are residual intergranular pores, intergranular dissolution pores, intergranular fractures, and intergranular dissolution pores. The proportion of pore throats with diameters of less than 100 nm ranges from 25.24% to 47.34%. There is a positive correlation between the proportion of nanopore throats and the clay mineral content. The fine-grained pebble conglomerate contains a large number of clay pores and local pores.
(d) The clay minerals and lithology jointly control the connectivity of the tight conglomerate. The movable fluid saturation controlled by the >50 nm pore throats in the overall tight conglomerate ranges from 8.7% to 33.72%, with an average of 20.24%. The clay mineral content, especially the I/S content, is negatively correlated with the movable fluid. The chlorite and kaolinite contents have unique quadratic relationships with the movable fluid in the range of 0%–22.2%. However, the clay minerals in the Mahu area are mainly I/S, and thus, as the clay mineral content increases, the pore-throat connectivity decreases, leading to a decrease in the movable fluid saturation.

Author Contributions

B.L.: Conceptualization, Methodology, Writing—original draft, Funding acquisition. L.S.: Project administration, Supervision, Funding acquisition. X.L.: Supervision, Investigation. C.F.: Investigation, Formal analysis. X.H.: Resources. Z.Z.: Resources, investigation. All authors have read and agreed to the published version of the manuscript.

Funding

This research was funded by Major project of CNPC (2021ZZ01-03) and CNPC science and technology project (2021DJ1103).

Acknowledgments

Core samples and a lot of data that Petrochina Xinjiang Oilfield Exploration and Development Research Institute provided, are much appreciate. This study was jointly supported by Major project of CNPC (2021ZZ01-03) and CNPC science and technology project (2021DJ1103). We thank LetPub (www.letpub.com, accessed on 9 November 2022) for its linguistic assistance during the preparation of this manuscript. Thanks to my wife, Zhai Yufei, for her support to the research.

Conflicts of Interest

All the authors declare no conflict of interest.

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Minerals 13 00009 g001 550
Figure 1. (A) Map showing the geographic location of the study area and the location of the well; and (B) integrated histogram of the sedimentary facies in Well M136.
Figure 1. (A) Map showing the geographic location of the study area and the location of the well; and (B) integrated histogram of the sedimentary facies in Well M136.
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Figure 2. Distributions of porosity and permeability in the Mahu area. ((A). Porosity; (B). Permeability).
Figure 2. Distributions of porosity and permeability in the Mahu area. ((A). Porosity; (B). Permeability).
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Figure 3. Correlation between porosity and permeability for the different conglomeratic lithologies in the Mahu area.
Figure 3. Correlation between porosity and permeability for the different conglomeratic lithologies in the Mahu area.
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Figure 4. Images of thin sections showing the morphology of the pore throats. (A) M154, 3024.39 m, sandy conglomerate; (B) M154, 3027.85 m, fine-grained conglomerate; (C) M154, 3070.74 m, conglomerate with large pebbles; (D) X89, 2231.26 m, pebbly sandstone; (E) X89, 2284.55 m, conglomerate with small pebbles; (F) X89, 2474.21 m, conglomerate with medium pebbles.
Figure 4. Images of thin sections showing the morphology of the pore throats. (A) M154, 3024.39 m, sandy conglomerate; (B) M154, 3027.85 m, fine-grained conglomerate; (C) M154, 3070.74 m, conglomerate with large pebbles; (D) X89, 2231.26 m, pebbly sandstone; (E) X89, 2284.55 m, conglomerate with small pebbles; (F) X89, 2474.21 m, conglomerate with medium pebbles.
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Figure 5. SEM images of samples from the Mahu tight reservoirs showing the relationships between the pore throats and clay minerals. (A) M136, conglomerate with small pebbles, 3295.1 m; (B) M131, sandy conglomerate, 3188.2 m; (C) M604, conglomerate with medium pebbles, 3782.6 m; (D) M136, pebbly sandstone, 3298.1 m; (E) M602, fine-grained conglomerate, 3882.6 m; (F) M604, fine-grained conglomerate, 3769.4 m.
Figure 5. SEM images of samples from the Mahu tight reservoirs showing the relationships between the pore throats and clay minerals. (A) M136, conglomerate with small pebbles, 3295.1 m; (B) M131, sandy conglomerate, 3188.2 m; (C) M604, conglomerate with medium pebbles, 3782.6 m; (D) M136, pebbly sandstone, 3298.1 m; (E) M602, fine-grained conglomerate, 3882.6 m; (F) M604, fine-grained conglomerate, 3769.4 m.
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Figure 6. Pore throat distribution obtained through high-pressure mercury injection experiments on core samples from blocks Ma131 and Ma18: (A) Block Ma131, well M139; and (B) Block Ma18, wells M18 and M604.
Figure 6. Pore throat distribution obtained through high-pressure mercury injection experiments on core samples from blocks Ma131 and Ma18: (A) Block Ma131, well M139; and (B) Block Ma18, wells M18 and M604.
Minerals 13 00009 g006aMinerals 13 00009 g006b
Minerals 13 00009 g007 550
Figure 7. NMR results of movable fluid saturation analysis of samples from the Mahu area. (A) Well M604, 3896.4 m, conglomerate with small pebbles; (B) Well M604, 3919.1 m, pebbly sandstone; (C) Well M139, 3267.0 m, sandy conglomerate; (D) Well M139, 3277.7 m, conglomerate with medium pebbles; (E) Well M18, 3882.5 m, sandy conglomerate; (F) Well M604, 3929.5 m, fine-grained conglomerate; (G) Well M137, 3256.4 m, fine-grained conglomerate; (H) Well M137, 3249.8 m, conglomerate with small pebbles.
Figure 7. NMR results of movable fluid saturation analysis of samples from the Mahu area. (A) Well M604, 3896.4 m, conglomerate with small pebbles; (B) Well M604, 3919.1 m, pebbly sandstone; (C) Well M139, 3267.0 m, sandy conglomerate; (D) Well M139, 3277.7 m, conglomerate with medium pebbles; (E) Well M18, 3882.5 m, sandy conglomerate; (F) Well M604, 3929.5 m, fine-grained conglomerate; (G) Well M137, 3256.4 m, fine-grained conglomerate; (H) Well M137, 3249.8 m, conglomerate with small pebbles.
Minerals 13 00009 g007
Minerals 13 00009 g008 550
Figure 8. Porosity, permeability, and apparent density of the different lithologies in the Mahu area.
Figure 8. Porosity, permeability, and apparent density of the different lithologies in the Mahu area.
Minerals 13 00009 g008
Minerals 13 00009 g009a 550Minerals 13 00009 g009b 550
Figure 9. Relationships between lithology and mineral contents in the Mahu area: (A) Total clay minerals; (B) Illite; (C) Kaolinite; (D) Chlorite; (E) Illite/smectite; (F) Potassium feldspar; and (G) Plagioclase. Note: FGC: fine-grained conglomerate; MPC: conglomerate with medium pebbles; SPC: conglomerate with small pebbles; PS: pebbly sandstone; SC: sandy conglomerate.
Figure 9. Relationships between lithology and mineral contents in the Mahu area: (A) Total clay minerals; (B) Illite; (C) Kaolinite; (D) Chlorite; (E) Illite/smectite; (F) Potassium feldspar; and (G) Plagioclase. Note: FGC: fine-grained conglomerate; MPC: conglomerate with medium pebbles; SPC: conglomerate with small pebbles; PS: pebbly sandstone; SC: sandy conglomerate.
Minerals 13 00009 g009aMinerals 13 00009 g009b
Minerals 13 00009 g010 550
Figure 10. Correlations between the porosity and permeability and the contents of the clay minerals for the samples from the Mahu area (A–F).
Figure 10. Correlations between the porosity and permeability and the contents of the clay minerals for the samples from the Mahu area (A–F).
Minerals 13 00009 g010
Minerals 13 00009 g011a 550Minerals 13 00009 g011b 550
Figure 11. Correlations between reservoir interface properties and clay mineral content in the Mahu area (A–D).
Figure 11. Correlations between reservoir interface properties and clay mineral content in the Mahu area (A–D).
Minerals 13 00009 g011aMinerals 13 00009 g011b
Minerals 13 00009 g012 550
Figure 12. Correlation between the clay content and the proportion of 100 nm pore throats.
Figure 12. Correlation between the clay content and the proportion of 100 nm pore throats.
Minerals 13 00009 g012
Minerals 13 00009 g013a 550Minerals 13 00009 g013b 550
Figure 13. Correlation between the movable fluid saturation distribution and the clay mineral content: (A) Movable fluid saturation distribution; (B) movable fluid saturation vs. clay mineral content; (C) movable fluid saturation vs. I/S content; and (D) movable fluid saturation vs. K + C content.
Figure 13. Correlation between the movable fluid saturation distribution and the clay mineral content: (A) Movable fluid saturation distribution; (B) movable fluid saturation vs. clay mineral content; (C) movable fluid saturation vs. I/S content; and (D) movable fluid saturation vs. K + C content.
Minerals 13 00009 g013aMinerals 13 00009 g013b
Table
Table 1. Bulk and clay mineral analysis results for samples from the Mahu area.
Table 1. Bulk and clay mineral analysis results for samples from the Mahu area.
BlockWellWell Depth (m)LithologyK (mD)Φ (%)Bulk Mineral Content (%)Clay Mineral Content (%)
QuartzPotassium FeldsparPlagioclaseCalciteDolomiteSideritePyriteClayIllKlnChlI/SS(I/S)
Ma131M1373249.8conglomerate with small pebbles0.1411.352.34.718.95.7 18.42.94.68.32.665
M1373255.7conglomerate with medium pebbles0.0897.4348.35.423.60.2 22.56.32.36.87.265
M1373256.4fine-grained conglomerate0.518.0350.72.317.90.2 28.92.66.615.64.065
M1373259.4conglomerate with medium pebbles0.1110.555.210.617.41.1 15.73.83.06.62.445
M1393264.8fine-grained conglomerate0.4210.748.15.018.7 0.3 27.93.63.614.56.130
M1393267sandy conglomerate0.2813.357.04.621.28.8 8.41.11.84.51.010
M1393268.3conglomerate with small pebbles0.269.650.36.426.41.6 15.32.93.18.01.410
M1393268.4conglomerate with small pebbles0.2210.949.45.627.61.31.1 15.02.93.57.51.210
M1393276.9conglomerate with medium pebbles0.28.9550.43.828.20.1 17.53.04.26.83.570
M1393277.7conglomerate with medium pebbles0.0768.9444.94.425.73.5 21.51.94.911.43.265
M1393285.4conglomerate with medium pebbles0.2713.356.06.619.32.9 15.22.63.28.11.410
M1393293.8pebbly sandstone0.1210.454.67.314.010.0 14.12.42.37.61.850
M1393296conglomerate with medium pebbles0.427.8653.64.725.30.6 15.84.62.84.93.575
M1393296.2conglomerate with medium pebbles0.0255.8452.26.517.91.30.7 21.45.12.89.63.955
M1393296.8fine-grained conglomerate0.05410.755.58.216.10.8 19.42.13.79.14.550
M1393297.5fine-grained conglomerate0.0728.252.38.723.10.8 15.13.22.66.82.650
M1393303.4conglomerate with medium pebbles0.596.446.44.826.25.6 17.02.93.78.22.250
M1393303.6conglomerate with medium pebbles0.278.5851.97.317.97.9 15.02.72.96.92.650
M1393304.2sandy conglomerate0.28.5252.15.222.60.8 19.32.33.19.54.465
M1393304sandy conglomerate0.139.4756.76.616.20.7 19.84.03.28.93.855
M1393305.3conglomerate with medium pebbles0.29.656.78.916.92.9 14.61.83.77.02.255
Ma18M183823.5sandy conglomerate0.0667.148.11.425.49.0 16.15.53.25.02.430
M183882.5sandy conglomerate1.451566.02.026.70.4 4.91.80.31.41.430
M6043929.2fine-grained conglomerate0.0736.7158.7 26.01.30.4 13.62.31.42.67.385
M6043932fine-grained conglomerate0.067.3252.02.321.00.6 24.14.13.49.67.090
M6043932.1fine-grained conglomerate0.138.4158.20.526.80.4 14.12.72.74.93.875
M6043932.5conglomerate with medium pebbles0.1410.2744.8 23.50.8 30.94.35.912.18.755
M6043933.2fine-grained conglomerate0.0957.2947.2 31.61.6 19.62.42.97.46.985
M6043933.4fine-grained conglomerate0.557.4552.6 30.61.3 15.52.62.03.77.190
M6043933.6conglomerate with medium pebbles0.367.8645.7 22.01.1 31.25.05.37.213.775
M6043925.1pebbly sandstone0.0245.6859.8 16.30.70.50.3 22.42.22.213.74.355
M6043923.5fine-grained conglomerate0.1110.647.6 32.70.1 19.64.33.74.37.385
M6043921.1pebbly sandstone0.0766.8947.1 31.8 21.14.22.78.06.190
M6043921.7conglomerate with small pebbles0.0626.0645.8 37.00.1 17.12.61.56.36.775
M6043919.1pebbly sandstone0.0174.4255.5 23.60.1 20.86.00.82.711.255
M6043919.7pebbly sandstone0.158.3247.5 31.40.1 21.06.71.34.68.485
M6043909.7pebbly sandstone0.57.158.1 22.60.4 0.218.75.01.91.710.190
M6043900conglomerate with medium pebbles0.529.6763.7 28.30.30.1 7.61.81.41.72.675
M6043900.3conglomerate with medium pebbles0.4911.252.5 35.30.40.40.30.210.93.81.41.44.385
M6043896.4conglomerate with small pebbles0.8611.249.8 27.42.8 20.05.62.84.86.885
M6043892.8fine-grained conglomerate0.11651.20.721.00.6 26.56.42.710.66.940
M6043883.2conglomerate with medium pebbles0.547.8149.2 25.20.5 25.17.51.36.89.570
Note: Φ: Porosity; K: Permeability; K: Kaolinite; C: Chlorite; I: Illite; S: Smectite; I/S: Interlaminar; C/S: Green/interlaminar%; S: Interlaminar ratio.
Table
Table 2. Interface properties of the samples from the Mahu area.
Table 2. Interface properties of the samples from the Mahu area.
BlockWellWell Depth (m)LithologyK (mD)Φ (%)Zeta-Potential (mV)Surface Area (m2/g)Cation Exchange Capacity (cmol/kg)
Ma131M1373249.8conglomerate with small pebbles0.1411.3−7.02.566.429
M1373255.7conglomerate with medium pebbles0.0897.43−7.8 8.186
M1373256.4fine-grained conglomerate0.518.03−8.53.739.719
M1373259.4conglomerate with medium pebbles0.1110.5−5.52.797.475
M1393264.8conglomerate with small pebbles0.4210.7−4.3 6.113
M1393267sandy conglomerate0.2813.3−3.62.6151.343
M1393268.3conglomerate with small pebbles0.269.6−4.42.4774.684
M1393268.4conglomerate with small pebbles0.2210.9−3.02.8973.863
M1393276.9conglomerate with medium pebbles0.28.95−6.33.0966.165
M1393277.7conglomerate with medium pebbles0.0768.94−4.84.1524.484
M1393285.4conglomerate with medium pebbles0.2713.3−4.53.248.085
M1393293.8pebbly sandstone0.1210.4−4.41.6362.454
M1393296conglomerate with medium pebbles0.427.86−6.62.79.453
M1393296.2conglomerate with medium pebbles0.0255.84−7.02.957.458
M1393296.8fine-grained conglomerate0.05410.7−7.1 4.379
M1393297.5fine-grained conglomerate0.0728.2−4.82.4095.99
M1393303.4conglomerate with medium pebbles0.596.4−5.83.5392.792
M1393303.6conglomerate with medium pebbles0.278.58−5.73.7585.133
M1393304.2sandy conglomerate0.28.52−5.34.1787.784
M1393304sandy conglomerate0.139.47−6.13.5216.935
M1393305.3conglomerate with medium pebbles0.29.6−6.33.0214.564
Ma18M183823.5sandy conglomerate0.0667.1−4.84.1971.43
M183882.5sandy conglomerate1.4515−7.3 11.588
M6043929.2fine-grained conglomerate0.0736.71−7.93.039.549
M6043932fine-grained conglomerate0.067.32−7.44.649.541
M6043932.1fine-grained conglomerate0.138.41−6.33.579.062
M6043932.5conglomerate with medium pebbles0.1410.27−6.7 12.137
M6043933.2fine-grained conglomerate0.0957.29−5.85.1746.913
M6043933.4fine-grained conglomerate0.557.45−4.22.6644.616
M6043933.6conglomerate with medium pebbles0.367.86−8.1
M6043925.1pebbly sandstone0.0245.68−6.05.4643.592
M6043923.5fine-grained conglomerate0.1110.6−5.42.3843.526
M6043921.1pebbly sandstone0.0766.89−5.92.4342.242
M6043921.7conglomerate with small pebbles0.0626.06−5.62.4442.173
M6043919.1pebbly sandstone0.0174.42−6.85.1872.902
M6043919.7pebbly sandstone0.158.32−6.64.6674.025
M6043909.7pebbly sandstone0.57.1−7.32.7694.14
M6043900conglomerate with medium pebbles0.529.67−7.12.4684.74
M6043900.3conglomerate with medium pebbles0.4911.2−6.01.7494.352
M6043896.4conglomerate with small pebbles0.8611.2−6.62.4283.049
M6043892.8fine-grained conglomerate0.116−5.3 8.311
M6043883.2conglomerate with medium pebbles0.547.81−5.5 11.299
Note: Φ: Porosity.
Table
Table 3. Pore-throat parameters from the high-pressure mercury injection experiments on the samples from the Mahu area.
Table 3. Pore-throat parameters from the high-pressure mercury injection experiments on the samples from the Mahu area.
BlockNO.LithologyΦ (%)K (mD)Pore Throat ParametersSorting ParametersConnectivity Parameters
Rt (μm)Rm (μm)Throat Sorting CoefficientRelative Sorting CoefficientPd (MPa)Sf (%)Mercury Ejection Rate (%)
Ma131M139-20SC8.520.20.170.013.950.390.5069.4935.67
M139-19MPC8.940.0760.15/5.381.020.8038.5532.59
M137-26FGC8.030.510.320.014.340.520.3062.1338.02
M139-27MPC13.30.270.370.033.470.360.3073.6428.45
M139-14SPC10.70.420.560.042.880.270.1583.0139.22
M139-13PS10.40.120.180.023.540.360.5072.8536.98
Ma18M18-1SC7.10.0660.260.014.610.580.3058.6227.77
M604-2MPC9.670.521.12/5.371.060.0837.8328.39
M604-5SPC11.20.860.520.015.040.670.2054.0825.61
M604-15FGC7.450.550.740.014.740.620.1558.2523.60
M604-19PS8.410.130.19/5.631.330.5029.2730.10
M604-22MPC11.20.491.510.014.570.680.0555.9417.37
Max14.853.921.510.045.631.330.8083.0139.22
Min7.040.050.150.012.880.270.0529.2717.37
Average10.760.940.940.940.940.940.940.940.94
Φ: Porosity; K: Permeability; Rt: Average throat radius; Rm: Median radius; Sf: Final total mercury saturation; Pd: Displacement pressure.
Table
Table 4. Movable fluid saturation controlled by different throat radius intervals.
Table 4. Movable fluid saturation controlled by different throat radius intervals.
NO.WellDepth (m)Lithology>1 μm0.5–1 μm0.10–0.5 μm0.05–0.1 μmTotal
1M6043921.7SPC2.89%0.08%6.35%6.45%15.77%
2M6043925.1PS0.10%8.16%0.39%0.05%8.70%
3M1393304.2SC7.49%3.69%4.88%3.60%19.66%
4M1393296.2MPC7.83%2.00%1.13%1.40%12.36%
5M183882.5SC2.62%2.05%24.11%4.94%33.72%
6M6043929.5FGC6.67%3.11%1.41%3.91%15.10%
7M1373256.4FGC0.02%4.98%10.76%16.12%31.88%
8M1373249.8SPC0.39%3.83%17.37%3.16%24.75%
Max7.83%8.16%24.11%16.12%33.72%
Min0.02%0.08%0.39%0.05%8.70%
Average3.50%3.49%8.30%4.95%20.24%
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Li, B.; Sun, L.; Liu, X.; Feng, C.; Zhang, Z.; Huo, X. Effects of Clay Mineral Content and Types on Pore-Throat Structure and Interface Properties of the Conglomerate Reservoir: A Case Study of Baikouquan Formation in the Junggar Basin. Minerals 2023, 13, 9. https://doi.org/10.3390/min13010009

AMA Style

Li B, Sun L, Liu X, Feng C, Zhang Z, Huo X. Effects of Clay Mineral Content and Types on Pore-Throat Structure and Interface Properties of the Conglomerate Reservoir: A Case Study of Baikouquan Formation in the Junggar Basin. Minerals. 2023; 13(1):9. https://doi.org/10.3390/min13010009

Chicago/Turabian Style

Li, Bowen, Linghui Sun, Xiangui Liu, Chun Feng, Zhirong Zhang, and Xu Huo. 2023. "Effects of Clay Mineral Content and Types on Pore-Throat Structure and Interface Properties of the Conglomerate Reservoir: A Case Study of Baikouquan Formation in the Junggar Basin" Minerals 13, no. 1: 9. https://doi.org/10.3390/min13010009

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