Study on Microscopic Pore Structure Classification for EOR of Low Permeability Conglomerate Reservoirs in Mahu Sag

Abstract

The microscopic pore structure controls the fluid seepage characteristics, which in turn affect the final recovery of the reservoir. The pore structures of different reservoirs vary greatly; therefore, the scientific classification of microscopic pore structures is the prerequisite for enhancing the overall oil recovery. For the low permeability conglomerate reservoir in Mahu Sag, due to the differences in the sedimentary environment and late diagenesis, various reservoir types have developed in different regions, so it is very difficult to develop the reservoir using an integrated method. To effectively solve the problem of microscopic pore structure classification, the low permeability conglomerate of the Baikouquan Formation in Well Block Ma18, Well Block Ma131, and Well Block Aihu2 are selected as the research objects. The CTS, HPMI, CMI, NMR, and digital cores are used to systematically analyze the reservoir micro pore structure characteristics, identify the differences between different reservoir types, and optimize the corresponding micro pore structure characteristic parameters for reservoir classification. The results show that the pore types of the low permeability conglomerate reservoir in the Baikouquan Formation of the Mahu Sag are mainly intragranular dissolved pores and residual intergranular pores, accounting for 93.54%, microfractures and shrinkage pores that are locally developed, accounting for 5.63%, and other pore types that are less developed, accounting for only 0.83%. On the basis of clear pore types, the conglomerate reservoir of the Baikouquan Formation is divided into four types based on the physical properties and microscopic pore structure parameters. Different reservoir types have good matching relationships with lithologies. Sandy-grain-supported conglomerate, gravelly coarse sandstone, sandy-gravelly matrix-supported conglomerate, and argillaceous-supported conglomerate correspond to type I, II, III, and IV reservoirs, respectively. From type I to type IV, the corresponding microscopic pore structure parameters show regular change characteristics, among which, porosity and permeability gradually decrease, displacement pressure and median pressure increase, maximum pore throat radius, median radius, and average capillary radius decrease, and pore structure becomes worse overall. Apparently, determining the reservoir type, clarifying its fluid migration rule, and formulating a reasonable development plan can substantially enhance the oil recovery rate of low permeability conglomerate reservoirs.

1. Introduction

In recent years, as conventional oil and gas production has continued to decline, unconventional oil and gas resources have gradually become a global research hotspot, among which, low permeability sand and conglomerate reservoirs are the focus of exploration and development in China′s energy sector and have huge development potential [1,2,3,4,5]. Compared with conventional reservoirs, low permeability conglomerate reservoirs are characterized by dense pores, poor physical properties, and strong heterogeneity [6]. Low permeability conglomerate reservoirs have a wider distribution of pore throats and more complex pore structures. The complex microscopic pore structure and severe heterogeneity not only affect the permeability of the reservoir but are also in close connection with the development effect of the oil and gas reservoir [2,7,8,9,10,11,12].

Due to the special sedimentary environment, limited distribution space, and complex pore structure, the research of low permeability conglomerate reservoirs is difficult, the research progress is slow, and it is difficult to obtain systematic results, which is also the weakness of clastic reservoir research. Microscopic pore structure is one of the most basic and important points in reservoir geology studies. At present, the study of reservoir microscopic pore structure is mainly focused on characterization. Wu et al. used scanning electron microscopy and X-ray diffraction analysis to clarify the reservoir space of low permeability conglomerate reservoirs, used conventional physical tests and mercury pressure experiments to characterize the throats of different lithofacies, and then comprehensively analyzed the reservoir genesis [13]. Du et al. used a combination of pressurized mercury experiments, nuclear magnetic resonance (NMR), casting thin sections (CTS), CT scans, scanning electron microscopy, and microscopic image stitching to characterize the microscopic pore structure of low permeability conglomerate reservoirs in a more comprehensive manner [14]. Although scholars have used multiple methods to characterize the microscopic pore structures of low permeability conglomerate reservoirs, they have not further classified them or established corresponding evaluation criteria, so they have limited effect on actual production. Jin et al. established a conglomerate reservoir classification method and productivity prediction model based on NMR logging data [15]. Huang et al. analyzed the reservoir characteristics and proposed corresponding classification indexes using physical analysis, CTS, constant rate mercury injection (CMI), and NMR [16]. Although the above two scholars conducted exploratory studies on the classification of reservoirs, their classification criteria did not provide an in-depth study of the microscopic pore structure of reservoirs. Therefore, how to establish the reservoir classification criteria based on microscopic pore structure is still one of the important problems that needs to be solved urgently.

In order to make up for this deficiency, we selected Mahu Sag, a typical and highly concerned hydrocarbon-rich sag in China, as the research area. Mahu Sag is one of the six major hydrocarbon-producing Sags in Junggar Basin (Xinjiang, NW China), with an exploration area of about 5000 km² (Figure 1a,b) [10]. The discovered oil reservoirs in the northwest margin of the Junggar Basin include volcanic rocks, volcanic clastic rocks, dolomites, shales, sandstones, and conglomerates. The reservoir of the Baikouquan Formation in Mahu Sag is a fan delta deposit, which can be divided into Baiyi Member (T₁b₁), Bai′er Member (T₁b₂), and Baisan Member (T₁b₃) from bottom to top. The main oil layers are distributed in T₁b₁ and T₁b₂ (Figure 1c). The overall thickness of the stratum is about 100–200 m, and the lithology is diverse, including coarse conglomerate, medium conglomerate, fine conglomerate, coarse sandstone, medium sandstone, sandstone, and mudstone. On the whole, the reservoir lithology of the Baikouquan Formation is sandy conglomerate, with poor physical properties [13,17,18,19,20]. The resource potential of the low permeability conglomerate reservoir in the Mahu Sag is huge, with total proven reserves of 520 million tons, a total production capacity of 6.334 million tons and annual oil production already exceeding 2 million tons in 2020. By analyzing the production effect of the low permeability conglomerate reservoir in the Mahu Sag, it can be seen that due to the extensive distribution of fine throat channels in the reservoir and the complex pore seepage system, the production pattern generally shows the development characteristics of large differences in oil and gas production from a single well, a high oil and gas decreasing rate, and low recovery rate [21,22,23].

Thus, the microscopic pore structure of the reservoir controls the seepage characteristics of the fluid, which in turn affects the ultimate recovery of the reservoir [25,26]. Previously, we studied the fluid migration rule in the low permeability conglomerate reservoir in the Mahu Sag and proposed a combination of displacement and soaking methods to effectively exploit the reservoir [24]. However, in the previous study, we only selected the low permeability conglomerate of Ma18 Well Block in Mahu Sag, but, in fact, there are many well blocks in Mahu Sag. Therefore, in order to realize the collaborative development of different well blocks, we expanded the scope of study and selected Ma18 Well Block, Ma131 Well Block, and Aihu2 Well Block as the study areas. The specific object of this study is the low permeability conglomerate reservoir of Baikouquan Formation, with the focus on the microscopic pore structure. Experiments such as high-pressure mercury injection (HPMI), CMI, CTS, NMR, and digital cores were used to quantitatively characterize the distribution of pore structures and pore throat configuration relationships at different scales, to clarify the differences in the microscopic pore structure parameters of different reservoirs, and then effectively classify the reservoir types. By comparing the multi-parameter classification results of the reservoir with the previous research result of migration rule, the corresponding migration rules of different types of reservoirs can be determined, so as to select the appropriate development method; that is, the effective combination of displacement and soaking. Therefore, this study of reservoir classification is an important prerequisite for clarifying the fluid migration rule, determining the appropriate development method, and then enhancing the overall oil recovery and providing a geological and theoretical basis for the refined exploitation and differentiated development of low permeability conglomerate reservoirs in the Mahu Sag.

2. Experimental Methods

2.1. Samples

The experimental samples were selected from the low permeability conglomerate reservoir of the Baikouquan Formation in Well Block Ma18, Well Block Ma131, and Well Block Aihu2, which belongs to Mahu Sag. Based on the core observation and basic physical properties, representative samples were preferably selected for various experimental tests. In order to more comprehensively characterize the microscopic pore structure of the low permeability conglomerate reservoir in the Mahu Sag, the experimental methods included not only conventional experiments such as CTS, HPMI, and digital cores, but also high-precision technical methods such as CMI and NMR.

2.2. Materials and Instruments

Experimental materials: The experimental water was taken from the actual formation water of the Baikouquan Formation, crude oil from the well of Baikouquan Formation, and the parameters are shown in

Table 1. Experimental material parameters.

Formation Water	Water type		CaCl2	Crude Oil	Density (g/cm3)	0.827
	Total salinity (mg/L)		11,047.4		Viscosity at 50 ℃ (MPa•s)	8.6
	Main ion mineralization (mg/L)	Na++K+	3054.2		Wax content (%)	8.2
		Mg2+	38.5
		Ca2+	1055.3		Freezing point (℃)	16.6
		SO42−	105.5
		Cl−	6295.1		Initial boiling point (℃)	137.2
		HCO3−	538.9

.

Experimental instruments: CMI (Glocom, Inc., ASPE-730, Chicago, IL, USA); HPMI (Core Laboratories: The Reservoir Optimization Company, OBMI Overburden Mercury Injection System, Houston, USA); NMR (PetroChina Pipeline Jingci New Materials Co., Ltd., SPEC035, Hong Kong, China); digital cores (Carl Zeiss AG, ZEISS Xradia 510 Versa, Oberkochen, Germany).

2.3. CMI Steps

(1) Put 9 core samples obtained by closed coring into the core holder, apply confining pressure, and freeze for more than 48 hours under the reservoir temperature. (2) The sample is vacuumed to ensure that the nature of irreducible water is consistent with that of oilfield formation water. Under the condition of saturated irreducible water, crude oil is used to displace water, and the irreducible water model is established. (3) Displace the crude oil at the mercury injection rate of 0.0005 mL/min, and record the capillary pressure change curve with the increase in mercury injection. (4) Continue to displace until mercury no longer enters the sample, and then end the experiment. Use the pressure change curve to determine the distribution of pores and throats, and determine the impact of different pore types on oil displacement efficiency in combination with the amount of mercury intake.

2.4. NMR Steps

(1) Put the core samples obtained by the closed coring method into the core holder, add the confining pressure, and freeze for more than 24 hours under the reservoir temperature. (2) Water drive oil at a constant speed of 0.02 mL/min, record the displacement pressure difference and oil production until the water content of the driven liquid reaches above 98%. (3) The simulated formation water is used to drive oil at a constant speed of 0.02 mL/min, and the relationship between displacement PV, displacement pressure difference, and oil production is recorded. (4) NMR test is performed on the core after displacement to determine the pore throat distribution of the core. (5) Wash the core and test the porosity and permeability of the core.

3. Microscopic Pore Throat Characteristics

3.1. Pore Types

The pore space and throat channel of the rock jointly form the pore structure of the rock, and the study of the pore structure of the reservoir is of great significance to the exploration and development of oil and gas fields [10,27]. The analysis of typical core samples from the study area shows that the lithology of the Baikouquan Formation of the Mahu Sag is dominated by gray and brown medium conglomerates and fine conglomerates, followed by grayish-green, gravel-bearing, unequal-grained lithic sandstone and gravel-bearing, medium-coarse-grained lithic sandstone. The sedimentary particles are poorly sorted, the gravels are of unequal size, the structural maturity and compositional maturity are relatively low, the heterogeneity is strong, the pore structure is dominated by particle support, and the cementation type is press-embedded porous cementation.

Due to the periodic changes in the sedimentary environment and hydrodynamic conditions, the Baikouquan Formation developed a different lithology, which controls the physical and oil-bearing properties of the reservoir [28,29]. Based on the lithological distribution characteristics of the reservoir, combined with the differences in the physical property and oil-bearing property, the conglomerate reservoirs of Baikouquan Formation in Mahu Sag are divided into four types, namely, sandy grain-supported conglomerate with good physical properties and oil-bearing properties (Figure 2a), gravelly coarse sandstone with good physical properties and oil-bearing properties (Figure 2b), sandy-gravelly matrix-supported conglomerate with medium physical properties and oil-bearing properties (Figure 2c), and argillaceous-supported conglomerate with poor physical properties and oil-bearing properties (Figure 2d).

Pore space is an important medium for fluid occurrence and seepage, and its type is mainly controlled by the depositional environment and late diagenesis. The results of CTS show that the pore types of the low permeability conglomerate reservoir in the Baikouquan Formation of the Mahu Sag are dominated by residual intergranular pores (Figure 3a,d) and intragranular dissolved pores (Figure 3b,c,e), accounting for a total of 93.54%, with microfractures (Figure 3i) and shrinkage pores (Figure 3f) that are locally developed accounting for 5.63%, while intergranular pores and intergranular dissolved pores account for a relatively small percentage of 0.83%. The large volume of intragranular pores in the reservoir is formed by the dissolution by groundwater, while the residual intergranular pores are formed as a result of rock particles and the original pore space within the rock being modified by later compaction, cementation, and other diagenesis. Three types of microfractures have mainly developed in the reservoir, which are gravel edge fractures (Figure 3g), tectonic fractures (Figure 3h), and intragranular fractures (Figure 3i). The development of microfractures can effectively increase the permeability of the reservoir and improve the seepage capacity of crude oil. Shrinkage pores are mainly formed by the shrinkage of the matrix caused by temperature and pressure changes. Although shrinkage pores are less distributed in the reservoir, they have a certain impact on the permeability of the reservoir [30]. To sum up, the reservoir of the Baikouquan Formation in Mahu Sag is generally characterized by small pores and fine throats, mainly developing curved lamellar throats, lamellar throats, and tube-shaped throats, which are irregular in shape and small in shape factor, easily cause the retention of crude oil in the pore throat, cause difficulty for displacement, and have low oil recovery.

3.2. Microscopic Pore Throat Structure

On the basis of clear pore types, the results of HPMI, CMI, NMR, and digital cores show that the pore throat radius of the low permeability conglomerate reservoir in the Mahu Sag has a relatively wide distribution range, mainly concentrated between 0.03 and 35.8 μm. The pore throat radius distribution range and main distribution frequencies of reservoirs in different well blocks differ greatly, and their corresponding NMR T₂ spectrum distribution characteristics and pore throat coordination numbers are also different (Figure 4).

The NMR signal and pore throat radius of conglomerate samples from Well Block Ma18 show a bimodal distribution; the large pore throat with a radius of 1–5 μm has a strong NMR signal amplitude and high distribution frequency, which is the main contribution space of permeability (Figure 4a). Its average coordination number is up to 2.63, with a good pore throat structure and strong permeability. For conglomerate samples from Well Block Ma131, the NMR signal and pore throat radius also show a bimodal distribution, but the NMR signal amplitude of large pore throats is weakened and the distribution frequency is reduced; the medium-scale pore throat with a radius of 0.5–2 μm is developed with high frequency and is the main contribution space of permeability (Figure 4b). Its average coordination number is 2.37 with a medium pore throat structure and permeability. The NMR signal bimodal distribution of conglomerate samples from Well Block Aihu2 is unobvious, and the small pore throat NMR signal with a radius of 0.2–1 μm has a strong amplitude and high distribution frequency, which is the main contribution space of permeability, while the large pore throat radius has a very low distribution frequency, resulting in low permeability (Figure 4c). Its average coordination number is the minimum, only 2.06, and the pore throat structure is the worst, with low permeability.

The microscopic pore throat structure characteristics of the low permeability conglomerate reservoir of the Baikouquan Formation in different well blocks of the Mahu Sag vary greatly. In order to reasonably classify the reservoir type of the whole reservoir, realize the refined development of the reservoir, and enhance the overall recovery, the lithology of different well blocks is used as the basis for classification, and the variability of the pore structure of different lithologies is determined by various experimental methods (

Table 2. Microscopic pore structure characteristics of low permeability conglomerate samples with different lithologies.

Lithology	Sandy-Grain-Supported Conglomerate	Gravelly Coarse Sandstone	Sandy-Gravelly Matrix-Supported Conglomerate	Argillaceous-Supported Conglomerate
Core Photos
CTS
3D Digital Cores
Pore Network Model
CMI
NMR

).

Sandy-grain-supported conglomerate has the coarsest particles, a large number of intragranular dissolved pores and residual intergranular pores, the largest pore volume, and a wide range of pore throat coordination numbers, mainly 1–9. The constant rate mercury injection curve shows a coarse skewness, which is characterized by low displacement pressure and high mercury saturation. Its starting pressure and median pressure are relatively small, the pore throat radius distribution range is large, the average value is high, the pore throat volume ratio is large, and the pore throat is well matched. The T₂ spectrum shows obvious trimodal distribution, indicating that sandy-grain-supported conglomerate has large pores, high porosity, and good permeability, and its pore structure is superior to that of other lithologic reservoirs.

Gravelly coarse sandstone has coarse particles, compared with sandy-grain-supported conglomerate, the intragranular pores are more developed, and the pore volume is reduced. Its main distribution interval of pore throat coordination number is 1–7. The constant rate mercury injection curve shows a medium skewness, which is characterized by medium displacement pressure and high mercury saturation. Its starting pressure and median pressure are small, the pore throat radius distribution range is medium, the average value is high, the pore throat volume ratio is large, and the pore throat is medium matched. The T₂ spectrum is characterized by a bimodal distribution, the large pores are less developed than the sandy-grain-supported conglomerate, with medium porosity and good permeability, and the reservoir pore structure is medium.

Sandy-gravelly matrix-supported conglomerate has medium particles and small pore volume, and its pore throat coordination number is mainly distributed in 1–5. The constant rate mercury injection curve shows a fine skewness, which is characterized by medium displacement pressure and low mercury saturation. Its starting pressure and median pressure are medium, the pore throat radius distribution range is medium, the average value is medium, the pore throat volume ratio is small, and the pore throat is poorly matched. The bimodal distribution of the T₂ spectrum is not obvious, indicating that the sandy-gravelly matrix-supported conglomerate has a very small number of large pores with low porosity and low permeability, and the pore structure is poor.

The argillaceous-supported conglomerate has the finest particles with small pore volume, and most pore throat coordination numbers are below 3. The constant rate mercury injection curve is not skewed, which is characterized by high displacement pressure and low mercury saturation. Its starting pressure and median pressure are high, the pore throat radius distribution range is small, the average value is low, the pore throat volume ratio is the smallest, and the pore throat is the poorest matched. The T₂ spectrum shows a unimodal distribution, and the argillaceous-supported conglomerate has almost no large pores, showing typical low porosity and low permeability characteristics, which is the worst pore structure among the four lithologies of the reservoir.

The pore structure characteristics of low permeability conglomerate reservoirs in the Baikouquan Formation of Mahu Sag vary greatly with different lithologies. From the quantitative characterization parameters of the microscopic pore structures of the four lithologies (

Table 3. Microscopic pore structure parameters of core samples with different lithologies.

Lithology	Sandy Grain-Supported Conglomerate	Gravelly Coarse Sandstone	Sandy-Gravelly Matrix-Supported Conglomerate	Argillaceous-Supported Conglomerate
Average Throat Radius (mm)	5.94	3.24	3.83	2.95
Average Pore Radius (mm)	178.31	160.13	169.94	160.14
Average Pore/Throat Radius Ratio	45.85	110.92	91.99	91.67
Average Pore Volume (nl)	28.74	22.16	26.9	23.12
Average Capillary Radius (mm)	5.97	3.1	3.23	2.43
Root Mean Square Value of Throat Radius (ΜM)	7.87	4.19	4.46	3.48
The radius of Main Throat (mm)	3	2	2	2.33
Final Mercury Saturation (%)	52.38	34.71	49.22	27.59
Total Pore Mercury Saturation (%)	9.92	5.21	16.63	2.75
Total Throat Mercury Saturation (%)	42.46	29.5	32.5 9	24.83
Total Pore/Throat Volume Ratio	0.23	0.17	0.44	0.11
Displacement Pressure (MPa)	0.01	0.08	0.45	0.1

), it can be seen that for the sandy-grain-supported conglomerate, the average throat radius is 5.94 μm, the average pore radius is 178.31 μm, the average pore volume is 28.74 nl, the final mercury saturation is 52.38%, and the total pore/throat volume ratio is 0.23, which is the best among all lithologies with good pore throat connectivity. For the gravelly coarse sandstone, the average throat radius is 3.24 μm, the average pore radius is 160.13 μm, the average pore volume is 22.16 nl, the final mercury saturation is 34.71%, and the total pore/throat volume ratio is 0.17, and compared with sandy-grain-supported conglomerate, the pore throat connectivity is worse. For the sandy-gravelly matrix-supported conglomerate, the average throat radius is 3.83 μm, the average pore radius is 169.94 μm, the average pore volume is 26.90 nl, the final mercury saturation is 49.22%, the total pore/throat volume ratio is 0.44, and the pore throat connectivity is medium. For the argillaceous-supported conglomerate, the average throat radius is 2.95 μm, the average pore radius is 160.14 μm, the average pore volume is 23.12 nl, the final mercury saturation is 27.59%, the total pore/throat volume ratio is 0.11, and the pore throat connectivity is the worst. In general, from sandy-grain-supported conglomerate to argillaceous-supported conglomerate, the difference in rock particle size becomes larger, the heterogeneity of the reservoir increases, and its corresponding macroscopic physical properties and microscopic pore structure gradually deteriorate.

In addition, it can be seen from the pore throat radius distribution map of different lithological reservoirs in the Mahu Sag (Figure 5) that the distribution range and main distribution frequency of the pore throat radius of different lithological reservoirs also vary greatly. For the sandy-grain-supported conglomerate, the average pore throat radius is the largest and most widely distributed, with a large proportion of large pore throats, good pore connectivity, large reservoir space, and the best physical properties. For the gravelly coarse sandstone, the pore throat radius and its distribution range are smaller than sandy-grain-supported conglomerate, with slightly reduced large pore throats and pore connectivity, medium reservoir space and good physical properties. For the sandy-gravelly matrix-supported conglomerate, the pore throat radius and its distribution range are small, with few large pore throats, poor pore connectivity, less reservoir space, and poor physical properties. For the argillaceous-supported conglomerate, the pore throat radius and its distribution range are the smallest, there are almost no large pore throats, the pore connectivity is the worst, the reservoir storage space is the smallest, and the physical properties are the worst. It can be seen that the microscopic pore structure of the low permeability conglomerate reservoir in the Mahu Sag, from sandy-grain-supported conglomerate to argillaceous-supported conglomerate, gradually deteriorates, the distribution range of pores and throats becomes narrower, and the main distribution frequency moves toward the small pore throat. To sum up, for the low permeability conglomerate reservoir in Mahu Sag, the distribution of the micro pore structures controls the porosity and permeability of the reservoir. The difference in the distribution frequency of the pore throat radius leads to the difference in the permeability of the reservoir, which further affects the development characteristics and recovery efficiency of the reservoir.

Through the comparison of throat radius distribution and pore radius distribution, it can be seen that the difference in the pore radius distribution frequency of different lithologies is not very large, which indicates that the porosity difference of the reservoir is small, but the difference in the throat radius distribution frequency is relatively large, which affects the seepage capacity of the reservoir, leading to large differences in the permeabilities of the four lithologies, and different production laws.

4. Reservoir Classification

A comparative analysis of the pore structures of different lithologies in the low permeability conglomerate reservoir of the Baikouquan Formation in the Mahu Sag shows that the depositional environment, hydrodynamic conditions, and later diagenesis jointly control the lithology distribution, while the lithology controls the physical properties and oil content of the reservoir. The pore throat radius distribution range and main distribution frequency of different lithologies in the Baikouquan Formation are different, and the distribution characteristics of their corresponding NMR T₂ spectra and pore throat coordination numbers are also different, resulting in large differences in microscopic pore structure parameters, which affect the seepage capacity of crude oil and ultimately cause limited enhancement in the overall recovery of the reservoir.

Based on the test results of CTS, CMI, HPMI, NMR, and digital cores, the physical parameters and microscopic pore structure parameters were comparatively studied by multi-factor analysis, and the low permeability conglomerate reservoir of the Baikouquan Formation in the Mahu Sag was divided into four types of reservoirs corresponding to the lithology, among which types I–IV correspond to four lithologies, including sandy-grain-supported conglomerate, gravelly coarse sandstone, sandy-gravelly matrix-supported conglomerate, and argillaceous-supported conglomerate, respectively.

Through comprehensive analysis of the quantitative characterization parameters, the cut-off values of the microscopic pore structure parameters for different reservoir types were established (

Table 4. Microscopic pore structure parameters of different reservoirs.

Reservoir Type	Porosity (%)	Permeability (mD)	Displacement Pressure (MPa)	Maximum Pore Throat Radius (mm)	Median Pressure (MPa)	Median Radius (mm)	Average Capillary Radius (mm)	Saturated Pore Volume Percentage (%)	Mercury Ejection Efficiency (%)
Type Ⅰ	5.9–14.8 9.46	0.32–86.4 2.85	0.16	35.8	0.5	1.12	35.8–0.035 1.42	77.5	18.6
Type Ⅱ	4.7–12.6 8.36	0.27–73.6 1.54	0.2	8.96	1.8	0.58	8.96–0.035 0.92	78.4	19.4
Type Ⅲ	4.3–10.7 7.72	0.18–25.3 1.06	0.32	4.59	10.1	0.26	4.59–0.03 0.51	66.3	16.4
Type Ⅳ	2.7–9.2 5.86	0.04–8.93 0.43	0.36	2.32	11.2	0.14	2.32–0.03 0.29	60.4	21.2

). As the low permeability conglomerate reservoir changes from type I to type IV, the porosity and permeability of the reservoir decrease and the microscopic pore structure parameters also show regular change characteristics. The displacement pressure and median pressure of the reservoir increase from 0.16 MPa and 0.5 MPa for a type I reservoir to 0.36 MPa and 11.2 MPa for a type IV reservoir, respectively, while the maximum pore throat radius, median radius, and average capillary radius decreased, with the maximum pore throat radius decreasing from 35.8 μm to 2.32 μm, the median radius decreasing from 1.12 μm to 0.14 μm, and the average capillary radius being reduced from 1.42 μm to 0.29 μm. It can be seen that the macroscopic physical properties and microscopic pore structures of the different reservoir types in the low permeability conglomerate reservoir of the Baikouquan Formation in the Mahu Sag vary greatly, and the seepage capacity of crude oil is different, which eventually leads to different product characteristics and development effects.

Different types of reservoirs have different micro pore structures and different oil migration rules, which ultimately lead to different production characteristics and development effects. Therefore, the effective classification of reservoirs can substantially enhance the oil recovery rate of reservoirs, and in the actual development, the corresponding development plan for different reservoir types can improve the development efficiency and reduce the extraction cost at the same time. This means that the reservoir type can be determined based on the classification of the low permeability reservoir in the Mahu Sag, so that the fluid migration rule can be determined and the appropriate development method can be selected, which can significantly enhance the final recovery rate of the reservoir. For type I reservoirs, the displacement method is preferred, while for the other three types of reservoirs, a combination method of displacement and soaking should be adopted [24]. This result can also be applied to the Baikouquan Formation reservoir in the whole area, which will accelerate the exploration and development process of Mahu Sag.

5. Conclusions

(1) The sedimentary environment and late diagenesis control the pore type of the low permeability conglomerate reservoir in the Baikouquan Formation of the Mahu Sag. The pore type is mainly intragranular dissolved pores and residual intergranular pores, accounting for 93.54%, microfractures and shrinkage pores that are locally developed, accounting for 5.63%, and other pore types that are less developed, accounting for only 0.83%, and the shrinkage pores developed in the matrix show good seepage characteristics.

(2) The pore throat radius distribution range and main distribution frequency of different lithological reservoirs are different, and the corresponding NMR T₂ spectrum distribution characteristics and pore throat coordination number are also different. From sandy-grain-supported conglomerate to argillaceous-supported conglomerate, the micro pore structure gradually becomes worse, the distribution range of pores and throats narrows, and the main distribution frequency moves to a small pore throat, thus affecting the development characteristics and production effect of the reservoir.

(3) The low permeability conglomerate reservoir of the Baikouquan Formation can be divided into four types of reservoirs corresponding to lithology. Among them, type I–IV reservoirs correspond to four types of lithology, namely, sandy-grain-supported conglomerate, gravelly coarse sandstone, sandy-gravelly matrix-supported conglomerate, and argillaceous-supported conglomerate. From type I to type IV, the porosity and permeability of the reservoir are reduced, and the micro pore structure becomes worse. Therefore, clarifying the migration rule of fluids in different types of reservoirs and then selecting a suitable development scheme can significantly enhance the overall recovery of low permeability conglomerate reservoirs in the Mahu Sag.