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Article

Migration Rule of Crude Oil in Microscopic Pore Throat of the Low-Permeability Conglomerate Reservoir in Mahu Sag, Junggar Basin

by
Feng-Qi Tan
1,2,
Chun-Miao Ma
1,2,*,
Xu-Yang Zhang
3,
Ji-Gang Zhang
3,
Long Tan
3,
Dan-Dan Zhao
3,
Xian-Kun Li
1,2 and
Yu-Qian Jing
1,2
1
College of Earth and Planetary Sciences, University of Chinese Academy of Sciences, Beijing 100049, China
2
Key Laboratory Computational Geodynamics, Chinese Academy of Sciences, Beijing 100049, China
3
Xinjiang Oilfield Company, PetroChina, Karamay 834000, China
*
Author to whom correspondence should be addressed.
Energies 2022, 15(19), 7359; https://0-doi-org.brum.beds.ac.uk/10.3390/en15197359
Submission received: 11 August 2022 / Revised: 25 September 2022 / Accepted: 28 September 2022 / Published: 7 October 2022
(This article belongs to the Special Issue Oil Field Chemicals and Enhanced Oil Recovery)
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Abstract

:
The low-permeability conglomerate reservoir in the Mahu Sag has great resource potential, but its strong heterogeneity and complex microscopic pore structure lead to a high oil-gas decline ratio and low recovery ratio. Clarifying the migration rule of crude oil in microscopic pore throat of different scales is the premise of efficient reservoir development. The low-permeability conglomerate reservoir of the Baikouquan Formation in the Mahu Sag is selected as the research object, and two NMR experimental methods of centrifugal displacement and imbibition replacement are designed to reveal the differences in the migration rule of crude oil in different pore throats. According to the lithology and physical properties, the reservoirs in the study area can be divided into four categories: sandy grain-supported conglomerates, gravelly coarse sandstones, sandy-gravelly matrix-supported conglomerates and argillaceous-supported conglomerates. From type I to type IV, the shale content of the reservoir increases, and the physical property parameters worsen. Centrifugal displacement mainly produces crude oil in large pore throats, while imbibition replacement mainly produces crude oil in small pores. In the process of centrifugal displacement, for type I reservoirs, the crude oil in the pore throats with radii greater than 0.5 μm is mainly displaced, and for the other three types, it is greater than 0.1 μm. The crude oil in the pore throats with radii of 0.02–0.1 μm, which is the main storage space for the remaining oil, is difficult to effectively displace. The crude oil in the pore throats with radii less than 0.02 μm cannot be displaced. The two experimental methods of centrifugation and imbibition correspond to the two development methods of displacement and soaking in field development, respectively. The combination of displacement and soaking can effectively use crude oil in the full-scale pore throat space to greatly improve the recovery of low-permeability conglomerate reservoirs.

1. Introduction

In recent years, with the reduction in conventional hydrocarbon reserves, tight reservoirs have become the focus of exploration and development. At present, low-permeability reservoirs account for a large proportion of the proven geological oil reserves in China [1,2], being widely distributed in the Junggar Basin, Ordos Basin, Bohai Bay Basin and Songliao Basin [3,4,5]. Among them, the low-permeability conglomerate reservoir of Mahu Sag, located in the northwest margin of the Junggar Basin, has great resource potential. According to statistics, its reserves amount to 1 billion tons and cumulative production reaches 10.142 million tons, making it an important foundation for the continuous and stable growth of oil and gas production in China [3]. However, with the development of the Mahu Sag, some production problems are becoming increasingly prominent, mainly reflected in the large differences in production from different types of reservoirs, large differences in production from single wells, and high oil and gas decline rates. As a result, the overall recovery of the reservoir is low and difficult to develop further [6,7,8].
The geological characteristics of oil reservoirs have a direct influence on the exploration and development of oil fields. Due to the near-source, multi-stream, and rapidly changing sedimentary environments, various types of low-permeability conglomerate reservoirs have been developed in the Mahu Sag [9,10]. Different types of reservoirs have significant differences in lithology and microscopic pore structure. This leads to the complexity of reservoir physical properties and crude oil migration rules, resulting in low oil recovery rates. Therefore, in order to solve the above problems, it is necessary to describe the microscopic pore structure of the reservoir in detail, and clarify the oil flow rules in the microscopic pore space of different types of reservoirs, that is, the migration rule of crude oil.
At present, the research on the microscopic pore structure of low-permeability conglomerate reservoirs is relatively well-developed. Theoretically, the fractal geometry theory is mainly used to design the classification model of porous media, which is related to the microscopic pore structure parameters [11,12]; experimentally, the methods of constant-rate mercury injection, high-pressure mercury injection, CT scanning and nuclear magnetic resonance (NMR) are mainly used to characterize the microscopic pore structures of reservoirs [13]. However, the transport behavior of porous media in rocks is complex, and the study of fluid generation in micropores is still insufficient [14,15,16,17,18,19]. To date, the main research objects are shale reservoirs. Li et al. studied the characteristics and influencing factors of low-velocity seepage in shale oil reservoirs, which provided valuable experiment data for subsequent studies [20]; Zhang et al. studied the effects of pore structure on the micro-scale seepage characteristics of tight gas reservoirs, and revealed the importance of “connecting fracture and expanding throat” [21]. Regarding the conglomerate reservoir in Mahu Sag, there has still not been much study of the seepage characteristics to date [14,22,23,24,25,26]. Kuang et al. realized quantitative characterization of the pore structure of the conglomerate reservoir in Ma 131 Well Block based on experiments such as casting thin section, scanning electron microscope, mercury injection and NMR [27]; Du et al. studied the microscopic pore structure characteristics of the Mahu conglomerate reservoir from a three-dimensional scale in combination with micro CT scanning technology, quantitative evaluation of minerals by scanning electron microscope and MAPS micro-image splicing technologies [28]; Fu et al. studied the pore structure and seepage characteristics of conglomerate reservoirs in Mahu Sag, but they only concluded that the seepage parameters of reservoirs generally deteriorate with the pore structure [29]. The single study of the microscopic pore structure of the reservoir can only provide a theoretical basis for the exploration and development of the oil field. Scholars have not conducted in-depth studies on the migration rule of fluids in the pore space, thus, there can be no direct effects on enhancing oil recovery.
Up to now, the main methods to study the migration rule in pore space include: NMR, relative permeability experiment and real sandstone micro model displacement experiment [30,31,32,33,34]. Among these, the NMR method can quickly, accurately and nondestructively determine the saturation of fluids in different pore spaces of the reservoir by analyzing the relaxation time of the hydrogen atom nucleus contained in the fluid in the rock pore space under the action of the external magnetic field and quantitatively characterize the occurrence state and production degree of the fluid in different pore spaces [35,36,37,38]. In this study, two kinds of NMR experiments, centrifugal displacement and imbibition replacement, were designed to study the oil migration rules in the microscopic pore structure of conglomerate reservoirs in the Mahu Sag. This study can not only improve on the previous pore structure studies and fill the gaps in the current research on low-permeability conglomerate reservoirs, but also play a significant role in guiding the actual development of the oilfield, promoting a significant increase of the recovery of low-permeability conglomerate reservoirs, and ensuring the high and stable production of Mahu conglomerate reservoirs.

2. Geological Settings

The Mahu Sag, located in the northwest margin of the Junggar Basin, is one of the six major hydrocarbon-generating sags in the Junggar Basin (Figure 1b) [29]. Mahu Sag is adjacent to the Wuxia Fault and Kebai Fault in the northwest and the Dabassong Uplift and Xiayan Uplift in the southeast. The structural section is a gentle monocline inclined to the southeast, with developed faults (Figure 1c) [6,39]. The strata in the study area developed from the Carboniferous to Cretaceous (Figure 1d). The Baikouquan Formation in the Mahu Sag, as the main development layer system of low-permeability conglomerate reservoirs, belongs to a set of fan delta sedimentary systems [40]. The lithology is complex and diverse, including mudstone, medium sandstone, coarse sandstone, fine conglomerate, medium conglomerate and coarse conglomerate. On the whole, it belongs to the conglomerate reservoir [6,7,8,9,10].
Sedimentary facies and hydrodynamic conditions control the distribution of lithology, while lithology controls physical properties and oil-bearing properties. The oil-bearing lithology of the Baikouquan Formation is mainly divided into four types: sandy grain-supported conglomerate, gravelly coarse sandstone, sandy-gravelly matrix-supported conglomerate and argillaceous-supported conglomerate, which correspond to four reservoir types (Figure 2a–d). The core analysis data show that the physical properties of the four types of reservoirs are quite different. Among them, the type I reservoir is mainly sandy grain-supported conglomerate, with the best physical properties, an average porosity of 9.98% and an average permeability of 2.91 mD; the type II reservoir is mainly gravelly coarse sandstone, with the next-best physical properties, an average porosity of 9.47% and an average permeability of 1.61 mD; the type III reservoir is mainly sandy-gravelly matrix-supported conglomerate, with medium physical properties, an average porosity of 7.97% and an average permeability of 1.30 mD; and the type IV reservoir is mainly argillaceous-supported conglomerate, with the worst physical properties, an average porosity of 5.37% and an average permeability of 0.28 mD (Figure 2e,f). The Baikouquan Formation in the Mahu Sag is a set of typical low porosity and low-permeability conglomerate reservoirs.
The macro physical properties of reservoirs are controlled by their microscopic pore structure and argillaceous content. The pore types of the Baikouquan Formation are mainly intragranular dissolved pores and residual intergranular pores, with relative contents accounting for 65.9% and 23.2%, respectively. Microfractures and shrinkage pores are locally developed, and the proportion of other pore types is small. The absolute argillaceous content in the Baikouquan Formation reservoir is 4.7%. The main type is the illite-montmorillonite mixed layer, with an average relative content of 55%. The contents of chlorite, kaolinite and illite are the same, all approximately 15%. The results of constant velocity mercury injection and mineral composition analysis show that there are great differences in the microscopic pore structure parameters and argillaceous content of the four types of reservoirs in the Baikouquan Formation. Low clay mineral content and good microscopic pore structure characteristics lead to the best physical properties of the type I reservoir. From type I to type IV, the physical properties of the reservoir gradually worsen, which is manifested in the increase of argillaceous content, displacement pressure and median pressure, and the decrease of porosity, permeability, average capillary radius, median radius, maximum pore throat radius and mercury withdrawal efficiency (Table 1).

3. Methods

Two experimental methods, centrifugal displacement and imbibition replacement, were used to determine the migration rule of crude oil in the microscopic pore throat. The centrifugal displacement is used to apply different centrifugal forces to the samples to displace the crude oil in the microscopic pore throat under pressure, and to obtain the oil production degree of displacement; The imbibition replacement is to record the flow of formation water into the pore to displace the crude oil under the action of capillary force, and obtain the oil production degree of imbibition.

3.1. Principle

In the process of core displacement, NMR can be used to quantitatively characterize the production degree of crude oil in different pore spaces and then calculate the final recovery of different types of reservoirs. The 1H contained in the fluid is polarized by the magnetic field in the uniformly distributed static magnetic field, which can produce the magnetization vector. At this time, when the external radio frequency field of the selected frequency is applied to the sample, the nuclear magnetic moment undergoes an absorption transition and produces NMR [42]. When the radio frequency field is removed, the relaxation motion of the hydrogen nucleus in the pore will produce a signal whose amplitude decays exponentially with time. NMR mainly uses the difference in relaxation time of different fluid properties (oil, gas and water) and the same fluid properties in different occurrence states, that is, the difference in T2 relaxation time, to evaluate the occurrence characteristics and migration rule of pore fluid [43,44,45]. The T2 cutoff divides the T2 spectrum into two parts. For the part greater than the T2 cutoff value, the fluid is in a free state, reflecting the movable fluid; for less than the T2 cutoff value, the fluid is bound by capillary force and viscous resistance and is in an immovable state, reflecting the bound fluid [46] (Figure 3). The distribution of remaining oil in different pore spaces can be determined by the T2 spectra of core samples of different reservoir types in different displacement stages. Then, the migration rule of pore throats crude oil can be clarified, and the reservoir recovery can be calculated quantitatively.
There are three relaxation behaviors of fluids in pores and throats: free relaxation T2B, surface relaxation T2S and diffusion relaxation T2D. For cores saturated with crude oil, T2 relaxation time mainly depends on surface relaxation T2S. It can be expressed as:
1 T 2 S = ρ 2 S V p o r e
where ρ 2 is the transverse surface relaxation rate, μm/ms; S V is the ratio of pore surface area and volume; The relationship between S V and pore radius is S V   = F S r , FS is the geometric factor, and r is the pore radius, μm. According to this, Equation (1) can be transformed into:
T 2 S = 1 ρ 2 F S r
Assuming that 1 ρ 2 F S = C , Equation (2) can be transformed into T 2 = C × r . Therefore, after the coefficient C value is obtained, the NMR T2 spectrum can be converted into the pore radius distribution [38,47].

3.2. Samples

Two NMR experiments, centrifugal displacement and imbibition replacement, were designed for the low-permeability conglomerate reservoir of Baikouquan Formation in Mahu Sag. In order to improve the accuracy of the experimental results and reduce the interference of other factors, the selected samples are basically at the same depth. This means that the core samples have essentially the same sedimentary age and environment, and the permeability and porosity parameters are slightly different. Ten core samples were selected for centrifugal displacement, including 3 samples of type I, 3 samples of type II, 3 samples of type III and 1 sample of type IV. The average gas logging porosity is 8.9% and the average gas logging permeability is 1.373 mD. Six core samples were selected for imbibition replacement, including 1 sample of type I, 2 samples of type II, 1 sample of type III, and 2 samples of type IV. All samples are selected from reservoirs of different lithology of Baikouquan Formation in Ma18 Well Block and Ma131 Well Block in Mahu Sag (Figure 4). Among them, type I reservoir corresponds to sandy grain-supported conglomerate, type II reservoir corresponds to gravelly coarse sandstone, type III reservoir corresponds to sandy-gravelly matrix-supported conglomerate and type IV reservoir corresponds to argillaceous-supported conglomerate. The average gas logging porosity is 8.1%, and the average gas logging permeability is 1.222 mD (Table 2).

3.3. Materials and Instruments

Experimental materials: The experimental fluid was taken from the formation water and crude oil of the Baikouquan Formation reservoir, and the parameters are shown in Table 3. For imbibition replacement, heavy water (D2O) with a density of 1.056 g/cm3 was selected.
Experimental instruments: NMR testing instrument (PetroChina Pipeline Jingci New Materials Co., Ltd., SPEC035, Hong Kong, China); viscometer (Brookfield Company, DV-III Ultra Viscometer, Middleboro, MA, USA); vacuum saturation device (Beijing Zhongbo Ruike Testing Equipment Co., Ltd., ZK-270, Beijing, China); core holder (Jiangsu Boruisi Scientific Research Instrument Co., Ltd., TY-4, Hai’an, China); graduated glass tube (Wuhan Dingsheng Zhongtian Experimental Instrument Co., Ltd., Wuhan, China); electronic balance (Mettler Toledo Technology (China) Co., Ltd., XPR226DR/AC, Shanghai, China); core centrifuge (Sichuan Shuke Instrument Co., Ltd., YX-1850R, Chengdu, China) (12bit core rotor, maximum speed 18500 rpm); measuring cup (Wuhan Dingsheng Zhongtian Experimental Instrument Co., Ltd., Wuhan, China).

3.4. Steps

The specific experimental steps of centrifugal displacement are as follows (Figure 5a):
  • Ten cores were cut into standard full diameter samples (Table 2) and dried at 50 °C for 48 h.
  • After vacuumizing the core for 24 h, 10 samples were continuously saturated with configured formation water for 72 h, and the effective vacuum level is −0.10 MPa.
  • The core that had been saturated with formation water was placed into the core holder, saturated with crude oil at a rate of 0.02 mL/min and driven to 20 PV, then the water displacement was recorded.
  • The cores were aged at 25 °C, 0.1 MPa for 15 days beforehand, and after aging at 75 °C, 35 MPa for 96 h in the core holder, the core was removed, the surface oil slick was removed with hard paper, and the core was scanned by NMR.
  • The core was placed into the centrifuge, the temperature and pressure conditions were set as the values in the middle of the reservoir, the temperature was set as 75 °C, and the confining pressure was set as 37 MPa.
  • The core was loaded with centrifugal forces of 42 psi, 208 psi, 417 psi and 900 psi (10,000–12,000 rpm), and the core was scanned by NMR after the experiment at different test points.
  • The above experiments were carried out on 10 samples, and the test data were collected and analyzed.
The specific experimental steps of imbibition replacement are as follows (Figure 5b):
  • Six cores were cut into standard full diameter samples (Table 2) and dried at 50 °C for 48 h.
  • After vacuumizing the core for 24 h, heavy water was inhaled, and the six samples were saturated for 72 h, and the effective vacuum level is −0.10 MPa.
  • The core was placed into the core holder, the crude oil was saturated at a rate of 0.02 mL/min and displaced to 20 PV, and the water displacement was recorded.
  • The cores were aged at 25 °C, 0.1 MPa for 15 days beforehand, and after aging at 75 °C, 35 MPa for 96 h in the core holder, the core was removed, the surface oil slick was removed with hard paper, and the core was scanned by NMR.
  • The core was placed into the imbibition bottle, the imbibition bottle was filled with heavy water to 5 mL of the graduated glass tube, the temperature and pressure were loaded in the middle of the reservoir, and the initial scale (5 mL of the graduated glass) and time were recorded.
  • Taking the time when the core was put into the imbibition bottle as the starting point, the test was performed continuously for 144 h. The oil precipitation data was analyzed according to the fixed time interval. The observation intervals for the IR-04, IR-05 and IR-07 cores are 12 h, 24 h and 48 h, respectively, and for the IR-01, IR-02 and IR-10 cores, the observation intervals are 8 h, 24 h and 48 h, respectively.
  • The IR-01, IR-02, IR-04, IR-07 and IR-10 cores were removed at each test point, the surface oil slick was removed, and NMR scanning was conducted.
  • To compare the difference between the intermediate break test and continuous test results in the imbibition process, the IR-05 core was placed in the imbibition bottle and was not removed until the end of the experiment. The change in the amount of oil precipitated in the imbibition bottle was continuously observed. When the experiment was completed, the core was removed, weighed and scanned by NMR. After that, hard paper was used to remove the surface oil slick every 24 h for NMR scanning, and the test was continued for 4 days.

4. Results and Discussion

4.1. Oil Migration Rule of Centrifugal Displacement

By analyzing the NMR T2 spectra of samples under different centrifugal forces, it is found that with increasing centrifugal force, the crude oil in the microscopic pore throat decreases, and the NMR signal weakens. Moreover, the NMR T2 spectrum characteristics and variation ranges of core samples from different reservoirs are also different. The microscopic pore structure and argillaceous content of different types of reservoirs are quite different, resulting in obvious differences in the migration rule of crude oil.
CD-3, CD-4 and CD-10 belong to the type I reservoir. The T2 spectrum of the type I reservoirs show a trimodal distribution in the saturated oil state, indicating the presence of large, medium and small pore throats (Figure 6a,d,g). According to the normal distribution simulation [48], the T2 cutoff values of effective pores, movable fluid pores and movable crude oil pores are 0.3 ms, 6.0 ms and 20.0 ms, respectively. The T2 cutoff value is determined by the distribution of the pore throat radius. For the type I reservoir, the distribution frequencies of pore throat radii >0.5 μm, 0.5–0.02 μm and <0.02 μm are 40.1%, 16.9% and 1.15%, respectively (Figure 6b,e,h). The production degree of crude oil can be calculated from the distribution of remaining oil in different pore throats. The average production degree of crude oil in the pore throats with a radius greater than 0.5 μm is 84.3% and that of 0.02–0.5 μm is 33.2%, which is the main occurrence space of the remaining oil. For crude oil in pore throats with radius less than 0.02 μm, due to the influence of pore structure and capillary force, the degree of crude oil production is 0% (Figure 6c,f,i).
CD-2, CD-5 and CD-7 belong to type II reservoirs. The T2 spectrum of the type II reservoirs show a bimodal distribution in the saturated oil state, indicating the reduction of large pore throats (Figure 7a,d,g). The T2 cutoff values of the effective pore, movable fluid pore and movable crude oil pore are 0.4 ms, 10.0 ms and 18.0 ms, respectively. For the type II reservoir, the distribution frequencies of pore throat radii >0.1 μm, 0.1–0.02 μm and <0.02 μm are 37.8%, 11.2% and 1.87%, respectively (Figure 7b,e,h). The crude oil in the pore throats greater than 0.1 μm has the highest production degree of 73.6%. The production degree of crude oil in pores with a radius of 0.02–0.1 μm is low, with an average of 16.4%, which is the main occurrence space of the remaining oil. For crude oil in pores with radius less than 0.02 μm, the degree of crude oil production is 0% (Figure 7c,f,i).
CD-1, CD-6 and CD-8 belong to the type III reservoirs. The T2 spectrum of the type III reservoirs show a bimodal distribution in the saturated oil state. The peak on the right is not obvious, indicating few large pore throats (Figure 8a,d,g). The T2 cutoff values of the effective pore, movable fluid pore and movable crude oil pore are 0.7 ms, 10.0 ms and 20.0 ms, respectively. For the type III reservoir, the distribution frequencies of pore throat radii >0.1 μm, 0.1–0.02 μm and <0.02 μm are 19.5%, 6.6% and 0.82%, respectively (Figure 8b,e,h). The average production degree of crude oil in the pore throats with a radius greater than 0.1 μm is 73.5% and that of 0.02–0.1 μm is 9.7%, which is the main occurrence space of the remaining oil. For crude oil in pore throats with radius less than 0.02 μm, the degree of crude oil production is 0% (Figure 8c,f,i).
CD-9 belongs to the type IV reservoir. The T2 spectrum of the type IV reservoir shows a unimodal distribution in the saturated oil state, indicating the absence of large pore throats. (Figure 9a). The T2 cutoff values of the effective pore, movable fluid pore and movable crude oil pore are 1.0 ms, 12.0 ms and 20.0 ms, respectively. For the type IV reservoir, the distribution frequencies of pore throat radii >0.1 μm, 0.1–0.02 μm and <0.02 μm are 20.6%, 7.63% and 0.43%, respectively (Figure 9b). The average production degree of crude oil in the pore throats with a radius greater than 0.1 μm is 78.1% and that of 0.02–0.1 μm is 20.2%, which is the main occurrence space of the remaining oil. For crude oil in pore throats with radius less than 0.02 μm, the degree of crude oil production is 0% (Figure 9c).
For the low-permeability conglomerate reservoir in the Mahu Sag, from type I to type IV, the development of large pore throats decreases, and the distribution frequency of the pore throat radii moves toward small pore throats (Figure 10). The fluid migration rules in pore throats are different for the four types of reservoirs. Type I reservoirs mainly produce crude oil in pore throats with radii larger than 0.5 μm, while the other three types are larger than 0.1 μm. For these four types of low-permeability conglomerate reservoirs, centrifugal displacement can effectively produce crude oil in large pore throats. The crude oil in the pore throats with a radius of 0.02–0.1 μm is difficult to be produced effectively due to the large capillary force, which has become the main space for residual oil to occur. Crude oil in pore throats with radius less than 0.02 μm cannot be produced by displacement, and the production degree of the four types of reservoirs is 0% (Figure 11).

4.2. Oil Migration Rule of Imbibition Replacement

The imbibition replacement is a multi-phase flow process in which the wetting phase fluid spontaneously enters the porous medium and replaces the non-wetting phase fluid in it under the action of capillary force [49]. The higher the capillary force, the stronger the spontaneous imbibition and the higher the production degree of crude oil in small pore throats [50]. For hydrophilic rocks, the direction of imbibition belongs to the same direction, that is, the process of water flooding [51]. Therefore, for the hydrophilic conglomerate reservoir in the Mahu sag, the production degree of crude oil in the pore throats can be clarified by infiltration replacement, and then appropriate development measures can be determined to effectively improve oil recovery.
Pore throats in samples can be divided into large pores and small pores by taking the T2 value equal to 10 ms as the boundary. The NMR T2 spectrum of imbibition replacement shows a typical bimodal distribution. The relaxation time of the left peak is short, which represents the signal amplitude of the fluid in the small pores. The relaxation time of the right peak is long, which represents the signal amplitude of the fluid in the large pores. As the soaking time increases, the NMR signal weakens, indicating that the crude oil in the pores is expelled. The different weakening ranges of NMR signals for different types of reservoirs indicate that the migration rules of crude oil in pore space are different for different reservoirs.
IR-07 belongs to the type I reservoir. The decrease of the NMR signal of large pore throats is greater than that of small pore throats, indicating a higher production degree of crude oil in large pore throats (Figure 12a). In the early stage, the crude oil production in the pore throat increased rapidly, reaching 19.08% at 48 h. With increasing time, the production efficiency of imbibition gradually decreased (Figure 12c). After 144 h of imbibition, the production degree of crude oil in the large pore throats reached 17.14%, while that in the small pore throats was only 6.07% (Figure 12b). The smaller capillary force difference between large and small pore throats and the lower development degree and oil-bearing ratio of small pore throats jointly lead to the lower production degree of crude oil in small pore throats.
IR-01 and IR-10 belong to the type II reservoir. The decrease of the NMR signal of small pore throats is greater than that of large pore throats, indicating a higher production degree of crude oil in small pore throats (Figure 13a,d). In the early stage, the production degree of crude oil in the pore throats increased rapidly, reaching 31.13% at 48 h. The growth was slow in the later stage (Figure 13c,f). At 144 h, the average production degree of crude oil in the small pore throats reached 31.12%, while that in the large pore throats was only 3.22% (Figure 13b,e).
IR-02 belongs to the type III reservoir. The decrease of the NMR signal of small pore throats is greater than that of large pore throats, indicating a higher production degree of crude oil in small pore throats (Figure 14a). In the early stage, the crude oil production in the pore throats increased rapidly, reaching 31.08% at 48 h (Figure 14c). In the later stage, the growth was slow, and the production degree of crude oil in the large and small pore throats reached 2.44% and 32.86%, respectively, at 144 h (Figure 14b).
IR-04 belongs to type IV reservoir. The decrease of the NMR signal of small pore throats is greater than that of large pore throats, indicating a higher production degree of crude oil in small pore throats (Figure 15a). In the early stage, the crude oil production in the pore throats increased rapidly, reaching 28.54% at 48 h (Figure 15c). In the later stage, the growth was slow, and the production degree of crude oil in the large and small pore throats reached 10.18% and 21.23%, respectively, at 144 h (Figure 15b). Compared with type II and type III reservoirs, the production degree of crude oil in the small pore throats of type IV reservoir decreases, while that in the large pore throats increases. This is mainly caused by the water sensitivity of clay minerals. The high content of clay minerals makes the influence of water sensitivity stronger than that of capillary force. As a result, partial small pore throats are blocked, which affects the imbibition replacement effect of small pore throats and reduces the production degree of crude oil in small pore throats.
IR-05 also belongs to the type IV reservoir. However, the migration rule of crude oil in pore throats of IR-05 is analyzed by continuous testing. From the variation amplitude of the NMR signal from 0 to 144 h, the contribution of oil production by imbibition was mainly from small pore throats (Figure 15d). After 144 h of imbibition, the production degree of crude oil in the small pore throats was 23.92%, while that in the large pore throats was 11.07% (Figure 15e). From 144 to 240 h, the NMR signal remained essentially unchanged, and the oil production degree changed slightly, increasing by only 0.49% (Figure 15f). This indicates that the effect of late imbibition on crude oil replacement is very small and has limited improvement on oil recovery.
The imbibition NMR results of all samples showed that the growth rate of oil production degree slowed down after 48 h of imbibition, and stabilized after 144 h of imbibition. The whole process of this experiment was carried out in the laboratory. Considering that the geological conditions are more complicated and the influencing factors are difficult to control during the actual production, it is suggested that the soaking time in the field development of the study area should be at least 72 h. At the same time, in order to achieve the optimal utilization of human and material resources in development, it is recommended that the maximum soaking time should not exceed 120 h.
According to the imbibition replacement results of the four types of reservoirs, the imbibition recovery is related to the average pore throat radius, oil-bearing ratio of pore throats and argillaceous content. From type I to type IV, the average pore throat radius decreases, the permeability decreases, and the oil-bearing proportion of pore throats gradually increases. The enhancement of imbibition leads to an increase of the oil production degree of small pore throats. In addition, the water sensitivity of clay minerals will affect the imbibition recovery rate. For type IV reservoirs with argillaceous contents greater than 8%, the production degree of crude oil in the small pore throats is reduced, with an average of only 22.58%, while that of type II and III reservoirs are 31.12% and 32.86%, respectively (Table 4). Therefore, for low-permeability conglomerate reservoirs with high argillaceous content, the effect of water sensitivity on oil recovery must be considered in the imbibition replacement process.

4.3. Comparison of Migration Rules

For the low-permeability conglomerate reservoir in the Baikouquan Formation of the Mahu Sag, the four types of reservoirs have obviously different microscopic pore structures and argillaceous content. This leads to significant differences in the oil migration rules of different types of reservoirs. From type I to type IV, the NMR T2 spectra showed a change from trimodal to bimodal and then to unimodal, indicating that the development degree and distribution frequency of large pore throats in the reservoir decreased, while those of small pore throats increased (Figure 16). For type I reservoirs, both methods produce more crude oil in large pore throats than in small pore throats. For the other three types of reservoirs, centrifugal displacement has a higher production degree of crude oil in the large pore throats, while imbibition replacement has a higher production degree of crude oil in the small pore throats (Table 5).
The two experimental methods of centrifugation and imbibition correspond to the two development methods of displacement and soaking in field development, respectively. Centrifugal displacement mainly produces crude oil in pore throats with a radius greater than 0.1 μm, while imbibition replacement mainly produces crude oil in pore throats with a radius of 0.02–0.1 μm. The combination of the two methods can effectively produce crude oil in the full-scale pore throat space of low-permeability conglomerate reservoirs. Therefore, in the actual development of the oilfield, the combination of displacement and soaking methods can be used for different types of reservoirs. It can effectively solve the problems of low oil and gas production of a single well and large differences in oil and gas production between different intervals. This method greatly enhances the final recovery of low-permeability conglomerate reservoirs.

5. Conclusions

  • For the low-permeability conglomerate reservoirs of the Mahu Sag, the microscopic pore structure and argillaceous content are the main controlling factors for the migration rule of crude oil in the pore space. The high argillaceous content and strong water sensitivity of clay minerals can lead to blockage of local small pores, reduction of infiltration channels and decrease of imbibition recovery in small pores.
  • The oil migration rules vary from reservoir to reservoir. For type I reservoirs, the two methods mainly produce crude oil in pore throats with radii greater than 0.1 μm. For the other three types of reservoirs, centrifugal displacement has a higher production degree of crude oil in pore throats with radii greater than 0.1 μm, while imbibition replacement has a higher production degree of crude oil in pore throats with radii of 0.02–0.1 μm. Crude oil in pore throats with a radius less than 0.02 μm cannot be used.
  • The NMR results of centrifugal displacement and imbibition replacement show that for the low-permeability conglomerate reservoir of Mahu Sag, the combination of displacement and soaking can effectively produce crude oil in the full-scale pore throats of the reservoir and improve the ultimate recovery of the reservoir. Considering the technical feasibility and economic rationality, the best soaking time is 3–5 days.

Author Contributions

Data curation, F.-Q.T.; Formal analysis, C.-M.M.; Funding acquisition, F.-Q.T.; Investigation, X.-Y.Z., J.-G.Z., L.T. and D.-D.Z.; Methodology, F.-Q.T.; Project administration, F.-Q.T.; Resources, X.-Y.Z., J.-G.Z., L.T. and D.-D.Z.; Supervision, F.-Q.T.; Validation, X.-K.L. and Y.-Q.J.; Visualization, C.-M.M.; Writing—original draft, C.-M.M.; Writing—review & editing, C.-M.M. All authors have read and agreed to the published version of the manuscript.

Funding

This research was funded by [the National Natural Science Foundation of China] grant number [No. 41902141], [the Fundamental Research Fund for the Central Universities] grant number [No. E1E40403] and [the PetroChina Innovation Foundation] grant number [No. 2018D-5007-0103].

Data Availability Statement

The data presented in this study are available on request from the corresponding author. The data are not publicly available due to the need for further relevant research.

Acknowledgments

This research was supported by the National Natural Science Foundation of China (No. 41902141), the Fundamental Research Fund for the Central Universities (No. E1E40403) and the PetroChina Innovation Foundation (No. 2018D-5007-0103).

Conflicts of Interest

The authors declare no conflict of interest.

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Figure 1. (a) Location of the Junggar Basin; (b) Location of Mahu Sag; (c) Geological and structural map of Mahu Sag; (d) Stratigraphic lithology histogram of Mahu Sag [41].
Figure 1. (a) Location of the Junggar Basin; (b) Location of Mahu Sag; (c) Geological and structural map of Mahu Sag; (d) Stratigraphic lithology histogram of Mahu Sag [41].
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Figure 2. (a) Sandy grain-supported conglomerate, type I reservoir; (b) Gravelly coarse sandstone, type II reservoir; (c) Sandy-gravelly matrix-supported conglomerate, type III reservoir; (d) Argillaceous-supported conglomerate, type IV reservoir; (e) Porosity whisker plots of different reservoir types; (f) Permeability whisker plots of different reservoir types.
Figure 2. (a) Sandy grain-supported conglomerate, type I reservoir; (b) Gravelly coarse sandstone, type II reservoir; (c) Sandy-gravelly matrix-supported conglomerate, type III reservoir; (d) Argillaceous-supported conglomerate, type IV reservoir; (e) Porosity whisker plots of different reservoir types; (f) Permeability whisker plots of different reservoir types.
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Figure 3. NMR T2 spectrum distribution of fluid in pores and throats.
Figure 3. NMR T2 spectrum distribution of fluid in pores and throats.
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Figure 4. Core data of Baikouquan Formation in Ma18 Well Block and Ma131 Well Block.
Figure 4. Core data of Baikouquan Formation in Ma18 Well Block and Ma131 Well Block.
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Figure 5. (a) Flow Chart of Centrifugal Displacement Experiment; (b) Flow Chart of Imbibition Replacement Experiment.
Figure 5. (a) Flow Chart of Centrifugal Displacement Experiment; (b) Flow Chart of Imbibition Replacement Experiment.
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Figure 6. Centrifugal NMR results of core samples of type I reservoir; (a,d,g) are the T2 spectrum of centrifugal NMR of CD-3, CD-4 and CD-10, respectively; (b,e,h) are the throat radius distribution frequency diagram of CD-3, CD-4 and CD-10, respectively; (c,f,i) are the frequency distribution of residual oil in pore space of different scales of CD-3, CD-4 and CD-10, respectively.
Figure 6. Centrifugal NMR results of core samples of type I reservoir; (a,d,g) are the T2 spectrum of centrifugal NMR of CD-3, CD-4 and CD-10, respectively; (b,e,h) are the throat radius distribution frequency diagram of CD-3, CD-4 and CD-10, respectively; (c,f,i) are the frequency distribution of residual oil in pore space of different scales of CD-3, CD-4 and CD-10, respectively.
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Figure 7. Centrifugal NMR results of core samples of type II reservoir; (a,d,g) are the T2 spectrum of centrifugal NMR of CD-2, CD-5 and CD-7, respectively; (b,e,h) are the throat radius distribution frequency diagram of CD-2, CD-5 and CD-7, respectively; (c,f,i) are the frequency distribution of residual oil in pore space of different scales of CD-2, CD-5 and CD-7, respectively.
Figure 7. Centrifugal NMR results of core samples of type II reservoir; (a,d,g) are the T2 spectrum of centrifugal NMR of CD-2, CD-5 and CD-7, respectively; (b,e,h) are the throat radius distribution frequency diagram of CD-2, CD-5 and CD-7, respectively; (c,f,i) are the frequency distribution of residual oil in pore space of different scales of CD-2, CD-5 and CD-7, respectively.
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Figure 8. Centrifugal NMR results of core samples of type III reservoir; (a,d,g) are the T2 spectrum of centrifugal NMR of CD-1, CD-6 and CD-8, respectively; (b,e,h) are the throat radius distribution frequency diagram of CD-1, CD-6 and CD-8, respectively; (c,f,i) are the frequency distribution of residual oil in pore space of different scales of CD-1, CD-6 and CD-8, respectively.
Figure 8. Centrifugal NMR results of core samples of type III reservoir; (a,d,g) are the T2 spectrum of centrifugal NMR of CD-1, CD-6 and CD-8, respectively; (b,e,h) are the throat radius distribution frequency diagram of CD-1, CD-6 and CD-8, respectively; (c,f,i) are the frequency distribution of residual oil in pore space of different scales of CD-1, CD-6 and CD-8, respectively.
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Figure 9. Centrifugal NMR results of core samples of type IV reservoir; (a–c) are the T2 spectrum of centrifugal NMR, throat radius distribution frequency diagram and frequency distribution of residual oil in pore space of different scales of CD-9, respectively.
Figure 9. Centrifugal NMR results of core samples of type IV reservoir; (a–c) are the T2 spectrum of centrifugal NMR, throat radius distribution frequency diagram and frequency distribution of residual oil in pore space of different scales of CD-9, respectively.
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Figure 10. Frequency distribution of the pore throat radius of types of reservoirs.
Figure 10. Frequency distribution of the pore throat radius of types of reservoirs.
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Figure 11. Producing degree of crude oil in the pores and throats of different of different types of reservoirs.
Figure 11. Producing degree of crude oil in the pores and throats of different of different types of reservoirs.
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Figure 12. Imbibition NMR results of core samples of type I reservoir; (a–c) are the T2 spectrum of imbibition NMR, the histogram of NMR signal at different imbibition times and the variation of production degree of crude oil in the pore throats of IR-07, respectively.
Figure 12. Imbibition NMR results of core samples of type I reservoir; (a–c) are the T2 spectrum of imbibition NMR, the histogram of NMR signal at different imbibition times and the variation of production degree of crude oil in the pore throats of IR-07, respectively.
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Figure 13. Imbibition NMR results of core samples of type II reservoir; (a,d) are the T2 spectrum of imbibition NMR of IR-01 and IR-10, respectively; (b,e) are the histogram of NMR signal at different imbibition times of IR-01 and IR-10, respectively; (c,f) are the variation of production degree of crude oil in the pore throats of IR-01 and IR-10, respectively.
Figure 13. Imbibition NMR results of core samples of type II reservoir; (a,d) are the T2 spectrum of imbibition NMR of IR-01 and IR-10, respectively; (b,e) are the histogram of NMR signal at different imbibition times of IR-01 and IR-10, respectively; (c,f) are the variation of production degree of crude oil in the pore throats of IR-01 and IR-10, respectively.
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Figure 14. Imbibition NMR results of core samples of the type III reservoir; (a–c) are the T2 spectrum of imbibition NMR, the histogram of NMR signals at different imbibition times and the variation in the production degree of crude oil in the pore throats of IR-02, respectively.
Figure 14. Imbibition NMR results of core samples of the type III reservoir; (a–c) are the T2 spectrum of imbibition NMR, the histogram of NMR signals at different imbibition times and the variation in the production degree of crude oil in the pore throats of IR-02, respectively.
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Figure 15. Imbibition NMR results of core samples of type IV reservoir; (a,d) are the T2 spectrum of imbibition NMR of IR-04 and IR-05, respectively; (b,e) are the histogram of NMR signal at different imbibition times of IR-04 and IR-05, respectively; (c,f) are the variation of production degree of crude oil in the pore throats of IR-04 and IR-05, respectively.
Figure 15. Imbibition NMR results of core samples of type IV reservoir; (a,d) are the T2 spectrum of imbibition NMR of IR-04 and IR-05, respectively; (b,e) are the histogram of NMR signal at different imbibition times of IR-04 and IR-05, respectively; (c,f) are the variation of production degree of crude oil in the pore throats of IR-04 and IR-05, respectively.
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Figure 16. Migration rule of crude oil in pore throats of different types of reservoirs; (a) Type I reservoir; (b) Type II reservoir; (c) Type III reservoir; (d) Type IV reservoir.
Figure 16. Migration rule of crude oil in pore throats of different types of reservoirs; (a) Type I reservoir; (b) Type II reservoir; (c) Type III reservoir; (d) Type IV reservoir.
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Table
Table 1. Comparison of the micropore throat structure parameters of different reservoir types.
Table 1. Comparison of the micropore throat structure parameters of different reservoir types.
TypePorosity (%)Permeability (mD)Argillaceous
Content (%)		Displacement Pressure (MPa)Maximum Throat
Radius (μm)		Median Pressure (MPa)Median Radius (μm)Average Capillary Radius (μm)Saturated Pore
Volume (%)		Mercury Removal Efficiency (%)
Type I9.982.91<20.1635.80.51.121.4277.521.6
Type II9.471.612–50.28.961.80.580.9278.419.4
Type III7.971.305–80.324.5910.10.260.5166.316.4
Type IV5.370.28>80.362.3211.20.140.2960.415.2
Table
Table 2. Information on the experimental samples.
Table 2. Information on the experimental samples.
Experimental MethodSampleTypeGas Porosity (%)Gas
Permeability (mD)		Diameter (cm)Length (cm)Dry Weight
(g)
Centrifugal displacementCD-1Type III7.40.9162.494.1647.45
CD-2Type II9.51.2712.463.5144.76
CD-3Type I10.82.2892.543.7945.63
CD-4Type I10.52.2742.554.0846.96
CD-5Type II9.41.2682.544.1247.15
CD-6Type III7.60.9232.493.9546.48
CD-7Type II9.81.2752.544.0647.08
CD-8Type III7.20.9312.513.8346.16
CD-9Type VI5.80.2852.494.1647.27
CD-10Type I10.92.2962.543.1742.85
Imbibition replacementIR-01Type II9.52.2722.398.0390.43
IR-02Type III7.30.9282.497.0879.34
IR-04Type VI6.00.2902.367.7190.91
IR-05Type VI5.70.2812.417.1285.52
IR-07Type I10.72.2902.407.8090.39
IR-10Type II9.21.2682.487.3185.02
Table
Table 3. Fluid property parameters of the Baikouquan Formation reservoir.
Table 3. Fluid property parameters of the Baikouquan Formation reservoir.
Formation Water
Water typeTotal salinity (mg/L)Main ion mineralization (mg/L)
Na+ + K+Mg2+Ca2+SO42−Cl−HCO3−
CaCl211,047.43054.238.51055.3105.56295.1538.9
Crude oil
Density (g/cm3)Viscosity at 50 °C (MPa·s)Wax content (%)Freezing point (°C)Initial boiling point (°C)
0.8278.68.216.6137.2
Table
Table 4. Oil recovery of different reservoir types by imbibition replacement.
Table 4. Oil recovery of different reservoir types by imbibition replacement.
Reservoir TypeSampleArgillaceous Content (%)Permeability (mD)Porosity (%)Oil Bearing Ratio of Small Pores (%)Production Degree of Crude Oil in Small Pores (%)Production
Degree of Crude Oil in Large Pores (%)		Imbibition
Recovery (%)
Type IIR-07<29.32010.233.056.0717.1423.21
Type IIIR-012–58.4009.577.0230.093.8933.98
Type IIIR-102–56.2408.967.6932.162.5434.70
Type IIIIR-025–81.3209.276.2332.862.4435.30
Type IVIR-04>81.0108.276.1221.2310.1831.41
Type IVIR-05>80.1541067.2923.9211.0734.99
Table
Table 5. Oil recovery of different types of reservoirs.
Table 5. Oil recovery of different types of reservoirs.
TypeMethodProduction Degree of Crude Oil (%)
<0.02 μm0.1~0.02 μm>0.1 μm
Type ICentrifugal displacement028.1967.7
Imbibition replacement06.0717.14
Type IICentrifugal displacement015.871.69
Imbibition replacement031.123.22
Type IIICentrifugal displacement010.272.69
Imbibition replacement032.862.44
Type IVCentrifugal displacement016.9574.41
Imbibition replacement022.5810.62
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Tan, F.-Q.; Ma, C.-M.; Zhang, X.-Y.; Zhang, J.-G.; Tan, L.; Zhao, D.-D.; Li, X.-K.; Jing, Y.-Q. Migration Rule of Crude Oil in Microscopic Pore Throat of the Low-Permeability Conglomerate Reservoir in Mahu Sag, Junggar Basin. Energies 2022, 15, 7359. https://0-doi-org.brum.beds.ac.uk/10.3390/en15197359

AMA Style

Tan F-Q, Ma C-M, Zhang X-Y, Zhang J-G, Tan L, Zhao D-D, Li X-K, Jing Y-Q. Migration Rule of Crude Oil in Microscopic Pore Throat of the Low-Permeability Conglomerate Reservoir in Mahu Sag, Junggar Basin. Energies. 2022; 15(19):7359. https://0-doi-org.brum.beds.ac.uk/10.3390/en15197359

Chicago/Turabian Style

Tan, Feng-Qi, Chun-Miao Ma, Xu-Yang Zhang, Ji-Gang Zhang, Long Tan, Dan-Dan Zhao, Xian-Kun Li, and Yu-Qian Jing. 2022. "Migration Rule of Crude Oil in Microscopic Pore Throat of the Low-Permeability Conglomerate Reservoir in Mahu Sag, Junggar Basin" Energies 15, no. 19: 7359. https://0-doi-org.brum.beds.ac.uk/10.3390/en15197359

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