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Article

Reservoir Body Development Characteristics in Deep Carbonate Gas Reservoirs: A Case Study of the Fourth Member of the Dengying Formation, Anyue Gas Field

by
Beidong Wang
1,2,
Shenglai Yang
1,2,*,
Jiangtao Hu
1,2,*,
Shuai Zhao
1,2,
Hui Deng
3,
Yuxiang Zhang
4,
Youjun Yan
3 and
Yi Jiang
1,2,3
1
College of Petroleum Engineering, China University of Petroleum (Beijing), Beijing 102249, China
2
National Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing), Beijing 102249, China
3
Exploration and Development Research Institute, PetroChina Southwest Oil & Gasfield Company, Chengdu 610041, China
4
PetroChina Research Institute of Petroleum Exploration and Development, Beijing 100083, China
*
Authors to whom correspondence should be addressed.
Processes 2024, 12(8), 1619; https://doi.org/10.3390/pr12081619
Submission received: 10 July 2024 / Revised: 27 July 2024 / Accepted: 30 July 2024 / Published: 1 August 2024
(This article belongs to the Section Energy Systems)
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Abstract

:
Deep carbonate rocks are characterized by strong heterogeneity and fracture and cavity development, which have important influence on the storage and seepage capacity of reservoirs. To comprehensively characterize the developmental characteristics of the reservoir body in the intra–platform reservoir of the fourth member of the Dengying Formation in the Anyue gas field, this study employed a multiscale pore–throat structure characterization method that combines physical property analysis, core surface observation, cast thin section observation, a nuclear magnetic resonance (NMR) test, and CT scanning analysis. The results reveal that the primary storage spaces in the intra–platform reservoirs consist of inter–crystalline pores and small cavities (<2 mm), with thick throats and fractures serving as the primary flow channels. The rock density is lower in areas where solution fractures and cavities are developed, and the fractures and cavities are generally distributed in clusters. Notably, the intra–platform reservoir of the fourth member of the Dengying Formation is characterized by low asphaltene content. The presence of fractures in fracture–cavity type cores can reduce seepage resistance in the near–fracture area and enhance the drainage efficiency of small pores, as observed in the NMR test combined with centrifugation. In the centrifugal experiments, the increase in centrifugal force had the most significant impact on drainage efficiency, with the highest efficiency being 25.82% for cavity–type cores and the lowest being 6.39% for pore–type cores. Furthermore, by integrating the results of cast thin section and NMR test, the cavity–type reservoirs were further classified into two categories: dissolved cavity storage type and dissolved pore storage type. This study clarifies the storage and seepage characteristics of dissolved–pore storage reservoirs, which are challenging to develop but have high development potential. With reasonable surface operation measures, these reservoirs can provide important support for stable production in the middle and late stages of intra–platform reservoir development.

1. Introduction

Natural gas, a low–carbon clean fuel, plays a pivotal role in the energy sector [1,2]. The significance of natural gas is underscored by its superior safety features during use and transport, as well as its environmental advantages. The reserves and production of natural gas are crucial for maintaining a balance in energy supply. Despite the decline in the proportion of conventional fossil fuels due to increasingly stringent environmental regulations, the proportion of natural gas within fossil fuels has consistently increased over the years, solidifying its key position in energy consumption [3,4,5]. In recent years, as shallow gas reservoirs have entered the late stage of development, deep carbonate gas reservoirs have emerged as one of the largest potential resources, garnering extensive attention in Sichuan Basin, China. Deep carbonate reservoirs are characterized by high temperatures, strong heterogeneity, and complex seepage mechanisms, which differ significantly from conventional reservoirs [6,7]. During the carbonate sedimentary diagenetic process, fractures and dissolved cavities develop under the influence of heterogeneous dissolution. As a result, these reservoirs exhibit strong heterogeneity, with multiple types of reservoir and seepage spaces, and the development characteristics of pores and throats are critical parameters in determining the reservoir gas storage and seepage capacity [8,9,10]. Therefore, understanding the pore structure of deep carbonate gas reservoirs and the relationships between seepage and pore–throat structures is essential.
Currently, the primary testing methods for characterizing the pore–throat structure of reservoir rock can be broadly classified into two categories. The first type encompasses methods such as casting thin section, high-pressure mercury intrusion (HPMI), scanning electron microscopy (SEM), and gas adsorption [11,12,13]. The advantages of these methods lie in their ability to characterize samples from multiple perspectives, with well-established technologies and affordable costs. Mercury will remain in the core in the HPMI method, while the core will be physically destroyed directly by scanning electron microscopy and the gas adsorption method, and the significant drawback of these methods is that they can damage the core and only provide a limited observation area, which may not accurately reflect the overall pore and throat development of the core. The second type of methods includes NMR testing, CT scanning analysis, and the construction of 3D pore–throat structure models [14,15]. These methods offer a larger observation area and do not damage the core, allowing for the observation of all pore throats within the accuracy range. However, they are associated with higher testing costs and longer testing times.
Researchers have conducted extensive studies on pore–throat structures globally. Li et al. [16] conducted HPMI experiments on Chang 7 member samples in Ordos basin, revealing that the pore–throat structure of the Chang 7 reservoir is complex and exhibits strong heterogeneity, with the structure and development degree of middle pores primarily influencing reservoir permeability space. Lai et al. [17] employed NMR test and CT scanning analysis to evaluate the pore size distribution of rock samples and the three-dimensional connectivity of pore throats, highlighting the irregular structure characteristics of pore throats and concluding that tight sandstone exhibits strong heterogeneity. Adegbite et al. [18] used the HPMI dates from 228 carbonate cores from the Middle East to investigate the relationship between porosity, permeability, and pore–throat radius using multiple regression analysis, artificial neural networks, and adaptive neuro-fuzzy inference systems, demonstrating that multiple regression was the best predictor for cores with 35% mercury feed saturation. Zhang et al. [19] utilized casting thin section and physical properties measurements to investigate the pore–throat structures of tight reservoirs, showing that the pore–throat structure has a significant impact on the percolation capacity of tight reservoirs, with porosity and pore–throat radius positively correlated with permeability. Yu et al. [20] applied micron-nano CT scanning technology and Avizo software to quantitatively evaluate the 3D pore–fracture network system of volcanic reservoir samples at multiple scales, revealing that multiscale CT scanning can accurately evaluate the physical properties of volcanic reservoirs with multiscale pore–throats and fractures. Zeng et al. [1] conducted CT scanning experiments on six cores at different resolutions, demonstrating that the coordination number, connectivity based on low-resolution X–CT data, and pore–throat radius based on high-resolution X–CT data are the primary parameters controlling permeability. Hu et al. [21] analyzed the pore–throat structure of deep carbonate rocks by casting thin section observation, SEM image observation, and NMR tests, describing the pore–throat structure characteristics of different types of carbonate rocks and fluid mobility in different types of carbonate samples under different centrifugal forces. Although numerous studies have been conducted on pore–throat structure, the research has primarily focused on static analysis through the integration of multiple testing methods. However, there is a significant lack of research on the dynamic production characteristics of different types of reservoirs based on distinct pore–throat development characteristics. Consequently, the existing research findings are insufficient to provide effective theoretical support for deep and complex gas reservoirs.
The pore–throat structure of deep carbonate gas reservoirs exhibits complex features due to the multiscale nature of pore–throat sizes and diverse pore types. This study focuses on three typical types of intra–platform reservoir cores from the fourth member of the Dengying Formation in the Anyue gas field, Sichuan Basin. A comprehensive analysis of pore–throat characteristics, storage capacity, and fluid mobility in these carbonate cores was conducted using a combination of experimental methods. Initially, a qualitative analysis of pore–throat structure characteristics was performed through observation of natural core photos and casting thin sections. Subsequently, the development and distribution characteristics of pores and throats were analyzed at different resolutions using two-dimensional CT scanning gray images, and three-dimensional pore–throat structure models of different core types were constructed to quantify the distribution of pore and throat sizes. Finally, T2 spectral variations and fluid mobility characteristics of different core types were analyzed using NMR experiments under varying centrifugal forces. Observation of natural core photos and casting thin sections aim to qualitatively obtain a reservoir’s characteristics of fractures, cavities, seepage channels, and the distribution of asphaltene. CT scanning focuses on quantitatively determining the pore size and quantity of the samples. In NMR experiments under different centrifugal forces, the characteristics of the target reservoir serve as the theoretical foundation to study the seepage characteristics.

2. Methodology

2.1. Material

The deep carbonate reservoirs in the fourth member of the Dengying Formation in the Anyue gas field, Sichuan Basin, are characterized by the development of fractures and pores, as well as strong heterogeneity. Based on the microscopic pore–throat characteristics and macroscopic seepage characteristics of the reservoir in the study area, the reservoir can be further classified into three types: pore type, cavity type, and fracture–cavity type [22,23]. However, the limited size of the plunger core (diameter 1 inch) restricts its ability to fully capture the development of fractures and cavities. To overcome this limitation, six representative full-diameter cores were selected from the study area, comprising two pore–type, two cavity–type, and two fracture–cavity type samples. Following the same core selection principle, six plunger cores were selected for NMR testing under different centrifugal forces. The permeability of the twelve cores ranged from 0.00049 × 10−3 μm2 to 5.09 × 10−3 μm2, with an average value of 0.53 × 10−3 μm2. The porosity ranged from 0.87% to 9.0%, with an average value of 3.94%. The physical properties of the core sample, including sample number, well number, porosity, permeability, length, diameter, and sample type, are presented in Table 1. According to the formation water composition data from the study reservoir, a CaCl2 brine with a salinity of 56,812 mg/L was used as the experimental simulation water. Additionally, high-purity nitrogen (99.99%) was used to simulate reservoir gas.
To elucidate the differences in permeability and porosity among various core types, permeability and porosity testing was conducted using helium on six full-diameter cores, adhering to the standards GB/T 29172-2012 [24] and SY/T 6385-2016 [25] of the People’s Republic of China. To eliminate the influence of the gas slip effect, which arises from low fluid pressure on gas permeability, the gas permeability was determined through multiple tests at varying pressures, employing the Klinkenberg Equation to calculate the gas slip coefficient [26]. The relationship is primarily expressed by the following formula:
K g = K ∞ 1 + b P
where Kg is the permeability measured with helium, 10−3 μm2; K∞ is Klinkenberg permeability (equivalent liquid permeability), 10−3 μm2; b is Klinkenberg gas slip coefficient, 10−1 MPa; and P is average pressure inside the core, 10−1 MPa.

2.2. Casting Thin Sections

The preparation of cast thin sections was conducted in accordance with the industry standard SY/T 5913-2004 [27] of the People’s Republic of China. The experimental environment was maintained at a constant temperature of 23 °C and a relative humidity of 35%. The procedure for preparing cast thin sections involved the following steps: (1) Manual trimming of the sample to a size suitable for placement in a cast tube, with mica separation in the middle, followed by 2 h vacuum treatment; (2) preparation of a mixture of methylene blue and epoxy (1.5%) with 15% triethanolamine addition, which was then injected into the casting tube over a period of approximately 20 min and subsequently placed in a casting machine (ZTHJ−3A, Haian, China); (3) heat treatment and pressurization for 4–6 h to reach a temperature of 65 °C and a pressure of 30 MPa, followed by a temperature increase to 95 °C and a pressure increase to 50 MPa, which was maintained for 20 h; (4) after cooling to room temperature, the cast tube was removed from the casting machine, and the sample was separated on a slicer, followed by grinding to produce cast thin sections; (5) the final cast thin sections were prepared with a slide size of 25,476.2 mm. After pressing the casting glue into the sheet at high temperature and high pressure, the flat surface was ground, and the sample was mounted on a slide and ground to a thickness of 0.035 mm. Finally, a coverslip (2424 mm, 0.17 mm thick) was applied, and the sample was labeled after cleaning.

2.3. CT Methods

2.3.1. CT Principles

The principle of CT scanning is based on the interaction between X-ray photons and the experimental core. As the X-ray beam traverses the core, a significant portion of the photons are either converted into electrons or absorbed, leading to a reduction in the X-ray intensity [28,29,30,31]. The degree of attenuation is directly dependent on the density and thickness of the object traversed by the X-ray beam. During the CT scanning of the core, the X-ray beam interacts with the internal pores, which exhibit heterogeneous spatial distribution characteristics. As a result, the degree of X-ray attenuation varies spatially within the core. The resulting grayscale image generated by CT scanning reflects the density distribution within the core, with higher densities corresponding to lighter colors and lower densities corresponding to darker regions, where cavities and fractures typically occur.
In this experiment, CT scanning of the core was performed at 1 μm and 10 μm resolutions using CT scanners (“Phoenix nanotom m” and “Phoenix V|tome|x M” by GE). The CT equipment features a unique dual X-ray tube design, which significantly enhances CT image quality compared to conventional cone beam micro-focus CT, and is characterized by a high magnification ratio. Equipped with a DXR temperature self-stabilizing detector and a diamond window anode target, the instrument is capable of acquiring stable and high-quality images. This equipment offers distinct advantages for detecting samples with high radiation absorption rates.

2.3.2. Three-Dimensional Pore–Throat Structure Model

The Avizo software was employed to process the 2D grayscale images obtained from the CT scans and construct a 3D pore–throat model. The model construction process is illustrated in Figure 1 and involves the following steps: (1) Image import: The tiff-format images obtained from CT scans were imported into Avizo. (2) Three-dimensional model construction: Avizo automatically generated a 3D grayscale model from the CT scan data, which was then adjusted for contrast to facilitate visualization. (3) Threshold segmentation: The “ full width at half maximum (FWHM)” was applied to adjust pore boundaries. FWHM is a commonly used evaluation and analysis method, especially when evaluating the size measurement of certain structures, such as pores. The FWHM is the full width of the absorption band at half the height, i.e., the transmission peak width at half the peak height. The pore network model was established using the Interactive Thresholding function. (4) Study area selection: To reduce computational requirements, a study area was selected using the Extract Subvolume Function. For fracture–cavity–type cores, areas with developed fractures were selected, while for pore–type and cavity–type cores, areas were chosen based on the principle that the porosity deviation between the selected area and the overall core porosity did not exceed 5%. A 5000 μm cube was selected as the study area for 10 μm resolution CT scans, and a 500 μm cube was selected for 1 μm resolution CT scans. (5) Connectivity pore and throat network modeling: Connectivity analysis was performed using Avizo’s Axis Connectivity function to establish the skeleton network model. After the threshold segmentation of samples is performed in Avizo software, sample connectivity analysis is performed by using the “Axis Connectivity” command, and the pore volume and pore quantity data of samples are obtained according to the analysis result “Label Analysis”; (6) Ball-stick model construction: The maximum ball algorithm was used to construct the ball-stick model.

2.4. NMR Methods

2.4.1. NMR Principles

NMR is a non-invasive and efficient technique for identifying the distribution of fluids within a reservoir. The principle underlying NMR is the detection of hydrogen signals in fluids, which yield a pattern of signal amplitude and transverse relaxation time (T2) [32,33]. This technique enables the measurement of the transverse relaxation time of formation pore fluids, thereby providing key petrophysical parameters such as formation porosity, permeability, and fluid saturation [34,35,36]. The relationship of transverse relaxation time T2 is mainly shown as follows:
1 T 2 = 1 T V R + 1 T S R + 1 T D R ≈ 1 T S R
where T2 is the transverse relaxation time, ms; TVR is the volume relaxation time, ms; TSR is the surface relaxation time, ms; and TDR is the diffusion relaxation time, ms. The value of T2B is significantly larger than that of TSR, and its impact on T2 is often negligible, thus it can be safely ignored. Furthermore, the influence of TDR on T2 is also negligible in a uniform static magnetic field.

2.4.2. NMR Test under Different Centrifugal Forces

The NMR testing principle under different centrifugal forces is based on the concept that when the centrifugal force generated by the centrifuge exceeds the resistance of fluid transport in the pore throat, the fluid in the core can be discharged. The magnitude of the drainage efficiency is correlated with the permeability of the core and the degree of pore–throat connectivity [37]. In this study, the connectivity and pore–throat matching of the cores were evaluated by comparing the T2 values of different types of cores under different centrifugal forces. NMR can provide the full-size T2 distribution of the core, which can be combined with the mercury injection method to convert the T2 values to pore diameters. Although many researchers have conducted extensive studies in this area, the results of their research on the application of carbonate rocks are unsatisfactory [38,39,40], failing to reflect the characteristics of carbonate reservoir development with fractures and cavities. Therefore, this study directly uses the magnitude of T2 to characterize the pore–throat of rock.
This experiment necessitates the use of two instruments (Figure 2): (1) an NMR instrument (SPEC-RC2, SPEC, Beijing, China), which features a magnetic field frequency of 12.8 MHz, a maximum testing area of a Φ200 mm × 200 mm cylinder, frequency control accuracy of 0.019 MHz, and a minimum digital acquisition interval of 100 ns; and (2) a multistage high-speed centrifuge instrument (H/T20MM, Herexi, Tianjin, China), equipped with a speed control range of 0~11,000 r/min, an adjustment accuracy of 25 r/min, and a temperature control range of −20 °C to 25 °C.
The brine injection is challenging due to the poor pore–throat structure characteristics of the reservoir core. To ensure full saturation, CO2 replacement vacuum and high-pressure saturation are employed. Subsequently, the brine-saturated core is subjected to NMR testing to obtain the T2 spectrum under saturated water conditions. Following centrifugal experiments at 0.1 MPa, 0.2 MPa, 0.3 MPa, 0.5 MPa, 1 MPa, and 3 MPa, NMR tests are conducted, resulting in seven sets of NMR curves for each core. Considering the core length and the influence of centrifuge rotational speed accuracy, a centrifugal force error not exceeding 3% is adopted. The manuscript uses changes in NMR spectrum distribution to determine core drainage efficiency. Figure 3 shows a schematic diagram for determining drainage efficiency. The drainage efficiency is mainly shown as follows:
η = 1 − S 1 S × 100 %
where η is the drainage efficiency, dimensionless; S1 is the mathematical integral area of the NMR curve under 0.1 MPa centrifugal force, dimensionless; and S is the mathematical integral area of the NMR curve in a saturated water state, dimensionless.

3. Pore–Throat Structure Characteristics of Deep Carbonate Reservoirs

3.1. Observation of Natural Core

The carbonate reservoir exhibits strong heterogeneity, as revealed by the observation of natural cores (Figure 4). The pore–type cores (Figure 4a) are characterized by the absence of visible solution cavities, with cavities primarily being millimeter-sized rather than centimeter-sized, and no fracture development. In contrast, the cavity–type cores (Figure 4b) feature a higher number of visible, spherical solution cavities with concentrated distributions and obvious dissolution phenomena. Although a few completely filled fractures are present, these cores lack developed stress fractures. Overall, the storage performance of cavity–type cores is superior to that of pore–type cores. The fracture–cavity–type cores (Figure 4c) exhibit prominent characteristics of concentrated fracture and cavity development, with lowly spherical cavities distributed along dissolution fractures. Overall, the storage and seepage performance of fracture–cavity type cores is advantageous.

3.2. Observation of Casting Thin Sections

Casting thin section images of three typical carbonate reservoir types reveal distinct reservoir space development characteristics. Pore–type cores (Figure 5a,b) feature intergranular (particle) pores and intergranular (particle) dissolved pores as storage spaces, with no dissolved cavities. Intergranular (particle) throats serve as the primary seepage channels, and the core connectivity is relatively weak. Notably, the degree of asphaltene filling is low in pore–type cores. Cavity–type cores can be further divided into two subcategories based on their pore development characteristics. The first subcategory, referred to as the dissolved cavity storage type (Figure 5c), features cavities as the primary storage space, with intergranular throats acting as the main flow channels. The second subcategory, referred to as the dissolved pore storage type (Figure 5d), is characterized by large-scale dissolved pores as the primary storage space, with connected pores and intergranular throats serving as the main flow channels. Both subcategories exhibit significant advantages in storage and seepage capacity compared to pore–type cores, with a slightly higher degree of asphaltene filling. Fracture–cavity cores (Figure 5e,f) exhibit strong overall seepage capacity, with dissolved cavities and large-scale dissolved pores serving as the primary storage spaces. However, dissolved fractures and stress fractures are filled with asphaltene to a high degree. Asphaltene is an important component of organic matter in hydrocarbon source rock. Studying the distribution of asphaltene in pores and throats plays an important role in reservoir. On the one hand, the existence of asphaltene will directly affect the porosity and permeability of core samples. In addition, asphaltene exists in pores as organic matter, and its strong adsorption of CO2 can be used to study the enhanced recovery rate of gas reservoirs. Finally, the migration and accumulation process of gas reservoirs can be studied by analyzing the components of asphaltene. During the gas reservoir formation process, the migration resistance of organic matter along fractures and high-permeability throats is small, so the asphaltene content in such cores is relatively high [41]. Overall, cores with superior storage and seepage capacity tend to be accompanied by a higher degree of asphaltene filling.

4. Characteristics of Cross-Scale Pore–Throat Development in Deep Carbonate Reservoirs

Figure 6 presents a grayscale image for comparing the developmental characteristics of storage space and seepage channels in different types of cores under varying CT scanning resolutions. Notably, pore–type cores exhibit no obvious dissolved pores at a resolution of 10 μm (Figure 6a), whereas sporadic pores with diameters ranging from 1 to 8 μm are observed at a resolution of 1 μm (Figure 6b). Cavity–type cores do not develop obvious fractures. At a resolution of 10 μm, dissolved pores with diameters of 10 μm to 1000 μm exhibit high sphericity and are mainly developed in low-density areas of the grayscale image. At a resolution of 1 μm, the pores are approximately spherical, with diameters of 0.5 μm to 50 μm, and are distributed more uniformly, characteristic of the dissolved pore storage type (Figure 6d).
In fracture–cavity–type cores, obvious stress fractures and dissolved fractures with varying degrees of development are observed (Figure 6e). Stress fractures develop in areas with high core density (Figure 6f), with lengths ranging from 2 mm to 15 mm and widths generally not exceeding 10 μm, serving as primary flow channels to enhance seepage ability but with poor storage capacity. The widths of dissolved fractures range from 10 μm to 30 μm, and the rock density in areas with developed dissolved fractures is low. During sedimentary diagenesis, freshwater will further dissolve rock particles along dissolved fractures, forming flat, centrally distributed dissolved fracture extension pores and solution fracture extension cavities. In the reservoir, extension pores and cavities exhibit a peanut rhizome-like distribution along the dissolved fracture. In fracture–cavity–type samples, dissolved cavities and large-sized dissolved pores are present, with few small-sized pores, and no pores are found in areas distant from fractures or cavities.
Figure 7 presents a comparative analysis of pore–throat development characteristics in the ball-stick model of the cube, obtained using CT scans at 10 μm and 1 μm resolutions. At 10 μm resolution, pore–type samples exhibit extremely poor pore development, characterized by a maximum pore volume of 0.26 mm3, a pore count of 838, and an average coordination number of 0.017 (Figure 7a). Cavity–type (Figure 7b) samples display a maximum pore volume of 0.42 mm3, a pore count of 1760, and an average coordination number of 0.44. Fracture–cavity–type (Figure 7c) samples exhibit a maximum pore volume of 3.78 mm3, a number of pores of 4628, and the average coordination number 1.86. At 1 μm resolution, pore–type small samples (Figure 7d) have a maximum pore volume of 2.05 × 10⁻4 mm3, 1949 pores, and an average coordination number of 0.11. Cavity–type small samples (Figure 7e) display a maximum pore volume of 4.61 × 10⁻4 mm3, 5974 pores, and an average coordination number of 0.29. The fracture–cavity small sample (Figure 7f) exhibits a maximum pore volume of 1.11 × 10⁻3 mm3, 921 pores, and an average coordination number of 0.59.
In summary, regardless of the resolution, the maximum pore volume and coordination number of the three sample types exhibit a consistent trend, with fracture–cavity–type, cavity–type, and pore–type samples displaying decreasing values. However, the number of pores exhibits a different pattern. At 10 μm resolution, the sequence of the three sample types remains the same, with fracture–cavity type, cavity–type, and pore–type samples showing decreasing numbers of pores. In contrast, at 1 μm resolution, the order is reversed, with cavity–type, pore–type, and fracture–cavity–type samples displaying decreasing numbers of pores. This anomalous phenomenon can be attributed to the unique characteristics of fracture–cavity cores during sedimentary diagenesis. Specifically, fractures and caves develop in fracture–cavity cores, and dissolution primarily occurs around these features during diagenesis, resulting in minimal dissolution outside the fracture–cavity development area. Consequently, the pore space size in fracture–cavity cores is relatively large, with few pores smaller than 1 μm.

5. Storage Capacity and Seepage Capacity of Deep Carbonate Reservoirs

5.1. Analysis of Pore–Type Core Spectrum Characteristics

Figure 8 presents the T2 spectral distribution of pore–type cores GNZ-5 and GNZ-6 under various centrifugal forces. The T2 spectrum of GNZ-5 (Figure 8a) in the saturated water state exhibits a single peak, with relaxation time ranging from 0.08 ms to 382.54 ms, and a peak distribution at 74.82 ms. After centrifugation at 0.1 MPa, the T2 spectra show an overall decrease, but further increases in centrifugal force do not result in significant changes. The T2 spectrum of GNZ-6 (Figure 8b) displays a single peak, with relaxation times ranging from 0.07 ms to 247.57 ms, and a peak distribution at 48.42 ms. The drainage efficiency of pores with relaxation times less than 100 ms increases to some extent with increasing centrifugal force, and the drainage efficiency of the core’s movable water is significantly enhanced. After centrifugation at 0.2 MPa, the movable water in the core is largely discharged, with a final drainage efficiency of 39.44%. Overall, pore–type cores exhibit single-peak T2 spectra, indicating poor pore–throat connectivity, low drainage efficiency, and poor storage and seepage capacity, making them challenging for beneficial development.

5.2. Analysis of Cavity–Type Core Spectrum Characteristics

Figure 9 presents the T2 spectral distribution of cavity–type cores GNZ-8 and GNZ-16 under various centrifugal forces. The T2 spectrum of GNZ-8 (Figure 9a) in the saturated water state exhibits a bimodal distribution, with relaxation time ranging from 0.02 ms to 7215.52 ms. The left peak has a peak distribution at 20.28 ms, while the right peak has a peak distribution at 276.02 ms, indicating the coexistence of pore and cavity storage spaces. After the 0.1 MPa centrifugal experiment, the T2 spectrum of GNZ-8 shows a significant overall decrease, with the right peak exhibiting a higher degree of mobilization than the left peak, suggesting good pore–throat connectivity and seepage capacity in regions with more developed cavities. As the centrifugal force increases, the relaxation times of the two peaks near the peak values decrease slightly after the 0.3 MPa centrifugal experiment. In this stage, the increased centrifugal force primarily utilizes large-size cavities and small-size dissolved pores. The final drainage efficiency reaches 81.73%. The non-homogeneity of these cavity–type cores is relatively strong, with large-sized cavities easily utilized as the main storage space, characteristic of dissolved cavity storage type.
The T2 spectrum of GNZ-16 (Figure 9b) exhibits a single peak, with relaxation times ranging from 0.69 ms to 3022.14 ms, and a peak distribution at 67.11 ms. This suggests that the core is primarily composed of different sizes of dissolved pores, without dissolved cavities. As the centrifugal force increases from 0.1 MPa to 3 MPa, the drainage efficiency increases significantly from 38.95% to 72.35%. This indicates that the core’s various scales of dissolved pores serve as the main accessible storage space. The core’s pore–throat matching degree is high, with premium connectivity, characteristic of dissolved pore storage type. Based on their spectral characteristics, cavity–type cores can be categorized into two types: (1) the dissolved cavity storage type, which exhibits strong storage capacity, high discharge rates, and high mobility after centrifugation at 0.1 MPa; and (2) the dissolved pore storage type, which has a high matching degree of pores and throats at different levels, and displays a more pronounced change in drainage efficiency with increasing centrifugal force.

5.3. Analysis of Fracture–Cavity–Type Core Spectrum Characteristics

Figure 10 presents the T2 spectral distribution of fracture–cavity cores GNZ-17 and GNZ-25 under various centrifugal forces. The T2 spectral distribution of GNZ-17 (Figure 10a) in the saturated water state exhibits a bimodal distribution, with relaxation time ranging from 0.07 to 276.02 ms. The left peak has a peak distribution at 8.49 ms, and the right peak has a peak distribution at 83.41 ms. Due to the limitation of the plunger core, dissolved cavities are absent, resulting in a drainage efficiency of 65.09% after the 0.1 MPa centrifugation experiment. The experimental simulation reveals that water in different-sized pores and throats is mobilized to varying degrees, and the movable water in large-sized dissolved cavities adjacent to the fracture is completely discharged. In subsequent experiments, distinct drainage characteristics are observed in fracture–cavity–type cores compared to pore–type and cavity–type cores. As the centrifugal force increases, the T2 spectra of small-sized pores in fracture–cavity–type cores continuously decrease. Due to capillary force and other resistances, when the centrifugal force is small, all the liquid in the core cannot be completely discharged. The throat with a small size needs larger centrifugal force to discharge the liquid. Fractures develop in the fracture–cavity cores. When the liquid flows in the fractures, only a small centrifugal force is needed. Moreover, the fractures connect in the throat with a small size, and the liquid in this type of throat with a small size only needs to overcome the resistance from the throat to the fractures. The ultimate drainage efficiency of GNZ-17 reaches 70.39%, reflecting its distinct characteristics of fracture development.
The T2 spectrum of GNZ-25 (Figure 10b) exhibits a bimodal distribution, with the relaxation time distribution ranging from 0.02 ms to 2180.63 ms. The distribution features two distinct peaks, with the left peak centered at 11.77 ms and the right peak at 160.22 ms, indicating the pronounced development of cavities. The left side of the T2 spectrum of GNZ-25 displays similar mobility characteristics to those of GNZ-17, whereas the spectrum of right side decreases more with the increase in centrifugal force, and a part of the larger pore space is mobilized step by step. Overall, the T2 spectrum of the fracture–cavity–type core exhibits a bimodal distribution, characterized by high final drainage efficiency, superior storage, and seepage capacity. The NMR testing results after centrifugation clearly demonstrate the development of fractures, with low overall utilization difficulty and ease of benefit development.

5.4. Characteristics of Drainage Efficiency in Different Types of Cores

Figure 11 presents the drainage efficiency curves of three types of deep carbonate cores. In the same type of core, with similar pore–throat structure characteristics, the greater the permeability of the same type of core, the larger the size of the main seepage channel and the lower the resistance to seepage, so under the same centrifugal conditions, the core permeability has obvious positive correlation with the initial drainage rate. Pore–throat connectivity refers to the matching relationship between pores and throats. The ratio of pore to throat size is called the pore–throat ratio. The ratio of the throat to pore number is called the pore–throat coordination factor. The larger these two parameters are, the better the connectivity of the pore–throat system of rock samples is. Therefore, the better the pore–throat connectivity is, the lower the liquid seepage resistance is and the higher the drainage efficiency is. The initial drainage efficiency of pore–type and fracture–cavity–type cores after 0.1 MPa centrifugation is primarily governed by the permeability, with higher permeability yielding higher initial drainage efficiency. Under a centrifugal force of 0.1 MPa, the average discharge rates of the three types of deep carbonate cores rank from highest to lowest as follows: fracture–cavity type (67.83%), cavity type (51.22%), and pore type (28.43%). The ultimate drainage efficiency after the 3 MPa centrifugal experiment is related to the connectivity of the pore–throat: the stronger the connectivity, the higher the final drainage rate. The ranking of the three core types from highest to lowest is fracture–cavity type (83.58%), cavity type (77.04%), and pore type (34.81%). The impact of increasing centrifugal force on drainage efficiency is primarily attributed to the matching degree of each level of pore and throat, with a higher matching degree resulting in a more significant effect; the ranking of the three core types in terms of the effect on drainage efficiency after 3 MPa centrifugation is cavity type (25.82%), fracture–cavity type (15.75%), and pore type (6.39%).

6. Suggestions on the Development of Deep Carbonate Gas Reservoirs

Based on comprehensive core observation, casting thin sections, NMR experiments combined with centrifugation, and multiscale CT scanning results of different resolutions (Table 2), we identified the pore–throat characteristics of three typical types of carbonate rock: (1) pore–type cores with a pore radius of 0.6 μm to 3.2 μm, pore volume of 3.05 × 104 μm3 or less, scattered development and a small number of storage spaces, and throat radius of 0.3 μm to 2.2 μm, with poor pore–throat connectivity, resulting in poor overall storage and seepage capacity, making it challenging to develop these reservoirs without improvement; (2) cavity–type cores with pore radius of 2.1 μm to 15.8 μm, scattered development and large number of storage spaces, premium gas storage capacity, throat radius of 1.7 μm to 12.2 μm, with superior pore–throat connectivity, resulting in strong overall storage capacity; (3) the pore radius of fracture–cavity–type cores is 1.7 μm to 11.7 μm and the throat radius is 1.4 μm to 10.7 μm, with fractures serving as the primary seepage channels, facilitating high seepage capacity and relatively low development difficulty without reservoir improvement.
Based on the storage and seepage capacity of the three typical reservoir types, we propose the following development strategies: (1) For fracture–cavity–type reservoirs, which exhibit high seepage capacity, fractures serve as the primary seepage channels, reducing overall seepage resistance. Therefore, gas wells should prioritize development areas with fracture–cavity reservoirs. (2) The dissolved cavity storage type of cavity–type reservoirs has low development difficulty under the condition of no reservoir improvement, in the early and middle development of the gas field, and it is used as the main gas reservoir for fracture–cavity–type reservoirs. (3) The development potential of the dissolved pore storage type of the cavity–type core reservoir is large, and it can be used as the focus of the research on the development of the reservoir. (4) The storage and seepage capacity of the pore–type reservoir is inferior, it is difficult to reach the lower limit of the industrial gas flow, and the change in the production system has less influence on it, so it is recommended to carry out the measures of reservoir improvement in order to increase the seepage capacity of the pore–type reservoir before the development.

7. Conclusions

This paper aims to study the storage and seepage characteristics of different types of reservoirs by combining various methods and provides effective theoretical support for deep and complex gas reservoirs. This study combines natural core photography, cast thin sections, and grayscale imaging under different CT scanning resolutions to qualitatively characterize the pore–throat structure characteristics of three types of carbonate gas reservoirs. Moreover, three-dimensional pore–throat models are constructed at different CT resolutions to quantitatively analyze pore and throat structures. Additionally, NMR experiments are conducted on three types of cores under varying centrifugal forces, and the fluid drainage characteristics of the cores are analyzed through changes in T2 spectra. The main conclusions of this study are as follows:
(1) The carbonate reservoirs of the fourth member of Dengying Formation in Anyue gas field are mainly composed of intergranular pores, intergranular dissolved pores, and small dissolved cavities. Cavity–type cores can be further divided into two subcategories: the dissolved cavity storage type and the dissolved pore storage type. In the fracture–cavity–type cores, extension pores and cavities exhibit a peanut rhizome-like distribution along the dissolved fracture, featuring dissolved cavities and large-sized dissolved pores, with few small-sized pores.
(2) The movable fluid is basically discharged from the pore–type core after the centrifugal test at 0.2 MPa. A large amount of fluid is discharged from the dissolved cavity storage type of the cavity–type core at the early stage of centrifugation. The correlation between the drainage efficiency and centrifugal force is stronger for the dissolved pores storage type of cavity–type cores. The existence of fractures in the process of increasing centrifugal force in fracture–cavity–type cores will obviously reduce the seepage resistance of small pores and increase their drainage efficiency, and the increment of drainage efficiency from high to low after centrifugal force increases from 0.1 MPa to 3 MPa is cavity type (25.82%), fracture–cavity type (15.75%), and pore type (6.39%).
(3) The difficulty of developing fracture–cavity–type and cavity–type reservoirs is low, they are the main gas-producing layer in the early and middle stages of development, and their production capacity is affected very little by the ground operation and reservoir improvement. The production capacity of the dissolved pore gas storage type of cavity–type core reservoirs is affected more by the ground operation measures, and the adoption of a reasonable pressure drop rate and the avoidance of premature water intrusion can give full play to their production capacity characteristics. These types of reservoirs can be used as a guarantee for successive stable production in the middle and late stages. In pore–type reservoirs, appropriate fracture measures can be adopted to connect the main permeability channel and increase its recoverable reserves under the condition that the reservoir improvement cost is allowed.

Author Contributions

Conceptualization, S.Y.; methodology, S.Y.; validation, J.H.; formal analysis, S.Z.; investigation, H.D.; resources, Y.Y.; data curation, B.W.; writing—original draft preparation, B.W.; writing—review and editing, J.H.; visualization, B.W.; supervision, S.Y.; project administration, Y.Z.; funding acquisition, Y.J. All authors have read and agreed to the published version of the manuscript.

Funding

This research is supported by the Sichuan Provincial Natural Science Foundation Project (2023NSFSC0261).

Data Availability Statement

The data presented in this study are available on request from the corresponding author.

Conflicts of Interest

Hui Deng, Youjun Yan, and Yi Jiang are employed by the PetroChina Southwest Oil & Gasfield Company; Yuxiang Zhang is employed by the PetroChina Research Institute of Petroleum Exploration and Development; and the remaining authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

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Figure 1. The 3D pore and throat structure modeling process: (a) image import; (b) 3D model construction; (c) threshold segmentation; (d) study area selection; (e) connectivity pore and throat network modeling; (f) ball–stick model construction.
Figure 1. The 3D pore and throat structure modeling process: (a) image import; (b) 3D model construction; (c) threshold segmentation; (d) study area selection; (e) connectivity pore and throat network modeling; (f) ball–stick model construction.
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Figure 2. Centrifugal NMR experimental equipment: (a) nuclear magnetic resonance core analyzer; (b) multistage high–speed centrifuge.
Figure 2. Centrifugal NMR experimental equipment: (a) nuclear magnetic resonance core analyzer; (b) multistage high–speed centrifuge.
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Figure 3. Drainage efficiency schematic.
Figure 3. Drainage efficiency schematic.
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Figure 4. Natural core photographs of three typical types of carbonate reservoirs: (a) pore type; (b) cavity type; (c) fracture–cavity type.
Figure 4. Natural core photographs of three typical types of carbonate reservoirs: (a) pore type; (b) cavity type; (c) fracture–cavity type.
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Figure 5. Casting thin section images of three typical types of carbonate reservoirs: (a) MX-125 well, 5322.46–5322.50 m, pore type; (b) MX-105 well, 5318.85–5319.11 m, pore type; (c) GS-20 well, 5191.80–5191.91 m, cavity type; (d) GS-18 well, 5136.19–5136.28 m, cavity type; (e) MX-8 well, 5111.43–5111.59 m, fracture type; (f) local image of casting thin section of fracture–cavity core, areas marked in Figure 5e.
Figure 5. Casting thin section images of three typical types of carbonate reservoirs: (a) MX-125 well, 5322.46–5322.50 m, pore type; (b) MX-105 well, 5318.85–5319.11 m, pore type; (c) GS-20 well, 5191.80–5191.91 m, cavity type; (d) GS-18 well, 5136.19–5136.28 m, cavity type; (e) MX-8 well, 5111.43–5111.59 m, fracture type; (f) local image of casting thin section of fracture–cavity core, areas marked in Figure 5e.
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Figure 6. Grayscale images under different CT scanning resolution: (a) pore type (10 μm); (b) pore type (1 μm); (c) cavity type (10 μm); (d) cavity type (1 μm); (e) fracture–cavity type (10 μm); (f) fracture–cavity type (1 μm).
Figure 6. Grayscale images under different CT scanning resolution: (a) pore type (10 μm); (b) pore type (1 μm); (c) cavity type (10 μm); (d) cavity type (1 μm); (e) fracture–cavity type (10 μm); (f) fracture–cavity type (1 μm).
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Figure 7. Three–dimensional pore and throat structure model of three typical types of carbonate reservoirs: (a) pore type (10 μm); (b) cavity type (10 μm); (c) fracture–cavity type (10 μm); (d) pore type (1 μm); (e) cavity type (1 μm); (f) fracture–cavity type (1 μm).
Figure 7. Three–dimensional pore and throat structure model of three typical types of carbonate reservoirs: (a) pore type (10 μm); (b) cavity type (10 μm); (c) fracture–cavity type (10 μm); (d) pore type (1 μm); (e) cavity type (1 μm); (f) fracture–cavity type (1 μm).
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Figure 8. T2 spectrum distribution curve of pore–type cores under different centrifugal forces: (a) GNZ-5; (b) GNZ-6.
Figure 8. T2 spectrum distribution curve of pore–type cores under different centrifugal forces: (a) GNZ-5; (b) GNZ-6.
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Figure 9. T2 spectrum distribution curve of cavity–type cores under different centrifugal forces: (a) GNZ-8; (b) GNZ-16.
Figure 9. T2 spectrum distribution curve of cavity–type cores under different centrifugal forces: (a) GNZ-8; (b) GNZ-16.
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Figure 10. T2 spectrum distribution curve of fracture–cavity cores under different centrifugal forces: (a) GNZ-17; (b) GNZ-25.
Figure 10. T2 spectrum distribution curve of fracture–cavity cores under different centrifugal forces: (a) GNZ-17; (b) GNZ-25.
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Figure 11. Drainage efficiency curves for different types of cores.
Figure 11. Drainage efficiency curves for different types of cores.
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Table 1. Experimental parameters of core sample.
Table 1. Experimental parameters of core sample.
Sample NumberLength
/cm		Diameter
/cm		Permeability
/10−3 μm2		Porosity
/%		Sample SizeSample Type
GNQ-610.1366.6100.0010.872Full-diameterPore type
GNQ-97.1606.5610.0252.413Full-diameterPore type
GNQ-57.9666.5030.0885.084Full-diameterCavity type
GNQ-138.2036.5200.0975.617Full-diameterCavity type
GNQ-78.3616.5340.1123.892Full-diameterFracture–cavity type
GNQ-49.7736.5730.4194.282Full-diameterFracture–cavity type
GNZ-54.6412.5320.000491.234PlungerPore type
GNZ-62.4832.5330.0131.894PlungerPore type
GNZ-82.0852.5340.0225.325PlungerCavity type
GNZ-162.2532.5250.00189.006PlungerCavity type
GNZ-172.1182.5130.542.167PlungerFracture–cavity type
GNZ–251.7212.5165.095.461PlungerFracture–cavity type
Table 2. Characteristics of reservoir body in fourth member of the Dengying Formation, Anyue gas field.
Table 2. Characteristics of reservoir body in fourth member of the Dengying Formation, Anyue gas field.
Characteristics of Reservoir BodyPore–Type ReservoirCavity–Type ReservoirFracture–Cavity Type Reservoir
Dissolved Cavity Storage TypeDissolved Pore Storage Type
Permeability/10−3 μm2<0.050.05–0.1>0.1
Porosity/%<3>5>4
Lithologic characterAlgal clot dolostone, laminar algal limestone, algal sandy limestone
Pore typeIntergranular (particle) pores, intergranular (particle) dissolved pores
Cavity type/Small cavity
Fracture–type//Dissolved fractures, stress structural fractures
T2 spectral characterizationUnimodalBimodalUnimodalBimodal
T2 distribution/ms0.07–382.540.02~7215.520.69~3022.140.02~2180
Main peak T2/ms61.6220.28 (left peak),
276.02 (right peak)		67.1110.13 (left peak),
121.82 (right peak)
0.1 MPa–3 MPa centrifugal drainage efficiency increase value/%6.3918.2533.4015.75
Pore radius/μm0.6–3.22.1–15.81.7–11.7
Fracture length/mm//2–15 mm
Fracture width/μm//10–30
Throat radius/μm0.3–2.21.7–12.21.4–10.7
Pore sphericityHighMiddleHighLow
Main storage spacePoreCavityLarge–sized dissolved poresCavity
Storage capacityWeakStrongStrongNot strong
Seepage capacityWeakNot weakNot strongStrong
Development difficultyBigSmallMiddleSmall
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Wang, B.; Yang, S.; Hu, J.; Zhao, S.; Deng, H.; Zhang, Y.; Yan, Y.; Jiang, Y. Reservoir Body Development Characteristics in Deep Carbonate Gas Reservoirs: A Case Study of the Fourth Member of the Dengying Formation, Anyue Gas Field. Processes 2024, 12, 1619. https://doi.org/10.3390/pr12081619

AMA Style

Wang B, Yang S, Hu J, Zhao S, Deng H, Zhang Y, Yan Y, Jiang Y. Reservoir Body Development Characteristics in Deep Carbonate Gas Reservoirs: A Case Study of the Fourth Member of the Dengying Formation, Anyue Gas Field. Processes. 2024; 12(8):1619. https://doi.org/10.3390/pr12081619

Chicago/Turabian Style

Wang, Beidong, Shenglai Yang, Jiangtao Hu, Shuai Zhao, Hui Deng, Yuxiang Zhang, Youjun Yan, and Yi Jiang. 2024. "Reservoir Body Development Characteristics in Deep Carbonate Gas Reservoirs: A Case Study of the Fourth Member of the Dengying Formation, Anyue Gas Field" Processes 12, no. 8: 1619. https://doi.org/10.3390/pr12081619

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