Diagenetic alteration,pore structure,and reservoir quality of the tight sandstone reservoirs in the Lishu fault depression in the Songliao Basin,northeastern China

Abstract

The analytical approaches including thin-section petrography, X-ray diffraction, scanning electron microscopy energy dispersive spectrometer, and high-pressure mercury intrusion porosimetry were conducted on the sandstone reservoirs in the Lishu fault depression to investigate the diagenetic alteration and their impacts on pore structure and reservoir quality. The results show that correlations between diagenetic processes and reservoir properties are observed. Six diagenetic facies, namely the strong compaction with moderate cementation facies (SCMCF), weak dissolution with cementation facies (WDCF), moderate cementation with feldspar dissolution facies (MCFDF), moderate cementation with residual intergranular pore facies (MCRIPF), moderate cementation with fracture facies (MCFF), and moderate cementation with mixed dissolution facies (MCMDF), were classified through detailed examination of microscopic petrography. Variations in pore volumes, pore size distribution, and pore fractal dimensions, alongside their influencing factors, were analyzed to elucidate the impacts of diagenetic processes on the reservoir quality of tight sandstones. The diagenetic coefficient and mineral composition are considered critical determinants of pore structure. Specifically, SCMCF and WDCF are regarded as unfavorable diagenetic facies. MCFDF and MCRIPF are categorized as moderate diagenetic facies. Conversely, MCFF and MCMDF are considered favorable diagenetic facies. The SCMCF and WDCF suggest a relatively low heterogeneity, Conversely, the MCFDF, MCRIPF, MCFF, and MCMDF show obvious reservoir heterogeneity and low pore-throat connectivity. The fractal properties of the WDCF, MCFDF, MCRIPF, and MCMDF are obvious, indicating relatively complex pore structures. This article provides insights into the relationships among the diagenetic facies, pore structure, fractal dimension, and reservoir quality of tight sandstones in the Lishu fault depression, in addition, has significance for the reservoir evaluation and exploration of tight sandstone gas the rift Basins.

Keywords

Lishu fault depression diagenesis diagenetic coefficient pore structures reservoir quality

Introduction

With the development of unconventional oil and gas production technologies, tight sandstone reservoirs have gradually become a focus of oil and gas exploration and development, especially in mature oil and gas basins where conventional resources are gradually depleting (Shen et al., 2022; Zhang et al., 2019; Zou et al., 2008). Rich tight oil and gas resources have been discovered in China's Ordos, Songliao, and Bohai basins, achieving significant exploration results (Fang et al., 2024; Shi et al., 2024; Wang et al., 2023). Compared to conventional reservoirs, tight sandstone reservoirs typically have low porosity and extremely low permeability (Hu et al., 2018). The pore structure is complex, especially under the influence of diagenesis (such as cementation), which greatly increases the difficulty of reservoir quality and extraction (Civitelli et al., 2023; Critelli et al., 1999; Qiao et al., 2022). Although dissolution may improve reservoir performance by forming secondary porosity, the overall development of tight sandstone reservoirs still faces considerable challenges (Becker et al., 2017; Zhang et al., 2015).

Diagenesis plays a key role in the study of tight sandstones. It affects not only porosity and permeability but also reservoir heterogeneity. Diagenetic facies analysis helps identify different rock facies within the reservoir and predict production potential, especially by evaluating diagenetic types, diagenetic strength, and the distribution of diagenetic minerals to locate favorable sweet spots (Cui et al., 2017; Lai et al., 2016; Taylor et al., 2010). Currently, although various research methods exist, most rely on factors such as diagenetic minerals, diagenetic environments, and diagenetic strength for classification (Vafaie et al., 2021; Zou et al., 2012). To more accurately characterize diagenetic facies, researchers have proposed quantitative diagenetic coefficients by combining parameters such as apparent compaction rate and cementation rate, along with thin-section observation and rock physics analysis.

Different diagenetic environments and rock facies combinations lead to significant heterogeneity in the physical properties and pore structure of reservoirs, which are important factors influencing their development. With the advancement of technology, advanced instruments like environmental scanning electron microscopes (SEMs), nuclear magnetic resonance, and focused ion beam SEMs have enabled in-depth study of pore-throat structures at the microscale and nanoscale (Chalmers et al., 2012; Curtis et al., 2012). Methods such as high-pressure mercury injection (HPMI), low-temperature gas adsorption, and micro-computed tomography scanning are also becoming key tools for the fine characterization of tight reservoir pore structures. Fractal theory, initially used to describe geometric self-similarity, has now been widely applied to the quantitative analysis of reservoir pore structures and heterogeneity, providing a new perspective for studying reservoir heterogeneity (Loucks et al., 2012). Diagenesis is a key factor in unconventional oil and gas exploration. Understanding its impact on reservoir properties can provide strong support for the development of tight oil and gas.

The objectives of this article are to: (1) propose a quantitative classification to identify diagenetic facies of tight sandstones; (2) discuss the relationships among the diagenetic facies, pore structure, fractal dimension, and reservoir quality of tight sandstones; (3) establish pore evolution model of tight sandstone reservoirs respect to diagenetic processes. This work may have significance for prediction of high-quality tight sandstone reservoirs in rift Basins.

Geological setting

The Lishu fault depression (LFD) is located in the southern part of the Songliao Basin, and an area of 2346 km² is covered by it. It is subdivided into six structural zones: the Sangshutai subdepression, the Shuanglong subdepression, the Sujiatun subdepression, the central uplift, the northern slope, and the southeastern slope (Figure 1(a)). Four distinct stages have been identified in the LFD: fault depression (J3-K1), fault-depression transformation (late K1), depression (K2), and subsequent uplift and erosion (An et al., 2020; Wang et al., 2011). The basement of the LFD is composed of metamorphic rocks and granites from the Carboniferous and Permian periods. Overlying the basement, the Huoshiling formation, Shahezi formation, Yingcheng formation, and Denglouku formation are developed sequentially from the base to the top (Figure 1(b)). The Yingcheng formation is predominantly composed of interbedded gray silt-fine sandstone and dark gray mudstone (Wang et al., 2011). The Shahezi formation is primarily composed of gray mudstone, gray siltstone, sandstone, and glutenite.

Figure 1.

(a) Location map of the study area showing the sub-tectonic units and sampled wells in the Lishu fault depression; (b) Generalized stratigraphy of the Lishu fault depression, showing the major petroleum system elements including the source rocks, multiple reservoir intervals, and major sealing units.

Samples and methods

Samples and experiments

A total of 22 samples were collected from the lower Cretaceous Yingcheng formation and Shahezi formation in the LFD. The samples were subjected to experiments including thin-section petrography, X-ray diffraction (XRD), SEM energy dispersive spectrometer (SEM-EDS), and HPMI porosimetry, as well as porosity and permeability tests, in order to study the diagenetic alteration, pore structure, and reservoir quality of tight sandstone reservoirs, as depicted in Table 1.

Table 1.

Sample information showing the sampled wells, formations, sampling depth, and lithology.

Sample ID	Well	Formation	Depth (m)	Lithology
LS-1	LS1	Sh₂	4455.8	Argillaceous siltstone
LS-2	LS2	Sh₂	4457.6	Argillaceous siltstone
LS-3	L8	Yc₁	4177.6	Glutenite
LS-4	L8	Yc₁	4179.8	Glutenite
LS-5	L8	Yc₁	4180.4	Glutenite
LS-6	L8	Yc₁	4185	Pebbled coarse sandstone
LS-7	L8	Yc₁	4181.3	Glutenite
LS-8	L8	Yc₁	4122.3	Pebbled coarse sandstone
LS-9	L8	Yc₁	4184	Grey white conglomerate
LS-10	L8	Yc₁	4123.2	Grey white conglomerate
LS-11	L8	Yc₁	4122.6	Grey white conglomerate
LS-12	L8	Yc₁	4179.5	Grey white conglomerate
LS-13	L8	Yc₁	4183	Grey white conglomerate
LS-14	L8	Yc₁	4181.1	Grey white conglomerate
LS-15	L8	Yc₁	4177.5	Grey white conglomerate
LS-16	L9	Sh₂	3356.32	Grey moderate conglomerate
LS-17	L9	Sh₂	3353.89	Grey gravel moderate sandstone
LS-18	L9	Sh₂	3351.56	Grey conglomerate
LS-19	L9	Sh₂	3352.2	Grey conglomerate
LS-20	L9	Sh₂	3353.03	Grey gravel moderate sandstone

XRD analyses were performed at the State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum (Beijing). The procedure was followed according to the national standards No. GB/T29172-2012 and No. SY-T5163-2010. Investigations into the microscopic attributes of samples were conducted using the Nova Nano 450 high-resolution field emission SEM at the Beijing Institute of Nuclear Industry, in accordance with the national standard No. SY/T5162-2014. HPMI measurements were undertaken at the laboratory of China University of Petroleum (East China), with the Micromeritics Autopore 9500 automatic mercury intrusion system, following the national standard No. SY/T5346-2005.

Methods

The diagenetic facies of tight sandstones were delineated quantitatively based on the diagenesis characteristics derived from abundant thin-section observations and statistical analyses. Parameters, including apparent compaction rate, apparent cementation rate, apparent dissolution rate, and visual microporosity (Gao et al., 2015; Lai et al., 2015), were used, and a comprehensive diagenetic coefficient was calculated for the quantitative delineation of diagenetic facies.

Apparent compaction rate

The apparent compaction rate, denoted as $φ_{c o}$ , is defined as the proportion of pore volume after compaction relative to the original pore volume. Consequently, when the $φ_{c o}$ surpasses 70%, a state of intense compaction is indicated; between 30% and 70%, a moderate level of compaction is inferred; and when the $φ_{c o}$ falls below 30%, weak compaction is suggested.

The formula for calculating $φ_{c o}$ is expressed as follows:

φ_{c o} = \frac{\emptyset_{O} - \emptyset_{c o}}{\emptyset} \times 100 %

(1)

\emptyset_{O} = 20.91 + 22.9 / S_{O}

(2)

where

φ_{c o}

represents the apparent compaction rate,

\emptyset_{O}

the primary porosity,

\emptyset_{c o}

the porosity after mechanical compaction, and

S_{0}

the Trask sorting coefficient, which is the ratio of the particle size at 25% to 75% of the cumulative particle size curve.

Apparent cementation rate

The apparent cementation rate, denoted as $φ_{c e}$ , is expressed as the ratio of the cemented pore volume to the uncemented pore volume after cementation. The $φ_{c e}$ exceeds 70%, indicates a state of strong cementation; between 30% and 70%, a moderate level of cementation; and below 30%, a state of weak cementation.

The formula for calculating $φ_{c e}$ is given by:

φ_{c e} = \frac{\emptyset_{O}}{\emptyset_{O} + \emptyset_{e}} \times 100 %

(3)

where $φ_{c e}$ represents the apparent cementation rate, $\emptyset_{O}$ the amount of cement, and $\emptyset_{c o}$ the intergranular pore volume.

Apparent dissolution rate

The apparent dissolution rate is employed to study the extent of reservoir alteration due to dissolution. The apparent dissolution rate, denoted as $φ_{d}$ , is expressed as the proportional relationship between the dissolution surface porosity and the total surface porosity (Wang et al., 2013). When $φ_{d}$ surpasses 70%, this indicates intense dissolution; between 30% and 70%, a moderate level of dissolution; and when $φ_{d}$ falls below 30%, weak dissolution is suggested.

The formula for calculating $φ_{d}$ is given by:

φ_{d} = \frac{S_{d}}{S_{t}} \times 100 %

(4)

where

φ_{d}

represents the apparent dissolution rate,

S_{d}

the dissolution surface porosity, and

S_{t}

the total surface porosity.

Visual microporosity

The visual microporosity, denoted as $φ_{m}$ , is expressed as the proportional relationship between the dissolution micropore volume and the total pore volume.

The formula for calculating $φ_{m}$ is expressed as:

φ_{m} = \frac{\emptyset - S_{t}}{\emptyset} \times 100 %

(5)

where

φ_{m}

represents the visual microporosity,

S_{t}

the total surface porosity, and

\emptyset

the porosity.

Diagenetic coefficient

Using $φ_{c o}$ , $φ_{c e}$ , $φ_{c d}$ , and $φ_{m}$ , we derive the diagenetic coefficient, denoted as K. This coefficient can quantitatively characterize the diagenetic facies and the impact of various diagenetic processes on pore volumes. A higher K suggests a greater influence of diagenesis in enhancing reservoir properties. It can serve as an effective parameter for quantitatively characterizing different diagenetic facies.

The formula for calculating K is given by:

K = \frac{\emptyset}{φ_{c o} + φ_{c e} + φ_{d} + φ_{m}}

(6)

where

\emptyset

represents the porosity,

φ_{c o}

the apparent compaction rate,

φ_{c e}

the apparent cementation rate, and

φ_{m}

the visual microporosity.

Results

Mineral compositions

The mineral compositions of tight sandstones in the LFD are primarily composed of quartz, feldspar, and detritus, alongside the presence of clay minerals, calcite, dolomite, and siderite (Table 2). Furthermore, the presence of illite-smectite mixed layers (I-S) in significant proportions indicates that the tight sandstone has reached a mesogenetic B stage.

Table 2.

Mineral composition of samples in the Lishu fault depression.

Sample	Quartz	Feldspar	Plagioclase	Calcite	Laumontite	Dolomite	Pyrite	Clay minerals
Sample	Quartz	Feldspar	Plagioclase	Calcite	Laumontite	Dolomite	Pyrite	Illite-smectite mixed layers	Illite	Kaolinite	Chlorite
Ls-1	35.9	1.7	16.8	0.90		0.60	0.90	9.53	18.67	1.91	8.00
Ls-2	48.1	0.7	29.5	4.5			0.3
Ls-3	45.0	3.4	26.3	12.1		0.30	0.80	1.55	5.37	0.73	1.46
Ls-4	45.7	4.6	25.3	0.3		1.20	0.10	4.03	8.05	1.58	3.85
Ls-5	29.3	12.8	29.5		21.9			3.46	1.92	0.26	0.77
Ls-6	58.4	2.9	27.2	0.6		0.30	0.10	0.97	6.32	0.24	0.57
Ls-7	55.1	5.8	21.8	0.7		0.70	0.70	2.19	5.04	0.57	1.71
Ls-8	34.5	0.6	32.1	1.3		0.20	0.10	3.98	5.71	1.38	6.23
Ls-9	27.6	14.4	43.4		7.7			1.93	3.52	0.35	1.10
Ls-10	35.3		52.1	2.6	1.6			2.24	4.57	0.33	1.16
Ls-11	17.4		29.8	2.4	41.9			1.70	3.97	0.65	1.78
Ls-12	29.3	11.6	38.6		13.2			4.39	1.22	0.36	1.22
Ls-13	35.5	13.1	39.1		7.1			1.78	3.02	0.11	0.43
Ls-14	28.4	14.7	34.2		17.3			3.14	1.79	0.17	0.5
Ls-15	21.9	9.6	39.7	5.8	17.2			1.82	3.02	0.34	0.51
Ls-16	68.3	5.5	18.4	2.6				2.62	0.62	0.44
Ls-17	42.8	5.3	23.3	2.5		1.00		3.70	0.62	1.36
Ls-18	51.4	7.4	24.9	1.3		2.20	0.10	5.33	3.04	4.31
Ls-19	56.8	6.1	21.0	3.5		2.20	0.10	5.35	2.98	1.95
Ls-20	48.3	6.2	24.5	2.3		5.10	0.10	6.21	4.72	2.565

Diagenesis

Diagenesis characteristics

The lower Cretaceous strata were subjected to mechanical compaction, cementation, dissolution, and metasomatism (Zhang et al., 2020). Mechanical compaction was predominantly observed during the initial stage, characterized by linear-concave contacts and the oriented arrangement of grains, accompanied by ductile deformation of particles (Figure 2(a)). Siliceous cement (Figure 2(b)), clay mineral cement (Figure 2(c) and (d)), carbonate cement (Figure 2(e)), and feldspar cement can be observed, leading to a reduction in porosity and pore connectivity. Dissolution of feldspar, calcite cement, and debris generated intergranular and intragranular pores, effectively improving the tight sandstone reservoir property. Moreover, secondary alteration of feldspar and calcite metasomatism of feldspar and debris can also be seen (Figure 2(h)).

Figure 2.

Photos showing diagenesis characteristics of tight sandstone samples in the Lishu (LS) fault depression. (a) Sample LS-1, compaction, plastic mineral deformed； (b) sample LS-15, siliceous cementation； (c) sample LS-5， illite and illite-smectite mixed layer cementation； (d) sample LS-4，clay minerals cementation； (e) sample LS-3, calcite cementation； (f) sample LS-10, dissolution pores and intergranular pores； (g) sample LS-20, dissolution, diagenetic fracture developed； (h) sample LS-8, calcite metasomatism； (i) sample LS-9, clastic particles and cements dissolved.

Diagenetic facies classification

Diverse diagenetic processes lead to distinct diagenetic facies. Given the absence of a commonly accepted standard for diagenetic facies, a classification scheme was employed based on the combination of diagenetic strength, mineral compositions, diagenetic type, and facies. Six diagenetic facies can be identified: the strong compaction with moderate cementation facies (SCMCF), weak dissolution with cementation facies (WDCF), moderate cementation with feldspar dissolution facies (MCFDF), moderate cementation with residual intergranular pore facies (MCRIPF), moderate cementation with fracture facies (MCFF), and moderate cementation with mixed dissolution facies (MCMDF) (refer to Table 3), can be identified.

Table 3.

Classification standard for identification of diagenetic facies including diagenetic assemblage, surface porosity, degree of diagenesis, reservoir space.

Diagenetic facies		Diagenetic assemblage	Surface porosity	Degree of diagenesis	Reservoir space
Cementation facie	Strong compaction with moderate cementation facies	Compaction, calcite cementation, clay minerals cementation, metasomatism, dissolution	<1%	Strong compaction, moderate cementation	Intragranular dissolution pore, intergranular pore
Cementation facie	Weak dissolution with cementation facies	Compaction, siliceous cementation, calcite cementation, clay minerals cementation, dissolution	<1%	Strong-moderate compaction, strong-moderate cementation, weak dissolution	Intragranular dissolution pore, intergranular pore
Monotype dissolution facie	Moderate cementation with feldspar dissolution facies	Compaction, siliceous cementation, calcite cementation, clay minerals cementation, dissolution	>1%	Strong-moderate compaction, moderate cementation, moderate dissolution	Intragranular dissolution pore, isolated intergranular micropores
Monotype dissolution facie	Moderate cementation with residual intergranular pore facies				Residual intergranular pore, enlarge intergranular dissolution pore
Fracture facie	Moderate cementation with mixed dissolution facies	Compaction, tectonic disruption, siliceous cementation, calcite cementation, clay minerals cementation, dissolution		Strong-moderate compaction, moderate cementation, moderate-strong dissolution	Enlarge intergranular dissolution pore, dissolution fracture
Mixed dissolution facie	Moderate cementation with mixed dissolution facies	Compaction, siliceous cementation, calcite cementation, clay minerals cementation, dissolution		Strong-moderate compaction, moderate-weak cementation, moderate-strong dissolution	Intragranular dissolution pore, enlarge intergranular dissolution pore, residual intergranular pore, isolated Micropores, dissolution fracture

Detailed diagenetic parameters are delineated in Table 4. The values of $φ_{c o}$ and $φ_{c e}$ for the SCMCF exceed 0.9, while $φ_{m}$ falls within the range of 0.3 to 0.6. Conversely, the parameters K, $\emptyset$ , k, $φ_{d}$ , and $S_{t}$ are observed to be below 0.3. For the WDCF, $φ_{c e}$ , $\emptyset$ , and $φ_{m}$ values are situated between 0.6 and 0.9, whereas K, $φ_{d}$ , $\emptyset$ , and k range from 0.3 to 0.6. In the case of MCFDF, $φ_{d}$ surpasses 0.9, with $S_{t}$ , $\emptyset$ , and $φ_{c o}$ ranging from 0.3 to 0.6. The MCRIPF presents $φ_{d}$ and $φ_{m}$ values > 0.6, while K and $\emptyset$ are between 0.3 and 0.6, and $φ_{c o}$ and $φ_{c e}$ are below 0.3. Furthermore, in the MCFF, K, $\emptyset$ , and $S_{t}$ exceed 0.6, whereas $φ_{c e}$ , $φ_{c o}$ , and $φ_{m}$ are found to be below 0.3. Lastly, for the MCMDF, K, $\emptyset$ , and $S_{t}$ exceed 0.9, while $φ_{m}$ , $φ_{c e}$ , and $φ_{c o}$ are observed to be below 0.3.

Table 4.

Parameters of specific diagenetic facies, including surface porosity $S_{t}$ (%), porosity $\emptyset$ (%), permeability k (×10⁻³μm²), apparent compaction rate $φ_{c o}$ (%), apparent cementation rate $φ_{c e}$ (%), apparent dissolution rate $φ_{d}$ (%), visual microporosity $φ_{m}$ (%), and diagenetic coefficient k (%).

Diagenetic facies	Sample	Surface porosity $S_{t}$ (%)	Porosity $\emptyset$ (%)	Permeability k (×10⁻³μm²)	Apparent compaction rate $φ_{c o}$ (%)	Apparent cementation rate $φ_{c e}$ (%)	Apparent dissolution rate $φ_{d}$ (%)	Visual microporosity $φ_{m}$ (%)	Diagenetic coefficient k (%)
Strong compaction with moderate cementation facies	Ls-1	0.69	0.7	0.0007	0.791	0.956	0.304	0.3	0.283
Strong compaction with moderate cementation facies	Ls-2	0.37	1.8		0.853	0.945	0.217	0.794	0.641
Weak dissolution with cementation facies	Ls-3	0.93	1.4	0.214	0.503	0.888	0.387	0.336	0.662
	Ls-4	0.54	6.7		0.549	0.859	0.519	0.919	2.353
	Ls-5	0.61	7.5	11.2	0.493	0.904	0.377	0.919	2.785
Moderate cementation with feldspar dissolution facies	Ls-6	2.05	2.5	0.00975	0.522	0.535	0566	0.18	1.386
	Ls-7	3.19	4	4.26	0.574	0.567	0.561	0.203	2.101
	Ls-8	2.65	4.6	2.98	0.552	0.632	0.506	0.424	2.176
Moderate cementation with residual intergranular pore facies	Ls-9	1.12	4.2	0.166	0.472	0.456	0.696	0.733	1.781
	Ls-10	1.83	4.5	0.283	0.431	0.491	0.443	0.593	2.299
	Ls-11	1.17	5.1	0.565	0.493	0.486	0.769	0.771	2.025
	Ls-12	1.29	5.5	0.677	0.384	0.458	0.574	0.765	2.521
	Ls-13	1.69	6.1	0.763	0.514	0.439	0.408	0.723	2.926
	Ls-14	1.36	6.4	5.4	0.561	0.492	0.537	0.786	2.865
	Ls-15	1.23	7.5	3.44	0.529	0.546	0.708	0.836	3.924
Moderate cementation with fracture facies	Ls-16	5.13	5.24	2.583	0.428	0.62	0.294	0.02	3.844
	Ls-17	4.36	7.278	0.263	0.428	0.618	0.411	0.401	3.931
	Ls-18	3.98	4.977	0.721	0.447	0.619	0.505	0.2	2.809
Moderate cementation with mixed dissolution facies	Ls-19	5.37	5.523	0.766	0.463	0.611	0.369	0.028	3.757
Moderate cementation with mixed dissolution facies	Ls-20	7.02	7.224	0.581	0.453	0.658	0.346	0.028	4.865

The strong compaction with moderate cementation facies

The SCMCF represents the comprehensive results of strong compaction, moderate cementation (calcite and clay minerals cements), metasomatism, and minimal dissolution effects. The parameters are as follows: $φ_{c o}$ at 82.19%, $φ_{c e}$ at 95.025%, $φ_{d}$ at 32.24%, $φ_{m}$ at 54.72%, and K at 0.462, $\emptyset$ at 1.25%, k at 0.0019 × 10⁻³μm², and $S_{t}$ at 0.53% (see Figure 3(a)). During the diagenesis processes, diagenetic compaction occurred alongside the cementation of clay minerals and calcite following the initial mechanical compaction. The cumulative effects of various diagenetic processes have compromised the reservoir quality, resulting in substantial tightness and negligible porosity.

Figure 3.

Photos show pore types of the tight sandstone reservoirs in the Lishu fault depression.

Weak dissolution with cementation facies

The WDCF represents the comprehensive results of moderate to strong compaction, moderate to strong cementation, and minimal dissolution processes. The parameters are as follows: $φ_{c o}$ at 51.52%, $φ_{c e}$ at 88.4%, $φ_{d}$ at 42.76%, $φ_{m}$ at 72.46%, K at 1.934, $\emptyset$ at 5.2%, and k at 5.707 × 10⁻³μm², and $S_{t}$ at 0.693% (refer to Figure 3(b)). The reservoirs were subjected to moderate to strong cementation following substantial compaction. The cementation exhibits significant diversity, predominantly characterized by illite and illite-smectite mixed-layer cements. Additionally, clay minerals are primarily responsible for occupying pore spaces through bridge plugging and pore filling. Furthermore, both siliceous and carbonate cements are observed within the matrix. The dissolution of potash feldspar and clay mineral cements occurs to a limited extent (Li et al., 2001). These diagenetic processes result in a severe reduction of porosity.

Moderate cementation with feldspar dissolution facies

The MCFDF represents the results of moderate to strong compaction, accompanied by moderate cementation and dissolution processes. The parameters are as follows: $φ_{c o}$ at 54.93%, $φ_{c e}$ at 57.81%, $φ_{d}$ at 54.42%, $φ_{m}$ at 26.88%, K at 1.888, $\emptyset$ at 3.7%, k at 2.417 × 10⁻³μm², and $S_{t}$ at 2.63% (refer to Figure 3(c)). The reservoir experienced moderate degrees of cementation and dissolution subsequent to moderate to strong compaction. These diagenetic processes significantly contribute to the increase of reservoir quality.

Moderate cementation with residual intergranular pore facies

The MCRIPF represents a holistic result of moderate to strong compaction, coupled with moderate cementation and dissolution processes. The parameters are as follows: $φ_{c o}$ at 48.34%, $φ_{c e}$ at 48.12%, $φ_{d}$ at 59.06%, $φ_{m}$ at 74.42%, K at 2.444, $\emptyset$ at 3.29%, k at 1.613 × 10⁻³μm², and $S_{t}$ at 1.384% (see Figure 3(d)). Various types of cement are filled in the pores, preserving residual intergranular porosity against significant compaction, while dissolution contributes to the formation of dissolution fractures and intergranular porosity. These comprehensive diagenesis processes are considered to play a constructive role in the reservoir quality.

Moderate cementation with fracture facies

The MCFF represents a comprehensive result of strong to moderate compaction, moderate cementation, tectonic disturbances, and moderate to strong dissolution processes. The parameters are as follows: $φ_{c o}$ at 43.42%, $φ_{c e}$ at 61.71%, $φ_{d}$ at 40.33%, $φ_{m}$ at 20.74%, K at 3.528, $\emptyset$ at 5.82%, k at 1.189 × 10⁻³μm², and $S_{t}$ at 4.49% (Figure 3(e)). The pore spaces were filled with cements and underwent significant to moderate compaction and tectonic disruption. As burial depth increased and hydrocarbon generation occurred, dissolution processes initiated the formation of particle fractures and dissolution fissures, as well as the development of localized microfracture networks. These diagenetic processes are significantly enhancing the reservoir quality characteristics.

Moderate cementation with mixed dissolution facies

The MCMDF represents a complex interplay of significant to moderate compaction, moderate to weak cementation, and moderate to strong dissolution processes. The parameters are as follows: $φ_{c o}$ at 45.8%, $φ_{c e}$ at 63.41%, $φ_{d}$ at 35.74%, $φ_{m}$ at 2.79%, K at 4.311, $\emptyset at$ 7.403%, k at 0.6735 × 10⁻³μm², and $S_{t}$ at 6.9% (Figure 3(f)). Cementation is effective in decreasing the pore space, thereby preserving intergranular voids that have experienced significant to moderate compaction. This process is complemented by dissolution activities that facilitate the formation of intragranular dissolution pores, the expansion of intergranular voids, and the generation of dissolution-induced fractures. The comprehensive diagenesis is considered to play a constructive role in the reservoir.

Diagenetic strength evaluation

To quantitatively evaluate the diverse diagenetic facies, the parameters are normalized, with the maximum and minimum values derived from all samples being designated as the upper and lower limits of the normalization process, respectively. The corresponding formula is given as follows:

\bar{x} = \frac{x_{i} - x_{m i n}}{x_{m a x} - x_{m i n}} (i = 1, 2, \dots)

(7)

Based on the provided formula (7),

x_{m a x}

and

x_{m i n}

represent the maximum and minimum values of the parameters, respectively. To study the normalized values across various diagenetic facies for the different parameters, we observe that after normalization, values are distributed as follows: a higher value is set at 0.9, the median at 0.6, and a lower value at 0.3. Additionally, it is noted that

\emptyset

, k,

φ_{d}

S_{t}

, and K display greater values while

φ_{c o}

φ_{c e}

, and

φ_{m}

assumes smaller values, indicative of favorable diagenetic facies.

The cementation facies (SCMCF and WDCF) are characterized by a high degree of compaction and cementation, resulting in poorly developed pores and relatively tight reservoirs, which are considered unfavorable diagenetic facies. In contrast, the parameters of monotype dissolution facies (MCFDF and MCRIPF) are indicative of their classification as moderate diagenetic facies. The fracture facies (MCFF) and mixed dissolution facies (MSMDF) are found to exhibit favorable diagenetic characteristics, with well-developed porosity, favorable diagenesis, and minimal compaction and cementation (Figure 4).

Figure 4.

Spider diagram showing diagenetic parameter for diagenesis facies.

Microscopic pore characteristics of diagenetic facies

Pore types

The reservoir space of the samples in this article is characterized by pores and microfractures. Pore types are classified into both primary and secondary pores (Hao et al., 2013). The primary pores are predominantly composed of intergranular pores and residual pores, while the secondary pores are represented by intragranular dissolution pores and intergranular dissolution pores. Specifically, the former is composed of particle dissolution pores and debris dissolution pores, while the latter is primarily characterized by enlarged dissolution intergranular pores and cement dissolution pores. Microfractures include tectonic and diagenetic fractures, which comprise dissolution fractures and fractures associated with encircling particles (Figure 3). These fractures are distributed heterogeneously through various formation mechanisms (Lionel et al., 2006). Overall, complex microscopic pore structure characteristics are presented by the samples.

Pore structure characteristic

The transformation of pore structures from micro-intragranular dissolution pores to micro–meso intergranular pores is achieved through the processes of cementation and subsequent dissolution. This phenomenon is corroborated by observations made from thin-section analyses and SEM. Concurrently, both the expulsion pressure and mercury extrusion efficiency are observed to exhibit a progressive increase, indicating a deterioration from dissolution facies to cementation facies. This trend underscores the increasing difficulty of mercury permeation into the pore spaces.

HPMI experiments were performed to analyze the pore structure of the samples (Table 5). The HPMI and extrusion curves derived for various diagenetic facies are used to characterize the microscopic pore structure across the different diagenetic conditions (Tang et al., 2006; Zhao et al., 2014). The results of the HPMI experiments exhibit variability among the samples from distinct diagenetic facies. Generally, the maximum mercury saturation ( $S_{m a x}$ ) of the samples ranges between 70% and 100%, while the mercury displacement pressure ( $P_{d}$ ) for cementation facies (SCMCF and WDCF) samples is observed to range from 20 to 30 MPa, with a mercury extrusion efficiency ( $W_{e}$ ) exceeding 50%. These findings suggest a relatively low degree of reservoir heterogeneity coupled with favorable pore-throat connectivity. Conversely, the $P_{d}$ of dissolution facies samples fluctuate between 0.1 and 1 MPa, and the $W_{e}$ is <50%, indicative of obvious reservoir heterogeneity and low pore-throat connectivity.

Table 5.

HPMI results and parameters of the tight sandstone samples in the Lishu fault depression.

Sample	Pore volume $V_{p}$ (ml)	Median pressure $P_{50}$ (mpa)	Median radius $r_{50}$ (μm)	Maximum radius of connection $r_{m a x}$ (μm)	Maximum mercury saturation $S_{m a x}$ (%)	Mercury extrusion efficiency $W_{e}$ （%）
LS-1	0.0042	215.034	0.003	0.026	100	93.08
LS-2	0.0778	153.884	0.005	0.033	100	80.6
LS-3	0.062	10.052	0.073	4.868	100	71.82
LS-4	0.3049	20.266	0.036	4.623	100	66.75
LS-5	0.3451	6.088	0.121	4.773	100	60.53
LS-6	0.1032	6.486	0.113	0.849	100	50.76
LS-7	0.1896	2.451	0.3	4.682	100	62.2
LS-8	0.2389	4.718	0.156	4.747	100	70.26
LS-9	0.1865	5.7295	0.128	2.722	84.869	6.817
LS-10	0.1896	21.0091	0.035	2.723	73.345	6.948
LS-11	0.1242	6.1125	0.12	2.723	80.999	54.783
LS-12	0.1077	7.7617	0.095	2.723	72.812	39.497
LS-13	0.1494	2.6779	0.275	2.722	78.399	19.609
LS-14	0.1736	1.424	0.516	6.312	87.268	43.092
LS-15	0.1069	2.7144	0.271	6.312	73.868	41.029
LS-16	0.1656	6.305	0.1	5.662	99.999	32.313
LS-17	0.1352	37.53	0.017	5.66	99.999	33.876
LS-18	0.172	2.917	0.214	5.666	99.999	30.673
LS-19	0.2137	5.603	0.112	5.661	99.999	36.678
LS-20	0.2718	1.091	0.579	5.66	99.999	31.674

HPMI: high-pressure mercury intrusion.

The mercury intrusion and extrusion curves for the various diagenetic facies are found to exhibit discrepancies and can be subdivided into three types. Type Ⅰ (SCMCF, as seen in Figure 5(a)) curves are characterized by no horizontal stages, and the curves are very steep throughout most of the mercury intrusion process, with only a slight reduction observed when approaching maximum mercury saturation. A displacement pressure larger than 10 MPa is found in most of the samples of this type. The mercury extrusion curves are slightly separated from the intrusion curves, indicating high mercury extrusion efficiency. The pore sizes and connectivity are considered to be better than those of the other two types. Type Ⅱ (WDCF, MCFDF, and MCMDF, as seen in Figure 5(b), (c), and (f)) curves show no relatively horizontal stage. The displacement pressure of samples of this type is found to be very small (around 0.1 MPa). The mercury extrusion curves are separated from the intrusion curves, indicating relatively high mercury extrusion efficiency. Type Ⅲ (MCRIPF and MCFF, as seen in Figure 5(d) and (e)) curves exhibit a comparatively horizontal stage during the early period of mercury intrusion with a relatively large slope. The displacement pressure of samples of this type is generally found to be between 8 and 70 MPa. The mercury extrusion curves are obviously separated from the intrusion curves, indicating very low mercury extrusion efficiency.

Figure 5.

High-pressure mercury intrusion and extrusion of different diagenetic facies in the Lishu fault depression.

In summary, the transition from micro-intragranular dissolution pores to micro–meso intergranular pores and ultimately to mixed pores and fractures is observed to occur from cementation to dissolution facies. This observation is aligned with the results obtained from thin-section analyses and SEM. Additionally, the extrusion pressure and extrusion efficiency are progressively enhanced, correlating with a degradation in conditions from dissolution facies to cementation facies, thereby reflecting the increasing difficulty of mercury intrusion into the pore spaces.

Pore size distribution

The pore size distributions across various diagenetic facies samples are plotted in Figure 6, with distinct diagenetic facies being shown to exhibit various characteristics in pore size distributions. A decrease trend in the pore throat sizes of the SCMCF sample (Figure 6(a)) is demonstrated, with micropores predominantly consisting of elevated mercury saturation. Furthermore, the range of pore size distribution is extended from 0.001 to 80 μm.

Figure 6.

Plots of pore size distribution of different diagenetic facies in the Lishu fault depression.

The pore throat sizes of the WDCF sample (Figure 6(b)) are initially shown to exhibit a decreasing trend, followed by a subsequent peak; the pores are predominantly classified as micropores and mesopores, with a few macropores. In contrast, the MCFDF (Figure 6(c)) and MCRIPF (Figure 6(d)) samples are characterized by a monomodal pore size distribution. These samples are primarily constituted of micropores and mesopores, while the MCRIPF samples are predominantly mesoporous. The MCFF and MCMDF samples are observed to display a bimodal pore size distribution, with significant heterogeneity being noted in both diagenetic facies. Specifically, the MCFF samples (Figure 6(e)) are composed of micropores and fractures, whereas the MCMDF samples (Figure 6(f)) are found to contain a combination of micropores, mesopores, and fractures.

The mercury saturation within fractures is noted to be the highest, with a significant peak value being attained. Analytical results indicate that the pore size distribution of reservoir samples is crucially regulated by diagenetic facies. Specifically, pore development in cementation facies is comparatively limited, with micropores being predominantly comprised, and single-peak characteristics being exhibited with a relatively small proportion of peak value. Conversely, pores within single dissolution facies are comparatively well-developed and uniform, with micropores and mesopores being primarily consisted, and the peak value accounting for a substantial proportion. Furthermore, significant disparities are observed in the pore development of multitype dissolution facies, which are characterized by a mixture of various pore types, displaying bimodal characteristics, marked polarization, and a substantial proportion of fracture peaks.

Fractal dimensions

When the pore structure exhibits fractal characteristics, a function relationship exists between the wetting phase saturation and capillary pressure.

S_{W} = {(\frac{P_{c}}{P_{m i n}})}^{D - 3}

(8)

In the formula,

P_{c}

is the capillary pressure corresponding to pore radius, MPa;

P_{m i n}

the minimum capillary pressure linked to the maximum pore radius (

r_{m a x}

);

S_{W}

the wetting phase saturation aligned with the

P_{c}

; and D the fractal dimension of pore structure.

The logarithm of equation (8) is obtained:

\lg S_{W} = (3 - D) l g P_{m i n} + (D - 3) \lg P_{c}

(9)

According to equation (9), if the pores exhibit fractal characteristics, a linear correlation can be observed between

l g S_{W}

and

l g P_{c}

, with the slope of the straight-line being D–3, thereby determine the fractal dimension (D) (Hao et al., 2013; Zhang et al., 2020). This linear relationship suggests a diverse fractal property within the pore system.

The fractal dimension (D) can be calculated as follows:

D = \frac{(D_{p - 1} \emptyset_{1} + D_{p - 2} \emptyset_{2} + D_{p - 3} \emptyset_{3})}{\emptyset_{1} + \emptyset_{2} + \emptyset_{3}}

(10)

In the formula,

D_{p - 1}

is the fractal dimension of macropores,

D_{p - 2}

the fractal dimension of mesopores,

D_{p - 3}

the fractal dimension of micropores,

\emptyset_{1}

the porosity of macropores,

\emptyset_{2}

the porosity of mesopores, and

\emptyset_{3}

the porosity of micropores. The quantitative classification of micropores (<100 nm), mesopores (100–1000 nm), and macropores (>1000 nm) is calculated from mercury intrusion curves (Zhang et al., 2017).

For the SCMCF, $D_{p - 1}$ is 2.99, $D_{p - 2}$ is 2.98, $D_{p - 3}$ ranges from 2.57 to 2.65, and D ranges from 2.60 to 2.68 (Figure 7(a)), indicating that the structures of macropores and mesopores, predominantly residual intragranular dissolution pores, exhibit a notable degree of complexity. Conversely, the micropore structure is comparatively homogeneity, primarily characterized by isolated intergranular micropores.

Figure 7.

Fractal dimensions derived from high-pressure mercury intrusion (HPMI) data of tight sandstones in the Lishu fault depression.

For WDCF, $D_{p - 1}$ ranges from 2.94 to 2.97, $D_{p - 2}$ ranges from 2.79 to 2.85, $D_{p - 3}$ ranges from 2.49 to 2.67, and D ranges from 2.68 to 2.77 (Figure 7(b)). In the case of MCFDF, $D_{p - 1}$ spans from 2.93 to 2.99, $D_{p - 2}$ ranges from 2.70 to 2.75, $D_{p - 3}$ varies from 2.55 to 2.57, and D ranges from 2.63 to 2.73 (Figure 7(c)). For both WDCF and MCFDF, a trend is observed in which the smaller the pore size, the greater the complexity and heterogeneity of the pore structure.

For the MCRIPF, $D_{p - 1}$ ranges from 2.93 to 2.99, $D_{p - 2}$ spans from 2.54 to 2.80, $D_{p - 3}$ varies between 2.77 and 2.99, and D falls within the range of 2.62 to 2.83 (Figure 7(d)). It is indicated by these measurements that the pore structure of macropores is intricate, with residual intergranular pores and enlarged intergranular dissolution pores being predominantly comprised. A degree of similarity is exhibited in the fractal characteristics of mesopores and micropores; however, the uniformity of porosity is considered inferior when compared to other diagenetic facies samples.

In the case of MCFF, $D_{p - 1}$ ranges from 2.91 to 2.95, $D_{p - 2}$ spans from 2.88 to 2.96, $D_{p - 3}$ varies from 1.82 to 2.15, and D is observed to range from 2.18 to 2.56 (Figure 7(e)). It is suggested by these findings that both the macropore and mesopore structures are complex, uneven, and exhibit high tortuosity. The pore architecture is primarily characterized by dissolution fractures along particle margins and dissolution macropores. Notably, the distribution of micropores is considered more homogeneous than that of the previously mentioned diagenetic facies, with isolated micropores being primarily comprised and uniformly distributed within localized regions.

For MCMDF, $D_{p - 1}$ ranges from 2.90 to 2.93, $D_{p - 2}$ spans from 2.76 to 2.85, $D_{p - 3}$ varies between 1.97 and 2.12, and D falls within the range of 2.43 to 2.60 (Figure 7(f)). It is observed that the pore structure of these diagenetic facies is analogous to that of the MCFF samples; however, greater uniformity is exhibited by the mesopore architecture, whereas the micropore structure is notably more complex. This complexity is primarily attributed to the diverse types of reservoir spaces present within the diagenetic facies and the interrelationship among various pore types.

In general, it is observed that the fractal dimensions of fracture facies and mixed dissolution facies are lower than those of other diagenetic facies. This suggests that the pore structure within fracture facies and mixed dissolution facies is relatively heterogenetic. Conversely, greater heterogeneity is characterized in the pore structure of cemented and monotype dissolution facies. The fractal properties of samples from WDCF, MCFDF, MCRIPF, and MCMDF are evident, indicating that various pore types possess relatively complex pore structures. In contrast, the fractal characteristics of macropores and mesopores in SCMCF and MCFF are less pronounced, suggesting that pore-fracture assemblages are predominantly present in the MCFF.

Discussion

Influence of diagenesis on pore structure

Relationship between minerals and pore structure parameters

Figure 8 illustrates the relationship between the mineral compositions of samples with varying diagenetic facies and their pore structure parameters. The pore structure in SCMCF and MCMDF is primarily influenced by quartz and feldspar, while the pore volume and size in WDCF are also notably affected by these minerals. The pore volume of SCMCF and MCMDF is predominantly impacted by clay minerals and carbonates, which contribute to increased pore complexity. Conversely, the pore volume in MCFDF is primarily influenced by quartz and clay minerals, while the independence of pores is effectively reduced by carbonates, enhancing pore fractal dimensions. In WDCF, the pore radius is diminished by clay minerals and carbonate cements, thereby increasing pore heterogeneity and complexity. Additionally, localized metasomatic alterations within carbonate minerals of WDCF result in an enhancement of both pore volume and pore size, contributing to increased reservoir porosity. The development of pores and fractures in MCFF is significantly affected by the fracturing and dissolution of clay minerals and carbonate cements.

Figure 8.

Correlations between pore structure parameters and mineral compositions.

Given the properties of rigid, plastic, and soluble minerals, distinct influences on pore structure are exerted by each mineral type. Quartz, being a rigid mineral, has a limited contribution to pore development, specific surface area, and pore volume. The fractal dimension of the pore structure is positively correlated with specific pore surface area and pore volume. Adsorption capabilities of clay minerals, which vary according to the diagenetic stage, are considered to significantly affect comparative surface areas (Sun et al., 2017). A higher specific surface area is found in the illite/smectite mixed layer compared to chlorite, resulting in an increase in mineral surface roughness, which in turn enhances pore complexity and reduces uniformity. The formation of nanoscale pores, such as interlayer pores, is thus facilitated (Zhang et al., 2017).

Relationship between diagenesis coefficient and pore structure parameters

The diagenesis coefficient (DC) can be defined as an indicator of diagenetic intensity, where a higher DC is associated with a more favorable diagenetic process and improved reservoir quality. It is understood that the pore structure is intrinsically linked to the DC, with variations in diagenetic intensity and facies potentially leading to different reservoir characteristics. The relationship between the diagenetic coefficient and pore structure parameters across different diagenetic facies is illustrated in Figure 9. Specifically, in the cementation facies (SCMCF and WDCF), a positive correlation is exhibited between the diagenetic coefficient and both porosity and permeability. This implies that a higher diagenetic coefficient is associated with more well-developed pores, enhanced reservoir storage and permeability, and lower pore heterogeneity. Conversely, diagenetic facies characterized by lower diagenetic coefficients often exhibit a higher volume fraction of illite and local occurrences of kaolinite and chlorite. The presence of significant amounts of alkaline ions during diagenesis results in illite predominantly being found as thin sheets, compared to the more needle-like or lamellar forms, with lower illite crystallinity similar to chlorite. These chlorite films, which are mainly adhered to quartz and feldspathic surfaces, can effectively inhibit secondary particle growth and prevent further compaction-induced damage to primary pore structures (Sun et al., 2017; Zhang et al., 2017).

Figure 9.

Correlations between diagenetic coefficient and pore structural parameters.

In the monotype dissolution facies (MCFDF, MCRIPF), the diagenetic coefficient is found to be positively correlated with porosity, permeability, fracture size, and median pore radius. This indicates that a higher diagenetic coefficient is associated with more developed and larger pores, a more complex pore structure, and intensified pore heterogeneity, resulting in a reservoir that is more capable in terms of storage and seepage. The comprehensive effects of kaolinite, carbonate, and siliceous cementation filling primary and secondary pores lead to a decrease in reservoir pore volume, thereby reducing fluid permeability. The late-stage dissolution of cement, feldspar particles, and other debris primarily results in monotype dissolution. In MCFF, the diagenetic coefficient is found to be positively correlated with porosity, but negatively correlated with fracture size and median radius. This suggests that a higher diagenetic coefficient is associated with more developed pores, enhanced pore independence, and increased pore heterogeneity. For MCMDF, the diagenetic coefficient is shown to exhibit positive correlations with porosity, fracture size, and negative correlations with permeability. This implies that a higher diagenetic coefficient is correlated with more developed and larger pores, a more complex pore structure, and reduced pore heterogeneity.

Differential diagenetic pore evolution model

The research demonstrates that tight sandstone reservoirs have undergone a sequence of diagenetic processes that significantly affect pore development, including compaction, cementation, and dissolution, through thin section observation, SEM + EDS, and XRD analyses. These processes are considered crucial in controlling reservoir characteristics. Pronounced variations in diagenetic processes within the study area are led by differences in burial depth and diagenetic conditions. Based on the diagenetic processes, diagenetic coefficients, pore structure parameters, and the evolution of different diagenetic facies, six distinct diagenetic facies are proposed in this study (Figure 10) to elucidate the impact of various diagenetic processes on porosity evolution and to clarify the role of differential diagenesis in controlling pore structure (Ren et al., 2020). The effects of acidic or alkaline waters have been emphasized in traditional diagenetic studies, where dissolution processes and the formation of secondary porosity are associated. Secondary porosity is often attributed to the dissolution of carbonate minerals induced by acid fluids. In the study area, alkaline formation water is identified as the primary fluid in the reservoirs, leading to the widespread dissolution of feldspar and carbonate cements, which can be observed in almost all samples. Minimal pore development is exhibited by the SCMCF, as a result of the combined effects of compaction and cementation. Only a few small dissolution pores are present in the WDCF, following significant compaction and cementation. In the MCFDF, relatively homogeneous pore distribution is observed, resulting from extensive compaction and cementation, with reduced pore volume and notable feldspar dissolution. Primary pores were filled by carbonate cements, clay minerals, and other cements in early diagenesis, leading to the formation of residual pores in the middle to late stages. As burial depth and temperature increase, organic acids and various acidic hydrocarbons are released into sandstone reservoirs along fractures and connected pore systems, altering the surrounding chemical diagenetic conditions. Vigorous dissolution of feldspar, debris, kaolinite, and calcareous cements along grain boundaries results in the creation of numerous dissolution pores. The MCRIPF, cemented by carbonate cements and clay minerals, exhibits complex residual intergranular pores with low connectivity and significant heterogeneity. Tectonic fractures in the MCFF were formed early due to compaction and tectonism, followed by dissolution, which created a microfracture network. The MCMDF, influenced by soluble minerals and cementation after compaction, displays a coexistence of various pore types and complex pore structures.

Figure 10.

Pore structure evolution model of different diagenetic facies in the Lishu fault depression.

Conclusions

The lower Cretaceous tight sandstone reservoirs within the LFD experienced four primary diagenetic processes: compaction, cementation, dissolution, and metasomatism, indicating the intermediate diagenetic B to late diagenetic stages. The reservoirs are further classified into six distinct diagenetic facies: SCMCF, WDCF, MCFDF, MCRIPF, MCFF, and MCMDF.

The diagenetic coefficient and mineral composition are critical determinants of pore structure. An analysis of diagenetic parameters reveals that the diagenetic coefficient and mineral composition are critical determinants of pore structure. Specifically, the SCMCF and WDCF represent unfavorable diagenetic facies. MCFDF and MCRIPF are categorized as moderate diagenetic facies. Conversely, MCFF and MSMDF are considered as favorable diagenetic facies.

The pore size distributions across various diagenetic facies exhibit various characteristics. The HPMI results exhibit variability, the SCMCF and WDCF suggest a relatively low degree of reservoir heterogeneity, Conversely, MCFDF, MCRIPF, MCFF, and MCMDF indicative of obvious reservoir heterogeneity and low pore-throat connectivity. The fractal properties of the WDCF, MCFDF, MCRIPF, and MCMDF are obvious, indicating relatively complex pore structures.

The pore evolution model with different diagenetic facies can be established. The SCMCF and WDCF show few pores due to the combined effects of extensive compaction, cementation, and minor dissolution. The MCFDF displays a homogeneous distribution of micropores, subjected to significant compaction and cementation processes. The MCRIPF reservoir is distinguished by cementation, resulting in heterogenetic pore structure. The MCMDF reservoir features a variety of pore types and complex pore structures.

Footnotes

Acknowledgements

The authors would like to express their sincere thanks to the editors and reviewers, whose suggestions significantly improved the quality of this article.

Declaration of conflicting interests

The authors declared no potential conflicts of interest with respect to the research, authorship, and/or publication of this article.

Funding

The authors disclosed receipt of the following financial support for the research, authorship, and/or publication of this article: This work was supported by the Sinopec Ministry of Science and Technology Basic Prospective Research Project (grant number No. P22084).

References

(2020) Characteristics of overpressure and its influence on diagenesis of Cretaceous Yingcheng Formation-Shahezi Formation in Lishu fault depression, Songliao Basin. Journal of Northeast Petroleum University 44(01): 65–76.

Becker

Wustefeld

Koehrer

, et al. (2017) Porosity and permeability variations in a tight gas sandstone reservoir analogue, Westphalian D, Lower Saxony Basin, NW Germany: Influence of depositional setting and diagenesis. Journal of Petroleum Geology 40: 363–389.

Chalmers

Bustin

Power

(2012) Characterization of gas shale pore systems by porosimetry pycnometry surface area and field emission scanning electron microscopy/transmission electron microscopy image analyses: Examples from the Barnett Woodford Haynesville Marcellus and Doig units. AAPG Bulletin 96(6): 1099–1119.

Civitelli

Ravida

DCG

Borrelli

, et al. (2023) Diagenesis and petrophysics of Miocene sandstones within southern Apennines foreland, Italy. Marine and Petroleum Geology 155: 106411.

Critelli

Reed

(1999) Provenance and stratigraphy of the Devonian (Old Red Sandstone) and Carboniferous sandstones of Spitsbergen, Svalbard. European Journal of Mineralogy 11: 149–166.

Cui

Wang

Jones

, et al. (2017) Prediction of diagenetic facies using well logs—a case study from the upper Triassic Yanchang Formation, Ordos Basin, China. Marine and Petroleum Geology 81: 50–65.

Curtis

Sondergeld

Ambrose

, et al. (2012) Microstructural investigation of gas shales in two and three dimensions using nanometer-scale resolution imaging. AAPG Bulletin 96(4): 665–677.

Fang

Zhao

, et al. (2024) Diagenetic evolution of tight sandstone and the formation of an effective reservoir in the lower member 3 of the Shahejie Formation, Bohai Bay Basin, East China. Marine and Petroleum Geology 161: 106658.

Gao

Wang

Fan

, et al. (2015) Quantitative classification and characteristics of diagenetic facies of sandstones in the 2nd member of the Shenmu Gas Field, Ordos Basin. Natural Gas Geoscience 26(06): 1057–1067.

10.

Hao

Wang

Tang

(2013) A review on the research methods and theories of microscopic pore structure of reservoir rocks. Lithologic Reservoirs 25(05): 123–128.

11.

Zhu

, et al. (2018) Profitable exploration and development of continental tight oil in China. Petroleum Exploration and Development 45: 790–802.

12.

Lai

Wang

Chai

, et al. (2016) . Prediction of diagenetic facies using well logs: Evidences from upper Triassic Yanchang formation Chang 8 Sandstones in Jiyuan Region, Ordos Basin, China. Oil Gas Science and Technology—Revue d'IFP Energies Nouvelles 71: 34.

13.

Lai

Wang

Huang

, et al. (2015) Quantitative classification of diagenetic facies and its logging identification method for tight sandstone reservoirs. Bulletin of Mineralogy, Petrology and Geochemistry 34(1): 128–138.

14.

Guo

Qiu

(2001) Diagenesis and division of diagenetic phases of the reservoirs in the north Weifang Oil Field. Sedimentary Geology and Tethyan Geology 21(4): 28–33.

15.

Lionel

Yves

Jean

(2006) Pore network geometry in low permeability argillites from magnetic fabric data and oriented mercury intrusions. Geophysical Research Letters 33(18).

16.

Loucks

Reed

Ruppel

, et al. (2012) Spectrum of pore types and networks in mudrocks and a descriptive classification for matrix-related mudrock pores. AAPG Bulletin 96(6): 1071–1098.

17.

Qiao

Zeng

Chen

, et al. (2022) Permeability estimation of tight sandstone from pore structure characterization. Marine and Petroleum Geology 135: 105382.

18.

Ren

Sun

, et al. (2020) The impacts of diagenetic facies on reservoir quality in tight sandstones. Open Geosciences 12(1): 1060–1082.

19.

Shen

Ruan

, et al. (2022) Characteristics of pore systems in the oil-bearing sandstones of the Dongying Depression, Bohai Bay Basin. Journal of Petroleum Science and Engineering 218: 111031.

20.

Shi

Wang

Xing

, et al. (2024) Geological characteristics of unconventional tight oil reservoir (109 t): A case study of Upper Cretaceous Qingshankou Formation, northern Songliao Basin, NE China. China Geology 7: 51–62.

21.

Sun

Lin

Dong

, et al. (2017) Effect of chlorite on siliceous cementation under reservoir lithology control. Earth Science 42(9): 1599–1607.

22.

Tang

Peng

Zhao

(2006) Microscopic pore structure characteristics and classification evaluation of tight sandstone reservoirs in Member he 2 + 3 of Daniudi Gas Field. Journal of Mineralogy and Petrology 03: 107–113.

23.

Taylor

Giles

Hathon

, et al. (2010) Sandstone diagenesis and reservoir quality prediction: Models, myths, and reality. AAPG Bulletin 94: 1093–1132.

24.

Vafaie

Kivi

Moallemi

, et al. (2021) Permeability prediction in tight gas reservoirs based on pore structure characteristics: A case study from South Western Iran. Unconventional Resources 1: 9–17.

25.

Wang

Mou

(2013) Reservoir diagenesis and diagenetic facies of he8 member, eastern 2 block, Sulige Gas Field. Natural Gas Geoscience 24(04): 678–689.

26.

Wang

Cheng

Wang

, et al. (2011) Sequence stratigraphy and sedimentary system of Yingcheng formation in Shiwu Oil Field of Lishu fault depression, Songliao Basin. World Geology 30(04): 631–640.

27.

Wang

Zhou

, et al. (2023) Diagenesis as a control on the tight sandstone reservoir quality of the upper Carboniferous strata in the northeastern Ordos basin, China. Marine and Petroleum Geology 158: 106565.

28.

Zhang

Jiang

Sun

, et al. (2019) A multiscale comprehensive study on pore structure of tight sandstone reservoir realized by nuclear magnetic resonance, high pressure mercury injection and constant-rate mercury injection penetration test. Marine and Petroleum Geology 109: 208–222.

29.

Zhang

Liao M

Yao J

, et al. (2017) Authigenic mineral characteristics and its effect on reservoir performance of tight sandstone reservoirs: A case study of Chang 3 oil formation in Longdong area, Ordos Basin. Sedimentary Geology and Tethyan Geology 37(3): 22–31.

30.

Zhang

Liu

, et al. (2020) Pore structure and fractal characteristics of ultra-low permeability reservoir of Yanchang Formation in Zhenbei area, Ordos Basin. Petroleum Geology and Recovery Efficiency 27(03): 20–31.

31.

Zhang

Pe-Piper

Piper

DJW

(2015) How sandstone porosity and permeability vary with diagenetic minerals in the Scotian Basin, offshore eastern Canada: Implications for reservoir quality. Marine and Petroleum Geology 63: 28–45.

32.

Zhao

Liu

Xie

, et al. (2014) Microscopic pore-throat structure classification of Chang 7 tight oil reservoir in Jiyuan Oil Field, Ordos Basin. China Petroleum Exploration 19(05): 73–79.

33.

Zou

Tao

Zhou

, et al. (2008) Genesis, classification, and evaluation method of diagenetic facies. Petroleum Exploration and Development 35: 526–540.

34.

Zou

Zhu

, et al. (2012) Types, characteristics, genesis and prospects of conventional and unconventional hydrocarbon accumulations: Taking tight oil and tight gas in China as an instance. Acta Petrolei Sinica 33: 173–187.