Pore-throat structures of the Permian Longtan Formation tight sandstones in the South Yellow Sea Basin, China: A case study from borehole CSDP-2

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

Contents lists available at ScienceDirect

Journal of Petroleum Science and Engineering journal homepage: http://www.elsevier.com/locate/petrol

Pore-throat structures of the Permian Longtan Formation tight sandstones in the South Yellow Sea Basin, China: A case study from borehole CSDP-2 Laixing Cai a, b, c, Xingwei Guo b, c, *, Xunhua Zhang b, c, Zhigang Zeng a, c, **, Guolin Xiao b, c, Yumao Pang c, Shuping Wang d a

Key Laboratory of Marine Geology and Environment, Institute of Oceanology, Chinese Academy of Sciences, Qingdao 266071, China Qingdao Institute of Marine Geology, China Geological Survey, Qingdao 266071, China Laboratory for Marine Mineral Resources, Pilot National Laboratory for Marine Science and Technology (Qingdao), Qingdao 266237, China d Oil Industry Training Center, China University of Petroleum (East China), Qingdao 266580, China b c

A R T I C L E I N F O

A B S T R A C T

Keywords: Pore-throat structure Reservoir quality Formation mechanism Tight sandstone Longtan formation Borehole CSDP-2 South Yellow Sea Basin

With good exploration prospects and proven source rocks in Permian, reservoir evaluation has become the main bottleneck hindering petroleum exploration in the South Yellow Sea Basin, China, where the pore-throat structures, which are particularly important for the reservoir quality of tight sandstones, have never been characterized. To solve this, tight sandstones taken from borehole CSDP-2 of the Permian Longtan (P2l) For­ mation were systemically investigated with high-precision pore-throat characterization methods. The results show that pore-throat structures of tight sandstones in the Longtan Formation can be classified into three cat­ egories with synthesis considerations of pore-throat type, size, and connectivity; these pore-throats are denoted lattice-like, tubular, and isolated, respectively. The lattice-like pore throats with relatively larger radii (>0.1 μm) and higher connectivity exhibit the best performance for reservoir quality, followed by tubular pore-throat structures, while isolated pore throats have almost no capacity to migrate or store fluids. In the formation mechanism of various pore-throat structures, both the plastic component content and complex diagenesis play a significant role. Strong compaction results in a loss of nearly half of the initial porosity (av. 49.81%) during the initial diagenetic stage. Then, clay mineral cements partially occlude pores and throats, which are the dominant factors in the transition of pore-throat structures from lattice-like to tubular. Silica and carbonate cementation are the key processes that fill the primary pore throats, secondary dissolution pores, and microfractures, leading to the formation of isolated pore-throat structures and low-porosity, ultra-low-permeability reservoirs. Feldspar dissolution cannot take place on a large scale due to the early densification of the sandstone, and it does not significantly improve the reservoir quality; it increases the porosity by less than 4.0%. This research provides constructive insights into the coupled evolution of pore-throat structures and diagenetic processes, which can aid in further understanding the formation mechanism of tight sandstones. In practice, this work also provides a scientific basis for identifying effective reservoirs, and promotes petroleum exploration in the South Yellow Sea Basin, China.

1. Introduction In this century, tight sandstone reservoirs have drawn considerable attention from the petroleum industry (Zou et al., 2012b; Arthur and Cole, 2014; Wang et al., 2016). They are also widely distributed in Chinese basins (Zhu et al., 2012; Jia et al., 2012; Zou et al., 2013; Xu et al., 2017). Tight sandstones, which generally require fracturing and production from horizontal wells, are defined as reservoirs with porosity

of less than 10.0% and intrinsic permeability of less than 0.1 mD, or air permeability of less than 1.0 mD (Zou et al., 2012b; Albrecht and Rei­ tenbach, 2015), with pores and throats ranging from nano-to micro-­ scale with complex and poor connectivity (Nelson, 2009; Rezaee et al., 2012; Xi et al., 2016; Rahner et al., 2018; Lai et al., 2018a). The reservoir quality of tight sandstones, such as storage capacity and percolation ability, is mainly controlled by the pore-throat structure rather than total porosity and permeability (Sakhaee-Pour and Bryant, 2014;

* Corresponding author. Qingdao Institute of Marine Geology, China Geological Survey, Qingdao 266071, China. ** Corresponding author. Key Laboratory of Marine Geology and Environment, Institute of Oceanology, Chinese Academy of Sciences, Qingdao 266071, China. E-mail addresses: [email protected] (X. Guo), [email protected] (Z. Zeng). https://doi.org/10.1016/j.petrol.2019.106733 Received 24 May 2019; Received in revised form 18 October 2019; Accepted 20 November 2019 Available online 25 November 2019 0920-4105/© 2019 Elsevier B.V. All rights reserved.

Please cite this article as: Laixing Cai, Journal of Petroleum Science and Engineering, https://doi.org/10.1016/j.petrol.2019.106733

L. Cai et al.

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

Schmitt et al., 2015; Xi et al., 2015; Li et al., 2017). In addition, the quantity of throats with relatively large radius is the dominant factor affecting the permeability of tight sandstone reservoirs (Xi et al., 2015). Only by detailed characterization of pore-throat structures, and inves­ tigation of their origin mechanism, can the permeability cut-off value of tight sandstones be truly and effectively evaluated, thus providing a scientific basis for oil and gas exploration. Compared with the Upper Yangtze region, a large-scale marine pe­ troleum base in China (Korsch et al., 1991; Wei et al., 2008; Borkloe et al., 2016; Chen et al., 2017; Yang et al., 2017), no commercial oil or gas flows have so far been discovered in the Lower Yangtze region, thus presenting both a challenge and an opportunity for petroleum geolo­ gists. The South Yellow Sea Basin has attracted considerable attention (Zhang et al., 2015; Li et al., 2014; Cai et al., 2019; Pang et al., 2019a,b), due to its high predicted marine hydrocarbon amount of 27.50 � 108 t ~ 35.37 � 108 t (Hu, 2010; Tan et al., 2018). Recent research on the petroleum geological conditions of borehole CSDP-2 has further vali­ dated two sets of source rocks and two hydrocarbon charging stages in the Permian Longtan Formation of the South Yellow Sea Basin (Xiao et al., 2017; Cai et al., 2019). However, confined to core and testing data, previous reservoir evaluations of the South Yellow Sea Basin are limited in qualitative approaches (Zhang et al., 2016; Yuan et al., 2017), thus scientific research on pore-throat structures has become necessary for oil–gas exploration. Pore-throat sizes (diameters) in tight-gas sandstones range from about 0.03 to 2.0 μm (Nelson, 2009). Bai et al., 2013 also reported that the median pore diameters of the Yanchang Formation tight sandstones in the Ordos Basin lie within the range of 20–300 nm, and that pore-throats exist as sheeted and curved lamellar structures. Various testing techniques and methods have been developed to evaluate the pore-throat characteristics of tight sandstones, which can be divided into two categories based on their test purpose: the pore-throat size and type technique, and the pore-throat connectivity technique (Table 1; Schmitt et al., 2013; Bai et al., 2013; Xiao et al., 2016; Zhang et al., 2016;

Gao and Li, 2016; Li et al., 2017; Lai et al., 2018a). Each of these technologies has both strengths and weaknesses in analysing pore-throat structures. Thin sections are commonly used to observe the pore size, shape, and pore-throat connectivity in conventional and unconventional reservoirs but are not ideal for recognizing nano-scale pores due to their low accuracy (Zou et al., 2015; Gao and Li, 2016). Scanning electron microscopy (SEM) can be used to observe the 2D micropore geometry and pore size at different scales but cannot construct 3D pore-throat distributions and lack a quantitative analysis of pore-throat connectiv­ ity (Hemes et al., 2015; Liu et al., 2017). Mercury injection capillary pressure (MICP) techniques can be used to quickly and accurately distinguish the overall pore-throat texture between 6.3 nm and 1 mm, but these cannot describe uneven pore-throat distribution (Rezaee et al., 2012; Bai et al., 2013). High-pressure mercury injection (HPMI) and rate-controlled mercury injection (RCMI) are widely used to obtain the full pore-throat structure and connectivity, particularly pore-throat size distributions from micro scale (up to approximately 350 μm) to nano­ scale (approximately 2 nm) (Anovitz and Cole, 2015; Lai and Wang, 2015; Xiao et al., 2016; Wu et al., 2018; Zhao et al., 2019). Nitrogen gas adsorption (NGA) experiments test the type, volume, size distribution, and specific surface area of nanoscale pores using adsorption–desorption curves. However, the testing range of NGA is limited to nanopores and it cannot determine pore-throat sizes in a closed micro-pore system (Clarkson et al., 2013; Schmitt et al., 2015; Liu et al., 2015; Zhao et al., 2019). X-ray computer tomography (XCT) is a technique developed in recent years that uses X-rays for rapid and non-destructive omni-scan­ ning of rock samples. This approach can be used to reconstruct 3D pore-throat texture at the nano-, micro-, and millimetre scales, but nano-CT is too expensive to be widely used and micro-CT has a limited resolution (Sakdinawat and Attwood, 2010; Cnudde and Boone, 2013; Desbois et al., 2016; Tang et al., 2016). Based on the investigation of relaxation processes of hydrogen nuclei in pore fluids, nuclear magnetic resonance (NMR) could quantitatively and non-destructively provide information on the full range of pore sizes in tight sandstones, but its

Table 1 Testing techniques to characterize pore-throat structures in tight sandstones. Type

Measurement technique

Measurement range

Purpose

References

2D testing techniques

Thin section

n � 10 μm – n � mm

Microscale pore-throat size and type

SEM (ESEM)

n � 10 nm – n � 10 μm

Nanoscale pore-throat size and type

Micro-CT

1 μm – n � mm

Microscale pore-throat size and connectivity

Nano-CT

50 nm–65 μm

Nanoscale pore-throat size and connectivity

FIB-SEM

0.5 nm–30 μm

Mercury injection capillary pressure

6.3 nm–1 mm

Nanoscale pore-throat size and connectivity Microscale pore-throat size and connectivity

Rate-controlled mercury injection

0.12 μm–39 μm

High-pressure mercury injection

1.8 nm–350 μm

NMR

3 nm – n � mm

Nanoscale pore-throat size distribution

Nitrogen gas adsorption

0.35 nm–200 nm

Nanoscale pore-throat size distribution

Nelson (2009); Zou et al. (2015); Gao and Li (2016) Nelson (2009); Hemes et al. (2015); Zou et al. (2015); Liu et al. (2017) Bai et al. (2013); Desbois et al. (2016) Liu et al. (2017) Bai et al. (2013); Tang et al. (2016); Lai et al. (2018a) Hemes et al. (2015); Tang et al. (2016); Pittman (1992) Nelson (2009); Rezaee et al. (2012) Xiao et al. (2016); Wu et al. (2018) Clarkson et al. (2012); Gong et al. (2015); Lai and Wang (2015); Zhao et al. (2019) Rezaee et al. (2012); Rosenbrand et al. (2015); Wu et al. (2018)

3D testing techniques

Pore-throat connectivity testing techniques

2

Microscale pore-throat size and connectivity Nanoscale pore-throat size and connectivity

Clarkson et al. (2013); Liu et al. (2015); Zhao et al. (2019)

L. Cai et al.

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

ability to predict pore-throat structures is still being explored (Rezaee et al., 2012; Rosenbrand et al., 2015; Zhang et al., 2016; Wu et al., 2018). Considering the microscopic pore-throat radius, complex geo­ metric shape, poor connectivity, and high heterogeneity of tight sand­ stones (Rezaee et al., 2012; Schmitt et al., 2015; Shanley and Cluff, 2015; Lai et al., 2018a), multi-scale testing methods should be jointly applied to obtain a full-scale map of pore-throat structures (Rezaee et al., 2012; Bai et al., 2013; Anovitz and Cole, 2015; Lai and Wang, 2015; Rosenbrand et al., 2015; Desbois et al., 2016; Rahner et al., 2018; Lai et al., 2018a). Moreover, digital rock (DR) technology can directly image pore sizes across a continuous range from the nanometre to millimetre scale, and provides a new way of constructing a nanoscale 3D pore-throat network of reservoir rocks. This technique offers significant potential for achieving cheaper and faster results compared to conven­ tional laboratory measurements (Berg et al., 2017; Lin et al., 2017, 2019; Sun et al., 2019). As an effective connection between and expansion of the Interna­ tional Continental Scientific Drilling Program (ICDP) (Litt et al., 2009; Koeberl et al., 2013) and the Integrated Ocean Drilling Program (IODP) (Cyranoski, 2003; Stein, 2014), China set up the Continental Shelf Drilling Program (CSDP), the first of its kind in the world. With the support of this drilling program, the drilling of boreholes CSDP-1 and CSDP-2 has been completed. Borehole CSDP-2 is the first well in the Central Uplift of the South Yellow Sea Basin, which represents a continuous core of 2843.18 m with 97.7% recovery and includes the first occurrence of the Lower Silurian in this region, closing a gap in the geological data (Guo et al., 2017; Pang et al., 2019a,b; Cai et al., 2019). Under the Neogene, borehole CSDP-2 successively drilled through the Mesozoic Triassic, Upper Palaeozoic Permian, Carboniferous, and Devonian, and encountered the Lower Palaeozoic Silurian, revealing the existence of thick marine strata and multiple sets of hydrocarbon source rocks (Guo et al., 2017; Xiao et al., 2017; Pang et al., 2017c, 2019a,b; Cai et al., 2019).

2. Geological setting The South Yellow Sea Basin, located in the eastern China seas is a large petroleum-bearing basin developed on the Presinian basement, which is mainly bounded by peripheral faults: the Qianliyan fault and Sulu–Imjingang orogenic belt in the north, and the Jiangshao fault zone in the south (Fig. 1a; Pang et al., 2017a, 2017b; Guo et al., 2019). As a superimposed basin, the South Yellow Sea Basin lies roughly between 121� E and 124� E, with an exploration area of about 10.15 � 104 km2. It can be further subdivided into five secondary tectonic units, namely the Qianliyan Uplift, Northern Depression, Central Uplift, Southern Depression, and Wunansha Uplift from north to south (Fig. 1a; Zhang et al., 2015; Pang et al., 2017a, 2017b; Guo et al., 2017; Cai et al., 2018, 2019). So far, only 24 exploratory boreholes have been drilled in the South Yellow Sea Basin, which is the lowest-density exploration area in China (Cao et al., 2009; Zhang et al., 2015; Pang et al., 2017a, 2019a,b). Of these boreholes, well CZ12-1-1 is the only in which the Carboniferous Gaolishan Formation was encountered, but several other formations were missing. Five other wells that penetrated the Triassic rock, such as wells W4-2-1 and CZ35-2-1, are all located in the Southern Depression and Wunansha Uplift (Fig. 1a; Pang et al., 2017c; Cai et al., 2019). The Longtan Formation, with interbedded sandstone and mudstone in a ‘sandwich style’, has always been the key exploration layer in the South Yellow Sea Basin (Dai et al., 2005; Zhang and Liang, 2014; Cai et al., 2017, 2019). However, the lack of original geological data, including core, logging, and testing data, is undoubtedly the main obstacle to its exploration. The previous analysis data collected from the onshore Subei Basin are clearly insufficient to meet the requirements of the current scientific investigation (Zhang et al., 2016; Pang et al., 2017a; Yuan et al., 2017). Borehole CSDP-2, the first well in the Central Uplift, is located at latitude 34� 330 18.900 N and longitude 121� 150 41.000 E (Fig. 1a). The Mesozoic section in borehole CSDP-2 is covered by the Indosinian

Fig. 1. a. Tectonic divisions of the South Yellow Sea Basin, China; b. Stratigraphic section of the Permian in the borehole CSDP-2. 3

L. Cai et al.

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

unconformity at a depth of 629.0 m. The Lower Triassic Qinglong For­ mation (T1q), at a depth of 629.0 m–866.2 m, consists of dark grey micrite and reddish-brown mudstones. The 866.2 m–914.8 m interval is the Upper Palaeozoic Permian Dalong Formation (P2d), which can be divided into two lithological associations. The first, developed in the depth range 866.2 m–887.55 m, consists mainly of grey calcareous fine sandstone deposits. The second, in the interval 887.55 m–914.8 m, consists mainly of grey fine sandstone and grey-black mudstone de­ posits. The Permian Longtan (P2l) Formation, distributed in the depth range 914.8 m–1636.6 m, developed mainly sandstones and mudstones from tidal flats, lagoons, and delta facies, and thin black carbonaceous mudstones and coal seams at its bottom. The ‘sandwich-style’ inter­ bedding of mudstones and sandstones provides a direct basis for hy­ drocarbon accumulation in the Upper Permian. Sediments of the Lower Permian Gufeng Formation (P1g) are dominated by siliceous mudstones in the interval 1636.6 m–1648.0 m. Finally, the Lower Permian Qixia Formation (P1q), from 1648.0 m to 1730.0 m, is composed of swine­ stones, carbonaceous mudstones, and mudstones (Fig. 1b; Guo et al., 2017; Cai et al., 2018, 2019).

throats (Yu et al., 2015; Zhao et al., 2018; Gao et al., 2019), was carried out on an ASPE-730 mercury porosimeter with a mercury injection rate of 5 � 10 5 mL/min. A maximum intrusion pressure of 6.20 MPa ensured a quasi-static intrusion rate, which corresponded to a throat radius of approximately 0.12 μm. HPMI experiments were performed on a PoreMaster 60 GT mercury porosimeter to determine the pore-throat size distribution of each sample. The minimum intruding pressure was 0.43 psia, and the maximum pressure was 56,944.20 psia, correspond­ ing to pore-throat sizes ranging from 3.2 nm to 423.59 μm. The assumed advancing contact angle was 140� , and the assumed surface tension for mercury was 485 dyn/cm. The oil-charging simulation experiments were conducted on a set of experimental apparatus including a core holder, pressure control system (confining pressure pump, water pump, oil pump, pressure sensor, dif­ ferential pressure transducer, back-pressure valve, etc.), strainer, oil–­ water separator, and data acquisition and processing system (Bunsen beaker, balance, computer, etc.). Before the experiment, each core plug was vacuumed for 24 h and fully saturated in a sodium chloride solution with salinity of 6000 mg/L. Then, under a series of different pressures, simulated oil with viscosity of 5 mPa⋅s was injected into the core plug samples, according to the following experimental procedures:

3. Data and methods

(1) Place one brine-saturated core plug in the core holder. Connect the core holder inlet through the strainer to the oil pump and the outlet to the oil–water separator. (2) Set the confining pressure of the oil injection to 35 MPa, which is 3–5 MPa higher than the maximum inlet displacement pressure. (3) To begin oil flooding at a low constant pressure, measure the flow rate when the outlet flow is constant, and water can no longer be displaced. Continue to inject fluid with a slightly enhanced inlet pressure and measure the oil flow rate when the outlet flow be­ comes stable. Repeat this experimental process until there is no movable water displaced from the core, and then obtain a com­ plete flow curve.

3.1. Core samples The core samples in this study were selected from the Longtan For­ mation of borehole CSDP-2, which represents a typical tight sandstone reservoir developed in the South Yellow Sea Basin. The samples used for analysing petrographic composition were scattered cores, and the other samples used to characterize the pore-throat structures were drilled as regular core plugs (4.0 cm in length and 2.5 cm in diameter). Three typical samples were extracted from depths of 1132.5 m (R1), 1225.8 m (R2), and 1538.4 m (R3) for the NMR, RCMI, and HPMI experiments, respectively. All core plugs were immersed in a mixture of alcohol and chloroform to remove residual asphalt, and then the porosity and permeability were measured using an instrument combination of an Ultrapore-200A helium porosimeter and an ULTRA-PERMTM200 per­ meameter after drying at 110 � C for 24 h.

4. Results 4.1. Petrography

3.2. Experimental methods

The Longtan Formation in borehole CSDP-2 mainly exhibits delta, tidal flat, and lagoon facies composed of medium- and fine-grained sandstones, siltstones, and mudstones, showing features of inter­ bedded distribution (Cai et al., 2017, 2018). One of the major charac­ teristics of the P2l tight sandstones is their low compositional maturity, with high argillaceous matrix content, and low textural maturity with sub-angular to sub-rounded sands and moderate sorting (Fig. 2a and b). Line contact is the dominant grain contact model, while concavo-convex contacts and pore cementation are also common in samples (Fig. 2b and c). Based on the Folk classification scheme (1974), the majority of tight sandstone samples from borehole CSDP-2 fall within the range of feld­ spathic litharenite and a few are litharenites, while only one sample is lithic arkose (Fig. 2d). Table 2 shows that the tight sandstones consist of quartz, feldspar, clay minerals including illite, kaolinite, and chlorite, and certain amounts of calcite, dolomite, siderite, and pyrite. Quartz is the most abundant detrital mineral, ranging in content from 31.7% to 83.6% with an average of 57.5%, while the feldspar content, including plagioclase feldspar and minor potash feldspar, varies from 2.0% to 49.5% with a mean value of 18.8%. The clay minerals are dominated by illite, accounting for 3.2%~31.4% (av. 14.9%); kaolinite, accounting for 0.5%~13.3% (av. 4.6%); and chlorite, accounting for less than 4.4% (Fig. 2e–g; Table 2). In the composition of cements, calcite with an average of 5.3% (ranging from 0.2% to 24.2%) is generally more abundant than other carbonate minerals such as dolomite and siderite. The dolomite content varies from 0.5% to 8.2% and occasionally up to 15.1%, while the siderite generally accounts for 0.2%~7.7% except for one maximum of 17.8% (Table 2). Pyrite is observed on calcite surfaces

To analyse sandstone composition and pore types, 79 blue epoxy resin-impregnated thin sections were examined under a Zeiss Axioscope A1 APOL digital transmission microscope, and 51 rock samples were analysed for whole-rock and clay fractions using a D/Max-2500 X-ray diffractometer. A total of 26 representative samples were observed under a Quanta FEG 450 scanning electron microscope equipped with an energy-dispersive X-ray spectrometer (EDX) to ascertain the geometry of pores and characteristics of clay minerals. Cathodoluminescence (CL) analyses were performed using an Olympus microscope equipped with a CL8200-MKS CL instrument. The characteristic parameters of pores and throats were obtained from an AutoPore IV 9520 mercury porosimeter, with a maximum injection pressure of 116.67 MPa. The pore sizes, throat sizes, and pore-throat structures of the tight sandstone samples were obtained by NMR, HPMI, and RCMI experi­ ments, respectively. Under vacuum, three typical sandstone plugs were fully saturated in n-dodecane simulated oil with a density of 0.748 g/ml for at least 24 h. Subsequently, NMR tests were performed on a MicroMR23-060H-1 NMR spectrometer with an echo spacing of 0.07 ms, waiting time of 3000 ms, and scanning time of 32; then, the satu­ rated T2 spectrum was obtained. Movable n-dodecane in the saturated core plugs was removed using a CSC-12 centrifugal machine with a rotation speed of 10,000 r/min and centrifugal time of 8 h, and the centrifuged T2 spectrum was also obtained. Following NMR, the core plugs without residual bitumen were dried again and cut into two reg­ ular cylindrical subsamples of 2.0 cm in length for HPMI and RCMI testing. RCMI testing, which can effectively distinguish pores and 4

L. Cai et al.

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

Fig. 2. Petrography characteristics of the P2l tight sandstones in the borehole CSDP-2: (a) siltstone of thin section ( ) showing the low textural maturity; (b) grain contact model of thin section ( ); (c) porosity typed cementation (calcite) of CL; (d) ternary diagram illustrating the framework compositions, Q ¼ quartz; F ¼ feldspar; RF ¼ rock fragments. (e) flaky kaolinite and its clay intercrystalline pores of SEM; (f) illite and its clay intercrystalline pores of SEM; (g) flaky chlorite of SEM; (h) granular pyrite of SEM; (i) illitization of smectites of SEM. I-illite; K-kaolinite; Ch-chlorite; Ca-carbonate; Py-pyrite.

and occurs mainly as granular pyrite (Fig. 2h), ranging from 0.1% to 8.2% with an average value of 1.5% (Table 2).

4.3. Pore-throat structures 4.3.1. Pore types and pore-throat connectivity Four major types of pores are identified by thin sections and SEM images in the P2l tight sandstone samples from borehole CSDP-2, including residual intergranular pores, dissolution pores, clay inter­ crystalline pores, and microfractures (Fig. 4). Residual intergranular pores with triangular or polygonal shapes range from 2 μm to 400 μm in size and are very rare due to strong mechanical compaction and cementation (Zhang et al., 2016, Fig. 4a–c). Dissolution pores with rather irregular geometry, an important contributor to pore space, are mainly derived from the partial dissolution of feldspars and rock frag­ ments. The sizes of dissolution pores vary from the nanometre to micrometre scale, with relatively poor to good connectivity (Fig. 4d–f). Microfractures triggered by thrust-nappe structures in the Indosinian Movement (Zhang et al., 2015; Pang et al., 2017a, 2019b) are common and relatively longer but nanoscale in width (Fig. 4g and h); they are known to increase the permeability of tight sandstone reservoirs and provide effective migration pathways for hydrocarbons. Intercrystalline pores are widely distributed in clay minerals including kaolinite, illite, and chlorite, with dimensions generally smaller than 20 μm (Fig. 2e and f; Fig. 4i). In addition to pore types, sizes, and geometries, the permeability of tight sandstones is correlated with pore-throat connectivity, i.e., porethroat radius, throat coefficient, relative sorting coefficient, kurtosis,

4.2. Porosity and permeability The porosity of 44 dry core plugs varies from 0.2% to 2.7% with an average of 1.26%, and approximately 88.6% of the samples have porosity values less than 2.0%. The permeability measured under un­ stressed conditions have a range of 0.0047–0.5438 mD with an average of 0.0413 mD, and the relative proportion of permeability less than 0.1 mD accounts for 97.7% of the samples (Fig. 3), indicating a typical tight sandstone. However, its exploration prospects should not be totally negated in view of the multiple instances of oil and gas in borehole CSDP-2 (Cai et al., 2019), and the fact that high-yield gas wells in the Upper Triassic Xujiahe Formation of the Sichuan Basin have similar densification (Zou et al., 2012b; Su et al., 2018; Liu et al., 2018). Moreover, the relationship between porosity and permeability shows very poor correlation, with a low correlation coefficient of 0.136. The permeability of some samples with similar porosity may vary by an order of magnitude (Fig. 3), which may be caused by strong heterogeneity.

5

L. Cai et al.

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

Table 2 Mineral contents obtained from X-ray diffractions (XRD) of the P2l tight sandstones in the borehole CSDP-2. Sample

Depth (m)

Quartz (%)

Potash Feldspar (%)

Plagioclase Feldspar (%)

Illite (%)

Kaolinite (%)

Chlorite (%)

Calcite (%)

Dolomite (%)

Siderite (%)

Pyrite (%)

X1 X2 X3 X4 X5 X6 X7 X8 X9 X10 X11 X12 X13 X14 X15 X16 X17 X18 X19 X20 X21 X22 X23 X24 X25 X26 X27 X28 X29 X30 X31 X32 X33 X34 X35 X36 X37 X38 X39 X40 X41 X42 X43 X44 X45 X46 X47 X48 X49 X50 X51

918.8 924.8 933.8 941.8 950.5 956.4 963.3 969.2 977.9 989.1 998.1 1015.9 1031.8 1049.1 1058.2 1092.8 1100.3 1109.5 1118.0 1127.9 1134.1 1142.4 1155.0 1161.1 1171.3 1177.6 1182.1 1189.0 1195.3 1207.5 1224.2 1231.7 1242.3 1262.9 1283.9 1297.1 1305.2 1321.9 1335.5 1348.3 1378.1 1398.1 1421.8 1447.1 1479.4 1508.5 1535.0 1556.0 1575.4 1617.8 1642.8

60.6 59.0 62.3 72.1 74.7 74.7 71.8 71.8 71.0 64.0 78.5 66.1 62.6 64.1 76.2 53.6 62.6 75.9 51.4 70.0 49.2 46.7 43.7 66.3 44.0 33.8 31.7 32.5 41.2 44.6 48.5 34.6 55.0 52.4 55.3 40.9 60.5 67.4 68.0 65.7 49.0 33.7 55.6 45.2 57.2 66.5 57.2 57.7 58.3 44.5 83.6

/ / / / / / / / / / / / / / / / / / / / 1.8 / / / / 23.4 22.4 19.6 21.2 / / / 0.9 / / / / / / / / / / / / / / / / / /

18.2 15.8 5.7 2.0 18.4 2.4 22.9 19.0 10.7 4.8 2.1 3.7 19.7 / 3.2 14.8 21.0 13.7 15.5 21.7 27.3 27.1 17.1 26.0 25.2 18.4 27.1 24.7 28.1 20.2 23.7 35.2 8.4 9.1 8.9 37.6 29.0 11.9 18.3 27.7 19.0 11.6 12.8 23.0 6.9 11.1 27.5 23.6 9.0 14.6 4.6

12.8 20.6 25.0 15.8 4.2 14.4 3.2 6.3 8.8 19.9 11.4 15.3 10.4 17.6 12.6 23.2 10.8 8.8 30.2 7.5 18.2 11.8 29.3 4.8 23.8 5.6 8.9 7.8 7.0 29.3 19.4 26.3 31.4 17.0 25.2 6.2 7.8 15.3 7.2 3.9 24.1 11.2 22.8 17.8 17.4 15.7 3.8 15.5 20.6 20.0 6.8

3.8 2.6 5.1 8.3 1.5 4.3 0.5 1.0 / 8.0 / 7.5 6.4 13.3 6.5 5.0 0.7 / / / 2.4 / 6.8 / / / / / / / / / / / / / / / / 1.0 / / / 6.4 4.6 / / / / 1.7 /

2.4 0.5 0.9 0.2 0.7 0.3 0.4 1.3 0.3 1.9 0.3 1.3 0.7 0.7 0.3 2.6 0.9 0.8 1.8 0.8 0.9 1.6 2.6 1.5 3.2 1.0 3.2 1.7 1.2 3.4 2.4 2.8 2.7 1.3 4.1 0.8 2.4 2.0 0.9 0.4 3.6 2.1 3.8 4.4 2.9 1.3 0.3 1.9 2.0 0.4 /

/ / / / / / 0.9 0.3 / / / / / / / / 3.0 0.4 / / / 12.8 / 1.3 3.2 17.9 6.6 13.8 0.6 / 3.4 0.5 / / / 12.4 0.2 / 1.7 0.6 / 24.2 0.8 0.8 3.2 / 9.4 / / 3.7 /

/ / / / 0.5 / / / / / / / / / / / / / 0.5 / / / 0.6 / / / / / / 1.6 0.8 / / 1.1 5.2 1.6 / 1.0 3.0 / 2.8 15.1 2.2 1.3 1.0 3.5 1.2 0.9 8.2 6.9 1.6

0.3 0.2 0.5 1.3 / 3.8 / 0.4 7.7 1.1 6.8 6.2 0.2 1.4 1.3 0.8 1.0 0.4 0.5 / 0.3 / / / 0.5 / / / 0.2 0.3 / 0.2 0.3 17.8 0.4 / / 2.3 0.8 0.7 1.6 1.8 2.0 1.1 1.2 0.7 0.7 0.3 1.3 / /

2.0 1.5 0.5 0.2 / / 0.3 / 1.4 0.3 0.9 / / 2.9 / / / / / / / / / / 0.1 / / / 0.5 0.6 1.9 0.4 1.3 1.2 1.0 0.4 / / / / / 0.3 / / 5.6 1.1 / / 0.5 8.2 3.3

and skewness (Zou et al., 2012b; Desbois et al., 2016). Table 3 shows that the highest value of maximum mercury intrusion saturation is from Sample Hg3, at 55.5%, and the highest efficiency of mercury withdrawal is from Sample Hg10, at 53.3%, clearly reflecting a large number of small pores and poor pore-throat connectivity in the P2l tight sand­ stones. Additionally, the poor-connectivity feature of ‘micrometre pores connected with nanometre throats’ is observed from the average throat radius, which ranges from 0.048 μm to 0.392 μm with an average of 0.189 μm (Table 3; Fig. 5a–c). Thus, three types of pore-throat con­ nectivity can be distinguished effectively based on the differences in parameters of MICP tests (Fig. 5). Type I is mainly characterized by the connectivity of lattice-like pore-throat networks, where intergranular pores are mostly occluded after strong compaction and cementation (Fig. 5a), and narrow pore throats with the maximum diameters of 1.6–2.5 μm (Fig. 5e) provide the necessary paths for the connection of dissolution pores and residual intergranular pores, leading to a maximum mercury intrusion saturation of 55.5% (Fig. 5d). By contrast,

the maximum mercury intrusion saturation of type II pore throats with tubular or spherical shapes (Fig. 5b) and maximum diameters of 0.63–1.60 μm (Fig. 5e) decreases to approximately 40.0% (Fig. 5d). Long tubular nanothroats act as major pathways connecting larger micro-pores, and adjacent spherical nanopores may act as both pores and throats (Fig. 5b). Type III is typically characterized by isolated micro–nanometre pores, and lacks effective percolation throats (Fig. 5c). The maximum radius of pore throats is less than 0.4 μm (Fig. 5e), which limits the maximum mercury intrusion saturation to only 20.0% (Fig. 5d). In this study area, the relationship between the relative sorting co­ efficient and throat coefficient shows good correlation, with a high correlation coefficient of 0.989, and skewness shows a notable powerfunction correlation with kurtosis (Fig. 5f and g). Throat coefficients greater than 7 and relative sorting coefficients less than 0.7 may reflect relatively good pore-throat connectivity, implying the existence of type I lattice-like pore-throat networks. For type II tubular pore-throat 6

L. Cai et al.

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

connectivity (Fig. 5g). 4.3.2. Pore-throat structures from RCMI tests Unlike MICP, RCMI can distinguish pores and throats effectively and calculate pore-throat ratios accurately (Xi et al., 2016; Xiao et al., 2016). According to the RCMI test results, the total mercury injection curves are consistent with the throat intrusion curves (Fig. 6a–c), as shown by the three typical tight sandstone Samples R1, R2, and R3, for which the detailed pore-throat structure parameters are listed in Table 4. All three samples have a Pd value less than or approximately equal to 1 MPa, and their maximum total mercury saturation (Sf) is only 46.53%. Further­ more, all the final pore mercury saturation (Sp) values range from 6.22% to 15.18%, far lower than the throat mercury saturation (St) values concentrated between 24.71% and 31.35% (Table 4), indicating that a small number of pore bodies are mainly connected by narrow throats with relatively higher content. At the low-pressure stage (Pd � 2 MPa), mercury first charges into throat areas with larger radii and pores, corresponding to lattice-like pore-throat structures. At the high-pressure stage, the total mercury injection curves show an ‘increasing segment’, indicating predominant throat intrusion and no pore intrusion, which corresponds to tubular pore-throat structures (Fig. 6a–c). The pore radius mainly ranges from 70 μm to 320 μm, and these three samples have small differences in pore size (Fig. 6d). The pore radii of Samples R2 and R3 are similar, with both showing an approximate Gauss shape with main peaks from 140 μm to 180 μm; this is higher than the peak range of Sample R1 from approximately 100 μm–130 μm (Fig. 6d). The

Fig. 3. Relationship between porosity and permeability of the P2l tight sand­ stones in the borehole CSDP-2.

networks, the throat coefficient varies from 4.10 to 6.02 and the relative sorting coefficient ranges from 0.89 to 1.38, indicating poorer porethroat connectivity. Type III samples with low throat coefficients of 2.15–2.77 and high relative sorting coefficients of 1.85–2.33 are generally ineffective in fluid flow (Table 3; Fig. 5f). Likewise, large differences in skewness and kurtosis among the three types of tight sandstone samples also reflect the heterogeneous pore-throat

Fig. 4. Typical pore types of the P2l tight sandstones in the borehole CSDP-2: (a) micrograph of thin section ( ) showing residual intergranular pores; (b) and (c) micrograph of SEM showing residual intergranular pores; (d) micrograph of thin section ( ) showing dissolution pores; (e) and (f) micrograph of SEM showing dissolution pores; (g) micrograph of thin section ( ) showing micro fractures; (h) micrograph of SEM showing micro fractures; (i) micrograph of SEM showing clay intercrystalline pores. 7

L. Cai et al.

2.29 2.83 2.37 5.43 3.65 2.92 2.79 3.67 2.90 3.87 3.20 2.71 7.11 3.17 2.78 0.63 0.95 0.63 1.85 1.25 1.02 0.89 1.32 0.98 1.38 1.10 0.97 2.23 1.15 0.99

1.49 1.66 1.50 2.32 1.88 1.69 1.65 1.90 1.69 1.95 1.77 1.63 2.65 1.77 1.66

heterogeneity of the throat radius is strong, and samples with different permeabilities show significant differences in throat size (Fig. 6e), which range from 0.2 to 2.2 μm with the main peak from 0.5 μm to 0.9 μm. For Sample R1, with its relatively higher permeability of 0.032 mD (Table 4), the proportion of pores with throat radii larger than 0.9 μm clearly increases. For Samples R2 and R3, with their relatively lower permeability (0.020–0.021 mD), the throat radius range is narrower and the main peak values decrease to 0.4–0.7 μm, suggesting that the permeability of tight sandstones may increase with throat radius but not pore radius (Fig. 6d and e). Moreover, differences between the pore and throat radii of the three typical samples result in a variable pore-throat ratio in the range of 50–660, with an average value (η) of 153.2, 276.5, and 337.9, respectively (Fig. 6f; Table 4). The ratio distribution of Sample R1 is much lower than that of Samples R2 and R3, indicating that the smaller the ratio of pore to throat radius is, the higher the connectivity of the pore-throat structure. 4.3.3. Pore-throat structures from HPMI tests Pore-throat structure parameters of the three typical tight sandstone samples can also be obtained from HPMI analysis and are listed in Table 5, which shows that the threshold pressure (Pt) ranges from 0.43 to 2.94 MPa and the corresponding maximum pore-throat radius (Rmax) is mainly centred around 0.368–0.370 μm. There is no significant dif­ ference in maximum intrusion mercury saturation (Smax), which occurs in the range 74.67%–88.69%, and more than 60.0% of the injected mercury is trapped in pores, implying a complicated pore-throat size distribution. The maximum residual mercury saturation (Sr) is found in Sample R3, with 68.82%, and the minimum is in Sample R1, with 60.36%. Samples R1 and R2 possess relatively large cumulative pore volumes of 0.0058 ml/g and 0.0048 ml/g, and the pore throats with radii larger than 0.01 μm contribute to 0.0037 ml/g and 0.0040 ml/g, respectively. In contrast, the total volume of pore throats with radii larger than 0.01 μm in Sample R3 is only 0.0027 ml/g, and its cumu­ lative pore volume is only 0.0031 ml/g (Fig. 7a). In addition, the rela­ tionship between dv/dlogD and pore-throat radius (Fig. 7a) reveals that the entire pore-throat size is less than 1.0 μm, and predominantly be­ tween 0.000006 μm and 0.42 μm. The pore-throat distribution of Sample R1 is bimodal, and the peak values fall in the ranges of 0.00008–0.0002 μm and 0.036–0.368 μm (av. 0.183 μm, Table 5), indicating the coex­ istence of lattice-like and tubular pore-throat networks. The pore-throat size of Sample R2 is characterized by a right-skewed distribution in a narrow range of 0.073–0.370 μm (av. 0.148 μm, Table 5), from which we can infer that some relatively larger pores are interconnected by narrower tubular throats. The distribution curve of pore-throat size in Sample R3 also shows two obvious peaks without pore throats less than 0.002 μm in radius, which are defined as dead-end nanopores. The HPMI test results of the three typical samples further indicate that those pore throats with a radius larger than 0.036 μm play the most important role in mercury injection or hydrocarbon migration (Fig. 7b). However, it should be cautioned that the HPMI test is not suitable for characterizing pores and throats less than 63 μm in radius (Xi et al., 2016; Wang et al., 2018).

55.3 40.8 55.5 19.2 31.2 37.8 43.7 29.5 40.1 28.0 36.1 39.4 14.8 34.0 38.9 0.066 0.037 0.084 0.026 0.054 0.038 0.030 0.028 0.081 0.037 0.040 0.032 0.018 0.032 0.027 2.6 1.0 1.5 2.0 1.9 1.3 0.7 1.1 1.3 1.2 1.0 1.4 1.2 1.8 0.9 972.7 1032.0 1129.4 1133.6 1159.2 1182.1 1226.5 1232.1 1236.1 1333.0 1490.2 1530.2 1537.7 1550.1 1554.4 Hg1 Hg2 Hg3 Hg4 Hg5 Hg6 Hg7 Hg8 Hg9 Hg10 Hg11 Hg12 Hg13 Hg14 Hg15

0.30 0.30 0.20 2.00 1.50 1.00 0.30 0.50 0.20 1.50 0.20 2.00 1.50 1.00 0.50

31.2 36.8 42.9 37.6 43.3 44.1 30.8 30.5 52.9 53.3 41.6 33.6 46.5 36.6 34.7

0.222 0.214 0.372 0.054 0.123 0.109 0.392 0.145 0.377 0.092 0.374 0.048 0.078 0.098 0.142

0.13 0.13 0.19 0.03 0.04 0.06 0.13 0.09 0.19 0.04 0.13 0.03 0.04 0.06 0.09

7.74 5.79 7.46 2.77 4.10 5.23 6.02 4.33 5.77 4.12 5.18 5.75 2.15 4.89 5.81

4.88 5.51 4.70 5.13 5.14 5.36 5.33 5.70 5.63 5.69 5.68 5.60 4.81 5.61 5.77

Kurtosis value Average throat radius (μm) Efficiency of mercury withdrawal (%) Maximum mercury saturation (%) Entry pressure (Mpa) Permeability (mD) Porosity (%) Depth (m) Sample

Table 3 Parameters of pore-throat connectivity obtained from MICP tests of the P2l tight sandstones in the borehole CSDP-2.

Uniformity coefficient

Throat coefficient

Throat sorting coefficient

Relative sorting coefficient

Skewness value

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

4.3.4. Pore-throat structures from NMR tests In NMR measurement, the transverse relaxation time T2 can be directly converted into pore size through Eq. (1) (Volokitin and Looyestijn, 2001; Zhao et al., 2017; Lai et al., 2018b), which enables a clearer illustration and discussion of the pore-throat structures: 1 S ¼ρ T2 V

(1)

where ρ (μm/ms) is the conversion coefficient corresponding to each T2 value, and is related only to pore surface properties; and S and V are pore surfaces in μm2 and volume in μm3, respectively, indicating that if the value of ρ is determined, then the pore-surface-to-pore-volume ratio (S/ 8

L. Cai et al.

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

Fig. 5. Pore-throat connectivity characteristics of the P2l tight sandstones in the borehole CSDP-2: (a) lattice-like pore-throats imaged by SEM and its connectivity model; (b) tubular pore-throats imaged by SEM and its model; (c) isolated pore-throats imaged by SEM and its connectivity model; (d) and (e) classification of porethroat connectivity from MICP; (f) classification of pore-throat connectivity based on the correlativity between throat coefficient and relative sorting coefficient; (g) classification of pore-throat connectivity based on the correlativity between kurtosis and skewness.

V) can be calculated (Lai et al., 2018b). Eq. (2) shows that the S/V value is a function of pore radius R (μm) and pore shape factor FS (Pape and Clauser, 2009; Zhao et al., 2017; Lai et al., 2018b), equal to 2 and 3 for cylindrical and spherical pores, respectively: S FS ¼ V R

distribution based on Eq. (3) (Zhao et al., 2017; Lai et al., 2018b; Lyu et al., 2018): R ¼ ρFST2

(3)

Fang et al. (2018) defined the concept of C, equivalent to ρFS, and proposed a model between C, porosity (Φ), and permeability (K) in tight sandstone reservoirs, which can be expressed as Eq. (4): pffiffiffiffiffi C ¼ ρFS ¼ 25:94e0:2872 ΦK (4)

(2)

Therefore, T2 at 100% water saturation can be converted to pore size 9

L. Cai et al.

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

Fig. 6. Pore-throat structures of the P2l tight sandstones in the borehole CSDP-2 from RCMI tests: (a), (b) and (c) mercury injection curves of total, pore and throat of samples R1, R2 and R3 in RCMI; (d) pore size distribution from RCMI; (e) throat size distribution from RCMI; (f) ratio of pore to throat radius from RCMI. Table 4 Parameters of pore-throat structures obtained from RCMI tests of the P2l tight sandstones in the borehole CSDP-2. Φ-porosity; K-permeability; Rt-average throat radius; Rmt-mean throat radius; Rmax-maximum connected throat radius; Rp-average pore radius; η-average pore-throat radius ratio; Sf-final total mercury saturation; SP-pore mercury saturation; St-throat mercury saturation; Pd-displacement pressure. Sample

Depth (m)

Φ (%)

K (mD)

Rt (μm)

Rmt (μm)

Rmax (μm)

Rp (μm)

η

Sf (%)

Sp (%)

St (%)

Pd (Mpa)

R1 R2 R3

1132.5 1225.8 1538.4

1.54 1.00 1.00

0.0320 0.0200 0.0210

1.010 0.672 0.518

1.240 0.637 0.483

1.934 0.940 0.676

130.06 157.59 151.94

153.2 276.5 337.9

33.49 46.53 34.07

6.22 15.18 9.36

27.27 31.35 24.71

0.380 0.782 1.088

Table 5 Parameters of pore-throat structures obtained from HPMI tests of the P2l tight sandstones in the borehole CSDP-2. Φ-porosity; K-permeability; Rmax-maximum porethroat radius; Rave-average pore-throat radius; R50-medium saturation pore-throat radius; Smax-maximum intrusion mercury saturation; Sr-residual mercury saturation; Pt-threshold pressure; P50-medium saturation pressure. Sample

Depth (m)

Φ (%)

K (mD)

Rmax (μm)

Rave (μm)

R50 (μm)

Smax (%)

Sr (%)

Pt (Mpa)

R1 R2 R3

1132.5 1225.8 1538.4

1.54 1.28 0.84

0.0320 0.0196 0.0212

0.368 0.370 0.368

0.183 0.148 0.167

0.231 0.168 0.175

88.69 79.27 74.67

60.36 68.82 65.45

0.43 0.50 2.94

Fig. 7. Pore-throat structures of the P2l tight sandstones in the borehole CSDP-2 from HPMI tests: (a) cumulative and dv/dlogD pore volume versus pore-throat radius characteristics from HPMI; (b) mercury injection saturation versus pore-throat radius characteristics from HPMI.

Combining these equations, the NMR-derived pore size of the P2l tight sandstones in borehole CSDP-2 can be directly obtained from the T2 spectrum through Eq. (5): pffiffiffiffiffi R ¼ 25:94e0:2872 ΦK T2 (5)

Before conducting NMR tests on the three samples, we first cali­ brated the relationship between signal amplitude and transverse relax­ ation time T2 of the n-dodecane simulated oil in free state. The results show that the signal peaks of the five simulated oil samples are all concentrated around 1000 ms, from 580 ms to 1900 ms (Fig. 8a). The larger the oil volume, the higher the peak value of the signal amplitude 10

L. Cai et al.

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

(Fig. 8a), which reveals that the cumulative signal amplitudes of oil samples have a positive linear correlation with their volumes, and the correlation coefficient (R2) is as high as 0.9999 (Fig. 8b). This provided a reliable test basis for identifying the T2 spectrum of simulated oil in tight sandstone samples, which can be further converted to pore sizes ac­ cording to the formulas mentioned above. In Fig. 8c–e, two types of T2 spectrum, one saturated with simulated oil and the other centrifuged for 8 h, of the three tight sandstone samples (R1, R2, and R3) have two peaks. The left peaks with T2 times distributed in the range of 0.01–1.0 ms generally have high signal amplitude, while the right peaks within the T2 range of 2.0–1000 ms are significantly lower (Fig. 8c–e). Consistent with this, the pore radius curves transformed from the T2 spectrum are also characterized by bimodal distribution behaviours, with a distinct left-skewed peak at 0.004–0.005 μm and an inconspic­ uous right peak ranging from 0.1 μm to 10.0 μm (Fig. 8f). The pore sizes of the left segments are mainly distributed in a wide range of 0.0005–0.03 μm, which accounts for 81.39%~92.32% of the total pore volume. The right segments consisting of relatively larger pores with radii larger than 0.1 μm represent just 7.68%~18.61% of the total pore volume.

5. Discussion 5.1. Necessity of combination of multi-scale testing methods in investigations of pore-throat structures As confirmed by previous research, the simultaneous existence of micro-scale pores and nanoscale throats leads to extremely complex pore-throat structures and strong heterogeneity in tight sandstones, which cannot be clearly characterized by a single testing method (Bai et al., 2013; Schmitt et al., 2015; Xi et al., 2016; Gao and Li, 2016; Liu et al., 2017). For comparison and discussion of the measured results, the pore-throat sizes of Samples R1 and R2 obtained from HPMI, RCMI, and NMR are depicted in Fig. 9, showing the various sizes of pore throats that can be detected by different techniques. RCMI can distinguish and measure the larger pore throats based on the fluctuation of mercury injection pressure; however, it is incapable of identifying pore throats smaller than 0.12 μm radius due to the low pressure. Pores with radii ranging from 90 μm to 300 μm constitute 8.13%~16.70% of the total pore-throat volume, and the remainder measured by RCMI are the throats with radii of 0.3–2.2 μm (Fig. 9), both of which jointly form the lattice-like pore-throat structure. Throats with radii ranging from 0.04 μm to 0.4 μm are mainly detected by HPMI, accounting for 29.9%– 31.5% of the total pore-throat volume (Fig. 9). Clay pores and throats with radii smaller than 0.04 μm can be detected by the combination of HPMI and NMR. The main difference is that the pore throats measured by HPMI exhibit higher accuracy and smaller scope (Fig. 7), while the

Fig. 8. Pore-throat radius of the P2l tight sandstones in the borehole CSDP-2 from NMR tests. 11

L. Cai et al.

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

Fig. 9. Overall pore-throat size distribution of the P2l tight sandstones in the borehole CSDP-2 from the combination of HPMI, RCMI and NMR.

opposite occurs in NMR (Fig. 8f). As shown in Fig. 8a, NMR testing is clearly more suitable for free-state oil samples with T2 times of about 1000 ms, corresponding to pores with radii of 10–100 μm (Fig. 8f). The T2 times of nanoscale pores in tight sandstones are too short to be measured accurately, so other testing methods, such as HPMI and NGA, are essential (Fig. 9; Clarkson et al., 2013; Schmitt et al., 2015; Xiao et al., 2016; Zhao et al., 2019). Taken together, the intersection between HPMI and RCMI (0.1–3.0 μm) includes most of the pore-throat radii, the sizes of which are at the same grade and most likely form a lattice-like pore-throat structure. The nanoscale pore throats at the far left have no prominent contribution to permeability, showing the poorest connectivity (Fig. 9). In addition, casting thin-section and SEM testing techniques can directly observe the 2D pore-throat structure, albeit with limited precision, while focused ion-beam SEM (FIB-SEM), CT scanning, and DR technologies can clearly reconstruct the 3D structure of micro–nanometre pores and throats (Tang et al., 2016; Liu et al., 2017; Berg et al., 2017; Lin et al., 2019). In summary, each technique can yield unique pore-throat information, but each also has its limitations. Therefore, it is imperative to combine testing methods in a multi-scale approach in the investigation of pore-throat structures of tight sandstones.

5.2. Correlation between pore-throat structures and reservoir quality of tight sandstones The dynamic process of hydrocarbon charging in tight sandstone reservoirs can be interpreted as the equilibrium between the driving force (hydrocarbon generation pressurization, buoyancy, capillary pressure, etc.) and migration resistance (capillary resistance and viscous resistance) (Spencer, 1987; Surdam, 1997). Only when the driving force is greater than the migration resistance can hydrocarbons enter the sand body and migrate continuously. From the experimental results of Sam­ ple R2 (Φ ¼ 1.28%, K ¼ 0.0196 mD, Table 5) in Fig. 10, we can see that the initial driving pressure is as high as 10 MPa, but the final cumulative injection volume of oil is only 0.05 ml, representing poor reservoir quality. Further analysis reveals that the process of oil injection can be divided into two stages: an early rapid stage and a later slow stage. Within the pressure range of 10–12 MPa, oil can be filled into larger pore throats with better connectivity, which correspond to the lattice-like pore throats in the samples. Accompanied by the increased driving pressure, the oil content in Sample R2 increases rapidly to 0.038 ml, accounting for 76% of the total oil content. Subsequently, although the driving pressure increases to 16 MPa, only 0.012 ml of oil is injected into

Fig. 10. Experimental result of oil charging simulation in sample R2 (1225.8 m) of the borehole CSDP-2. 12

L. Cai et al.

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

the smaller (tubular pore) throats with greater migration resistance. However, even if the driving pressure increases to 30 MPa, the cumu­ lative injection of oil remains at 0.05 ml, indicating that the isolated pore throats with minimum size are not capable of improving the reservoir quality (Fig. 10). The three stages of oil charging correspond to the three types of pore-throat structures (Fig. 10). The samples rich in lattice-like pore-throat structures clearly have better storage and seepage capacities. Permeability is a crucial parameter to describe reservoir quality (Rezaee et al., 2012; Xi et al., 2016), and is mainly controlled by throat size, shape, and quantity. Except for a few irregular data, permeability of the P2l tight sandstones is positively correlated with throat radii and coefficients, but negatively correlated with throat sorting coefficients. More throats with larger radii lead to better sorting and higher sample permeability (Fig. 11a–c). Well-structured pore throats with higher structural coefficients correspond to higher permeability (Fig. 11d). Hence, it is not difficult to draw the conclusion that the reservoir quality of tight sandstones is closely related to the connectivity rate of pores and throats (Zou et al., 2012a) and the volume ratio of pores to throats (Cao et al., 2018), which are the key differences between various pore-throat structures (Fig. 5a–c). When the pore-throat volume ratio is too large, there is a lack of throat connectivity between the pores in the reservoir, such as the isolated and tubular pore-throat structures described above. However, when the pore-throat volume ratio is too small, the total reservoir space mainly controlled by the throats is too limited to charge oil and gas. Using Eq. (6) (Yu et al., 2015), we calculated the volume ratio of pores to throats in the three Samples R1, R2, and R3: Bt ¼ Sr=（Smax

Sr）

R1 is also the largest among the three samples (Fig. 8c–e). 5.3. Origin analysis of pore-throat structures in the P2l tight sandstones The composition and structure of original sediments determine the initial appearance of pore-throat structures (Bjørlykke, 2014; Yang et al., 2014; Liu et al., 2018), and outstanding performances for sandstones with different grain sizes and argillaceous matrix contents often show different pore-throat distributions (Philip, 2009; Zhang et al., 2017). The type and intensity of later diagenesis control the evolution process and differentiation of pore-throat structures (Worden et al., 2000; Xiao et al., 2016; Liu et al., 2018; Cao et al., 2018). 5.3.1. Destructive influence of depositional fabric and compaction on porethroat structures As described above, the sandstone types in the Longtan Formation are mainly delta facies feldspathic litharenites and litharenites, and their particle diameters are concentrated in the range of 0.03–0.50 mm with a maximum size of 0.81 mm (Table 6). The sandstones tend to develop small initial pores and throats among the finer detrital particles (Philip, 2009), and the 2.0%~9.0% (av. 6.08%) (Table 6) argillaceous matrix fills in the intergranular pores. Furthermore, plastic rock fragments in the sandstone samples are higher than 21.0% with an average of 31.4% (Table 6), which can easily lead to compaction and deformation of pore-throat structures. Additionally, plastic components such as the argillaceous matrix and mica will partially occlude the pores and throats during compaction and preliminarily change the pore-throat structures. The initial porosity (Φinitial, %) of the P2l tight sandstones in borehole CSDP-2 is between 29.65% and 39.72%, with an average of 36.94%, as calculated using Scherer’s (1987) method:

(6)

where Bt is the volume ratio of pores to throats, which is dimensionless; and Sr and Smax are the residual and maximum mercury saturation (%) obtained from HPMI tests, respectively. The results of the calculation demonstrate that the Bt of Sample R1 is approximately 2.13, which is on the verge of favourable pore-throat configuration (Cao et al., 2018), while that of Samples R2 and R3 is as high as 6.58 and 7.09, respectively. Thus, the permeability of Sample R1 is slightly higher than that of Samples R2 and R3. Larger pores and throats tend to form lattice-like pore-throat networks, which have con­ tent positively correlated with permeability (Fig. 8f). However, the effective storage space (filling part with yellow background) in Sample

(7)

Φinitial ¼ 20:91 þ 22:9=So

In this formula, So, the sorting coefficient, is distributed in the range 1.22–2.62 (av. 1.47). The amount of porosity destroyed by compaction (Φcompaction, %) is calculated using Eq. (8) (Lundegard, 1992), and is estimated to be 4.23% ~30.20% with an average of 18.40% (Fig. 13), approximately 49.81% of the initial porosity: Φcompaction ¼ Φinitial

½ð100

ΦinitialÞ � Φmc� = ð100

Fig. 11. Relation diagram between permeability and throat of the P2l tight sandstones in the borehole CSDP-2. 13

ΦmcÞ

(8)

L. Cai et al.

Table 6 Parameters of depositional fabric obtained from thin sections of the P2l tight sandstones in the borehole CSDP-2. Sample

14

942.9 1031.1 1069.1 1099.7 1104.9 1224.1 1301.7 1311.5 1346.9 1400.7 1402.9 1509.0 1521.7 1523.7 1539.9 1544.7 1553.4 1554.7 1558.7 1560.9 1563.1 1579.7 1581.6 1582.4 1585.9

Relative content of clastic particles (%) Quartz (%)

Feldspar (%)

61.0 65.0 67.0 51.0 48.0 53.0 52.0 53.0 56.0 46.0 45.0 43.0 53.0 47.0 44.0 42.0 43.0 37.0 40.0 34.0 43.0 57.0 53.0 54.0 59.0

8.0 9.0 10.0 15.0 17.0 26.0 19.0 21.0 17.0 5.0 27.0 23.0 17.0 16.0 26.0 21.0 24.0 27.0 22.0 26.0 24.0 16.0 17.0 16.0 19.0

Lithic fragments (%) Magmatite rock

Metamorphic rock

Sedimentary rock

Mica

3.0 3.0 3.0 4.0 5.0 3.0 5.0 4.0 3.0 7.0 3.0 3.0 2.0 5.0 4.0 6.0 5.0 5.0 4.0 5.0 3.0 7.0 5.0 5.0 3.0

25.0 20.0 18.0 27.0 29.0 17.0 23.0 18.0 18.0 38.0 21.0 27.0 25.0 29.0 20.0 28.0 26.0 29.0 29.0 28.0 28.0 19.0 22.0 20.0 18.0

/ / / / / / / / / 2.0 / 2.0 / / 3.0 / / / 3.0 4.0 / / 2.0 2.0 /

3.0 3.0 2.0 3.0 1.0 1.0 1.0 4.0 6.0 2.0 4.0 2.0 3.0 3.0 3.0 3.0 2.0 2.0 2.0 3.0 2.0 1.0 1.0 3.0 1.0

Absolute content of clastic particles (%)

Argillaceous matrix (%)

Interstitial material (%) Cements (%) Calcite

Dolomite

Silicious

Iron minerals

87.0 91.0 89.0 86.0 91.0 82.0 83.0 88.0 80.0 93.0 87.0 86.0 87.0 89.0 88.0 87.0 85.0 81.0 89.0 86.0 88.0 80.0 78.0 81.0 82.0

6.0 6.0 7.0 6.0 7.0 3.0 8.0 9.0 8.0 5.0 7.0 8.0 6.0 8.0 8.0 7.0 7.0 6.0 4.0 8.0 7.0 4.0 2.0 2.0 3.0

/ / / 4.0 2.0 12.0 6.0 / 12.0 / / 2.0 1.0 / / 1.0 1.0 5.0 / / / / / / /

5.0 / / / / / / / / / 4.0 4.0 5.0 3.0 4.0 3.0 5.0 7.0 7.0 3.0 5.0 16.0 20.0 17.0 15.0

/ 3.0 2.0 / / / 3.0 / / / / / / / / / / / / / / / / / /

2.0 / 2.0 4.0 / 3.0 / 3.0 / 2.0 2.0 / 1.0 / / 2.0 2.0 1.0 / 3.0 / / / / /

Maximum particle size (mm)

Main particle size (mm)

Cementation type

0.24 0.4 0.56 0.26 0.25 0.23 0.32 0.16 0.28 0.64 0.67 0.56 0.4 0.48 0.64 0.68 0.72 0.81 0.56 0.48 0.72 0.52 0.6 0.45 0.56

0.06–0.13 0.13–0.25 0.13–0.25 0.13–0.25 0.06–0.25 0.06–0.13 0.06–0.13 0.06–0.13 0.06–0.13 0.25–0.50 0.13–0.50 0.13–0.25 0.13–0.25 0.13–0.25 0.13–0.25 0.13–0.25 0.13–0.25 0.13–0.25 0.06–0.25 0.03–0.48 0.06–0.25 0.13–0.25 0.13–0.25 0.06–0.25 0.13–0.25

pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed pore typed

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

S1 S2 S3 S4 S5 S6 S7 S8 S9 S10 S11 S12 S13 S14 S15 S16 S17 S18 S19 S20 S21 S22 S23 S24 S25

Depth (m)

L. Cai et al.

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

Φmc in the above formula stands for the sum of total cements amount and present porosity, mainly in the range of 2.00%~39.46% (av. 21.39%).

quartz cements (Giles et al., 1992; Peltonen et al., 2009; Metwally and Chesnokov, 2012), while the late quartz cements are mainly attributed to the dissolution of feldspar, which may be triggered by acidic fluids formed during the maturation of organic matter (Fig. 13; Zhang et al., 2015; Zhang et al., 2016; Du et al., 2018). Generally, authigenic quartzes occur in sandstone samples with thin or discontinuous clay rims, showing partial or whole overgrowths around quartz grains (up to 80–100 μm thick), and pore-lining and pore-filling morphologies (Fig. 12d–f). Silica cementation begins in the middle diagenetic stage A, where vitrinite reflectance (Ro) ranges between 0.62% and 1.30% (Cai et al., 2019, Fig. 13). As another predominant cement type, carbonate cements are formed mainly during the middle diagenetic stage B (1.3�Ro � 1.52) (Fig. 13) and extensively occlude the intergranular pores and microfractures (Fig. 12g and h). In thin sections, carbonates are sometimes found filling feldspar dissolution pores (Fig. 12i), also indicating the late diagenetic stage of carbonate cements. According to the analysis of hydrocarbon-bearing inclusions, the peak homogenization temperature in the quartz overgrowths ranges from 80 � C to 100 � C and is significantly lower than the peak temper­ ature of 130–150 � C in carbonate cements (Cai et al., 2019), which co­ incides with the proposed cementation sequence.

5.3.2. Destructive influence of cementation on pore-throat structures The reservoir space of the P2l tight sandstones is greatly reduced due to strong compaction in the South Yellow Sea Basin, but the pores and throats are compressed in roughly equal proportions, resulting in a poreto-throat ratio that does not exhibit variation (Xiao et al., 2016). Cementation, including carbonate, siliceous, and clay minerals, is the main factor in pore-throat occlusion and the resulting destruction of pore structures (Yang et al., 2014; Wilson et al., 2014; Xiao et al., 2016). (1) Cementation sequence in the P2l tight sandstones The observed results of thin sections, CL, and SEM analyses show that illite, kaolinite, and chlorite are the predominant clay cements and commonly adhere to the surface of particles (Fig. 12a–c), followed by authigenic quartz and carbonate (mainly calcite and dolomite) porefilling cements (Fig. 12d–h). Iron minerals and halite are minor ce­ ments identified in the study area. The clay minerals of the P2l tight sandstones are rich in illite (3.20% ~31.40%, av. 14.92%) but poor in montmorillonite (Table 2), and partial illite remains cellular in the clay transition state (Fig. 2i). Silica released from illitization and chloritization of smectites during early to middle diagenesis are partly responsible for the formation of early

(2) Further porosity reduction and throat blockage caused by cementation

Fig. 12. Diagenetic characteristics of the P2l tight sandstones in the borehole CSDP-2: (a) Illite adhered to particle surfaces of SEM; (b) Kaolinite adhered to particle surfaces of SEM; (c) Illite occluded throat of SEM; (d), (e) and (f) authigenic quartzes and carbonates of thin section; (g) carbonates filled into intergranular pores of CL; (h) carbonates filled into micro fractures of CL; (i) carbonates filled into feldspar dissolution pores of thin section ( ). I-illite; K-kaolinite; Dd-detrital quartz; Qaauthigenic quartz; Ca-carbonate; Dp-dissolution pore. 15

L. Cai et al.

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

Fig. 13. Schematic diagram of diagenetic sequence and pore-throat structures evolution of the P2l tight sandstones in the borehole CSDP-2.

After entering middle diagenetic stage A (Middle Jurassic–Late Cretaceous), the partial dissolution of feldspar and other aluminosilicate rocks by organic acids took place, with high contents of illite and kaolinite further formed in the Longtan Formation (Table 2; Zhang et al., 2015; Du et al., 2018). Clay cements occupy limited reservoir space and significantly reduce the permeability of reservoirs. Illite is mostly distributed in filamentous and flocculent shapes at the edge of primary intergranular pores (Fig. 12c), which not only reduces pore-throat radius but also increases throat curvature. Meanwhile, the filamentous illite is easily broken by the fluid in the reservoirs and then plugs the pores and throats (Fig. 12c), thus reducing the number and radius of effective pore throats and resulting in a direct decrease in permeability (Wilson et al., 2014; Liu et al., 2018). Although the intercrystalline micropores of kaolinite are well developed, the damage of its flake aggregates to intergranular pores is of greater importance. Under this diagenesis mechanism, the initial pore-throat structures begin to change from reticular to tubular (Fig. 13). The successive occurrence of authigenic quartz and carbonate ce­ ments has in essence occupied all the remaining reservoir spaces (Fig. 12d–h). The pore volume destroyed by cementation (Φcementation, %) ranges from 4.53% to 31.75% with an average of 14.52% (ac­ counting for approximately 39.31% of the initial porosity) as calculated using Eq. (9) (Xi et al., 2015), and ultimately results in the formation of isolated pore-throat structure (Fig. 13): Φcementation ¼ 2:5203P0:8457

Fig. 12i), together with the connectivity of microfractures (Fig. 4d–h) in the P2l tight sandstones, comprise the critical factors that influence the pore-throat structures and reservoir quality (Wang et al., 2017; Li et al., 2017; Liu et al., 2018). The early, strong compaction and clay and sili­ ceous cementation in this study area occludes some pore throats, which hinders acidic fluid flow and occurrence of large-scale dissolution (Surdam et al., 1989; Zhu et al., 2014). Consequently, the dissolution strength of the P2l tight sandstones is generally weak, and the plane porosity generated by dissolution is limited to 3.96%~6.94%, corre­ sponding to an increase in porosity of 3.20%~5.15% with an average of 3.43% (Fig. 13), which produces little improvement in reservoir quality. Microfractures also do little to promote reservoir porosity, but can connect pores and throats, and thus significantly improve permeability (Xi et al., 2016; Gao and Li, 2016; Cao et al., 2018; Zhao et al., 2019). 6. Conclusions In this study, multiple characterization approaches, including thin section, SEM, MICP, HPMI, RCMI, and NMR, were deployed to investi­ gate the pore-throat structures of P2l tight sandstones in borehole CSDP2, which can help us to understand the formation mechanism of tight sandstone reservoirs. The conclusions drawn from this study can be summarized as follows: (1) The P2l sandstones of the South Yellow Sea Basin with low compositional and textural maturity have poor porosity (0.2% ~2.7%, av. 1.26) and ultra-low permeability (0.0047–0.5438 mD, av. 0.0413 mD), typical of tight sandstone reservoirs. The reservoir space is predominantly composed of residual inter­ granular pores, dissolution pores, clay intercrystalline pores, and microfractures.

(9)

where P is the plane porosity of authigenic quartz and carbonate ce­ ments, ranging from 2.00% to 20.00% (Table 6). 5.3.3. Constructive influence of dissolution and cracking on pore-throat structures The irregular dissolution of feldspars and rock fragments (Fig. 4d; 16

L. Cai et al.

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

(2) The testing combination of MICP, HPMI, RCMI, and NMR can effectively characterize the overall pore-throat sizes of the P2l tight sandstones, which range from 0.00001 μm to 300 μm, while those interconnected pores and throats larger than 0.1 μm make a major contribution to the reservoir quality. (3) Based on the characterization of pore types and pore-throat connectivity, three types of pore-throat structures were identi­ fied in the P2l tight sandstones, categorized as lattice-like, tubular, and isolated pore-throat structures. (4) The sedimentary composition, types, and intensities of diagenesis caused the differences in pore-throat structures. Compaction and cementation account for the major destruction of pore-throat structures, destroying 49.81% and 39.31% of the initial porosity, respectively. Compaction reduces pore size, porosity, and permeability, but the connectivity rate of pore throats de­ creases with increasing cement content. Filamentous illite and flaky kaolinite occlude or even fill intergranular pores, thus changing lattice-like pore throats into tubular pore throats and reducing permeability. Authigenic quartz and carbonate cements are the key processes for the formation of isolated pore-throat structures. However, the increased porosity from dissolution is about 3.4%, less than 10% of the initial porosity.

oil and gas reservoir in lacustrine basin: the case of the fourth Member of Lower Cretaceous Quantou Formation in the southern Songliao Basin. Acta Pet. Sin. 39 (3), 247–265 (in Chinese with English abstract). Chen, L., Lu, Y.C., Fu, X.F., Xing, F.C., Wang, C., Luo, C., 2017. Oolitic shoal complexes characterization of the lower Triassic Feixianguan Formation in the Yuanba gas field, northeast Sichuan Basin, China. Mar. Pet. Geol. 83, 35–49. Clarkson, C.R., Jensen, J.L., Chipperfield, S., 2012. Unconventional gas reservoir evaluation: what do we have to consider? J. Nat. Gas Sci. Eng. 8, 9–33. Clarkson, C.R., Solano, N., Bustin, R.M., Bustin, A.M.M., Chalmers, G.R.L., He, L., Melnichenko, Y.B., Radli� nski, A.P., Blach, T.P., 2013. Pore structure characterization of North American shale gas reservoirs using USANS/SANS, gas adsorption, and mercury intrusion. Fuel 103, 606–616. Cnudde, V., Boone, M.N., 2013. High-resolution X-ray computed tomography in geosciences: a review of the current technology and applications. Earth Sci. Rev. 123, 1–17. Cyranoski, D., 2003. Ocean drilling: digging in. Nature 426 (6966), 492–494. Dai, C.S., Yang, Y.Q., Yan, G.J., 2005. Modelling of burial and hydrocarbon-generation histories of Meso-Paleozoic marine residual basins in South Yellow Sea and its geologic significance. Oil Gas Geol. 26 (1), 49–56 (in Chinese with English abstract). Desbois, G., Urai, J.L., Hemes, S., Schr€ oppel, B., Schwarz, J.O., Mac, M., Weiel, D., 2016. Multi-scale analysis of porosity in diagenetically altered reservoir sandstone from the Permian Rotliegend (Germany). J. Pet. Sci. Eng. 140, 128–148. Du, T., Xing, F.C., Lu, Y.C., Hu, H.R., Chen, P., 2018. Fluid characteristics and evolution of Longtan Formation tight sandstone cements in Huangqiao area, Lower Yangtze, China. J. Chengdu Univ. Technol. (Sci. Technol. Ed.) 45 (3), 292–302 (in Chinese with English abstract). Fang, T., Zhang, L.K., Liu, N.G., Zhang, L.Q., Wang, W.M., Yu, L., Li, C., Lei, Y.H., 2018. Quantitative characterization of pore structure of the Carboniferous–Permian tight sandstone gas reservoirs in eastern Linqing depression by using NMR technique. Pet. Res. 3 (2), 110–123. Gao, H., Cao, J., Wang, C., He, M.Q., Dou, L.B., Huang, X., Li, T.T., 2019. Comprehensive characterization of pore and throat system for tight sandstone reservoirs and associated permeability determination method using SEM, rate-controlled mercury and high pressure mercury. J. Pet. Sci. Eng. 174, 514–524. Gao, H., Li, H.A., 2016. Pore structure characterization, permeability evaluation and enhanced gas recovery techniques of tight gas sandstones. J. Nat. Gas Sci. Eng. 28, 536–547. Giles, M.R., Stevenson, S., Martin, S.V., Cannon, S.J.C., Hamilton, P.J., Marshall, J.D., Samways, G.M., 1992. The reservoir properties and diagenesis of the Brent Group: a regional perspective. Geol. Soc. Spec. Publ. 61 (1), 289–327. Gong, Y.J., Liu, S.B., Zhu, R.K., Liu, K.Y., Tang, Z.X., Lin, J., 2015. Low limit of tight oil flowing porosity: application of high-pressure mercury intrusion in the fourth member of Cretaceous Quantou Formation in southern Songliao Basin, NE China. Pet. Explor. Dev. 42 (5), 745–752. Guo, X.W., Zhang, X.H., Wu, Z.Q., Xiao, G.L., Hou, F.H., Liu, J., 2019. Scientific objectives and preliminary progresses of CSDP-2 well in continental Shelf drilling program. J. Jilin Univ. (Earth Sci. Ed.) 49 (1), 1–12 (in Chinese with English abstract). Guo, X.W., Zhu, X.Q., Mu, L., Xu, Y., Pang, Y.M., Cai, L.X., Zhang, X.H., Liu, J., Lu, H.N., 2017. Discovery of Permian-Triassic ammonoids in the central Uplift of the south Yellow Sea and its geological implications. Mar. Geol. Quat. Geol. 37 (3), 121–128 (in Chinese with English abstract). Hemes, S., Desbois, G., Urai, J.L., Schr€ oppel, B., Schwarz, J.O., 2015. Multi-scale characterization of porosity in Boom Clay (HADES-level, Mol, Belgium) using a combination of X-ray μ-CT, 2D BIB-SEM and FIB-SEM tomography. Microporous Mesoporous Mater. 208, 1–20. Hu, F., 2010. Hydrocarbon resources potential study in Mesozoic-Palaeozoic marine strata in the south Yellow Sea basin. Offshore Oil 30 (3), 1–8 (in Chinese with English abstract). Jia, C.Z., Zheng, M., Zhang, Y.F., 2012. Unconventional hydrocarbon resources in China and the prospect of exploration and development. Pet. Explor. Dev. 39 (2), 139–146. Koeberl, C., Pittarello, L., Reimold, W.U., Raschke, U., Brigham-Grette, J., Melles, M., Minyuk, P., Spray, J., 2013. El’gygytgyn impact crater, Chukotka, Arctic Russia: impact cratering aspects of the 2009 ICDP drilling project. Meteorit. Planet. Sci. 48 (7), 1108–1129. Korsch, R.J., Mai, H.Z., Sun, Z.C., Gorter, J.D., 1991. The Sichuan basin, southwest China: a late proterozoic (Sinian) petroleum province. Precambrian Res. 54 (1), 45–63. Lai, J., Wang, G.W., 2015. Fractal analysis of tight gas sandstones using high-pressure mercury intrusion techniques. J. Nat. Gas Sci. Eng. 24, 185–196. Lai, J., Wang, G.W., Cao, J.T., Xiao, C.W., Wang, S., Pang, X.J., Dai, Q.Q., He, Z.B., Fan, X.Q., Yang, L., Qin, Z.Q., 2018. Investigation of pore structure and petrophysical property in tight sandstones. Mar. Pet. Geol. 91, 179–189. Lai, J., Wang, G.W., Wang, Z.Y., Chen, J., Pang, X.J., Wang, S.C., Zhou, Z.L., He, Z.B., Qin, Z.Q., Fan, X.Q., 2018. A review on pore structure characterization in tight sandstones. Earth Sci. Rev. 177, 436–457. Li, P., Zheng, M., Bi, H., Wu, S.T., Wang, X.R., 2017. Pore throat structure and fractal characteristics of tight oil sandstone: a case study in the Ordos Basin, China. J. Pet. Sci. Eng. 149, 665–674. Li, W.Y., Liu, Y.X., Xu, J.C., 2014. Onshore-offshore structure and hydrocarbon potential of the south Yellow Sea. J. Asian Earth Sci. 90 (4), 127–136. Lin, W., Li, X., Yang, Z., Manga, M., Fu, X., Xiong, S., Gong, A., Chen, G., Li, H., Pei, L., Li, S., Zhao, X., Wang, X., 2019. Multiscale digital porous rock reconstruction using template matching. Water Resour. Res. 55 (8), 6911–6922. Lin, W., Li, X.Z., Yang, Z.M., Wang, J., Xiong, S.C., Luo, Y.T., Wu, G.M., 2017. Construction of dual pore 3-D digital cores with a hybrid method combined with

Acknowledgements This work is supported by the National Natural Science Foundation of China (No. 41906188; No. 41776081;No. 41806057), the National Marine Geology Project of China (DD20160147; DD20190365). and the Special Fund for the Taishan Scholar Program of Shandong Province (No. TS201511061). We also thank the China University of Petroleum (East China) for testing and providing data. Appendix A. Supplementary data Supplementary data to this article can be found online at https://doi. org/10.1016/j.petrol.2019.106733. References Albrecht, D., Reitenbach, V., 2015. Investigations on fluid transport properties in the North-German Rotliegend tight gas sandstones and applications. Environ. Earth Sci. 73 (10), 5791–5799. Anovitz, L.M., Cole, D.R., 2015. Characterization and analysis of porosity and pore structures. Rev. Mineral. Geochem. 80 (1), 61–164. Arthur, M.A., Cole, D.R., 2014. Unconventional hydrocarbon resources: prospects and problems. Elements 10 (4), 257–264. Bai, B., Zhu, R.K., Wu, S.T., Yang, W.J., Gelb, J., Gu, A., Zhang, X.X., Su, L., 2013. Multiscale method of nano(micro)-CT study on microscopic pore structure of tight sandstone of Yanchang Formation, Ordos Basin. Pet. Explor. Dev. 40 (3), 354–358. Berg, C.F., Lopez, O., Berland, H., 2017. Industrial applications of digital rock technology. J. Pet. Sci. Eng. 157, 131–147. Bjørlykke, K., 2014. Relationships between depositional environments, burial history and rock properties. Some principal aspects of diagenetic process in sedimentary basins. Sediment. Geol. 301 (3), 1–14. Borkloe, J.K., Pan, R.F., Jin, J.N., Nyantakyi, E.K., Meng, J.H., 2016. Evaluation of shale gas potential of Cambriam Jiulaodong Formation in Wei-201 well block in Sichuan Basin, China. AAPG (Am. Assoc. Pet. Geol.) Bull. 4 (2), T123–T140. Cai, L.X., Guo, X.W., Xu, Z.H., Zhang, X.H., Li, W.Q., Xiao, G.L., Zhu, X.Q., Hou, F.H., 2018. Depositional environment of upper Paleozoic in the central Uplift of the south Yellow Sea basin. Acta Sedimentol. Sin. 36 (4), 695–705 (in Chinese with English abstract). Cai, L.X., Wang, J., Guo, X.W., Xiao, G.L., Zhu, X.Q., Pang, Y.M., 2017. Characteristics on sedimentary facies and source rocks of Mesozoic-Paleozoic in the Central Uplift of South Yellow Sea: a case study of the CSDP-2 overall coring well. J. Jilin Univ. (Earth Sci. Ed.) 47 (4), 1030–1046 (in Chinese with English abstract). Cai, L.X., Xiao, G.L., Guo, X.W., Wang, J., Wu, Z.Q., Li, B.G., 2019. Assessment of Mesozoic and upper Paleozoic source rocks in the south Yellow Sea basin based on the continuous borehole CSDP-2. Mar. Pet. Geol. 101, 30–42. Cao, Q., Ye, J.R., Shi, W.Z., Chen, C.F., 2009. Preliminary prediction and evaluation of source rocks in low-exploration basins: a case study on the northeast sag of the Northern South Yellow Sea Basin in China. Acta Pet. Sin. 30 (4), 522–529 (in Chinese with English abstract). Cao, Y.C., Xi, K.L., Liu, K.Y., Zhu, R.K., Yuan, G.H., Zhang, X.X., Song, M.S., 2018. Reservoir properties characterization and its genetic mechanism for tight sandstone

17

Journal of Petroleum Science and Engineering xxx (xxxx) xxx

L. Cai et al. physical experiment method and numerical reconstruction method. Transp. Porous Media 120 (1), 227–238. € Litt, T., Krastel, S., Sturm, M., Kipfer, R., Orcen, S., Heumann, G., Franz, S.O., Ülgen, U. B., Niessen, F., 2009. ‘PALEOVAN’, international continental scientific drilling program (ICDP): site survey results and perspectives. Quat. Sci. Rev. 28 (15–16), 1555–1567. Liu, H.L., Yang, Y.Y., Wang, F.Q., Deng, X.Q., Liu, Y., Nan, J.X., Wang, J., Zhang, H.J., 2018. Micro pore and throat characteristics and origin of tight sandstone reservoirs: a case study of the Triassic Chang 6 and Chang 8 members in Longdong area, Ordos Basin, NW China. Pet. Explor. Dev. 45 (2), 239–250. Liu, X.F., Wang, J.F., Ge, L., Hu, F.L., Li, C.L., Li, X., Yu, J., Xu, H., Lu, S.F., Xue, Q.Z., 2017. Pore-scale characterization of tight sandstone in Yanchang Formation Ordos Basin China using micro-CT and SEM imaging from nm- to cm-scale. Fuel 209, 254–264. Liu, X.J., Xiong, J., Liang, L.X., 2015. Investigation of pore structure and fractal characteristics of organic-rich Yanchang formation shale in central China by nitrogen adsorption/desorption analysis. J. Nat. Gas Sci. Eng. 22, 62–72. Lundegard, P.D., 1992. Sandstone porosity loss—a big picture “view of the importance of compaction”. J. Sediment. Res. 62 (2), 250–260. Lyu, C.H., Ning, Z.F., Wang, Q., Chen, M.Q., 2018. Application of NMR T2 to pore size distribution and movable fluid distribution in tight sandstones. Energy Fuels 32 (2), 1395–1405. Metwally, Y.M., Chesnokov, E.M., 2012. Clay mineral transformation as a major source for authigenic quartz in thermo-mature gas shale. Appl. Clay Sci. 55, 138–150. Nelson, P.H., 2009. Pore-throat sizes in sandstones, tight sandstones, and shales. AAPG (Am. Assoc. Pet. Geol.) Bull. 93 (3), 329–340. Pang, Y.M., Guo, X.W., Han, Z.Z., Zhang, X.H., Zhu, X.Q., Hou, F.H., Han, C., Song, Z.G., Xiao, G.L., 2019. Mesozoic–Cenozoic denudation and thermal history in the Central Uplift of the South Yellow Sea basin and the implications for hydrocarbon systems: constraints from the CSDP-2 borehole. Mar. Pet. Geol. 99, 355–369. Pang, Y.M., Guo, X.W., Zhang, X.H., Han, Z.Z., Zhu, X.Q., Hou, F.H., Cai, L.X., 2019. Denudation of indosinian unconformity and tectonic evolution in the central Uplift of South Yellow Sea Basin—insights from CSDP-2 well. Geotect. Metallogenia 43 (2), 235–245 (in Chinese with English abstract). Pang, Y.M., Zhang, X.H., Guo, X.W., Xiao, G.L., Zhu, X.Q., 2017. Mesozoic and cenozoic tectono-thermal evolution modeling in the northern South Yellow Sea Basin. Chin. J. Geophys. 60 (8), 3177–3190 (in Chinese with English abstract). Pang, Y.M., Zhang, X.H., Guo, X.W., Xiao, G.L., Han, Z.Z., 2017. Basin modeling in the initial stage of exploration: a case study from the north subbasin of the south yellow Sea Basin. Acta Oceanol. Sin. 36, 65–78. Pang, Y.M., Zhang, X.H., Xiao, G.L., Guo, X.W., Wen, Z.H., Wu, Z.Q., Zhu, X.Q., 2017. Characteristics of Meso-cenozoic igneous complexes in the south Yellow Sea basin, lower Yangtze craton of eastern China and the tectonic setting. Acta Geol. Sin. (Engl. Ed.) 91 (3), 971–987. Pape, H., Clauser, C., 2009. Improved interpretation of nuclear magnetic resonance T1 and T2 distributions for permeability prediction: simulation of diffusion coupling for a fractal cluster of pores. Pure Appl. Geophys. 166, 949–968. Peltonen, C., Marcussen, Ø., Bjørlykke, K., Jahren, J., 2009. Clay mineral diagenesis and quartz cementation in mudstones: the effects of smectite to illite reaction on rock properties. Mar. Pet. Geol. 26 (6), 887–898. Philip, H.N., 2009. Pore-throat sizes in sandstones, tight sandstones, and shales. AAPG (Am. Assoc. Pet. Geol.) Bull. 93 (3), 329–340. Pittman, E.D., 1992. Relationship of porosity and permeability to various parameters derived from mercury injection-capillary pressure curves for sandstone. AAPG (Am. Assoc. Pet. Geol.) Bull. 76 (2), 191–198. Rahner, M.S., Halisch, M., Fernandes, C.P., Weller, A., Santos, V.S.S., 2018. Fractal dimensions of pore spaces in unconventional reservoir rocks using X-ray nano- and micro-computed tomography. J. Nat. Gas Sci. Eng. 55, 298–311. Rezaee, R., Saeedi, A., Clennell, B., 2012. Tight gas sands permeability estimation from mercury injection capillary pressure and nuclear magnetic resonance data. J. Pet. Sci. Eng. 88–89, 92–99. Rosenbrand, E., Fabricius, I.L., Fisher, Q., Grattoni, C., 2015. Permeability in Rotliegend gas sandstones to gas and brine as predicted from NMR, mercury injection and image analysis. Mar. Pet. Geol. 64, 189–202. Sakdinawat, A., Attwood, D., 2010. Nanoscale X-ray imaging. Nat. Photonics 4 (12), 840–848. Sakhaee-Pour, A., Bryant, S.L., 2014. Effect of pore structure on the producibility of tight-gas sandstones. AAPG (Am. Assoc. Pet. Geol.) Bull. 98 (4), 663–694. Scherer, M., 1987. Parameters influencing porosity in sandstones: a model for sandstone porosity predication. AAPG (Am. Assoc. Pet. Geol.) Bull. 71 (5), 485–491. Schmitt, M., Fernandes, C.P., Neto, J.A.B.D.C., Wolf, F.G., Santos, V.S.S.D., 2013. Characterization of pore systems in seal rocks using nitrogen gas adsorption combined with mercury intrusion capillary pressure techniques. Mar. Pet. Geol. 39 (1), 138–149. Schmitt, M., Fernandes, C.P., Wolf, F.G., Neto, J.A.B.D.C., Rahner, C.P., Santos, V.S.S.D., 2015. Characterization of Brazilian tight gas sandstones relating permeability and Angstrom-to micron-scale pore structures. J. Nat. Gas Sci. Eng. 27 (2), 785–807. Shanley, K.W., Cluff, R.M., 2015. The evolution of pore-scale fluid-saturation in low permeability sandstone reservoirs. AAPG (Am. Assoc. Pet. Geol.) Bull. 99, 1957–1990. Spencer, C.W., 1987. Hydrocarbon generation as a mechanism for overpressuring in Rocky mountain region. AAPG (Am. Assoc. Pet. Geol.) Bull. 71 (4), 368–388. Stein, R., 2014. Chapter 3.1–introduction: environmental change, processes and effects—new insights from Integrated Ocean drilling program (2003–2013). Dev. Mar. Geol. 7, 255–258.

Su, K.M., Lu, J.G., Zhang, G.W., Chen, S.J., Li, Y., Xiao, Z.L., Wang, P., Qiu, W., 2018. Origin of natural gas in Jurassic Da’anzhai Member in the western part of central Sichuan Basin, China. J. Pet. Sci. Eng. 167, 890–899. Sun, H.F., Belhaj, H., Tao, G., Vega, S., Liu, L.F., 2019. Rock properties evaluation for carbonate reservoir characterization with multi-scale digital rock images. J. Pet. Sci. Eng. 175, 654–664. Surdam, R.C., 1997. A New Paradigm for Gas Exploration in Anomalously Pressured “Tight Gas Sands” in the Rocky Mountain Laramide Basins, AAPG Memoir 67: Seals, Traps, and the Petroleum System, pp. 283–298. Surdam, R.C., Crossey, L.J., Hagen, E.S., Heasler, H.P., 1989. Organic-inorganic interactions and sandstone diagenesis. AAPG (Am. Assoc. Pet. Geol.) Bull. 73 (1), 1–23. Tan, S.Z., Chen, C.F., Xu, Z.Z., Hou, K.W., Wang, J., 2018. Geochemical characteristics and hydrocarbon generation potentials of Paleozoic source rocks in the Southern Yellow Sea basin. Mar. Geol. Quat. Geol. 38 (3), 116–124 (in Chinese with English abstract). Tang, X.L., Jiang, Z.X., Jiang, S., Li, Z., 2016. Heterogeneous nanoporosity of the Silurian Longmaxi Formation shale gas reservoir in the Sichuan Basin using the QEMSCAN, FIB-SEM, and nano-CT methods. Mar. Pet. Geol. 78, 99–109. Volokitin, Y., Looyestijn, W., 2001. A practical approach to obtain primary drainage capillary pressure curves from NMR core and log data. Petrophysics 42 (4), 334–343. Wang, G.W., Chang, X.C., Yin, W., Li, Y., Song, T.T., 2017. Impact of diagenesis on reservoir quality and heterogeneity of the Upper Triassic Chang 8 tight oil sandstones in the Zhenjing area, Ordos Basin, China. Mar. Pet. Geol. 83, 84–96. Wang, H.J., Ma, F., Tong, X.G., Liu, Z.D., Zhang, X.S., Wu, Z.Z., Li, D.H., Wang, B., Xie, Y. F., Yang, L.Y., 2016. Assessment of global unconventional oil and gas resources. Pet. Explor. Dev. 43 (6), 925–940. Wang, W., Jiang, Y.L., Swennen, R., Yuan, J., Liu, J.D., Zhang, S.M., 2018. Pore-throat characteristics of tight sandstone reservoirs composed of gravity flow sediments: Yingcheng Formation, Longfengshan sag, China. J. Pet. Sci. Eng. 171, 646–661. Wei, G.Q., Chen, G.S., Du, S.M., Zhang, L., Yang, W., 2008. Petroleum systems of the oldest gas field in China: neoproterozoic gas pools in the Weiyuan gas field, Sichuan Basin. Mar. Pet. Geol. 25 (4–5), 371–386. Wilson, L., Wilson, M.J., Green, J., Patey, I., 2014. The influence of clay mineralogy on formation damage in North Sea reservoir sandstones: a review with illustrative examples. Earth Sci. Rev. 134 (1), 70–80. Worden, R.H., Mayall, M., Evans, I.J., 2000. The effect of ductilelithic sand grains and quartz cement on porosity and permeability in Oligocene and Lower Miocene clastics, south China sea: prediction of reservoir quality. AAPG (Am. Assoc. Pet. Geol.) Bull. 84 (3), 345–359. Wu, H., Zhang, C.L., Ji, Y.L., Liu, R.E., Wu, H., Zhang, Y.Z., Geng, Z., Zhang, Y.L., Yang, J. Q., 2018. An improved method of characterizing the pore structure in tight oil reservoirs: Integrated NMR and constant-rate-controlled porosimetry data. J. Pet. Sci. Eng. 166, 778–796. Xi, K.L., Cao, Y.C., Haile, B.G., Zhu, R.K., Jahren, J., Bjørlykke, K., Zhang, X.X., Hellevang, H., 2016. How does the pore-throat size control the reservoir quality and oiliness of tight sandstones? The case of the Lower Cretaceous Quantou Formation in the southern Songliao Basin, China. Mar. Pet. Geol. 76, 1–15. Xi, K.L., Cao, Y.C., Wang, Y.Z., Haile, B.G., Zhang, X.X., Zhang, J.H., Jin, J.H., 2015. Diagenesis and porosity-permeability evolution of low permeability reservoirs: a case study of Jurassic Sangonghe Formation in Block 1, central Junggar Basin, NW China. Pet. Explor. Dev. 42 (4), 475–485. Xiao, D.S., Lu, S.F., Lu, Z.Y., Huang, W.B., Gu, M.W., 2016. Combining nuclear magnetic resonance and rate-controlled porosimetry to probe the pore-throat structure of tight sandstones. Pet. Explor. Dev. 43 (6), 1049–1059. Xiao, G.L., Cai, L.X., Guo, X.W., Wu, Z.Q., Dong, H.P., Li, B.G., 2017. Detailed assessment of Meso-Paleozoic hydrocarbon source rocks: implications from well CSDP-2 on the central Uplift of the south Yellow Sea basin. Mar. Geol. Front. 33 (12), 24–36 (in Chinese with English abstract). Xu, Z.J., Liu, L.F., Wang, T.G., Wu, K.J., Dou, W.C., Song, X.P., Feng, C.Y., Li, X.Z., Ji, H. T., Yang, Y.S., Liu, X.X., 2017. Characteristics and controlling factors of lacustrine tight oil reservoirs of the Triassic Yanchang Formation chang 7 in the Ordos Basin, China. Mar. Pet. Geol. 82, 265–296. Yang, R., Hu, Q.H., He, S., Hao, F., Guo, X.S., Yi, J.Z., He, X.P., 2017. Pore structure, wettability and tracer migration in four leading shale formations in the Middle Yangtze Platform, China. Mar. Pet. Geol. 89, 415–427. Yang, R.C., Fan, A.P., Loon, T.V., Han, Z.Z., Wang, X.P., 2014. Depositional and diagenetic controls on sandstone reservoirs with low porosity and low permeability in the eastern Sulige gas field, China. Acta Geol. Sin. (Engl. Ed.) 88 (5), 1513–1534. Yu, J., Ma, J., Lu, J.G., Cao, Y., Feng, S.B., Li, W.C., 2015. Application of mercury injection and rate-controlled mercury penetration in quantitative characterization of microscopic pore structure of tight reservoirs: a case study of the Chang 7 reservoir in Huachi-Heshui area, the Ordos Basin. Pet. Geol. Exp. 37 (6), 789–795 (in Chinese with English abstract). Yuan, Y., Chen, Y.W., Liang, J., Zhang, P.H., 2017. Source-reservoir-seal assemblage of marine Mesozoic-Paleozoic in South Yellow Sea Basin by land-ocean comparison. Pet. Geol. Exp. 39 (2), 195–212 (in Chinese with English abstract). Zhang, L., Zou, H.Y., Hao, F., Li, P.P., Yang, S., Song, Y., 2017. Characteristics and densification causes and of highly-tight sandstone of the Xujiahe Formation (T3x2) in the Yuanba area, Northeastern Sichuan Basin. Acta Geol. Sin. 91 (9), 2105–2118 (in Chinese with English abstract). Zhang, N., Lin, C.M., Yu, H., Zhang, X., 2015. Characteristics and diagenetic evolution model of the Permian Longtan Formation reservoir in the Huangqiao area of the lower Yangtze region. J. Geol. 39 (4), 535–542 (in Chinese with English abstract).

18

L. Cai et al.

Journal of Petroleum Science and Engineering xxx (xxxx) xxx and gas bearing basins and its natural gas accumulation. J. Asian Earth Sci. 50 (50), 88–104. Zhu, H.H., Zhong, D.K., Zhang, Y.X., Sun, H.T., Du, B.Q., Meng, H., Zhang, C.W., Yang, Z., 2014. Pore types and controlling factors on porosity and permeability of Upper Triassic Xujiahe tight sandstone reservoir in Southern Sichuan Basin. Oil Gas Geol. 35 (1), 65–76 (in Chinese with English abstract). Zou, C.N., Yang, Z., Tao, S.Z., Li, W., Wu, S.T., Hou, L.H., Zhu, R.K., Yuan, X.J., Wang, L., Gao, X.H., Jia, J.H., Guo, Q.L., Bai, B., 2012. Nano-hydrocarbon and the accumulation in coexisting source and reservoir. Pet. Explor. Dev. 39 (1), 15–32. Zou, C.N., Yang, Z., Zhu, R.K., Zhang, G.S., Hou, L.H., Wu, S.T., Tao, S.Z., Yuan, X.J., Dong, D.Z., Wang, Y.M., Wang, L., Huang, J.L., Wang, S.F., 2015. Progress in China’s unconventional oil & gas exploration and development and theoretical technologies. Acta Geol. Sin. (Engl. Ed.) 89 (3), 938–971. Zou, C.N., Zhang, G.S., Yang, Z., Tao, S.Z., Hou, L.H., Zhu, R.K., Yuan, X.J., Ran, Q.Q., Li, D.H., Wang, Z.P., 2013. Concepts, characteristics, potential and technology of unconventional hydrocarbons: on unconventional petroleum geology. Pet. Explor. Dev. 40 (4), 413–428. Zou, C.N., Zhu, R.K., Liu, K.Y., Su, L., Bai, B., Zhang, X.X., Yuan, X.J., Wang, J.H., 2012. Tight gas sandstone reservoirs in China: characteristics and recognition criteria. J. Pet. Sci. Eng. 88–89, 82–91.

Zhang, P.H., Chen, J.W., Liang, J., Gong, J.M., Yuan, Y., Dong, G., Zhang, Y.G., 2016. Diagenesis and characteristics of the marine reservoirs in the south Yellow Sea basin. Mar. Geol. Front. 32 (1), 35–42 (in Chinese with English abstract). Zhang, Y.G., Liang, J., 2014. Sedimentary system characteristics and their sedimentary evolution from the Permian to Triassic in the southern Yellow Sea basin. J. Jilin Univ. (Earth Sci. Ed.) 44 (5), 1406–1418 (in Chinese with English abstract). Zhao, P.Q., Wang, Z.L., Sun, Z.C., Cai, J.C., Wang, L., 2017. Investigation on the pore structure and multifractal characteristics of tight oil reservoirs using NMR measurements: Permian Lucaogou Formation in Jimusaer Sag, Junggar Basin. Mar. Pet. Geol. 86, 1067–1081. Zhao, X.L., Yang, Z.M., Lin, W., Xiong, S.C., Luo, Y.T., Wang, Z.Y., Chen, T., Xia, D.B., Wu, Z.K., 2019. Study on pore structures of tight sandstone reservoirs based on nitrogen adsorption, high-pressure mercury intrusion, and rate-controlled mercury intrusion. J. Energy Resour. Technol. Trans. ASME 141 (11), 112903-112903-11. Zhao, X.L., Yang, Z.M., Lin, W., Xiong, S.C., Wei, Y.Y., 2018. Characteristics of microscopic pore-throat structure of tight oil reservoirs in Sichuan Basin measured by rate-controlled mercury injection. Open Phys. 16, 675–684. Zhu, G.Y., Gu, L.J., Su, J., Dai, J.X., Ding, W.L., Zhang, J.C., Song, L.C., 2012. Sedimentary association of alternated mudstones and tight sandstones in China’s oil

19