The reservoir characterization and shale gas potential of the Niutitang formation: Case study of the SY well in northwest Hunan Province, South China

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Contents lists available at ScienceDirect

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

The reservoir characterization and shale gas potential of the Niutitang formation: Case study of the SY well in northwest Hunan Province, South China

T

Zhaodong Xia,b,c, Shuheng Tanga,b,c,∗, Jing Wanga,b,c a

School of Energy Resource, China University of Geosciences, Beijing, China Key Laboratory of Marine Reservoir Evolution and Hydrocarbon Enrichment Mechanism, Ministry of Education, China c Key Laboratory of Strategy Evaluation for Shale Gas, Ministry of Land and Resources, China b

A R T I C LE I N FO

A B S T R A C T

Keywords: Middle and upper Yangtze regions The lower cambrian shale Niutitang formation Pore structure Shale gas

Marine shale is extensive throughout the subsurface, and commercially well-developed as natural gas producers throughout south China, attracting attention in recent years by both politicians and scientists on a variety of issues. Previous research on shale has predominantly focused on the Longmaxi and Niutitang Formations in the Sichuan Basin, but rarely on the periphery in northwestern Hunan Province where the Niutitang Formation has long been known as a potential shale gas reservoir. In this study, hydrocarbon generation potential, reserving performance, and shale gas potential of the Niutitang Formation from northwestern Hunan Province was studied to determine its gas producing potential. Total organic carbon (TOC) analysis, rock-eval pyrolysis, vitrinite reflectance and organic maceral analysis, mercury intrusion, nitrogen adsorption, and methane adsorption were run on a total of 52 samples from the SY well consisting of the Upper and Lower Members of the Niutitang Formation. Analysis of the results showed that the Niutitang shale has high TOC content (2.37% on average), high thermal maturity (3.15% on average), and oil-prone kerogen types, indicating good shale gas potential in the study area. The shale consists of relatively high concentrations of brittle minerals (quartz and feldspar, 69% on average) and low clay content (22% on average), indicating a brittle shale. The shale is a tight formation, with measured porosity averaging 2.66% (free gas potential) and methane adsorption capacity averaged 1.55 cm3/g (adsorbed gas potential). TOC and burial depth control reservoir space of the shale. The Lower Member samples had lower porosity but higher methane adsorption capacity than those from the Upper Member, indicating that a relatively larger amount of gas may occur as adsorbed gas in the Lower Member. It is suggested that the Lower Member of the Niutitang Formation is the ideal location for exploration and development of shale gas due to consistently thick organic-rich layers, high TOC content, high brittleness index, and stronger adsorption capacity.

1. Introduction Shale gas is a new important green energy resource that has been successfully commercially developed in the US over the last century (Curtis, 2002; Clackson et al., 2016). North American shale primarily features high total organic carbon (TOC) content typically in the mature to over mature stage, high brittle mineral content with the development of fractures, shallow to moderate depth, and high thermogenic gas content, which are conducive factors for exploration and development (Ross and Bustin, 2008, 2009; Wang et al., 2016). Based on the success of shale gas development in the US, exploration and development of marine shale gas in south China, particularly in the Sichuan Basin, has

∗

remarkably progressed in recent years, and four national shale gas demonstration zones in south China are currently in operation (Zou et al., 2015; Zhao et al., 2016). Many previous studies have focused on the Longmaxi and Niutiang Formations in the Sichuan Basin where exploration is at a relatively mature stage. Within this region, the shale distribution characteristics, geological conditions for shale gas formation, hydrocarbon accumulation mechanisms, and gas resource assessments have been widely studied (Nie et al., 2011; Chen et al., 2011; Tan et al., 2014). Significant marine shale gas production in the Sichuan Basin has increased confidence of the Chinese government to further explore the entire Yangtze Platform of south China. Shale is defined as an intricate and heterogeneous porous media

Corresponding author. School of Energy resource, China University of Geosciences, Beijing, China. E-mail address: [email protected] (S. Tang).

https://doi.org/10.1016/j.petrol.2018.08.002 Received 19 February 2018; Received in revised form 27 July 2018; Accepted 1 August 2018 Available online 03 August 2018 0920-4105/ © 2018 Elsevier B.V. All rights reserved.

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Z. Xi et al.

studies exist on the shale gas reservoir and accumulation conditions as it is still the early exploration stage of shale gas in northwest Hunan Province. In 2015, shale gas well SY was developed by the China National Administration of Coal Geology in this area. A series of preliminary experiments on shale samples collected from well SY consisted of the geochemistry, reservoir characteristics, and shale gas potential of the Niutiang Formation. The data and information not only provided an important dataset for future Niutitang Formation exploration, but also offered practical significance for shale gas exploration, evaluation, and production in the Niutitang Formation.

with complex pore systems that lead to different shale gas storage mechanisms and transition mechanisms. This makes it hard to predict the spatial distribution and availability of shale gas in a region (Jiang et al., 2017; Guo et al., 2018; Xi et al., 2018a). Therefore, practical exploration of shale gas must be in accordance with reliable source and reservoir evaluations (Curtis, 2002; Huang et al., 2012; Hao et al., 2013). Shale gas reservoirs have been characterized as a self-contained source reservoir system, and thus geochemical characteristics, mainly including TOC content, vitrinite reflectance (Ro), rock-eval pyrolysis data, and kerogen types, have proven essential for explaining shale gas potential and observed productivity patterns (Chen et al., 2011). Additionally, mineral composition, pore structure, and gas sorption capacity are also the important parameters for evaluating shale gas reservoirs. Free gas can be stored in larger pores and fractures, while adsorbed gas is generally stored in micropores and fine mesopores that are in contact with organic matter (OM) and clay minerals; residual oil volume mainly controls gas in the solution (Labani et al., 2013). The free gas content directly controls the initial production and ultimately the recoverable shale gas content, while adsorbed gas mainly controls the late period of shale gas development (Wang et al., 2013). Therefore, to systematically evaluate a shale gas reservoir, knowing the main indicators for reservoir performance is critical to accurately evaluate and predict shale gas volume as well as recoverable gas content. More than 200 wells were drilled through 2016 and industrial gas flows were established in the Wufeng-Longmaxi Formations, whereas only an estimated 40 wells were drilled into the Niutitang Formation. Moreover, there are still limited wells or production history for evaluating shale gas potential of the Niutitang Formation, especially along the periphery of Sichuan Basin. Hunan Province is adjacent to Sichuan Basin, where thick organic-rich black shale exists in the Niutitang Formation (Fig. 1). Recoverable shale gas resources from the Niutitang Formation have been estimated to be approximately 3.23 × 1012 m3 in northwestern Hunan Province. Shale gas was obtained from well CY-1 (Lin et al., 2014), which indicated that northwest Hunan Province has high shale gas resource potential. Prior studies in this area have focused on structural features, sequence stratigraphic framework, depositional environment, and shale distribution patterns (Hu et al., 2016; Tang et al., 2016; Wan et al., 2017). However, a limited number of in-depth

2. Geological setting The Yangtze area in South China evolved to an open shelf during the Cambrian, which featured prevailing anoxic bottom waters in most places, including southern Sichuan, northern Guizhou, and western Hunan provinces, and the Niutitang shales were widely deposited across the entire Yangtze area (Yang et al., 2016). In the Early Cambrian, deposited sediments consisted of mainly black shales (including carbonaceous shale and siliceous shale) due to the deep water oxygen deficiency. As sea level dropped and oxygen content increased in the late stage of the Early Cambrian, the sediments deposited changed to dark-gray or gray-green colored shales (including silty shale and mudstone). This change in lithological sequence of the Niutitang Formation is controlled by sedimentary facies change. The thickness of the Niutitang Formation generally is greater than 40 m and increases eastwards across the Yangtze area. Ro values of the Niutitang shale are commonly 1.4%–5.0%, with most values greater than 3% in most places of the Yangtze area (Xi et al., 2018b), and the TOC content ranges between 0.15% and 39.7%, with most values greater than 2%. The Niutitang Formation in northwest Hunan Province are suggested to be favorable shale gas reservoirs, according to the distribution patterns of thickness, burial depth, TOC, and Ro values of the Niuttiang shale within the entire Yangtze area (Yan et al., 2016). In addition, many scholars have presented data showing high TOC or high primary productivity and anoxic depositional environment during the Niutitang Formation (Yuan et al., 2014; Cai et al., 2015; Xiang et al., 2016), indicating that if shale gas can be found in the study area, it is quite

Fig. 1. Location of the study area in northwest Hunan Province of southern China.

688

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Z. Xi et al.

3. Samples and methods 3.1. Samples In this study, 52 core samples were obtained from the vertical shale gas well SY in the northwestern Hunan Province, including 25 samples from the Upper Member and 27 samples from the Lower Member (Table 1). Table 1 lists the Niutitang shale samples along with the measurements taken on each sample. A relatively complete experimental workflow was conducted, including TOC and maceral composition analysis, thermal maturity analysis, X-ray diffraction (XRD) analysis, optical microscope (OPM) and scanning electron microscope (SEM), porosity tests, mercury intrusion, nitrogen (N2) adsorption, methane adsorption, and rock mechanics tests. The samples were picked carefully to analyze in laboratory, numbered consecutively from SY-1 to SY-52 with burial depth. 3.2. Methods 3.2.1. Organic geochemistry TOC measures the amount of total organic carbon in a sample. TOC was measured with a Leco CS230 carbon/sulfur analyzer. The samples were ground to less than 200 mesh in size, weighed, and then diluted with 5% HCl at 80 °C to dissolve any inorganic carbon within the carbonate. The samples were then rinsed, dried, and reweighed before combustion at high temperatures in the Leco CS230. All operations followed Chinese National standards GB/T 19145-2003 and GB/T 18602-2001. The shale samples were crushed to 100 mesh size after surface cleaning, and a Rock-Eval 6 instrument was used for pyrolysis parameter analysis, including free hydrocarbon amounts (S1) expressed as mg HC/g rock, the remaining hydrocarbon generation potential (S2) as mg HC/g rock, and the generated maximum remaining hydrocarbon (Tmax). More details on this experimental process can be found in Lafargue et al. (1998) and Behar et al. (2001). Stable carbon isotope analysis was conducted using the Finnigan MAT-252 instrument and the results were relative to the V-PDB standard (δ13CPDB). Measurement precision was estimated to be ± 0.5‰. All operations followed Petroleum and Natural Gas Industry Standard SY/T 5238-2008.

Fig. 2. Generalized stratigraphic column showing stratigraphy, lithology, and depositional environments of well SY.

possible to occur in other areas of Yangtze Platform, especially for the periphery of Sichuan Basin. The Northwest Hunan Province is close to Chongqing and Guizhou Provinces (Fig. 1) and has more than 15 shale gas blocks in a second tender offer (Ministry of Natural Resources of People's Republic of China held). The Niutitang Formation is highly valued and recently selected as the main target for shale gas resource exploration and development. The thickness of the Niutitang Formation generally increases towards the northwest, and the maximum thickness approaches 674 m in the study area (Lin et al., 2014) (Fig. 1). This change in thickness is controlled by sedimentary facies change (Tang et al., 2016). The sedimentary facies transitions from deep shelf to basin-margin facies from northwest to southeast (Li et al., 2018). Vertically, the Lower member developed black shales, carbonaceous shale, and black siliceous shales, the whole of which belongs to deep shelf environment in the high tide period of transgression, while the Upper member gradually evolves into dark-grey silty shale which belongs to a shallow shelf environment (Fig. 2) (Wan et al., 2018; Li et al., 2018). Structurally, Northwest Hunan is located in the southeast edge of the Sichuan Basin, which is at the southeastern margin of the Yangtze Platform. Tectonic deformation is strong in the area, striking southwest to the northeast. There are a series of NNE-NE-EW arc-like fold belts (Wan et al., 2018, see their Fig. 2). The Sinian, Cambrian, Ordovician, Middle-Lower Silurian, Devonian, Permian, and Triassic deposits are found throughout the study area as indicated by previous studies (Wang et al., 2018; Wan et al., 2018). The well SY reached a total depth of 1136.84 m, with the Lower Cambrian Niutitang Formation between 987 m and 1082 m (Fig. 2).

3.2.2. Vitrinite reflectance measurement and maceral micro-observation Vitrinite reflectance is used to represent thermal maturity of the shale. The vitrinite-like material reflectance (bitumen reflectance) was measured with random solid bitumen in non-polarized light under oil immersion using a Leitz MPV-3 micro-photometer, and at least 20 readings from each sample were taken. The average for each sample was used to represent the reflectance value. The measurement precision was estimated to be ± 0.5%, following Chinese National Standards GB/ T 6948-1998. The maceral composition was observed under both reflected white and fluorescent light with an optical microscope using the same Leitz MPV-3 micro-photometer, and followed Petroleum and Natural Gas Industry Standard SY/T 5125-2014. 3.2.3. X-ray diffraction analysis The mineralogical compositions of the samples were measured using a Bruker D8 Advance X-ray diffractometer, at 45 kV and 35 mA with a Cu Kα-radiation. The samples were crushed to 200–300 mesh in size and mixed with ethanol, hand ground, and then smeared onto mounted glass slides for XRD analysis. The measured data were analyzed via basal reflections. 3.2.4. Mercury intrusion Mercury intrusion analysis was conducted using a Quantachrome Poremaster. 3–5 g of a 1–20 mesh sample was dried at 110 °C for at least 24 h under vacuum in an oven. The mercury injection pressure can 689

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Z. Xi et al.

Table 1 Niutitang Formation shale samples of SY well in the study area and applied measurements. Unit

Upper Member

Lower Member

Sample ID

Depth

Formation

SY-1 SY-2 SY-3 SY-4 SY-5 SY-6 SY-7 SY-8 SY-9 SY-10 SY-11 SY-12 SY-13 SY-14 SY-15 SY-16 SY-17 SY-18 SY-19 SY-20 SY-21 SY-22 SY-23 SY-24 SY-25

987.33 997.27 1000.9 1008.2 1009.6 1012.3 1015.3 1017.2 1017.6 1025.4 1026.2 1027.7 1029.8 1031.0 1033.2 1036.0 1037.2 1038.3 1039.4 1042.1 1043.4 1044.5 1046.4 1048.5 1049.3

Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang

SY-26 SY-27 SY-28 SY-29 SY-30 SY-31 SY-32 SY-33 SY-34 SY-35 SY-36 SY-37 SY-38 SY-39 SY-40 SY-41 SY-42 SY-43 SY-44 SY-45 SY-46 SY-47 SY-48 SY-49 SY-50 SY-51 SY-52

1051.1 1052.7 1054.4 1056.7 1057.8 1060.3 1062.3 1063.0 1064.6 1065.4 1066.3 1067.0 1068.7 1069.7 1070.3 1071.4 1072.0 1073.8 1074.9 1075.9 1076.9 1077.3 1078.8 1079.8 1080.5 1081.2 1081.6

Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang Niutitang

Organic geochemistry

Mineralogy

Microscopy

Petrophysics

OPM

HP

% Ro

TOC

MC

CI

XRD

✓

✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓

✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓ ✓

✓ ✓

✓ ✓

✓ ✓

✓

✓

✓

✓

✓

✓

✓

✓

✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓

✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓

✓

✓

✓ ✓ ✓ ✓

✓

✓

✓ ✓

✓

✓

✓

✓ ✓

✓

✓

SEM

MIP

Rock mechanics N2

✓

CH4 ✓

✓

✓

✓

✓

✓

✓

✓

✓

✓ ✓

✓ ✓

✓ ✓

✓ ✓

✓ ✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

✓

Note: XRD: X-ray diffraction; Ro: Vitrinite reflectance values; MC: Maceral composition; CI: Carbon isotope; OPM: Optical microscope; SEM: Scanning electron microscopy; MIP: Mercury injection porosimetry; N2: Nitrogen physisorption; CH4: Methane adsorption; HP: Helium porosity.

range up to 3.13 × 104 Psi (215Mpa), and can be injected into a pore as small as 6 nm as determined using the Washburn equation (Washburn, 1921).

3.2.6. Methane adsorption experiment Methane adsorption was conducted using high pressure gas sorption & desorption instrumentation from a HPVA Isotherm Measurement System in accordance with Chinese National Standard GB/T 195602008. Each sample was crushed to 60–80 mesh in size and about 100 g was weighed before moisture equilibration was conducted in an evacuated desiccator. After weighing each sample once every 24 h until the weight no longer changed, methane adsorption was estimated using an IS-100 high pressure isothermal adsorption apparatus at 30 °C. Continuous 12 h periods were required for each equilibrium point before the two parameters, and finally Langmuir volume (VL) and Langmuir pressure could be obtained. Eight equilibrium points were obtained during this test.

3.2.5. Low temperature nitrogen adsorption N2 adsorption analysis was conducted using a Micromeritics ASAP 2020 surface area analyzer at 77.35 K and less than 760 mmHg. The crushed samples (60–80 mesh) were dried at 110 °C for 5 h and outgassed at 110 °C for 24 h. The Multi-point Brunauer-Emmett-Teller (BET; Brunauer et al., 1938) model was used to calculate the specific surface area (SSA) and the Barrette-Joynere-Halenda (BJH; Barrett et al., 1951) model for pore volume (PV) and pore size distribution (PSD). 690

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Z. Xi et al.

Table 2 Geochemical data of the shale samples in the SY well from the northwestern Hunan Province. Unit

Sample ID

Depth (m)

TOC (%)

Rom (%)

Ro (%)

S1 (mg/g)

S2 (mg/g)

HI (mg/g)

Tmax (°C)

Maceral composition (%) Sapropelinite

Inertinite

TI

δ13CPDB (‰)

Upper Member

SY-1 SY-2 SY-3 SY-4 SY-5 SY-6 SY-7 SY-8 SY-9 SY-10 SY-11 SY-12 SY-13 SY-14 SY-15 SY-16 SY-17 SY-18 SY-19 SY-20 SY-21 SY-22 SY-23 SY-24 SY-25

987.33 997.27 1000.9 1008.2 1009.6 1012.3 1015.3 1017.2 1017.6 1025.4 1026.2 1027.7 1029.8 1031 1033.2 1036 1037.2 1038.3 1039.4 1042.1 1043.4 1044.5 1046.4 1048.5 1049.3

1.51 0.94 0.59 2.28 0.58 0.9 0.6 0.75 1.23 1.28 1.51 0.94 1.54 2.28 1.12 0.86 0.84 1.02 1.1 0.99 1.03 0.97 1.54 1.2 1.39

3.05 / / / 2.87 / / / 2.79 / 2.24 3.14 / 2.88 / / / 3.35 / / / / 3.01 / /

3.14 / / / 2.97 / / / 2.89 / 2.37 3.22 / 2.98 / / / 3.42 / / / / 3.10 / /

0.01 / / / 0.01 / / / 0 / 0 0 / 0.03 / / / 0 / / / / 0 / /

0.03 / / / 0.03 / / / 0.06 / 0.06 0.08 / 0.073 / / / 0.058 / / / / 0.07 / /

1.99 / / / 5.17 / / / 4.88 / 3.97 8.51 / 3.20 / / / 5.69 / / / / 4.55 / /

495 / / / 470 / / / 475 / 500 525 / 489 / / / 552 / / / / 503 / /

71 85 78 85 88 95 91 80 82 78 87 84 95 89 66 86 88 82 77 90 70 89 85 98 76

29 15 22 15 12 5 9 20 18 22 13 16 5 11 34 14 12 18 23 10 30 11 15 2 24

42 70 56 70 76 90 82 60 64 56 74 68 90 78 32 72 76 64 54 80 40 78 70 96 52

−29.2 / / / −31.2 / / / −30.7 / −28.9 −29.5 / −31.5 / / / −30.6 / / / / −31.5 / /

Lower Member

SY-26 SY-27 SY-28 SY-29 SY-30 SY-31 SY-32 SY-33 SY-34 SY-35 SY-36 SY-37 SY-38 SY-39 SY-40 SY-41 SY-42 SY-43 SY-44 SY-45 SY-46 SY-47 SY-48 SY-49 SY-50 SY-51 SY-52

1051.1 1052.7 1054.4 1056.7 1057.8 1060.3 1062.3 1063 1064.6 1065.4 1066.3 1067 1068.7 1069.7 1070.3 1071.4 1072 1073.8 1074.9 1075.9 1076.9 1077.3 1078.8 1079.8 1080.5 1081.2 1081.6

1.52 1.87 2.02 6.32 1.48 2.39 0.97 1.28 3.39 3.38 3.16 3.04 3.1 5.42 2.91 3.04 3.8 3.54 3.81 3.72 4.46 3.54 7.06 6 3.34 7.06 3.02

/ 2.25 / 3.69 / / 3.22 / / 2.99 / / / 3.15 / / 3.55 / 3.14 / / 3.42 / / / 3.34 /

/ 2.38 / 3.75 / / 3.30 / / 3.08 / / / 3.23 / / 3.62 / 3.22 / / 3.49 / / / 3.42 /

/ 0.02 / 0 / / 0 / / 0 / / / 0.01 / / 0.05 / 0 / / 0 / / / 0.1 /

/ 0.09 / 0.42 / / 0.02 / / 0.22 / / / 0.33 / / 0.26 / 0.15 / / 0.07 / / / 0.38 /

/ 4.81 / 6.65 / / 2.06 / / 6.51 / / / 6.09 / / 6.84 / 3.94 / / 1.98 / / / 5.38 /

/ 483 / 526 / / 525 / / 330 / / / 485 / / 472 / 530 / / 533 / / / 535 /

83 89 88 88 87 87 99 91 92 91 89 80 95 88 89 95 97 98 97 82 87 84 90 88 79 94 81

17 11 12 12 13 13 1 9 8 9 11 20 5 12 11 5 3 2 3 18 13 16 10 12 21 6 19

66 78 76 76 74 74 98 82 84 82 78 60 90 76 78 90 94 96 94 64 74 68 80 76 58 88 62

/ −28.1 / −30.7 / / −33.1 / / −31.1 / / / −30.5 / / −30.5 / −30.8 / / −29.5 / / / −30.2 /

Note: TI = 100 * %sapropelinite + 50 * %liptinite + (−75) * %virtrinite + (−100) * %inertinite; “/”: not detected.

4. Results and discussion

3.2.7. Porosity determination and rock mechanical measurements Porosity was obtained by using apparent density in combination with skeletal density according to Chalmers et al. (2012) (Porosity = (skeletal density - apparent density)/skeletal density *100%). Coated paraffin was used to measure the apparent density of each shale sample weighing around 50 g (Tian et al., 2013), and the skeletal density was determined using a helium pycnometer after the paraffin was removed. The shale samples were prepared cylindrical shapes with a diameter of 2.5 cm and a height of 2.5 cm, and mechanical tests were conducted using a TAW-1000 triaxial rock-testing machine. The experiments were performed following Chinese National Standard GB/T 23561.7–2009.

4.1. The characteristics of organic geochemistry 4.1.1. Thermal maturity and rock-eval pyrolysis parameters Seventeen samples were tested for thermal maturity based on the vitrinite-like material reflectance (Rom) parameter, also called the bitumen reflectance value, which ranged from 2.24% to 3.69%. Using the arithmetic relationship between bitumen reflectance and vitrinite reflectance (%Ro; Ro = (Rom + 0.2443)/1.0495) (Yang et al., 2009), the calculated Ro values were found to range from 2.36% to 3.74% with an average of 3.15%. This indicates that the Niutitang shale samples in well SY had entered the dry gas window. Tmax is another thermal 691

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Z. Xi et al.

that the shale samples are characterized by high Tmax values and low HI values, which made it impossible to identify kerogen types (Fig. 3). TI values were calculated according to the maceral composition of the kerogen, and TI > 80, < 80-40, < 40-0 and < 0 refer to Type I, Type II, Type II-III, and Type III, respectively (Cao, 1985). The primary maceral of the organic particles was amorphous sapropel, with a mean value of 86%. The granular texture of kerogen was fuzzy when observed under a transmission optical microscope. It appeared cloudy and spongy, with hardly any biogenetic texture (Fig. 4). The calculated TI values for the Niutitang shale ranged from 32 to 96 with an average of 72 (Table 2), suggesting that the primary kerogen type was Type II. The kerogen type ranges from Type I to Type III with increasing δ13CPDB values (Stahl et al., 1977): Type I, δ13CPDB range from −35‰ to −30‰; Type II, −30‰ to −27.5‰; Type II-III, δ13CPDB −27.5‰ to −25‰; Type III, δ13CPDB was greater than −25‰. The δ13CPDB values of the kerogen in Niutitang shale ranged from −33.1‰ to −28.1‰ with an average of −30.44‰ (Table 2), and most fell into Type I. The two methods (TI analysis and carbon stable isotope analysis) provided different results, but we note that the kerogen type of the shale samples from the Upper Member was primarily Type II kerogen, and there was a predominance of Type I kerogen in the Lower Member (Fig. 5). However, determine the kerogen types for these over-mature shales based on TI analysis and carbon stable isotope analysis was questionable (Hunt, 1996; Hou et al., 2017). The kerogen type may be presumed to be dominantly Type II marine kerogen based on sedimentology and other characteristics of the source rock. In any case, the kerogens in the Niutitang shale from the study area were mainly dominated by oil-prone types, which had stronger hydrocarbon generation capability compared to Type III kerogen.

Fig. 3. Relationship between Tmax and the hydrogen index of the shale samples.

maturity indicator and also showed a high level of maturity (average of 495 °C) (Table 2). The Ro values of the Niutitang shale is similar to the Niutitang shale from Qianbei area and northern Yunan area, but is higher than that of Longmaxi shale in the Sichuan Basin and much higher than that of typical shale from North America (Xi et al., 2018b). Previous studies have suggested that a large amount of natural gas can still potentially be generated in the high-over mature stage, mainly through secondary cracking of in-situ bitumen (Chen et al., 2011). However, the hydrogen index (HI) and S2 values of the samples in well SY were low in content and ranged from 1.97 to 8.51 mg/gTOC and 0.02–0.42 mg/gRock (Table 2), respectively. In addition, S2 can be converted into volume of methane as proposed by Dang et al. (2016), and the remaining gas generation potential of OM present in the samples ranged from 0.05 to 0.64 cm3 CH4/g, with an average of 0.21 cm3 CH4/g, indicating that the Niutitang shale from well SY has poor hydrocarbon generation potential. This also indicates that a large amount of gas was generated during maturation and the Niutitang Formation has the greatest potential for shale gas production due to its higher thermal maturity.

4.1.3. Characteristics of organic matter The characteristics of OM (enrichment, type and maturity) are among the most important properties that control gas generation and storage capacity in shale (Hu et al., 2016; Xi et al., 2017a; b). In general, high TOC content indicates good prospects for oil and gas resources in key productions areas, such as the Barnett Shale of the Fort Worth Basin (Jarvie et al., 2007) and the Longmaxi Formation in the Sichuan Basin (Chen et al., 2011). Table 2 provides the TOC results for all 52 shale samples, showing that the Niutitang shale could have fair to excellent source potential, with TOC of at least 0.5% (Hunt, 1996). Additionally, there was a clear change in TOC between shales from the Lower Member to the Upper Member in well SY (Fig. 6a). The TOC within the Lower Member (3.10% on average and 70% of the shale samples had TOC > 2.0%) was much higher than that in the Upper Member (1.01% on average and 92% of the shale samples had TOC < 2.0%). The extractable OM content was represented by the parameter bitumen “A”, and the parameter bitumen “A”/TOC was used to represented how much and what relative portion of TOC could be transformed into extractable OM. Generally, OM from marine shale in southern China is considered to be in the high-over mature gas-

4.1.2. Kerogen types In general, three methods were used to determine kerogen types: pyrolysis Tmax versus hydrogen index (HI), type index (TI) analysis, and carbon stable isotope analysis. The rock-eval pyrolysis results show

Fig. 4. Brown lucency-opacitas amorphous solid. (For interpretation of the references to color in this figure legend, the reader is referred to the Web version of this article.) 692

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Z. Xi et al.

Fig. 5. Histogram showing identification of kerogen types based on the TI method and carbon isotope analysis for the samples.

Fig. 6. TOC and pyrite content of the shale samples by burial depth of well SY.

the residual liquid hydrocarbons in the shale have been cracked into gas due to the higher thermal maturity. Many factors influence the accumulation of OM in the Niutitang Formation, and sedimentary environments may play a vital role in controlling OM accumulation in the study area. In this study, higher TOC corresponded deep shelf environments that were generally characterized by euxinic conditions, stable hydrodynamic conditions, and more organisms relative to those in a shallow shelf (Zhu, 2008; Hou et al., 2017). Furthermore, we note that TOC increased with the burial depth, similar to pyrite (Fig. 6b), indicating that pyrite abundance was closely correlated to the presence of OM (Yan et al., 2016; Cai, 2018). Previous studies have suggested that a reducing sedimentary environment (anaerobic conditions) favors the formation of pyrite framboids (Ohfuji and Rickard, 2005; Wilkin et al., 1996, 1997). The formation of pyrite framboids with a larger diameter (10 μm in average) is related to oxygen supply, while framboids with a small diameter (5 μm in average) are associated with euxinic conditions (Wilkin et al., 1997). SEM images showed that most of the pyrites in the shale samples were pyrite framboids (Fig. 8). The pyrite framboids were numerous yet small in the Lower Member samples, ranging from 0.5 to 5.5 μm in diameter (Fig. 8c–e), whereas there were fewer yet larger pyrite framboids in the Upper Member, mostly greater than 10 μm in diameter (Fig. 8a–b). These SEM images do not represent all samples, and the

Fig. 7. Relationship between bitumen ‘A’/TOC and TOC.

generating stage (Zhao et al., 2016), and contains a very low content of extractable OM (Tuo et al., 2015). The measured bitumen “A” content of 10 selected samples ranged from 9 to 68 ppm. Samples with higher TOC had lower bitumen “A”/TOC values (Fig. 7). This result was similar to those of Tuo et al. (2015) who studied the Niutitang shale in the Sichuan Basin. This contradictory result may indicate that most of 693

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Z. Xi et al.

Fig. 8. The characteristics of pyrite in the shale samples from well SY: (a) pyrite framboids with diameters greater than 10 μm, Upper Member sample SY-14; (b) pyrite framboids with diameters of about 6 μm, Upper Member sample SY-23; (c) abundant pyrite framboids with diameters ranging from 1 to 5 μm, Lower Member sample SY-47; (d) abundant pyrite framboids with diameters ranging from 0.5 to 5.5 μm, Lower Member sample SY-51; (e) one pyrite framboid with diameters of about 4 μm and pyrite can be confirmed by the EDS, Lower Member sample SY-51.

Fig. 9. Thin-section lithofacies of the Niutitang shale (a) Carbonaceous shale at depth of 1081.2 m, sample SY-51; (b) Calcareous carbonaceous shale at depth of 1078.8 m, sample SY-48; (c) Carbonaceous shale at depth of 1067 m, sample SY-37; (d) Argillaceous shale at depth of 1049.3 m, sample SY-25; (e) Argillaceous mudstone at depth of 1042.1 m, sample SY-20; (f) Silty shale at depth of 987.33 m, sample SY-1.

4.2. Lithology and mineral composition

number of framboidal pyrites counted in each measured depth was limited. Thus using particle size characteristics of the framboidal pyrite to study the redox conditions may have a limitation in this study. Yet, according to our previous work on paleo-environmental conditions of the Niutitang Formation in Guizhou Province (Li et al., 2018), the diameter of framboidal pyrite is suggested to be a useful proxy for the benthic redox conditions in addition to several other redox proxies (such as Th/U ratios and vanadium (V/Sc and V/(V + Ni) systematics and Mo and Co and Ni/Co). Although the statistical data of pyrite framboids in this study are limited, they do provide insights into important processes occurring in the shale. Therefore, we suggest that the Lower Member Niutitang Formation has very good deposition conditions for organic-rich shale formation, and the reduced sedimentary environment was conducive to OM accumulation and preservation.

Photomicrographs showed strong heterogeneity of the lithology within the Niutitang shale of the two members (Fig. 9). Siliceous carbonaceous shale, calcareous carbonaceous shale, and carbonaceous shale were the most common lithofacies of the Lower Member, with a carbon content greater than 50%. Detrital grains in samples were interbedded within an organic-rich matrix (Fig. 9b–c) or floating within the organic matrix (Fig. 9a). Argillaceous shale and silty shale were the dominant lithofacies of Upper Member, both of which had more detrital grains (mostly > 70%) and less carbon content (mostly < 20%). Alternating gray silt and dark grey organic-rich layers showed some horizontal laminae (Fig. 9d–e). The repeating gray and black strips showed in Fig. 9d–e may be due to changes of energy of the water body. Fig. 9f shows abundant and uniform quartz distribution, which was homogenously mixed with clay minerals. 694

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Z. Xi et al.

Fig. 10. Mineral composition from the Niutitang shale samples by burial depth.

Fig. 11. Relationships between rock mechanical parameters and mineral content of the shale samples.

(Fig. 10c), while carbonate minerals slightly increase (Fig. 10d). Shale from the Niutitang Formation has a higher quartz content compared to other famous gas-producing wells in China (Guo and Zhang, 2013; Liu et al., 2014; Zhao et al., 2016) (Jiaoye-1 well, 44.4% on average; Pengye-1 well, 34% on average; and Wei-201 well, 40% on average) but a lower clay content. High quartz content is correlated with a high Young's Modulus, while high clay mineral content is correlated with a high Poisson's ratio (Fig. 11), indicating that the shale from well SY has a much better potential for hydraulic stimulation due to its brittleness. Many previous studies have found that there is a positive correlation between TOC and quartz content in marine shales (Chalmers et al., 2012; Tian et al., 2013; Hu et al., 2016; Sun et al., 2016). Bustin et al. (2009) suggested that quartz may be positively (biogenic origin) or negatively (detrital origin) correlated with TOC. However, no apparent relationship between TOC and quartz contents was observed for this shale overall (Fig. 12), although a slight positive correlation was observed in the Lower Member samples when plotted alone (Fig. 12). This may indicate that the marine shale was deposited in a deep shelf sedimentary environment where the quartz may have been mainly of biogenic origin. In contrast, the Niutitang shale from the Upper Member was deposited in relatively shallow water, which is relatively conducive to the input of terrigenous minerals and quartz may have been mainly of detrital origin. The Niutitang shale with lower TOC in the Upper Member may have relatively high terrigenous detrital quartz content, whereas the shale with higher TOC in the Lower Member may have relatively high biogenic quartz content. The differences in the two

Fig. 12. Relationship between TOC and quartz content of the shale samples.

Mineral composition is one of the important factors of influence for reservoir quality, and thus the mineral compositions in shale were a key factor for evaluating the reservoirs. The Niutitang Formation is mainly composed of quartz, clay minerals, feldspar, pyrite, and carbonates (calcite and dolomite). Quartz and clay are the primary minerals present and there is no regular pattern in their content from bottom to top (Fig. 10a–b), with an average quartz content of 52% (ranging from 40 to 61%) and an average clay content of 22% (ranging from 17 to 32%). From top to bottom, feldspar decreases after an initial gradual increase 695

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Z. Xi et al.

Fig. 13. SEM images of main pore types in Niutitang Formation.

Fig. 14. Nitrogen adsorption-desorption isotherms (a) the Upper Member shale samples; (b) the Lower Member shale samples.

and were dispersed and distributed throughout the matrix (Fig. 13e and f). Fig. 13e shows that the interP exhibited slit-like openings along the particle boundary. These pores were comparatively larger in size range compared to other types of pores; however, they cannot form an effective pore network because they do not connect to each other. The length of the fracture was 1.7 μm, while the widths were 50 nm. The shape of the N2 adsorption-desorption isotherms was used to characterize the pore shape of the shale (Xi et al., 2017, 2018). As shown in Fig. 14, the N2 adsorption-desorption isotherms were of type IV with a hysteresis loop, which was observed among all the shale samples. According to IUPAC classification, in general, a Type H2 hysteresis loop occurs in pores with narrow necks and wide bodies (defined as inkbottle-shaped pores), and Type H3 hysteresis indicates slit-shaped or wedge-shaped pores. The 10 selected shale samples varied between Types H2 and H3, indicating a combination of several typical pore types. Furthermore, the hysteresis loop of the Lower Member samples was closer to a Type H2 (there was a more obvious

members could be due to the changing sedimentary environment.

4.3. Pore structure characteristics 4.3.1. Pore types Based on the classification scheme for pores, published by Loucks et al. (2012), interparticle (interP) pores, intraparticle (intraP) pores, and OM pores were clearly observed in the Niutitang Formation under SEM (Fig. 13). Most OM pores were formed during the progressive thermal evolution of OM, which varied from a nearly spherical to an irregular polygonal shape (Fig. 13a and b). Compared to the high gasproducing Longmaxi shale in the Sichuan Basin, the pore sizes of OM pores in these shales generally ranged below 100 nm and were difficult to find. IntraP pores were mainly developed within mineral grains, especially feldspar. The shapes of the intraP were typically irregular, polygonal, and alveolate (Fig. 13c and d). InterP generally occurred between grains and crystals such as quartz, feldspar, and clay minerals, 696

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Z. Xi et al.

Fig. 15. Relationships between TOC, mineral compositions and BET SSA and BJH PV.

inflection point, e.g. sample SY-39), while most of the Upper Member samples were characterized by a Type H3 hysteresis loop. Yang et al. (2014) have suggested that shale with more inkbottle-shaped pores has a more complex pore structure than other types, indicating that shale from the Lower Member had a less homogeneous pore structure than that of the Upper Member.

4.3.2. Pore volume, specific surface area, pore size distribution Ten samples were tested using mercury intrusion and N2 adsorption to obtain the BET SSA (specific surface area) and BJH PV (pore volume). The BET SSA ranged from 3.818 to 11.765 m2/g with a mean value of 8.58 m2/g, and the BJH PV was between 0.01155 and 0.01673 cm3/g with an average of 0.01395 cm3/g. The values of the two pore structure parameters positively correlated with TOC, whereas there was no obvious relationship between the primary mineral content and the pore structure parameters (Fig. 15). This indicates that TOC

Fig. 16. Relationship between TOC and uniaxial compression strength. 697

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Z. Xi et al.

Fig. 17. Pore size distribution of the shale samples (a) PSD based on BJH model using N2 adsorption data; (b) PSD obtained by mercury injection.

investigate the pore size distribution (PSD), and the dV/dlog(D) vs. D plot was used to display PSD, which highlights the PV distribution. The PSD obtained from the N2 adsorption analysis was unimodal, with a peak near 2–6 nm (Fig. 17a). Due to the limitations of N2 adsorption analysis, previous studies have used mercury intrusion to identify the presence of macropores. The dominant volume was mostly controlled by macropores larger than 10 μm, and pores ranging in size from 50 nm to 10 μm were not developed except for sample SY-5, which peaked at 300–600 nm (Fig. 17b). Pores with a diameter greater than 10 μm and those ranging from 2 to 6 nm were the dominant PV within the Niutitang shale.

4.3.3. Porosity The integration of porosity data (free gas potential) with methane isothermal adsorption data (adsorbed gas potential; discussed in the next section) provides a measure of the potential shale gas capacity, and was used to evaluate the economic feasibility of the Niutitang shale gas reservoir. The porosity ranged between 1.53% and 4.06% for the 17 samples, with a mean value of 2.66%. The measured porosity of the shale is similar to the Niutitang shale within the CY well, but lower than the Longmaxi shale (generally around 4.0%; Hu et al., 2016) in the study area. Although the lower limits of porosity for shale gas reservoirs have been suggested to be around 1% (Nie et al., 2011), the measured porosity of the Niutitang shale with higher thermal maturity was lower than that of marine and marine-continental transitional shale with relatively lower maturities. It was much lower than that of immature-low mature continental shale (Fig. 18). The porosity of the shale samples decreased with increasing burial depth (Fig. 19a). In general, compaction reduced porosity at greater burial depths, but porosity was also associated with TOC and mineral composition variations (Fig. 19b–f). The total porosity of the shale was divided into inorganic matrix porosity and organic porosity. Higher TOC corresponded to greater depth, and could decrease the brittleness and fracture density of the shale, as mentioned above. Therefore, the contribution of OM to the total porosity decreased with increasing burial depth, which was attributed to the increased compaction resulting in a negative correlation between TOC and porosity (Fig. 19b). The shale samples with lower porosity but higher TOC may represent pore collapse during gas expulsion and a consequence of greater OM connectivity and framework compaction. In addition, OM pores were generally associated with micorpores and fine meospores (Yang et al., 2014, 2016a, Yang et al., 2014; Xi et al., 2017a; Tian et al., 2013, 2015), and the contribution of such small diameter pores to the SSA was more significant than porosity. Wang et al. (2013) have suggested that the contribution of per gram OM to total porosity is only 0.4% for Lower Cambrian shale in southern China with a Ro of 2.5–3.6%. The inorganic matrix porosity is mainly controlled by diagenesis and compaction. Although the Niutitang shale from well SY contained higher

Fig. 18. Relationship between porosity and vitrinite reflectance (Ro) values for shale in China. Data sources: Marine-continental transitional shales (Xi et al., 2017a); Continental shales (Hou et al., 2017); Longmaxi shales (Tian et al., 2013); Niutitang shales (Wang et al., 2016).

was an important controlling factor that affected pore structure development. Notably, the positive relationship shown in Fig. 15a–b was similar to that of Niutitang shale in the Qianbei and Qiannan depression in Guizhou Province, which is close to Hunan Province (Tian et al., 2015; Wang et al., 2016a), but it was much weaker than the results obtained from studies on North American shale (Chalmers et al., 2012) and the Longmaxi shale in southern China (Xiong et al., 2015). This difference may be attributed to the high thermal maturity of the OM and severe diagenetic compaction, which decreased both the amount and size of OM pores. In addition, BET SSA and BJH PV gradually stabilized when TOC became much higher (Fig. 15a–b). Milliken et al. (2013) suggest that the rock fabric of OM-rich shale is more easily compacted, and marine kerogens are unstable and easy to deform during compaction, which is detrimental for preservation of OM pores. As shown in Fig. 16, uniaxial compression strengths were negatively correlated with TOC, and when TOC was greater than 2% the negative relationship was more obvious, indicating that excessive TOC could decrease the brittleness and fracture density of the shale. Potentially, pore content will decrease with increasing TOC content when the TOC content exceeds a certain amount. The quartz content had no apparent relationships with SSA and PV, and several differences exists between this shale and previous studies of marine shale (particularly from the Longmaxi Formation) in south China (Chalmers et al., 2012; Jiao et al., 2014; Hu et al., 2016). The origin of quartz may be the main reason that led to distinct correlations in different areas, and detailed investigations on the origin of quartz from the Niutitang Formation in the study area should be carried out in the future. The N2 adsorption branch and mercury intrusion data were used to 698

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Z. Xi et al.

Fig. 19. Relationships between porosity and (a) burial depth, (b) TOC, (c) quartz content, (d) clay content, (e) feldspar content, and (f) carbonate content.

types, and pore structure characteristics (Ross and Bustin, 2009; Chalmers et al., 2012; Zhang et al., 2012). Here, we mainly discuss the effects of pore structure parameters and shale components on the methane adsorption capacities. The VL positively correlated with TOC, and had no apparent relationship to quartz and clay minerals contents (Fig. 20a–c). These correlations suggest that TOC may be one of the primary factors that affects shale gas adsorption capacity, which has also been observed by previous studies (Wang et al., 2016a; Han et al., 2016). The sorption capacity for OM was much higher than that for clay minerals. Moisture was preferentially adsorbed on clay minerals, but was not found on the surface of hydrophobical OM. Additionally, the VL correlated positively with BET SSA and had no apparent relationship to PV (Fig. 20d–e). The increase in BET SSA with TOC contents shown in Fig. 15 indicates that the majority of methane sorption sites were associated with OM. The analysis of the relationship between pore structure parameters and VL further highlighted TOC as an important control on shale gas adsorption capacity. As shown in Fig. 20f, the VL

quartz content which could shield the pores from compaction, the overly abundant quartz may have reduced gas storage space due to reprecipitation within pore spaces (Volpi et al., 2003), and quartz therefore has a complex relationship with porosity (Fig. 19c). In addition, weak carbonate and feldspar dissolution and high carbonate cementation in the shale may cause porosity to decrease (Fig. 19e–f). 4.4. Gas adsorption capacity This study conducted a methane adsorption experiment under moisture-equilibrium for 17 shale samples to estimate the gas sorption capacity, which was characterized by the Langmuir volume (VL) parameter. The VL ranged from 0.132 cm3/g to 2.592 cm3/g with a mean value of 1.55 cm3/g, similar to typical values from the Longmaxi and Niutitang Formations in the Sichuan Basin (Chen et al., 2011). Generally, the methane adsorption capacity of shale is influenced by many geological factors, including TOC content, thermal maturity, kerogen 699

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Z. Xi et al.

Fig. 20. Relationships between Langmuir volume and (a) TOC, (b) quartz content, (c) clay content, (d) BET SSA, (e) BJH PV, and (f) burial depth.

to suggest that the study area potentially contains sufficient shale gas for commercial production. Key findings include the following: (1) The kerogen type of the Niutitang shale is oil-prone types, which has strong generation potential. The Niutitang shale also has high TOC with an average of 2.37%, which favors the generation of shale gas. In addition, there is an organic-rich layer with consistent thickness of around 17 m at depths of 1064–1081 m. The TOC in this organic-rich layer for all samples is greater than 3%, with an average value of 4.04%; (2) The low values of HI and S2 combined with the high thermal maturity of the samples indicate that a large amount of natural gas was generated during maturation in the study area; (3) The shale has a high brittle mineral content and low clay mineral content, implying much better potential for hydraulic stimulation due to its brittleness; (4) Although the high thermal maturity and strong compaction negatively influences the shale gas reservoir quality, the gas storage capacity of the shale is still high. The sample porosity ranges between 1.53% and 4.06% and

values increased from the top to the bottom of the Niutiang Formation, indicating that there is promising gas adsorption capacity at the Lower Member Niutitang Formation. This relationship may also be attributed to TOC, which was more enriched in the Lower Member Niutitang Formation.

4.5. Shale gas potential and exploration suggestions for the Niutitang Formation in Hunan Province The important parameters for evaluating shale gas potential, namely TOC, kerogen types, mineral composition, pore structure, and gas storage capacity (porosity and adsorption capacity) (Chen et al., 2011), were analyzed for the Niutitang shale in well SY from the northwest Hunan Province. The above analyses showed that the Niutitang Formation has good enrichment conditions for shale gas. When compared to major gas-producing shale in China (Fig. 21), these properties seem 700

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Z. Xi et al.

Fig. 21. Geological characteristics of organic-rich shale intervals of major gas-producing wells in southern China: Jiaoye-1 well, Wei-204 well, Ning-201 well, Yang101 well, and YS-108 well located in the Sichuan Basin (Guo and Zhang, 2013; Zhao et al., 2016), and Jinye-1 well located in the Sichuan Basin (Zhao et al., 2016), and Zhao-101 well located in the northern Yunnan-Guizhou (Zhao et al., 2016), and Changye-1 well located in the northwestern Hunan Province (Lin et al., 2014), and SY well located in the northwestern Hunan Province (this study).

periphery of the Sichuan Basin (Guo, 2014). Therefore, in this study, we suggest that the Lower Member of the Niutitang Formation may be an ideal location for exploration and development of shale gas in northwest Hunan Province. The distribution of favorable areas may be controlled by sedimentary environment and tectonic movement.

the Langmuir maximum of methane sorption capacity varies from 0.132 to 2.592 m3/t. The Lower Member was deposited in a deep shelf environment, containing high OM abundance. Through time, the water depth gradually became shallower as the Upper Member was deposited in a shallow shelf environment with a greater amount of terrigenous detrital minerals compared to the Lower Member. Due to the changing sedimentary environment, the Upper Member contains relatively low OM abundance. Therefore, the Lower Member Niutitang Formation has better shale gas potential than the Upper Member due to its high TOC, sapropelic quality, and high thermal maturity. Also, the reservoir performance of the Niutitang shale is affected by mineral composition, TOC, pore structure, and burial depth. The Lower Member has lower porosity and higher methane adsorption capacity than the Upper Member, indicating that a comparatively larger amount of gas would be expected to occur as adsorbed gas. Marine shales in southern China experienced several episodes of intensive tectonic motions after peak gas generation (Ma et al., 2004; Wan et al., 2017); therefore, preservation conditions are also important for the over mature Niutitang Formation. The pressure coefficient plays an important role in shale gas preservation, and overpressurization (pressure coefficient > 1.0) is common for high-yield shale gas with a relatively high proportion of free gas (Liu et al., 2016). The WufengLongmaxi Formation in the Sichuan Basin is dominated by overpressurization, such as the Jiaoshiba area with a pressure coefficient of around 1.5; however, the pressure coefficient was only 0.9 (below 1.0) in the study area, suggesting that the preservation condition of Niutitang Formation was worse than that of other major gas-producing shales, and a loss of free gas during intensive uplift and erosion may be a major risk for shale gas exploration in the study area (Hao et al., 2013). Previous studies have suggested that strong gas adsorption capacity is important for the preservation of shale gas in complex tectonic areas (Ma et al., 2015; Han et al., 2016), and low-pressurization (pressure coefficient < 1.0) is common for shale gas with a relatively high proportion of adsorbed gas, such as PY1 well and CY well in the

5. Conclusions (1) TOC within the Niutitang shale from well SY in the study area ranges between 0.58% and 7.06%, and the OM is more enriched in the Lower Member. The kerogens are dominated by oil-prone types, and Ro values of the shale ranges between 2.36% and 3.74%, with most values being greater than 3%, indicating that shale is in the dry gas window. The low HI and S2 values of the samples indicate that a large amount of natural gas has been generated from the OM. The organic geochemistry data of the shale indicates good shale gas potential in the study area. (2) The shales are characterized by high concentrations of brittle minerals (quartz and feldspar) and low clay content, indicating much better potential for hydraulic stimulation due to its high brittleness. The origin of quartz may have been different in the two Niutitang Formation members, likely due to the change in depositional environments. The variation of TOC content between the two members may have been due to the same reason. (3) The porosity of the shale is related to the burial depth and compaction, and shale at greater burial depths has lower porosity. The gas adsorption capacity is associated with TOC, and shale with high TOC has more specific surface area to provide more methane adsorption sites, resulting in greater adsorption capacity. The Lower Member has lower porosity but higher methane adsorption capacity than that of the Upper Member, indicating that a relatively larger amount of gas may occur as adsorbed gas. It is suggested that the Lower Member of the Niutitang Formation is an ideal location for the exploration and development of shale gas in northwest Hunan Province due to the regular thickness of the organic-rich layer, high 701

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Z. Xi et al.

TOC, high brittleness index, and stronger adsorption capacity.

porosimetry: a case study from the Perth and Canning Basins, Western Australia. J. Petrol. Sci. Eng. 112, 7–16. Lafargue, E., Espitalie, J., Marquis, F., et al., 1998. Rock-Eval 6 applications in hydrocarbon exploration, production, and soil contamination studies. Inst. Fr. Pet. 53, 421–437. Li, J., Tang, S., Zhang, S., et al., 2018. Paleo-environmental conditions of the Early Cambrian Niutitang Formation in the Fenggang area, the southwestern margin of the Yangtze Platform, southern China: evidence from major elements, trace elements and other proxies. J. Asian Earth Sci. 159, 81–97. Liu, H., Wang, H., Sun, S., et al., 2016. The formation mechanism of overpressure reservoir and target screening index in south China marine shale. Nat. Gas Geosci. 23 (02), 48–54. Lin, T., Zhang, J., Li, B., et al., 2014. Shale gas accumulation conditions and gas-bearing properties of the lower cambrian Niutitang Formation in well Changye 1, northwestern Hunan. Acta Pet. Sin. 35 (5), 839–846. Liu, S., Ran, B., Guo, T., et al., 2014. Lower Palaeozoic Organic-matter-rich Black Shale in the Sichuan Basin and its Periphery: from Oil-prone Source Rock to Gas-producting Shale Reservoir. Science Press, Beijing, pp. 42–294. Loucks, R.G., Reed, R.M., Ruppel, S.C., et al., 2012. Spectrum of pore types and networks in mudrocks and a descriptive classification for matrix-related mudrock pores. AAPG Bull. 96, 1071–1098. Ma, L., Chen, H., Gan, K., 2004. Tectonics and marine Petroleum Geology in south China: Beijing, China. Geology Press, pp. 37–41. Ma, Y., Zhong, N., Li, D., et al., 2015. Organic matter/clay mineral intergranular pores in the Lower Cambrian Lujiaping shale in the north-eastern part of the upper Yangtze area, China: a possible microscopic mechanism for gas preservation. Int. J. Coal Geol. 137, 38–54. Milliken, K.L., Rudnicki, M., Awwiller, D.N., et al., 2013. Organic matter-hosted pore system, marcellus formation (Devonian), Pennsylvania. AAPG Bull. 97, 177–200. Nie, H., Zhang, J., Li, Y., 2011. Accumulation conditions of the lower cambrian shale gas in the Sichuan Basin and its periphery. Acta Pet. Sin. 32, 959–967. Ohfuji, H., Rickard, D., 2005. Experimental syntheses of framboids-a review. Earth Sci. Rev. 71, 147–170. Ross, D.J.K., Bustin, R.M., 2008. Characterizing the shale gas resource potential of Devonian-Mississippian strata in the Western Canada sedimentary basin: application of an integrated formation evaluation. AAPG Bull. 92 (1), 87–125. Ross, D.J.K., Bustin, M.R., 2009. The importance of shale composition and pore structure upon gas storage potential of shale gas reservoirs. Mar. Petrol. Geol. 26, 916–927. Stahl, W.J., Wollanke, G., Boigk, H., 1977. Carbon and nitrogen isotope data of Upper Carboniferous and Rotliegend natural gases from North Germany and their relationship to the maturity of the organic source material. In: Proceedings of the 7th International Meeting on Organic Geochemistry Advances in Organic Geochemistry, 1975, pp. 539–560 (Madrid). Sun, M., Yu, B., Hu, Q., et al., 2016. Nanoscale pore characteristics of the lower cambrian Niutitang Formation shale: a case study from well Yuke #1 in the southeast of chongqing, China. Int. J. Coal Geol. 154–155, 16–29. Tan, J., Horsfield, B., Fink, R., et al., 2014. Shale gas potential of the major marine shale formations in the upper Yangtze Platform, south China, Part III: mineralogical, lithofacial, petrophysical, and rock mechanical properties. Energy Fuels 28, 2322–2342. Tang, S., Fan, E., Zhang, S., et al., 2016. Reservior characteristics and gas-bearing capacity of the Lower Palaeozoic marine shales in Northwestern Hunan. Geo. Sci. Front. 23 (2), 135–146. Tian, H., Pan, L., Xiao, X., et al., 2013. A preliminary study on the pore characterization of Lower Silurian black shales in the Chuandong Thrust Fold Belt, southwestern China using low pressure N2 adsorption and FE-SEM methodsMar. Petrol. Geol. 48, 8–19. Tian, H., Pan, L., Zhang, T., et al., 2015. Pore characterization of organic-rich Lower Cambrian shales in Qiannan depression of Guizhou province, southwestern China. Mar. Petrol. Geol. 62, 28–43. Tuo, J., Chen, J., Wu, M., et al., 2015. Organic matter properties and shale gas potential of Paleozoic shales in Sichuan Basin, China. J. Nat. Gas Sci. Eng. 434–446. Volpi, V., Camerlenghi, A., Hillenbrand, C.-D., et al., 2003. Effects of biogenic silica on sediment compaction and slope stability on the Pacific margin of the Antarctic Peninsula. Basin Res. 15, 339–363. Wang, D., Shao, L., Li, Z., et al., 2016. Hydrocarbon generation characteristics, reserving performance and preservation conditions of continental coal measure shale gas: a case study of Mid-Jurassic shale gas in the Yan’an Formation, Ordos Basin. J. Petrol. Sci. Eng. 145, 606–628. Wang, F., Guan, J., Feng, W., et al., 2013. Evolution of overmature marine shale porosity and implication to the free gas volume. Petrol. Explor. Dev. 40 (6), 819–824. Wan, Y., Tang, S., Pan, Z., 2017. Evaluation of the shale gas potential of the lower Silurian Longmaxi Formation in northwest Hunan province, China. Mar. Petrol. Geol. 159–175. Wan, Y., Zhang, S., Tang, S., et al., 2018. A comparative study of characterization of lower Palaeozoic Niutitang shale in northwestern Hunan, China. J. Nat. Gas Sci. Eng. 53, 284–300. Washburn, E.W., 1921. Note on a method of determining the distribution of pore sizes in a porous material. Proc. Natl. Acad. Sci. U.S.A. 115–116. Wang, R., Gu, Y., Ding, W., et al., 2016a. Characteristics and dominant controlling factors of organic-rich marine shales with high thermal maturity: a case study of the Lower Cambrian Niutitang Formation in the Cen’gong block, southern China. J. Nat. Gas Sci. Eng. 33, 81–96. Wang, X., Ding, W., Cui, L., et al., 2018. The developmental characteristics of natural fractures and their significance for reservoirs in the Cambrian Niutitang marine shale of the Sangzhi block, southern China. J. Petrol. Sci. Eng. 165, 831–841. Wilkin, R.T., Arthur, M.A., Dean, W.E., 1997. History of water-column anoxia in the Black

Acknowledgments This work was financially supported by National Science and Technology Major Project of China (grant no. 2017ZX05035001-003). The authors also greatly acknowledge the China National Administration of Coal Geology for sample support and their permission to publish the results of this study. We also greatly thank the anonymous reviewers and editors for their critical comments and valuable suggestions, which were very helpful to improve the manuscript. References Barrett, E.P., Joyner, L.G., Halenda, P.P., 1951. The determination of pore volume and area distribution in porous substances. I. Computations from nitrogen isotherms. J. Am. Chem. Soc. 73, 373–380. Behar, F., Beaumont, V., De, B., et al., 2001. Rock-Eval 6 technology: performances and developments. Oil Gas Sci. Technol. Rev. IFP 56, 111–134. Brunauer, S., Emmett, P.H., Teller, E., 1938. Adsorption of gases in multimolecular layers. J. Am. Chem. Soc. 60, 309–319. Bustin, R.M., Bustin, A., Ross, D., 2009. Shale gas opportunities and challenges. Search Discov. Articles 40382, 20–23. Cai, C., Xiang, L., Yuan, Y., et al., 2015. Marine C, S and N biogeochemical processes in the redox-stratified Early Cambrian Yangtze ocean. J. Geol. Soc. (Lond.) 172 (3), 390–406. Cai, C., 2018. Application of organic sulfur isotopic composition to petroleum origin and evolution: a review. Nat. Gas Geosci. 29 (2), 159–167. Cao, Q., 1985. Identification of microcomponents and types of kerogen under transmitted light. Pet. Explor. 5, 14–23. Chalmers, G.R., Bustin, R.M., Power, I.M., 2012. Characterization of gas shale pore systems by porosimetry, pycnometry, surface area, and field emission scanning electron microscopy/transmission electron microscopy image analyses: examples from the Barnett, Woodford, Haynesville, Marcellus, and Doig units. AAPG Bull. 96, 1099–1119. Clackson, C., Haghshenas, B., Ghanizadeh, A., et al., 2016. Nanopores to megafractures: current challenges and methods for shale gas reservoir and hydraulic fracture characterization. J. Nat. Gas Sci. Eng. 31, 612–657. Chen, S., Zhu, Y., Wang, H., et al., 2011. Shale gas reservoir characterisation: a typical case in the southern Sichuan Basin of China. Inside Energy 36, 6609–6616. Curtis, J.B., 2002. Fractured shale-gas systems. AAPG Bull. 86 (11), 1921–1938. Dang, W., Zhang, J., Tang, X., et al., 2016. Shale gas potential of Lower Permian marinecontinental transitional black shales in the Southern North China Basin, central China: characterization of organic geochemistry. J. Nat. Gas Sci. Eng. 28, 639–650. Guo, X., 2014. Rules of two-factor enrichment for marine shale gas in southern China: understanding from the Longmaxi Formation shale gas in Sichuan Basin and its surrounding area. Acta Geol. Sin. 88 (7), 1209–1218. Guo, C., Li, Q., Wei, M., 2018. Pore structure characteristics of marine Silurian shales in the Sichuan Basin, China: insights to reserve assessment and production design. J. Petrol. Sci. Eng. 164, 437–449. Guo, T., Zhang, H., 2013. Formation and enrichment mode of Jiaoshiba shale gas field, Sichuan Basin. Petrol. Explor. Dev. 41 (1), 28–36. Hao, F., Zou, H.Y., Lu, Y.C., 2013. Mechanisms of shale gas storage: implications for shale gas exploration in China. AAPG Bull. 97 (8), 1325–1346. Han, H., Zhong, N., Ma, Y., et al., 2016. Gas storage and controlling factors in an overmature marine shale: a case study of the Lower Cambrian Lujiaping shale in the Dabashan arclike thrustefold belt, southwestern China. J. Nat. Gas Sci. Eng. 33, 839–853. Hou, H., Shao, L., Li, Y., et al., 2017. Geochemistry, reservoir characterization and hydrocarbon generation potential of lacustrine shales: a case of YQ-1 well in the Yuqia Coalfield, northern Qaidam Basin, NW China. Mar. Petrol. Geol. 88, 458–471. Hu, J., Tang, S., Zhang, S., 2016. Investigation of pore structure and fractal characteristics of the lower Silurian Longmaxi shales in western Hunan and Hubei provinces in China. J. Nat. Gas Sci. Eng. 28, 522–535. Huang, J., Zou, C., Li, J., et al., 2012. Shale gas generation and potential of the lower cambrian Qiongzhusi Formation in the southern Sichuan Basin, China. Petrol. Explor. Dev. 39, 75–81. Hunt, J.M., 1996. Petroleum Geochemistry and Geology, second ed. W.H. Freeman and Company, New York, pp. 743. Jarvie, D.M., Hill, R.J., Ruble, T.E., et al., 2007. Unconventional shale-gas systems: the Mississippian Barnett Shale of north-central Texas as one model for thermogenic shale-gas assessment. AAPG Bull. 91, 475–499. Jiang, S., Tang, X., Cai, D., et al., 2017. Comparison of marine, transitional, and lacustrine shales: a case study from the Sichuan Basin in China. J. Petrol. Sci. Eng. 150, 334–347. Jiao, K., Yao, S., Liu, C., et al., 2014. The characterization and quantitative analysis of nanopores in unconventional gas reservoirs utilizing FESEM-FIB and image processing: an example from the lower Silurian Longmaxi Shale, upper Yangtze region, China. Int. J. Coal Geol. 1–11. Labani, M.M., Rezaee, R., Saeedi, A., et al., 2013. Evaluation of pore size spectrum of gas shale reservoirs using low pressure nitrogen adsorption, gas expansion and mercury

702

Journal of Petroleum Science and Engineering 171 (2018) 687–703

Z. Xi et al.

Yang, J., Yi, F., Qian, Z., 2009. Study of paleotemperature of the Lower Cambrian black shale series and their implications in northern Guizhou province. Acta Mineral. Sin. 29, 87–94. Yang, F., Ning, Z., Liu, H., 2014. Fractal characteristics of shales from a shale gas reservoir in the Sichuan Basin, China. Fuel 115, 378–384. Yang, R., He, S., Yi, J., et al., 2016. Nano-scale pore structure and fractal dimension of organic-rich Wufeng-Longmaxi shale from Jiaoshiba area, Sichuan Basin: investigations using FE-SEM, gas adsorption and helium pycnometry. Mar. Petrol. Geol. 70, 27–45. Yang, X., Fan, T., Wu, Y., 2016a. Lithofacies and cyclicity of the lower cambrian Niutitang shale in the Mayang basin of western Hunan, South China. J. Nat. Gas Sci. Eng. 28, 74–86. Yuan, Y., Cai, C., Wang, T., et al., 2014. Redox condition during Ediacaran-Cambrian transition in the Lower Yangtze deep water basin, South China: constraints from iron speciation and δ13Corg in the Diben section, Zhejiang. Chin. Sci. Bull. 59, 3638–3649. Zhao, W., Li, J., Yang, T., et al., 2016. Geological difference and its significance of marine shale gases in South China. Petrol. Explor. Dev. 43 (4), 547–559. Zhang, T., Ellis, G.S., Ruppel, S.C., et al., 2012. Effect of organic-matter type and thermal maturity on methane adsorption in shale-gas systems. Org. Geochem. 47, 120–131. Zhu, X., 2008. Sedimentary Petrology, fourth ed. Petroleum Industry Press, Beijing, China, pp. 208–286 (in Chinese). Zou, C., Dong, D., Wang, Y., et al., 2015. Shale gas in China: characteristics, challenges and prospects (II). Petrol. Explor. Dev. 42 (6), 753–767.

Sea indicated by pyrite framboid size distributions. Earth Planet Sci. Lett. 148, 517–525. Wilkin, R.T., Barnes, H.L., Brantley, S.L., 1996. The size distribution of framboidal pyrite in modern sediments: an indicator of redox conditions. Geochem. Cosmochim. Acta 60, 3897–3912. Xiang, L., Cai, C., He, X., et al., 2016. The ocean redox state evolution and its controls during the cambrian series 1-2: evidence from Lijiatuo section, south China. J. Earth Sci. 27, 265–280. Xi, Z., Tang, S., Zhang, S., et al., 2017a. Nano-Scale pore structure of marine-continental transitional shale from Liulin area, the eastern margin of Ordos basin, China. J. Nanosci. Nanotechnol. 17, 1–15. Xi, Z., Tang, S., Zhang, S., et al., 2017b. Pore structure characteristics of marine–continental transitional shale: a case study in the Qinshui Basin, China. Energy Fuel. 31, 7854–7866. Xi, Z., Tang, S., Wang, J., et al., 2018a. Pore structure and fractal characteristics of Niutitang shale from China. Minerals 163, 8. Xi, Z., Wang, J., Hu, J., Tang, S., Xiao, H., Zhang, Z., Xing, Y., 2018b. Experimental investigation of evolution of pore structure in Longmaxi marine shale using an anhydrous pyrolysis technique. Minerals 8, 226. Xiong, J., Liu, X., Liang, L., 2015. Experimental study on the pore structure characteristics of the Upper Ordovician Wufeng formation shale in the southwest portion of the Sichuan Basin, China. J. Nat. Gas Sci. Eng. 22, 530–539. Yan, J., Men, Y., Sun, Y., et al., 2016. Geochemical and geological characteristics of the Lower Cambrian shales in the middleeupper Yangtze area of South China and their implication for the shale gas exploration. Mar. Petrol. Geol. 70, 1–13.

703