Characteristics of Black Shale Reservoirs and Controlling Factors of

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Characteristics of Black Shale Reservoirs and Controlling Factors of Gas Adsorption in the Lower Cambrian Niutitang Formation in the Southern Yangtze Basin Margin, China Yuehao Ye, Chao Luo, Shugen Liu, Christopher Xiao, Bo Ran, Wei Sun, Di Yang, Luba Jansa, and Xiangliang Zeng Energy Fuels, Just Accepted Manuscript • Publication Date (Web): 20 Jun 2017 Downloaded from http://pubs.acs.org on June 20, 2017

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Characteristics of Black Shale Reservoirs and Controlling Factors of Gas Adsorption in the Lower Cambrian Niutitang Formation in the Southern Yangtze Basin Margin, China YE Yue-hao1, LUO Chao2, LIU Shu-gen 1*, Christopher Xiao3, RAN Bo1, SUN Wei1,YANG Di1, Luba Jansa4 , ZENG Xiangliang5 1. State key laboratory of Oil and Gas reservoir geology and exploitation, Chengdu University of Technology, Chengdu, Sichuan, China, 610059; 2. Exploration and development Research Institute of Southwest Oil & Gas Field Company (CNPC), Chengdu, Sichuan, China, 610041; 3. University of Houston, 4800 Calhoun Rd, Houston, TX 77004, USA; 4. Geological Survey of Canada-Atlantic, Dartmouth, N.S., Canada； 5 Key Laboratory of Shale Gas Exploration, Ministry of Land and Resources, Chongqing Institute of Geology and Mineral Resources, Chongqing 400042, China

Abstract: The pore structure and shale adsorption capacity has a great impact on the formation of shale gas field of yield industrial gas flow. This investigates focuses on the characteristics of the reservoir and adsorbed gas of the lower Cambrian Niutitang formation in the southern margin of the Yangtze basin. Based on geochemical analysis, low pressure nitrogen gas adsorption, X-ray diffraction and isothermal adsorption experiments on core samples, the Niutitang Formation show following characteristics:（1）The pore of the Niutitang shale can be divided into four categories: interparticles pores, intraparticles pores, organic matter pores and microfractures .（2）The pores structure of shale shows three characteristics: the micropores frequency peaks is higher than that of mesopores in the dV(d) curve, and specific surface area frequency is greatest in micropores, these pore characteristics primarily appear in siliceous shale; Pore volume frequency is primarily dominant in mesopores, which mainly appear in carbonaceous shales; The pore volume peaks of micropores and mesopores are extremely low, and specific surface frequency is commonly dominant in mesopores, which mainly appear in silty shale.（3）Organic matter and quartz are beneficial to the growth of shale porosity, and organic matter in shale main control factor in the development of micropores, while quartz is a primary control factor in mesopore and macropore development; High clay mineral content is not conducive to shale porosity development, and is particularly detrimental to the development of micropores.（4）The function relationship between buried depth and the adsorbed gas capacity was establish based on the relationship of temperature and pressure with gas adsorbed. The results suggest that the maximum gas adsorption capacity occurs at depths around 1,800 m, and pressure is the dominant control factor at depths below 1,800 m, where gas adsorption capacity increases with depth; while temperature is the primary control factor at depths greater than 1,800 m, where gas adsorption capacity decrease with depth.（5）Black shale of the lower Cambrian under High evolution, Good pore structure(pore volume and specific surface area) and high TOC are advantageous to the gas adsorption capacity of the highly mature lower Cambrian black shales, while high maturity and clay content may inhibit gas adsorption capacity. Key words：：Southern Margin of Yangtze Block, Niutitang Formation, Pore Characteristics, Gas Adsorption, Control Factors Funded Project: Science and Technology of Sichuan Province Support Planning Project（15ZC1390） Corresponding Author: Liu Shugen (1964.10-), Male, Professor, Major research interest: Oil and Gas accumulation and structural geology, E-mail: [email protected].

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1 Introduction Shale gas exploration has recently become a major focus of E & P companies in many countries in Asia, Europe, and the Americas. The extensively explored Barnett Shale in the southern United States is regarded as a successful case and model for shale gas exploration and exploitation in different basins around the world

1,2

. However, the production model of the Barnett Shale gas in the Fort Worth basin

cannot be dogmatically reproduced in other basins or areas3,4 due to the differences in geography, local geologic setting, and the transformation path of organic carbon in the shale, thus each of the occurrences has to be treated as unique5-9. Because shale gas reservoirs are different from conventional gas reservoirs, the complex nature of gas storage is a focus of unconventional reservoir research10-13.Though China is considered the country with the second richest shale gas reserves in the world14, there is still no agreement on the reservoir characteristics9, 15-16.The Longmaxi Shale and Niutitang shale in the Upper Yangtze block are two of the major gas shale prospects in China. The relatively poor understanding of reservoir conditions in the Upper Yangtze block is partially due to the complex tectonic background of the area, which experienced several episodes of intensive tectonic uplift after the end of gas generation17,18, affecting the gas-bearing properties of the shale reservoirs in the Sichuan Basin9,15-16, and

increasing the difficulty of

shale gas exploration. Presently, only the Jiaoshiba and Yibin-Changning formations have yielded high industrial gas flow rates in the Longmaxia formation, however, the Niutitang shale has thus far not experienced any significant breakthroughs. At present, the reservoir, pore structure, and gas adsorption characteristics of the lower Silurian shales in the Yangtze Block have been extensively studied15, 19-21, the Lower Cambrian black shales in the Yangtze Block have not been systematically studied. The present study of the Niutitang formation shale is mainly concentrated in the relationship between the pore type and organic matter or mineral, and gas adsorption characteristics19, 22-27. However, there is less research about control factors behind pore structure , adsorption gas, and the relationship between the adsorption gas and buried depth. Therefore this investigates focuses on controlling factors of pore structure and gas-adsorption of the lower Cambrian Niutitang formation in the southern margin of the Yangtze. The results of this study will be significant for understanding the gas-bearing potential of the lower Cambrian shale reservoirs, and provide a foundation for future breakthroughs in shales gas of the Lower Cambrian in southern Yangtze margin.

2 Geological Setting After the Neoproterozoic rift events, the Yangtze Block evolved into a passive continental margin basin during the Ediacarane-Cambrian transition28-30 The Cambrian Period defines the beginning of metazoan expansion and eukaryotic diversification, with its lowest part stratigraphically correlated using assemblages of Small Shelly Fossils (SSF’s)28.Due to the Early Cambrian global sea level rise, black shales were deposited over almost the entire Yangtze Block, which unconformably covered the lowermost Ediacaran Cambrian platform carbonates or conformably overlay the coeval black chert-shale successions basin-wards


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in South China30-32. This study focuses on the Ediacaran–Cambrian successions in the southern margin of the Upper Yangtze Platform. Paleogeographically, it was located in a deep-water lower slope to basinal setting south of the Yangtze Platform (Figure. 1)33, 34. A section of the JY-1 well, located at Jinsha County in western Zuiyi, was selected for the study of pore structure and gas adsorption. The“deep-water” Ediacaran–Cambrian successions include the Dengying Formation (composed of dolomite) and the overlying Laobao Formation, composed of a 7.05 m thick layer of basal chert and siliceous shale layer. The Laobao Formation is overlain by the 112.8 m thick Niutitang formation, which is composed of a carbonaceous shale layer, a carbonaceous mudstone and interbedded calcareous siltsone, and finally a silty mudstone layer interbedded with calcareous sandstone. Finally, the Niutitang Formation is overlain by the gray shale of the Mingxinsi Formation(Figure, 2).

Figure.1 Lithofacies paleogeographic brief map of Yangtze block during the Ediacaran–Cambrian transition


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Figure 2 Histogram of lower Cambrian sedimentary facies from the Jinye 1well. Pictures of cores and microstructures are provided at different depth intervals. Sample names and depths are provided to the right of the stratigraphic column. 1-Dolomite; 2-Siliceous shale; 3-Phosphorites; 4-Limestone; 5-Carbonaceous mudstone; 6-Silty mudstone; 7Calcareous siltstone; 8-“Ni-Mo metal layer”


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3 Samples and Methods The lower Cambrian black shales from the Jinye 1well in the southern margin of the Upper Yangtze Platform were chosen for study. The Laobao - Niutitang Formation is 119.85 m thick at the Jinye 1well (Figure. 2). A total of 166 samples were collected for TOC studies, 48 samples were collected for X-ray diffraction analyses, and 18 samples were collected for FE-SEM imaging, low pressure nitrogen adsorption and methane isothermal adsorption. tests. The total organic carbon (TOC) was measured by a LECO CS-200 analyzer after the samples were treated by hydrochloric acid to remove any carbonates. X-ray diffraction (XRD) analysis of shale powders was carried out on a XRF-1500 Advance X-Ray diffraction at 40 kV and 30 mA with Cu Kα radiation (λ = 1.5406 for CuKα1). Stepwise scanning measurements were performed at a rate of 4° /min in the range of 3° – 85° (2θ). The relative mineral percentages were estimated semi-quantitatively using area of the major peaks of each mineral with correction for Lorentz Polarization35. EI™ Quanta™ 200F scanning electron microscope was employed to observe the microstructure morphology. It could produce images of nanopore structure with high resolution of 1.2 nm and a magnification of 25 k e 200 k. Shale samples were ground with fine grit sand paper, underwent argon ion beam milling to produce a much flatter surface, and coated with a 4 nm thick layer of gold to avoid charging. Low pressure nitrogen adsorption isotherms were obtained at −195.8 °C on an accelerated surface area using a porosimetry system (Quadrasorb SI). The samples were crushed into grains of 60-80 mesh size (180 – 250 µm), dried in an oven at 110 °C overnight, and degassed under high vacuum ( 2.0% are about 62.62 m thick, while the layers of black shales with TOC > 3% are 54.99 m thick. The TOC of the siliceous shale from the Laobao formation ranges from 1.28% to 11.48%, with an average of 5.52%. The TOC of black carbonaceous shale in the first section of the Niutitang formation ranges from 0.36%to 11.83%, with an average of 4.79%.The TOC of the black carbonaceous shale in the second section of the Niutitang formation ranges from 0.10% to 1.02%, with an average of 0.27%. The TOC of silty mudstone in thethree sections of the Niutitang formation range from 0.10% to 0.22%, with an average of 0.15%.The TOC of the Lower Cambrian black shales gradually decreases from the bottom to the top of the formation (Figure 3). Table 1Organic geochemical characteristics of the lower Cambrian black shale in Jinye1 well, including lithology, kerogen type, organic matter abundance, and thermal maturity. Kerogen type Epoch

Lithology

Lower

Organic matter abundance 13

Organic matter maturity

Saprope

Type

δ Corg

TOC

S1+S2

Ro

Tmax

l

index

(‰)

(%)

(mg/g)

(%)

(℃)

—

—

—

0.31

2.29

565

—

—

-30.2

Black shale

Cambrian

Niutitang Formation

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Third

Calcareous

part

Sandstone

Second

Silty

part

Sandstone

First

Carbonaceous

part

Shale

Laobao

Siliceous

Formation

Shale

Annotation：

：

2.11

—

。

Thermal maturity was measured in 18 samples using a reflected light microscope. The parameter obtained is vitrinite-like reflectance (Rom), also called “marine” vitrinite. Its relationship to true vitrinite


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reflection (Ro) was experimentally established by Zhong and Qin(1995)40. The vitrinite-like reflectance (Rom) can be transposed into equivalent vitrinite reflectance (Ro)39, which can be used for reservoir evaluation. The equivalent vitrinite reflectance (Ro) in the Niutitang Shale samples are determined to be between 0.79% and 5.28%, with a mean value of 3.11%, indicating a moderately high thermal maturity stage(Table 1,Figure 3).

Figure 3 Comprehensive parameters of the Lower Cambrian shale gas in the Jinye1 well, including GR

log, TOC, %Ro, and Specific Surface Area.

4.2 Mineral Compositions A total of 48 black shale samples from the lower Cambrian were chosen for XRD analyses. The mineral composition of the studied samples included clay minerals(illite, chlorite and minor amounts of montmorillonite), quartz, feldspar, carbonates (calcite and dolomite), pyrite and apatite(Figure 3).Quartz content gradually decreases from bottom to top of the formation, ranging from 17% to 80% with an average of 35%. Clay content ranges from 8% to 72% with an average of 49%.The siliceous shale at the bottom of the formation has an average clay content of 20%, and the average clay content gradually increases from the base to the top of the formation. The silty mudstone at the top of the formation has an average clay content of65%.The average carbonate mineral (calcite and dolomite) content is 10.07% (ranging from 0%


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to 31.31%), average feldspar content is 5.23% (ranging from 0% to 14.51%). Feldspar content is lowest at the bottom of section, and increases towards the top of the section. Terrigenous input and falling sea level led to an increase in feldspar content. The clay mineral content is dominated by illite and chlorite(Figure 4), the relative content of illite varies from 22% - 75% with an average of 45%, while chlorite content ranges from14% - 78% with an average of 38%. A small amount of montmorillonite was found at the bottom of the section. In addition, the black shales generally contain a minor lIllite/smectite mixed layer, but lack kaolinite. Based on these observations, the Lower Cambrian black shales experienced a high thermal maturity stage. At temperatures over 200 degrees C (Ro > 2.0), montmorillonite an orderly transformation to illite and Illite/smectite mixed layer, while kaolinite has been completely transformed into chlorite and illite. Therefore, it can be concluded montmorillonite resulted from drilling contamination, as montmorillonite is normally transformed into mixed layers at 3km of burial.

Fig 4 Mineral composition of black shale from the Laobao-Niutitang formation in Jinye 1well.

4.3 FE–SEM Imaging 4.3.1 Pore Type After a detailed study of the FE-SEM images of the Lower Cambrian black shale, four different pore types were recognized: intrapore, interpore, micro-fracture and macerapores(Figure 5), the pore types was identified in accordance with

the classification scheme of Loucks (2012)41.

(1) Intrapores exist in framework minerals, cement and fossil. Intrapores are most commonly spherical in shape, but also include groove and honeycomb shapes. Pore size also differs, ranging from the dozens of nm up to 10 microns, but with relatively poor connectivity. In framework minerals, intrapores mainly


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develop in quartz, feldspar, clay, carbonate minerals, mica and framboidal pyrite. The characteristics of these framework minerals largely determine the intrapore formation mechanism. Quartz is stable, and there are relatively few intrapores in quartz minerals(Figure 5a). Intrapores in clay are largely the result of compaction (Figure. 5b),dissolution, and the conversion of montmorillonite to illite during burial. Intrapores are more easily formed during dissolution of carbonate and feldspar (Figure 5c and e). Pyrite may also contain intrapores formed from dissolution (Figure 5d), and intrapores may also form by cleavage of mica (Figure 5e). The degree of intrapore development largely depends on mineral stability. Intrapores are less developed in stable minerals such as quartz, while intrapores are more prevalent in less stable minerals such as feldspar, dolomite, and calcite. (2)Interpores occur in open spaces of the grain fabric, which is primarily composed of quartz (Figure 5f), clays (Figure 5g), feldspar (Figure 5 h), pyrite and dolomite (Figure 5i). Interpores have a greater diameter compared to other types of micropores, ranging from several ten to several hundred nanometers in diameter. This pore type also has good connectivity. Quartz grains have small interpores, but good porosity, while clays, feldspars, and pyrites contain fewer, but larger interpores compared to quartz. Interpores were the second most abundant pore type observed in the investigated samples, and most interpores exhibited irregular, belt-, chain- or ball-like shapes. (3)Micro-fractures occur in the matrix grains or the rims of grains (clay, quartz and feldspar).Quartz micro-fractures are the result of differences in hardness between quartz and its surrounding minerals during formation(Figure 5 k). Clay and feldspar micro-fractures result from the dehydration of clay during diagenesis (Figure 5 l , m). Clay and feldspar micro-fractures generally have widths of less than 100 nm, while their length cannot be determined. (4) Macerapores appear during the maturation of organic matter1, 2.Macerapores begin to develop when organic matter reaches the gas window at approximately 1.2%vitrinite reflectance (%Ro)42. Macerapores are generally absent in organic matter with low thermal maturity. For example, macerapores were not found in Woodford shale samples with 0.51 – 0.90% Ro43. The Niutitang shale samples experienced a moderately high stage of thermal maturity, and numerous macerapores have been observed in the organic matter of shales. Macerapores were mainly concentrated in organic matter among quartz particles(Figure 5n) or clay minerals (Figure 5k), but were rare in other types of minerals. Macerapores range in shape from honeycomb to globose and stomatal (Figure 5 n, k). The FE–SEM images show that OM-hosted pores are better preserved when surrounded by rigid framework minerals.


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Figure 5 Pore types of lower Cambrian black shales from the Jinye 1 well. Pore type and mineral type are indicated on the axes.

4.3.2 Pore Size Distribution Based on scanning electron microscopy images of the lower Cambrian shale samples, if was found that the abundance of pores of small aperture gradually decreases, while pores of large aperture increase from the base to the top of lower Cambrian black shale. Due to the decreasing abundance of pores, the total porosity decreases upwards (Figure 6). The pore size distribution of samples from different intervals was analyzed. Based on statistics analysis, 555 pores with diameters less than 50 nm were found, accounting for 37.8% in siliceous shale of Laobao formation, counting for 25.6% in first part of Niutitang formation, accounting for 5.1% in second part of the Niutitang formation, and 10.8% in the third part of Niutitang formation. The abundance of small aperture pores gradually decreases from the base to the top (Figure 7) of the Laobao - Niutitang section. The frequency of pores measuring 50 -500 nm gradually increases, the frequency of the large aperture pores in the four interval frequency are 55.5%, 61.5%, 83.4% and 81.8% respectively from base to top (Figure 7). The peak frequency of pores > 10 nm occurs in the carbonaceous shale of the first part of Niutitang Formation (Figure 7).


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Figure 6 Characteristics of vertical variation of microscopic pores in the Lower Cambrian Niutitang Formation. The figure provides examples of the three different pore types and fractures at different depth intervals. Scale size is provided at the bottom right of each photograph


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Figure 7 Pore diameter and frequency of pore distribution in the lower Cambrian black shale. The relative depth and wells at which samples were collected are indicated next to the stratigraphic column.


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4.4 Low Pressure Nitrogen Gas Adsorption 4.4.1 Characteristics of Nanometer Pore Size Low-pressure gas adsorption using N2 as the adsorbate is the most commonly used method for determining pore volume, surface area and pore-size distribution in shales. The DFT of nitrogen gas adsorption method is adopted for pore size distribution (Figure 8 e, Table 2). The pore size distribution of black shale is an expression of isotherm characteristics (Figure 8 e). The pore definition was provided by the International Union of Pure and Applied Chemistry (IUPAC): micropores (diameter

Characteristics of Black Shale Reservoirs and Controlling Factors of

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