Article pubs.acs.org/EF
Organic Matter Pore Characterization in Lacustrine Shales with Variable Maturity Using Nanometer-Scale Resolution X‑ray Computed Tomography Fujie Jiang,*,†,‡ Jian Chen,†,‡ Ziyang Xu,†,‡ Zhifang Wang,†,‡ Tao Hu,†,‡ Di Chen,†,‡ Qinglin Li,†,‡ and Yaxi Li†,‡ †
State Key Laboratory of Petroleum Resources and Prospecting and ‡College of Geosciences, China University of Petroleum (Beijing), Beijing 102249, China ABSTRACT: Mature-stage lacustrine shale was sampled from the Late Triassic Chang 7 member in the Ordos Basin, China. Two aliquots separated from the original sample were heated by hydrous pyrolysis to high- and overmature stages. The three samples were analyzed by nanometer-scale resolution X-ray computed tomography (nano-CT). From the distribution and geometry of the organic matter pores (OM pores) in the two-dimensional (2-D) nano-CT images, this study calculated the total organic matter content and porosity of the OM pores (2-D TOC and 2-D OM porosity, respectively) and characterized the OM pores and throats. The results suggest the following: (1) The OM pores tended to distribute centrally rather than sparsely throughout the organic matter, and large-area pores existed above a 2-D TOC threshold of 2%. (2) The main diameter range of the OM pores was 100−700 nm, and the number of OM pores increased with maturity. (3) The amount of coordination numbers corresponding to a given pore diameter interval and the number of pores corresponding to the same range of coordination numbers (1−10) were greater in the high-mature and overmature samples than in the mature samples, indicating that the OM pore connectivity improved with maturity. The three-dimensional volume data confirmed that the OM pore connectivity decreased in the following order: high-mature, overmature, and mature samples. Highly mature samples may be more conducive to the diffusion of natural gas within the OM pores.
1. INTRODUCTION To meet today’s continuously increasing energy demands, researchers have explored and developed unconventional resources.1,2 From 2005 to 2013, the total natural gas production in the United States increased by 35% mainly because of development of shale gas resources in the lower 48 states.3 Shale has long been ignored as a reservoir of natural gas because of its low porosity and permeability.4,5 However, modern horizontal drilling and hydraulic fracturing technologies can transform low-permeability shale gas reservoirs into commercial assets, permitting the economic exploitation of shale gas.1,6 The volume and specific surface area of the pores affect the storage phase and migration of the natural gas within shale. Pore space connectivity is necessary for delivering gas to the borehole in native unfractured shale.7 On the basis of the microscopic pore geometries, pore positions, and shale mineral grains, pores have been classified and characterized as silt-like, intrapores, interpores, organic matter pores (OM pores), and mineral pores.8,9 Pores have been further classified as micropores (50 nm) according to their diameters. 10 OM pores demonstrate better adsorption ability than mineral pores and provide the main storage space for adsorbed shale gas.8,9 To identify the storage and migration mechanisms of shale gas, characterizing the OM pores is essential. Recently, the volume and distribution of OM pores were found to depend on the maturity of the shale. Most studies have proposed that the maturity level positively affects the OM pore volume, porosity, number of pores, and formation of new OM pores.11,12 Sun et al. characterized shale from the Chang 7 © 2017 American Chemical Society
member in the Ordos Basin, China, using low-pressure nitrogen adsorption and reported that increasing the maturity promotes the formation of new OM pores, most of which are mesopores and micropores.13 However, other researchers have proposed a decrease in the OM pore number with increasing maturity.12 Pores are typically analyzed and characterized by indirect and direct analytical methods. Using indirect methods, such as lowpressure nitrogen and carbon dioxide adsorption, the volume and diameter are calculated, and the pore distribution is characterized using mathematical models.14 These methods accurately quantify the pore features but cannot provide the morphological pore characteristics and spatial relationships between the pore and shale components. In contrast, direct methods such as scanning electron microscopy (SEM) and backscattered electron (BSE) imaging lack quantification abilities but can illustrate the pore geometry, distinguish minerals such as pyrite, and locate organic matter at the micrometer and nanometer scales.1,4,8 Hundreds of twodimensional (2-D) BSE or SEM images can be reconstructed into three-dimensional (3-D) micro- or nanoscale volume data images, from which we can derive the pore diameters and volumes in porous systems and analyze their microconnectivity.2,7,15 From these 3-D volume data images, pores can be characterized both qualitatively and quantitatively. Nanometerscale resolution X-ray computed tomography (nano-CT) can determine the inner structure of a sample without requiring Received: December 13, 2016 Revised: February 3, 2017 Published: February 6, 2017 2669
DOI: 10.1021/acs.energyfuels.6b03313 Energy Fuels 2017, 31, 2669−2680
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Energy & Fuels
Figure 1. (A) Location of the Ordos Basin, China. (B) Structural unit division of the Ordos Basin and the location of the study area.17 (C) Location of the sampled well.
temperatures of 392 and 456 °C were 0.74%, 1.23%, and 2.32%, respectively. The three samples (the original sample and both pyrolyzed samples) were analyzed by nano-CT. (1) The OM pore distributions and sample microstructures were visually characterized using 2-D images from the three samples. The pore distributions were then quantified by determining the numbers of OM pores with various diameters from 3-D volume data of the pore−throat system. (2) The effects of organic matter on the pores were assessed by calculating the total organic content and OM pore porosity (2-D TOC and 2-D OM porosity, respectively) from the 2-D images. The maturity was then related to the derived OM pores (OM porosity). (3) The pore connectivities of the samples with different maturities were derived from the coordination numbers of the samples,
polishing (which risks damage to the sample). Nano-CT quantifies the microfeatures of OM pores and displays the pores and organic matter as 2-D nano-CT images. Data on the pore characteristics, such as the coordination number and OM porosity, can be extracted from the 3-D volume data of the pore−throat system, and the pore connectivity can be displayed in the visual 3-D volume of the connected pores. Therefore, this method combines the advantages of both direct and indirect methods. In this study, two samples were separated from the original lacustrine shale from the Chang 7 member in the Ordos Basin, China, and the samples were subjected to hydrous pyrolysis at 392 and 456 °C. The Ro values (vitrinite reflectance values) of the original shale sample and the samples matured at pyrolysis 2670
DOI: 10.1021/acs.energyfuels.6b03313 Energy Fuels 2017, 31, 2669−2680
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Energy & Fuels and the connectivities of the shale samples were visually ranked by scrutinizing the 3-D volume images of mutually connected OM pores. Finally, the diffusion of natural gas in the OM pores was speculated based on past studies.
2. GEOLOGICAL SETTING The Ordos Basin (area, 320 000 km2) is located in the northwestern part of the North China Plate (Figure 1A).16 This basin is a north-trending giant syncline that dips gently to the east and climbs steeply to the west. This basin is divided into six structural units: the northern Yimeng uplift zone, the southern Weibei uplift zone, the eastern Jinxi fold belt, the western Tianhuan depression, the Xiyuan thrust fault belt, and the middle Yishan slope zone (Figure 1B).16 The Ordos Basin has experienced five tectonic evolutionary stages: Meso-Neoproterozoic aulacogen, early Paleozoic shallow marine platform, late Paleozoic strand plain, Mesozoic inland depression, and Cenozoic fault depression. This basin has a crystalline basement composed of Archean and Paleoproterozoic layers.16,17 The basement of the Ordos Basin is crystalline rock from the Archean Eonothem and Palaeoproterozoic era, which has have undergone five tectonic evolutionary stages: Meso-Neoproterozoic aulacogen, Early Paleozoic shallow marine platform, Late Paleozoic strand plain, Mesozoic inland depression, and Cenozoic fault depression.18,19 Starting from the Early Triassic, Ordos massif uplifted in the east and sank in the west, forming the basin prototype. The tectonic activities from the Late Triassic to Late Cretaceous had a significant influence on the generation and aggregation of hydrocarbons in the Ordos Basin.20 The Yanchang Formation, deposited by a freshwater lake that formed in the Ordos Basin during the Late Triassic,21,22 constitutes most of the reservoir and source rock in the Ordos Basin.23 The Yanchang Formation is 690−1415 m thick24 and is mainly composed of shale and mudstone in the basin center and sandy mudstone at the basin margins.25 The Yanchang Formation is divided into 10 members labeled Chang 10 to Chang 1 (Figure 2). The main sedimentary environments from the Chang 10 member to the Chang 8 member were fluvial, delta, and alluvial fan. The ancient lake area was the largest in the Chang 7 member, when the main sedimentary environment was a deep lacustrine with sediments dominated by organic-rich black-gray deep lacustrine shale and mudstone.21,22 During the Chang 6 member to Chang 1 member period, the ancient lake area and water depth decreased, and the main sedimentary environment was fluvial and swampland.21 The samples were obtained from the Fuye-2 well located on the southwest Yishan slope (Figure 1C). The original shale sample was a core collected from the Chang 7 member, one of the main source rocks, with a thickness ranging from 78 to 120 m.24,26,27 The Chang 7 member lacustrine shale has a Ro of 1.7%−1.2%, has a low porosity of 0.1%−13.14%, and mainly generates hydrocarbons (HCs) as wet gas.28 The gas content in Chang 7 member shale is 3.71−6.26 m3/t, and the adsorption gas percentage exceeds 50%.29 The resource volume in Chang 7 member shale is 4.47−8.83 × 1012 m3.30
Figure 2. Stratigraphic column, source, reservoir, and position of the Chang 7 member core sample.22 3.1. Sample Preparation. The original shale sample from the Late Triassic Chang 7 member in the Ordos Basin was collected from the Fuye-2 well at a depth of 1417.01−1417.12 m. In a Rock-Eval pyrolysis analysis, the values of the S1 peak (dissolved hydrocarbons) and S2 peak (pyrolyzed hydrocarbons) were determined as 7.3 mg/g and 15.99 mg/g, respectively (Table 1). The total organic content (TOC)
Table 1. Geochemical Parameters of the Three Samplesa sample
Ro (%)
TOC (%)
S1 (mg/g)
S2 (mg/g)
S1 + S2 (mg/g)
kerogen type
H0 H1 H2
0.74 1.23 2.32
6.11 5.72 2.01
7.30 1.62 0.48
15.99 2.50 0.21
23.29 4.12 0.69
II1 II1 II1
a
Ro, vitrinite reflectance; TOC, total organic carbon content; S1, dissolved hydrocarbons; S2, pyrolyzed hydrocarbons; and S1 + S2, hydrocarbon generation potential. of the original sample was determined to be 6.11% using CS-230HC analysis (Table 1). A Ro of 0.74% indicated that the original sample was thermally mature. The kerogen type of the original sample was determined to be II1 by the transmission-fluorescent light kerogen maceral identification method, which uses the type index for classification (Table 1). Type II1 kerogens refer to H/C atomic ratios of 1.0−1.4 and O/C atomic ratios of 0.10−0.15 (Table 2).31 The type index of the original sample (labeled H0) was 76.25% (Table 3). The kerogen maceral identification and the combination of the H/C and O/C atomic ratios confirmed the same kerogen type.32 3.2. Experimental Procedure for Hydrous Pyrolysis. Two shale aliquots weighing 25 g each were artificially heated to achieve higher thermal maturity. We set the artificial temperatures at 407 and 456 °C to vary the Ro of the artificially matured shale sample. The hydrous pyrolysis experiments involved isothermal heating of the shale samples with 4 mL of distilled water in an autoclave for 72 h. The water addition ensured that the simulated HC formation approximated
3. METHOD The hydrous pyrolysis experiments and parameter testing of samples were conducted in the State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum, Beijing. Nano-CT was implemented at the Beijing Research Institute of Petroleum Exploration and Development, PetroChina. 2671
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Energy & Fuels Table 2. Kerogen Type Classifications Based on the Combined H/C and O/C Atomic Ratios and Type Indexes31,32
I = I0 exp[−
I
II1
II2
III
H/C atomic ratio O/C atomic ratio type index
>1.40 80
1.00−1.40 0.10−0.15 80−40
1.00−0.80 0.15−0.20 40−0
0.20 H2 > H0. This order indicates that the OM pores were better connected in the highmature shale than in the overmature shale and better connected in the overmature shale than in the mature shale. The diffusion coefficient, D, of the natural gas can increase with the increasing OM porosity, which may be attributed to the increased number and improved connectivity of the OM pores. Our investigation was limited to OM pore characterization; however, various types of pores, OM, mineral, and OM− mineral pores are connected geologically. The spectrum of different pore types should be studied quantitatively to improve our understanding of the storage and diffusion of natural gas in 2679
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