Characterization of Acidic Compounds in Ancient Shale of Cambrian

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Characterization of Acidic Compounds in Ancient Shale of Cambrian Formation Using Fourier Transform Ion Cyclotron Resonance Mass Spectrometry, Tarim Basin, China Meng Wang, and Guangyou Zhu Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b04220 • Publication Date (Web): 28 Jan 2019 Downloaded from http://pubs.acs.org on February 5, 2019

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Energy & Fuels

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Characterization of Acidic Compounds in Ancient Shale of

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Cambrian Formation Using Fourier Transform Ion Cyclotron

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Resonance Mass Spectrometry, Tarim Basin, China

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Meng Wang†, Guangyou Zhu†*

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†

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100083, PR China

Research Institute of Petroleum Exploration and Development, PetroChina, Beijing

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0. Abstract

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The polar acidic compounds in the lately found Cambrian Formation shale from

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Tarim Basin have been characterized by electrospray ionization Fourier transform ion

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cyclotron resonance mass spectrometry (ESI FT-ICR MS). These marine type-I

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source shale have different thermal maturity levels. The acidic species ocurred in the

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bitumen of source rocks are mainly O2, O3, O4 and O5 compounds. Results of FT-ICR

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MS suggest the production of n-alkanes from the fatty acids during diagenesis and

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thermal maturation. High abundance of C32 hopanoic acid has been tentatively

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identified in several samples. Results clearly show the compositional dependence of

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acidic compounds on the thermal maturation levels of source rocks. O2 class species

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gradually increase, together with the decrease of O3 and O4 class species with the

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increasing maturation, which also enhances the condensation degrees and decreases

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the alkylation degree of the acidic compounds in shale. These effective source rocks

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represent the promising ultra-deep exploration potential of the Cambrian formation in

ACS Paragon Plus Environment

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Tarim Basin. This work may contribute to deeper understanding of origin, migration

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and charge histories of crude oils in Cambrian petroleum system in Tarim Basin.

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Keywords：Ultra-deep source rocks, acidic compounds, FT-ICR MS, shale,

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petroleum exploration

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1. Introduction

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In petroleum generation process, initial kerogen in source rocks decomposes partially

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to polar bitumen, which further decomposes to oil and gas.1 Biomarker

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characterization and n-paraffin isotopic analyses are conventional and useful tools for

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investigating the sedimentary environments and maturity of source rocks as well as

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the thermal evolution and secondary alterations of crude oils.2 Nevertheless, studies of

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the polar compounds in bitumen in source rocks remain limited. Fourier transform ion

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cyclotron resonance mass spectrometry (FT-ICR MS) is an advanced tool for

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characterization of compounds in ultra-complex natural organic mixtures. It could

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provide sufficiently high mass resolving power and accuracy for unambiguous

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formula identification of compounds in crude oils and source rocks. Electrospray

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ionization (ESI) source could seletively ionize polar compounds, avoiding the

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interference from hydrocarbon background. Recently, “Petroleomics”, based on

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sufficient characterization of petroleum at the molecular level, is adopted to correlate

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the properties and behavior of petroleum under various conditions.3 Practical

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examples in upstream industry include studies correlating crude oil properties and

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behavior (e.g. origins, maturity, biodegradation and migration history) with its

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composition.4-15

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Geochemical characterization of source rocks can provide important information for

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their organic matters origin, depositional environments, thermal maturity as well as

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quality and quantity of oil and gas to support hydrocarbon exploration and


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developments.16,

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topic of petroleum exploration.18, 19 Cambrian and Sinian systems in deep basins are

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the major objects for petroleum geology research in China.20 The exploration of

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commercial oil and gas in Lower Cambrian ZS1C well (6944 m) in Tarim Basin,21

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which is believed from the Cambrian Yuertusi source rocks, has caused great concern

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of the petroleum exploration community.22 This has revealed new deep exploration

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strata and advanced the discovery of ancient hydrocarbon accumulation. Tarim Basin

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is the largest oil and gas bearing area in China, where the main objective formations

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are deeply buried. The deepest Paleozoic marine reservoir in the world (7750 m) was

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discovered in the Ordovician system,23 which greatly encouraged the morale to find

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hydrocarbon accumulations in the ultra-deep reservoirs. Source rocks are obviously

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the prerequisite for oil and gas occurrence. Because of the deep burial of source rocks

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in Cambrian and Precambrian systems and the lack of drilling samples, the source

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rocks in outcrop area need to be studied. Zhu et al. have reported the discovery of the

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Cambrian Yuertusi source rocks in Tarim Basin,22 however, the geochemical

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characteristics of organic matters especially the polar species in them are not well

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studied.

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In this work, molecular composition of organic compounds from the ancient shale of

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the Yuertusi Formation in Yutixi area, were investigated by ESI FT-ICR MS and

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GC-MS. The results provide new geochemical information for effect of maturity on

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the distribution pattern of acidic species in shale from an infrequently explored part of

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the Tarim Basin, which will be helpful for oil-source correlations, oil migration from

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origins to reservoirs and oil charge histories in ultra-deep strata of Tarim Basin.

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2. Geological setting

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Tarim Basin is composed of the metamorphic basement in Neoarchean-Early

In recent years, the ancient formation has gradually been a hot


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Neoproterozoic system and marine continental-transitional facies-continental facies

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sedimentary cover in Neoproterozoic-Palaeozoic system. In early and middle

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Neoproterozoic, Tarim craton was unified by the collision and joint of Tarim land

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plates in south and north and arcterrane in the central part of basin.24 Then, it entered

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into the evolution of craton and the first sedimentary cover developed in

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Nanhua-Sinian period. The global transgression occurred at Lower Cambrian with

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widely development of shale. The high quality source rocks can be discovered in

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drilling and outcrops of Tarim Basin. The high-quality source rocks of Yuertusi

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formation in the bottom of Lower Cambrian are shale and they are well-exposed in

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Yutixi (YTX) outcrop section of Aksu area, NW Tarim Basin.

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3. Samples and methods

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3.1. Samples. A total of 7 Cambrian samples were collected from the YTX outcrop

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section (YTX01~YTX07). Fresh samples were collected during mining to avoid the

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possible effects of weathering on the nature of outcrop shale. All the samples were

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analyzed for total organic carbon (TOC), vitrinite reflectance (Ro), stable carbon

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isotope value of kerogen (δ13Corg). The samples were crushed to 100~200 mesh and

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extracted for 48 h with dichloromethane and methanol (v/v = 99/1) by Soxhlet

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extraction. Bitumens were obtained after removing the solvents in the extraction

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solution. One part of the bitumens was subjected to ESI FT-ICR MS analysis without

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any seperation. The other part of the bitumens was separated into aliphatic

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hydrocarbons, aromatic hydrocarbons, nonhydrocarbons and asphaltenes by silica gel

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and alumina column chromatography, and the aliphatic hydrocarbons were


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characterized by GC-MS.

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3.2. Measurements of TOC, Ro and δ13Corg. TOC was measured with a Leco

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CS-200 carbon-sulfur analyzer after the samples were treated with hydrochloric acid

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(10%) to remove the carbonate and the analysis precisions are ±0.5%. Ro

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measurements were conducted on a Leica microscope, and at least 30 vitrinite

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particles were measured in each sample. The Kump method was used to determine the

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carbon isotopes in kerogen (δ13Corg). First, approximately 3.5 g sample was dissolved

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in 4M hydrochloric acid for 24 hours. The processed samples were repeatedly washed

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with distilled water until they were pH neutral, and dried at 60 oC. The collected

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samples were then mixed evenly with Cu2O powder at a mass ratio of 1:8, placed in a

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quartz tube which was then evacuated and sealed, and placed in a muffle furnace for

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reaction at 850 oC. CO2 was collected by opening the vacuum line, and the carbon

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isotope compositions were measured using a MAT253 gas isotope ratio mass

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spectrometer. The isotopic values were reported in parts per thousand relative to the

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Vienna Peedee Belemnite.

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3.3. Negative-ion ESI FT-ICR MS Analyses.

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The bitumens were dissolved in toluene and diluted to a final concentration of 0.2

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mg/mL with toluene/methanol (3:1, v/v). About 20 μL of ammonia was added to 1

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mL of the final solution of the analyte to enhance the ionization efficiency of acidic

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compounds. MS analyses were performed using a Bruker FT-ICR MS instrument

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(Model Apex-Ultra 9.4 T). The diluted samples were injected into the spray needle

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with a syringe pump at the rate of 180 μL/h. The operating conditions for negative ion


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mode were set as follows: spray sheld voltage = 3.5 kV; capillary column introduction

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voltage = 4.0 kV; and capillary column end voltage = -320 V. Ions were accumulated

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for 1 ms in a hexapole with 2.4 V direct current and 500 V radio-frequency (RF)

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amplitude. Optimized mass for the quadrupole was 200 Da. An argon-filled hexapole

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collision pool was operated at 500 V RF amplitude and 5 MHz, in which ions

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accumulated for 0.2 s. The delay generally was set to 1.0 ms to transfer the ions to an

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ICR cell by the electrostatic focusing of transfer optics. The RF excitation was

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attenuated at 13.75 dB and used to excite ions over the range of m/z 150~800. The

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dataset size was set as 4 megabytes. Mass spectra were internally calibrated using an

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extended homologous alkylation series (quasi-molecular ion of carboxylic acids) of

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high relative abundance within the mass range of 200~550 Da. The mass resolving

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power (m/Δm50%) generally was more than 300 000 at m/z 400. Mass spectrum

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peaks with a relative abundance greater than 6 times the standard deviation of the

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baseline noise were exported to a spreadsheet. Data analysis was performed using a

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custom software. The detail of data processing has been described elsewhere.25

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3.4. GC-MS Analyses. An Agilent 7890~5975c system equipped with a HP-5MS (60

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m × 0.25 mm × 0.25 μm) fused-silica capillary column was used for the analyses of

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the aliphatic hydrocarbons. The GC injector was maintained at 300 °C in splitless

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mode. The programmed oven temperature was held at 80 °C for 1 min, increased to

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250 °C at a rate of 3.5 °C /min, and then increased to 300 °C at a rate of 2 °C/min, and

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held constant at 300 °C for 30 min. The MS worked with an electron impact source

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with ionization energy of 70 eV. The full scan mass range was set from m/z 35 to 500


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with an interval of 1 s.

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4. Results and Discussion

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4.1. Source rock characteristics. As shown in Table 1, TOC contents of the YTX

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shale range from 1.77% to 4.87% with an average value of 2.87%. The carbon isotope

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values of kerogen in source rocks which are principally affected by the organic matter

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source and remain constant during the thermal evolution of the organic matter, could

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be used to evaluate the organic matter type.26 The δ13C values of kerogen in the YTX

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shale range between -31.554‰ and -28.103‰ (average = -29.255, Table 1).

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According to the evaluation standards previously presented,27 sediments with δ13Corg

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values lighter than -28.0‰ belong to type I organic matter. The δ13Corg values of most

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YTX shale fall into this range, indicating type I organic matter with strong

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hydrocarbon generating capacity.

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4.2. Acidic Compounds. Negative ion ESI FT-ICR–MS can selectively ionize and

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identify the polar acidic and non-basic nitrogen compounds without interference from

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the hydrocarbon background.28-32 For the bitumen of each YTX shale, more than 1958

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peaks (> 6σ of baseline noise) were detected, of which 1365 were assigned with the

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molecular formulas by exact masses. Figure 1 and Figures S1 to S6 (see Supporting

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Information) show the acidic class species determined from the spectra of the bitumen

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are mainly O2, O3, O4 and O5, whereas non-basic nitrogen compounds were not

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detected due to the low abundance in the samples. The O2 class species are dominant

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among the acidic class species in all shale, which is shown in Figure 1 (left). Figure 1

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(right) shows the typical relative ion abundance map of DBE versus carbon number


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for O2 class species in shale YTX05. O2 class species have a carbon number range of

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10-36 and a DBE value range of 1-13, among which DBE = 1 series is the most

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abundant. The O2 class species with 1 DBE are generally assigned as fatty acids, and

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species with DBE values of 2-7 are naphthenic acids with 1-6 naphthenic rings,28, 33

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even though the hydroxyl O1 class species are also possible present. Species with

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higher DBE values are likely multi-ring naphthenic acids and/or aromatic acids.28

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Specifically, O2 compounds with DBE > 10 could be highly aromatic bi-phenols.31

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Species with a DBE of 5, 6, or higher values and with low carbon numbers are likely

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aromatic acids.

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Figure 2 shows the m/z 85 GC-MS distribution of the aliphatic hydrocarbons from

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YTX05 which contains a full range of C17~C34 n-alkanes and isoprenoids, with some

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loss of the more volatile n-alkanes. The distribution of n-alkane is generally unimodal

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maximising at C25. The values of OEP (odd-to-even predominance) and CPI (carbon

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preference index) of seven samples studied range from 1.00 to 1.23 (averaging 1.07)

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and 1.06 to 1.23 (averaging 1.13), respectively (Table 1). Both OEP and CPI suggest

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slight odd preference in the rock extracts, especially in the range of C19~C25. OEP and

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CPI are used to determine the maturity of organic matter.2 Specifically, CPI and OEP

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values significantly above or below 1.0 indicate low thermal maturity, while mature

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rocks have slight or no carbon-number preference. Values of OEP and CPI support

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that the YTX shale are thermally mature.34 Peters et al. reported that n-alkane

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maximum in range C18~C24 and low CPI value indicate that organic matter was

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derived from phytoplankton, zooplankton and benthic bacteria with no photosynthetic


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organisms and terrestrial plants.2 Therefore, the organic matter in YTX shale was

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interpreted to be derived mainly from planktonic and/or bacterial organisms with little

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terrigenous organic matter contribution, deposited under marine conditions.35 As

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illustrated in Figure 1 (right), the fatty acids with carbon number range of 20–26 show

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slight “even-to-odd predominance”, which also observed in C14–C18 fatty acids.

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Nevertheless, due to the dubious abundance for C16 and C18 fatty acids which often

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act as contaminants2,

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predominance value of fatty acids (OEPFA) is calculated for the carbon number range

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of 20~26. The OEPFA values of YTX shale range from 1.02 to 1.78 (averaging 1.29,

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Table 1). It is known that n-alkanes may be directly derived from epicuticular waxes

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of higher plants or from the genetically related fatty acids by reductive process of

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decarboxylic reaction in sediments.2, 36 Previously documented reducing depositional

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marine environment of YTX shale suggests little terrigenous input of organic matter,

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excluding the possibility of higher plant origin of the n-alkanes. As a result, the

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n-alkanes probably were produced by decarboxylation of fatty acids (lost one carbon

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atom) during diagenesis. Hence, it is reasonable to observe the even-to-odd

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predominance in fatty acids and odd-to-even predominance in n-alkanes of the YTX

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shale, indicating a likely precursor–product relationship.

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The data in Figure 2 also show the high abundances of species at DBE value of 6 and

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a carbon number of 32. As illustrated in Figure S8, bitumen of YTX shale contains

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various pentacyclic naphthenes like hopanes. The species with DBE value of 6 are

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probably hopanoic acids, because previous studies revealed that hopanoic acids

28

in negative ESI analyses of petroleum, the odd-to-even


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possessed similar skeleton structures of hopanes in petroleum or sediments,37-39

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whereas the pentacyclic steroidal acids were rarely discovered in geosphere.40,

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Hopanoic acids with relatively high abundance were also identified in YTX03 and

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YTX04 (see Figure S3 and Figure S4). The species of DBE = 2 and carbon number =

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16 exist in relatively high concentration, but the possible structure cannot be

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speculated for now.

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Figure 3 (top) shows the distributions of O2~O5 class species in YTX shale. The

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relative abundance of O2 class species shows an overall trend of increase from ~50%

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to ~78% with enhancive maturation level (1.13~1.53) of the shale, which is illustrated

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in Figure 3 (bottom). In general, the relative abundance of O3 class species decreases

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from ~30% to ~10% with the ongoing maturation of shale. The distribution behavior

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of O4 class species in samples resembles that of O3 class species, from ~15% droped

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to ~10%. These phenomena are probably due to the decarboxylation and dehydration

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reactions involving the Ox class species.42 For instance, decarboxylation and

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dehydration reactions of the O3 and O4 class species could generate O2 class species

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and accordingly cause an increase in relative abundance. Similar behavior was

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observed in acidic compounds in bitumens of source rocks pyrolyzed to different

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degrees.16

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A comparison of the DBE distribution for O2 class species in selected samples

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(YTX02, YTX03, YTX05 and YTX07) with different maturation levels shows clear

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differences in Figure 4. The species with DBE range of 3~9 was chosen to avoid the

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potential contaminant interference from the C16 and C18 fatty acids as well as the


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anomaly high-abundance species with 2 DBE and 16 carbon atoms. The relative

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abundance of O2 class species with DBE = 3 significantly decreases with increasing

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mature levels. On the contrary, the proportion of O2 class species with larger DBE

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values (5~9) increases continuously with the increasing of vitrinite reflectance values.

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The observations clearly show DBE dependence on maturation of source rocks.

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Generally, compounds with larger DBE valves possess larger core than their

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counterparts with lower DBEs. In other words, the more mature source rocks are, the

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greater relative abundance of acidic compounds with high condensation degrees

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occurs in them. Hence, these results should be due to the occurrence of aromatization

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and/or condensation reactions invovled with acidic compounds which were also

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observed in pyrolysis products of Araripe Basin sediments with increasing thermal

238

maturation and other studies.16, 17 The gradual aromatization and condensation of O2

239

species with lower DBE to those with higher DBE in maturation process may lead to

240

the irregularity of relative abundance of O2 species with DBE = 4.

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Figure 5 illustrates the changes in the carbon number distributions of O2 class species

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with values of 7, 5 and 3 in samples with different maturation levels. O2 class species

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with DBE ＞ 10 are not selected to avoid the possible interference of bi-phenols31

244

with naphthenic acids and aromatic acids. Generally, with increasing of maturity, the

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relative abundance of acidic compounds with higher carbon number decrease, while

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their counterparts with lower carbon numbers increase. It is reasonable to believe that

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gradual cleavage of alkyl groups from the cores of acidic compounds during thermal

248

evolution caused the reduction of the numbers and/or the length of the alkyl groups


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attached.17 The dependence of carbon number distribution on maturation levels of

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source rocks is obvious in O2 class species with DBE value of 7 and 5, less obvious

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for that of DBE = 3.

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Acidic compounds could serve as geochemical tracers for oil-source correlations, oil

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migration from origins to reservoirs and oil charge histories.37, 43, 44 This work could

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probably contribute to the hydrocarbon exploration and developments in the

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Cambrian petroleum system after further investigation of Cambrian crude oils using

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integrated methods including FT-ICR MS.

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5. Conclusions

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Compositional difference of polar acidic compounds in bitumen of ancient shale with

259

various thermal maturity levels has been revealed using ESI FT-ICR MS, depending

260

on its ultrahigh mass resolution and mass accuracy. O2, O3, O4 and O5 class species

261

are the main acidic compounds determined in the bitumen of source rocks. A likely

262

precursor–product relationship of fatty acids and n-alkanes has been observed based

263

on the FT-ICR MS results. In some shale, abundant C32 hopanoic acid has been

264

detected. Analytical results obviously show several compositional regularities of

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acidic compounds as a function of maturation degree. They could be summarized as

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following aspects: 1) O3 and O4 class species progressively decline with increasing

267

maturation probably due to decarboxylation and dehydration reactions, leading the

268

increase of relative abundance of O2 class species; 2) aromaticity of acidic compounds

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increases with the maturation levels; 3) maturation strengthens the dealkylation

270

degree of the acidic compounds. The compositional information of bitumen in the


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Cambrian source rocks of type I orgnaic matter may contribute to promising

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exploration potential for ultra-deep petroleum extraction in Tarim Basin, China.

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Author Information

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*E-mail: [email protected] Tel: +86 10 83592318 and +86 10

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18601309981

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Notes: The authors declare no competing financial interest.

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compounds in biodegraded oils of the Liaohe Basin by negative ion ESI FT-ICR MS. Organic Geochemistry 2012, 47, 51-65. 10. Jin, J. M.; Kim, S.; Birdwell, J. E., Molecular Characterization and Comparison of Shale Oils Generated by Different Pyrolysis Methods. Energy & Fuels 2012, 26, (2), 1054-1062. 11. Pomerantz, A. E.; Ventura, G. T.; McKenna, A. M.; Cañas, J. A.; Auman, J.; Koerner, K.; Curry, D.;


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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Nelson, R. K.; Reddy, C. M.; Rodgers, R. P.; Marshall, A. G.; Peters, K. E.; Mullins, O. C., Combining

315 316

13. Hughey, C. A.; Minardi, C. S.; Galasso‐Roth, S. A.; Paspalof, G. B.; Mapolelo, M. M.; Rodgers, R.

317 318 319 320 321 322 323 324 325 326 327 328 329 330 331 332 333 334 335 336 337 338 339 340 341 342 343 344 345 346 347 348 349 350 351

based on semi‐quantitative electrospray ionization Fourier transform ion cyclotron resonance mass

biomarker and bulk compositional gradient analysis to assess reservoir connectivity. Organic Geochemistry 2010, 41, (8), 812-821. 12. Li, M.; Cheng, D.; Pan, X.; Dou, L.; Hou, D.; Shi, Q.; Wen, Z.; Tang, Y.; Achal, S.; Milovic, M.; Tremblay, L., Characterization of petroleum acids using combined FT-IR, FT-ICR–MS and GC–MS: Implications for the origin of high acidity oils in the Muglad Basin, Sudan. Organic Geochemistry 2010, 41, (9), 959-965. P.; Marshall, A. G.; Ruderman, D. L., Naphthenic acids as indicators of crude oil biodegradation in soil, spectrometry. Rapid Communications in Mass Spectrometry 2008, 22, (23), 3968-3976. 14. Hughey, C. A.; Galasso, S. A.; Zumberge, J. E., Detailed compositional comparison of acidic NSO compounds in biodegraded reservoir and surface crude oils by negative ion electrospray Fourier transform ion cyclotron resonance mass spectrometry. Fuel 2007, 86, (5), 758-768. 15. Kim, S.; Stanford, L. A.; Rodgers, R. P.; Marshall, A. G.; Walters, C. C.; Qian, K.; Wenger, L. M.; Mankiewicz, P., Microbial alteration of the acidic and neutral polar NSO compounds revealed by Fourier transform ion cyclotron resonance mass spectrometry. Organic Geochemistry 2005, 36, (8), 1117-1134. 16. Rocha, Y. d. S.; Pereira, R. C. L.; Mendonça Filho, J. G., Negative electrospray Fourier transform ion cyclotron resonance mass spectrometry determination of the effects on the distribution of acids and nitrogen-containing compounds in the simulated thermal evolution of a Type-I source rock. Organic Geochemistry 2018, 115, 32-45. 17. Poetz, S.; Horsfield, B.; Wilkes, H., Maturity-Driven Generation and Transformation of Acidic Compounds in the Organic-Rich Posidonia Shale as Revealed by Electrospray Ionization Fourier Transform Ion Cyclotron Resonance Mass Spectrometry. Energy & Fuels 2014, 28, (8), 4877-4888. 18. Craig, J.; Biffi, U.; Galimberti, R. F.; Ghori, K. A. R.; Gorter, J. D.; Hakhoo, N.; Le Heron, D. P.; Thurow, J.; Vecoli, M., The palaeobiology and geochemistry of Precambrian hydrocarbon source rocks. Marine and Petroleum Geology 2013, 40, 1-47. 19. Zhang, S.; Wang, X.; Hammarlund, E. U.; Wang, H.; Costa, M. M.; Bjerrum, C. J.; Connelly, J. N.; Zhang, B.; Bian, L.; Canfield, D. E., Orbital forcing of climate 1.4 billion years ago. Proceedings of the National Academy of Sciences 2015, 112, (12), E1406-E1413. 20. Zhu, G.-Y.; Ren, R.; Chen, F.-R.; Li, T.-T.; Chen, Y.-Q., Neoproterozoic rift basins and their control on the development of hydrocarbon source rocks in the Tarim Basin, NW China. Journal of Asian Earth Sciences 2017, 150, 63-72. 21. Wang, M.; Zhu, G.; Ren, L.; Liu, X.; Zhao, S.; Shi, Q., Separation and Characterization of Sulfur Compounds in Ultra-deep Formation Crude Oils from Tarim Basin. Energy & Fuels 2015, 29, (8), 4842-4849. 22. Zhu, G.; Chen, F.; Wang, M.; Zhang, Z.; Ren, R.; Wu, L., Discovery of the Lower Cambrian high-quality source rocks and deep oil and gas exploration potential in the Tarim Basin, China. AAPG Bulletin 2018, (20,180,315). 23. Zhu, G.; Milkov, A. V.; Chen, F.; Weng, N.; Zhang, Z.; Yang, H.; Liu, K.; Zhu, Y., Non-cracked oil in ultra-deep high-temperature reservoirs in the Tarim basin, China. Marine and Petroleum Geology 2018, 89, 252-262. 24. Xu, B.; Zou, H.; Chen, Y.; He, J.; Wang, Y., The Sugetbrak basalts from northwestern Tarim Block


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of northwest China: Geochronology, geochemistry and implications for Rodinia breakup and ice age in the Late Neoproterozoic. Precambrian Research 2013, 236, 214-226. 25. Shi, Q.; Pan, N.; Long, H.; Cui, D.; Guo, X.; Long, Y.; Chung, K. H.; Zhao, S.; Xu, C.; Hsu, C. S., Characterization of Middle-Temperature Gasification Coal Tar. Part 3: Molecular Composition of Acidic Compounds. Energy & Fuels 2012, 27, (1), 108-117. 26. Wu, C.; Tuo, J.; Zhang, M.; Sun, L.; Qian, Y.; Liu, Y., Sedimentary and residual gas geochemical characteristics of the Lower Cambrian organic-rich shales in Southeastern Chongqing, China. Marine and Petroleum Geology 2016, 75, 140-150. 27. Wu, Y.; Fan, T.; Zhang, J.; Jiang, S.; Li, Y.; Zhang, J.; Xie, C., Characterization of the Upper Ordovician and Lower Silurian Marine Shale in Northwestern Guizhou Province of the Upper Yangtze Block, South China: Implication for Shale Gas Potential. Energy & Fuels 2014, 28, (6), 3679-3687. 28. Shi, Q.; Zhao, S.; Xu, Z.; Chung, K. H.; Zhang, Y.; Xu, C., Distribution of Acids and Neutral Nitrogen Compounds in a Chinese Crude Oil and Its Fractions: Characterized by Negative-Ion Electrospray Ionization Fourier Transform Ion Cyclotron Resonance Mass Spectrometry. Energy & Fuels 2010, 24, (7), 4005-4011. 29. Vaz, B. G.; Abdelnur, P. V.; Rocha, W. F. C.; Gomes, A. O.; Pereira, R. C. L., Predictive Petroleomics: Measurement of the Total Acid Number by Electrospray Fourier Transform Mass Spectrometry and Chemometric Analysis. Energy & Fuels 2013, 27, (4), 1873-1880. 30. Colati, K. A. P.; Dalmaschio, G. P.; de Castro, E. V. R.; Gomes, A. O.; Vaz, B. G.; Romão, W., Monitoring the liquid/liquid extraction of naphthenic acids in brazilian crude oil using electrospray ionization FT-ICR mass spectrometry (ESI FT-ICR MS). Fuel 2013, 108, 647-655. 31. Orrego-Ruiz, J. A.; Gomez-Escudero, A.; Rojas-Ruiz, F. A., Combination of Negative Electrospray Ionization and Positive Atmospheric Pressure Photoionization Fourier Transform Ion Cyclotron Resonance Mass Spectrometry as a Quantitative Approach of Acid Species in Crude Oils. Energy & Fuels 2016, 30, (10), 8209-8215. 32. Rojas-Ruiz, F. A.; Orrego-Ruiz, J. A., Distribution of Oxygen-Containing Compounds and Its Significance on Total Organic Acid Content in Crude Oils by ESI Negative Ion FT-ICR MS. Energy & Fuels 2016, 30, (10), 8185-8191. 33. Barrow, M. P.; McDonnell, L. A.; Feng, X.; Walker, J.; Derrick, P. J., Determination of the Nature of Naphthenic Acids Present in Crude Oils Using Nanospray Fourier Transform Ion Cyclotron Resonance Mass Spectrometry: The Continued Battle Against Corrosion. Analytical Chemistry 2003, 75, (4), 860-866. 34. Chen, L.; Xu, G.; Da, X.; Ji, C.; Yi, H., Biomarkers of Middle to Late Jurassic marine sediments from a canonical section: New records from the Yanshiping area, northern Tibet. Marine and Petroleum Geology 2014, 51, 256-267. 35. Ding, X.; Liu, G.; Zha, M.; Gao, C.; Huang, Z.; Qu, J.; Lu, X.; Wang, P.; Chen, Z., Geochemical characterization and depositional environment of source rocks of small fault basin in Erlian Basin, northern China. Marine and Petroleum Geology 2016, 69, 231-240. 36. Mingju, X.; Jiyang, S.; Zhiqing, H.; Qizhong, W., Evolution of biomarkers in early diagenesis: organic geochemistry of Quaternary sediment in the Chiawobao basin. Journal of Southeast Asian Earth Sciences 1991, 5, (1), 219-223. 37. Nascimento, L. R.; Rebouças, L. M. C.; Koike, L.; de A.M Reis, F.; Soldan, A. L.; Cerqueira, J. R.; Marsaioli, A. J., Acidic biomarkers from Albacora oils, Campos Basin, Brazil. Organic Geochemistry 1999, 30, (9), 1175-1191.


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417

Figure 1. (left) Typical DBE distribution of acidic species derived from negative-ion

418

ESI FT-ICR MS of YTX05 shale; (right) Typical plot of DBE vs carbon number for

419

O2 class species in YTX05.

420 421

Figure 2. Typical n-alkane and isoprenoid (m/z 85) distribution of the shale (YTX05).

422 423

Figure 3. (top) Distributions of acidic compounds (O2~O5 class species) in bitumen

424

of YTX shale; (bottom) Plot of relative abundance O2 (%RA O2) versus Ro values of

425

YTX shale.

426 427

Figure 4. Normalized DBE distribution for O2 class species in samples with different

428

maturation levels.

429 430

Figure 5. Normalized carbon number distributions for O2 compounds with DBE

431

values of 7, 5 and 3 in samples with different maturation levels.

432


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434 435

Figure 1


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437 438

Figure 2


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440 441

Figure 3


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443 444

Figure 4


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

446 447

Figure 5


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448

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Table 1. Organic Geochemical Data for the Cambrian Yuertusi shale. Sample

YTX01

YTX02

YTX03

YTX04

YTX05

YTX06

YTX07

Average

TOC (%)

2.49

2.03

1.77

4.87

2.05

2.83

4.06

2.87

Ro

1.28

1.25

1.39

1.48

1.53

1.24

1.13

1.33

δC13org (‰)

-28.103

-28.304

-28.177

-31.554

-28.356

-29.518

-30.774

-29.255

OEP1

1.23

1.05

1.03

1.05

1.14

1.00

1.00

1.07

CPI2

1.23

1.08

1.10

1.06

1.07

1.07

1.29

1.13

OEPFA3

1.02

1.04

1.11

1.78

1.78

1.25

1.02

1.29

449

Note: 1OEP =

450

2CPI

451

3OEP𝐹𝐴

C23 + 6 × C25 + C27 4 × C24 + 4 × C26

1 ∑(C25~C33) ∑(C24~C32)

=2

[

=

+

;

∑(C25~C33) ∑(C26~C34)

𝐶22𝐹𝐴 + 6 × 𝐶24𝐹𝐴 + 𝐶26𝐹𝐴 4 × 𝐶23𝐹𝐴 + 4 × 𝐶25𝐹𝐴

]; .


Characterization of Acidic Compounds in Ancient Shale of Cambrian

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