Petrological record of hydrocarbon accumulation in the Kela-2 gas field, Kuqa Depression, Tarim Basin

Accepted Manuscript Petrological record of hydrocarbon accumulation in the Kela-2 gas field, Kuqa Depression, Tarim Basin Zhichao Yu, Keyu Liu, Mengjun Zhao, Shaobo Liu, Qinggong Zhuo, Xuesong Lu PII:

S1875-5100(17)30087-2

DOI:

10.1016/j.jngse.2017.02.034

Reference:

JNGSE 2087

To appear in:

Journal of Natural Gas Science and Engineering

Received Date: 8 July 2016 Revised Date:

22 February 2017

Accepted Date: 26 February 2017

Please cite this article as: Yu, Z., Liu, K., Zhao, M., Liu, S., Zhuo, Q., Lu, X., Petrological record of hydrocarbon accumulation in the Kela-2 gas field, Kuqa Depression, Tarim Basin, Journal of Natural Gas Science & Engineering (2017), doi: 10.1016/j.jngse.2017.02.034. This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.

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Petrological Record of Hydrocarbon Accumulation in the Kela-2 Gas

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Field, Kuqa Depression, Tarim Basin

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*, Keyu Liu

1, 2,3

*, Mengjun Zhao

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, Shaobo Liu

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, Qinggong Zhuo

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, Xuesong Lu

1, 2

PetroChina Exploration and Development Research Institute, Beijing 100083, China

Key Laboratory of Basin Structure and Hydrocarbon Accumulation, CNPC, Beijing 100083, China

School of Geosciences, China University of Petroleum, Qingdao, Shandong 266580, China

*Corresponding author.

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Zhichao Yu

Tel: +86-10-83593451; Fax: +86-10-83593451

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[email protected] (Z.C. Yu); [email protected] (K.Y. Liu)

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E-mail address: [email protected] (Z.C. Yu); [email protected] (K.Y. Liu);

[email protected]

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[email protected] (Q.G. Zhuo); [email protected] (X.S. Lu).

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(M.J.

Zhao);

[email protected]

(S.B.

Liu);

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Postal address: 20 Xueyuan Road, PetroChina Exploration and Development Research Institute,

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Beijing 100083, P.R. China. Tel: +86-10-83593451; Fax: +86-10-83593451.

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Abstract The reservoir diagenetic process and the petroleum charge histories of the Cretaceous

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Bashijiqike Formation (K1bs) in the Kuqa Depression, Tarim Basin were studied using an

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integrated petrographic, fluid inclusion, reservoir diagenesis and basin modeling approach. A

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suite of techniques were used in the investigation including optical microscopy, scanning

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electron

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microthermometry,

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petrographic characterization of the reservoir sandstone, identification of fluid inclusion

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assemblages, and construction of the diagenetic history of the reservoir sandstone with

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reference to the hydrocarbon charge and emplacement. Key diagenetic events identified

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include quartz overgrowths, early calcite cementation, dolomite cementation, alteration of

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kaolinite, bitumen emplacement, micro-quartz and ankerite cementation. The first diagenetic

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event was characterized by quartz overgrowths and followed by calcite and dolomite

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cementation. Kaolinite and ankerite cementation were the last diagenetic events, coincided

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with hydrocarbon charge and emplacement. Three episodes of hydrocarbon charge and

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emplacement have been recorded by the diagenetic products and fluid inclusions in the K1bs

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Formations: (1) the first episode of oil charge was recorded in the early calcite cement, and

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were trapped around at 18 Ma; (2) the second and third episodes of hydrocarbon charge were

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recorded in the telo-diagenetic ankerite, and were trapped around at 4~6 Ma. The timing of oil

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emplacement determined from fluid inclusion homogenization temperature and basin

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modelling is consistent with the formation order of the diagenetic minerals. This study has thus

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demonstrated that integrated analysis of fluid inclusion and reservoir diagenesis can be an

(SEM), Laser

Raman

diffraction

(XRD),

microspectroscopy.

fluorescence The

spectroscopy,

workflow

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effective tool for determining hydrocarbon charge and emplacement history.

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Keywords: Fluid inclusion; Diagenesis; Cement; hydrocarbon charge; Oil emplacement

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1 Introduction A number of studies undertaken in recent decades demonstrate the importance of fluid

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inclusion studies of diagenetic minerals towards understanding petroleum generation and

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migration histories of sedimentary basins (Baron et al., 2008; Burley et al.,1989; Guilhaumou

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et al.,1996; Tillman and Barnes, 1983; Mullis, 1987; Roedder, 1984). During and after

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subsurface fluid migration, including oil migration and emplacement of reservoirs, minute fluid

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can be encapsulated as inclusions during cement precipitation and microfracture annealing

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(Bourdet et al., 2010). Information from those fluid inclusions allows us to reconstruct the

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temperatures, salinities and compositions of fluids at the time of encapsulation (Parnell et al.,

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2001). Moreover, the timing of petroleum charge can be determined by using fluid inclusion

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entrapment temperatures combined with burial (thermal) history plots, predictions of oil

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generation and migration from geothermal and subsidence models (Parnell et al., 2010).

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Detailed petrographic analysis of fluid inclusions within the context of diagenetic history can

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also provide additional information on the timing and sequence of reservoir emplacement.

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The Kela-2 Gas Field in the Kuqa Depression, northern Tarim Basin is a world-scale giant

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over-pressured dry gas field. The natural gas is now mainly composed by dry gas with

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abnormally heavier methane and ethane carbon isotope, which was derived from highly and

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over-matured coal mainly sourced from the Jurassic coal-measure source rocks (Lu et al.,

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2012). Previous studies show that the Kela-2 Gas Field has experienced multi-stage

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hydrocarbon accumulation that is, oil filling at the Early-Mid Miocene, high-matured oil and gas

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filling and destruction at the Pliocene, and high and over-mature coal-derived gas

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accumulation at the Quaternary (Zhang et al., 2001; Zhao et al., 2002; Lu et al., 2012; ).

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However, either the specific time of the hydrocarbon charging or the relationship between the

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oil emplacement and the diagenetic minerals are still not clear. In order to investigate the hydrocarbon charge history and diagenetic processes in the

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Kela-2 Gas Field, we performed fluid inclusion and diagenesis analysis of the reservoir

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sandstones in the Cretaceous Bashenjiqike Formation (K1bs). The primary objective of our

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study is to document the chronological order between the diagenesis and the petroleum

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charge and to unravel the petroleum charge history by using an integrated fluid inclusion and

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reservoir diagenesis investigation.

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2 Geological setting

The Kuqa Depression is one of the most petroliferous area in the Tarim Basin, located in

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the northern part of the Tarim Basin and south of the Tianshan Mountains, northwest China

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(Fig. 1). It is adjacent to the Northern Tarim Uplift, which is about 750 km long and 30–75 km

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wide (Zeng et al., 2010). The Kuqa Depression is a low geothermal gradient basin, with an

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average geothermal gradient of 2.65°C/100 m.

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The Kela-2 Gas Field, located in the central and western Kelasu Trust Belt (Fig. 1), in the

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northern part of the Kuqa Depression, is a world-scale giant over-pressured dry gas field (Li et

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al., 2009). A thick Paleogene gypsum-salt and cretaceous sandstone constitute a high-quality

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reservoir/seal assemblage in the Kuqa Depression (Jia et al., 2008). The Cretaceous

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Bashijiqike Formation (K1bs), immediately below the gypsum-salt layer and, is the major

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oil-bearing reservoir interval in the Kela-2 Gas Field. K1bs comprises predominantly sandy

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delta front facies (Han et al., 2011) with the reservoir dominated by tight sandstone with

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porosity ranging from 6% to 8% (Feng et al., 2013).

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3 Samples and methods A total of 62 sandstone core samples from the K1bs intervals with depths ranging from

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3639.79 m to 4075.30 m were collected from well KL-2 and KL-201 in the northern Kuqa

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Depression (Figure 1). The samples were examined petrographically by point counting 300 to

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400

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Cathedoluminecence (CL) microscope, using the CL8200&MK4 instrument made by

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Cambridge Image Technology Ltd., UK. Diagenetic mineral textures and morphologies of the

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sandstones were also analysed using Back-Scattered Electron (BSE) and Scanning Electron

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Microscopic (SEM) microscope (JSM6700F, JEOL Corporation, Tokyo, Japan). The SEM was

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operated at an accelerating voltage of 15 KV and a beam current of 10 nA, equipped with an

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energy dispersive X-ray system (EDS). The bulk-rock and clay fraction (< 2 µm) mineralogy of

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the reservoir and cap core samples were characterized in detail by quantitative XRD analysis

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(D/max-2500, Rigaku Corporation, Tokyo, Japan).

sample/slide.

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Forty core samples from Well KL-201 were analysed using the Quantitative grain

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fluorescence (QGF), Quantitative grain fluorescence on extract (QGF-E) and the Total

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Scanning Fluorescence (TSF). The QGF (QGE-E) technique (Liu and Eadington, 2005) uses

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fluorescence spectrophotometry to detect current (residual) and palaeo oil zones. The

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methods use a highly sensitive spectrophotometer to analyze ～1 g of clean, dry whole quartz

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grains in bulk volume (QGF) and the solvent extract (QGF-E, TSF) after a pre-cleaning

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procedure removes surface contaminants. The methods use short UV excitation wavelengths

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spectrum between 300 and 600 nm (Liu et al., 2005). The most frequently used parameters in

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TSF are (1) the peak positions of the spectrogram in reference to the excitation (Ex) and

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emission (Em) wavelengths, (2) the (weight/volume) normalised intensity (TSF Intensity), and

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(3) the ratio of the emission intensities at 360 nm over 320 nm, corresponding to an excitation

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wavelength of 270 nm (TSF R1; Brooks et al., 1983). TSF R1 is a proxy for the ratio of the

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three-ring aromatic over single-ring aromatic hydrocarbons in oil (Reyes, 1994; Barwise and

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Hay, 1996).

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Fluid inclusion analysis was conducted on five selected samples using a Leica DMRX HC

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fluorescence microscope in the Key Laboratory of Basin Structure and Hydrocarbon

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Accumulation, CNPC, Beijing. UV illumination is from a mercury lamp with a 400 nm barrier

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epi-fluorescence filter. The fluorescence spectra of individual oil inclusions were measured

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using an Ocean Optics USB4000 miniature fiber optic spectrometer. Microthermometry of oil

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and aqueous fluid inclusions were performed using a calibrated LINKAM THMS600 heating–

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cooling stage. Homogenization temperatures (Th) are measured with a precision of 1 °C. The

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final ice melting temperatures (Tm) are obtained by cooling an inclusion until it freezes, and

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then gradually heating it up until the ice melting completely at the invariant triple point

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(co-presence of liquid water, vapour and ice). By cycling temperatures close to the final

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melting point with repeated heating/cooling cycles (Goldstein and Reynolds, 1994), this allows

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measurements with a precision of 0.1 °C. Qualitative Raman micro-spectrometric analyses of

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aqueous inclusions were performed on a LabRAM HR800 research-grade laser Raman

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micro-spectrometer equipped with a 632.81 nm YAG laser, with an acquisition time of 8 s, and

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operated at 25°C and a humidity of 50%.

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4 Results

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4.1 Petrography of reservoir rocks

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XRD analysis shows that the most common mineral are quartz (29.2–70.2 wt%),

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plagioclase (3.9–21.9 wt%), K-feldspar (0.8–28.5 wt%), calcite (0.6–39.2 wt%), dolomite (3.3–

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36.7 wt%),

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mixed-layer illite/smectite (5–81% of relative amount), illite (7–65%), chlorite (2-52%) and

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some kaolinite (2–30 %) (Table 2).

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4.1.1 Detrital mineralogy

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clay minerals (4.6–37.9 wt%) and some analcime (Table 1). Clay minerals include

The sandstones of the Bashenjiqike Formation are moderately well or well sorted, very

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fine to fine-grained. Most of K1bs samples are classified as feldspathic litharenite (Fig. 2). Point

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counting data show that the most common detrital grains are quartz (mean 59% of the rock

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volume), K-feldspar (mean 7%) and plagioclase (mean 16%) (Table 3). Quartz grains are

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dominantly monocrystalline, but some polycrystalline metamorphic quartz is also present.

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Rock fragments are present in volumes varying from 1 to 50% (mean 18%) (Table 3), most

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having an igneous origin.

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4.1.2 Authigenic mineralogy The mineralogy and petrophysical properties of the K1bs within the Kela-2 Gas Field have undergone significant diagenetic modification. Authigenic minerals occupy an average of ～30%

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of the rock volume. The main diagenetic minerals include quartz, calcite, dolomite, ankerite,

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kaolinite and solid bitumen. Quartz cements occur as overgrowths and microcrystalline pore-filling cements,

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representing <1%. Quartz overgrowths 15–40 µm in diameter are normally replaced by calcite

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and other early carbonate cements (Fig. 3A). Micro-quartz are associated with bitumen in

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residual pores contributed by feldspar dissolution (Fig. 3B), indicating that micro-quartz are

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synchronous with the formation of the bitumen.

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Carbonates constitute the most widespread and often spatially associated pore-filling

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cement minerals in the K1bs Formation and occupied up to ～29% of the rock volume (for

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both calcite, dolomite and ankerite). Two generations of carbonates can be identified using CL:

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the first phase is calcite and characterized by yellow-luminescence colour, replaced by orange

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red-luminescence coloured dolomite (Fig. 3C); the second phase is dolomite and

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characterized by orange red-luminescence colour, which appear to be zoned under the

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cathode ray (Fig. 3C). Ankerite cement occurs in most samples, representing <1%. It

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predominantly occurs as zoned overgrowths on non-ferroan dolomite (Fig. 3D, E). Ankerite

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cement grows in the residual pores contributed by kaolinite and bitumen, which is not any

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dissolution phenomenon suggesting that ankerite is formed later than kaolinite and bitumen

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(Fig. 3D, E).

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Kaolinite is well developed in the K1bs Formation and occupies up an average of ～1.2%

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of the rock volume. It exists as booklets of 5–20 µm in diameter and pseudohexagonal plates

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(Fig. 3F). Solid bitumen is also well developed pore-filling product, which is always associated

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with authigenic kaolinite (Fig. 3F), suggesting that the solid bitumen is synchronous with the

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formation of the authigenic kaolinite.

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4.2 Quantitative Grain Fluorescence According to the results of well testing, log analysis and gas saturation (Sg), the current

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gas-water contact (GWC) in well KL-201 is around 3938 m (Fig. 4). The QGF index values in

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Well KL-201 range from 1 to 10 with the maximum value occurring at 3685 m, and the lowest

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value at 3980–4000 m (Fig. 4). Above the current GWC at 3938 m in the current gas zone

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QGF index values generally are greater than 3, most of them greater than 4. Below the GWC

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at 3939 – 4000 m, the QGF index values are low and less than 2 below the 3980 m (Fig. 4).

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The QGF spectra have characteristic peaks around 375–425nm for all samples and the

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maximum fluorescence emission occurs at wavelengths of 400 nm (Fig. 4). Similar changes

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have also been found in the QGF-E. Above the GWC, the QGF-E index values have increased

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upwards from 13.6 pc near the current GWC to over 200 pc around 3680 m (Fig. 4). Both the

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QGF index and QGF-E intensities have abruptly decreased below the 3980m (Fig. 4), which

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indicates that this depth is the palaeo oil-water contact (POWC), which is below the current

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GWC.

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According to the results of TSF R1, the spectrogram of QGF-E and TSF, two features of

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hydrocarbons in Well KL-201 are identified. The first one, which is above the current GWC, is

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characterized by relatively high values of R1 (values of 1-3) and single broad peaks at

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wavelengths of 410–480 nm (Fig. 5). The second one, which is below the current GWC, is

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characterized by relatively low values of R1 (values <1) and two peaks at wavelengths of

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365-385 nm and 400–430 nm, respectively (Fig. 5).

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4.3 Fluid inclusion analyses

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4.3.1 Optical and fluorescence Petrographic studies show that oil inclusions are relatively abundant within K1bs reservoir

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sandstones and are located within micro-fractures in quartz, quartz grain boundary and

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carbonate cements. However, the coexisting aqueous inclusions are much less frequent and

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no oil inclusions were found in the diagenetic quartz overgrowths. Based on appearance and

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fluorescence colours, the inclusions can roughly be divided into three groups. The first group

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consists of relatively small inclusions, 1-15 µm in dimensions, round to oval in shape and

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containing 0–15 vol% gas bubble. They are usually near-yellow coloured in transmitted light,

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and are characteristic of yellowish-brown fluorescence. They are located in transgranular

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fractures (Fig. 6A, B), cleavage planes of the feldspar (Fig. 6C, D) and early calcite cements

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(Fig. 7A,B). The oil inclusions in the second group are generally larger, 20–30 µm in the long

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axis, and oval shaped. These inclusions contain 5–25 vol% gas, are mostly colourless in

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transmitted light and are characterized by yellow-white to blue-white fluorescence. They

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generally locate in the quartz grain boundary (Fig. 6E, F), micro-fractures of quartz grains and

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in the late-generation ankerite (Fig. 7C, D). The last group consists mainly of vapour inclusions,

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15–20 µm in the long axis, round to narrow strip in shape. They are usually black-brown

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coloured in transmitted light, and have no fluorescence. These inclusions are located in

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transgranular fractures in quartz grains (Fig. 6G) and occasionally in telo-diagenetic carbonate

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cements (Fig. 6H). In addition, some of vapour inclusions trails in last group are occasionally

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cross-cut entire quartz grains (Fig. 6G), suggesting that these vapour inclusions formed quite

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late. The fluorescence colours of the oil inclusions investigated vary from near yellowish-brown, yellow-white to blue-white in the K1bs Formation. Among them, yellowish-brown and

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blue-white fluorescent oil inclusions in calcite and ankerite are measured for fluorescence

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spectroscopy, respectively. The fluorescence spectra show distinct difference between the oil

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inclusions with yellowish-brown and that of blue-white fluorescence colours (Fig. 7). The oil

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inclusions with yellowish-brown fluorescence have characteristic peaks around 500–550 nm

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and the maximum fluorescence intensity occurs at wavelengths of 523 nm. In contrast the oil

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inclusions with blue-white fluorescence has characteristic peaks around 475–525 nm and the

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maximum fluorescence intensity occurs at wavelengths of 495 nm.

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4.3.2 Microthermometry

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aqueous inclusions in quartz micro-fractures, quartz grain boundary, calcite and ankerite

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cements from the K1bs reservoir sandstones. Most of the fluid inclusions are located along

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healed micro-fractures of quartz. The measured Th, Tm and salinity data range are shown in

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Table 4. Figure 8 shows the Th distribution of the coexisting oil and aqueous inclusions in all

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samples analyzed. All the measured inclusions are able to homogenize to single liquid phase.

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The oil inclusions with the yellowish-brown fluorescence hosted in early calcite homogenized

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around 80°C, and the coeval aqueous inclusions homogenized between 95 and 120°C. The

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Th of the oil inclusions with the yellow-white to blue-white fluorescence in quartz grain

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boundary and late-generation ankerite cements are around 93°C, whereas the coeval

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inclusions

homogenized

between

114

and

123°C.

Compared

with

the

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above-mentioned aqueous and oil inclusions, the aqueous inclusions associated with the

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vapour inclusions within healed micro-fractures in quartz yield higher Th values ranging

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between 123 and 178°C. It should be noted that all the temperatures referred here represent

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the minimum trapping temperatures and the true trapping temperature and pressure can only

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be estimated through a full PVTx reconstruction (Aplin et al., 2000; Pironon et al., 2008;

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Bourdet et al., 2008). However, because of the continuous charging process of the petroleum

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fluids, we are convinced that the minimum temperatures of the aqueous inclusions coeval with

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the hydrocarbon inclusions represent the trapping temperature for the petroleum. It is therefore

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that the Th of the yellowish-brown fluorescent oil inclusions is 95°C; while the yellow-white to

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blue-white fluorescent oil inclusions is 114°C. The Th for the vapour inclusions is 123°C.

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The salinities of aqueous inclusions associated with different generations of petroleum

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charge were calculated from the final ice melting temperatures (Tm) in 14 aqueous inclusions

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associated with hydrocarbon inclusions. Because the sizes of the majority aqueous inclusions

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are very small, only few inclusions can be measured for their Tm. The salinity values of these

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inclusions range from 13.94 to 20.52 wt% NaCl equivalent (Table .4) and exhibit a good

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correlation with the Th (Fig. 9). Figure 9 shows the first and second generation oil inclusions

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with minimum trapping temperature of 95°C and 114°C, respectively, have a relatively high

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salinity (17.34–20.52 wt% NaCl equivalent); while the third generation hydrocarbon fluids with

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minimum trapping temperature of 123°C, have a relatively low salinity (13.94–18.13 wt% NaCl

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equivalent).

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4.3.3 Laser Raman spectroscopy We applied Laser Raman spectroscopy to analyse the vapour inclusions (the third

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generation). Raman mapping spectrum analysis of these vapour inclusions indicates that the

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gas phases of the vapour inclusions are dominated by CH4, with spectral peak positions at

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2911, 2912 and 2913 cm (Fig. 10). This suggests that the gaseous inclusions are mainly CH4

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gas and the natural gas is the last episode of the hydrocarbon charge in the K1bs Formation.

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5 Discussion

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5.1 Timing of diagenesis

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Diagenesis comprises a broad spectrum of physical, chemical and biological

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post-depositional process by which original sedimentary assemblages and their interstitial

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pore waters reach textural and geochemical equilibrium (Burley, Kantorwicz, & Waugh, 1985;

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Curtis, 1977). As described in Section 4.1.2, the sandstones in the K1bs Formation are

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cemented by calcite, dolomite, kaolinite, solid bitumen and silica (in the form of quartz

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overgrowths and micro-quartz). The textural relationships seem to suggest quartz overgrowths

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are the first diagenetic event for the K1bs sandstones. However, quartz is known to precipitate

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at the expense of chalcedony under the presence of high organic fluids and it is not uncommon

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for quartz overgrowth or crystals to be associated with petroleum systems (Parnell et al., 1996).

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This is probably the reason that why quartz overgrowth is very little in the K1bs sandstones.

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The calcite cementation started slightly later than quartz cementation as indicated by the

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euhedral quartz overgrowths which are embedded and partially replaced by calcite (Fig. 3A).

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Dolomite is the most abundant cement and formed later than calcite cement according based

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on CL data. Abundant precipitation of dolomite suggests that a high concentration of

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magnesium,

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(Gierlowski-Kordesch and Rust, 1994), is restricted to subaqueous sandstones of the K1bs

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Formation. Kaolinite and solid bitumen are the most important cement in the K1bs sandstones,

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only second to dolomite. Petrographic observations show that the aforementioned pore-filling

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cements precipitated in residual pores contributed by poikilotopic dolomite, indicating that they

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were formed later than the dolomite. Kaolinite is one of the most abundant minerals in soils

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and sediments (Murray, 1988; Dixon, 1989). The dissolution of micas, feldspars, mud matrix,

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mud intraclast, and pseudomatrix and the formation of kaolinite have attributed to near-surface,

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meteoric water diagenesis during eo- and telo-diagenesis (Meisler et al., 1984; Morad et al.,

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2000; Ketzer et al., 2003) and/or to flux of organic acids during mesodiagenesis (Surdam et al.,

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1984; Van Keer et al., 1998). Moreover, the coexistent textural relationships between kaolinite

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and solid bitumen indicate that the formation of kaolinite in the K1bs sandstones most likely

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occurred during mesodiagenesis as a result of dissolution of detrital silicates by organic acids

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(Fig. 3B), which could have been derived from thermal alteration of organic matter. In addition,

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micro-quartz associated with solid bitumen can be found in residual pores contributed by

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dissolution of the feldspar by organic acid, which indicate that micro-quartz, kaolinite and solid

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bitumen were coeval. Ankerite is the last-stage diagenetic product of the K1bs sandstones.

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Perfect rhombohedral structure without any dissolution suggests that late-generation organic

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fluid with bitumen did not dissolve the ankerite (Fig. 3D), indicating that the deposition of the

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ankerite post-dated the formation of the bitumen. In addition, ankerite in the K1bs sandstones

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occurs as zoned overgrowths on non-ferroan dolomite, which indicate that formation

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bicarbonate

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alkaline

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temperature of the ankerite could be up to 110°C (Schmid et al., 2004), providing an

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overwhelming evidence of the telo-diagenetic product for ankerite in the K1bs sandstones.

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5.2 Effects of carbonate cements on the reservoir porosity-permeability

RI PT

4

Normally, both porosity and permeability of sandstone reservoirs decrease with

6

increasing carbonate cements. However, the sandstone reservoir in the Kela-2 Gas Field

7

shows a different trend. As the cement content increases, porosity shows a distinct reduction,

8

while permeability shows a slight decrease (Fig.11). This may suggest that the carbonate

9

cements fill the pore space and lead porosity reduction. The permeability reduction appears to

10

be randomly, showing little correlation with the amount of cements, suggesting that pore

11

throats have been less affected much by the cementation compared with pores. The presence

12

of high porosity and permeability values in the KL-2 reservoir sandstone indicate that

13

cementation may not the only factor determining the reservoir petrophysical properties. Burial

14

and thermal history modeling of Well KL201 shows that the reservoir of K1bs had been in a

15

shallow burial stage for a prolonged time. Mechanical compaction on the reservoir is thus

16

correspondingly weak. The primary pores can therefore be preserved and lead to an overall

17

abnormally high porosity and permeability (Han et al., 2014 and Cao et al., 2014).

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18

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5

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5.3 Oil charge and diagenetic processes

20

5.3.1 Oil charge history

21

Quantitative fluorescence analyses associated with hydrocarbon inclusions indicate that

22

an around 330 m palaeo-oil column has been present in the current gas-water zones in well

16

ACCEPTED MANUSCRIPT KL201 (Fig. 4). Moreover, the results of TSF show that the oil composition above the POWC

2

heavier than that below the POWC (Fig. 5), which suggest that the Kela-2 oil has been

3

subjected to the transformation of strong gas flushing, thus leading to the abundant

4

precipitation of bitumen in Well KL-201 (Lu et al., 2012). Therefore, the abundant presence of

5

bitumen in the core samples, as well as petroleum inclusions in the K1bs sandstones, suggest

6

the presence of an oil and gas hydrocarbon system in Well KL-201. Moreover, fluid inclusions

7

combined with diagenesis analysis indicate that three episodes of oil charge in the K1bs

8

Formations. The first episode consists of the yellowish-brown fluorescent petroleum inclusions

9

trapped in the micro-fractures, cleavage plans of the feldspars and early calcite cements (Fig.

10

12), having the trapping temperature of 95°C and salinity of 17.34–18.8 wt% NaCl equivalent.

11

The fluorescence spectra analyses show this period of oil inclusions has a relatively heavy

12

composition with the maximum fluorescence peak at 523 nm. The second episode consists of

13

the yellow-white to blue-white petroleum inclusions trapped in the quartz grain boundary

14

micro-fractures of quartz grains and the telo-diagenetic ankerite (Fig. 12), having the trapping

15

temperature of 114°C and salinity of 20.22–20.52 wt% NaCl equivalent. The fluorescence

16

spectra analyses suggest that this period of oil inclusions has a relatively light composition with

17

the maximum fluorescence peak at 495nm. The third episode consists of non-fluorescent

18

vapour inclusions trapped in the transgranular fractures in quartz grains and occasionally in

19

telo-diagenetic carbonate cements (Fig. 12), having a high trapping temperature of 123 °C and

20

salinity of 13.94–18.13 wt% NaCl equivalent. The Raman analyses indicate that the gas

21

phases in these vapour inclusions are dominant by CH4, suggesting this period of inclusions

22

represent nature gas charge. The timing of oil charge can be determined by combining the

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1

17

ACCEPTED MANUSCRIPT homogenization temperatures of the aqueous fluid inclusions coeval with the oil inclusions with

2

the inferred burial and geothermal histories of the host rocks (Xiao et al., 2002, 2006).

3

Thermometric analysis coupled with the burial history of Well KL201 in the Kuqa Depression

4

has shown that the three episodes of oil charge are at around 18Ma, 6Ma and 4Ma,

5

respectively (Fig. 13). It should be noted that the formation of CH4-bearing vapour inclusions

6

are close to the second generation oil inclusions, because they have a similar trapping

7

temperature. We here divide these inclusions into two generations only according to their

8

phases, minimum trapping temperature and salinities, and cannot exclude the possibility that

9

they are different manifestations of the same hydrocarbons event. However, the CH4 phases

10

should be the last products according to the principle of oil-gas generation. Otherwise, given

11

the fact that the K1bs Formations are the largest gas reservoirs in Western China, we consider

12

that the last generation hydrocarbon charge should be the nature gas represented by vapour

13

inclusions.

15

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5.3.2 The effects of oil emplacement on diagenetic processes

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14

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The maturity of organic material in hydrocarbon source rocks and inorganic diagenetic

17

processes in reservoir sandstones are a natural consequence when a prism of sedimentary

18

rocks is buried (Girish et al., 1992). Water-soluble organic acid anions (e.g., carboxylic)

19

generated by thermocatalytic reactions in the source rocks during diagenesis can significantly

20

affect the stability of both carbonates and aluminosilicates (Surdam et al., 1989). Petrographic

21

observations show that lower content of quartz overgrowth and no feldspar overgrowth are

22

present in the K1bs sandstones. Similar results can also be found in the studies of Girish et al.

AC C

16

18

ACCEPTED MANUSCRIPT (1992), who founded that the extent of quartz overgrowth and albitization of K-feldspars is

2

lower in oil-saturated zones compared with water-saturated zones. This suggests that the oil

3

and gas emplacement in the K1bs Formation can retard the formation of quartz overgrowth and

4

albitization of feldspars. However, minor quartz overgrowth can still be formed after oil

5

emplacement, while the albitization of feldspars is completely retarded. Because albitization of

6

feldspars depends on a supply of sodium and removal of potassium, this process is more likely

7

to be terminated by oil emplacement (Girish et al., 1992). Moreover, the authigenic kaolinite is

8

well developed in the K1bs Formation, suggesting a lot of organic acids or CO2 generated

9

during the late stage of natural gas generation in the Kela-2 Gas Field. The kaolinite has a very

10

important effect in terms of developing secondary porosity in the Kela-2 Gas Field. The wells of

11

kaolinite well developed have better porosity-permeability than that of no or kaolinite not well

12

developed in the same tectonic belts (Zou et al, 2005).

TE D

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1

13

Fluid inclusions studies indicate that the multiple episodes of oil emplacement are

14

recorded by diagenetic carbonate cements in the K1bs Formations. The first generation oil

15

charge

16

pseudo-primary petroleum inclusions, forming around 18Ma. The second and third generation

17

oil charges are both recorded by late ankerite, represented by yellow-white to blue-white

18

pseudo-primary petroleum inclusions and vapour inclusions, forming around 6 Ma, 4 Ma,

19

respectively. This is consistent with the result of diagenesis, which concludes the formation of

20

calcite post-dates the deposition of ankerite. As shown in Fig. 14: the diagenetic mineral before

21

the first generation oil charge is quartz overgrowth, and the early calcite cements form

22

synchronously with the first generation oil charge. The mineral assemblages before the

by

early calcite,

EP

recorded

represented

by

yellowish-brown

fluorescent

AC C

is

19

ACCEPTED MANUSCRIPT second - third oil-gas charge are quartz overgrowth, early calcite, dolomite, kaolinite, bitumen

2

and micro-quartz, and the ankerite forms earlier or synchronously with this period of oil-gas

3

charge. Otherwise, high mature oil inclusions and CH4-bearing vapour inclusions always occur

4

with the telo-diagenetic carbonate cements and, sometimes we can even find these vapour

5

inclusions cross-cut entire quartz grains, which suggest that the formation of nature gas in

6

Kela-2 Gas Field are very late. Moreover, the presences of organic matter inclusions occur

7

within both carbonate cements and annealed microfractures, suggesting that carbonate has

8

replaced organic-rich sediment (Golfberg et al., 2011), and that diagenesis continued after or

9

during oil emplacement, and that fractures were involved in oil migration (Parnell et al., 2001).

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1

10

6 Conclusions

12

(1) Carbonate cementation is widespread in the Cretaceous Bashijiqike Formation in the

13

Kuqa Depression, Tarim Basin. Diagenetic products such as quartz overgrowths, calcite,

14

dolomite, kaolinite and micro-quartz were formed prior to the main oil emplacement in the

15

K1bs Formation. Ankerite is the last-generation authigenic mineral, forming synchronously

16

with the hydrocarbon charge.

AC C

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11

17

(2) Three episodes of oil charge are identified in the K1bs Formation: the first episode

18

represented by the heavy-medium oil inclusions with a minimum trapping temperature of

19

95°C associated with high salinity aqueous inclusions; the second episode represented by

20

the medium-light oil inclusions with a minimum trapped temperature of 114°C associated

21

with high salinity aqueous inclusions; the third episode represented by the CH4-bearing

22

vapour inclusions with a minimum trapped temperature of 123°C associated with low

20

ACCEPTED MANUSCRIPT 1

2

3

salinity aqueous inclusions. (3) The first oil emplacement was recorded by the early calcite cement while the second and third oil emplacements were recorded by the precipitation of the telo-diagenetic ankerite.

5

RI PT

4

Acknowledgements

6

This work was supported by National Key Projects of China (No. 2016ZX05003-002) and

7

the 13 Five-year Program of PetroChina (No. 2016B-0502). These sources of funding are

8

gratefully acknowledged.

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th

The nomenclature explanation of the abbreviations used in this study:

11

K1bs: Cretaceous Bashijiqike Formation

12

CL: Cathedoluminecence

13

BSE: Back-Scattered Electron

14

SEM: Scanning Electron Microscopic

15

EDS: Energy dispersive X-ray system

16

QGF: Quantitative grain fluorescence

17

QGF-E: Quantitative grain fluorescence on extract

18

TSF: Total Scanning Fluorescence

19

Ex: Excitation wavelengths

20

Em: Emission wavelengths

21

Th: Homogenization temperatures

22

Tm: Final ice melting temperatures

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21

ACCEPTED MANUSCRIPT 1

GWC: Gas-water contact

2

POWC: Palaeo oil-water contact

3

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ACCEPTED MANUSCRIPT 1

786–799. (in Chinese, with English Abstr.).

2

Figure captions

4

Fig. 1 Map of the Tarim Basin showing the location of Kela-2 Gas Field in the Kuqa Depression

5

(Sourced from the Tarim Oilfield Company, PetroChina). (a) —Tectonic units of the Kuqa

6

Depression and location of the Kela-2 Gas Field and sample wells in the Kuqa Depression; (b)

7

—Geological cross-section AA' showing the location of the two sampling wells in the Kela-2

8

Gas Field; (c) —Stratigraphy of the Cretaceous Bashijiqike Formation in the Kela-2 Gas Field.

9

Fig. 2 Lithology of the K1bs Formation Sandstone, plotted on the Folk (1968) classification

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3

ternary diagram.

11

Fig. 3 Characteristic photomicrographs for authigenic mineralogy in the K1bs reservoir

12

sandstones. A — quartz overgrowths engulfed by calcite, thin-section photo-micrograph, cross

13

polarized light; B — micro-quartzes and k-feldspar dissolution, BSE image; C — calcite and

14

dolomite, CL image; D — ankerite occurred as zoned overgrowths on non-ferroan dolomite

15

and kaolinite and bitumen filled in the porosity, BSE image; E — pore-filing kaolinite and

16

bitumen, BSE image; F — booklet-shaped kaolinite and bitumen filled in the porosity, BSE

17

image. Qtz — quartz; Kfs — k-feldspar; OQ — quartz overgrowths; Cal — calcite; Bi —

18

bitumen; Ank — ankerite; MQ — micro-quartz; Dol — dolomite; Pl —plagioclase; Kao —

19

kaolinite.

20

Fig. 4 QGF and QGF-E depth profile and QGF spectra in the K1bs Formations of well KL201 in

21

the Kela-2 Gas Field. Gamma ray and resistivity logs are used as references. Sg: Gas

22

saturation

AC C

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28

ACCEPTED MANUSCRIPT Fig. 5 TSF R1 depth profile and QGF-E and TSF spectra in the K1bs Formations of well KL201

2

in the Kela-2 Gas Field.

3

Fig. 6 Characteristic photomicrographs for oil and coexisting aqueous inclusions in the K1bs

4

reservoir sandstones. A — the first episode oil inclusion assemblage along the annealed

5

micro-fractures in quartz grain, thin-section photo-micrograph, plane polarized light; B — UV

6

epi-fluorescence photomicrograph corresponding to A; C —the first episode oil inclusions

7

hosted in the cleavage plans of the feldspar; D — UV epi-fluorescence photomicrograph

8

corresponding to C; E — the second episode oil inclusion assemblage within the boundary of

9

quartz grain; F— UV epi-fluorescence photomicrograph corresponding to C; G — the third

10

vapour inclusions assemblage along the annealed micro-fractures in quartz grain, thin-section

11

photo-micrograph, plane polarized light; H — pseudo-primary vapour inclusion within the

12

ankerite. Qtz — quartz; Pl —plagioclase; Ank — ankerite; OIs- oil inclusion assemblage

13

Fig. 7 Characteristic photomicrographs and Fluorescence spectra of two episodes of oil

14

inclusions in the K1bs reservoir sandstones. A — pseudo-primary 1st oil inclusion within calcite;

15

B —UV epi-fluorescence photomicrograph corresponding to A; C — pseudo-primary 2nd oil

16

inclusion within ankerite; D — UV epi-fluorescence photomicrograph corresponding to C. Cal

17

— calcite; Ank — ankerite; Qtz — quartz.

18

Fig. 8 Homogenization temperature histogram of petroleum and coexisting aqueous fluid

19

inclusions.

20

Fig. 9 Homogenization temperature versus ice-melting temperature plot for aqueous inclusions

21

associated with oil inclusions.

22

Fig. 10 Raman spectra of typical CH4-bearing vapour inclusions. a and b —positions of the

AC C

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1

29

ACCEPTED MANUSCRIPT analytical CH4-bearing vapour inclusions; c and d — Raman spectra of the corresponding

2

inclusions.

3

Fig. 11 Relationship of cement content versus porosity (a) and permeability (b) in the K1bs

4

sandstone. Cements include both calcite and dolomite

5

Fig. 12 Evolutionary chart constructed from the oil and coexisting aqueous fluid inclusions

6

emplacement process linked with the petrography and the interpreted fluid inclusion data. A —

7

the relationship between the 1 oil charge and diagenetic minerals; B — the relationship

8

between the 2 and 3 oil charge and diagenetic minerals.

9

Fig. 13 Inferred oil charge timing obtained from integration of the minimum Th of the aqueous

10

fluid inclusions coeval with the oil inclusions with the thermal history plots in well KL201. Blue

11

solid line — Stratigraphic boundary; Red line — Isotherm; Crt. or Mesozoic — Stratigraphic

12

chronology; Yellow triangle — Sample depth and trapping temperature of different episodes of

13

oil inclusions.

14

Fig. 14 Paragenetic sequence of diagenetic minerals and oil charge events in K1bs reservoir

15

sandstones in the Kela-2 Gas Field. Left column — Diagenetic events; Right column —

16

Duration of different diagenetic events; Yellow line with arrow — Charge timing of different

17

episodes of oil and gas migration events.

rd

EP

TE D

M AN U

nd

SC

st

AC C

18

RI PT

1

19

Table captions

20

Table 1 XRD quantitative analysis of bulk-rock mineralogy of the K1bs reservoir sandstones.

21

Table 2 XRD quantitative analysis of clay fraction mineralogy of the K1bs reservoir sandstones.

22

Table 3 Summary of point count results of the clastic constituents of the K1bs reservoir

30

ACCEPTED MANUSCRIPT sandstones.

2

Table 4 Summary of microthermometric results.

AC C

EP

TE D

M AN U

SC

RI PT

1

31

ACCEPTED MANUSCRIPT Table 1 Mineral types and content / wt.% No.

Well

Depth (m) Quartz

K-feldspar

Plagioclase

Calcite

Dolomite

Analcime

Clay

3743.5

60.9

7.7

13.6

/

8.8

0.8

8.2

2

3860.4

44.6

2.6

16.7

/

22.1

/

14.0

3

3861.0

37.6

6.1

16.3

/

19.5

/

20.5

4

3799.0

38.1

6.2

16.0

/

29.7

1.5

8.5

5

3800.5

43.1

6.7

20.5

/

22.0

0.9

6.8

6

3801.5

50.9

5.9

18.4

/

11.8

2.1

10.9

7

3802.5

54.9

4.1

16.8

/

18.4

/

5.8

8

3803.0

47.0

6.1

17.2

/

18.9

/

10.8

9

3859.0

49.7

6.3

18.3

/

14.2

/

11.5

10

3860.0

49.2

10.5

16.5

11

3863.4

45.8

6.1

20.0

12

3992.5

68.9

3.8

14.7

13

3994.5

58.0

3.4

14.1

14

3998.7

60.8

4.2

15

3997.7

62.8

16

4025.0

17

SC

RI PT

1

/

12.6

/

11.2

/

11.5

1.7

14.9

3.9

/

/

8.7

13.6

/

/

10.9

12.1

12.8

/

/

10.1

4.0

16.5

10.1

/

/

6.6

45.4

3.4

9.3

34.9

/

/

7.0

4026.0

58.2

4.9

20.2

0.9

/

/

15.8

18

4028.0

60.6

3.0

16.4

/

12.7

/

7.3

19

4070.3

59.5

4.1

15.7

/

5.0

/

15.7

20

4071.8

57.0

1.2

21

4075.3

22

4070.0

23

3661.9

24

3662.3

25

3663.6

26

M AN U

KL2

/

8.4

/

14.9

0.8

18.3

/

6.5

/

12.1

57.0

2.9

15.4

/

11.6

/

13.1

58.6

4.1

9.0

13.1

3.3

/

11.9

41.9

6.9

3.9

33.3

/

/

14.0

54.8

8.2

7.1

18.2

/

/

11.7

3664.7

44.7

28.5

5.6

8.8

/

/

12.4

27

3666.7

69.8

5.6

8.9

0.8

3.4

/

11.5

28

3667.8

66.4

8.4

10.8

1.8

/

/

12.6

29

3670.3

56.1

10.5

10.7

6.5

4.4

/

11.8

30

3676.3

47.3

4.3

4.6

35.6

/

/

8.2

3680.2

63.8

11.3

9.5

/

/

/

15.4

32

3682.4

54.7

7.3

7.3

9.5

4.3

/

16.9

33

3726.0

62.5

12.3

10.7

/

/

/

14.5

34

3731.0

70.2

6.8

7.6

/

5.6

2.0

7.8

35

3733.0

57.3

5.9

10.9

/

7.9

2.4

15.6

36

3741.4

55.6

7.0

10.8

/

13.9

3.4

9.3

37

3747.0

64.3

7.6

11.7

/

6.8

/

9.6

38

3776.3

52.3

10.1

15.2

/

8.7

1.0

12.7

39

3788.1

62.0

5.6

19.1

/

5.2

0.5

7.6

40

3794.6

47.1

4.9

13.5

/

14.1

/

20.4

AC C

EP

TE D

18.5

62.3

31

KL201

ACCEPTED MANUSCRIPT 3800.7

31.8

3.8

14.6

/

27.9

/

21.9

42

3920.0

41.9

10.1

15.6

/

24.0

/

8.4

43

3924.0

46.2

5.6

16.8

/

21.6

/

9.8

44

3929.0

43.8

5.1

21.8

/

22.1

/

7.2

45

3930.0

46.7

4.8

12.7

/

23.2

/

12.6

46

3931.5

34.2

5.6

13.2

/

36.7

/

10.3

47

3932.3

69.8

5.6

12.5

/

7.5

/

4.6

48

3933.3

38.2

8.0

15.0

/

21.0

/

17.8

49

3933.9

40.5

3.4

18.2

/

20.4

/

17.5

50

3934.3

45.3

4.5

13.4

/

16.6

/

20.2

51

3934.8

48.1

6.5

16.8

/

6.0

/

22.6

52

3935.0

34.8

4.0

14.2

/

29.1

/

17.9

53

3936.3

51.0

6.8

11.4

/

25.0

/

5.8

54

3935.8

54.7

3.0

12.5

55

3937.5

50.8

9.2

16.5

56

3939.0

38.9

3.4

8.8

57

3941.4

38.4

11.4

11.5

58

3984.1

29.2

3.6

11.3

59

3985.1

52.4

5.3

13.6

60

4018.5

42.3

3.9

61

4020.5

60.7

62

4024.1

49.1

EP AC C

SC 23.3

/

6.5

/

16.5

/

7.0

36.1

4.9

/

7.9

/

22.3

/

16.4

39.2

5.5

/

11.2

/

19.5

/

9.2

13.7

2.2

/

/

37.9

3.4

15.5

0.6

/

/

19.8

2.6

21.9

9.7

/

/

16.7

M AN U

/

TE D

wt. % — Weight percent; "/ "— not detected.

RI PT

41

ACCEPTED MANUSCRIPT Table 2 Mineral types and relative content (%) No.

Well

Depth (m)

S% Smectite

Mixed-layer illite/smectite

Illite

Kaolinite

Chlorite

3743.5

/

71

19

3

7

25

2

3860.4

/

57

29

4

10

25

3

3861.0

/

54

32

4

3799.0

/

61

22

5

3800.5

/

49

29

6

3801.5

/

53

29

7

3802.5

/

46

29

8

3803.0

/

65

12

9

3859.0

/

58

10

3860.0

/

62

3863.4

/

60

12

3992.5

/

13

3994.5

/

14

3998.7

/

15

3997.7

/

16

4025.0

/

17

4026.0

/

18

4028.0

19

4070.3

20

4071.8

21

4075.3

22

4070.0

12

20

4

13

25

4

18

25

6

12

25

7

18

25

15

8

30

24

7

11

25

23

4

11

20

25

4

11

20

53

28

6

13

20

51

27

6

16

20

50

26

6

18

20

43

29

6

22

20

22

48

9

21

20

34

32

7

27

20

/

47

32

5

16

20

/

46

27

5

22

20

/

37

39

5

19

20

/

45

30

7

18

20

/

45

28

6

21

20

EP

TE D

KL2

23 24

3661.9

/

35

10

22

5

30

3662.3

/

81

7

10

2

30

3663.6

/

39

12

25

5

30

AC C

25

SC

2

M AN U

11

RI PT

1

26

3664.7

/

43

10

24

5

30

27

3666.7

/

26

12

25

6

30

28

3667.8

/

26

12

26

5

30

29

3670.3

/

36

12

29

5

30

3676.3

/

35

11

30

6

30

31

3680.2

/

38

14

13

9

30

32

3682.4

/

42

15

20

11

30

33

3726.0

/

44

12

20

13

35

34

3731.0

/

65

20

8

7

35

35

3733.0

/

43

11

25

10

35

36

3741.4

/

65

20

7

8

30

37

3747.0

/

59

20

14

7

30

30

KL201

ACCEPTED MANUSCRIPT 3776.3

/

55

21

14

10

30

39

3788.1

/

64

21

8

7

30

40

3794.6

/

60

23

5

12

25

41

3800.7

/

53

33

4

10

25

42

3920.0

/

25

48

11

16

15

43

3924.0

/

24

55

6

15

15

44

3929.0

/

32

49

7

12

20

45

3930.0

/

34

50

4

12

20

46

3931.5

/

17

51

15

17

20

47

3932.3

/

36

46

5

13

20

48

3933.3

/

26

54

5

15

20

49

3933.9

/

28

40

23

9

20

50

3934.3

/

35

45

5

15

20

51

3934.8

/

32

52

3935.0

/

20

53

3936.3

/

34

54

3935.8

/

38

55

3937.5

/

56

3939.0

/

57

3941.4

/

58

3984.1

/

59

3985.1

/

60

4018.5

/

61

4020.5

/

62

4024.1

EP

SC 6

15

20

51

13

16

20

44

8

14

20

46

5

11

20

62

23

5

10

20

17

56

5

22

15

25

49

6

20

20

5

65

7

23

20

25

53

9

13

20

28

44

5

23

20

35

28

6

31

20

17

25

6

52

20

S% — the proportion of smectite layers of in mixed-layer illite/smectite;

AC C

47

M AN U

TE D /

RI PT

38

"/ "— not detected.

ACCEPTED MANUSCRIPT Table 3 Mineral types and content / vol.% Well

Depth (m) Quartz

K-fledspar

Plagiovlase

Rock fragments

3860.4

52

3

19

26

2

3861.0

47

8

21

25

3

3799.0

42

7

17

34

4

3800.5

46

7

22

25

5

3801.5

57

7

21

16

6

3802.5

58

4

18

20

7

3803.0

53

7

19

21

8

3859.0

56

7

21

16

9

3860.0

55

12

19

14

10

3863.4

54

7

24

16

3992.5

75

4

16

4

12

3994.5

65

4

16

15

13

3998.7

68

5

13

14

14

3997.7

67

4

18

11

15

4025.0

49

4

10

38

16

4026.0

69

6

24

1

17

4028.0

65

3

18

14

18

4070.3

71

5

19

6

19

4071.8

67

1

22

10

4075.3

71

1

21

7

4070.0

66

3

18

13

3661.9

67

5

10

19

3662.3

49

8

5

39

3663.6

62

9

8

21

3664.7

51

33

6

10

3666.7

79

6

10

5

3667.8

76

10

12

2

28

3670.3

64

12

12

12

29

3676.3

52

5

5

39

3680.2

74

13

11

1

31

3682.4

66

9

9

17

32

3726.0

72

14

13

1

33

3731.0

76

7

8

8

34

3733.0

68

7

13

12

35

3741.4

61

8

12

19

36

3747.0

71

8

13

8

37

3776.3

60

12

17

11

38

3788.1

67

6

21

6

39

3794.6

59

6

17

18

20 21 22

25 26

AC C

27

EP

23 24

M AN U

KL2

TE D

11

30

RI PT

1

SC

No.

KL201

3800.7

41

5

19

36

41

3920.0

46

11

17

26

42

3924.0

51

6

19

24

43

3929.0

47

5

23

24

44

3930.0

53

5

15

27

45

3931.5

38

6

15

41

46

3932.3

73

6

13

8

47

3933.3

46

10

18

26

48

3933.9

49

4

22

25

49

3934.3

57

6

17

21

50

3934.8

62

8

22

8

51

3935.0

42

5

17

35

52

3936.3

54

7

12

27

53

3935.8

59

3

13

25

54

3937.5

55

10

18

18

55

3939.0

42

4

10

45

56

3941.4

46

14

14

27

57

3984.1

33

4

13

50

58

3985.1

58

6

15

21

59

4018.5

68

6

22

4

60

4020.5

76

4

19

1

61

4024.1

59

3

26

12

AC C

EP

M AN U

TE D

Vol. % — volume percent

RI PT

40

SC

ACCEPTED MANUSCRIPT

ACCEPTED MANUSCRIPT

ҩvap

Th (°C)

Tm (°C)

Salinity (wt% NaCl eq)

1

2×3

5%

95.0

-13.5

17.34

2

2×4

5%

96.2

/

/

2×3

5%

120.0

/

/

Yellowish-brown fluorescent

2×3

5%

102.3

-14.5

18.22

oil inclusions

5

2×5

10%

108.3

-14.5

18.22

6

1×8

5%

7

1×3

5%

8

1×4

5%

2×4

Mineral

2-phase Quartz

4

Location

Fracture

aqueous inclusions

-15.2

18.8

123.0

-12.6

16.53

160.0

-14.1

17.87

5%

140.0

-13.3

17.17

5×9

10%

145.8

-13.4

17.26

2×4

20%

156.4

-10.0

13.94

2×4

10%

123.4

/

/

2×2

10%

162.1

/

/

3×12

5%

154.7

/

/

2×1

10%

175.3

-14.4

18.13

2×6

10%

177.7

-12.6

16.53

3×6

10%

114.0

/

/

2×3

5%

122.0

-17.0

20.22

2×4

5%

122.0

-17.4

20.52

1×5

5%

123.0

-17

20.22

10×25

25%

93.7

/

/

/

pseudo-primary

7×15

25%

80.0

/

/

/

inclusions

10×14

30%

81.2

/

/

/

9 10 11 2-phase

Quartz

Fracture

12 aqueous inclusions 14 15 16

18 2-phase 19

pseudo-primary Ankerite

aqueous inclusions

Blue-white fluorescent

oil inclusions

pseudo-primary

Ankerite oil inclusion

22

Vapour inclusions

Blue-white fluorescent

inclusions

20

21

Boundary

EP

Quartz

TE D

13

17

Associated inclusions

96.7

M AN U

3

Type

AC C

No.

RI PT

Size (µm)

SC

Table 4

inclusions

Yellowish-brown fluorescent Calcite

23

oil inclusions

wt. % — weight percent; ҩvap — vapour volume fraction; "/ "— not detected or non-existent.

AC C

EP

Fig.1

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Fig. 2

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

Fig.3

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

Fig.4

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

Fig.5

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

Fig.6

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

Fig.7

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Fig.8

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Fig.9

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

Fig.10

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

Fig.11

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

Fig.12

AC C

EP

Fig.13

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Fig.14

ACCEPTED MANUSCRIPT Research Highlights Diagenetic history suggests seven key diagenetic events. Diagenetic history recored three episodes of hydrocarbon emplacement.

AC C

EP

TE D

M AN U

SC

RI PT

Oil fluid inclusions can be trapped by the diagenetic minerals.