The Silurian Qusaiba Hot Shales of Saudi Arabia: An integrated assessment of thermal maturity

International Journal of Coal Geology 159 (2016) 107–119

Contents lists available at ScienceDirect

International Journal of Coal Geology journal homepage: www.elsevier.com/locate/ijcoalgeo

The Silurian Qusaiba Hot Shales of Saudi Arabia: An integrated assessment of thermal maturity Sedat İnan a,⁎, Fariborz Goodarzi b, Andreas Schmidt Mumm a, Khaled Arouri a, Salman Qathami a, Omid H. Ardakani c, Tulay İnan d, Amer A. Tuwailib d a

Saudi Aramco, EXPEC Advanced Research Center, Dhahran 31311, Saudi Arabia FG & Partners Ltd., 219 Hawkside Mews, NW Calgary, Alberta T3G3J4, Canada Geological Survey of Canada, 3303 33rd St., NW Calgary, Alberta T2L2A7, Canada d Saudi Aramco, Research and Development Center, Dhahran 31311, Saudi Arabia b c

a r t i c l e

i n f o

Article history: Received 7 March 2016 Received in revised form 7 April 2016 Accepted 9 April 2016 Available online 13 April 2016 Keywords: Silurian source rock Thermal maturity calibration Integrated assessment Qusaiba shales Graptolite Reflectance measurements

a b s t r a c t The Lower Silurian Qusaiba Hot Shales (QHS) are proven source rocks for oil within the Paleozoic, and possibly some of the Mesozoic, reservoirs in Saudi Arabia. Moreover, these shales have oil shale potential where they are immature and shallow enough for mining, as well as unconventional shale oil and shale gas potential, in areas where they are within oil-maturity and gas-maturity levels, respectively. The QHS were deposited in relatively shallow marine environments under anoxic water conditions, resulting in accumulation of amorphous kerogen, organic-walled graptolites and acritarchs. Across the Arabian Basin, organic matter quality does not show much variation for the QHS, but the maturity varies greatly as a result of varying burial history. Thermal maturity assessment of shale source rocks that lack vitrinite, such as the Qusaiba Hot shales, continues to be challenging, especially where conflicting measurements are obtained from different sources. This paper presents an integrated assessment of QHS thermal maturity parameters, based on cores from 13 carefully selected boreholes that – based on regional basin models – are believed to cover a wide maturity range (ca. 0.5 to 2.0% Ro). We conducted some analyses on kerogen (maceral petrography, graptolite reflectance, UVfluorescence, whole rock pyrolysis, Raman spectroscopy of graptolite) and other analyses on bitumen extracts (GC and GC–MS of saturate and aromatic fractions, and FTIR spectroscopy of the asphaltene fraction). We show that using many thermal maturity parameters reduces uncertainty significantly, and we therefore recommend that graptolite reflectance analyses should be conducted in support of other maturity indicators. Proper reflectivity measurements of the graptolites set the reference for comparison of other maturity parameters obtained from petrographic, geochemical, and spectroscopic techniques. Our work provides a template by which Qusaiba thermal maturity can be more accurately estimated when only a limited set of maturity parameters is available. © 2016 Elsevier B.V. All rights reserved.

1. Introduction The increasing interest in unconventional shale oil/gas resources has resulted in a greater focus on source rocks. Furthermore, globally widespread Ordovician-Silurian organic-rich shales (Klemme and Ulmishek, 1991) are attracting more attention in the US, Europe, Middle East, China, and Australia. Thermal maturity is among many key factors that play an important role in determining the viability of these shales as both source and reservoir (e.g., Curtis, 2002; Montgomery et al., 2005; Hill et al., 2007; Jarvie et al., 2007; Bruner and Smosna, 2011; Loucks et al., 2009; Alexander et al., 2011; Chalmers et al., 2012; Zhang et al., 2012; Romero-Sarmiento et al., 2013; Milliken et al., 2013; Hao et al., 2013; Romero-Sarmiento et al., 2013; O'Connor et al., 2014; Inan et al., ⁎ Corresponding author. E-mail address: [email protected] (S. İnan).

http://dx.doi.org/10.1016/j.coal.2016.04.004 0166-5162/© 2016 Elsevier B.V. All rights reserved.

in press). Although reflectance of vitrinite particles in coal, and carbonaceous organic matter dis@persed in sedimentary rocks, is a widely used and robust thermal maturity indicator (Tissot and Welte, 1984; Hunt, 1996; Hackley et al., 2015), pre-Devonian shales do not contain vitrinite, which originates from ligno-cellulosic tissues of higher land plants that postdated the Late Silurian, when the first vascular plants evolved (Teichmüller, 1982; Tissot and Welte, 1984; Taylor et al., 1998). Therefore, in this study it is essential to achieve reliable thermal maturity measurements (expressed as vitrinite reflectance equivalent, VRE) which are optimally suited to define oil and gas generation windows for the Qusaiba shales. In the absence of vitrinite in Lower Paleozoic rocks, reflectance measurements have been carried out mostly on zooclasts, like graptolite, which exist in abundance with other organic matter, e.g., bitumen and vitrinite-like particles (Jacob, 1989; Suárez-Ruiz et al., 2012; Petersen et al., 2013). In several studies the reflectance of various types of

108

S. İnan et al. / International Journal of Coal Geology 159 (2016) 107–119

zooclasts and bitumen were measured and compared with other maturity indicators, such as pyrolysis Tmax, Conodont Alteration Index (CAI), Thermal Alteration Index (TAI), and atomic H/C ratios of isolated kerogens (e.g., Bertrand, 1990; Bertrand and Héroux, 1987; Buchardt and Lewan, 1990; Haeri-Ardakani et al., 2015). Graptolites are the most widely used zooclast group for reflectance measurements because evolution of their optical properties is comparable to that of vitrinite (Bustin et al., 1989; Goodarzi and Norford, 1986, 1989; Goodarzi et al., 1992; Petersen et al., 2013; Hartkopf-Fröder et al., 2015). Extreme care must be exercised, however, due to inaccuracy in reflectance measurements that may arise from graptolite anisotropy, especially in samples of advanced maturities. Measurements based on bitumen reflectance are less reliable for maturity determination, because bitumen may have various origins and morphologies, and it may not be indigenous to the host rock (Petersen et al., 2013). In addition, surface quality and roughness of bitumen can significantly affect bitumen reflectance (Sanei et al., 2015). On the other hand, although experienced microscopists can easily and reliably distinguish and measure graptolite reflectance, the nature of graptolite anisotropy, especially at advanced maturities, prevents these measurements from being made and used reliably by less experienced organic petrologists. This study offers an integrated account of this subject, comparing and calibrating a wide array of thermal maturity parameters for the widespread graptolitic Silurian Qusaiba Hot Shales (QHS) of Saudi Arabia. Oil and gas windows can then be more accurately defined.

the initial Early Silurian transgression that resulted from the melting of the Late Ordovician ice cap (Lüning et al., 2000). A summary of the PPS is shown in Fig. 1. This petroleum system contains the Early Silurian basal Qusaiba “hot shale” and, to a lesser extent, the overlying warm shales, as its principal source rocks, with reservoirs extending from the Ordovician to the Early Triassic. Seals occur at different stratigraphic levels, with the evaporitic Sudair Formation of the Early Triassic age serving as the regional top seal of the PPS. Hanadir and Ra′an shales of the Ordovician Qasim Formation may also possess some source potential (Aramco internal reports).

Age

my

Lithology

Play Element & Stratigraphic Unit

2. Geological setting The main tectonic phases that shaped the Arabian Plate include: 1) basement formation during Precambrian, 2) major glaciation, followed by de-glaciation in the Ordovician-Early Silurian and deposition of the organic-rich Qusaiba Hot Shales, 3) major basin inversion and erosion during mid-Carboniferous (Hercynian Orogeny), 4) fragmentation of the Gondwana Supercontinent and drift of the Arabian Plate to the equator, leading to favorable source-reservoir pairs development from Late Permian through to the Jurassic, 5) closure of the Neo-Tethys and the rejuvenation of Hercynian structures during Middle to Late Cretaceous, and 6) the Zagros Orogeny and tilt of the Arabian Plate followed by Zagros thrusting during Tertiary to present (Powers et al., 1966; McGillivray and Husseini, 1992; Alsharhan and Nairn, 1997; Wender et al., 1998; Al-Hajri and Owens, 2000; Konert et al., 2001; Sharland et al., 2001; Ziegler, 2001; Faqira et al., 2009; Cantrell et al., 2014, and references therein). Throughout the Paleozoic era, continental and shallow-marine clastic sedimentation prevailed on a stable passive margin in northeastern Gondwana. The Hercynian events of the mid-Carboniferous affected the area, creating regional uplift, widespread erosion and basement tectonism due to rejuvenation of the pre-existing weaknesses in the basement (Konert et al., 2001). From the Permian to the Eocene, the area was a broad stable passive margin, where the deposition of mainly shallow-water carbonates with minor anhydrites and shales occurred (Cantrell et al., 2014). Since the Oligocene, the northeastern part of the basin (along the Arabian Gulf) has undergone shortening, as a consequence of collision of the Arabian Plate with Laurasia (Zagros Orogeny). The resulting flexure of the Arabian Plate underneath the Zagros fold and thrust belt created a wedge-shaped, low-angle (b2°, tilting NE) foreland basin. With respect to Paleozoic Petroleum System (PPS) of the Arabian Basin, the Early Silurian has prime importance, due to deposition of organic-rich (hot) shales in an expansive shelf area of the Gondwana, covering present-day North Africa and Arabian Peninsula where, according to Klemme and Ulmishek (1991), Lower Silurian organic-rich shales have generated about 80–90% of the Paleozoic-sourced hydrocarbon accumulations. These hot shales represent the lowermost (basal) part of the Qusaiba Formation of the Qalibah Group (Alsharhan and Nairn, 1997). In most cases, hot shales were deposited directly above Upper Ordovician peri-glacial sandstones (Sarah Formation) during

Hercynian Unconformity

Sarah sst. Hanadir/ Raan shales.

Fig. 1. Generalized stratigraphic column and the elements of the Paleozoic and Mesozoic Petroleum Systems in the Saudi Arabian Basin (modified from Cantrell et al., 2014).

S. İnan et al. / International Journal of Coal Geology 159 (2016) 107–119

Although several fine clastics intervals (e.g., shales and mudstone) are potential source rocks of various organic richness locally, the basal organic-rich hot shale member of the Qusaiba Formation (Fig. 1) extends across the entire basin (Mahmoud et al., 1992; Cole et al., 1994; Senalp, 2010). Termination of glaciation at the end of the Ordovician resulted in a major sea-level rise during the early Silurian, leading to deposition of the upward-coarsening progradational Qalibah Group. This rapid transgression resulted in the deposition of organic-rich siliciclastics (so-called hot shales) within anoxic intra-shelf depressions of northern Gondwana (Jones and Stump, 1999). Subsequently, a more oxic depositional environment led to a widespread and thick deposition of organic-lean shales (so-called warm shales) of the Qusaiba Formation (Lüning et al., 2000). The hot shale is best developed in east-central Saudi Arabia, as well as in northwestern Saudi Arabia, having an average total organic carbon (TOC) content of about 5 wt.%, with maximum values as high as 20 wt.% (Cole et al., 1994) and Hydrogen Index values of up to 500 mg HC/g TOC for immature samples (this study). Several Paleozoic oil and gas fields in Saudi Arabia are known to have been sourced from this hot shale (Abu-Ali et al., 1991, 1999; McGillivray and Husseini, 1992; Mahmoud et al., 1992; Cole et al., 1994; Jones and Stump, 1999). This hot shale contains type II amorphous organic matter, with graptolite and chitinozoans as the main identifiable macerals, and ranges in thickness from 10 to 250 ft (3–70 m), as reported by many workers (e.g., Mahmoud et al., 1992; Wender et al., 1998; Abu-Ali et al., 1999; Abu-Ali and Littke, 2005). The overlying warm shale is leaner in organic richness (only a few weight percent TOC), with mixed oil and gas potential (Cole et al., 1994). The greater thickness of the warm shale can, however, make up for its leaner TOC with respect to volumes generated, potentially rendering it a viable hydrocarbon contributor to Paleozoic reservoirs. 3. Samples and methods For this integrated maturity calibration study, all core samples were collected from the organic-rich graptolitic Silurian Qusaiba Hot Shales

109

(QHS), that — based on the current working basin model (İnan et al., in press) — appear to cover a wide maturity range (from immature to overmature with respect to hydrocarbon generation). Wells sampled are indicated in Fig. 2. 3.1. Sample selection and preparation Core samples (n = 33) of the QHS from 13 wells in two areas (NW and east-central) (Fig. 2) were washed to remove drilling mud and then oven-dried (35 °C) prior to further handling. Each sample was then split perpendicular to bedding into two sub-samples. The first split was ground to b 250 μm grain size using a mortar and pestle. The second split (whole rock sample) was polished for microscopic examination. Samples as polished blocks (both parallel and perpendicular to bedding) were mixed with a cold-setting epoxy–resin, and after hardening the sample pellets were ground and polished, following Mackowsky (1982). The types of analyses conducted were solely based on availability and sufficient sample quantity for a given analysis. 3.2. Pyrolysis of whole-rock samples Thirty-three core samples from 13 wells were ground to powder (b250 μm) and approximately 60 mg of each sample was analyzed with the Source Rock Analyzer® (SRA, Weatherford, USA). Pyrolysis results are listed in Table 1. Pyrolysis was run at 300 °C for 3 min (to release free hydrocarbons, S1, mg HC/g rock), then at 25 °C/min to 650 °C, to release, through thermal cracking, kerogen-bound hydrocarbons (S2, mg HC/g rock) and oxygen-containing compounds (S3, mg CO2/g rock collected up to 390 °C). The temperature at which generation amount per unit time of the S2 pyrolysis products is at a maximum is recorded as Tmax (°C). Helium was the carrier gas. The residual (inert) organic carbon is measured as a fourth peak (S4, mg CO plus mg CO2/g rock) by oxidation (at 25 °C/min from 300 °C to 850 °C) under oxygen. All four peaks (S1–S4) are used to calculate TOC. Oxygen Index (OI) = S3 / TOC × 100. Hydrogen Index (HI) = S2 / TOC × 100.

N

Fig. 2. Map of the study areas, showing well localities from which core samples of the Qusaiba Hot Shales were obtained.

S. İnan et al. / International Journal of Coal Geology 159 (2016) 107–119

110

Table 1 Qusaiba Hot Shale core samples collected from 13 wells across Saudi Arabia. Depth information is not given for confidentiality reasons. Well

Sample

1–Pyrolysis TOC

A

S2

S3

HI

OI

PI

0.29

486

14

3

0.19

1.91

1.14

0.21

482

16

3

0.63

B1

1.01

0.15

0.51

0.36

442

50 35

0.22

B2

1.46

0.14

0.45

0.58

446

31 39

0.24

C1

1.67

0.45

1.33

0.04

451

80

3

0.25

C2

1.04

0.31

0.78

0.19

455

77 18

0.28

C3

1.02

0.18

0.35

0.17

448

35 17

0.34

C4

5.84

0.09

0.2

0.13

461

D

D1

5.65 4.61

1.55

1.23

0.31

469

27

7

0.56

D3

2.26

0.24

0.37

0.15

477

16

6

0.39

E

E1

1.22

0.24

1.14

0.1

447

93

8

0.18

E2

1.19

0.16

0.63

0.13

443

53 11

E3

6.89

1.35

8.47

0.25

D2

1.42

1.4

0.27

3–Maltene

2–Deasphaltening Tmax

1.45

7.15

C

10.4

S1 0.34

A2 B

A1

473

3 25

2 5

84.1

90.4

4–Optical microscopy

∑ Asph%

Sat%

Aro%

NSO%

GRo %

VRE%

15.9

37.3

41.5

21.2

1.78

1.43

54.6

19.2

26.2

0.98

0.78

68.5

12.3

19.2

50.0

8.5

41.5

9.6

1.51

0.5

62.3

17.5

20.2

13.4

30.4

2.03

1.62

1.31

1.05

2.32

0.64

0.2

81.7

18.3

53.8

19.3

26.9

0.14

87.1

12.9

55.8

18.9

25.3

79.7

20.3

19.9

42.2

37.9

0.68

0.54

1.78

1.43

449

123

10

2.02

14.6

0.33

443

146

3

0.12

F1

12.6

2.52

63.8

0.56

414

508

4

0.04

G1

3.39

1.11

1.54

0.2

453

46

6

0.42

G2

5.02

1.02

2.81

0.23

475

56

5

0.27

66.7

33.3

32.5

17.5

50.0

H1

6.01

2.11

20.5

0.25

444

340

4

0.09

67.4

32.6

25.3

35.4

39.3

H2

6.52

2.93

13.6

0.23

440

209

4

0.18

30.8

46.7

22.5

H3

5.19

2.18

8.4

0.25

442

162

5

0.21

H4

5.52

2.18

7.21

0.1

439

131

2

0.23

83.2

16.8

43.9

39.4

16.7 2.2

1.76

44.8

21.3

33.9

1.33

1.06

47.0

29.7

0.76

0.61

I

I1

3.17

J

J1

1.5

0.24

0.5

0.28

456

33 18

0.33

J2

1.63

0.39

0.61

0.24

454

37 15

0.39

7.53

2.14

33.4

0.05

418

443

K

K1

M

510

6 10

Aromaticity%

Yellow

Brown

6–Raman

0.25

Mean (G–D)

MPR

Rc%

MAS aromatization

TNR–1

TNR–2

257.1

3.01

1.41

0.03

1.86

1.12

1584.6

246.2

0.78

0.84

0.09

0.81

0.72

0.91

0.90

0.15

1.10

0.88

0.93

0.91

0.10

1.19

0.93

4.72

1.61

2.90

1.40

0.10

1.76

1.09

3.10

1.43

0.21

1.49

0.96

1598.8

254.3

0.86

1.94

Yellow

Blue/green

0.88

0.20

1.22

0.90 0.76

1591.5

254.2

1.36

1.07

0.05

0.92

35.3

1579.7

237.3

1.35

1.07

0.62

0.78

0.75

65.0

1595.6

251.5

2.28

1.29

0.02

2.02

1.14

0.82

0.85

0.31

1.01

0.85

0.85

0.87

0.23

0.86

0.80

0.84

0.86

0.21

0.76

0.78

48.6

Dark yellow 0.77

0.87

44.1

1590.0

245.5

1599.9

261.6

2.69

1.37

0.02

1592.6

252.4

1.48

1.11

0.04

1.73

1.09

1581.5

236.9

1.22

1.03

0.44

0.64

0.64

416

419

2.42

30.8

0.15

419

373

2

0.07

23.5

43.6

32.8

1.32

1.06

0.43

0.73

0.72

0.61

0.15

429

31

8

0.08

43.2

18.2

38.6

1.02

0.95

0.80

1.15

0.82

L2

1.26

0.06

0.68

0.13

431

54 10

0.09

L3

1.77

0.04

0.39

0.12

428

22

7

0.09

M1

1.61

0.03

0.27

0.12

428

17

8

0.11

M2

0.73

0.02

0.22

0.12

427

31 16

0.09

1

23.3

1.07

Blue

250.4

0.05

0.08

26.1

Orange/brown

1588.0

8.27

32.3

73.9

62.9

2.01

2.18

0.06

Orange/brown

7–GC–MS

G Peak 1597.3

L1

7.71

1

5–FTIR FC

K3

K2 L

0.31

2.95

56.3

E4

0.2

1.56

1.21

F

0.07

R/G Q

0.3

G H

4

∑ Maltene%

0.06

0.7

1.2

0.64

0.99

Blue/light yellow

0.69

1.17

Light yellow

Color indicates maturity inferred from collective evidence: Yellow–immature to marginally mature, Green– Oil window maturity, Orange– Late oil window maturity, Pink– Gas window maturity. 1– Pyrolysis– Rock Eval pyrolysis analyses, parameters are defined in the text. 2– and 3– asphaltene recovery and maltene fractionation by column chromatography 4– Microscopy: GRo = Mean graptolite reflectance, VRE = Vitrinte reflectance caluclated from graptolite reflectance, R/G Q = Ratio of Red/Green spectrum under UV light excitation –1

FC = Fluorescence color of liptinitic material. 5– FTIR Spectroscopy–derived aromaticity. 6–Raman Spectroscopy–derived D and G peaks (cm

) of graptolites,

7– GC–MS derived biomarker maturity parameters MPR (Methylphenanthrene Ratio) = (2–MP/1–MP). %Rc = Vitrinite reflectance calculated from MPR, where %Rc = 0.99*log(MPR)+0.94 (Radke, 1988) MAS Aro– Monoaromatic steroid aromatization = TA26–28/TA26–28+MA27–29 (Peters et al., 2005), Trimethyl Nafthalene Ratios (TNR–1 and TNR–2 of Alexander et al., 1985), TNR–1 = 2,3,6–TMN / (1,3,5 & 1,4,6–TMN), TNR–2 = (1,3,7–TMN +2,3,6–TMN) / (1,3,6–TMN + 1,3,5 & 1,4,6–TMN).

3.3. Organic petrology Microscopic work was conducted with a Zeiss Axioimager II microscope system, equipped with incident white- and fluorescent-light sources and the Diskus-Fossil system. Reflectance measurements used a 50 × oil objective lens under oil immersion (refractive index, n = 1.518 at 23 °C). Core samples consisted of four relatively organic-lean silty carbonates and eleven shales (Table 1). These samples were examined using reflected white light and fluorescent light microscopy. The standard reference for reflectance measurement was yttrium-aluminum-garnet (Ro = 0.906%, under oil immersion). Fluorescence properties of the liptinites were determined under water using ultraviolet source G 365 nm excitation, with 450–490 nm excitation filter, beam splitter 510 nm and a 420 nm barrier filter. This combination allowed the determination of the red to green fluorescence color quotient (R/G Q). This quotient is defined as a ratio of relative intensity at 650 nm over relative intensity at 500 nm using two standards for the color of liptinites. 3.4. Bitumen extraction and fractionation Bitumen from pulverized samples was extracted using Accelerated Solvent Extraction system (ASE 200, Dionex), with MAC (methanol, acetone, chloroform; 15:15:70, v/v) as the solvent. The instrument was operated at 1500 psi and 120 °C; first preheated for 5 min, then flushed with a total of 80 mL of solvent for 10 min. Extracted bitumen was allowed to dry before deasphaltening with excess n-pentane (40:1, v/ v). Precipitated asphaltenes were separated from maltene by filtration of the maltene through 0.45 μm teflon filter. The asphaltene was washed several times by n-pentane and was dried under flowing nitrogen stream. Maltene (pentane-soluble) fractions were fractionated into saturated hydrocarbons, aromatic hydrocarbons, and NSO compounds by open column silica-gel liquid chromatography, using, respectively, npentane, an equal mixture of n-pentane and dichloromethane, and finally MAC solvent, as eluents. 3.5. GC–MS of the saturated and aromatic hydrocarbons The saturated and aromatic fractions of the extracted bitumen were analyzed for biomarkers by selected ion monitoring gas chromatography–mass spectrometry (SIM GC–MS), using an HP

6890 GC interfaced to an HP mass selective detector (MSD 5973), and controlled by Chemstation software. A DB-1 capillary column (with 60 m length and 0.25 mm i.d., and 0.25 μm film thickness) was used, with helium as the carrier gas. Samples in dichloromethane (2 mL aliquot) were injected in split mode. The oven temperature was increased from 70 to 200 °C at 5 °C/min and then to 320 °C at 8 °C/min, after which it remained isothermal for 20 min. Several saturated and aromatic compounds were monitored, but only the methylnaphthalenes (m/z 170), phenanthrene (m/z 178), methylphenanthrene (m/z 192), and aromatic steranes (m/z 253 and 231) data are used in this study for determination of maturity. Peaks were identified based on published mass spectra and quantified based on peak are. 3.6. FTIR spectroscopy of asphaltene fraction FTIR Spectroscopic data were collected on dried asphaltene samples in powder form using a Thermo Electron Nicolet 8700 FTIR spectrophotometer equipped with a deuterated triglycine sulfate (DTGS) detector and golden gate attenuated total reflectance (ATR), with zinc selenide (ZnSe) sample cell and average of 128 scans at a resolution of 32 cm−1. 3.7. Raman spectroscopy of graptolite Raman experiments were performed on a HORIBA (Jobin Yvon) LABRAM Spectrometer. The 632.8 nm diode laser was focused onto the sample through a microscope with a 50× or 100× magnification objective, and a spot size at the sample of 2 to 5 μm. Spectra were usually collected over a range of 800 to 2000 cm−1 using a 600 g/mm grating, which resulted in a spectral resolution of typically ~1.5 cm−1. The detector is a Peltier cooled CCD camera. Details are given in Schmidt Mumm and İnan (submitted for publication). All samples were prepared as polished resin mounts of rock fragments. Graptolite reflectance (GRo) values for the samples analyzed by Raman ranged from 0.76 to 2.2%. For each sample mount, graptolites were selected from several different fragments, based on their characteristic shape and occurrence, as well as their UV fluorescence intensity, to generate representative data sets. Abundance and size of graptolites in the samples were quite variable, from some containing only a few fragments of clearly identifiable graptolite, to several samples apparently consisting of a large percentage of graptolites of variable size and preservation. Between 60 and 200 Raman spectra were collected from graptolites for each sample. The number of analyses mainly reflects the abundance of clearly

S. İnan et al. / International Journal of Coal Geology 159 (2016) 107–119

a)

Oil Gas Maturity Maturity

111

b)

Fig. 3. a) Modified van Krevelen diagram, showing a plot of HI vs. OI, and b) a plot of HI vs. Tmax. Both show anticipated maturity trends of different types of kerogens. Filled circle depicts graptolite isolated from an immature shale sample (K1) which plots in the Type III kerogen region.

identifiable, undisturbed graptolites, or fragments thereof. The respective spots for analysis were pre-selected at several μm distance, and analyses were run automatically. This way a statistically significant number of data points were collected for each sample. Measurements of graptolite Raman spectra were performed with multiple accumulations between 20 and 60 s exposure time. Laser power was typically reduced to between 1% and 0.1% to avoid fluorescence, sample overheating or laser-induced pyrolysis. The instrument was regularly calibrated against a silicon wafer and coarse crystalline and ground graphite for wave number consistency. This analytical setup is the result of a range of tests to optimize signal intensity. It produced good results in most cases, and only minor variations in instrument settings, mostly of exposure time and number of accumulations, were applied. 4. Results and discussion 4.1. Pyrolysis Pyrolysis (Source Rock Analyzer) data are listed in Table 1. Quality checks like pyrogram observations of the S1 and S2 peaks and amount of S2 were conducted for the pyrolysis results. We examined the pyrograms of all samples and detected contamination for example (very high S1 yield and a hump before S2 peak) in sample A1 probably due to drilling mud. This sample, therefore, was solvent-extracted and pyrolyzed again. Thus, the Production Index for this sample, calculated as PI = S1 / (S1 + S2), is not reliable. Sample set ranges for TOC, Tmax, and HI are 0.73–12.6 wt.%, 414–510 °C, and 3–508 mg HC/g TOC, respectively. Nine samples from four wells (F, K, L and M) are thermally immature to marginally mature (Tmax b 435 °C), whereas samples from Wells A, B, C, D, E, G, H, I and J range from being mature to overmature. The immature to early mature samples (Tmax b 435 °C) °C) possess high HI values (N 400 mg HC/g TOC), suggesting they contain mainly Type II kerogen (Fig. 3a and b). However, some low-maturity samples have low HI values, plotting near the Type II/III region, which could be ascribed to increased abundance of graptolite in these samples as we will discuss later. One organic-rich (7.53 wt.% TOC) and immature (418 °C Tmax) sample (K1) was demineralized with HF to loosen and isolate graptolite fragments. Graptolitic fragments were hand-picked under a binocular microscope to obtain about 5 mg of material, which was then pyrolyzed. The HI and OI values for the separated graptolites were 200 mg HC/g TOC and 30 mg CO2/g TOC, respectively (shown on Fig. 3). This confirmed the hydrogen-poor, mostly aromatic nature of graptolite, which does not fluoresce under blue-light excitation, as discussed later. A similar conclusion was reached by Rantitsch (1995), who reported that graptolites fall in the vitrinite field on a van Krevelen diagram. An

abundance of graptolites within the organic matter assemblage will, therefore, yield lower HI values. Although chitinozoans, another class of organic-walled marine microfossils, are believed to be made up of dominantly aromatic macromolecules (Dutta et al., 2007; Jacob et al., 2007), little is published on the chemistry of graptolite. Our pyrolysis results and those of Rantitsch (1995) approximate the chemistry of graptolite to be close to that of vitrinite. Our future work on more samples will focus on the chemistry of graptolites as well as their contribution towards the hydrocarbon potential of these shales. Limitations of pyrolysis, which was originally meant to be a screening technique (Katz, 1983; Peters, 1986; Carvajal-Ortiz and Gentzis, 2015), should be carefully considered, and efforts must be made to follow classic guidelines to interpret pyrolysis results. For instance, a Tmax value of 560 °C recorded for sample C4 (Table 1) has been classified as unreliable because pyrolyzable hydrocarbon (S2) value is only 0.2 and the pyrogram for this sample did not show a well-defined S2 peak. The rest of the analyses were at acceptable quality and therefore sample selection was made for more detailed analyses mostly based on TOC content and thermal maturity level. 4.2. Visual kerogen analyses Microscopic kerogen observations of many samples, particularly immature to marginally mature samples, showed that amorphous kerogen (detected mainly under blue light) is dominant among organic matter, but graptolite is also abundant in many samples, and thus suitable for reliable graptolite reflectance measurements. Visual kerogen estimations by point-count method have not been performed. Organic matter of immature to mature samples was shown, under white light and fluorescence-induced blue light microscopy, to consist mainly of alginite, lipto-detrinite, and graptolite, together with amorphous organic matter (Fig. 4). Fluorescence color of alginite, liptodetrinite and amorphous kerogen, as expected, turns darker in the sequence from immature (e.g., sample F) to late-oil maturity level (e.g., sample H2). In contrast, graptolite rhabdosome fragments are generally non-granular and non-fluorescing, regardless of the maturity of the sample. Graptolites are dominant in the Qusaiba shale samples, and based on visual estimates, they may form up to half of the organic matter. Although we did not perform point-counting under microscope, we have observed, in some core specimens, that 20–25% of the bedding parallel core surface area is dominated by mega graptolites. By comparison, Luo et al. (2016) reported that graptolites account for 20–93% of the dispersed organic matter in the Upper Ordovician-Lower Silurian WufenLong Maxi shales in China. Granular graptolites are commonly found in carbonates (Goodarzi and Norford, 1989). The occurrence of algae with different fluorescence colors indicates various levels of thermal

S. İnan et al. / International Journal of Coal Geology 159 (2016) 107–119

112

a)

b)

G 50µm 50µm

d)

c)

Am

Fig. 4. a) Graptolite fragments in section parallel to bedding (reflected white light), sample F1; b) Blue-green and green-yellow fluorescing algae (A), and graptolite fragment with nongranular morphology in a section parallel to bedding (Sample F1). c) Graptolite fragments (G) of non-granular morphology in a section parallel to bedding, showing collapsed branching graptolite rhabdosome; also showing dark grey bitumen labelled as B (sample K1). d) Yellow-fluorescing algae (A) and Lipto-detrinite (Ld), indicating higher maturity; also shown is amorphous kerogen (Am) disseminated throughout the rock matrix, sample H2.

Frequency

stress on this hydrogen-rich organic material. Graptolitic fragments in the samples show some detail of morphology, such as part of rhabdosome and branching rhabdosome (Fig. 4a and c). It is important to determine graptolite percentages in different samples, because aromatic-rich graptolite affects the proper evaluation of organic matter type and hydrocarbon potential of the shales. For example, H-rich type II kerogen containing sample may plot on a Van Krevelen plot in area for Type II or even Type III because of the high content of graptolite which are H-poor.

Min Ro% = 0.84

Max Ro% = 1.20

N = 142 Random Ro = 1.02%

% Reflectance in oil Fig. 5. Graptolite reflectance for a sample of moderate maturity, showing two populations generated from measurements on graptolite in bedding-parallel and beddingperpendicular orientations. Reflectance measured on bedding-parallel orientation results in higher readings. The two populations seem to be separated at about 1.0%GRo.

4.3. Graptolite reflectance as maturity indicator Several studies have investigated the possibility of using the reflectance of structured marine-derived organic matter, including algae, chitinozoan, graptolite, as maturity indicators in pre-Devonian rocks in the absence of vitrinite (Goodarzi, 1984, 1985; Goodarzi and Norford, 1986, 1989; Goodarzi and Higgins, 1987; Goodarzi et al., 1988, 1992; Riediger et al., 1989; Stasiuk et al., 1994; Petersen et al., 2013). They found that graptolite shows similar maturation patterns as that of vitrinite (Goodarzi, 1984, 1985). Maturity of graptolite increases with increasing thermal maturity of the host rock as determined by Conodont Alteration Index (CAI) (Goodarzi and Norford, 1986). In addition, the reflectance of graptolite follows similar patterns as that of vitrinite, and is higher in sections parallel to bedding (maximum reflectance) as compared to sections perpendicular to bedding (minimum reflectance) (Goodarzi, 1984; Goodarzi et al., 1992), and reflectance of graptolite increases similar to the way in which vitrinite reflectance increases with depth (Goodarzi and Norford, 1986). Recently, Petersen et al. (2013) showed that graptolite reflectance increases faster than vitrinite. In general, the best orientation for measuring graptolite reflectance is parallel to bedding, and often both maximum and minimum reflectance can be determined in the same sample (Fig. 5). Goodarzi et al. (1992) stated that there is a direct correlation between vitrinite reflectance (%Ro) and graptolite reflectance (%GRo). They found that the oil window as defined by a vitrinite reflectance range of 0.5–1.3 Ro%. This coincides with a graptolite reflectance range of 0.7–1.7%, which, when converted to reflectance of vitrinite, is equivalent to 0.56–1.36% VRE, where VRE is vitrinite reflectance equivalent calculated from random graptolite reflectance. Cole (1994) stated that a reduction of 20% on measured graptolite Ro should be considered for anoxic shale, and 35% in oxic shales. 20% reduction of graptolite reflectance values produced VRE values in

S. İnan et al. / International Journal of Coal Geology 159 (2016) 107–119

113

Minimum GRo

Well E

Well F

Well K

Well B

Maximum GRo

Well C

Well A

Frequency

Well G Well H

Well D

Well I

Well J

N=94 Random Ro=2.2%

Fig. 6. Graptolite reflectance measurements (histograms and mean random values) for all Qusaiba samples. Two graptolite reflectance histograms (measurements for minimum reflectance and maximum reflectance) are given for samples from Well C.

agreement with results of Goodarzi et al. (1992). Therefore, we followed this simple relation of %VRE = 0.80 ∗ %GRo. Graptolite reflectance (GRo) for Qusaiba samples ranges from 0.76 to 2.2%, which is equivalent to 0.61 to 1.76% VRE (Fig. 6). Graptolite reflectance measurements were of high quality, with limited variations for each sample. Petersen et al. (2013) reported a relationship between graptolite reflectance and vitrinite reflectance equivalent as “%VRE = 0.73 ∗ GRo + 0.16” and this relationship produces similar results to ours. Photomicrographs of samples of increasing maturity, with graptolite reflectance properties, as well as changes in fluorescence color, are shown in Fig. 7. The graptolite is initially dark grey in immature samples, becoming lighter in color and brighter with increasing maturity. On the other hand, liptinitic materials, under blue-light excitation, show a light yellow color in immature samples, with fluorescence darkening to orange/brown color with increasing maturity. A very good correlation between measured pyrolysis Tmax and calculated %VRE derived from graptolite reflectance is also evident (Fig. 8). This relationship is interesting as it lends support to the notion that pyrolysis Tmax which has been widely used in industry (due mainly to practicality of pyrolysis) is indeed a powerful maturity indicator. Obtaining fast and accurate Tmax values by pyrolysis of hundreds of samples is possible in a relatively short time (e.g., days) and that only few graptolite reflectance measurements will suffice for verification of Tmax to determine the spatial distribution of maturity of a given preDevonian source rock. 4.4. Liptinite fluorescence Fluorescence for all types of liptinites variably increases first with increasing thermal maturity, but at advanced maturity levels, then it decreases and disappears (Goodarzi et al., 1987; Thompson Rizer and Woods, 1987; Gentzis et al., 1993). The change in color (from blue all the way to brown, and the accompanied change in Red/Green spectral ratio, R/G Q) under UV excitation is related to formation and subsequent expulsion of hydrocarbons (Teichmüller, 1982). In immature to

marginally mature graptolitic QHS (e.g., samples F1 and K1), the matrix fluoresces, mainly due to amorphous organic matter disseminated throughout the shale, but the graptolites themselves are nonfluorescing, even in immature and low-maturity samples; consistent with their hydrogen-poor chemistry, as is also indicated by their low pyrolytic yield and HI value, as discussed above. These graptolite-rich kerogens, in terms of van Krevelen diagram placement, behave like Type III. Correlation between measured fluorescence R/G Q and calculated %VRE is excellent (R2 = 0.97, Fig. 9), and indicates that above 1.1%VRE the organic matter loses its fluorescence, and the relationship no longer exists. 4.5. Bitumen fractions and molecular maturity Nineteen out of the 33 samples were solvent extracted, and their extracted bitumens were first deasphaltened and then fractionated. Their saturated and aromatic hydrocarbon fractions were analyzed by GC and GC–MS. A subset of samples was additionally deasphaltened to look into maltene vs. asphaltene behavior in samples of differing maturities (Table 1). The maltene fraction, and specifically the saturated hydrocarbon fraction, dominate the hydrocarbon distributions, irrespective of sample maturity, indicative of the aliphatic nature of derived (extracted) products. Sample A1 which was suspected of contamination based on pyrolysis results was not bitumen-extracted. Both saturated and aromatic biomarkers were identified by GC–MS analysis, but only selected aromatic parameters are discussed here due to their wider response to different ranges of maturity (Table 1). Steranes, hopanes, tri-methyl-naphthalenes and methyl-phenanthrenes (Radke, 1988; Peters et al., 2005) were thoroughly investigated to assess consistent trends with increasing maturity. The results show that, for our suite of samples, only some parameters are useful. C29 sterane (20S/ (20S + 20R)) and C31 homohopane (22S/(22S + 22R)) isomerizations are complete at relatively low maturity levels (e.g., 0.7% VRE) and thus they are not of much use in our sample set. However, parameters derived from sterane aromatization (MAS), tri-methyl-naphthalene ratios and to

S. İnan et al. / International Journal of Coal Geology 159 (2016) 107–119

114

a)

b)

c) Well F

Early oil maturity

50µm

Peak oil maturity

Late oil maturity

Wet gas maturity

Well H

Well J

Well A

Fig. 7. Microscopic observations in a) white light, and b) blue light for a selection of samples of increasing maturity (from the early oil to wet-gas window). Corresponding graptolite reflectance measurements (%GRo) are shown in panel c. Note the increase of reflectivity of graptolite and the associated decrease of fluorescence of liptinitic material (alginite and lipto-detrinite) with the increase in maturity. A- Alginite, Ld- Lipto-detrinite. UV-fluorescence photomicrograph for the wet-gas maturity sample is not shown, due to its very dark appearance on a low-quality image.

S. İnan et al. / International Journal of Coal Geology 159 (2016) 107–119

115

Fig. 8. Correlation between measured pyrolysis Tmax (°C) and calculated (estimated) %VRE.

some extent the methyl-phenanthrene index (MPR) were found to consistently vary with increasing maturity, and thus may be useful. The results considered to be reliable for these parameters are listed in Table 1. In Fig. 10, VRE values estimated from methylphenanthrene index (MPR) and GRo are both cross-plotted against pyrolysis Tmax measurements. It is clear that VRE values estimated from MPR, for low maturity samples, are overestimated, whereas for higher maturity (Tmax ≥ 440 °C) samples they correlate better with pyrolysis Tmax. On the other hand, VRE derived from graptolite reflectance shows much better correlation with pyrolysis Tmax for the entire range of maturity (Fig. 10). Therefore, it is clear that MPI-based maturity should be used with caution, as the MPR may be additionally influenced by non-maturity controls, such as mixing by migrated hydrocarbons and/or alteration. Trimethylnaphthalene-derived maturity indices (Alexander et al., 1985) show some trend with increasing maturity, although this

correlation is not very strong (R2 ~ 0.7, Fig. 11). TNR1 shows a wider range of variation and might be considered better compared to TNR2, which shows relatively little variation through the entire maturity range tested (Tmax of 410 to about 500 °C). Monoaromatic steroid (MAS) aromatization is another useful parameter that has been widely used to assess the thermal maturity of source rock bitumen, as well as oil (Peters et al., 2005). Fig. 12 shows the correlation between MAS aromatization and Tmax. Although the plot shows some scatter, a general trend is apparent, showing a decrease with increasing maturity. 4.6. FTIR spectroscopy of extracted bitumen Another independent proxy for quantifying the thermal maturity of organic matter in source rocks is based on Fourier–Transform Infrared (FTIR) spectroscopic behavior of the carbon bond distribution in

Fig. 9. Correlation between measured fluorescence Red/Green (R/G) Quotient and calculated %VRE as derived from graptolite reflectance.

S. İnan et al. / International Journal of Coal Geology 159 (2016) 107–119

116

Fig. 10. Relationship between graptolite- and MPR-derived %VRE (Radke, 1988), on the yaxis, with pyrolysis Tmax (°C). Note the good correlation between graptolite-derived %VRE and pyrolysis Tmax. MPR-derived maturity is not as good.

kerogen (Lis et al., 2005). Ratios of aromatic (1610 cm−1) and aliphatic carbon (2800–3200 cm−1) FTIR absorption peak areas have been used to compute aromaticity, which is defined as absorption peak area of aromatic carbon over the total absorption peak area of aromatic and aliphatic carbon. The results, reported as Aromaticity%, are given in Table 2. The FTIR spectra for bitumen asphaltene extracted from five samples (immature to overmature) show a consistent increase in aromatic carbon peak area (centered at 1610 cm−1) at the expense of aliphatic carbon peak areas (centered at about 2800–3000 cm−1) with increasing maturity in the range (from 0.54 to 1.43% VRE; Fig. 13a). Calculated aromaticity is then cross-plotted against graptolite-derived VRE of the samples (Fig. 13b). Quite good correlation is observed, with a relatively high correlation coefficient (R2 ~ 0.92). The reason for utilizing only five samples is that many core splits were small in amount and bitumen extracted was too small to obtain a sufficient amount of asphaltene. Future work will cover more samples for a more robust correlation. 4.7. Raman spectroscopy of graptolites An increasing number of studies report the use of Raman spectroscopy of vitrinite, kerogen and other organic components to develop more

Fig. 12. Relation between monoaromatic steroid (MAS) aromatization (m/z 231) and pyrolysis Tmax.

quantitative maturity parameters (Kelemen and Fang, 2001, Liu et al., 2013, Guedes et al., 2010, Jehlicka et al., 2003; Romero-Sarmiento et al., 2014; Hinrichs et al., 2014, Schmidt-Mumm and İnan, submitted for publication). Raman spectroscopy data of G and D peak positions for individual graptolites (Fig. 14a) were collected for 11 QHS samples, where sufficiently representative graptolite fragments were present. The results, reported as the position of the G peak and the mean difference between the G and D peak positions (in cm−1), are tabulated in Table 1, with details of the calculations given in Table 3. Both values correlate well with increasing maturity (%GRo, Fig. 14b and d). In Fig. 14c and e, we plotted %VRE versus position of the G peak and the mean difference between the G and D peak positions (in cm−1), respectively. With increasing maturity of the sample, the G peak shifts to a higher wavelength domain in the spectra. The shift of the D peak is not pronounced. Therefore, as a second verifying parameter, the distance between the G and D peaks (ΔG–D) on the spectra is taken into account. Both Raman (ΔG–D) and Raman G-peak position versus graptolite reflectance produce a robust correlation (R2 ~ 0.9 and higher). The negligible spread is probably related to Raman spectroscopic signals being recorded on graptolite particles with varying degrees of heterogeneity and/or anisotropy. It is known that, as in the case of vitrinite, graptolite particles also develop anisotropy at higher maturities (see, e.g., Goodarzi, 1985). This is confirmed in Figs. 14b and c, which show less spread in the correlation for the low maturity samples, in which anisotropy is not expected to have developed. 5. Conclusions We have used a set of reliable graptolite reflectance measurements as a reference to compare with maturity-related parameters derived Table 2 FTIR spectroscopy-based asphaltene-aromaticity calculation from ratios of carbons in aromatic structures to all carbons present in aliphatic and aromatic structures. %Aromaticity = 100 ∗ Car / (Car + Cal), where Car = carbon in aromatic structure, and Cal = carbon in aliphatic structure. Estimated Aromaticity shows a good correlation with graptolite-derived VRE, where %VRE = 0.181e0.0301 × Aromaticity (R2 = 0.92). Sample Absorption peak area for aliphatic carbon (2800–3000 cm−1)

TNR1 =2,3,6-TMN / (1,3,5 & 1,4,6-TMN) TNR2 = (1,3,7-TMN +2,3,6-TMN) / (1,3,6-TMN + 1,3,5 & 1,4,6-TMN) Fig. 11. Relationship between trimethylnaphthalene (m/z 170) indices (TNR1 and TNR2) and pyrolysis Tmax.

F1 K1 H2 E2 G2

1013 998 1752 1002 1176

Absorption Total % aromaticity % VRE peak area for peak area aromatic carbon (1610 cm−1) 553 786 1655 1702 2188

1566 1784 3407 2704 3364

35.3 44.1 48.6 62.9 65.0

0.54 0.61 0.86 1.05 1.43

S. İnan et al. / International Journal of Coal Geology 159 (2016) 107–119

117

Fig. 13. a) FTIR spectroscopy of asphaltene from five samples of varying maturity, and (b) Correlation of FTIR aromaticity and vitrinite reflectance equivalent (% VRE).

from other methods, including included petrographic, geochemical, and spectroscopic techniques. We conclude based on our integrated reassessment of thermal maturity on Silurian Qusaiba Hot Shales that: • We have confirmed that vitrinite reflectance equivalent (VRE) parameter can be reliably calculated from high quality reflectance measurements of graptolite. It has been customary to use vitrinite reflectance to define oil and/or gas maturity windows. Thus VRE estimations are very useful. • G–D peak separation from Raman spectroscopy shows a good correlation for the whole range of maturity (immature to dry gas generation stage). We found this to be the most reliable and the least operator-biased parameter which can be used successfully in the absence of quality graptolite reflectance data. As the number of studies utilizing Raman measurements will increase, we believe that the oil and gas maturity windows will be defined in the future by the spectral positions of the Raman G and D peaks of the organic matter. • The monoaromatic steroid (MAS) aromatization parameter [represented either as TA26-28/TA26-28 + MA27-29 or 28TA/(28TA + 29MA)] shows a good correlation with maturity for the whole range of maturity (immature to dry gas generation stage).

• Aromaticity increases based on aromatic carbon distribution in the asphaltene fraction (as determined by FTIR spectroscopy), showing good correlation with maturity for the whole range of maturity (immature to dry gas generation stage). • Pyrolysis Tmax proved to be useful from immature to dry gas maturity (e.g., 1.8% Ro), equivalent to Tmax 410 to 510 °C. Caution should be exercised in samples with possible drilling mud contamination and impregnation with migrated oil. Pyrograms should be examined and abnormal samples must be solvent extracted and re-pyrolyzed. This parameter at present day is probably the most useful as Tmax value is inexpensive and easy to acquire. • MPR (Methylphenanthrene Ratio) is not reliable for low maturity (≤0.8% Ro), but appears more consistent at higher maturities (up to dry gas generation stage), provided that samples are not contaminated with drilling mud or they have been thoroughly cleaned.

• Trimethylnaphthalene-based maturity indices are useful maturity indicators up to the late oil/wet gas generation stage (e.g., 1.5% Ro). • Liptinite fluorescence is useful up to the peak to late oil generation stage of maturity (e.g., 1.1% Ro). This is a reliable and established method and can be used successfully as one of the strong maturity indicators.

b)

c)

d)

e)

Intensity [arbitrary units]

a) 226 - VRE1.98

1000

Sample I1

1100

D

G

1200 1300 1400 1500 1600 Raman Signal: wavenumber [cm-1]

1700

1800

Fig. 14. a) An example of a Raman spectrum showing diagnostic peaks for disorder (D) and graphitic (G) carbon structures in the organic matter (in this case graptolite). b) Correlation of G-peak position (measured on graptolitic particles) versus graptolite reflectance. c) Correlation of G-peak position (measured on graptolitic particles) versus vitrinite reflectance equivalent. d) Correlation of ΔG–D peak distance measured on graptolitic particles versus graptolite reflectance. e) Correlation of ΔG–D peak distance measured on graptolitic particles versus vitrinite reflectance equivalent.

S. İnan et al. / International Journal of Coal Geology 159 (2016) 107–119

118

Table 3 Raman spectroscopy determination of G and D peak positions for graptolites in different Qusaiba samples. The G peak position, as well as the difference in G and D peak positions, Δ(G–D), are correlated with an increase in maturity, as shown by graptolite reflectance (%GRo) and vitrinite reflectance equivalent (%VRE). *Not measured, but predicted from the empirical correlation shown in Fig. 14. Optical measurements

Mean maximum

Sample

%VRE

%GRo

D peak

STDev

G peak

STDev

Δ(G–D)

I1 G2 A2 C3 E3 J2 E2 H2 B1 K1 F1

1.76 1.43 1.43 1.21 1.17 1.06 1.05 0.86 0.78 0.61 0.54

2.2 1.78 1.78 1.51 1.38* 1.33 1.31 1.07 0.98 0.76 0.68

1338.3 1344.1

5.0 8.1

1.9 5.8

1344.5

4.4

1340.2

5.2

1343.4 1338.5 1344.7

6.4 5.9 4.2

1599.85 1595.57 1597.3 1598.78 1591.5 1592.62 1588.0 1589.95 1584.62 1581.54 1579.7

261.59 251.48 257.1 254.29 254.2 252.39 250.4 245.54 246.15 236.86 237.3

1.3 6.2 3.4 7.1 4.0

Acknowledgment We thank the Saudi Arabian Oil Company (Saudi Aramco) and the Ministry of Petroleum and Mineral Resources for permission to publish this paper. We extend our appreciation to Maher I. Al-Marhoon for his interest and continuous support. We thank our colleagues Zhenzhu Wan, Marco Vecoli, Christian Cesari for graptolite separation, and Donya Sewdan and Adnan Al-Hajji for technical support in spectroscopic analyses. We thank Dr. Joe Curiale, Dr. Henrik Petersen and an anonymous reviewer for insightful reviews that helped improve the manuscript. We appreciate Dr. S. Dai for editorial handling.

References Abu-Ali, M.A., Franz, U.A., Shen, J., Monnier, F., Mahmoud, M.D., Chambers, T.M., 1991. Hydrocarbon generation and migration in the Paleozoic sequence of Saudi Arabia. Soc. Petrol. Eng. 21376, 345–356. Abu-Ali, M.A., Rudkiewicz, J.L., McGillivray, J.G., Behar, F., 1999. Paleozoic petroleum system of Central Saudi Arabia. GeoArabia 4, 321–335. Abu-Ali, M.A., Littke, R., 2005. Paleozoic petroleum systems of Saudi Arabia: a basin modeling approach. GeoArabia 10, 131–168. Al-Hajri, S., Owens, B., 2000. Sub-surface palynostratigraphy of the Palaeozoic of Saudi Arabia. In: Al-Hajri, S., Owens, B. (Eds.), Stratigraphic Palynology of the Palaeozoic of Saudi Arabia: GeoArabia Special Publication 1. Gulf PetroLink, Bahrain, pp. 10–17. Alexander, T., Baihly, J., Boyer, C., Clark, B., Waters, G., Jochen, V., Le Calves, J., Lewis, R., Miller, C.K., Thaeler, J., Toelle, B.E., 2011. Shale gas revolution. Oilfield Rev. 23, 40–55. Alexander, R., Kagi, R.I., Roland, S.J., Sheppard, P.N., Chirila, T.V., 1985. The effects of thermal maturity on distributions of dimethylnaphthalenes and trimethylnaphthalenes in some ancient sediments and petroleum. Geochim. Cosmochim. Acta 49, 385–395. Alsharhan, A.S., Nairn, A.E.M., 1997. Sedimentary Basins and Petroleum Geology of the Middle East. Elsevier Science B.V., Amsterdam (843 pp.). Bertrand, R., 1990. Correlations among the reflectances of vitrinite, chitinozoans, graptolites and scolecodonts. Org. Geochem. 15, 565–574. Bertrand, R., Héroux, Y., 1987. Chitinozoan, graptolite, and scolecodont reflectance as an alternative to vitrinite and pyrobitumen reflectance in Ordovician and Silurian strata, Anticosti Island, Quebec, Canada. Am. Assoc. Pet. Geol. Bull. 71, 951–957. Bruner, K.R., Smosna, R., 2011. A comparative study of the Mississippian Barnett shale, Fort Worth Basin, and Devonian Marcellus shale, Appalachian Basin. U.S. Department of Energy Report, DOE/NETL-2011/1478 (106 pp.). Buchardt, B., Lewan, M.D., 1990. Reflectance of vitrinite-like macerals as a thermal maturity index for Cambrian–Ordovician Alum shale, Southern Scandinavia. Am. Assoc. Pet. Geol. Bull. 74, 394–406. Bustin, R.M., Link, C., Goodarzi, F., 1989. Optical properties and chemistry of graptolite periderm following laboratory simulated maturation. Org. Geochem. 14, 355–364. Cantrell, D.L., Nicholson, P.G., Hughes, G.W., Miller, M.A., Bhullar, A.G., Abdelbagi, S.T., Norton, A.K., 2014. Tethyan petroleum systems of Saudi Arabia. In: Marlow, L., Kendall, C., Yose, L. (Eds.), Petroleum Systems of the Tethyan Region. AAPG Memoir Vol. 106, pp. 613–639. Carvajal-Ortiz, H., Gentzis, T., 2015. Critical considerations when assessing hydrocarbon plays using rock-eval pyrolysis and organic petrology data: data quality revisited. Int. J. Coal Geol. 152, 113–122. Chalmers, G.R., R.M. Bustin and I.M. Power, 2012. Characterization of gas shale pore systems by porosimetry, pycnometry, surface area, and field emission scanning electron microscopy/transmission electron microscopy image analyses: Examples from the

Barnett, Woodford, Haynesville, Marcellus, and Doig units: AAPG Bull., v. 96, p. 1099–1119, doi.10.1306/10171111052. Cole, G., 1994. Graptolite-chitinozoan reflectance and its relationship to other geochemical maturity indicators in the Silurian Qusaiba shale Saudi Arabia. Energy Fuel 8, 1443–1459. Cole, G.A., Abu-Ali, M.A., Aoudeh, S.M., Carrigan, W.J., Chen, H.H., Colling, E.L., Gwathney, W.J., Al-Hajji, A.A., Halpern, H.I., Jones, P.J., Al-Sharidi, S.H., Tobey, M.H., 1994. Organic geochemistry of the Paleozoic petroleum system of Saudi Arabia. Energy Fuel 8, 1425–1442. Curtis, J.B., 2002. Fractured shale-gas systems. AAPG Bull. 86, 1921–1938. Dutta, S., Brocke, R., Hartkopf-Froder, C., Littke, R., Wilkes, H., Mann, U., 2007. Highly aromatic character of biogeomacromolecules in chitinozoa: a spectroscopic and pyrolytic study. Org. Geochem. 38, 1625–1642. Faqira, M., Rademakers, M., Afifi, A.M., 2009. New insights into the Hercynian orogeny, and their implications for the Paleozoic hydrocarbon system in the Arabian plate. GeoArabia 14, 199–228. Gentzis, T., Goodarzi, F., Snowdon, L.R., 1993. Variation of maturity indicators (optical and Rock-Eval) with respect to organic matter type and matrix lithology: an example from Melville Island, Canadian Arctic archipelago. Mar. Pet. Geol. 10, 507–513. Goodarzi, F., 1984. Organic petrology of graptolite fragments from Turkey. Mar. Pet. Geol. 1, 202–210. Goodarzi, F., 1985. Dispersion of optical properties of graptolite epidermis with increased maturity in early Palaeozoic organic rich sediments. Fuel 64, 1735–1740. Goodarzi, F., Norford, B.S., 1986. Graptolites as indicators of the temperature histories of rocks. J. Geol. Soc. Lond. 142, 1089–1099. Goodarzi, F., Higgins, A.C., 1987. Optical properties of scolecodonts and their use as indicators of thermal maturity. Mar. Pet. Geol. 14, 353–359. Goodarzi, F., Davies, G.R., Nassichuk, W.W., Snowdon, L.R., 1987. Organic petrology and Rock Eval analysis of the lower carboniferous Emma fiord formation in Sverdrup Basin, Canadian Arctic archipelago. Mar. Pet. Geol. 4, 132–145. Goodarzi, F., Stasiuk, L.D., Lindholm, K., 1988. Graptolite reflectance and thermal maturity of lower and middle Ordovician shale from Scania, Sweden. Geol. Fören. Stockh. Förh. 110, 225–236. Goodarzi, F., Norford, B.S., 1989. Variation of graptolite reflectance with depth of burial. Int. J. Coal Geol. 11, 127–141. Goodarzi, F., Fowler, M.G., Bustin, M., McKirdy, D.M., Trudinger, A., 1992. Thermal maturity of lower Palaeozoic sediments as determined by the optical properties of marine-derived organic matter. In: Schilowski, M., Golubic, S., Kimberley, M.M., McKirdy, D.M. (Eds.), Early Organic Evolution. Springer Verlag, pp. 279–295 (IGCP volume). Guedes, A., Valentim, B., Prieto, A.C., Rodrigues, S., Noronha, F., 2010. Micro-raman spectroscopy of collotelinite, fusinite and macrinite. Int. J. Coal Geol. 83, 415–422. Hackley, P.C., Araujo, C.V., Borrego, A.G., Bouzinos, A., Cardott, B.J., Cook, A.C., Eble, C., Flores, D., Gentzis, T., Gonçalves, P.A., Mendonça Filho, J.G., Hámor-Vidó, M., Jelonek, I., Kommeren, K., Knowles, W., Kus, J., Mastalerz, M., Menezes, T.R., Newman, J., Oikonomopoulos, I.K., Pawlewicz, M., Pickel, W., Potter, J., Ranasinghe, P., Read, H., Reyes, J., De La Rosa Rodriguez, G., Fernandes de Souza, I.V.A., Suárez-Ruiz, I., Sýkorová, I., Valentine, B.J., 2015. Standardization of reflectance measurements in dispersed organic matter: results of an exercise to improve inter-laboratory agreement. Mar. Pet. Geol. 59, 22–34. Haeri-Ardakani, O., Sanei, H., Lavoie, D., Chen, Z., Jiang, C., 2015. Geochemical and petrographic characterization of the upper Ordovician Utica shale, southern Quebec, Canada. Int. J. Coal Geol. 138, 83–94. Hao, F., H. Zou and Y. Lu, 2013. Mechanisms of shale gas storage: implications for shale gas exploration in China. AAPG Bull., v. 97(8), p. 1325-1346. Hartkopf-Fröder, C., Königshof, P., Littke, R., Schwarzbauer, J., 2015. Optical thermal maturity parameters and organic geochemical alteration at low grade diagenesis to anchimetamorphism: a review. Int. J. Coal Geol. 150-151, 74–119. Hill, R.J., Jarvie, D.M., Zumberge, J., Henry, M., Pollastro, R.M., 2007. Oil and gas geochemistry and petroleum systems of the Fort Worth Basin. AAPG Bull. 91, 445–473. Hinrichs, R., Brown, M.T., Vasconcellos, M.A.Z., Abrashev, M.V., Kalkreuth, W., 2014. Simple procedure for an estimation of the coal rank using micro-Raman spectroscopy. Int. J. Coal Geol. 136, 52–58. Hunt, J.M., 1996. Petroleum Geochemistry and Geology. W.H. Freeman and Company, New York (743 pp.). İnan, S., Hakami, A., Abu Ali, M.A., 2016. A petroleum system and basin modeling study of northwest and East-Central Saudi Arabia: effect of burial history and adjacent rock lithology on the gas potential of the Silurian Qusaiba shales. AAPG Memoir: Petroleum Systems Case Studies (in press). Jacob, J., Paris, F., Monod, O., Miller, M.A., Tang, P., George, S.C., Beny, J.-M., 2007. New insights into the chemical composition of chitinozoans. Org. Geochem. 38, 1782–1788. Jacob, H., 1989. Classification, structure, genesis and practical importance of natural solid oil bitumen (migrabitumen). Int. J. Coal Geol. 11, 65–79. Jarvie, D.M., Hill, R.J., Ruble, T.E., Pollastro, R.M., 2007. Unconventional shale-gas systems: the Mississippian Barnett shale of north-central Texas as one model for thermogenic shale-gas assessment. AAPG Bull. 91, 475–499. Jehlicka, J., Urban, O., Pokorny, J., 2003. Raman spectroscopy of carbon and solid bitumens in sedimentary and metamorphic rocks. Spectrochim. Acta A 59, 2341–2352. Jones, P.J., Stump, T., 1999. Depositional and tectonic setting of the lower Silurian hydrocarbon source rock facies, Central Saudi Arabia. AAPG Bull. 83, 314–332. Katz, B.J., 1983. Limitations of “Rock-Eval” pyrolysis for typing organic matter. Org. Geochem. 4, 195–199. Kelemen, S.R., Fang, H.L., 2001. Maturity trends in Raman spectra from kerogen and coal. Energy Fuel 15, 653–658. Klemme, H.D., Ulmishek, G.F., 1991. Effective petroleum source rocks of the world: stratigraphic distribution and controlling depositional factors. AAPG Bull. 75, 1809–1851.

S. İnan et al. / International Journal of Coal Geology 159 (2016) 107–119 Konert, G., Afifi, A.M., Al-Hajri, S.A., Droste, H.J., 2001. Paleozoic stratigraphy and hydrocarbon habitat of the Arabian plate. GeoArabia 6, 407–442. Lis, G., Mastalerz, M., Schimmelmann, A., Lewan, M.D., Stankiewicz, A., 2005. FTIR absorption indices for thermal maturity in comparison with vitrinite reflectance Ro in typeII kerogens from Devonian black shales. Org. Geochem. 36, 1533–1552. Liu, D.H., Xiao, X.M., Tian, H., Min, Y.S., Zhou, Q., Cheng, P., Shen, J.G., 2013. Sample maturation calculated using Raman spectroscopic parameters for solid organics: methodology and geological applications. Chin. Sci. Bull. 58, 1285–1298. Loucks, R.G., Reed, R.M., Ruppel, S.C., Jarvie, D.M., 2009. Morphology, genesis, and distribution of nanometerscale pores in siliceous mudstones of the Mississippian Barnett Shale. J. Sediment. Res. 79, 848–861. Luo, Q., Zhong, N., Dai, N., Zang, W., 2016. Graptolite-derived organic matter in the Wufeng-Longmaxi (Upper Ordovician-Lower Silurian) of southeastern Chongqing, China: implications for gas shale evaluation. Int. J. Coal Geol. 153, 87–98. Lüning, S., Craig, J., Loydell, D.K., Storch, P., Fitches, B., 2000. Lower Silurian “hot shales” in North Africa and Arabia: regional distribution and depositional model. Earth-Sci. Rev. 49, 121–200. Mackowsky, M.Th., 1982. Methods and tools of examination. In: Stach, E., Mackowsky, M.Th., Teichmüller, M., Taylor, G.H., Chandra, D., Teichmüller, R. (Eds.), Stach Textbook of Coal Petrology. Gebruder Borntraeger, Berlin, p. 295. Mahmoud, M.D., Vaslet, D., Al-Husseini, M.I., 1992. The Lower Silurian Qalibah Formation of Saudi Arabia—an important hydrocarbon source rock. AAPG Bull. 76, 1491–1506. McGillivray, J.G., Husseini, M.I., 1992. The Paleozoic petroleum geology of Saudi Arabia. Am. Assoc. Pet. Geol. Bull. 76, 1473–1490. Milliken, K.L., Rudnicki, M., Awwiller, D.A., Zhang, T., 2013. Organic matter-hosted pore system, Marcellus fFormation (Devonian), Pennsylvania. AAPG Bull. 97, 177–200. Montgomery, S.L., Jarvie, D.M., Bowker, K.A., Pollastro, R.M., 2005. Mississippian Barnett Shale, Fort Worth basin, north-central Texas: gas-shale play with multi-trillion cubic foot potential. AAPG Bull. 89, 155–175. O'’Connor, S., Green, S., Edwards, A., 2014. What is the impact of geopressure on unconventional plays? EAGE First Break 32, 91–97. Peters, K., Walters, C., Moldowan, J., 2005. The Biomarker Guide: Biomarkers and Isotopes in Petroleum Systems and Earth History. second ed. Vol. 22. Cambridge University Press, New York. Peters, K.E., 1986. Guidelines for evaluating petroleum source rock using programmed pyrolysis. AAPG Bull. 70, 318–329. Petersen, H.I., Schovsbo, N.H., Nielsen, A.T., 2013. Reflectance measurements of zooclasts and solid bitumen in Lower Paleozoic shales, southern Scandinavia: correlation to vitrinite reflectance. Int. J. Coal Geol. 114, 1–18. Powers, R.W., Ramirez, L.F., Redmon, C.D., Elberg Jr., E.L., 1966. Geology of the Arabian Peninsula. U. S. Geol. Surv. Prof. Pap. 560–D (127 pp.). Radke, M., 1988. Application of aromatic compounds as maturity indicators in source rocks and crude oils. Mar. Pet. Geol. 5, 224–236. Rantitsch, G., 1995. Coalification and graphitization of graptolites in the anchizone and lower epizone. Int. J. Coal Geol. 27, 1–22.

119

Riediger, C., Goodarzi, F., Macqueen, R.W., 1989. Graptolites as indicators of regional maturity in lower Palaeozoic sediments, Selwyn Basin, Yukon and Northwest Territories, Canada. Can. J. Earth Sci. 26, 2003–2015. Romero-Sarmiento, M.F., Rouzaud, J.N., Bernard, S., Deldicque, D., Thomas, M., Littke, R., 2014. Evolution of Barnett Shale organic carbon structure and nanostructure with increasing maturation. Org. Geochem. 71, 7–16. Romero-Sarmiento, M.F., Ducros, M., Carpentier, B., Lorant, F., Cacas, M.C., Pegaz-Fiornet, S., Wolf, S., Rohais, S., Moretti, I., 2013. Quantitative evaluation of TOC, organic porosity and gas retention distribution in a gas shale play using petroleum system modeling: application to the Mississippian Barnett sShale. Mar. Pet. Geol. 45, 315–330. Sanei, H., Haeri Ardakani, O., Wood, J., Curtis, M., 2015. Effects of nanoporosity and surface roughness in bitumen reflectance (BRo) measurements in unconventional reservoirs. Int. J. Coal Geol. 138, 95–102. Schmidt Mumm, A., İnan, S., 2016. Raman spectroscopic determination of organic maturity using graptolites. Int. J. Coal Geol. (submitted for publication). Senalp, M., 2010. Stratigraphy and sedimentology of Paleozoic succession in Saudi Arabia. Book 1: Cambrian to Silurian. Saudi Aramco Confidential Publication (412 pp.). Sharland, P.R., Archer, R., Casey, D.M., Davies, R.B., Hall, S.H., Heward, A.P., Horbury, A.D., Simmons, M.D., 2001. Arabian Plate Sequence Stratigraphy. GeoArabia Special Publication Vol. 22. Gulf PetroLink, Bahrain (371 pp.). Stasiuk, L.D., Goodarzi, F., Fowler, M.G., Mukhopadhyay, P.K., Dow, W.G., 1994. Corpohuminite from Canadian Paleozoic: source rocks: petrology and reflectance properties. Vitrinite Reflectance as a Maturity Parameter: Applications and Limitations. ACS Symposium Series. Suárez-Ruiz, I., Flores, D., Filho, J.G.M., Hackley, P.C., 2012. Review and update of the applications of organic petrology: part 1, geological applications. Int. J. Coal Geol. 99, 54–112. Taylor, G.H., Teichmüller, M., Davis, A., Diessel, C.F.K., Littke, C.R., Robert, P., 1998. Organic Petrology. Gebrüder Borntraeger, Berlin (704 pp). Teichmüller, M., Taylor, G.H., Chandra, D., Teichmüller, R., 1982. Origin of the petrographic constituents of coal. In: Stach, E., Mackowsky, M.Th., Teichmüller, M. (Eds.), Stach Textbook of Coal Petrology. Gebruder Borntraeger, Berlin, pp. 219–294. Thompson Rizer, C.L., Woods, R.A., 1987. Micro-spectrofluorescence measurements of coals and petroleum source rocks. Int. J. Coal Geol. 7, 85–104. Tissot, B.P., Welte, D.H., 1984. Petroleum Formation and Occurrence. Springer-Verlag, Berlin (699 pp.). Wender, L.E., Bryant, J.W., Dickens, M.F., Neville, A.S., Al-Moqbel, A.M., 1998. Paleozoic (Pre-Khuff) hydrocarbon geology of the Ghawar area, eastern Saudi Arabia. GeoArabia 3, 273–302. Zhang, T.W., Ellis, G.S., Ruppel, S.C., Milliken, K., Yang, R.S., 2012. Effect of organic matter type and thermal maturity on methane adsorption in shale-gas systems. Org. Geochem. 47, 120–131. Ziegler, M.A., 2001. Late Permian to Holocene Paleofacies evolution of the Arabian plate and its hydrocarbon occurrences. GeoArabia 445–504.