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Assessment of hydrocarbon generation potential and thermal maturity of the offshore Mannar Basin, Sri Lanka

  • Amila Sandaruwan Ratnayake
  • Chaminda Wimal Kularathne
  • Yoshikazu Sampei
Open Access
Original Paper - Exploration Geology
  • 611 Downloads

Abstract

The Mannar Basin is an under-explored offshore sedimentary basin in terms of petroleum geology. The Cretaceous to Paleogene cutting samples were collected in three offshore exploration wells (i.e. the Dorado North, Dorado and Barracuda) in the Mannar Basin. In this study, kerogen type, quantity and thermal maturity of sedimentary organic matter were ascertained using Rock–Eval pyrolysis and vitrinite reflectance analyses. In addition, 1-D basin modelling was used to analyse the timing of hydrocarbon generation in the Mannar Basin. Total organic carbon (TOC) contents and total hydrocarbon potential are higher in the Cretaceous calcareous mudstones than in the Paleogene calcareous silty/sandy mudstones. TOC contents show a negative correlation with oxygen index. Hydrogen index and oxygen index values range from 77 to 785 mg HC/g TOC and from 25 to 165 mg HC/g TOC, respectively. Organic matters were identified as mixed Type II–III and Type III kerogen. Maturity expressed in term of Tmax and vitrinite reflectance range from 332 to 456 °C and from 0.26 to 1.49%, respectively. It indicates both immature and mature sediments. In general, maturity values are relatively high in the Late Cretaceous sediments (Tmax, from 332 to 456 °C, average = 423 °C ± 25) compared to the Paleogene sediments (Tmax, from 388 to 431 °C, average 419 °C ± 10). Geochemical proxies show that oil and gas prone (Type II–III) and gas prone (Type III) kerogen-rich Late Cretaceous sediments of the Dorado and Barracuda wells have principally achieved maturity levels for oil window. Therefore, it suggests incomplete thermal conversion for the wet gas generation in the northeast part of the Mannar Basin. In the 1-D basin modelling, the maximum hydrocarbon generation was observed during the Neogene Period in the Late Cretaceous sediments of the deeper Barracuda well.

Keywords

Rock–Eval pyrolysis Vitrinite reflectance Kerogen type 1-D kinetic modelling Petroleum geochemistry 

Introduction

The Mannar Basin is one of the largest geological provinces for the hydrocarbon exploration in Sri Lanka (Fig. 1). The tectonic settings of this basin have considerably influenced the distribution of basic sedimentary patterns (Ratnayake et al. 2014). In addition, previous investigations suggested that the Mannar Basin is a prolific producer of both gas and oil in the currently explored deepwater area based on numerical estimation in the framework of the basin modelling and considering actual lithological composition (Ratnayake and Sampei 2015b). Thus, it makes a potential target area for future oil and gas exploration in Sri Lanka (Ratnayake et al. 2017a). These previous investigations were carried out based on limited geochemical data regarding the hydrocarbon generation potential and thermal maturity of the offshore Mannar Basin.
Fig. 1

Basic geological setting of the Mannar Basin and locations of exploration wells

Rock–Eval pyrolysis is the most widely applied standard method in petroleum industry to characterise hydrocarbon generation potential (quantity), types of kerogen, types of primary hydrocarbons (oil and gas) and thermal maturity of sedimentary organic matter (e.g. Espitalié et al. 1977; Katz 1983; Delvaux et al. 1990; Langford and Blanc-Valleron 1990; Vandenbroucke and Largeau 2007; Adegoke et al. 2015; Jiang et al. 2015). In addition, vitrinite reflectance is an optical thermal maturity indicator of sedimentary organic matter since Silurian (Ritter 1984; Sweeney and Burnham 1990; Uysal et al. 2000; Mani et al. 2015). Petroleum geochemists generally deal with these analytical results together with standard reference diagrams and numerical modelling for identifying potential source rock beds (e.g. Welte and Yukler 1981; Tissot et al. 1987; Pepper and Corvi 1995; Pepper and Dodd 1995; Abbassi et al. 2014; Mashhadi et al. 2015). The current study is based on the detailed interpretation of qualitative and quantitative aspects of hydrocarbon generation potential and thermal transformation of organic matter using Rock–Eval pyrolysis and vitrinite reflectance (Ro%) data. In addition, compositional kinetics models were considered to determine the evolution of thermal maturity and timing of hydrocarbon generation. This study thus provides basic information for the hydrocarbon exploration works in Sri Lanka.

Study area

The Mannar Basin is a north–south trending offshore sedimentary basin that is located between southeast of India and southwest to northeast of Sri Lanka (Fig. 1). The basin covers an area of 45,000 km2 in Sri Lankan jurisdiction. The basement of the Mannar Basin consists of Precambrian high-grade metamorphic rocks (Cooray 1984). Tectonostratigraphic evolution of the Mannar Basin can be mainly identified as three phases of possible pre-rift, rift and post-rift. Rift phase can be mainly subdivided into early and late syn-rift phases (the Middle Jurassic to Early Cretaceous). Rift transition (or post-rift) is considered with thermal sag phase during the Late Cretaceous and an inversion episode during the Oligocene and Miocene Epochs (Shaw 2002; Kularathna et al. 2015).

The early rifting of the Mannar Basin was related to the late disaggregation of eastern and western Gondwana during the Middle Jurassic Period (Molnar and Tapponnier 1975). This tectonic breakup was associated with the opening of the Indian Ocean (McKenzie and Sclater 1971; Norton and Sclater 1979). The consecutive extensional (rifting) activities resulted in the deposition of terrestrial and marine sedimentary organic matter in the offshore Mannar Basin over nearly 167 million years from the Jurassic to recent in age (Fig. 2). The horsts and tilted fault blocks and compression induced traps were mainly developed during the rifting process and provided encouraging exploration opportunities in this basin (Shaw 2002).
Fig. 2

Lithostratigraphic sections of the Dorado North, Dorado, and Barracuda exploration wells in the Mannar Basin

(modified after Ratnayake et al. 2014; Kularathna et al. 2015)

The Mannar Basin continuously subsided since its rifting and resulted in the deposition of a thick sedimentary succession (Fig. 2). The sediment thickness around the present day depocenter of the Mannar Basin exceeds over 6 km (Ratnayake et al. 2017a). Several studies have demonstrated the wide range of dark colour mudstones from the Jurassic to Cretaceous Periods in neighbouring offshore and onshore sedimentary basins in India, and the Jurassic onshore sedimentary basins in Sri Lanka (e.g. Chandra et al. 1991; Ratnayake and Sampei 2015a). These rocks are possibly related to potential source rock beds in the Mannar Basin. The fragmentation of Madagascar, Laxmi Ridge/Seychelles and Seychelles from the Indian plate was associated with extensive rifting activities (Storey et al. 1995; Chatterjee et al. 2013). In addition, such sequential separations were followed by intrusive and extrusive igneous provenance in the Mannar Basin (Fig. 2). In contrast, the mid to late Cenozoic carbonates-rich sediments in the Mannar Basin can probably indicate climatic transition from arid to tropical conditions (Ratnayake et al. 2014; Ratnayake 2016).

Materials and methods

Materials

The cutting samples were collected from three exploration wells of the Dorado North, Dorado and Barracuda in the Mannar Basin. All the exploration wells are located on the northeast margin of the basin (Fig. 1). The offshore commercial drilling program was conducted from 2011-08-12 to 2011-11-20 using the scientific riser-equipped deepwater drillship Chikyu. The present water depths of the Dorado North, Dorado and Barracuda wells are 1346.4, 1383 and 1509 m, respectively. The sampling depths of the Dorado North, Dorado and Barracuda wells are 2200–3622, 2150–3288 and 2139–4741 m, respectively (Fig. 2). The Dorado and Barracuda wells were plugged as gas discovered wells, and the Dorado North was plugged as a dry well. The Late Cretaceous sediments depths of the Dorado North, Dorado and Barracuda exploration wells are 3010–3622, 2850–3288 and 3440–4741 m, respectively (Fig. 2). The Paleogene sediments depths of the Dorado North, Dorado and Barracuda exploration wells are 2200–3010, 2150–2850 and 2340–3440 m, respectively (Fig. 2).

Geochemical analysis

In this study, the extraction was performed to remove oil-based mud contaminants using the dichloromethane: methanol 9:1 v/v solution. All geochemical analysis was carried out on these solvent extracted samples. According to the Ichron limited technical report (2012), Rock–Eval pyrolysis was performed for 71 samples on ca. 100 mg of powdered samples. Samples were heated from 300 to 550 °C in a helium atmosphere, according to standard procedures. This analysis provides the following measured parameters including Tmax (the temperature of maximum pyrolysis peak at S 2, °C), S 1 (the amount of naturally generated hydrocarbons or the free hydrocarbons, mg HC/g rock), and S 2 (the amount of hydrocarbons produced during pyrolysis, mg HC/g rock). The measured parameters were used to calculate standard geochemical proxies such as hydrogen index (HI), oxygen index (OI) and production index (PI) based on the literature (e.g. Espitalié et al. 1977; Tissot et al. 1980, 1987; Peters and Cassa 1994).

Vitrinite reflectance (Ro%) was measured on selected 45 manually crushed samples at EGS-Ploration laboratory based on procedure mentioned in the Ichron limited technical report (2012). Ro determination was performed under oil immersion (n e 1.517, at 23 °C) of incident white light (546 nm) with a Zeiss Standard Universal research microscope-photometer system (MPM01 K). Samples were calibrated against certified standards of 0.413, 0.506, 0.917, 1.025, 1.817 and 3.256%.

Basin modelling

Kinetic models of the Mannar Basin were generated using actual lithostratigraphic and geochemical data together with burial model and geothermal properties (the standard rifting heat flow) using the software package of Basin Mod 1-D at Shimane University, Japan. In detail, standard burial history model was initially prepared using age and present thickness of the each sedimentary facies. Actual lithologies were determined by mixing the percentages of the default compositions.

Similarly, kerogen types (organofacies) were defined for each sedimentary facies considering the mixing of standard Type I, Type II and Type III kerogen based on Rock–Eval pyrolysis data. Moreover, geochemical data such as total organic carbon, hydrogen index, oxygen index, Tmax and vitrinite reflectance were manually entered for the each sedimentary facies. Therefore, geochemical data can be used to edit kinetic window with reference to maturity parameters. For example, transformation ratio (i.e. the ratio of hydrocarbons generated to the genetic potential) depends on kerogen types and maturity. In contrast, kinetic model qualitatively predicts multiple components of oil and gas generation from different kerogen types. Basin Mod 1-D software consists of default kinetic parameters for the standard Type I, Type II and Type III kerogen. The kinetic parameters for the mixed kerogen types can be derived from the default values of Type I, Type II and Type III kerogen. In addition, these kinetic parameters include reaction fraction (percentage of kerogen with specific activation energy), activation energy (energy required for bond rupture) and Arrhenius constant/frequency factor (frequency with a certain reaction takes place).

According to the literature, standard rifting heat flow was used as the most applicable method for estimating paleo-thermal history of the Mannar Basin (e.g. Ratnayake and Sampei 2015b). Therefore, these simplified kinetic models were used to evaluate thermal history and timing of hydrocarbon generation in the Mannar Basin.

Results and discussion

Organic richness and kerogen type

Total organic carbon (TOC) is a fundamental proxy to identify organic matter richness in sediments and sedimentary rocks (e.g. Tissot and Welte 1978; Jiang et al. 2015; Mani et al. 2015; Ratnayake et al. 2017b). TOC values range from 0.55 to 2.10 wt% with an average of 1.16 ± 0.39 wt% (Table 1). Organic richness is higher in the Cretaceous calcareous mudstones (averages of 1.39 wt% in Dorado and 1.37 wt% in Barracuda) than in the Paleogene calcareous silty/sandy mudstones (averages of 1.19 wt% in Dorado and 0.87 wt% in Barracuda; Table 1). Similarly, total hydrocarbon potential (amount of naturally generated hydrocarbons or the free hydrocarbons of S 1 and amount of hydrocarbons produced during pyrolysis of S 2) is also higher in the Cretaceous sediments (averages of 3.97 mg HC/g rock in Dorado and 5.23 mg HC/g rock in Barracuda) than in the Paleogene sediments (averages of 3.88 mg HC/g rock in Dorado and 2.24 mg HC/g rock in Barracuda; Table 1 and Fig. 3). Therefore, TOC has a good correlation with total hydrocarbon potential in analysed sediments (Fig. 4). In addition, the relationship between TOC and the amount of hydrocarbon yield from cracked kerogen (S 2, mg HC/g rock) can be used to estimate the generation potential of source rocks (Peters 1986; Langford and Blanc-Valleron 1990; Peters and Cassa 1994; Hakimi et al. 2010). S 2 values vary between 0.66 and 9.01 mg HC/g rock with an average of 3.09 ± 1.86 mg HC/g rock (Table 1). In general, a significant amount of the analysed samples recorded more than 1.0 wt% of TOC, and more than 4 mg HC/g rock of S 2 yield in Rock–Eval pyrolysis. Consequently, these results indicate fair to good source rock generative potential in the representative stratigraphic units (Fig. 5).
Table 1

Rock–Eval pyrolysis and vitrinite reflectance (Ro) data from the Dorado North, Dorado, and Barracuda exploration wells in the Mannar Basin

Exploration well

Depth (m)

Reference no.

TOC (%)

Rock–Eval pyrolysis

Vitrinite reflectance

S 1

S 2

S 1 + S 2

S 3

HI

OI

MI

PI

Tmax

Ro (%)

SD

Counts

Dorado North

3155

2643-2

0.74

1.66

4.09

5.75

1.22

553

165

2.24

0.29

377

   

Dorado North

3165

2643-3

0.67

0.10

0.98

1.08

0.34

146

51

0.15

0.09

419

   

Dorado North

3180

2643-5

0.78

0.40

3.67

4.07

0.60

471

77

0.51

0.10

412

   

Dorado North

3190

2643-6

1.09

1.01

6.99

8.00

0.78

641

72

0.93

0.13

398

0.82

0.05

12

Dorado North

3295

2643-15

0.55

1.20

4.32

5.52

0.90

785

164

2.18

0.22

399

   

Dorado North

3520

2643-21

0.88

0.21

1.98

2.19

0.39

225

44

0.24

0.09

433

   

Dorado North

3535

2643-22

0.90

0.60

2.67

3.27

0.43

297

48

0.67

0.18

419

0.58

0.06

18

Dorado North

3550

2643-23

1.31

1.01

5.54

6.55

0.79

423

60

0.77

0.15

423

0.61

0.03

20

Dorado North

3565

2643-24

1.09

0.45

3.09

3.54

0.34

283

31

0.41

0.13

425

0.73

0.05

20

Dorado North

3580

2643-25

0.78

0.09

0.91

1.00

0.60

117

77

0.12

0.09

426

   

Dorado North

3590

2643-26

0.95

0.23

3.66

3.89

0.81

385

85

0.24

0.06

427

0.83

0.04

11

Dorado North

3605

2643-27

0.91

0.10

3.01

3.11

0.71

331

78

0.11

0.03

424

0.77

0.05

11

Dorado North

3615

2643-28

1.11

0.61

5.45

6.06

0.88

491

79

0.55

0.10

427

0.90

0.07

10

Average (Cretaceous)

0.90

0.59

3.57

4.16

0.68

396

79

0.70

0.13

416

0.75

0.05

15

Dorado

2210

2579-5

1.13

0.78

3.59

4.37

1.07

318

95

0.69

0.18

419

0.26

0.01

5

Dorado

2270

2579-9

0.99

0.55

2.31

2.86

0.69

233

70

0.56

0.19

415

0.31

0.02

6

Dorado

2340

2579-13

1.10

0.49

3.23

3.72

0.77

294

70

0.45

0.13

412

0.38

0.04

6

Dorado

2510

2579-16

1.16

0.61

3.67

4.28

0.67

316

58

0.53

0.14

415

0.41

0.02

7

Dorado

2645

2580-10

1.36

0.87

2.78

3.65

0.59

204

43

0.64

0.24

426

0.42

0.04

9

Dorado

2715

2580-13

1.34

0.77

3.19

3.96

0.65

238

49

0.57

0.19

426

0.47

0.03

8

Dorado

2785

2580-17

1.28

2.45

1.87

4.32

0.45

146

35

1.91

0.57

422

0.52

0.04

7

Dorado

2890

2580-20

1.25

2.33

2.84

5.17

0.88

227

70

1.86

0.45

420

0.55

0.05

7

Dorado

2905

2580-21

1.20

1.11

3.01

4.12

0.56

251

47

0.93

0.27

422

0.69

0.01

2

Dorado

2920

2580-22

1.31

1.44

4.02

5.46

0.88

307

67

1.10

0.26

421

0.56

0.05

5

Dorado

2935

2580-23

1.19

0.98

2.34

3.32

1.89

197

159

0.82

0.30

419

0.64

0.04

4

Dorado

2950

2580-24

1.56

1.77

2.89

4.66

0.77

185

49

1.13

0.38

399

0.68

0.03

4

Dorado

2965

2580-25

1.49

2.27

2.62

4.89

0.67

176

45

1.52

0.46

336

0.69

0.03

6

Dorado

2980

2580-26

1.52

3.53

2.79

6.32

0.85

184

56

2.32

0.56

332

0.73

0.07

7

Dorado

2995

2580-27

1.67

1.98

4.01

5.99

0.79

240

47

1.19

0.33

412

0.68

0.05

2

Dorado

3010

2580-28

1.32

0.34

1.89

2.23

0.67

143

51

0.26

0.15

442

0.83

0.03

3

Dorado

3025

2580-29

1.19

0.29

2.11

2.40

0.77

177

65

0.24

0.12

440

0.69

0.06

4

Dorado

3035

2580-30

1.67

0.45

3.01

3.46

0.80

180

48

0.27

0.13

439

0.93

0.07

5

Dorado

3090

2580-31

1.31

0.61

2.09

2.70

0.78

160

60

0.47

0.23

441

0.94

0.07

7

Dorado

3095

2580-32

1.18

0.19

1.34

1.53

0.61

114

52

0.16

0.12

446

   

Dorado

3100

2580-33

0.99

0.32

0.98

1.30

0.50

99

51

0.32

0.25

444

   

Dorado

3115

2580-34

1.77

0.22

2.98

3.20

0.71

168

40

0.12

0.07

451

0.91

0.03

6

Dorado

3125

2580-35

2.02

0.43

3.08

3.51

0.50

152

25

0.21

0.12

456

1.12

0.07

6

Dorado

3135

2580-36

1.89

2.44

3.31

5.75

0.56

175

30

1.29

0.42

412

0.95

0.05

5

Dorado

3142.5

2580-43

1.04

6.05

3.95

10.00

0.26

380

25

5.82

0.61

385

0.97

0.05

6

Dorado

3145

2580-37

0.87

0.29

0.67

0.96

0.51

77

59

0.33

0.30

450

1.07

0.06

5

Dorado

3150

2580-38

1.45

0.49

1.99

2.48

0.45

137

31

0.34

0.20

447

1.14

0.03

3

Average (total)

1.34

1.26

2.69

3.95

0.71

203

55

0.97

0.27

420

0.70

0.04

5

Average (Paleogene)

1.19

0.93

2.95

3.88

0.70

250

60

0.76

0.23

419

0.40

0.03

7

Average (Cretaceous)

1.39

1.38

2.60

3.97

0.72

186

54

1.04

0.29

421

0.82

0.05

5

Barracuda

2370

2615-8

0.56

0.10

1.10

1.20

0.45

196

80

0.18

0.09

422

   

Barracuda

2430

2615-10

0.74

0.12

1.41

1.53

0.88

191

119

0.16

0.08

420

   

Barracuda

2580

2615-15

0.61

0.20

0.71

0.91

0.67

116

110

0.33

0.22

411

   

Barracuda

2605

2615-16

0.80

0.12

1.01

1.13

0.77

126

96

0.15

0.11

421

   

Barracuda

2690

2615-19

1.01

0.11

2.11

2.22

0.56

209

55

0.11

0.05

427

   

Barracuda

2715

2615-20

0.78

0.20

1.98

2.18

1.01

254

129

0.26

0.09

424

   

Barracuda

2745

2615-21

0.70

0.22

2.34

2.56

0.70

334

100

0.31

0.09

403

   

Barracuda

2780

2615-22

0.56

0.11

0.98

1.09

0.61

175

109

0.20

0.10

419

   

Barracuda

2820

2615-23

0.99

0.23

0.87

1.10

0.67

88

68

0.23

0.21

413

   

Barracuda

2925

2615-26

0.65

0.10

0.78

0.88

0.71

120

109

0.15

0.11

420

   

Barracuda

3090

2615-32

1.01

0.35

3.87

4.22

1.01

383

100

0.35

0.08

427

0.55

0.05

14

Barracuda

3280

2615-38

0.87

0.32

0.81

1.13

0.66

93

76

0.37

0.28

388

   

Barracuda

3315

2615-39

1.10

0.21

3.44

3.65

1.00

313

91

0.19

0.06

420

0.65

0.05

15

Barracuda

3340

2615-40

0.89

0.30

2.09

2.39

0.67

235

75

0.34

0.13

427

   

Barracuda

3370

2615-41

1.23

0.60

2.78

3.38

0.81

226

66

0.49

0.18

430

0.66

0.04

14

Barracuda

3400

2615-42

1.34

0.34

4.09

4.43

0.90

305

67

0.25

0.08

428

   

Barracuda

3435

2615-43

1.03

0.56

3.44

4.00

0.34

334

33

0.54

0.14

431

0.68

0.04

7

Barracuda

3830

2615-45

0.77

0.12

0.80

0.92

0.79

104

103

0.16

0.13

430

   

Barracuda

3835

2615-46

0.80

0.12

1.34

1.46

1.01

168

126

0.15

0.08

427

   

Barracuda

4306.5

2615-66

0.61

0.08

0.66

0.74

0.81

108

133

0.13

0.11

436

   

Barracuda

4325

2615-49

1.56

0.56

6.50

7.06

0.70

417

45

0.36

0.08

433

0.88

0.05

14

Barracuda

4345

2615-50

1.43

0.71

5.98

6.69

0.87

418

61

0.50

0.11

434

0.94

0.06

10

Barracuda

4380

2615-51

1.89

0.66

7.01

7.67

0.66

371

35

0.35

0.09

433

1.02

0.03

15

Barracuda

4405

2615-52

1.44

0.43

6.22

6.65

0.98

432

68

0.30

0.06

436

1.09

0.05

14

Barracuda

4425

2615-53

1.23

0.30

4.77

5.07

1.01

388

82

0.24

0.06

434

1.08

0.04

13

Barracuda

4485

2615-56

0.65

0.16

0.78

0.94

0.71

120

109

0.25

0.11

420

   

Barracuda

4640

2615-61

1.80

0.98

6.77

7.75

0.85

376

47

0.54

0.13

423

1.11

0.05

11

Barracuda

4660

2615-62

2.04

1.20

9.01

10.21

1.22

442

60

0.59

0.12

428

1.27

0.03

13

Barracuda

4685

2615-63

1.56

0.34

4.89

5.23

0.83

313

53

0.22

0.07

434

1.26

0.05

6

Barracuda

4705

2615-64

2.10

0.34

5.44

5.78

0.90

259

43

0.16

0.06

433

1.49

0.03

7

Barracuda

4725

2615-65

1.33

0.78

6.21

6.99

1.12

467

84

0.59

0.11

437

   

Average (total)

1.10

0.35

3.23

3.59

0.80

261

82

0.29

0.11

425

0.98

0.04

12

Average (Paleogene)

0.87

0.25

1.99

2.24

0.73

218

87

0.27

0.12

419

0.64

0.05

13

Average (Cretaceous)

1.37

0.48

4.74

5.23

0.89

313

75

0.32

0.09

431

1.13

0.04

11

Total hydrocarbon potential = (S 1 + S 2), hydrogen index (HI = S 2/TOC × 100, mg HC/g TOC), oxygen index (OI = S 3/TOC × 100, mg HC/g TOC), migration index (MI = S 1/TOC), and production index (PI = S 1/S 1 + S 2)

Fig. 3

Vertical variation in total hydrocarbon potential in the analysed samples. Lower grey parts show the Cretaceous sediments

Fig. 4

Relationship between total hydrocarbon potential (S 1 + S 2) and total organic carbon [TOC (%)]

Fig. 5

Plot of S 2 versus TOC (%) for determining organic richness of potential source rock beds

The modified Van Krevelen diagram of hydrogen index (HI) versus oxygen index (OI) is regarded as one of the reliable ways to recognise the dominant kerogen type of organic matter (Tissot and Welte 1978; Tissot et al. 1980, 1987). HI values vary between 77 and 785 mg HC/g TOC with an average of 263 ± 139 mg HC/g TOC (Table 1). OI values range between 25 and 165 mg HC/g TOC with an average of 71 ± 32 mg HC/g TOC (Table 1). In general, it suggests large variations in an origin of organic matter compositions and oxic/anoxic depositional conditions. However, most of the studied samples plotted in the zone of mixed Types II–III (oil and gas prone) and Type III (gas prone) kerogen in the potential source rocks (Fig. 6). Therefore, gas generation can be mainly expected under the conditions of adequate burial and heating. On the other hand, the mixed Type II–III kerogen can also suggest deposition of either terrigenous and marine organic matter or poor preservation of Type I and II kerogen under strongly oxidised conditions.
Fig. 6

Modified van Krevelen diagram based on hydrogen index (HI) versus oxygen index (OI), showing kerogen type

TOC has a negative correlation with OI values (Fig. 7). However, original geochemical fingerprints can still remain under the influence of low OI values (< 200 mg HC/g TOC) (Arab et al. 2015). Therefore, the majority of samples consist of mixed Type II–III kerogen rather than biodegraded or oxidised Type I or Type II kerogen. In contrast, HI values were apparently increased in few samples such as in Dorado North 3155, 3190 and 3295 m (Table 1 and Fig. 6). This anomaly can probably indicate contamination with remained drilling mud/oil and/or migrated hydrocarbon in reservoir rocks. In addition, it is followed by higher migration index (S 1/TOC ratio, greater than 1.5; Table 1). Previous studies suggested that heavy hydrocarbons such as resins and asphaltenes can be realised at the S 2 peak with the same temperature range as for kerogen pyrolysis (Delvaux et al. 1990).
Fig. 7

Relationship between oxygen index (OI) and TOC (%) in offshore sediments of the Mannar Basin

The ratio of the amount of hydrocarbon produced during pyrolysis (S 2) and the amount of carbon dioxide produced during pyrolysis (S 3) versus organic richness are directly related to type and quantity of potential hydrocarbon. Therefore, Fig. 8 clearly indicates deposition of gas-prone to oil-prone mixed organic matter in fair to good source rocks.
Fig. 8

Plot of S 2/S 3 versus TOC (%) indicates the potential of hydrocarbon generation and type

Thermal maturity and hydrocarbon generation potential

The vitrinite reflectance and Tmax values of the Mannar Basin range from 0.26 to 1.49% and 332 to 456 °C, respectively (Table 1). It suggests the existence of both immature and mature sediments. Tmax and Ro values normally increase with temperature (Sykes and Snowdon 2002). In this study, a cross-plot of Tmax to Ro can probably indicate oxidised pseudo-vitrinite particles (Fig. 9). Similarly, graphite was also identified as pseudo-vitrinite particles (Ro > 3.54%) in the Mannar Basin. These pseudo-vitrinite particles experienced higher thermal activities before erosion and deposition into a new geological cycle (Ratnayake and Sampei 2015b). In general, Tmax values are high in the Late Cretaceous sediments of the Mannar Basin (Fig. 9), as a result of increasing age and burial depth of sediments.
Fig. 9

Cross-plot of Rock–Eval Tmax and vitrinite reflectance (Ro) data of the Mannar Basin

The value of ca. 0.55 Ro% is normally recognised as a beginning level of oil generation window (Tissot and Welte 1978; Ryu 2008). Consequently, most of the analysed samples (except the Paleogene sediments in the Dorado well) have achieved oil to wet gas windows (Fig. 9). In addition, Ro (range from 0.26 to 0.52%) and Tmax (range from 412 to 426 °C) values of the analysed Paleogene sediments in the Dorado well are plotted in the immature zone (Table 1). Similarly, Tmax values (range from 388 to 431 °C) are lower in the Paleogene sediments of the Barracuda well (Table 1). Therefore, these younger and relatively shallow burial Cenozoic sedimentary sequences can be regarded as immature to early mature for hydrocarbon generation. In addition, maturity of non-coaly sedimentary organic matter can also be expressed by the production index (PI) that is partially related to hydrocarbon expulsion (Fig. 10). PI values range from 0.03 to 0.61 (Table 1). It shows both early mature to mature sediments, as the value of 0.05 indicates a boundary of immature and mature organic matter (Adegoke et al. 2015; Du et al. 2015).
Fig. 10

Plot of Production Index (PI) versus vitrinite reflectance (Ro) data of the Mannar Basin

Similarly, HI versus Ro (%) and Tmax plots can be widely used to determine types of generated hydrocarbon (i.e. oil and gas or mixed) from sedimentary organic matter (Fig. 11). Most of the samples are plotted as Type II and Type III kerogen, although very few immature sediment samples are plotted between Type I and Type II kerogen from possibly contaminated cuttings (Fig. 11b). According to geochemical characteristics of cutting samples, the thermal maturity zone of the Mannar Basin is mainly associated with liquid hydrocarbons from the Late Cretaceous sediments of the Dorado and Barracuda wells. It suggests that thermal transformation is not sufficient to generate gas from available oil–gas prone (Type II–III) and gas prone (Type III) kerogen (Fig. 11b). In summary, the Late Cretaceous sediments are generally characterised by relatively high potential for oil generation (Fig. 11b). However, the Paleogene sediments are characterised by low potential for hydrocarbon generation (Fig. 11b).
Fig. 11

Distribution of HI versus a vitrinite reflectance (Ro) and b Rock–Eval Tmax showing kerogen type and maturity of potential source rock beds in the Mannar Basin

Geochemical data can also be assessed to reconstruct geothermal history with respect to the geological evolution of the particular basin. Rifting basins are usually distinguished by a relatively high thermal capacity due to lithospheric thinning (McKenzie 1978; Abbassi et al. 2014). The heat flow variations in rifting basins depend on nature and thickness of the lithosphere as a function of the geodynamic evolution of the particular basin. The Mannar Basin and surrounding oceanic basins record extensive igneous layers during the Late Cretaceous under the influence of rifting processes (e.g. Gombos et al. 1995; Galushkin 2015; Varma et al. 2015; Premarathne et al. 2016). However, the increment of Tmax values falls within a narrow range during the Cretaceous (Fig. 9). It suggests slightly higher palaeogeothermal gradient in the northeast margin of the basin during the Late Cretaceous. Therefore, the heat flow amplitude may partially support to generate gasses from the drilled Late Cretaceous sediments (Fig. 11).

Basin modelling

The kinetic model describes the timing of petroleum generation and expulsion via thermal conversion of kerogen in the Late Cretaceous sediments based on Rock–Eval pyrolysis data (Fig. 12). For example, transformation ratio and cumulative hydrocarbon generation depend on kerogen types (e.g. HI values) and maturity (Tmax). Simulating results show that the Dorado North, Dorado and Barracuda wells predominantly started the in situ oil and gas generation windows at ca. 40, 20 and 60 Ma, respectively (Fig. 12). The Barracuda well acquired peak generation during the Neogene Period (ca. 20 Ma, Fig. 12c). The in situ oil and gas generation rates of the Barracuda well are about 120 mg/g TOC and 190 mg/g TOC, respectively (Fig. 12c). Thus, it suggests nearly 1:1.6 oil to gas generation ratio. However, the Dorado North and Dorado wells have not yet reached to its peak generation for analysed samples (Fig. 12a, b), may be due to structural complexity of terrestrial kerogen. In general, cellulose- and lignin-rich terrestrial kerogen enhances hydrocarbon generative temperature of sedimentary organic matter (e.g. Tissot et al. 1987; Pepper and Corvi 1995; Hakimi et al. 2010). Finally, geochemical maturity proxies and model results indicate that the most likely higher matured rocks for gas expulsion can be probably located below the drilled depths of the exploration wells. However, these predicted models strongly depend on reconstructed paleo-heat flow properties.
Fig. 12

Simplified compositional kinetic models based on standard rifting heat flows for a Dorado North, b Dorado, and c Barracuda exploration wells in the Mannar Basin

Conclusion

Organic richness is higher in the Cretaceous calcareous mudstones than in the Paleogene calcareous silty/sandy mudstones in the Mannar Basin. TOC contents have a good correlation with total hydrocarbon potential in analysed sediments. TOC showed a negative correlation with OI, indicating that oxic marine bottom condition controlled TOC contents in this basin. Mixed Type II–III and Type III kerogen were predominantly recorded in the Late Cretaceous to Paleogene offshore sediments. Consequently, studied stratigraphic units in the Mannar Basin are more capable of generating gaseous than liquid hydrocarbons.

Tmax values are generally consistent with vitrinite reflectance data excluding possible pseudo-vitrinite particles. Tmax values show that the Late Cretaceous sediments of the Dorado (average = 421 ± 35 °C) and Barracuda (average = 431 ± 5 °C) wells have reached to mature stage for oil window. Therefore, it indicates incomplete thermal conversion of oil–gas prone (Type II–III) and gas prone (Type III) kerogen to wet gas zone. 1-D thermal modelling shows that onset of hydrocarbon generation started in the Early Paleogene for the Late Cretaceous sediments of the deeper Barracuda well. It reached the maximum in situ oil and gas generation at about 20 Ma. The amount of cumulative hydrocarbon generation can strongly depend on compositions and concentrations of Type II–III and Type III kerogen.

Notes

Acknowledgements

The authors wish to greatly acknowledge the Director General Saliya Wickramasuriya of Petroleum Resources Development Secretariat (PRDS), Sri Lanka, for supplying the cuttings samples and necessary permission to publish this article.

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© The Author(s) 2017

Open AccessThis article is distributed under the terms of the Creative Commons Attribution 4.0 International License (http://creativecommons.org/licenses/by/4.0/), which permits unrestricted use, distribution, and reproduction in any medium, provided you give appropriate credit to the original author(s) and the source, provide a link to the Creative Commons license, and indicate if changes were made.

Authors and Affiliations

  • Amila Sandaruwan Ratnayake
    • 1
    • 2
  • Chaminda Wimal Kularathne
    • 3
  • Yoshikazu Sampei
    • 1
  1. 1.Department of Geoscience, Faculty of Science and EngineeringShimane UniversityMatsueJapan
  2. 2.Faculty of Science and TechnologyUva Wellassa UniversityBadullaSri Lanka
  3. 3.Petroleum Resources Development Secretariat (PRDS)Colombo 01Sri Lanka

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