Shale Oil Assessment for the Songliao Basin, Northeastern China

Article pubs.acs.org/EF

Shale Oil Assessment for the Songliao Basin, Northeastern China, Using Oil Generation−Sorption Method Huairen Cao,†,‡ Yan-Rong Zou,*,† Yan Lei,†,‡ Dangpeng Xi,§ Xiaoqiao Wan,§ and Ping’an Peng*,†,‡ †

State Key Laboratory of Organic Geochemistry, Guangzhou Institute of Geochemistry, Chinese Academy of Science, Guangzhou 510640, China ‡ University of Chinese Academy of Sciences, Beijing 100039, China § China University of Geosciences, Beijing 100083, China ABSTRACT: This study was performed in order to evaluate shale oil in the first member of the Qingshankou formation (K2qn1) in the Songliao basin in northeastern China. The evaluation was carried out using immature type I kerogen kinetics in a closed system, two wells drilled into oil prone source rocks, in order to apply Rock-Eval, mineral composition and residual hydrocarbon analysis, and the hydrocarbon sorption method. The “oil windows” for K2qn1 in mudstone and shale wells range from 0.6% to 1.05%, with maximum hydrocarbon generation at around 420 mg of hydrocarbon per gram of total organic carbon. In addition, the brittle mineral contents of K2qn1 conform to the requirements for industrial oilfield development and exploitation. Our results demonstrate that there is clear potential for shale oil exploration in the K2qn1; a highly potential zone is defined as low risk at burial depths of greater than 2065 m for well H14, while well X83 exhibits relatively discrete depth based on oil saturation and production indexes as well as free hydrocarbon content. In contrast to oil saturation index, the generation− sorption method is reasonable to assess free oil in organic-lean rocks. Restricted maturity conditions of free oil are represented by Easy%Ro values of 0.8−0.97% based on three sets of parametersgeneration, adsorption, and residual oilfor K2qn1 mudstones and shales in the Songliao basin. rocks have been considered to be hot targets for exploration,27 closely related to shale oil content.25 Therefore, for shale oil evaluation, the sorption or residual oil in source rock should receive the same attention as oil generation. Two significant geochemical parameters, chloroform bitumen “A” and RockEval S1, have also been suggested as key criteria for the assessment of shale oil content.27 Mobile hydrocarbon content is residual hydrocarbon minus adsorbed hydrocarbon, such as oil sorption on surfaces of quartz and clay minerals.28−30 Geochemical parameters, including the oil saturation index (OSI), production index (PI), and sorption potential (Sp), are used to predict the presence of mobile oil resources and provide guidance to shale oil exploration.5,10,31,32 Therefore, the shale oil enrichment in the source rock depends on the volume of hydrocarbon generation, residual hydrocarbon, and sorption hydrocarbon potential. As studied, an intermittent oil crossover in the Bakken shales indicates active generation and expulsion.5 The objective of this study is to determine the type I kerogen pyrolysis products and predict the extent of hydrocarbon generation and retention history. Pyrolysis was thus carried out on oil-prone shale kerogen, and the soluble constituents were collected and separated in order to gain an improved understanding of residual and adsorption hydrocarbons. The free hydrocarbon potential and desirable maturity range of mudstones/shales are discussed in terms of shale oil potential.

1. INTRODUCTION An ever-increasing number of unconventional shale gas reservoirs are being explored and exploited in the United States,1−3 but the study of shale oil globally is still in its infancy.4−6 Recent studies have shown that, while shale oil tends to be abundant in marine shales, including the Eagle Ford, Monterey, and Bakken shales,7 it can also be present in lacustrine shales, for example, in the Bohai Bay basin of China.8−10 These discoveries have provided motivation for researchers and energy companies to discover and develop Chinese shale oil resources.3,11 Shale oil has always been understood scientifically as a retention product and is thus an unconventional resource within source rock12 intervals or migrated into juxtaposed or even continuous low-organic carbonates, sands, or silts.5 Oil usually forms as a result of the thermal evolution of kerogen and bitumen in a sedimentary basin.12−15 Indeed, whether the study is on conventional petroleum resources or unconventional oil resources, kerogen is the key source of hydrocarbon generation, undergoing thermal evolution in a sedimentary basin,12−15 and that process can be simulated under experiment with increasing time and temperature.12,15−18 The literature shows that processing of kerogen thermal evolution is generally accompanied by a series of complicated reactions and petroleum products, including liquid compounds and gas yields predicted using a variety of kinetic models.15,19−26 These are commonly described as oil generation of conventional oil or shale oil. Jarvie5 proposed that sorption oil content reached 70−80 mg of oil per gram of total organic content (TOC) retained by organic-rich source rocks, consistent with volumetric solvent swelling results.24 The residual hydrocarbons (HCs) in source © XXXX American Chemical Society

Received: January 10, 2017 Revised: March 16, 2017 Published: March 28, 2017 A

DOI: 10.1021/acs.energyfuels.7b00098 Energy Fuels XXXX, XXX, XXX−XXX

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Energy & Fuels

Figure 1. (a) Geographical location of sample collection sites. (b) Stratigraphic columns in the Songliao basin.

Table 1. Geochemical Parameters of Outcrop Shale Sample in Songliao Basin sample

TOC (%)

Tmax (°C)

S1 (mg/g)

S2 (mg/g)

S3 (mg/g)

HI (mg HC/g TOC)

OI (mg CO2/g TOC)

L

2.38

433

0.16

16.59

0.62

697

26

2. GEOLOGICAL BACKGROUND

structural inversion stage (late Cretaceous). The late Jurassic to early Cretaceous period was characterized by frequent igneous activity in northeastern China;35 this sedimentary succession overlaps the Paleozoic basement in Figure 1b34 and comprises a complete time series of Cretaceous terrestrial sediments. It represented semi-deep to deep lake facies with seawater incursion in the Cretaceous Pale lake based on organic geochemistry and palaeontology evidence.37−39 The k2qn shale is characterized by gray-black and dark gray shales/ mudstones with semi-deep to deep lake facies, forming the important petroleum source rocks in Figure 1b.35 The Daqing oilfield, located in the central part of the Songliao basin, contains two main source rocks, K2n1+2 and K2qn1+2, the subjects of a large number of geological investigations. Cumulative oil production in the Songliao basin has exceeded 2.1 billion tons since the discovery of the first oil well in 1959, the Songji-3 gusher.35 However, the shale oil resource has not received enough attention. Recently, exploration efforts for shale oil have been enhanced.7

The Songliao basin is superposed onto a Paleozoic basement and is the largest Meso-Cenozoic lacustrine sedimentary basin in northeastern China. This basin comprises approximately 260 000 km2 and has a thickness of about 10 000 m.33 The extent of the Songliao basin is approximately equal to that of the present-day Songliao plain, which has a width of 350 km from east to west, and a length of about 750 km from south to north, as shown in Figure 1a.34 The Songliao basin is composed of six first-order tectonic units: the central depression zone, the northeastern uplift zone, the northern plunge zone, the western slope zone, the southwestern uplift zone, and the southeastern uplift zone labeled in Figure 1a.35 Within the basin, the upper Cretaceous sedimentary sequence comprises the Qinshankou (K2qn), Yaojia (K2y), Nenjiang (K2n), Sifangtai (K2s), and Mingshui (K2m) formations, as listed in Figure 1b.36 The basin evolutional history can be subdivided into a fault depression stage (that lasted from the late Jurassic to the early Cretaceous), a sag stage (early to mid Cretaceous), and a B


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Energy & Fuels

3. SAMPLES AND EXPERIMENTS

Table 2. Thermal Pyrolysis Products of L Kerogen at Different Heating Rates

3.1. Samples. Two kinds of shale samples, outcrop and core samples, were collected in this study. The sampling sites are shown in Figure 1a. Outcrop sample (L shale), located at N 44°54′42″ and E 125°39′34″, was collected from lacustrine sediments of the upper Cretaceous Qingshankou formation (91.4−90.4 Ma). The essential geochemical parameters of the L shale are presented in Table 1; the sample contains immaturity Type I kerogen. The shale was crushed into 200 mesh (about 75 μm), and the powder sample was demineralized repeatedly with HCl and HF, cleaned using distilled water, and dried at 70 °C. Finally, the kerogen was isolated for pyrolysis experiments in the gold tube system. A total of 118 Qingshankou formation core samples were collected from wells H14 (2032.5−2081.5 m) and X83 (2051.4−2139.7 m). The two wells are situated on the eastern uplifted side of the Halahai fault zone and at the nose structure of the Qijia sag in the central depression in Figure 1a, respectively. Samples of mudstone and black shale from these wells were used for residual oil analysis; core samples were first cleaned with deionized water and dried at 70 °C before being crushed into powder less than 200 mesh (about 75 μm). These powder samples were then trisected. The first subsample was subject to Soxhlet apparatus extraction with dichloromethane:methanol (v:v = 9:1) for 72 h in order to determine retained oil (chloroform “A”) via quantitative weighing. The other two subsamples were used for RockEval pyrolysis and for X-ray diffraction (XRD) analysis. 3.2. Pyrolysis Experiments. Isolated kerogen pyrolysis was carried out using a system of gold tubes. Samples of 20−120 mg of kerogen were injected into gold tubes (60 mm × 4 mm i.d.) with one end welded, and then the other end was welded under argon gas conditions. The sealed tubes were then put into autoclaves, and about 10 mL volume of water was added to each as a delivery pressure fluid. Two tubes were placed in each autoclave, one for volatiles and the other for liquid hydrocarbon analysis. Pyrolysis experiment was performed under 50 MPa constant pressure, with an error of less than 2 MPa; the temperature of pyrolysis was increased from 30 to 300 °C within 10 h, and then at heating rates of 2 and 20 °C/h, respectively. Target temperatures ranged from 320 to 480 °C to obtain the kinetic parameters and model the oil generation under geological conditions.17,24,40 Last, the autoclave was removed from the heating oven at the set time (temperature) and was quenched in cold water. Pyrolyzed kerogens were extracted in a Soxhlet apparatus using a mixture of dichloromethane and methanol (v:v = 9:1) over 72 h. Quantitative determination of the pyrolysates of the C14+ fraction ws done by weighing (Table 2). The asphaltene was first precipitated from these Soxhlet extractions by n-hexane, and the maltene fraction was further divided into saturated hydrocarbons, aromatic hydrocarbons, and polar fraction via silica gel/Al2O3 adsorption chromatography, eluting with hexane, a mixture of hexane and dichloromethane (1:1), and a mixture of dichloromethane and methanol (v:v = 3:1), respectively. 3.3. Rock-Eval and Mineral Analysis. Rock-Eval pyrolysis was used to determine the oil potential of core samples from wells H14 and X83 using a Rock-Eval VI instrument, which provided information on the quantity, type, and maturity level of organic matter. The chloroform bitumen “A” fraction was quantified via Soxhlet extraction and weighing; data from Rock-Eval pyrolysis and volumes of chloroform bitumen “A” are listed in Table 3. A diagram of hydrogen index (HI) vs Tmax shows that organic matter is characteristic of type I, fair-to-good oil-prone source rocks (Figure 2c,d). The total organic carbon (TOC) contents of mudstones and shales from wells H14 and X83 are within the range 0.38−6.39%, predominantly 1.0−3.0%. Results show that HI varies from 178 to 666 mg HC/g TOC (Table 3), mainly as a result of maturity. Sample mineral compositions were investigated using the following steps: (1) Abundant H2O2 was added to extracted samples to remove insoluble organic matter. (2) Clay minerals with particle diameters less than 2 μm and greater than 10 μm were isolated by using the Stokes sedimentation equation. (3) Isolated material was analyzed using an

C14+ yields (mg/g TOC) T (°C)

saturate

aromatic

resin

asphaltene

320 334.5 349 363.5 378 392.5 407 421.5 436 450.5 465 480

17.2 36.5 66.8 100.5 204.7 268.3 216.5 88.5 47.9 24.6 16.6 10.1

Heating Rate = 2 °C/h 24.6 50.7 3.9 48.0 81.6 6.2 90.6 143.2 15.6 127.7 175.2 32.0 151.8 137.5 49.0 134.0 93.3 72.6 105.8 70.7 42.9 68.1 31.5 25.7 40.3 12.3 4.2 29.1 6.1 2.0 19.0 1.7 0.2 12.9 0 0

320 334.5 349 363.5 378 392.5 407 421.5 436 450.5 465 480

7.3 13.2 24.9 43.8 58.6 106.6 158.2 199.7 261.2 158.6 127.4 97.0

Heating Rate = 20 °C/h 10.5 20.9 1.8 22.1 26.4 3.7 35.4 43.6 6.6 55.3 78.4 15.1 74.5 118.7 26.9 90.8 171 43.1 118.9 117.7 65.3 145.9 72.3 51.7 100.5 48.4 35.1 81.8 28.3 19.6 51.3 9.7 7.2 35.9 2.2 2.2

EasyRo (%) 0.64 0.72 0.79 0.89 1.03 1.18 1.34 1.53 1.76 1.99 2.24 2.50

0.49 0.56 0.63 0.69 0.77 0.84 0.95 1.07 1.24 1.40 1.58 1.78

XRD/XRF-BTX at 40 kV and 30 mA with 2θ = 3−85° under Cu Kα radiation conditions. The mineral compositions of samples are presented in Table 4.

4. RESULTS AND DISCUSSION 4.1. Kinetic Model and Liquid Yields (C14+). As mentioned above, Behar et al.12 documentedthat shale oil, a retention product within source rock, could be scientifically interpreted as pyrolysates from kerogen or “NSOs” with high molecular weight.13,24,41,42 With the aim of assessing shale oil, a low temperature way to model oil generation was designed in this study (Table 2). For a kinetic model, kerogen degradation rates could be generally calculated under laboratory conditions by assuming that they conform to a first-order kinetic law and using the Arrhenius equation.15,19,20 In addition, artificial maturity parameters, called Easy%Ro values,43 were calculated using pyrolysis temperatures and times from the gold tube experiments. In our study, L kerogens were pyrolyzed at different heating rates of 2 and 20 °C/h. The C14+ pyrolysate yields are presented in Table 2; these data show that cumulative yields increased gradually to a maximum with increasing temperature, but then displayed a decreasing trend at high temperatures. Maximum cumulative liquid yields were 517.8 mg/g TOC at 392.5 °C (Easy%Ro = 1.18%) for 2 °C/h heating rate and 469.6 mg/g TOC at 421.5 °C (Easy%Ro = 1.07%) for 20 °C/h heating rate (Table 2). These results are consistent with previous studies; i.e., the C14+ fractions of samples from the Duvernay and Toarcian shales reached maximum yields in the closed system at about 430 and 470 °C, respectively, under a C


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Energy & Fuels Table 3. Geochemical Parameters of Samples from Wells H14 and X83 in Songliao Basin chloroform bitumen “A”

Ro (%)

S2 (mg/g)

Tmax (°C)

HI (mg HC/ g TOC)

saturate (mg/g)

aromatic (mg/g)

resin (mg/g)

bitume (mg/g)

calcd

formation

lithology

TOC (wt%)

S1 (mg/g)

Well H14 1 2032.49

K2qn1

2.58

2.13

11.77

447

455

6.84

0.53

1.46

0.10

0.89

2

2033.85

K2qn1

1.86

1.90

10.82

445

582

5.49

0.51

1.53

0.06

0.85

3

2036.05

K2qn1

1.31

1.03

5.20

442

397

2.94

0.32

0.81

0.04

0.80

4

2038.05

K2qn1

1.69

1.45

9.88

447

426

4.22

0.52

1.04

0.22

0.89

5

2039.15

K2qn1

1.32

0.50

4.56

444

346

2.31

0.29

0.70

0.06

0.83

6

2040.2

K2qn1

1.59

2.06

5.24

442

330

4.40

0.35

0.96

0.36

0.80

7

2041.53

K2qn1

1.12

1.75

4.48

433

400

3.13

0.58

1.04

0.04

0.63

8

2041.95

K2qn1

0.87

1.27

3.31

439

380

2.38

0.39

0.77

0.04

0.74

9

2047.15

K2qn1

1.86

1.57

7.04

444

378

4.24

0.53

1.19

0.03

0.83

10

2048.1

K2qn1

2.03

1.67

8.02

445

395

5.41

0.54

1.36

0.07

0.85

11

2050.85

K2qn1

2.11

1.66

8.47

444

401

4.64

0.62

1.51

0.24

0.83

12

2052.73

K2qn1

3.08

3.18

14.64

446

475

9.28

1.19

1.91

0.16

0.87

13

2054.45

K2qn1

2.14

2.06

9.00

444

421

5.67

0.67

1.61

0.21

0.83

14

2056.45

K2qn1

2.98

2.30

13.77

448

462

6.32

0.71

1.60

0.08

0.90

15

2059.02

K2qn1

1.69

1.47

10.81

447

640

3.97

0.58

1.14

0.05

0.89

16

2060.78

K2qn1

1.47

1.45

9.89

448

586

3.62

0.68

0.74

0.06

0.90

17

2062.38

1

K2qn

1.48

0.75

6.00

447

405

1.93

0.42

0.77

0.08

0.89

18

2065.1

K2qn1

2.67

2.71

15.20

444

569

6.07

0.77

1.10

0.06

0.83

19

2066.06

K2qn1

3.27

3.71

17.09

449

523

8.61

0.96

2.41

0.24

0.92

20

2067.11

K2qn1

2.84

2.71

14.85

447

523

6.68

1.03

1.50

0.09

0.89

21

2068.3

K2qn1

2.65

3.48

13.55

445

511

7.86

0.76

1.48

0.07

0.85

22

2070.77

K2qn1

1.70

2.05

6.95

441

409

5.25

0.49

1.01

0.07

0.78

23

2074.86

K2qn1

4.04

4.62

18.36

451

454

9.82

1.16

2.21

0.14

0.96

24

2076.22

K2qn1

0.38

0.26

0.94

435

247

0.49

0.20

0.25

0.05

0.67

25

2077.7

K2qn1

2.64

3.99

15.78

449

598

8.75

0.79

1.86

0.09

0.92

26

2079.63

K2qn1

2.13

3.51

14.19

449

666

8.64

0.74

1.78

0.05

0.92

27

2081.09

K2qn1

2.90

3.74

13.87

449

477

8.95

0.94

1.71

0.05

0.92

28

2081.5

K2qn1

black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone

2.22

2.73

10.39

445

468

6.64

0.59

1.60

0.07

0.85

black mudstone black mudstone black mudstone

1.27

0.90

2.25

436

178

1.68

0.56

0.86

0.07

0.69

1.18

1.94

7.21

443

611

3.85

0.48

1.12

0.32

0.81

1.99

1.33

10.73

448

539

2.47

0.68

1.20

0.12

0.90

sample

depth (m)

Well X83 1 2051.44

K2qn1 1

2

2052.99

K2qn

3

2054.76

K2qn1

D

measd

0.82

0.88

0.75

0.82

0.85


Article

Energy & Fuels Table 3. continued chloroform bitumen “A”

Ro (%)

S2 (mg/g)

Tmax (°C)

HI (mg HC/ g TOC)

saturate (mg/g)

aromatic (mg/g)

resin (mg/g)

bitume (mg/g)

calcd

formation

lithology

TOC (wt%)

S1 (mg/g)

Well X83 4 2055.22

K2qn1

2.47

1.06

10.93

451

443

2.75

0.59

1.00

0.07

0.96

5

2057.43

K2qn1

1.26

0.86

7.19

447

571

1.71

0.40

0.74

0.12

0.89

6

2058.28

K2qn1

1.43

1.35

9.01

446

630

2.95

0.58

1.15

0.09

0.87

7

2059.51

K2qn1

2.74

1.16

12.05

449

440

2.49

0.71

1.01

0.12

0.92

8

2060.37

K2qn1

1.76

0.84

9.49

450

539

1.43

0.28

0.55

0.07

0.94

9

2061.41

K2qn1

1.95

1.63

9.87

451

506

2.11

0.56

0.89

0.10

0.96

10

2063.58

K2qn1

1.18

0.89

4.42

444

375

2.48

0.29

0.77

0.07

0.83

11

2064.61

K2qn1

1.77

1.46

9.73

449

550

2.82

0.69

1.31

0.14

0.92

12

2065.69

K2qn1

1.72

1.28

10.25

447

596

2.90

0.63

1.21

0.14

0.89

13

2066.16

K2qn1

1.85

1.22

10.14

446

548

2.09

0.55

0.97

0.11

0.87

14

2066.78

K2qn1

2.16

1.55

8.89

443

412

5.75

0.77

1.16

0.04

0.81

15

2068.32

K2qn1

1.67

0.57

8.25

448

494

0.98

0.48

0.78

0.11

0.90

16

2069.35

K2qn1

1.88

0.93

10.15

449

540

1.93

0.65

1.00

0.15

0.92

17

2070.48

K2qn1

1.21

0.51

6.40

449

529

0.85

0.30

0.55

0.08

0.92

18

2071.34

K2qn1

1.39

0.65

4.16

444

299

1.44

0.16

0.67

0.12

0.83

19

2072.37

K2qn1

1.36

0.86

6.43

444

473

1.87

0.56

1.05

0.09

0.83

20

2072.62

1

K2qn

1.41

0.89

7.55

447

535

2.26

0.51

0.57

0.12

0.89

21

2074.46

K2qn1

2.05

0.97

11.46

449

559

1.99

0.72

1.39

0.10

0.92

22

2075.05

K2qn1

2.91

0.93

12.04

453

414

1.74

0.63

0.88

0.11

0.99

23

2076.3

K2qn1

2.19

0.95

9.77

446

561

1.89

0.68

1.39

0.09

0.87

24

2077.2

K2qn1

2.61

1.33

14.15

449

542

2.93

0.90

1.57

0.11

0.92

25

2078.24

K2qn1

1.67

1.22

9.61

443

575

3.63

0.94

1.44

0.12

0.81

26

2079.26

K2qn1

2.32

0.74

8.55

447

369

2.50

0.57

1.11

0.06

0.89

27

2080.23

K2qn1

1.58

0.91

7.82

448

495

1.75

0.51

0.80

0.14

0.90

28

2081.34

K2qn1

1.91

1.24

10.43

449

546

2.78

0.74

1.08

0.16

0.92

29

2082.03

K2qn1

1.88

1.45

11.28

447

600

3.32

0.68

1.20

0.08

0.89

30

2083.29

K2qn1

2.42

0.97

10.70

449

442

3.45

0.68

1.23

0.07

0.92

31

2083.72

K2qn1

1.50

1.15

9.70

444

647

3.27

0.68

1.23

0.06

0.83

32

2084.81

K2qn1

1.65

0.96

9.97

446

604

2.45

0.73

1.02

0.10

0.87

33

2085.97

K2qn1

1.66

0.65

10.46

452

630

1.58

0.39

0.64

0.07

0.98

34

2087

K2qn1

black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone

3.35

0.92

15.99

452

477

2.82

0.73

0.88

0.07

0.98

2.04

0.95

11.48

449

563

2.42

0.46

0.96

0.07

0.92

1.89

0.82

11.58

452

613

2.00

0.57

0.81

0.08

0.98

sample

depth (m)

1

35

2087.97

K2qn

36

2088.51

K2qn1

E

measd

0.92

0.91

0.94


Article


Ro (%)

S2 (mg/g)

Tmax (°C)

HI (mg HC/ g TOC)

saturate (mg/g)

aromatic (mg/g)

resin (mg/g)

bitume (mg/g)

calcd

formation

lithology

TOC (wt%)

S1 (mg/g)

Well X83 37 2089.62

K2qn1

1.52

0.72

8.38

449

551

2.05

0.41

0.54

0.11

0.92

38

2089.82

K2qn1

2.03

0.81

8.56

447

422

2.53

0.46

0.55

0.09

0.89

39

2091.79

K2qn1

2.56

1.01

13.47

452

526

1.78

0.55

0.74

0.07

0.98

40

2092.79

K2qn1

1.38

0.91

8.61

448

624

2.01

0.49

0.77

0.08

0.90

41

2093.72

K2qn1

1.73

0.66

10.65

450

616

1.11

0.35

0.44

0.09

0.94

42

2094.72

K2qn1

2.24

0.61

10.67

450

476

2.03

0.27

0.95

0.07

0.94

43

2095.47

K2qn1

1.72

0.99

10.50

448

610

1.27

0.31

0.51

0.03

0.90

44

2096.17

K2qn1

1.92

1.33

11.42

448

595

2.72

0.56

1.07

0.05

0.90

45

2097.67

K2qn1

1.31

0.94

7.90

443

603

2.55

0.50

0.83

0.07

0.81

46

2098.57

K2qn1

1.87

1.17

9.04

441

483

3.37

0.70

1.17

0.07

0.78

47

2099.62

K2qn1

2.65

1.12

14.13

451

533

2.52

0.41

0.70

0.08

0.96

48

2100.68

K2qn1

2.61

1.18

14.24

451

546

2.96

0.30

0.65

0.10

0.96

49

2101.86

K2qn1

2.35

1.64

12.57

451

535

3.44

0.49

0.86

0.08

0.96

50

2102.52

K2qn1

2.07

1.15

7.76

444

375

3.23

0.45

0.80

0.08

0.83

51

2103.75

K2qn1

1.32

1.26

7.40

439

561

3.10

0.45

0.79

0.09

0.74

52

2104.75

K2qn1

2.00

2.08

8.80

439

629

4.40

0.40

0.82

0.07

0.74

53

2105.77

1

K2qn

2.12

1.90

9.67

450

456

3.35

0.47

0.76

0.12

0.94

54

2106.09

K2qn1

2.16

1.54

8.18

445

379

4.25

0.48

0.80

0.10

0.85

55

2107.67

K2qn1

1.54

1.71

8.52

439

553

3.19

0.41

0.83

0.05

0.74

56

2108.42

K2qn1

1.17

1.86

7.48

434

639

3.80

0.30

0.66

0.07

0.65

57

2109.77

K2qn1

1.39

1.93

7.52

444

541

3.88

0.35

0.73

0.09

0.83

58

2110.21

K2qn1

3.20

1.09

12.97

450

405

2.85

0.40

0.76

0.15

0.94

59

2111.37

K2qn1

1.62

0.81

8.20

449

506

2.44

0.50

0.83

0.10

0.92

60

2111.8

K2qn1

1.23

0.92

7.84

443

637

2.28

0.39

0.69

0.07

0.81

61

2113.27

K2qn1

2.72

1.29

13.46

454

495

2.28

0.46

0.78

0.11

1.01

62

2114.51

K2qn1

3.38

1.09

13.21

452

391

1.87

0.65

0.83

0.11

0.98

63

2115.12

K2qn1

0.72

0.88

4.03

442

560

1.34

0.38

0.21

0.09

0.80

64

2116.11

K2qn1

2.92

1.53

13.85

452

474

2.95

0.52

0.67

0.09

0.98

65

2116.92

K2qn1

2.66

1.49

12.04

452

453

2.04

0.45

0.28

0.10

0.98

66

2118.51

K2qn1

2.05

0.75

6.57

447

320

1.75

0.39

0.25

0.16

0.89

67

2118.82

K2qn1

1.12

0.82

6.55

446

585

1.88

0.45

0.64

0.07

0.87

68

2119.81

1

K2qn

1.65

0.91

8.18

448

496

1.39

0.30

0.77

0.09

0.90

69

2120.84

K2qn1

black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone

1.09

1.66

4.79

447

439

2.82

0.37

0.76

0.06

0.89

sample

depth (m)

F

measd

0.88

0.96


Article


Ro (%)

S2 (mg/g)

Tmax (°C)

HI (mg HC/ g TOC)

saturate (mg/g)

aromatic (mg/g)

resin (mg/g)

bitume (mg/g)

calcd

formation

lithology

TOC (wt%)

S1 (mg/g)

Well X83 70 2122.14

K2qn1

1.19

0.55

3.59

443

302

1.80

0.52

0.43

0.10

0.81

71

2123.13

K2qn1

1.35

0.88

5.70

446

422

2.66

0.30

0.51

0.08

0.87

72

2124.13

K2qn1

4.27

1.70

15.77

459

369

1.75

0.60

0.79

0.16

1.10

73

2124.81

K2qn1

6.39

2.90

23.78

457

372

2.81

0.20

1.26

0.16

1.07

74

2126.14

K2qn1

3.14

1.20

10.88

452

346

2.57

0.62

0.70

0.12

0.98

75

2126.96

K2qn1

1.76

1.01

7.54

449

428

2.45

0.40

0.75

0.09

0.92

76

2128.01

K2qn1

1.66

1.16

8.23

451

496

2.14

0.58

0.77

0.12

0.96

77

2128.8

K2qn1

1.25

0.58

5.71

448

457

1.10

0.32

0.48

0.07

0.90

78

2129.99

K2qn1

1.62

0.53

4.88

446

301

1.71

0.40

0.62

0.05

0.87

79

2130.96

K2qn1

0.44

0.28

2.34

449

532

1.22

0.28

0.47

0.11

0.92

80

2131.86

K2qn1

1.40

0.77

6.48

442

463

2.08

0.38

0.66

0.07

0.80

81

2132.82

K2qn1

1.25

0.41

5.30

450

424

0.73

0.30

0.40

0.09

0.94

82

2134.02

K2qn1

1.92

0.47

5.78

449

301

0.80

0.28

0.41

0.07

0.92

83

2134.64

K2qn1

1.77

0.41

9.50

453

537

1.89

0.55

0.84

0.19

0.99

84

2135.77

K2qn1

1.58

0.93

7.08

449

448

1.76

0.37

0.51

0.09

0.92

85

2136.32

K2qn1

1.35

0.91

8.13

448

602

1.68

0.43

0.56

0.09

0.90

86

2137.86

1

K2qn

2.33

0.84

7.93

452

340

1.74

0.34

0.37

0.07

0.98

87

2138.1

K2qn1

1.29

0.94

6.48

448

502

2.18

0.41

0.07

0.06

0.90

88

2138.72

K2qn1

0.75

0.99

4.12

440

549

2.50

0.35

0.54

0.10

0.76

89

2138.88

K2qn1

1.88

1.20

10.55

451

561

2.37

0.29

0.55

0.05

0.96

90

2139.65

K2qn1

black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone black mudstone

0.80

0.24

1.63

454

204

1.04

0.31

0.23

0.12

1.01

sample

depth (m)

heating rate of 5 K/min,44 and Paleogene source rocks from Liaodong bay showed decreasing C14+ yields at Ro = 0.96% for Es1 and Ro = 1.1% for Es3.32 4.2. Kinetic Parameters and Stabilities of Pyrolysates. The basis of petroleum generation is complicated rupture and reassembly of covalent bonds under different maturity models,45 depending on time and temperature.41 These processes are reflected by a series of first-order kinetic models that are related to frequency factor (A) and activation energy (Ea).19,46 In order to optimally verify that there are differences in kinetic process for L kerogen generation pyrolysates and group compositions, a fixed frequency factor of A = 5.0 × 1015 s−1 was used, a reasonable value that falls between 1.0 × 1012 and 1.0 × 1018 s−1.47,48 This frequency was also suitable for early HC or NSOs generation.24 The kinetic parameters for our samples were calculated using the Kinetics 2000 software package,43 a model that incorporates the distribution of activation energies and frequency factors.47

measd

1.13

0.88

Results demonstrate that the C14+ hydrocarbons in our samples fall within the activation energy range of Ea = 47−58 kcal/mol at a frequency factor of A = 5.0 × 1015 s−1 (Figure 3). These data are similar to those reported previously: Ea = 54 kcal/mol for type I kerogen32 and Ea = 55−60 kcal/mol for the type I kerogen of the Dongying depression at A = 5.0 × 1015 s−1.24 The analytical distinction between samples in terms of activation energy could reflect variations in heterogeneity of organic matter;49 i.e., those organisms’ variety and sedimentary environment are clear factors for organic compositions.50 The kerogen pyrolysis process is often accompanied by the cracking of macromolecules into smaller compounds and finally gases.41,42 Previous studies have shown that resins crack into asphaltenes and the components of secondary oil and gas42 because of the lower activation energy of resins compared to asphaltenes.51 It is noteworthy that the activation energies of Saturate, Aromatic, Resin and Asphaltene (SARA), based on the scale of average values for L kerogen, are in the sequence S > A > As > R in Figure 3. In the thermal evolution scheme, G


Article

Energy & Fuels

Figure 2. Rock-Eval data of source rocks from wells H14 and X83, Songliao basin.

heat flow (1.75 HFU) have led to oil generation at shallow depths in the Songliao basin.55,56 As demonstrated by previous research, a %Ro value of less than 0.5% is found at shallower than 800 m, and %Ro values within the range of 0.5−0.7% at 800−1500 m; at the depths of deeper than 1500 m, abundant liquid hydrocarbons are found within the “oil windows”.56 The peak hydrocarbon generation of these source rocks has been also documented at %Ro values in the range 1.05−1.1%.55,56 It is fortunate that oil generation can be simulated by pyrolysis experiments57 and reproduced on the basis of the kinetic parameters obtained from experiments on immature kerogen.24,43,58,59 The generation of C14+ hydrocarbons, resins, and asphaltenes under geological conditions is shown in Figure 4. Houseknecht and Hayba60 proposed that oil generation generally comprises three phases: early, main, and late generation, corresponding to transformation ratios within the ranges 10−25%, 25−65%, and 65−90%, respectively. As plotted in Figure 4, few hydrocarbons are generated at Easy% Ro values less than 0.6%; the main liquid hydrocarbon generation stage is at Easy%Ro values in the range 0.6− 1.05%, close to the values previously obtained by Gao55 and Hou et al.56 Data from this study display that the maximum hydrocarbon yield is about 420 mg HC/g TOC, shown by the

kerogen first generates polar compounds before the formation of hydrocarbons, which is closely related to the secondary degradation of these compounds (Table 2).24,52 In this study, the results are consistent with those of Behar et al.12 that liquid hydrocarbons mainly originate from the thermal decomposition of heavy group compounds within the range of early stages of maturity to “oil windows”. In pyrolysis experiments, data display that the proportion of C14+ n-alkanes gradually decreased as the yield of C6−14 n-alkanes increased with higher temperatures, revealing that the proportion of low-carbon nalkanes is related to the heavy n-alkanes cracking into lowcarbon n-alkanes.15,25,32 Similar results have been also obtained with cracking of C6−14 n-alkanes or alkylated aromatics into gas or aggregation of pyrobitumenin at higher temperatures.15,53 4.3. Processes of Oil Generation in Geological Application. Tissot and Welte41 have suggested that hydrocarbon generation of types I and II kerogen can generally be divided into three stages: oil generation in the %Ro range 0.6− 1.35%, condensate and wet gas in the %Ro range 1.35−2.0%, and production of dry gas at %Ro greater than 2.0%. Hydrocarbon generation in source rocks can be also described on the basis of depth variation.31,32,54 The relatively high geothermal gradient (on average 4 °C per 100 m) and H


Article

Energy & Fuels Table 4. Mineral Compositions of Samples from Wells H14 and X83 in Songliao Basin clay mineral sample

depth

formation

(m)

brittle mineral

clay

I/S

illite

kaolinite

quartz

feldspar

calcite

dolomite

siderite

pyrite

(%)

(%)

(%)

(%)

(%)

(%)

(%)

(%)

(%)

(%)

Well H14 1 2032.49 2 2033.85 3 2036.05 4 2038.05 5 2039.15 6 2040.2 7 2041.53 8 2041.95 9 2047.15 10 2048.1 11 2050.85 12 2052.73 13 2054.45 14 2056.45 15 2059.02 16 2060.78 17 2062.38 18 2065.1 19 2066.06 20 2067.11 21 2068.3 22 2070.77 23 2074.86 24 2076.22 25 2077.7 26 2079.63 27 2081.09 28 2081.5

K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1

50.3 43.6 42.5 48.9 47.4 48.9 49.8 33.5 42.7 42.2 38.7 42.1 46.9 43.4 40.7 43.9 45.7 47.8 51.5 53.8 49.9 48.8 58.9 23.9 48.4 46.9 49.6 42.2

9.7 10.7 9.1 9.3 10.8 8.9 14.3 8.6 7.8 7.1 10.1 9.1 9.1 9.7 7.8 13.6 10.9 9.7 11.7 11.1 8.6 8.4 9.7 1.9 7.4 6.3 5.8 7.1

30.7 22.0 31.2 31.6 32.1 30.5 20.2 24.9 28.7 31.4 28.6 23.0 32.7 27.4 24.9 19.9 27.3 29.9 32.2 35.3 36.4 32.3 40.9 19.0 28.8 25.5 32.7 26.4

9.9 10.9 2.2 8.0 4.5 9.5 15.3 0.0 6.1 3.7 0.0 10.0 5.1 6.3 8.0 10.4 7.4 8.2 7.6 7.4 5.0 8.2 8.3 3.0 12.2 15.1 11.1 8.7

27.9 38.6 39.7 26.7 26.9 34.1 25.7 32.6 40.3 32.6 38.4 37.0 31.9 37.4 36.5 34.2 32.3 33.5 29.7 28.1 31.1 31.0 22.8 26.6 34.0 35.1 30.7 37.6

21.8 17.8 17.8 24.4 22.9 17.1 12.8 18.8 17.0 25.2 17.6 20.8 19.6 19.1 18.9 17.7 18.8 16.1 18.7 18.2 14.5 17.5 15.2 23.8 17.6 13.4 15.3 18.2

0.0 0.0 0.0 0.0 2.7 0.0 11.0 11.2 0.0 0.0 0.0 0.0 1.6 0.0 1.4 4.2 3.2 2.6 0.0 0.0 0.0 2.7 0.0 20.6 0.0 1.7 2.5 2.0

0.0 0.0 0.0 0.0 0.0 0.0 0.7 3.8 0.0 0.0 5.3 0.0 0.0 0.0 2.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3.1 5.1 0.0 2.9 1.9 0.0

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Well X83 1 2051.44 2 2052.99 3 2054.76 4 2055.22 5 2057.43 6 2058.28 7 2059.51 8 2060.37 9 2061.41 10 2063.58 11 2064.61 12 2065.69 13 2066.16 14 2066.78 15 2068.32 16 2069.35 17 2070.48 18 2071.34 19 2072.37 20 2072.62 21 2074.46 22 2075.05 23 2076.3 24 2077.2 25 2078.24 26 2079.26 27 2080.23

K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1

42.4 48.4 41.8 47.9 54.0 50.7 51.8 51.4 53.3 43.6 47.4 39.5 51.3 51.6 43.7 57.0 51.3 56.0 57.2 47.7 48.4 44.7 49.7 47.5 45.3 49.8 52.6

9.9 11.5 12.5 10.6 11.7 13.4 12.1 10.1 12.8 7.6 10.3 10.3 9.6 10.4 9.9 10.1 9.6 10.3 16.0 12.1 10.6 10.4 9.9 11.0 11.2 8.6 17.9

31.1 35.9 27.4 36.3 41.1 33.3 36.8 36.8 37.0 33.5 36.1 27.3 37.8 39.3 31.0 44.3 37.2 41.7 38.3 34.5 36.9 32.4 36.8 31.7 30.2 38.3 31.8

1.4 1.0 2.0 1.1 1.2 3.9 3.0 4.6 3.6 2.5 1.1 1.9 4.0 2.0 2.8 2.6 4.5 3.9 2.9 1.1 1.0 1.9 3.0 4.9 3.8 2.9 2.8

30.0 25.9 35.8 28.9 27.0 30.7 32.3 29.9 29.7 39.8 29.5 43.0 29.6 25.5 41.8 25.8 29.6 14.3 21.7 29.1 25.9 31.7 27.6 28.9 25.9 27.6 26.1

26.0 17.0 19.4 15.4 13.9 13.7 15.9 16.5 17.0 16.6 16.3 17.5 19.1 17.3 14.5 17.2 19.0 21.7 16.7 17.8 21.7 23.7 21.3 21.0 21.5 18.5 19.6

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

0.0 5.0 1.5 4.5 3.3 2.5 0.0 0.0 0.0 0.0 3.4 0.0 0.0 3.0 0.0 0.0 0.0 6.0 4.3 4.0 2.5 0.0 0.0 2.6 5.7 2.5 0.0

1.6 1.6 0.6 1.4 0.0 0.0 0.0 0.0 0.0 0.0 2.0 0.0 0.0 1.4 0.0 0.0 0.0 0.0 0.0 1.4 1.5 0.0 0.0 0.0 0.0 0.0 0.0

0.0 2.0 0.8 1.8 1.8 2.4 0.0 2.2 0.0 0.0 1.3 0.0 0.0 1.2 0.0 0.0 0.0 2.0 0.0 0.0 0.0 0.0 1.4 0.0 1.7 1.5 1.8

I


Article

Energy & Fuels Table 4. continued clay mineral sample

depth

formation

(m) Well X83 28 2081.34 29 2082.03 30 2083.29 31 2083.72 32 2084.81 33 2085.97 34 2087 35 2087.97 36 2088.51 37 2089.62 38 2089.82 39 2091.79 40 2092.79 41 2093.72 42 2094.72 43 2095.47 44 2096.17 45 2097.67 46 2098.57 47 2099.62 48 2100.68 49 2101.86 50 2102.52 51 2103.75 52 2104.75 53 2105.77 54 2106.09 55 2107.67 56 2108.42 57 2109.77 58 2110.21 59 2111.37 60 2111.8 61 2113.27 62 2114.51 63 2115.12 64 2116.11 65 2116.92 66 2118.51 67 2118.82 68 2119.81 69 2120.84 70 2122.14 71 2123.13 72 2124.13 73 2124.81 74 2126.14 75 2126.96 76 2128.01 77 2128.8 78 2129.99 79 2130.96 80 2131.86 81 2132.82 82 2134.02 83 2134.64 84 2135.77

K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1

brittle mineral

clay

I/S

illite

kaolinite

quartz

feldspar

calcite

dolomite

siderite

pyrite

(%)

(%)

(%)

(%)

(%)

(%)

(%)

(%)

(%)

(%)

39.2 48.5 47.4 45.5 48.4 47.7 48.3 51.1 50.3 51.4 46.7 51.6 46.8 50.7 40.7 49.1 53.7 51.6 40.3 49.7 48.2 52.5 48.4 47.3 53.1 48.9 44.2 47.5 47.5 54.0 42.5 52.9 42.8 42.0 47.5 51.2 45.1 49.1 49.2 44.6 52.8 52.3 50.8 47.1 47.3 39.7 49.9 48.7 41.5 50.8 45.5 47.1 52.6 46.3 45.7 55.3 42.1

12.3 12.5 10.0 11.5 11.8 11.7 13.7 11.0 12.0 11.2 12.1 17.8 9.8 12.1 12.9 11.3 11.1 12.1 11.8 11.3 9.7 12.1 12.3 15.1 11.9 13.3 10.8 11.4 11.3 10.6 13.0 13.1 13.5 10.4 9.8 11.0 11.6 13.4 11.7 10.7 11.1 12.1 10.9 12.4 9.6 9.7 11.3 11.7 10.9 11.3 12.3 12.1 12.7 12.5 10.0 12.3 10.7

23.1 32.8 35.4 31.1 34.5 34.1 30.7 34.2 34.4 36.6 31.5 30.9 33.5 37.6 26.4 33.8 39.5 37.5 26.2 33.1 35.1 37.6 34.0 29.0 38.8 32.6 27.6 32.1 32.6 39.3 26.0 37.0 27.2 29.0 34.6 36.3 31.4 32.6 35.4 28.9 38.6 38.1 37.8 30.8 35.5 26.5 36.5 34.1 28.5 36.5 31.2 29.0 35.6 29.0 32.6 40.1 29.3

3.9 3.2 2.0 2.9 2.1 2.0 3.9 5.9 4.0 3.6 3.0 2.9 3.5 0.9 1.5 4.0 3.0 2.0 2.3 5.3 3.4 2.8 2.1 3.2 2.4 3.0 5.9 4.1 3.6 4.0 3.5 2.8 2.1 2.6 3.1 3.9 2.1 3.0 2.1 4.9 3.0 2.1 2.1 3.9 2.2 3.5 2.0 2.9 2.1 3.0 2.1 6.1 4.3 4.9 3.0 2.9 2.1

36.5 24.5 28.9 25.9 25.1 28.6 31.6 28.9 28.5 25.4 25.5 26.9 28.6 23.9 30.4 27.4 23.9 27.0 32.7 25.4 24.0 23.6 26.8 32.3 23.0 27.8 38.3 26.8 23.8 22.5 20.8 28.1 25.8 26.8 21.6 23.6 21.9 25.9 23.0 23.8 25.8 21.1 24.2 23.1 23.6 25.6 25.3 23.8 23.7 24.6 23.8 27.7 24.6 29.7 21.0 20.6 25.1

17.5 19.5 19.0 19.6 17.8 23.6 20.0 18.5 21.2 21.5 21.0 21.5 22.7 22.5 28.9 23.5 22.5 18.7 25.2 22.9 25.2 23.9 24.9 20.4 22.0 16.8 13.2 20.1 23.5 23.6 20.6 19.0 27.3 24.8 24.7 21.5 26.3 25.0 20.6 23.8 21.4 23.7 22.2 25.6 27.3 28.3 22.1 23.8 28.3 23.1 25.1 23.9 21.5 19.3 27.8 22.8 30.1

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

6.8 4.7 4.7 5.9 2.9 0.0 0.0 0.0 0.0 0.0 2.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.3 2.7 2.8 3.6 0.0 16.1 0.0 0.0 4.1 3.0 0.0 5.0 0.0 7.3 4.0 0.0 0.0 0.0 0.0 0.0 3.0 0.0 0.0 3.1 0.0 3.9 0.0 0.0 4.7 2.5 0.0 0.0

0.0 0.0 0.0 0.0 1.1 0.0 0.0 1.5 0.0 1.7 2.1 0.0 1.9 2.9 0.0 0.0 0.0 2.6 1.8 1.9 1.1 0.0 0.0 0.0 0.0 0.0 0.0 1.1 1.5 0.0 0.0 0.0 2.3 2.3 1.6 1.7 1.7 0.0 0.0 2.1 0.0 1.2 1.0 2.1 0.0 1.8 1.2 2.0 1.7 1.5 1.6 1.3 1.3 0.0 1.7 1.3 0.0

0.0 2.8 0.0 3.1 4.6 0.0 0.0 0.0 0.0 0.0 1.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.6 0.0 0.0 0.0 1.9 2.2 1.6 1.8 0.0 0.0 0.0 0.0 1.8 0.0 1.5 2.1 0.0 0.0 0.0 1.7 0.0 1.7 1.8 2.1 1.8 1.6 1.5 1.7 1.7 0.0 0.0 0.0 0.0 0.0 1.4 0.0 2.7

J


Article

Energy & Fuels Table 4. continued clay mineral sample

depth

formation

(m) Well X83 85 2136.32 86 2137.86 87 2138.1 88 2138.72 89 2138.88 90 2139.65

K2qn1 K2qn1 K2qn1 K2qn1 K2qn1 K2qn1

brittle mineral

clay

I/S

illite

kaolinite

quartz

feldspar

calcite

dolomite

siderite

pyrite

(%)

(%)

(%)

(%)

(%)

(%)

(%)

(%)

(%)

(%)

44.7 43.5 50.5 44.2 48.0 42.9

10.6 15.2 12.0 10.7 11.3 13.1

31.1 25.4 36.0 28.0 34.2 25.3

3.0 2.9 2.6 5.6 2.5 4.5

30.9 34.1 24.8 25.1 27.2 27.6

24.4 20.0 22.7 29.0 22.7 25.2

0.0 0.0 0.0 0.0 0.0 0.0

0.0 0.0 0.0 0.0 0.0 0.0

0.0 0.0 0.0 0.0 0.0 0.0

0.0 2.3 2.0 1.6 2.0 4.3

rich productivity zones. Equilibrium sorption amounts of 18.0, 3.0, and 1.8 mg/g for clay, corporate quartz and feldspar, and carbonate, respectively, have been reported in recent work, and a conceptual model has been presented,10 as follows:

hydrocarbon generation curve at Easy%Ro value of 1.05 in Figure 4. Thus, experimental results of thermal simulations of hydrocarbon generation under geological conditions are of scientific use, in particular with regard to the generation of geochemical data of %Ro. 4.4. Evaluation of Shale Oil. 4.4.1. Geochemical Characteristics of Source Rocks. Rock-Eval data in Figure 2 show that hydrocarbons can be produced from the mature source rocks in this study. However, the %Ro maturity parameter is hard to measure in pyrolysis experiments on type I kerogen, because very little vitrinite and kerogen is injected. The Tmax-to-Ro (Ro = 0.018 × Tmax − 7.16) conversion equation50 was here applied to calculate equivalent vitrinite reflectance (Table 3), which was also used in the Tuma borehole.61 As tabulated in Table 3, values of equivalent %Ro are in the range of 0.6−1.05%, characteristic of the main phase of hydrocarbon generation. The equivalent %Ro values correspond well with measured values in Figure 5; in other words, equivalent %Ro can be used to extrapolate the variation in oil yields under geological conditions. Potential for oil generation can thus be investigated on the basis of calculated Easy%Ro from geological deductions and the equivalent %Ro from the conversion equation presented above. In the preamble, we have simulated processes of oil generation from kerogen sample of K2qn, significantly consistent with oil products derived from source rocks,62 and volumes of residual hydrocarbons have been calculated for source rocks from two wells. The volumes of chloroform bitumen “A” present in the residual hydrocarbons of oil-prone source rocks from wells H14 and X83 are shown in Table 3. The ternary diagram of group components shows that saturates and aromatics (ca. 60−90%) make up the principal components of chloroform bitumen “A” in Figure 6, indicating that these source rocks are in the main phase of oil generation and have a high capacity for hydrocarbon retention. In addition, enrichment hydrocarbon yields provide evidence for obligate physical flow properties; previous data suggested that shale oil resources formed in the liquid hydrocarbon generation stage, having molecular diameters in the range 0.5−0.9 nm, tend to be of industrial interest.63 4.4.2. Sorption and Free Hydrocarbon. The production of shale oil is dependent mainly on whether substantial free oil is present in mudstones and shales under existing technical conditions.5,7,10,26 Furthermore, there is no oil flow until the adsorption threshold is exceeded.5 However, it is problematic to directly measure or calculate the amounts of mobile oil; therefore, it is necessary to study oil adsorptions amounts indirectly in order to estimate the potential of free hydrocarbon in shales. Jarvie5 has also proposed that adsorption affinity plays an important role in the unconventional resource from organic-

i=1

Sp = p0 x0 + γ ∑ px i i n

(1)

i=1

p0 +

∑ pi = 1 n

γ=

⎡ Φ ⎤2/3 S =⎢ ⎥ S0 ⎣ Φ0 ⎦

(2)

(3)

In this expression, Sp is shale adsorption potential, p0 and x0 are the fraction and adsorption of organic matter, respectively, γ is the coefficient of variation of specific surface area (eq 3 from ref 64), pi and xi denote the ith mineral fraction and its adsorption contents, S and S0 refer to the specific surface area of pores without (S) and with (S0) compacted effects, and Φ0 and Φ denote porosity before and after compaction. Because previous work has reported that the porosity of black shale from unit K2qn1 at Qijia Sag in the Songliao basin is in the range 1.20−3.09% (depths between 1985 and 2279 m), a midrange value of 2.15% is reasonable based on the intermediate depths of wells H14 and X83.65 Porosity (Φ0) at the surface is about 50%, and γ can be obtained using eq 3 (above). The mineral composition percentages of the K2qn1 unit (i.e., wells X83 and H14) are 23.9−58.9% clay, 20.8−43.0% quartz, 12.8−30.1% feldspar, 0−20.6% calcite, 0−16.1% dolomite, 0− 4.6% pyrite, and 0−2.9% siderite (Figure 7 and Table 4). High quartz compositions in the K2qn1 source rocks, as well as pyrite, play a significant role in the shale oil potential yields because of its high adsorption content of organic matter.10,66 In detail, oil adsorption amounts on quartz and pyrite are 3.0 and 10.0 mg/ g,10,67 respectively, while the adsorption capacity of clay reaches 18.0 mg/g, and the adsorption potential value of carbonatite, including total of calcite and dolomite, is about 1.8 mg/g.10 As a result, oil adsorption capacity of inorganic minerals can be calculated in mudstones and shale samples. In addition, percent content of quartz (>20 wt%) and brittle minerals (quartz + feldspar + calcite + dolomite + pyrite + siderite) generally exceeds 40 wt%, meeting the requirements of industrial fracturing.68 In the case of the Bohai Bay basin mudstone, Wei et al.24 used the solvent swelling method to determine that hydrocarbon retention was in the range 40−120 mg HC/g TOC within an Easy%Ro range of 0.6−1.2%. Li et al.10 suggested that K


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Energy & Fuels

Figure 3. Fitting curves and activation energy distribution for four group components from pyrolysates at different heating rates in a closed system.

80 mg HC/g TOC is adsorbed by TOC within “oil windows”. The intersection (75 mg HC/g TOC) of the envelope curve

between the hydrocarbon expulsion threshold depth and S1/ TOC is considered to represent the boundary of movable oil L


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Energy & Fuels

the results outlined above. As shown in Figure 8, organic matter contents have an important impact on oil adsorption from mudstones and shales at a correlation coefficient of 0.96; Sp values exhibit a gradually ascending trend with increasing TOC, and the presence of organic matter is a factor in favor of hydrocarbon adsorption. In our case, an intersection point is determined by the equation Sp = 0.7642 × TOC + 1.0761 between the red trendline and Sp, indicating the mineral absorption for crude oil to be ∼1.1 mg/g (Figure 8). This result is consistent with previous studies; i.e., the adsorption on inorganic mineral surfaces is about 1.2−1.8 mg/g for the Berea sandstone reservoir69 and 2.0 mg/g for well NY1 in the Dongying Depression, Bohai Bay basin.10 The quantification of free hydrocarbon is important for the exploration and development of shale oil under current technological conditions. Differences between S1 and Sp are referred to as free oil potential; S1 > Sp indicates oversaturation, while S1 < Sp indicates starvation in the case of shale oil.10 In other words, oversaturation indicates the presence of free hydrocarbons, while starvation sets a limit on a shale oil resource. The OSI (= S1/TOC) was proposed by Jarvie5 on the basis of data from Lopatin et al.70 as a further indicator for potentially producible oil (free oil) when S1 exceeded TOC on an absolute basis in organic-rich and organic-lean shales, signifying OSI of 100 mg/g or greater value. The production index (PI = S1/(S1 + S2)) can also be used to estimate the state of hydrocarbon aggregation, with a PI > 0.2 indicating hydrocarbon expulsion while a PI < 0.2 suggests that hydrocarbons are present in source rock pores.31 These three parameters, i.e., S1−Sp, OSI, and PI, can be generally used to show that oversaturated oil zones are mainly present at depths greater than 2065 m in well H14, as well as at relatively discrete depths (2051.4−2139.7 m) in well X83 (Figure 9), implying active generation and expulsion in the K2qn1. In addition, intervals not showing crossover could be also sealed by two free oil zones in Figure 9, as in the study on Toarcian shale in Paris basin by Jarvie.5 Generally, shale oil resources have been discovered in well H14 (>2065 m), but as yet there is no industrial production from the mudstones and shales in well X83. These results show that our study is consistent with the actual geological conditions in the Songliao basin. However, the

Figure 4. Hydrocarbon generation vs Easy%Ro under geologically thermal rate.

Figure 5. Plot of measured Ro and calculated Ro.

content in the K2qn1 unit of the Songliao basin.7 Adsorption contents of organic matter can be thus calculated by applying

Figure 6. Termary diagram for four groups from separation of chloroform bitumen “A”. M


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Energy & Fuels

Figure 7. Mineral percentages of source rock from wells H14 and X83 in Songliao basin.

(oil in place) with excellent estimated ultimate recovery (EUR) in organic-lean rocks. Therefore, our data give a good assessment free oil in abundant organic source rocks and a more reasonable estimation of moveable oils in low organic rocks by application of S1−Sp, based on considering the sorption oil content. 4.4.3. Maturity Models for Shale Oil Assessment. Shale oil mainly forms within “oil windows”,25,27,63 and a study has shown that a low hydrocarbon generation potential may lead to insufficient free oil at Easy%Ro < 0.7%.41 Actually, a classic marine black shale from Upper Jurassic Bazhenov formation in the West Siberian basin contains an unconventional oil accumulations reservoir, with a general maturity of around Ro 0.62−0.75% and but active fault zone. One of the main goals for exploring unconventional oil is to provide an obvious increase in the source of heating to 1.1% Ro, indicating that thermal maturity is a major factor controlling production risk.70 Data derived from graphic plots in the work of Jarvie5 indicate that free oil (OSI > 100 HC mg/g TOC) mainly arises in Miocene Monterey shale, Miocene Antelope shale, lower or upper Bakken shale, and Eagle Ford shale, corresponding respectively to %Ro values (calculated from Tmax) of about 0.8, 0.6, 0.6−0.7, and 1.0%. Organic-rich source rocks with excellent or good oil saturation in the range of “oil window” are most likely to have abundant oil, but “oil window” must be carefully considered because it does vary in source rocks, and then it is also necessary to rationalize optimal maturity values varying from 0.6 to 1.4%Ro, which are significant for petroleum liquid generation.5 Nevertheless, there is still less attention given to shale maturity assessment in free oil zones. As illustrated in Figure 4, when Easy%Ro < 0.6%, hydrocarbon yields remain low, but when Easy%Ro is in the range 0.6−1.05%, the hydrocarbon yield derived from secondary cracking of NSOs progressively increases. Indeed, when Easy%Ro > 1.05%, a part of C14+ oil cracking to C6−14

Figure 8. Diagram of TOC and shale adsorption potential for two wells in K2qn1.

data (S1−Sp) do not support OSI as plotted in Figure 9, referring to depths of 2042−2045 m in well H14 and 2138.7 and 2115.1 m in well X83. It shows significant free oil accumulations with organic-rich (TOC > 3.0%) source rocks in faults and macrofractures zones,70 but it is likely to appear as overrated potential producibility of free oil because of the much lower oil contents in organic-lean rocks, as shown by low chloroform bitumen “A” in Table 3. Indeed, the abnormally high carbonates contents (>11.0%) at depths of 2042−2045 m in well H14 decrease oil content5 and relatively high pyrite compositions (>2.0%) at 2138.7 and 2115.1 m in well X83 could support higher oil adsorption amounts.10,67 Jarvie66 suggested there will be a crossover effect when reaching maximum storage capacity or corresponding to actively expelling hydrocarbon in organic-rich source rocks, and with the occurrence of saturation with migrated oil or very high OIP N


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Energy & Fuels

Figure 9. Data for free oil potential, oil saturation index, and production index with variation of burial depth.

compounds can occur at higher stages of maturity.15,32 Our data show that oil-prone source rock intervals in the Songliao basin are within the range for main hydrocarbon generation according to equivalent %Ro (Table 3), providing the necessary prerequisite conditions for shale oil formation. As the retention and expulsion properties of hydrocarbons from type I kerogen have been thoroughly investigated using gold tube pyrolysis and solvent swelling experiments by Wei et al.,24 results from these approaches display that, at the start, peak, and end of the “oil window”, hydrocarbons retained in shales and mudstones contain about 120, 100, and 40 mg HC/g TOC, respectively. Therefore, these values are used as reference points for hydrocarbon adsorptions, free hydrocarbons occurring at stages of Ro < 1.0% within the “oil window” range, roughly corresponding to HC oversaturation (Sp < S1) samples for the mudstones and shales of the K2qn1 unit in the Songliao basin in Figure 10. In studies on unconventional oil, chloroform bitumen “A” is mainly another parameter, which is closer to liquid accumulation (7, 27). The results of this study show that measured amounts of “A”/TOC gradually increase with S1/ TOC (W“A”/TOC = 2.562WS1/TOC + 66.29) with a correlation coefficient R2 = 0.7714 in Figure 11. Therefore, absorbed amounts of “A”/TOC can be reasonably calculated by means of this relation, as shown in Figure 12; oil generation, chloroform bitumen “A”, and the retention oil line vs Easy%Ro are presented for the interpretation of the generation, retention, and mobile properties of shale oil. On the basis of the detailed analysis presented in Figure 10, it is possible to determine which sample is generally distributed between the curves for oil

Figure 10. Hydrocarbon generation and oil saturation index vs Easy% Ro for mudstone/shale of K2qn1 in the Songliao basin.

generation and adsorption (imaginary line A), indicating free oil. Considering three sets of oil occurrencegeneration, sorption, and free in this textthe oil retention calculated for the two well samples having especially high contents of adsorption oil at low maturity (Easy%Ro < 0.8%), with low free oil thought to mainly comprise resins and asphaltenes, as shown in Figure 12. In addition, these samples (red hydrocarbon points) exceed maximum adsorption, which agrees well with the presence of oversaturated shale oil (S1 > Sp). The black points (S1 < Sp) on this graph also reveal the O


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Energy & Fuels

5. CONCLUSIONS This study assesses shale oil of the Songliao basin by considering hydrocarbon generation as well as volumes of residual and adsorbed hydrocarbons. The two mudstone and shale oil wells in the K2qn1 oil-prone source rock unit considered here are in a stage of oil generation and have rich residual hydrocarbon content. Brittle mineral contents in these wells meet the requirements for industrial oilfield development and exploitation. Data on S1−Sp, OSI, and PI all suggest a lowrisk exploration target at burial depths less than 2065 m in well H14 as well as at relatively discrete depths (2051.4−2139.7 m) in well X83, and in comparison to general OSI, S1−Sp is an edge to estimate free oil in rocks. An oil generation−sorption method for shale oil assessment is constructed and reveals that suitably restricted conditions of movable shale oil are accompanied by Easy%Ro values in the range 0.8−0.97% for the K2qn1 mudstone and shale unit in the Songliao basin.

■

Figure 11. Relationship of oil saturation index and measured chloroform bitumen “A”.

AUTHOR INFORMATION

Corresponding Authors

*Tel.: +86 20 85290187. E-mail: [email protected]. *Tel. +86 2085290126. Fax: +86 20 85290117. E-mail: [email protected]. ORCID

Yan-Rong Zou: 0000-0003-4071-6233 Notes

The authors declare no competing financial interest.

■

ACKNOWLEDGMENTS This study was financially supported by the Foundation for Innovative Research Groups of the National Science Foundation of China (Grant No. 41621062) and the National Science Foundation of China (Grant Nos. 41273059 and 41302008). We especially thank Dr. Jingming Wei for guidance in XRD analysis. Two anonymous reviewers are especially acknowledged for their comments and constructive suggestions.

■

Figure 12. Oil generation and calculated oil yields vs Easy%Ro for mudstone/shale of K2qn1 in the Songliao basin.

REFERENCES

(1) Hill, D. G.; Lombardi, T. E.; Martin, J. P. Northeast. Geol. Environ. Sci. 2004, 26, 57−78. (2) Perry, K.; Lee, J. Unconventional gas reservoirs: tight gas, coal seams, and shales; National Petroleum Council: Washington, DC, 2007. (3) Li, X. J.; Lü, Z. G.; Dong, D. Z.; Cheng, K. M. Nat. Gas. Ind. 2009, 29, 27−32. (4) Kinley, T. J.; Cook, L. W.; Breyer, J. A.; Busbey, A. B. AAPG Bull. 2008, 92, 967−991. (5) Jarvie, D. M. AAPG Bull. Memoir 2012, 97, 89−119. (6) Kirschbaum, M. A.; Mercier, T. J. AAPG Bull. 2013, 97, 899−921. (7) Xue, H. T.; Tian, S. S.; Lu, S. F.; Zhang, W. H.; Du, T. T.; Mu, G. D. Petrol. Geochem. 2015, 34, 70−78 (in Chinese). (8) Zhang, L. Y.; Bao, Y. S.; Li, J. Y.; Li, Z.; Zhu, R. F.; Zhang, J. G. Petrol. Explor. Dev. 2014, 41, 703−711. (9) Wang, M.; Sherwood, N.; Li, Z. S.; Lu, S. F.; Wang, W. G.; Huang, A. H.; Peng, J.; Lu, K. Int. J. Coal Geol. 2015, 152, 100−112. (10) Li, Z.; Zou, Y.-R.; Xu, X.-Y.; Sun, J.-N.; Li, M. W.; Peng, P. A. Org. Geochem. 2016, 92, 55−62. (11) Lu, S. F.; Zhang, M. Petroleum Geochemistry; Petroleum Industry Press: Beijing, 2008; p 4 (in Chinese). (12) Behar, F.; Lorant, F.; Mazeas, L. Org. Geochem. 2008, 39, 764− 782. (13) Tissot, B. P.; Espitalié, J. Rev. Oil Gas Sci. Technol. 1975, 30, 743−777. (14) Pepper, A. S.; Corvi, P. J. Mar. Pet. Geol. 1995, 12, 417−452.

presence of residual oil in comparison to adsorption oil under the region of the dotted line, a potential disadvantage for shale oil exploration and exploitation. Hydrocarbon generation and the cracking of NSO compounds corresponding with low activation energies are mainly distributed within the maturity stage of oil generation;20,42 significant occurrence of free oil when oil generation yields more than the adsorption capacity of a mudstone or shale is referred to as the “sweet area” for shale oil exploration and exploitation. In contrast, when Easy%Ro > 0.97%, the absence of free oil suggests that the oil undergoes a main hydrocarbon expulsion process. As Xue et al.71 have reported, we find an obvious linear relationship between hydrocarbon expulsion efficiency and %Ro, as well as a hydrocarbon expulsion efficiency that exceeds 73% when Ro > 1.0%, by analysis on source rocks in the K2qn1 unit within the Songliao basin. Finally, maturity models for shale oil assessment reveal that the potential intervals for shale oil are in the range from 0.8 to 0.97%Ro for the K2qn1 mudstones and shales in the Songliao basin. P


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Shale Oil Assessment for the Songliao Basin, Northeastern China

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