Contribution and significance of dispersed liquid hydrocarbons to reservoir formation

PETROLEUM EXPLORATION AND DEVELOPMENT Volume 42, Issue 4, August 2015 Online English edition of the Chinese language journal Cite this article as: PETROL. EXPLOR. DEVELOP., 2015, 42(4): 439–453.

RESEARCH PAPER

Contribution and significance of dispersed liquid hydrocarbons to reservoir formation ZHAO Wenzhi1,*, WANG Zhaoyun1, WANG Dongliang2, LI Jian2, LI Yongxin1, HU Guoyi1 1. PetroChina Research Institute of Petroleum Exploration & Development, Beijing 100083, China; 2. Langfang Branch, PetroChina Research Institute of Petroleum Exploration & Development, Langfang 065007, China

Abstract: Oil expulsion rate of different types of source rock in geologic settings are estimated by modeling hydrocarbon generation and expulsion and examining the geological sections of different source-reservoir combinations. The major gas generation peak of oil-cracked gas kitchen is determined by study on the gas generation timing of dispersed liquid hydrocarbon inside and outside source rock and ancient oil reservoirs, and the factors affecting the gas generation timing. A “five-step method” based on the origin method is set up to quantitatively evaluate the cracked gas generated by dispersed liquid hydrocarbons. The hydrocarbon generation and expulsion experiment of different types of source rock, the study on oil expulsion rate of different source-reservoir combinations, analysis of rock pyrolysis parameters of reservoir rock all show that there is a large amount of liquid hydrocarbons retained in the source rock, and the feature on the whole is the oil expulsion rate decreases with the reducing of total organic carbon (TOC). The expulsion rate of source rock with TOC of less than 2% is below 50% in general during the liquid-window stage, while that of alternating sandstone and mudstone and of thick mudstone, with TOC of 2%−4%, are 60% and 30% respectively. Affected by the ancient landform, the expelled liquid hydrocarbons accumulated in different abundance in formations, with dispersed or semi-dispersed and semi-gathered form, and they are called dispersed liquid hydrocarbons outside source rock. When buried deeper, both dispersed liquid hydrocarbons inside and outside the source can be cracked into natural gas to form conventional and unconventional gas accumulations. Exploration practices in the Sichuan and Tarim basins have proven that the cracked gas generated by dispersed, semi-dispersed and semi-accumulated, and accumulated liquid hydrocarbons is an important source of deep natural gas in China, and takes an important position in gas exploration. Key words: dispersed liquid hydrocarbon; dispersed liquid hydrocarbon inside source rock; dispersed liquid hydrocarbon outside source rock; liquid hydrocarbon cracked gas; source rock oil expulsion rate; liquid hydrocarbon cracking into gas; quantitative evaluation of cracked gas

Introduction A series of large gas fields have been discovered successively in deep marine series of strata in the Sichuan, Tarim, and other basins of China in recent years, among which, the supergiant Sinian-Cambrian gas field in the Gaoshiti-Moxi area of the Sichuan Basin is the largest monolithic gas field ever discovered in the past century in this basin[1], with proved gas in place (GIP) of 4 403.8×108 m3 in the Cambrian Longwangmiao Formation and probable gas in place (GIP) of 2 042.9×108 m3 in Member IV of the Sinian Dengying Formation only in the Moxi block. In 2014, more than 1 000 000 m3 high rate gas flow per day was obtained from the Permian Qixia Formation and Maokou Formation in Well Shuangtan 1 in western Sichuan Basin; whereas Well Gucheng 6 and Gucheng 8 in the Gucheng low salient of eastern Tarim Basin

also obtained high and stable natural gas flow[2] of (26.40−47.84)×104 m3 a day, setting the highest gas output record from carbonate series of strata without stimulation. In addition, a major breakthrough has also been made in the Cambrian in Well Zhongshen 1 of central Tarim Basin, showing a bright future of deep gas exploration. There develop multiple sets of excellent source rocks including the Cambrian and Meso-Epiproterozoic in ancient marine series of strata of China. However, most of the source rocks of marine series of strata are in deep superposed basins, with high evolution degree, and mostly in high-over mature stage. The nuclear magnetic resonance (NMR) analysis of kerogen shows that the oil and gas potential carbons content of type I, II and III kerogens are all lower at high to over mature stage, indicating limited gas generation potential[3−4].

Received date: 13 Jan. 2015; Revised date: 10 May 2015. * Corresponding author. E-mail: [email protected] Foundation item: Supported by the China National Science and Technology Major Project (2011ZX05004); PetroChina International Cooperation Project (2008E-07-14). Copyright © 2015, Research Institute of Petroleum Exploration and Development, PetroChina. Published by Elsevier BV. All rights reserved.

ZHAO Wenzhi et al. / Petroleum Exploration and Development, 2015, 42(4): 439–453

It is shown by the study on the quantity, distribution range and concentration degree of dispersed liquid hydrocarbon and thermogenic bitumen that dispersed liquid hydrocarbon wide spread in the formation, including hydrocarbon retained in the source kitchen and liquid hydrocarbon dispersed outside the source rock, can crack into gas, which plays a critical role in the formation of deep gas reservoirs, and is the principal gas source of deep gas accumulation[5−8]. Strengthening the study on key geological problems like oil cracked type gas source kitchens, hydrocarbon accumulation effectiveness and gas geneses of deep marine strata in China, and quantitatively evaluating the cracked gas generated by dispersed liquid hydrocarbon with the genetic method based “five-step method” have not only important theoretical significance for understanding the exploration potential of the Proterozoic-Paleozoic hydrocarbon system, but also important realistic significance for expanding the exploration discovery.

1.

Hydrocarbons retained in source kitchen

The oil expulsion rate is closely related to types of source rock and the source-reservoir collocation[9−14]. Starting with the thermal simulation experiment of hydrocarbon generation and expulsion of different types of source rock, combined with the anatomy of actual geologic profile, the retained hydrocarbon content of different types of source rock formed under different geologic conditions was estimated in this study. Table 1.

Thermal simulation experiment

Thermal simulation experiment of hydrocarbon generation and expulsion is an important means to study the generation and primary migration of hydrocarbon[15−20]. To make the experimental results representative, 15 marine and continental source rock samples were selected by considering the elements like organic abundance, type, maturity and lithology comprehensively, to conduct watered thermal simulation experiment in a confined system. The basic geochemical parameters of the samples are listed in Table 1. The selected samples have the I, II1, II2 and III types of kerogen, TOC of 0.68%−10.08%, including low abundance, high abundance and oil shale; the Ro ranges 0.34%−0.68%, allowing the investigation of the whole process of hydrocarbon generation and expulsion of source rock. The simulation experiment results are shown in Fig. 1, which have the following features: (1) With the increase of thermal evolution level, the oil expulsion rates of all types of source rock have a fast increase stage: this stage of high abundance source rock corresponds to the oil window of Ro from 0.7% to 1.0%, whereas that of the low abundance source rock corresponds to the Ro of 1.0%−1.3%, which results from the massive hydrocarbon expulsion from source rock after the generated liquid hydrocarbon having met the adsorption of source rock organic matter and clay minerals; (2) The differences in lithology, organic matter type and organic abundance, give rise to big discrepancy in oil expulsion rate, and the oil expulsion rate of type I, II1, II2 to III kerogens decline in turn

Basic geochemical characteristics of simulation experiment samples.

Sample No 1

1.1.

Sample source

Lithology

Formation

TOC/%

Tmax/°C

(S1+S2)/ (mg·g−1)

Kerogen IH/ Ro/% (mg·g−1) type

Zhangjiakou, Hebei

Limestone

Pt

0.68

435

0.32

231.00

0.68

Ⅱ2

2

Hequ, Shanxi

Limestone

C

0.68

430

19.05

209.00

0.58

Ⅱ2

3

Well Wei 20 in Dongpu sag, Bohai Bay Basin

Marl

E

4.75

431

47.51

502.00

0.64

Ⅱ1

4

Tangshan, Hebei

Oil shale

C

7.55

434

44.40

564.00

0.60

Ⅰ

5

Maoming, Guangdong

Oil shale

E

10.08

436

56.65

608.00

0.34

Ⅰ

6

Well Yu 24 in Heiyupao sag, Songliao Basin

Mudstone

E

1.40

443

8.96

629.66

0.67

Ⅰ

7

Well Jin 88 in Qijia sag, Songliao Basin

Mudstone

E

3.47

452

29.85

796.00

0.65

Ⅰ

8

Well Xing 2 in Sanxing anticlinal zone, Songliao Basin Well Feng 29-19 in Kongnan buried hill, Bohai Bay Basin

Mudstone

E

5.87

434

47.62

802.10

0.60

Ⅰ

Mudstone

E

7.71

438

52.96

674.58

0.58

Ⅱ1

Well Yan 14 in Yanshan sag, Bohai Bay Basin Mudstone

E

4.47

424

32.54

706.58

0.38

Ⅱ1

Mudstone

E

2.27

423

14.71

622.95

0.38

Ⅱ1

Mudstone

E

4.50

435

18.56

396.55

0.67

Ⅱ2

9 10 11 12 13

Well Shen 6 in Shenqingzhuang buried hill, Bohai Bay Basin Well Gangshen 50 in Dagang buried hill, Bohai Bay Basin

Mudstone

E

2.26

441

4.68

199.67

0.53

Ⅱ2

14

Well Ban 59 in Banqiao sag, Bohai Bay Basin Mudstone

Well Qi 86 in Qibei slope, Bohai Bay Basin

E

1.05

441

2.44

221.19

0.68

Ⅱ2

15

Well Yu 19 in Heiyupao sag, Bohai Bay Basin Mudstone

E

1.10

439

1.13

88.00

0.54

Ⅲ

Note: Tmax—Source rock pyrolysis peak temperature; S1—Free hydrocarbon content; S2—Pyrolytic hydrocarbon content; IH—Hydrogen index; Ro—Vitrinite reflectance.

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Fig. 1.

Comparison of oil expulsion rate of different types of source rock.

on whole; the higher the TOC, the higher the oil expulsion rate is, and the oil expulsion rate of oil shale is the highest, reaching about 80%; on the contrary, the source rock with lower TOC has lower oil expulsion rate, mostly less than 40% in liquid hydrocarbon window, and even only about 20%. 1.2.

Actual geologic profile

To analyze the oil expulsion rate of source rock in actual geologic profiles and compare it with the thermal simulation experiment, the lacustrine source rocks encountered in Well Gangshen 48, Xinglong 1 and Niudong 1 of the Bohai Bay Basin were selected to conduct analysis. The specific method is as follows: conducting cluster sampling on the drilling well profile, measuring the chloroform bitumen “A” content and the TOC, taking the ratio of chloroform bitumen “A” content to TOC as the residual hydrocarbon content, on this basis, making hydrocarbon generation trend line, taking the difference between the total envelope area of hydrocarbon generation trend line of a certain evolution stage and the residual hydrocarbon area as the hydrocarbon expulsion area, and the ratio of it to the total hydrocarbon generation area as the apparent oil expulsion rate of this evolution stage. The source rock samples of the above 3 wells are divided into two types: sand-mudstone interbeds representing good source-reservoir collocation; and large set of mudstone section representing poor source-reservoir collocation. The profile analysis not only observed the retained hydrocarbon quantity of different types of source rock, but also investigated the effect of single bed source rock thickness on oil expulsion rate. The Ro of the mudstone is 0.6%−1.0%, at low mature - mature stage. The analysis results are shown in Fig. 2, which have the

following features: (1) The oil expulsion rate of mudstone is 20%−80%, mostly between 30% and 70%; (2) On the whole, the oil expulsion rate increases with the rise of organic abundance; when the TOC of source rock is 2%, the oil expulsion rate is about 50%, when less than 2%, the oil expulsion rate is mostly less than 50% in liquid hydrocarbon window; however, for the mudstone section with TOC of 4%−6%, the oil expulsion rate is as high as 75%; which tally with the thermal simulation experiment data; (3) As the maturity rises, the oil expulsion rate of source rock increases, and at high evolution stage, the oil expulsion rate tends to be constant; and (4) The thickness of source rock has a marked effect on the oil expulsion rate, e.g., a set of 150 m thick continuous mudstone section developed at 3 906−4 056 m in Well Gangshen 48, is only

Fig. 2. Oil expulsion rate of Tertiary lacustrine source rock in Bohai Bay Basin.

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about 30% in oil expulsion rate, far lower than the oil expulsion rate (averaging 60.4%) of mudstone in the laminated sand and mudstone section with the same organic abundance (2%−4%), indicating that the thick source rock restricts the effective expulsion of liquid hydrocarbon and makes more liquid hydrocarbon retained in it.

2. Geologic data statistics of dispersed liquid hydrocarbon content Statistics on fluorescence samples, thermogenic bitumen and rock pyrolysis parameter S1 data all confirm that a substantial amount of liquid hydrocarbon is retained inside the source rock. Besides, a large amount of dispersed liquid hydrocarbon also exists in the paths of secondary migration, especially in the preferential migration pathways. 2.1. Statistics on number of samples with fluorescence and thermogenic bitumen Currently, more analysis has been conducted on the soluble organic content in the source rock, but less study on the soluble organic content in reservoirs. If the formation temperature has not reached the one at which substantive crude oil cracks into gas, the organic matter dispersed inside and outside

source rock still exists in the state of liquid hydrocarbon, with the features of stronger sample fluorescence and high mineral asphaltic matrix content. Fluorescence observation of 2178 samples taken from Paleozoic reservoir in 148 wells of the Tarim Basin, shows that 1876 samples taken from 145 wells have fluorescence, accounting for a very high proportion, reflecting the extensive existence of dispersed liquid hydrocarbon outside the source; the fluorescence intensity of different samples can be divided into three levels: strong, moderate and weak (Fig. 3), reflecting the multiphasic formation of dispersed soluble organic matter and different heating histories experienced by them at late stage. Thermogenic bitumen is the thermal cracking residual matter of soluble organic matter when it reaches the cracking temperature. Thermogenic bitumen observation of 2436 thin section from 67 wells in the Tarim Basin, show the samples of 54 wells have bitumen shows, accounting for a very high proportion. 2.2.

Statistics on rock pyrolysis parameters

In principle, the rock pyrolysis parameter S1 can represent the hydrocarbon content retained in the source rock, however, because some high boiling point heavy components donot expulse before 300 °C in the course of pyrolysis, overlap with

Fig. 3. Fluorescent characteristics of Paleozoic reservoir samples in Tarim Basin. (a) Intercrystalline straw yellow fluorescence, Well He4, 4 359.99 m, limestone, reflecting fluorescence, ×260; (b) Mineral asphaltic matrix with strong fluorescence, Well Yingdong2, 4 803.2 m, siliceous mudstone, reflecting fluorescence, ×260; (c) Mineral asphaltic matrix with weak fluorescence, Well Yingdong2, 4 355.6 m, gray mudstone, reflecting fluorescence, ×260; (d) Mineral asphaltic matrix with moderate to weak fluorescence, Well He3, 4 024.37 m, limestone, reflecting fluorescence, ×260.

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S2 peak, and are also important gas generation source at high-over mature stage, it is necessary to conduct correction to the conventional pyrolysis parameter S1. In this paper, the Cambrian-Sinian rock samples taken from Well Gaoshi 2 and Moxi 11 in the Gaoshiti-Moxi area of the Sichuan Basin were selected to compare rock pyrolysis parameter before and after chloroform extraction, the sum of the S2 difference ΔS2 before and after extraction and the S1 (S1i) before extraction is marked as the corrected S1 (S1c), and the data regression analysis of them shown in Fig. 4 indicates that S1c is twice the S1i. As per this standard, the pyrolysis parameter of marine and continental source rocks in the basins like Tarim, Sichuan, Ordos, Songliao and Bohai Bay were corrected, and correlation analysis of them with the thermal evolution parameter Tmax was conducted (Fig. 5). The hydrocarbon content retained in the source rock differs largely at different evolution stages: it is the highest in liquid hydrocarbon window, indicating that a large amount of liquid hydrocarbon is still retained in the source rock after scale hydrocarbon generation and expulsion at this stage; whereas at high to overmature stage, the hydrocarbon content retained in the source rock reduces sharply due to massive cracking of retained hydrocarbon. Therefore, thermal evolution level shall be considered while conducting statistics on the hydrocarbon content retained in the source rock. The statistical results show that for the marine source rock in the Tarim Basin, in liquid hydrocarbon window with Tmax ranging 435−455 °C, the average hydrocarbon content

Fig. 5.

retained in limestone and mudstone samples are 0.14 mg/g and 0.47 mg/g respectively, the proportion of samples with retained hydrocarbon of more than 0.10 mg/g are 51.9% and 63.5% respectively; whereas at high-over mature stage with Tmax of more than 455 °C, the average hydrocarbon content retained in limestone and mudstone samples are 0.10 mg/g and 0.17 mg/g respectively, and the proportion of samples with retained hydrocarbon of more than 0.10 mg/g are 38.1% and 41.8% respectively. Obviously, a large part of hydrocarbons is still retained inside source rock, enough to ensure the scaled gas cracking at high-over mature stage.

3. Thermodynamic conditions for dispersed liquid hydrocarbon to crack into gas Different types of source rock generate crude oils different

Fig. 4.

Correction curve of source rock pyrolysis parameter S1.

Comparison of hydrocarbon content retained inside source rock at different evolution stages.

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in chemical composition and physical property, which lead to differences in cracking commencing temperature, massive cracking time and cracking finish temperature. The essence of crude oil cracking is the conversion from long chain hydrocarbons to short chain hydrocarbons, and finally methane. The variation rate of different components are greatly different at different thermal evolution stages; taking the different kinds of marine crude oil in the Lunnan area of the Tarim Basin as an example, the distribution of activation energy for the crudes cracking into gaseous hydrocarbons and methane are shown in Fig. 6. The average activation energy for light oil to crack into gaseous hydrocarbon is 248.8 kJ/mol, and that for light oil to crack into methane is 260.8 kJ/mol; whereas the average activation energy for heavy oil to crack into methane is 288.1 kJ/mol, much higher. Lithology and fluid pressure can also affect the timing of crude cracking into gas[21−27], and the preliminary research results are listed in Tables 2 and 3.

generated by pyrolysis at 300 °C and 600 °C are shown in Fig. 7. The pyrolysis gas generated by bitumen at different key temperature points represents different genesis of natural gas. The gas generated at temperature lower than 300 °C is dominantly absorbed gas of rock, which is affected by its origin,

4. Composition characteristics of cracked gas generated by dispersed liquid hydrocarbon In the course of cracking of dispersed liquid hydrocarbons into gas, the catalysis of inorganic minerals not only affects the timing of cracking, but also the light hydrocarbon composition of cracked gas[28−33]. The preliminary research results reveal that compared with cracked gas from accumulated liquid hydrocarbon, cracked gas from retained hydrocarbon is more rich in cyclanes like methylcyclohexane[3, 5] (Table 4). To find out whether the cracked gas from dispersed liquid hydrocarbon outside source is also characterized by rich cyclanes like methylcyclohexane, dolomite samples containing bitumen taken from the 2nd member of Sinian Dengying Formation in Well Moxi 11 in the Moxi area of the Sichuan Basin was selected to conduct pyrolytic gas generation modeling experiment; the asphalt content of the 3 samples were 0.1%, 0.3% and 0.9% respectively, and the converted initial liquid hydrocarbon contents are about 0.2%, 0.6% and 1.8% respectively. The light hydrocarbon chromatograms of gas samples Table 2.

Fig. 6. Distribution of activation energy for different kinds of crude oil cracking into gaseous hydrocarbons and methane.

Effect of reservoir lithology on the timing of liquid hydrocarbon cracking into gas[21−27]. Ro corresponding to the principal gas generation stage/%

Sample Pure crude oil

1.5−3.8

Crude oil + mudstone (Well Lunnan 63 in Tarim Basin)

1.3−3.4

Crude oil + limestone (Well Lunnan 41 in Tarim Basin)

1.2−3.2

Crude oil + sandstone (Well Lunnan 63 in Tarim Basin)

1.4−3.6

Note: The experimental crude oil was from Well Lungu 2 in the Tarim Basin. Table 3.

Effect of pressure on the timing of liquid hydrocarbon cracking into gas[21−27]. Pressure/MPa

Heating rate/(°C·h−1)

Experimental results

1

50

20

2

200

20

Principal gas generation stage does not change remarkably in experiment 1 and experiment 2

3

50

2

4

200

2

Experiment No

Compared with experiment 3, when reaching the same conversion rate, the temperature lags by 30 °C and Ro by 2%−3% in experiment 4

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Table 4. Comparison of light hydrocarbon composition of cracked gas generated by dispersed and accumulated liquid hydrocarbons[3,5]. Concentration of original liquid hydrocarbon/%

Liquid hydrocarbon type Liquid hydrocarbon dispersed inside source

1 5 20

Liquid hydrocarbon highly accumulated inside source

50 100 0.2

Liquid hydrocarbon dispersed outside source

Fig. 7.

Experimental series 1% crude oil + 99% montmorillonite 5% crude oil + 95% montmorillonite 20% crude oil + 80% montmorillonite 50% crude oil + 50% montmorillonite 100% crude oil Dolomite with 0.1% asphalt content

0.6

Dolomite with 0.3% asphalt content

1.8

Dolomite with 0.9% asphalt content

Experimental temperature/°C

Ratio of methylcyclohexane to normal heptane content

550

3.48

550

3.38

550

0.44

550

0.44

550 300 600 300 600 300 600

0.43 20.0 0.58 0.54 0.08 0.37 0.57

Light hydrocarbon characteristics of cracked gas generated by dispersed bitumen in reservoirs.

thermal maturity, and interchange and diffusion experienced by it at late stage, and what is shown now is the final result of all the above factors; as listed in Table 4, at 300 °C, the light hydrocarbon composition of pyrolysis gas of the 3 samples are largely different, and not any common characteristic is exhibited. The gas composition at 600 °C represents the characteristics of bitumen cracked gas, and the common characteristic of the 3 samples is that all of them are not characterized by high methylcyclohexane content. Based on the study of Mango et al[28, 30], the generation of cyclanes like methylcyclohexane is possibly related to the isomerization or steady-state catalysis of cations in the acidic clay; for the cracking of retained hydrocarbons, due to the participation of

clay minerals, the cracking mode is dominated by catalytic cracking, however, there is no catalytic cracking action of clay minerals in dolomite. This explains why the content of cyclanes like methylcyclohexane in the cracked gas of dispersed liquid hydrocarbon in reservoir is lower than that inside source.

5. Hydrocarbon accumulation contribution and exploration significance of cracked gas from dispersed liquid hydrocarbon The cracked gas from dispersed liquid hydrocarbon is the principal gas source of deep large gas fields, whereas the 3 types of occurrence states of liquid hydrocarbon decide the

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source of cracked gas, affecting the gas generation potential and gas accumulation time, and then the exploration prospect of deep gas in turn. 5.1. Light hydrocarbon characteristics of deep gas in Sichuan Basin and Tarim Basin In this study, the light hydrocarbon data of natural gas taken from 38 wells in 6 gas fields, Gaoshiti-Moxi, Weiyuan, Luojiazhai and Puguang in the Sichuan Basin and Gucheng and Hetianhe in the Tarim Basin was collected and analyzed, and the light hydrocarbon spectrum of key wells are shown in Fig. 8. Moreover, the light hydrocarbon data of natural gas of Lunnan area, Mandong-Yingjisu area, Tazhong major horst

Fig. 8.

zone and north Tazhong slope in the Tarim Basin in the previous studies was also collected. The methylcyclohexane to normal heptane ratio of light hydrocarbon data of natural gas samples taken from the above areas are shown in Fig. 9, in which the gas genesis is converted from cracked gas of dispersed liquid hydrocarbon to cracked gas of paleo-oil reservoir in direction of the arrow, i.e., as the concentration of liquid hydrocarbon increases gradually, the methylcyclohexane content in natural gas reduces gradually. Cutting off at the methylcyclohexane to normal heptane ratio of 1, area A is the distribution area of cracked gas of paleo-oil reservoir or kerogen degradation gas. It should be noted that area B shows the natural gas taken from the Puguang gas field where the

Light hydrocarbon spectrum characteristics of natural gas taken from key wells in the Sichuan and Tarim basins.

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Fig. 9. Distribution of ratio of methylcyclohexane to normal heptane content in natural gas of key gas reservoirs in the Sichuan and Tarim basins.

reservoir is the Triassic Feixianguan Formation, and it is also rich in cyclanes like methylcyclohexane due to the contribution of underlying Permian Longtan coal measure hydrocarbon source kitchen. The cracked gas of paleo-oil reservoir and kerogen degradation gas in area A are mainly distinguished from each other based on the composition and isotopic data of gas component C1-C4 and the comprehensive analysis of regional thermal evolution history, tectonic evolution history and hydrocarbon accumulation conditions. The natural gas in Tazhong major horst zone, north Tazhong slope and Ordovician of Lunnan area is dominantly kerogen degradation gas, including the associated gas of mature stage and condensate gas of highly mature stage. Based on whether the ratio of methylcyclohexane to normal heptane content in light hydrocarbon of natural gas is higher than 1, the distribution and quantity of thermogenic bitumen and the analysis on tectonic evolution history, it is concluded that the natural gas of Gaoshiti-Moxi and Weiyuan gas fields in the Sichuan Basin and of Hetianhe and Mandong-Yingjisu (Ordovician) gas fields in the Tarim Basin is dominated by cracked gas from dispersed liquid hydrocarbon, the natural gas of Gucheng area (Wells Gucheng 6, Gucheng 9 and Gucheng 12) in the Tarim Basin is dominated by cracked gas of semi-accumulated-semi-dispersed type liquid hydrocarbon and paleo-oil reservoir, whereas the natural gas of Luojiazai and Puguang gas fields in the Sichuan Basin is dominated by cracked gas of paleo-oil reservoir. 5.2. Accumulation process of cracked gas from dispersed liquid hydrocarbon The above study shows that the supergiant Gaoshiti-Moxi

gas field in the Sichuan Basin is a large gas field formed mainly by cracked gas from dispersed liquid hydrocarbon, where major gas-bearing series of strata consist of Sinian Deng II Member, Deng IV Member and Cambrian Longwangmiao Formation. The hydrocarbon generation evolution history of this area is analyzed by taking Well Gaoshi 1 as an example. Well Gaoshi 1, located at structural high of the Leshan-Longnüsi Paleohigh, has Sinian Deng III Member, Doushantuo Formation and Cambrian Qiongzhusi Formation black shale. Deng III Member mudstone, 20-30 m thick and 1.13% in average TOC, is a set of good source rock. The Qiongzhusi Formation source rock with good hydrocarbon generation conditions and big thickness, is a set of high quality source rock. These two sets of source rocks entered oil threshold from the end of Ordovician to Silurian; afterwards, affected by uplifting, the hydrocarbon generation terminated; however, they were deeply buried once again and entered secondary hydrocarbon generation stage after Late Permian. The tectonic evolution not only controlled the timing of the liquid hydrocarbon converting to gas, but also affected the accumulation scale of late cracked gas by controlling the multiple occurrence states of early liquid hydrocarbon. At the end of Silurian, the Gaoshiti-Moxi buried structure was not yet formed[34−36], and the liquid hydrocarbon generated in Deng III Member and Qiongzhusi Formation source rock was not possible to accumulate in a large scale there; while the liquid hydrocarbon generated in the Late Permian-Triassic could migrate to the Leshan-Longnüsi Paleohigh, and accumulate in the structural high to form paleo-oil reservoir, whereas in the slope area, the liquid hydrocarbon occurred in a dispersed state. The distribution and characteristics of thermogenic bi-

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tumen content are shown in Figs. 10 and 11 respectively. Developed in the large paleohigh and its slope position, the Gaoshiti-Moxi gas field went through two main stages of hydrocarbon reservoir formation: liquid hydrocarbon generation and preservation at early stage and cracked gas accumulation at late stage. Controlled by the topographic slope at the time of hydrocarbon expulsion, liquid hydrocarbon accumulated in the formation at different abundances. In the steeper slope (higher than 3°), the liquid hydrocarbon accumulated in a large scale at structural high with high concentration, forming large paleo-oil reservoirs; in the gentler slope, the liquid hydrocarbon, not so highly concentrated, but in a semi-accumulated to semi-dispersed state, with dispersibility greater than accumulation, had lower requirements on the preservative conditions; whereas in the more gentler slope (lower than 1°), the liquid hydrocarbon could not accumulate, and was in a dispersed state (Fig. 12). The quantitative evaluation on cracked gas from dispersed liquid hydrocarbon involves 5 aspects of contents, which can be summarized as “five-step” quantitative evaluation method: (1) study on distribution ratio and quantity of liquid

Fig. 10. Basin.

hydrocarbon inside and outside source rock; (2) study on major distribution and enrichment zone of liquid hydrocarbon dispersed outside source rock; (3) study on cracked gas conversion rate of liquid hydrocarbon in different occurrence states; (4) study on hydrocarbon systems in the study area; and (5) quantitative evaluation and resource assessment on cracked gas from dispersed liquid hydrocarbon. With the help of genetic method based quantitative evaluation “five-step method” of cracked gas from dispersed liquid hydrocarbon established based on hydrocarbon generation and expulsion simulation experiment, actual geologic profile anatomy, data statistics and numerical modeling study, the overall systematic evaluation of cracked gas from liquid hydrocarbon dispersed inside and outside source rock, cracked gas of paleo-oil reservoir and kerogen degradation gas has been realized. The “five-step method” was adopted to assess the contribution of Sinian-Cambrian source rock to gas resources in the Sichuan Basin. The study results show that the contribution proportion of liquid hydrocarbon dispersed inside Doushantuo Formation, Deng III Member and Qiongzhusi Formation source rocks to Deng II Member gas are 21%, 10% and

Superimposed map of present top Sinian structure and bitumen, gas and water distribution in central and western Sichuan

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Fig. 11. Thermogenic bitumen characteristics of key wells (Po—pore; An—anthraxolite; Cl—clay mineral; Py—pyrite; Do—dolomite). (a) Well Gaoshi 7, Deng IV Member, bitumen filling in pores; (b) Well Gaoshi 1, Deng IV Member, bitumen filling in dissolved pores and fractures; (c) Well Moxi 12, Longwangmiao Formation, aplite-mesocrystalline residual dolarenite, bitumen filling intergranular dissolved pores; (d) Well Gaoshi 10, argillaceous dolomite, vein anthraxolite filling along wall in pores; (e) Well Moxi 17, argillaceous dolomite, locally dominated by clay minerals in which microgranular primary anthraxolite is densely distributed; (f) Well Moxi 8, Deng IV Member, sparry algae arenitic dolomite, dolomite and bitumen filling intergranular pores partially or completely.

2% respectively, and the contribution proportion of liquid hydrocarbon dispersed outside source rock reaches 67% (Fig. 13a); while the traditional assessment method not considering the contribution of liquid hydrocarbon dispersed outside source rock to natural gas worked out the contribution proportion of Doushantuo Formation, Deng III Member and Qiongzhusi Formation source rocks at 67%, 30% and 3% respectively (Fig. 13b). The contribution proportion of liquid hydrocarbon dispersed inside Doushantuo Formation, Deng III Member and Qiongzhusi Formation source rocks to Deng IV Member gas are 1%, 23% and 38% respectively, and the contribution proportion of liquid hydrocarbon dispersed outside source rock reaches 38% (Fig. 13c); while the traditional assessment method not considering the contribution of liquid hydrocarbon dispersed outside source rock to natural gas estimated the contribution proportion of Doushantuo Formation, Deng III Member and Qiongzhusi Formation source rocks at 2%, 22% and 76% respectively (Fig. 13d). Located at the Hebaochang structure at structural low of south flank slope of the Leshan-Longnüsi Paleohigh, Well Heshen 1 (Fig. 10) drilled recently tested a 12.9×104 m3 daily industrial gas flow from Deng II Member (5 400−5 440 m), marking a new important exploration breakthrough. From the perspective of hydrocarbon accumulation conditions, apart from existence of paleohigh at Sinian depositional stage, the structure where the well lies has been at structural low for a long term at late stage, and is new. The gas source can only come from the Sinian system itself, indicating the reservoir is a product of accumulation by cracked gas from retained liquid hydrocarbons.

5.3. Accumulation of cracked gas from liquid hydrocarbon dispersed inside source rock and shale gas exploration The discovery of thermogenic shale gas is a powerful evidence for in-situ accumulation of cracked gas from retained hydrocarbon. Thermogenic shale gas is a kind of unconventional gas mainly distributed in the organic rich shale concentrated sections with certain thickness (generally thicker than 15 m), and the ideal Ro of 1.1%−3.0% (Ro too high or too low is unfavorable for the formation and preservation of cracked natural gas). In addition, both the preservation conditions of the roof and floor of organic rich shale concentrated section and the organic matter parent material type all have strong effects on the preservation and accumulation of economic shale gas. Shale gas resources have been discovered in 48 basins of 32 countries in the world, with a total shale gas in place of about 623×1012 m3 and technically recoverable resources of 187×1012 m3; whereas in China, the geologic resources of shale gas reaches 100×1012 m3, and the recoverable resources are more than 20×1012 m3[37−40].

6.

Conclusions

Based on the hydrocarbon generation and expulsion simulation experiment of different types of source rocks and the actual profile study of different source-reservoir assemblages, the oil expulsion rate of different types of source rocks under different geologic settings were estimated. Ranging from 20% to 80%, the oil expulsion rate of source rock is closely related to the organic abundance, type, evolution level, source rock lithology, thickness and carrier layer development level, etc. On the whole, the higher the organic content, the higher the

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Fig. 12.

Liquid hydrocarbon distribution in the Sinian-Cambrian of Sichuan Basin.

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Fig. 13.

Contribution of different types of hydrocarbon source kitchens to natural gas of Deng II and Deng IV Members.

oil expulsion rate is. Cutting off at TOC of 2%, the oil expulsion rate is about 50%, and that of oil shale can reach 80%; the better the organic type, the higher the oil expulsion rate is; and the oil expulsion rate of thick mudstone is far lower than that of sand and mudstone interbed section with the same organic abundance. Sand mudstone interbeds with TOC of 2%−4% are 60% on average in oil expulsion rate; while, the oil expulsion rate of thick mudstone section can drop to 30%. The quantity statistics on hydrocarbon retained inside source rock, thermogenic bitumen and reservoir fluorescence all confirm the wide distribution of dispersed liquid hydrocarbon. Based on the study on liquid hydrocarbon dispersed inside and outside source rock, timing of paleo-oil reservoir cracking into gas and factors affecting the timing, the principal gas generation stage of oil cracking gas source kitchens is clarified. The comparison experiment of crude cracked gas and kerogen degradation gas reveals that the kerogen degradation gas is massively generated at the stage of Ro ranging 1.0%−1.8%, mainly lower than 1.6%; whereas the crude cracked gas is mostly generated at Ro higher than 1.6%, and the generation time of crude cracked gas is obviously later than that of kerogen degradation gas. The cracked gas volume of unit liquid organic matter is much larger than the degrada-

tion gas volume of equivalent kerogen, and the former is about 4 times the latter[5]. The dispersed liquid hydrocarbon in mudstone, carbonate rock and sandstone, are different somewhat in timing of cracking due to the catalysis of different kinds of minerals: the principal gas generation stage of crude oil dispersed in carbonate rock, mudstone and sandstone are at the Ro of 1.2%−3.2%, 1.3%−3.4% and 1.4%−3.6% respectively. The effect of pressure on gas generation from crude oil cracking is inhibitory on the whole. It is confirmed by exploration practices that conventional and unconventional gas reservoirs can be formed by cracked gas from dispersed liquid hydrocarbon. The gas generated from liquid hydrocarbon cracking is characterized by late timing, little dissipation volume, high accumulation effectiveness and large resource potential. Based on the analysis on light hydrocarbon characteristics of cracked gas generated by liquid hydrocarbon dispersed outside source rock, combined with the light hydrocarbon analysis data of gas samples taken from the Sichuan and Tarim basins, it is clarified that the ratio of methylcyclohexane to normal heptane content being 1 is an important parameter to discriminate cracked gas generated by dispersed liquid hydrocarbon from cracked gas generated by paleo-oil reservoirs. The natural gas of Gaoshiti-Moxi and

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Weiyuan gas fields in the Sichuan Basin and of the Hetianhe gasfield in the Tarim Basin is dominated by cracked gas from dispersed liquid hydrocarbon, the natural gas of Gucheng area (Wells Gucheng 6, Gucheng 9 and Gucheng 12) in the Tarim Basin is dominated by cracked gas of semi-accumulated – semi-dispersed type liquid hydrocarbon and paleo-oil reservoir, whereas that of Luojiazhai and Puguang gas fields in the Sichuan Basin is dominated by cracked gas from paleo-oil reservoir. The various forms of gas supply from paleo-oil reservoirs in large paleohighs and their slope positions, semi-accumulated – semi-dispersed type liquid hydrocarbon and retained hydrocarbon inside source rock have laid gas source foundation for the formation of deep marine large and supergiant gas fields.

2009, 27(1): 153–161. [8]

Zhao Wenzhi, Wang Zhaoyun, Wang Hongjun, et al. Cracking conditions of oils existing in different modes of occurrence and forward and backward inference of gas source rock kitchen of oil cracked type. Geology in China, 2006, 33(5): 952–965.

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Acknowledgements

of petroleum formation, destruction, and expulsion from la-

Dr. Yuan Qingdong and Dr. Zhang Liping from the PetroChina Research Institute of Petroleum Exploration and Development provided the data of some risk wells and the Tarim Basin, Dr. Ma Wei and Dr. Wang Yifeng from the Key Laboratory of Gas Reservoir Formation and Development, CNPC, helped to accomplish some hydrocarbon generation and expulsion simulation experiments, we would like to take this opportunity to express our appreciation to all of them.

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