Restoration of “original organic carbon content” and its relationship with micropore evolution of the Middle Jurassic source rock in the Muli Depression, Southern Qilian Basin
Shi-ming LIU
, 1
,
Fu-rong TAN
, 2
,
Shu-heng TANG
1
,
Jin-xi WANG
3
,
Wei-chao WANG
4
,
Yong-hong LI
4
Expand
1. School of Energy Resource,China University of Geosciences,Beijing 100083,China
2. Shaanxi Mineral Resources and Geological Survey,Xi’an 710068,China
3. Key Laboratory of Resource exploration Research of Hebei Province,Handan 056038,China
4. China National Administration of Coal Geology,Beijing 100038,China
Received date: 2020-10-20
Revised date: 2020-12-23
Online published: 2021-07-22
Supported by
The National Natural Science Foundation of China(41702144)
Fundamental Research Funds for the Central Universities(2652018234)
Organic carbon content (TOC) of shale is one of the significant parameters for shale oil and gas assessment. However, the generation and expelling of hydrocarbons in shale was influenced by thermal evolution of organic matter, and a certain deviation occurred using present TOC to evaluate and predict shale oil and gas resources. Therefore, the restoration of original organic carbon from source rocks is of great significance for the evaluation of oil and gas resources. The Muli Depression, located in the northeast of the Southern Qilian Basin, was widely developed the Middle Jurassic continental shale. The Middle Jurassic is composed of a set of fine clastic rocks deposited in the lacustrine and delta setting. Multiple sets of thick dark organic-rich shales were developed, which have great hydrocarbon generation potential, and are found with abundant petroleum resources, and the thermal maturity of organic matter was from low maturity to high maturity, which provides the necessary conditions for the restoration of the original organic carbon content. In this paper, the original organic carbon content of Middle Jurassic shale in Muli Depression was calculated by material balance method using rock pyrolysis data. The results suggest that the ratio of original to present TOC content of the Middle Jurassic shale is between 1.04 and 1.62, and increases with the higher thermal maturity. No obvious relationship between the present TOC content and the pore development of organic matter in the Middle Jurassic shale. However, the difference between original and present TOC content could effectively assess the development of the micropores of organic matter in shale. The organic matter is mainly types Ⅱ and Ⅲ with thermal evolution (Tmax) greater than 440 ℃, and the transform and expulsion of hydrocarbons is greater than 40%. Compared with the minerals content (quartz and clay minerals content), Tmax and present TOC content, the original TOC content has a better correlation with the shale Langmuir volume, which combined with Tmax, could be more reasonable to evaluate the shale oil and gas adsorption capacity. Therefore, the original organic carbon content provides theoretical basis for source rocks evaluation, as well as a new idea for oil and gas exploration in the Muli Depression.
Fig.3 Relationship between organic matter conversion rate and hydrocarbon expulsion rate and thermal evolution of Jurassic source rocks in Muli Depression
WANG P W, CHEN Z H, PANG X Q, et al. Revised models for determining TOC in shale play: Example from Devonian Duvernay shale, western Canada sedimentary basin[J]. Marine & Petroleum Geology,2016,70:304-319.
2
JIANG F J, CHEN J, XU Z Y, et al. Organic matter pore characterization in lacustrine shales with variable maturity using nanometer-scale resolution X-ray computed tomography[J]. Energy & Fuels,2017,31(3):2669-2680.
3
BOWKER K A. Barnett shale gas production, Fort Worth Basin: Issues and discussion[J].AAPG Bulletin,2007,91(4):523-533.
WEI G Q,WANG Z H,LI J, et al. Characteristics of source rocks,resource potential and exploration direction of Sinian and Cambrian in Sichuan Basin[J].Natural Gas Geoscience,2017, 28(1):1-13.
5
CHEN Z H,JIANG C Q. A data driven model for studying kerogen kinetics with application examples from Canadian sedimentary basins[J]. Marine and Petroleum Geology,2015,67:795-803.
ZOU C N, DU J H, XU C C, et al. Formation, distribution, resource potential and discovery of the Sinian-Cambrian giant gas field,Sichuan Basin,SW China[J]. Petroleum Exploration and Development,2014,41(3):278-293.
LUO S Y, CHEN X H, YUE Y, et al. Analysis of sedimentary-tectonic evolution characteristics and shale gas enrichment in Yichang area,Middle Yangtze[J].Natural Gas Geoscience,2020,31(8): 1052-1068.
WANG P W, CHEN Z H, JIN Z J, et al. Optimizing parameter “total organic carbon content” for shale oil and gas resource assessment:Taking west Canada sedimentary basin Devonian Duvernay shale as an example[J].Earth Science,2019,44(2): 504-512.
9
WU S T, ZHU R K, CUI J G, et al. Characteristics of lacustrine shale porosity evolution, Triassic Chang 7 member, Ordos Basin, NW China[J]. Petroleum Exploration and Development, 2015,42(2):185-195.
10
LOUCKS R G, REED R M, RUPPEL S C, et al. Spectrum of pore types and networks in mudrocks and a descriptive classification for matrix-related mudrock pores[J]. AAPG Bulletin, 2012,96(6):1071-1098.
11
LU J M, RUPPEL S C, ROWE H D. Organic matter pores and oil generation in the Tuscaloosa marine shale[J].AAPG Bulletin,2015,99(2): 333-357.
QIN J Z, JIN J C, LIU B Q. Thermal evolution pattern of organic matter abundance in various marine source rocks[J]. Oil & Gas Geology,2005,26(2):177-184.
13
PETERS K E, WALTERS C C, MOLDOWAN J M. The Biomarker Guide, Volume 1, Biomarkers and Isotopes in the Environment and Human History[M].Cambridge: Cambridge University Press,2005:471.
14
CHEN Z H, JIANG C Q. A revised method for organic porosity estimation using rock-eval pyrolysis data, example from Duvernay shale in the western Canada sedimentary basin[J].AAPG Bulletin,2016,100(3):405-422.
15
MODICA C J, LAPIERRE S G. Estimation of kerogen porosity in source rocks as a function of thermal transformation: Example from the Mowry shale in the Powder River Basin of Wyoming[J].AAPG Bulletin,2012,96(1):87-108.
16
PEPPER A S, CORVI P J. Simple kinetic models of petroleum formation: Part I. Oil and gas generation from kerogen[J]. Marine and Petroleum Geology,1995,12(3):291-319.
ZHU Y H, LIU Y L, ZHANG Y Q. Formation conditions of gas hydrates in permafrost of the Qilian Mountains, north-west China[J]. Geological Bulletin of China, 2006, 25(1-2): 58-63.
CHENG Q S, GONG J M, ZHANG M, et al. Geochemical characteristics of Jurassic source rocks in the Muli coal field, Qilian Mountain permafrost[J].Geoscience,2016,30(6):1408-1416.
ZHU Y H, ZHANG Y Q, WEN H J, et al. Gas hydrates in the Qilian Mountain permafrost, Qinghai, northwest China[J]. Acta Geologica Sinica,2009,83(11):1762-1771.
TAN F R, LIU S M, CUI W X, et al. Origin of gas hydrate in the Juhugeng mining area of Muli coal field[J]. Acta Geologica Sinica,2017,91(5):1158-1167.
22
LIU S M, TAN F R, HUO T, et al. Origin of the hydrate bound gases in the Juhugeng Sag, Muli Basin, Tibetan Plateau[J].International Journal of Coal Science & Technology,2020,7:43-57.
HAO A S, WANG R, LI J, et al. Evaluation and petroleum exploration potential of hydrocarbon source rocks in the Muli Depression, southern Qlian Basin, China[J]. Bulletin of Mineralogy, Petrology and Geochemistry, 2017, 36(1): 134-140.
24
JUSTWAN H, DAHL B. Quantitative hydrocarbon potential mapping and organofacies study in the Greater Balder area, Norwegian North Sea[C]// DORE A G, A VININO A, Petroleum Geology, Northwest Europe and Global Prospective: Proceedings of the 6th Petroleum Geology Conference: Geological Society, London, 2005:1317-1329.
25
LAFARGUE E, ESPITALIE J, JACOBSEN T, et al. Experimental simulation of hydrocarbon expulsion[J].Organic Geo-chemistry,1990,16(1-3): 121-131.
26
BURNHAM A K, BRAUN R L. Development of a detailed model of petroleum formation,destruction,and expulsion from lacustrine and marine source rocks[J].Organic Geochemistry, 1990,16(1-3):27-39.
27
JARVIE D M. Shale resource systems for oil and gas: Part 2-Shale-oil resource systems[J]∥BREYER J A.Shale reservoirs-Giant resources for the 21st century.AAPG Memoir,2012,97: 89-119.
28
COOLES G P,MACKENZIE A S,QUIGLEY T M. Calculation of petroleum masses generated and expelled from source rocks[J]. Organic Geochemistry,1986,10(1):235-245.
29
CHOW N, WENDTE J, STASIUK L D. Productivity versus preservation controls on two organic-rich carbonate facies in the Devonian of Alberta: Sedimentological and organic petrological evidence[J]. Bulletin of Canadian Petroleum Geology,1995,43(4):433-460.
30
NOBLE R A, KALDI J G, ATKINSON C D. Oil saturations in shales:Applications in seal evaluation[J].AAPG Memoir,1997,67:13-29.
31
ZUO Y H, WANG Q F, LU Z Q, et al. Tectono-thermal evolution and gas source potential for natural gas hydrates in the Qilian Mountain permafrost, China[J]. Journal of Natural Gas Science and Engineering, 2016, 36: 32-41.
32
POMMER M, MILLIKEN K. Pore types and pore-size distributions across thermal maturity, Eagle Ford Formation, southern Texas[J].AAPG Bulletin,2015,99(9):1713-1744.
33
CURTIS M E, CARDOTT B J, SONDERGELD C H, et al. Development of organic porosity in the Woodford Shale with increasing thermal maturity[J]. International Journal of Coal Geology. 2012,10 (23):26-31.
FAN D W, LU Z Q, LI G Z, et al. Organic geochemical characteristics of the Carboniferous-Jurassic potential source rocks for natural gas hydrates in the Muli Depression, southern Qilian Basin[J]. Oil & Gas Geology,2020,41(2):348-358.
35
CHALMERS G R L, BUSTIN R M. The organic matter distribution and methane capacity of the Lower Cretaceous strata of northeastern British Columbia, Canada[J].International Journal of Coal Geology,2007,70:223-339.
36
MAHLSTEDT N, HORSFIELD B. Metagenetic methane generation in gas shales I. Screening protocols using immature samples[J].Marine and Petroleum Geology,2012,31(1):27-42.