Marine Oil and Gas Exploration in China 3662611457, 9783662611456

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Yongsheng Ma

Marine Oil and Gas Exploration in China B&R Book Program

Marine Oil and Gas Exploration in China

Yongsheng Ma

Marine Oil and Gas Exploration in China

B&R Book Program

123

Yongsheng Ma Sinopec Beijing, China

ISBN 978-3-662-61145-6 ISBN 978-3-662-61147-0 https://doi.org/10.1007/978-3-662-61147-0

(eBook)

Jointly published with Geological Publishing House The print edition is not for sale in China (Mainland). Customers from China (Mainland) please order the print book from: Geological Publishing House. Map Approval Document No. GS(2019)5278 ISBN of the Chinese edition: 978-7-116-11967-3 © Geological Publishing House and Springer-Verlag GmbH Germany 2020 This work is subject to copyright. All rights are reserved by the Publishers, whether the whole or part of the material is concerned, specifically the rights of translation, reprinting, reuse of illustrations, recitation, broadcasting, reproduction on microfilms or in any other physical way, and transmission or information storage and retrieval, electronic adaptation, computer software, or by similar or dissimilar methodology now known or hereafter developed. The use of general descriptive names, registered names, trademarks, service marks, etc. in this publication does not imply, even in the absence of a specific statement, that such names are exempt from the relevant protective laws and regulations and therefore free for general use. The publishers, the authors, and the editors are safe to assume that the advice and information in this book are believed to be true and accurate at the date of publication. Neither the publishers nor the authors or the editors give a warranty, express or implied, with respect to the material contained herein or for any errors or omissions that may have been made. The publishers remain neutral with regard to jurisdictional claims in published maps and institutional affiliations. This Springer imprint is published by the registered company Springer-Verlag GmbH, DE part of Springer Nature. The registered company address is: Heidelberger Platz 3, 14197 Berlin, Germany

Preface

As the manuscript of Marine Oil and Gas Exploration in China draws to a close, I think it is necessary to explain the original intent of this book. In general, I want to introduce the theoretical exploration and practices of Chinese geologists in the field of marine strata to the peers around the world interested in China oil and gas industry. The geological conditions associated with oil and gas exploration are unique and complex in China’s marine strata. Several generations of geologists and engineering experts have worked and explored tirelessly to solve key problems and made a series of innovative advances and breakthroughs, developing new theories and technologies for marine strata oil and gas exploration. The new understanding of “Multiple Hydrocarbon Generation” provides an excellent answer for the key question of whether deeply buried ancient marine source rocks with high thermal evolution can effectively supply hydrocarbons. The establishment of the concept and the evaluation system on “Effective Hydrocarbon Preservation Unit” provides an effective method for selecting favorable exploration targets in southern China which was intensely deformed by multi-episode tectonic movements. The “Three-Element Controlling Reservoir, Structure-Lithology Composite Controlled Accumulation” and “Three-Step Method of the Facies Controlled Reservoir” theories have successfully solved problems on the formation mechanism of high-quality reservoirs, exploration prospects, and target prediction in deep and ultra-deep marine strata. Faced with the problems of high hydrogen sulfide, carbon dioxide, and other acidic and toxic gas content in marine gas fields, a series of techniques have been developed including corrosion and leakage prevention, safe and efficient drilling and completion, and new testing technology. Over the past two decades, the Chinese explorationists have been constantly innovating, exploring, and making a successive series of important discoveries and breakthroughs in the field of marine strata that was not discovered during a long time. For example, the Tahe, Lunnan, Hadexun, Shunbei oilfields, and the Tazhong I condensate gas field in the Tarim basin; the Puguang, Yuanba, Anyue gas fields, and Fuling shale gas field in the Sichuan basin; The Jingbian and Shenmu gas fields in the Ordos basin; the Renqiu oilfield in the Bohai bay basin and so on. These major oil and gas discoveries supported the development of China oil and gas industry. The theories and technologies mentioned above have been tested and further improved in large-scale exploration practices. These achievements have also received extensive attention from international peers who wish to gain a more thorough understanding of these theoretical and technological advances and the discovery processes of oil and gas fields. Our successes have been achieved by standing on the shoulders of our predecessors and continuing to solve problems through mutual learning. We learned the basic theories and methods of marine hydrocarbon exploration from our peers around the world, and were deeply inspired by comparing and analyzing some of the world’s largest hydrocarbon discoveries. Faced with the complex geological conditions in China, we also understand that we cannot simply apply ready-made theories and experience. On the road of marine strata oil and gas exploration, the exploration and practices utilized by previous generations were not always successful, and the process of exploration is full of the joys of success and lessons of failure. v

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Preface

These experiences acquired by effort and wisdom are precious, and they are of great significance and reference value to our peers today and in the future. Therefore, I think it is necessary to introduce this book to you, and I hope that these living cases can inspire others. My idea was encouraged and supported by many organizations and institutes. Major contributors include teams of faculty and students from Peking University, China University of Geosciences, Chengdu University of Technology, and other universities; teams from oil companies such as PetroChina and Sinopec; and peers from the National Geological Survey. The academician Yunhua Deng and his team shared with us the important achievements of CNOOC marine strata oil and gas exploration in the form of special manuscripts, which further enriched our content systematically. For a long time, many teams were committed to China’s marine strata oil and gas exploration, and each has made an important contribution. Due to the long time span involved, it is difficult to cover all the achievements in one or several books. I was hesitant about how to write this book, because I knew how hard it would be. Thanks to the support from many institutes, my writing team and I had the confidence to complete this book. Special thanks to academicians Guangding Liu, Pengda Zhao, Jinxing Dai, Hongfu Yin, Chengzao Jia, and Xuanxue Mo in the Chinese Academy of Sciences, and Mr. Shuling Mu and others for their encouragement. I would like to thank the exploration and science & technology administrative departments from PetroChina, Sinopec, and CNOOC for their support. In the first part of this book, we summarized the main advances in the theory and technology of marine strata oil and gas exploration. These understandings were mainly derived from the practice in the field of marine strata oil and gas exploration on both onshore and offshore in China. Part II focuses on analyzing some important oil and gas field discoveries including the background, process, and specific practice, which are presented in the form of case studies. These sections are completed by the main participants of each oil and gas field discovery. Due to limitation of space, specific information may not be detailed enough. However, the content is relatively objective, accurate, and vivid, and I believe readers will enjoy it. China’s marine strata oil and gas exploration has just been unfolding and has broad prospects. Our research is still in progress, and there are still many unknowns for us to explore. We expect more people with vision to offer their wisdom and contribute new and greater oil and gas discoveries to the world. Finally, I would like to thank all the members of the writing team for their efforts and hard work. Special thanks to the key translation project of “B&R Book Program” for providing funding. I would also like to thank Geological Publishing House, especially Mr. Yajun Liu, Sinopec Exploration and Production Research Institute, Houston Research and Development Center, and other experts for their guidance and help. Heyuan, Beijing November 2019

Yongsheng Ma

Contents

Part I

Introduction and Overview of Major Basins and Marine Strata in China

1

Regional Tectonic Setting and Prototype Basin Evolution . . . . . . . . . . . 1.1 Tectonic Framework . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1.1 Chinese Plate Tectonic Division and its Characteristics . . . . 1.1.2 China’s Main Craton . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1.3 China’s Main Orogenic Belt . . . . . . . . . . . . . . . . . . . . . . . . 1.2 Outline of Regional Tectonic Evolution . . . . . . . . . . . . . . . . . . . . . . 1.2.1 Structural Cycles in Mainland China . . . . . . . . . . . . . . . . . . 1.2.2 China’s Tectonic Evolution . . . . . . . . . . . . . . . . . . . . . . . . 1.3 Formation and Evolution of China’s Major Marine Prototype Basins 1.3.1 Tectonic Evolution of the Sichuan Basin . . . . . . . . . . . . . . . 1.3.2 Formation and Evolution of the Ordos Basin . . . . . . . . . . . . 1.3.3 Formation and Evolution of the Tarim Basin . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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2

Characteristics and Evolution of Lithofacies Paleogeography . . . . . . . . 2.1 Particularity and Regularity of Marine Strata Development in China 2.1.1 Marine Stratigraphic Division and Correlation . . . . . . . . . . 2.1.2 Particularity and Regularity of Marine Strata . . . . . . . . . . . 2.2 Lithofacies Paleogeographic Characteristics and Evolution Rules of Marine Strata in China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.1 Lithofacies Paleogeographic Characteristics of Marine Strata in China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.2 Marine Stratigraphic Carbonate Sedimentary Model in China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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3

Major Source Rocks and Distribution . . . . . . . . . . . . . . . . . . . . . . . . 3.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2 Major Marine Source Rock and Its Distribution in the Yangtze Region . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.1 Doushantuo Formation Source Rocks of the Upper Sinian 3.2.2 Dengying Formation Source Rocks of the Upper Sinian . . 3.2.3 Lower Cambrian Source Rock . . . . . . . . . . . . . . . . . . . . 3.2.4 Upper Ordovician–Lower Silurian Source Rocks . . . . . . . 3.2.5 Middle Permian Source Rocks . . . . . . . . . . . . . . . . . . . . 3.2.6 Upper Permian Source Rocks . . . . . . . . . . . . . . . . . . . . . 3.3 Major Marine Source Rock and Their Distribution in North China 3.3.1 Mid-Neoproterozoic Source Rocks . . . . . . . . . . . . . . . . . 3.3.2 Lower Paleozoic Source Rocks . . . . . . . . . . . . . . . . . . . . 3.3.3 Carboniferous–Permian Source Rocks . . . . . . . . . . . . . . .

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3.4

Major Marine Source Rock and Its Distribution in the Tarim Basin 3.4.1 Cambrian Source Rocks . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.2 Ordovician Source Rocks . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.3 Carboniferous Source Rocks . . . . . . . . . . . . . . . . . . . . . . . 3.4.4 Permian Source Rocks . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

4

5

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Reservoir Type and Origin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1 Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1.1 Research Progress with Respect to Marine Strata Reservoirs in China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1.2 Types and Genesis of Marine Facies Reservoirs in China . . 4.2 Characteristics and Distribution of Marine Carbonate Reservoirs in China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.1 Reservoir Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.2 Meso-Neoproterozoic Reservoirs . . . . . . . . . . . . . . . . . . . . . 4.2.3 Lower Paleozoic Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . 4.2.4 Upper Paleozoic Reservoir . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.5 Mesozoic Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.6 Cenozoic Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3 Marine Clastic Reservoirs in China . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.1 The Silurian in the Tarim Basin . . . . . . . . . . . . . . . . . . . . . 4.3.2 The Triassic–Jurassic in the Qiangtang Basin . . . . . . . . . . . 4.3.3 The Cretaceous-Eocene in the East China Sea Shelf Basin . . 4.3.4 The Cretaceous—Eocene in the South China Sea . . . . . . . . 4.4 Marine Shale Reservoirs in China . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.1 Precambrian Shale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.2 Ordovician–Silurian Shale Reservoir . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Regional Cap Rock and Hydrocarbon Preservation . . . . . . . . . . . . . . . . . . 5.1 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.1.1 Cap Rock Lithology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.1.2 Cap Rock Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.1.3 Fault Sealing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.1.4 Cap Rock Hydrogeology . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.1.5 Evaluation System for the Preservation Conditions . . . . . . . . . 5.2 Marine Hydrocarbon Preservation Conditions in Yangtze Area . . . . . . . 5.2.1 Cap Rock Type and Distribution . . . . . . . . . . . . . . . . . . . . . . 5.2.2 Influence of Tectonic Activities on Cap Rocks . . . . . . . . . . . . 5.2.3 Marine Hydrocarbon Preservation Units in South China . . . . . . 5.2.4 Evaluation of the Preservation Conditions of Marine Deposits in the Mesozoic and Paleozoic Region (Basin) in South China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3 Preservation Conditions of Marine Hydrocarbons in North China . . . . . 5.3.1 Cap Rock Type and Distribution . . . . . . . . . . . . . . . . . . . . . . 5.3.2 Reconstruction of the Paleozoic by the Differential Overlapping of Mesozoic and Neozoic Basins in North China . . . . . . . . . . . 5.3.3 Marine Hydrocarbon Accumulation and Preservation in North China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Contents

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5.4

Hydrocarbon Preservation Conditions of Marine Strata in the Tarim Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4.1 Cap Rock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4.2 Relationship Between the Tectonic Movement and Hydrocarbon Preservation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4.3 Hydrocarbon Accumulation and Preservation of Marine Strata in the Tarim Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

6

Reservoir Type and Spatial Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1 The Particularity of Oil and Gas Accumulation in Marine Strata in China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.1 Development of Marine Strata in China is Characterized by Small Plates, Strong Activity, and Many Tectonic Cycles . . 6.1.2 Marine Strata in China are Characterized by an Old Age, Deep Burial, and High Degree of Evolution . . . . . . . . . . . . . . 6.1.3 Multi-supply Hydrocarbon Mechanism . . . . . . . . . . . . . . . . . . 6.1.4 Three-Element Controlling Reservoir . . . . . . . . . . . . . . . . . . . 6.1.5 Effective Preservation and Compound Accumulation . . . . . . . . 6.2 Oil and Gas Enrichment and Distribution . . . . . . . . . . . . . . . . . . . . . . 6.2.1 The Tectonic Evolution Controls the Development of the Prototype Basin and Its Superimposed Structure and also Controls the Distribution of the Reservoir–Cap Combination . . 6.2.2 The Tectonic Basin Evolution Controls the Subsidence, Burial, Hydrocarbon Formation and Accumulation, and Hydrocarbon Accumulation Location . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2.3 Structural Paleo-Uplift Controls the Oil and Gas Migration Direction and Enrichment Zone . . . . . . . . . . . . . . . . . . . . . . . 6.2.4 The Basic Pattern of Oil and Gas Loss and Preservation is Controlled by Late Tectonic Movement and Tectonic Deformation and the Relatively Stable Preservation Unit Controls the Final Positioning of Marine Oil and Gas . . . . . . . 6.3 New Understanding of the Hydrocarbon Accumulation Theory . . . . . . . 6.3.1 Oil and Gas Geological Theory of Ultra-Deep Fracture-Cavity Marine Carbonate Rocks in the Tarim Basin . . . . . . . . . . . . . . 6.3.2 New Understanding of the Oil and Gas Theory of Marine Deep Carbonate Rocks in the Sichuan Basin . . . . . . . . . . . . . . 6.3.3 Main Factors Controlling the Silurian Marine Shale Gas Accumulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.4 New Understanding of the Oil and Gas Geological Theory of Marine Carbonate Rocks in the Ordos Basin . . . . . . . . . . . . 6.3.5 Progress with Respect to the Accumulation Theory of the Carbonate Paleo-Buried Hill in the Bohai Bay Basin . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Part II 7

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Exploration Case Studies

Progress and Theory of Marine Strata Oil and Gas Exploration in the Sichuan Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.1 Geographical Location and Regional Geology of the Sichuan Basin . 7.1.1 Geographical Location of the Sichuan Basin . . . . . . . . . . . . 7.1.2 Regional Tectonics–Sedimentary Evolution . . . . . . . . . . . . .

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7.2

Oil and Gas Discovery Process and Exploration Results in Sichuan Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.2.1 Oil and Gas Discovery Process . . . . . . . . . . . . . 7.2.2 Major Oil and Gas Discoveries . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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8

Wubaiti Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1 Basic Geological Characteristics . . . . . . . . . . . . . . . . . . . . . . . . 8.1.1 Structure and Trap Characteristics . . . . . . . . . . . . . . . . . 8.1.2 Carboniferous Division and Its Distribution . . . . . . . . . . 8.2 Basic Characteristics of the Reservoir . . . . . . . . . . . . . . . . . . . . 8.2.1 Main Reservoir Space Type . . . . . . . . . . . . . . . . . . . . . 8.2.2 Relationship Between the Porosity and Water Saturation 8.3 Main Factors Controlling the Reservoir . . . . . . . . . . . . . . . . . . . 8.4 Analysis of Gas Source Rocks . . . . . . . . . . . . . . . . . . . . . . . . . 8.5 History of Gas Migration and Accumulation . . . . . . . . . . . . . . . 8.6 Main Controlling Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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9

Puguang Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1 Location and Geological Setting . . . . . . . . . . . . . . . . . . . . . . . . 9.1.1 Location . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1.2 Geological Setting . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2 Gas Field Discovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.3 Characteristics of the Puguang Gas Field . . . . . . . . . . . . . . . . . . 9.3.1 Structural Characteristics . . . . . . . . . . . . . . . . . . . . . . . 9.3.2 Gas Field Fluid Characteristics . . . . . . . . . . . . . . . . . . . 9.4 Main Gas Layer Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . 9.4.1 Stratigraphic Characteristics . . . . . . . . . . . . . . . . . . . . . 9.4.2 Sequences and Sedimentary Facies . . . . . . . . . . . . . . . . 9.4.3 Diagenesis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.4.4 Reservoir Physical Characteristics and Main Controlling Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.5 Hydrocarbon Accumulation Process . . . . . . . . . . . . . . . . . . . . . 9.5.1 Burial and Hydrocarbon Generation . . . . . . . . . . . . . . . 9.5.2 Accumulation Period . . . . . . . . . . . . . . . . . . . . . . . . . . 9.5.3 Recovery of the Accumulation Process . . . . . . . . . . . . . 9.5.4 Main Factors Controlling the Oil and Gas Accumulation References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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10 Yuanba Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.1 Geographical Location and Regional Geological Background . . . . . 10.1.1 Geographical Location . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.1.2 Stratigraphic Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.1.3 Tectonic Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2 Gas Field Discovery History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3 Gas Field Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3.1 Lithologic Reef–Shoal Gas Reservoir of the Changxing Formation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3.2 Oolitic Shoal Lithologic Gas Reservoir of the Feixianguan Formation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3.3 Natural Gas Source . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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265 265 265 265 265 267 268

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10.4 Main Gas Layer Characteristics . . . . . . . . . . . . . . . . . 10.4.1 Stratigraphic Profile . . . . . . . . . . . . . . . . . . . 10.4.2 Sequence and Sedimentary Facies . . . . . . . . . 10.4.3 Diagenesis . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4.4 Reservoir Properties Characteristics and Main Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5 Dynamic Analysis of the Accumulation Process . . . . . 10.5.1 Accumulation Time and Period . . . . . . . . . . 10.5.2 Recovery of the Accumulation Process . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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270 270 271 274

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276 281 281 281 283

11 Pengzhou Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.1 Geographical Location and Regional Geological Settings . . . . . . . 11.1.1 Geographical Location . . . . . . . . . . . . . . . . . . . . . . . . . . 11.1.2 Regional Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.1.3 Stratigraphy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.1.4 Structural Evolution History . . . . . . . . . . . . . . . . . . . . . . 11.2 Exploration and Discovery Process . . . . . . . . . . . . . . . . . . . . . . . 11.3 Geologic Characteristics of the Pengzhou Gas Field . . . . . . . . . . . 11.3.1 Structural Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.3.2 Trap Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.3.3 Gas Reservoir Characteristics . . . . . . . . . . . . . . . . . . . . . 11.4 Geological Characteristics of the Main Oil and Gas Intervals . . . . 11.4.1 Stratigraphic Profiles . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.4.2 Stratigraphic Sequence and Facies . . . . . . . . . . . . . . . . . 11.4.3 Reservoir Characteristics . . . . . . . . . . . . . . . . . . . . . . . . 11.4.4 Reservoir Formation Mechanism . . . . . . . . . . . . . . . . . . . 11.5 Main Control Factors and Enrichment Rules of the Accumulation . 11.5.1 Gas Source Comparison of the Leikoupo Gas Reservoir in the Sichuan Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.5.2 The Main Controlling Factors of the Leikoupo Formation in Pengzhou Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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285 285 285 285 287 287 290 290 290 292 293 293 293 293 296 301 303

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12 An’yue Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.1 Location . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.2 Stratigraphical Characteristics of the Sinian–Cambrian . . . . . . . . 12.2.1 Division and Comparison of the Lithologic Sections of the Dengying Formation . . . . . . . . . . . . . . . . . . . . . 12.2.2 Maidiping Formation . . . . . . . . . . . . . . . . . . . . . . . . . . 12.2.3 Longwangmiao Formation . . . . . . . . . . . . . . . . . . . . . . 12.3 Sinian–Cambrian Lithofacies Paleogeography . . . . . . . . . . . . . . 12.3.1 Characteristics of the Lithofacies Paleogeography of the Sinian Dengying Formation . . . . . . . . . . . . . . . . 12.3.2 Characteristics of the Lithofacies Paleogeography of the Cambrian Longwangmiao Formation . . . . . . . . . . 12.4 Structural Characteristics and Evolution of the Paleo-Uplift Area in Central Sichuan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.4.1 Features of Paleo-Uplift in Central Sichuan . . . . . . . . . . 12.4.2 Formation and Evolution of the Paleo-Uplift in Central Sichuan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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307 309 309 309

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12.5 Discovery of the Giant An’yue Gas Field . . . . . . . . . . . . . . . . . . . . . 12.5.1 Discovery of the Weiyuan Gas Field (1940–1964) . . . . . . . . . 12.5.2 Difficult Exploration Stage (1964–2005) . . . . . . . . . . . . . . . . 12.5.3 Risky Exploration Stage (2006–2011) . . . . . . . . . . . . . . . . . . 12.5.4 Overall Evaluation Stage (2012 to Present) . . . . . . . . . . . . . . 12.6 Geological Characteristics of the An’yue Giant Gas Field . . . . . . . . . . 12.6.1 Reservoir Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.6.2 Reservoir Type of the An’yue Gas Field . . . . . . . . . . . . . . . . 12.6.3 Gas Reservoir Fluid Characteristics . . . . . . . . . . . . . . . . . . . . 12.7 Main Factors Controlling the Formation of the An’yue Gas Field . . . . 12.7.1 Rich Source Rocks in the Paleo-Rift Depression . . . . . . . . . . 12.7.2 Development of High-Quality Reservoirs in the Paleo-Mound and -Shoal Complex . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.7.3 The Paleo-Uplift is Advantageous for Hydrocarbon Migration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.7.4 The Paleo-Trap is Beneficial to the Early Accumulation of Hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Progress and Theory of Marine Strata Oil and Gas Exploration in the Ordos Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.1 Location and Regional Geological Outline . . . . . . . . . . . . . . . . . . . . 13.1.1 Geographical Location . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.1.2 Regional Geological Setting . . . . . . . . . . . . . . . . . . . . . . . . 13.1.3 Characteristics of the Marine Formation . . . . . . . . . . . . . . . 13.2 Petroleum Exploration and Achievements . . . . . . . . . . . . . . . . . . . . 13.2.1 Petroleum Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.2.2 Petroleum Exploration in the Ordos Basin . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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323 324 324 324 327 327 327 330 332 333 334

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341 341 341 341 341 346 346 346 351

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353 353 353 353

14 Jingbian Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.1 Overview of the Jingbian Gas Field . . . . . . . . . . . . . . . . . . . . . 14.2 Exploration and Development History of the Jingbian Gas Field . 14.2.1 Exploration History of the Jingbian Gas Field . . . . . . . . 14.2.2 Geological Characteristics and Development of the Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.3 Geological Characteristics of Weathering Crust Gas Reservoirs in the Jingbian Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.3.1 Stratum Development Characteristics . . . . . . . . . . . . . . 14.3.2 Lithofacies Palaeogeography and Favorable Sedimentary Facies Belts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.3.3 Reservoir Characteristics . . . . . . . . . . . . . . . . . . . . . . . 14.3.4 Main Controlling Factors of the Reservoir Development 14.3.5 Analysis of the Gas Accumulation Process . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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358 360 363 366 371

15 Daniudi Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15.1 Geographic Location and Regional Geological Setting 15.2 Exploration of the Gas Field . . . . . . . . . . . . . . . . . . . 15.3 Geological Characteristics of the Gas Field . . . . . . . . 15.3.1 Trap Characteristics in the Gas Field . . . . . . 15.3.2 Fluid Characteristics of the Gas Field . . . . . . 15.3.3 Production and Exploitation . . . . . . . . . . . . .

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373 373 373 374 374 375 375

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15.4 Characteristics of the Main Gas Layer . . . . . . . . . . . . . . . . . . . . . . 15.4.1 Strata . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15.4.2 Sedimentary Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15.4.3 Three-Stage Karst Development Model . . . . . . . . . . . . . . . 15.4.4 Physical Features and Controlling Factors of the Reservoir 15.4.5 Geophysical Technology and Methods Used to Verify Petroleum Formation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15.4.6 Analysis of the Gas Reservoir Accumulation . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Shenmu Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.1 Location and Regional Geological Settings . . . . . . . . . . . . . . . . . . 16.1.1 Geological Location . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.1.2 Regional Geological Overview . . . . . . . . . . . . . . . . . . . . . 16.2 Exploration History of the Shenmu Gas Field . . . . . . . . . . . . . . . . 16.2.1 Early Exploration Stage . . . . . . . . . . . . . . . . . . . . . . . . . . 16.2.2 Discovery of the Gas Field . . . . . . . . . . . . . . . . . . . . . . . . 16.2.3 Large-Scale Exploration of the Gas Field . . . . . . . . . . . . . 16.3 Characteristics of the Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.3.1 Trap Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.3.2 Temperature and Pressure . . . . . . . . . . . . . . . . . . . . . . . . . 16.3.3 Fluid Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.3.4 Reserves and Production Characteristics . . . . . . . . . . . . . . 16.3.5 Development Characteristics . . . . . . . . . . . . . . . . . . . . . . . 16.4 Characteristics of the Main Gas-Bearing Strata in the Shenmu Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.4.1 Stratigraphic Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.4.2 Sedimentary Environment . . . . . . . . . . . . . . . . . . . . . . . . 16.4.3 Diagenesis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.4.4 Main Factors Controlling the High-Quality Reservoir . . . . . 16.5 Formation of the Shenmu Gas Field . . . . . . . . . . . . . . . . . . . . . . . 16.5.1 Analysis of the Basic Geological Conditions During the Reservoir Formation . . . . . . . . . . . . . . . . . . . . . . . . . . 16.6 Technology for the Seismic Prediction of the Reservoir Distribution of Favorable Sandstone . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.6.1 Geophysical Basis of the Seismic Prediction of Sandstone in the Taiyuan Formation . . . . . . . . . . . . . . . . . . . . . . . . . 16.6.2 Large-Section Waveform Analysis of the Forward Geological Model of the Wave Equation . . . . . . . . . . . . . . 16.6.3 Sandstone Distribution Prediction by Seismic Inversion . . . 16.6.4 Seismic Attribution Prediction of the Sandbody Thickness and Gas-Bearing Prediction Technique . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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376 376 377 379 383

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391 391 391 391 394 394 395 395 396 396 396 397 397 397

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398 398 399 399 402 403

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17 Progress and Theory of Marine Strata Oil and Gas Exploration in the Tarim Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.1 Regional Geographical Location and Geological Overview . . . . . . . . 17.2 History of Oil and Gas Exploration in Marine Strata . . . . . . . . . . . . 17.2.1 Breakthrough in Large Structures (1984–1989) . . . . . . . . . . 17.2.2 Exploration of Deep Marine Clastic Rocks (1990–1996) . . . 17.2.3 Increased Production and Reserve in Ultra-Deep Fracture-Cavity Marine Carbonate (1996 to Present) . . . . . .

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17.3 Oil and Gas Characteristics of Fracture-Cavity Reservoirs in Marine Carbonate Rocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.3.1 Tectonic Characteristics of the Tazhong–Tabei Platform Uplift . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.3.2 Main Layers and Sedimentary Characteristics of Oil and Gas Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.3.3 Karst Reservoir Characteristics . . . . . . . . . . . . . . . . . . . . . 17.3.4 Regional Cap Characteristics . . . . . . . . . . . . . . . . . . . . . . 17.3.5 Characteristics of Quasi-layered Fracture-Cavity Reservoirs in Marine Carbonate Rocks . . . . . . . . . . . . . . . . . . . . . . . 17.4 Exploration Achievements and Exploration Prospects for Marine Oil and Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.4.1 Exploration Achievements for the Carboniferous Donghe Sandstone . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.4.2 Giant Oil–Gas Area in the Tazhong–Tabei Intra-Platform Uplift . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.4.3 Exploration Prospects . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Tahe Oilfield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.1 Regional Geological Location and Geology . . . . . . . . . . . . . . . . . . 18.1.1 Regional Geological Location . . . . . . . . . . . . . . . . . . . . . . 18.1.2 Regional Geology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.2 Oilfield Discovery History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.2.1 Stage I: Significant Hydrocarbon Exploration Breakthrough (1996–1997) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.2.2 Stage II: Exploration Evaluation, Rapidly Proved and Production Increment (1998–2005) . . . . . . . . . . . . . . . 18.2.3 Stage III: Peripheral Expansion, Overall Control, and Scale Development of the Tahe Oilfield (2006–2010) . 18.3 Oilfield Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.3.1 Trap Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.3.2 Reservoir Fluid Properties . . . . . . . . . . . . . . . . . . . . . . . . 18.3.3 Oilfield Development Status . . . . . . . . . . . . . . . . . . . . . . . 18.4 Pay Interval Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.4.1 Pay Interval Distribution and Lithology . . . . . . . . . . . . . . . 18.4.2 Reservoir Characteristics and Main Controlling Factors . . . 18.4.3 Geophysical Prediction Techniques for Carbonate Oil–Gas Layers (Reservoirs) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.5 Analysis of the Hydrocarbon Accumulation Process . . . . . . . . . . . . 18.5.1 Formation Period of the Ordovician Carbonate Karst Reservoir During the Early Hercynian Movement . . . . . . . 18.5.2 Establishment and Local Destruction of the Closed Reservoir Formation System at the End of the Late Hercynian Movement . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.5.3 Reconstruction of the Indosinian–Early Himalayan Regional Closed System . . . . . . . . . . . . . . . . . . . . . . . . . . 18.5.4 Regional Closed System and Ordovician Reservoir Completion of the Tahe Oilfield in the Late Himalayan . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . 419 . . . . . 419 . . . . . 420 . . . . . 422 . . . . . 422 . . . . . 424 . . . . . 424 . . . . . 424 . . . . . 424 . . . . . 426 . . . . . 427 . . . . .

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432 432 432 434 435 436 436 436

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19 Tazhong I Condensate Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19.1 Regional Geographical Location and Geology . . . . . . . . . . . . . . . . . . . 19.2 Exploration and Development History . . . . . . . . . . . . . . . . . . . . . . . . . 19.2.1 2D Seismic Exploration Proved 8220 Km2 Giant Buried Hill in the Desert Area and Realizing the Strategic Breakthrough of Carbonate Rocks in the Tazhong Area . . . . . . . . . . . . . . . . 19.2.2 Local Structure Exploration: Multiple Oil Shows Were Found Within The 200 km East–West Range of the Northern Tazhong Slope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19.2.3 Based on the Ideas of the Lunnan Karst Exploration and Deepen the Understanding of the Reef Beach Body and Interlayer Karst . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19.3 Geological Characteristics of Gas Condensate Fields . . . . . . . . . . . . . . 19.3.1 Fluid Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19.3.2 Ordovician Strata Distribution and Sedimentary Reservoir Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19.3.3 Diagenesis Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19.3.4 Tectonic Evolution Characteristics of the Paleo-Uplift . . . . . . . 19.4 Exploration and Development Enlightenment . . . . . . . . . . . . . . . . . . . . 19.4.1 Breakthrough in the Understanding of Quasi-Stratified Oil and Gas Reservoirs, Guiding the Discovery of Large Oil and Gas Fields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19.4.2 Reef–Shoal Karst and Interlayer Karst Fissure Cavities Are Primary Drilling Targets . . . . . . . . . . . . . . . . . . . . . . . . . 19.4.3 Improving the Quality of 3D Seismic Data Is the Eternal Theme of Fracture-Cavity Marine Carbonate Rocks . . . . . . . . . 19.4.4 The Fine Description and Target Technique for the Fracture-Cavity Are the Keys to Improve the Drilling Success Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19.4.5 Perseverance and Indomitable Spirit Are the Keys to the Success of Large Oil and Gas Fields . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Hadexun Oilfield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20.1 Regional Geographic Location and Geological Background . . . . . . 20.2 Exploration and Development History . . . . . . . . . . . . . . . . . . . . . . 20.2.1 Drilling the Low-Relief Anticline and Discovering a Thin Sandstone Reservoir in the Middle Mudstone Member . . . . 20.2.2 Drilling Stratigraphic Traps to Achieve a Breakthrough in the Donghe Sandstone . . . . . . . . . . . . . . . . . . . . . . . . . 20.2.3 Integration of Progressive Exploration and Development Massively Improving Reserves and Production . . . . . . . . . 20.2.4 Optimization and Adjustment of Development to Maintain the Stable Production in the Million-Ton Oilfield . . . . . . . 20.3 Reservoir Geologic Characteristics . . . . . . . . . . . . . . . . . . . . . . . . 20.3.1 Sequence Stratigraphic Characteristics . . . . . . . . . . . . . . . . 20.3.2 Sedimentary Facies Characteristics . . . . . . . . . . . . . . . . . . 20.3.3 Characteristics of the Sandstone Reservoirs . . . . . . . . . . . . 20.3.4 Characteristics of the Trap (Structure) . . . . . . . . . . . . . . . . 20.4 Reservoir Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20.4.1 Fluid Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20.4.2 Reservoir Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20.4.3 Accumulation Period and Main Controlling Factors . . . . . .

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20.5 Enlightenment of the Exploration and Development . . . . . . . . . . . . . . . 20.5.1 Progressive Exploration and Development Is the Guarantee for the Successful Exploration and Development of Ultra-Deep and Complex Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20.5.2 Deep and Thin Marine Clastic Rock Reservoir Has Been Developed Efficiently by Horizontal Well Technology . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Bohai Bay Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.1 Progress of the Petroleum Exploration in the Bohai Bay Basin . . . . . . 21.1.1 Geographical Location and Regional Geological Conditions . . 21.1.2 Oil and Gas Discovery Process and Exploration Results . . . . 21.2 Renqiu Oilfield (Buried Hills of the Wumishan Formation in the Jixian System) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.2.1 Oilfield Location and Regional Geological Background . . . . . 21.2.2 History of the Discovery of Oil and Gas Fields . . . . . . . . . . . 21.2.3 Characteristics of Oil and Gas Fields . . . . . . . . . . . . . . . . . . 21.2.4 Characteristics of the Main Reservoirs . . . . . . . . . . . . . . . . . 21.2.5 Analysis of the Hydrocarbon Accumulation Process . . . . . . . 21.3 Niudong Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.3.1 Geographical Location and Regional Geological Background . 21.3.2 History of the Discovery of Oil and Gas Fields . . . . . . . . . . . 21.3.3 Characteristics of the Niudong Buried Hill Oil and Gas Reservoir . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.3.4 Characteristics of the Main Oil and Gas Reservoirs . . . . . . . . 21.3.5 Analysis of the Hydrocarbon Accumulation . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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22 Resource Potential and Exploration Progress of Shale Gas in Marine Strata in China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22.1 Characteristics of Marine Shale in China . . . . . . . . . . . . . . . . . . . 22.1.1 Lower Cambrian . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22.1.2 Upper Ordovician–Lower Silurian . . . . . . . . . . . . . . . . . . 22.2 Resource Condition of Marine Shale Gas in China . . . . . . . . . . . . 22.3 Exploration and Exploitation Status of Marine Shale Gas in China 22.4 Evaluation Method for the Selected Marine Shale Gas Area and Favorable Areas in China . . . . . . . . . . . . . . . . . . . . . . . . . . . 22.4.1 Evaluation of the Selected Marine Shale Gas Area . . . . . 22.4.2 Distribution of Favorable Marine Shale Gas in China . . . 22.5 Exploration Prospects of Marine Shale Gas in China . . . . . . . . . . 22.5.1 Exploration Development Area . . . . . . . . . . . . . . . . . . . . 22.5.2 Exploration Breakthrough and Preparation Area . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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23 Fuling Shale Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23.1 Geographical Location and Regional Geological Background . . 23.1.1 Geographical Location . . . . . . . . . . . . . . . . . . . . . . . . 23.1.2 Regional Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . 23.1.3 Tectonic–Sedimentary Evolution History . . . . . . . . . . . 23.1.4 Regional Stratigraphy . . . . . . . . . . . . . . . . . . . . . . . . . 23.2 Exploration History of the Fuling Shale Gas Field . . . . . . . . . . 23.3 Basic Geological Characteristics of the Fuling Shale Gas Field . 23.3.1 Structural Features . . . . . . . . . . . . . . . . . . . . . . . . . . . 23.3.2 Organic Geochemical Characteristics . . . . . . . . . . . . .

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23.3.3 Reservoir Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . 23.3.4 Shale Mineral Composition . . . . . . . . . . . . . . . . . . . . . . . . . 23.4 Analysis of the Main Factors Controlling the Enrichment and High Production in the Fuling Shale Gas Field . . . . . . . . . . . . . . 23.4.1 Main Factors Affecting the Shale Gas Enrichment . . . . . . . . . 23.4.2 Main Factors Controlling the High Production Shale Gas . . . . 23.4.3 Main Factors Controlling the Accumulation and Productivity of Shale Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . 549 . . . 555 . . . 559 . . . 559 . . . 563 . . . 569 . . . 569

Contributors

Original Chinese Manuscript: Yongsheng Ma China Petroleum & Chemical Corporation, Beijing, China (contributor to Preface; major contributor to Chaps. 6, 9 and 22) Dengfa He China University of Geosciences, Beijing, China (contributor to Chap. 1) Hongde Chen Chengdu University of Techonology, Chengdu, China (major contributor to Chap. 2) Dongzhou Qiu (deceased) Chengdu Institute of Geology and Mineral Resources, Chengdu, China (major contributor to Chap. 2) Liang Yue Chengdu University of Techonology, Chengdu, China (contributor to Chap. 2) Wen Zhou Chengdu University of Techonology, Chengdu, China (major contributor to Chaps. 3 and 8) Yicai Chen Chengdu University of Techonology, Chengdu, China (major contributor to Chap. 3) Min Guo Chengdu University of Techonology, Chengdu, China (contributor to Chaps. 3 and 8) Bo Liu Peking University, Beijing, China (major contributor to Chap. 4) Xuefeng Zhang Peking University, Beijing, China (major contributor to Chap. 4) Kaibo Shi Peking University, Beijing, China (contributor to Chap. 4) Zhanghua Lou Zhejiang University, Hangzhou, China (major contributor to Chap. 5) Aimin Jin Zhejiang University, Hangzhou, China (contributor to Chap. 5) Xunyu Cai Sinopec Oilfield Exploration and Development Division, Beijing, China (major contributor to Chaps. 6 and 22) Peirong Zhao Sinopec Oilfield Exploration and Development Division, Beijing, China (major contributor to Chaps. 6 and 22) Tonglou Guo Sinopec Exploration Company, Chengdu, China (major contributor to Chaps. 7, 9, 10 and 23) Ping Zeng Sinopec Exploration Company, Chengdu, China (major contributor to Chaps. 7 and 23) Jinbao Duan Sinopec Exploration Company, Chengdu, China (contributor to Chaps. 9 and 10) Keming Yang Sinopec Southwest Oil & Gas Company, Chengdu, China (major contributor to Chap. 11)

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Hongquan Zhu Sinopec Southwest Oil & Gas Company, Chengdu, China (major contributor to Chap. 11) Guomin Xu Sinopec Southwest Oil & Gas Company, Chengdu, China (contributor to Chap. 11) Xiaobo Song Sinopec Southwest Oil & Gas Company, Chengdu, China (contributor to Chap. 11) Jinhu Du PetroChina Exploration & Production Company, Beijing, China (major contributor to Chap. 12) Zecheng Wang Research Institute of Petroleum Exploration & Development, PetroChina, Beijing, China (major contributor to Chap. 12) Hua Yang PetroChina Changqing Oilfield Company, Xi’an, China (major contributor to Chaps. 13, 14 and 16) Hongping Bao Research Institute of Petroleum Exploration & Development, PetroChina Changqing Oilfield Company, Xi’an, China (major contributor to Chaps. 13, 14 and 16) Shumin Hao Sinopec North China Oil & Gas Company, Zhengzhou, China (major contributor to Chap. 15) Sihong Liu Sinopec North China Oil & Gas Company, Zhengzhou, China (major contributor to Chap. 15) Wei Zhang Sinopec North China Oil & Gas Company, Zhengzhou, China (contributor to Chap. 15) Zhaoming Wang PetroChina Tarim Oilfield, Korla, China (major contributor to Chaps. 17, 19 and 20) Wenqing Pan Research Institute of Exploration and Development, PetroChina Tarim Oilfield, Korla, China (major contributor to Chaps. 17, 19 and 20) Lijuan Zhang Research Institute of Exploration and Development, PetroChina Tarim Oilfield, Korla, China (major contributor to Chaps. 17, 19 and 20) Guizhang Lian Research Institute of Exploration and Development, PetroChina Tarim Oilfield, Korla, China (contributor to Chaps. 17, 19 and 20) Bing Jing Research Institute of Exploration and Development, PetroChina Tarim Oilfield, Korla, China (contributor to Chaps. 17, 19 and 20) Hongfeng Yu Research Institute of Exploration and Development, PetroChina Tarim Oilfield, Korla, China (contributor to Chaps. 17, 19 and 20) Fuyuan Zhao Research Institute of Exploration and Development, PetroChina Tarim Oilfield, Korla, China (contributor to Chaps. 17, 19 and 20) Yanlong Xu Research Institute of Exploration and Development, PetroChina Tarim Oilfield, Korla, China (contributor to Chaps. 17, 19 and 20) Lixin Qi Sinopec Northwest Oil & Gas Company, Urumqi, China (major contributor to Chap. 18) Renlian Yu Sinopec Northwest Oil & Gas Company, Urumqi, China (major contributor to Chap. 18) Huashan Jiang Sinopec Northwest Oil & Gas Company, Urumqi, China (contributor to Chap. 18) Xianzheng Zhao PetroChina Dagang Oilfield, Tianjin, China (major contributor to Chap. 20)

Contributors

Contributors

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Quan Wang PetroChina Dagang Oilfield, Tianjin, China (major contributor to Chap. 20) Lixin Fu PetroChina Dagang Oilfield, Tianjin, China (major contributor to Chap. 20) Fengming Jin PetroChina Dagang Oilfield, Tianjin, China (contributor to Chap. 20) Chunyuan Han PetroChina Dagang Oilfield, Tianjin, China (contributor to Chap. 20) Mingshun Zhou PetroChina Dagang Oilfield, Tianjin, China (contributor to Chap. 20) Lanzhu Cao PetroChina Dagang Oilfield, Tianjin, China (contributor to Chap. 20)

Chinese Manuscript Compilation: Yongsheng Ma China Petroleum & Chemical Corporation, Beijing, China Xunyu Cai Sinopec Oilfield Exploration and Development Division, Beijing, China Haiqin Tian Sinopec Petroleum Exploration and Production Research Institute, Beijing, China Peirong Zhao Sinopec Oilfield Exploration and Development Division, Beijing, China

Manuscript Translation & Revision from Chinese to English Herong Zheng Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the first translation revision of Chaps. 1–3) Yitian Xiao Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the first translation revision of Chaps. 4–6) Zhongmin Zhang Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the translation of Preface, Chaps. 13, 15 and 22; contributor to the first translation revision of Chaps. 7–12; contributor to the third translation revision of Chaps. 2, 10 and 20) Taizhong Duan Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the first translation revision of Chaps. 13–15) Demin Zhang Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the translation of Chaps. 3, 6, 8, 9, 12 and 18; contributor to the first translation revision of Chaps. 16–18; contributor to the third translation revision of Chaps. 1, 6, 11, 16 and 17) Ming Li Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the translation of Chaps. 1, 2, 5, 21 and 23; contributor to the first translation revision of Chaps. 19–21; contributor to the third translation revision of Chaps. 13–15, 18–20) Yixuan Zhu Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the translation of Preface; contributor to the first translation revision of Chaps. 22 and 23; contributor to the third translation revision of Chaps. 3, 5, 9, 21 and 22) Wei Yao Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the third translation revision of Chaps. 7, 8 and 12) Rui Xu Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the translation of Chaps. 4, 17 and 20) Mingchuan Wang Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the translation of Chaps. 3, 11 and 16)

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Chaonian Si Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the translation of Chap. 14; contributor to the third translation revision of Chap. 19) Fengguang Jiang Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the translation of Chap. 10; contributor to the third translation revision of Chap. 19) Binbin Teng Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the translation of Chaps. 5 and 18) Xiujuan Du Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the translation of Chaps. 3 and 7) Meng Xiao Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the third translation revision of Chaps. 20 and 21) Rongtao Guo Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the third translation revision of Chap. 4) Ting Lu Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the third translation revision of Chap. 22) Yue Gong Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the third translation revision of Chap. 19) Weihong Shen Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (major contributor to the text composition) Zeyang Peng Sinopec Petroleum Exploration and Production Research Institute, Beijing, China (contributor to the third translation revision of Chap. 23) Samruddhi Gandhi Editage by Cactus Communications, Houston, USA (contributor to the second translation revision of Chaps. 7–12) Vivian Antao Editage by Cactus Communications, Houston, USA (contributor to the second translation revision of Chaps. 1–6) Lino Cardoz Editage by Cactus Communications, Houston, USA (contributor to the second translation revision of Chaps. 13–18) Sylvia-Monique Thomas Editage by Cactus Communications, Houston, USA (contributor to the second translation revision of Chaps. 19–23)

Chinese Figure Compilation: Guangxiang Liu Sinopec Petroleum Exploration and Production Research Institute, Beijing, China Zhongbao Liu Sinopec Petroleum Exploration and Production Research Institute, Beijing, China

Executive Editor: Yajun Liu Geological Publishing House, Beijing, China

Contributors

Part I Introduction and Overview of Major Basins and Marine Strata in China

1

Regional Tectonic Setting and Prototype Basin Evolution

The Chinese mainland and its adjacent areas comprise an assembled continent consisting of several blocks of varying sizes and orogenic belts sandwiched among them (Ren and Huang 1980; Li 2010). The main components include the Tulan, Tarim, Zhongchao, and Yangtze blocks and the Ural– Mongolian, Kunlun–Qilian–Qinling, Tethys–Himalayan, and Pacific Ocean orogenic belts. Based on paleo-blocks, the following sedimentary basin types of China marine strata formed, that is intracratonic depression, craton margin depression, etc. Since the Mesozoic and Cenozoic, China has been located at the intersection of four sectors: Europe and Asia, India–Australia, the Pacific, and the Philippines. The subduction and collision of the Indian–Australian and Pacific plates to the Eurasian plate and its induced crust–mantle interaction played strong roles in the superimposition and transformation of the Paleozoic lithosphere and its sedimentary basins in the Chinese mainland and its adjacent areas to form a series of multi-cyclic superimposed sedimentary basins.

1.1

Tectonic Framework

Based on the theory of plate tectonics and continental dynamics, the Chinese tectonic units are divided according to the tectonic framework of the Paleozoic continental plate and the regional tectonic features of the Mesozoic and Cenozoic (Figs. 1.1 and 1.2, Table 1.1).

1.1.1 Chinese Plate Tectonic Division and its Characteristics In Fig. 1.1, the Chinese regional tectonic unit is divided into seven lithospheric plates according to the geological characteristics of the crust evolution in the Chinese continental block and the lithospheric plate suture zone (binding zone)

as well as the large strike-slip fault zone occurring later. These include the southern margin of Siberian Plate (I), the Tarim Plate (II), the Qaidam–North China Plate (III), the Qiangtang–Yangtze–South China Plate (IV), the northern margin of Gondwana Plate (V), and the Pacific Plate (VI) and the western margin of Philippine Sea Plate (VII). These include 32 Class II tectonic units (craton, orogenic belts, and basins) and approximately 103 Class III structural units.

1.1.1.1 Lithosphere Plate Suture Zone The plate boundary (i.e., the plate junction) is divided into two types: a convergent crustal consumption zone and an accretional crustal consumption zone (Wang 1985): (1) Convergent Crustal Consumption Zone A convergent crustal consumption zone refers to two relative paleocontinental marginal areas in close proximity, from an arc–arc and arc–land collision of a marginal sea and an island arc to the final joint. The oceanic crust and the transitional crust between the two ancient continents subsequently formed a folded belt and finally formed the joint belt when the splicing was completed. Because the continent and its marginal area are nearly symmetrical, this area is known as a convergent crustal consumption zone. (2) Accretional Crustal Consumption Zone In the accretional crustal consumption zone, the passive continental margin of place continent was stretched and fractured, and the landmasses moved apart to form an active margin with an island arc marginal sea the subducted to the mainland. Constant outward movement of the arc–basin system and the successive proliferation of the folded belt caused the belt to bold in various stages. The boundary of the ocean crust constantly underwent reduction and joining in this zone.

© Geological Publishing House and Springer-Verlag GmbH Germany 2020 Y. Ma, Marine Oil and Gas Exploration in China, https://doi.org/10.1007/978-3-662-61147-0_1

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4

1 Regional Tectonic Setting and Prototype Basin Evolution





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Legend Crustal Contact Zone Jinning-Nanhua Caledonian Hercynian Indo-China Yanshanian

Himalayan Crustal Lap Joint Zone Jinning-Nanhua Caledonian Hercynian Indo-China Yanshanian Himalayan

Ophiolite First-order Tectonic unit ĉ Second-order Tectonic unit Large Scale Mesozoic and Cenozoic Continental Sedimentary Basins ķCrustal Contact Zone of Southern Margin of Central Tianshan (Khan Tengri PeakBaluntai-Kumishi Fault) ĸCrustal Contact Zone of Xar Moron ĹCrustal Contact Zone of Kengxiwar -Xiugou-Mozitan ĺCrustal Contact Zone of Bangong-Nujiang ĻCrustal Contact Zone of Tongjiang-Mishan ļ Crustal Contact Zone of East Taiwan Longitudinal Valley Ľ Aerjin Fault ľTan-Lu Fault ĉ

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Large Scale Strike-slip Faults in (The Mesozoic and Cenozoic are dominant) Boundary Faults in Other Tectonic Units Instructions: Data shortage in Taiwan province. Data shortage in the Hong Kong & Macao Special Administrative Regions.

China Tectonic Unit Division (limited to first and second tectonic units) Fig. 1.1 Map showing Chinese geotectonic units

1.1.1.2 Boundary Division of Plate Tectonic Units The boundary division is based mainly on the lithospheric plate suture zone (binding zone) and a subsequent large strike-slip fault zone occurring in various periods. Many ophiolite belts are known in China. Among these belts are Paleozoic plate boundaries formed by the crustal

convergent zones of (1) the southern margin of central Tianshan (Hantenggeli Peak–Baluntai–Kumishi fault), (2) Xilamulun, (3) Kangxiwa–Xiugou–Tongcheng, (4) Bangonghu–Nujiang, (5) Tongjiang–Mishan, and (6) the Longitudinal Valley in eastern Taiwan. The boundary of the plate, which is considered to be composed of large strike-slip

1.1 Tectonic Framework

5

Beijing

landmass zone orogenic belt suture zone in orogenic belt Instructions: Data shortage in Taiwan province. Data shortage in the Hong Kong & Macao Special Administrative Regions.

Fig. 1.2 Major landmasses, orogenic belts, and crustal convergent zones in China (Zhang et al. 2015). I. Altay–Xingmeng, II. Irtyles– Silamuron, III. Tianshan–Junggar–Beishan, IV. South Tianshan, V. Tarim, VI. North China, VII. Kuanping–Foziling, VIII. Qinling–

Qilian–Kunlun, IX. Qiangtang–Sanjiang, X. Yangtze, XI. Jiangshao– Chenzhou–Qinfang, XII. Cathay, XIII. Taitung, XIV. Bangonghu– Shuanghu–Nujiang River–Changning–Menglian, XV. Gangdise; XVI. Yaruzampbo, XVII. Himalaya

6

1 Regional Tectonic Setting and Prototype Basin Evolution

Table 1.1 Division of plate tectonics in China (including Class III structural units) (after Liu and You 2015) I. Siberia plate (including Kazakhstan–Junggar sub-Plates)

I. Siberia plate (including Kazakhstan–Junggar sub-Plates)

I-1 Altai Paleozoic Orogenic Belt

I-8-4 Jiamusi–Xingkai Massif

I-1-1 Northern Altai Early Paleozoic Activity Continental Margin

I-9 Songliao Basin

I-1-2 South Altai Late Paleozoic Activity Continental Margin I-2 Paleozoic Orogenic Belt in the northern margin of Junggar (Active Continental Margin)

II. Tarim Plate

I-2-1 Taerbahtai–Almante–Santang Lake Paleozoic Island Arc

II-1 South Tianshan Paleozoic Orogenic Belt (Active Continental Margin)

I-2-2 Shemistai–Kurangazi Devonian Continental Margin Volcanic Belt

II-1-1 Haerke Mountain Paleozoic Marginal Sea

I-2-3 Dalabut–Klamayi Late Paleozoic Remnant Ocean Basin

II-1-2 Erbin Mountain Medium Massif (Devonian Carbonate Platform)

I-3 Junggar Basin (Overlying Basin)

II-1-3 Bosten Intermontane Depression (Overlying Basin)

I-4 Northern Tianshan Late Paleozoic Orogenic Belt (Passive Continental Margin)

II-1-4 Maidantuwu Late Paleozoic Continental Margin Basin

I-4-1 Batamayin Mountains Carboniferous Overlying Basin (?)

II-2 Tarim Basin (Craton)

I-4-2 Bogda Late Paleozoic Rift Trough

II-2-1 Keping Uplift

I-4-3 Yilianhabierga Late Paleozoic Remnant Ocean Basin

II-2-2 Kuluketage Uplift

I-4-4 Tuha Basin (Overlying Basin)

II-2-3 Tabei Uplift

I-4-5 Jueluotage Late Paleozoic Remnant Ocean Basin

II-2-4 Northern Depression

I-5 Yili–Mid-Tianshan Microcontinent

II-2-5 Tazhong Uplift

I-5-1 Selim Massif

II-2-6 Southwest Depression

I-5-2 Nalati Early Paleozoic Fault-Depression Zone

II-2-7 Southeast Depression

I-5-3 Yili River Carboniferous–Permian Rift Belt

II-2-8 Tiekelike Uplift

I-5-4 Turks Massif

II-2-9 Dunhuang Massif

I-6 Beishan Paleozoic Orogenic Belt (Active Continental Margin)

II-3 West Kunlun Late Paleozoic Orogenic Belt (Passive Continental Margin)

I-6-1 Redstone Mountain Paleozoic Arc Back Basin

II-4 Altun Paleozoic Orogenic Belt

I-6-2 Mazong Mountain Medium Massif I-6-3 Badain Jaran Cenozoic Basin

III. Qaidam–North China Plate

I-7 Erguna Microcontinent

III-1 East Kunlun Paleozoic Orogenic Belt

I-7-1 Mohe Foreland Basin

III-2 Qilian Early Paleozoic Orogenic Belt

I-7-2 Ergun Mesozoic Island Arc

III-2-1 Hexi Corridor Cenozoic Basin

I-7-3 Hailar Late Paleozoic Arc Back Basin

III-2-2 Northern Qilian Late Proterozoic–Early Paleozoic Trench

I-8 Xingmeng Paleozoic Orogenic Belt

III-2-3 Central Qilian Early Paleozoic Island Arc

I-8-1 Duobaoshan Paleozoic Island Arc

III-2-4 Southern Qilian Early Paleozoic Rift Continental Margin

I-8-2 Xilinhot Late Paleozoic–Mesozoic Magma Arc

III-3 Qaidam Microcontinent

I-8-3 Xiaoxing’anling-Zhangguang Cailing Magma Arc

III-3-1 Qimantage Early Paleozoic Magma Arc

III. Qaidam–North China Plate

IV. Qiangtang–Yangtze–South China Plate

III-3-2 Qaidam Basin

IV-1-2 Qiaoertianshan–Axechin Paleozoic Subsiding Belt

III-3-3 Northern Margin of Qaidam Late Proterozoic–Early Paleozoic Settlement Belt

IV-1-3 Tuanfeng–Linjitang Mesozoic Depression Belt

III-3-4 Ela Mountain Early Mesozoic Fault-Depression Zone

IV-2 Qiangtang Microcontinent

III-4 Alashan Microcontinent

IV-2-1 Ruolagangri Continental Margin Arc

III-4-1 Longshou Mountain–Yabulai Mountain Massif

IV-2-2 North Qiangtang Massif

III-4-2 Tengeli Accretionary Wedge

IV-2-3 Tuohepingcuo–Chaduogangri Oceanic Island Seamount Accretionary Belt

III-5 North China Land Block (Craton)

IV-2-4 South Qiangtang Massif (continued)

1.1 Tectonic Framework

7

Table 1.1 (continued) III-5-1 Ordos Mesozoic Depression

IV-2-5 Tanggula–Zuogong Massif

III-5-2 Western Margin of Ordos Neoproterozoic–Early Paleozoic Fault-Depression Zone

IV-2-6 Lanping Mesozoic Foreland Basin

III-5-3 North China North Rim Uplift Zone (Including Yan Liao Continental Nucleus)

IV-2-7 Baoshan Massif

III-5-4 Yanshan Mid–Neoproterozoic Fault-Depression Zone

IV-3 Kekexili–Bayankera Mesozoic Orogenic Belt

III-5-5 Central and Southern Shanxi Neoproterozoic–Early Mesozoic Depression Area

IV-3-1 Kekexili–Songpan Triassic Foreland Basin

III-5-6 North China Basin

IV-3-2 Yalong River Triassic Remnant Basin

III-5-7 Eastern Liaoning Late Neoproterozoic–Geozoic Depression Belt

IV-3-3 Ganzi–Yidun–Shaluli Mesozoic Island Arc (P2–T3)

III-5-8 Western Shandong Massif

IV-3-4 Zhongzan–Zhongdian Massif

III-5-9 Eastern Shandong Proterozoic Depression

IV-4 Yangtze Block (Craton)

III-5-10 Western Henan Proterozoic Rift Belt

IV-4-1 Kangding–Yunnan Massif

III-5-11 Fenwei Cenozoic Rift Belt

IV-4-2 Central Yunnan Mesozoic Depression

III-6 Northern North China Paleozoic Depression Belt

IV-4-3 Longmenshan Decken Belt

III-6-1 Langshan Paleozoic Rift Belt

IV-4-4 Sichuan Mesozoic Basin

III-6-2 Yinshan–Northern North China Paleozoic Rift Belt

IV-4-5 Bamianshan Paleozoic Depression Belt

III-7 Northern Qinling Neoproterozoic–Early Paleozoic Orogenic Belt (Passive Continental Margin)

IV-4-6 Yunnan–Guizhou–Guangxi–Hunan Late Paleozoic–Early Mesozoic Depression Belt IV-4-7 Youjiang Late Paleozoic Depression Belt

IV. Qiangtang–Yangtze–South China Plate

IV-4-8 Zhejiang–Jiangxi–Hunan Late Paleozoic Depression Belt

IV-1 Karakorum Paleozoic–Mesozoic Orogenic belt (Passive Continental Margin)

IV-4-9 Jiangnan Late Proterozoic Orogenic Belt (Rifted Continental Margin; Formerly Jiangnan Ancient Land

IV-1-1 Dahongliutan–Quan Shuigou Triassic Depression Belt

IV-4-10 Lower Yangtze Paleozoic Depression Belt

IV. Qiangtang–Yangtze–South China Plate

V. Gondwana Plate

IV-4-11 North Jiangsu Late Mesozoic–Cenozoic Basin

V-1 Gangdese Mesozoic–Cenozoic Orogenic Belt (Active Continental Margin)

IV-5 South Qinling–Dabieshan Neoproterozoic–Paleozoic Orogenic Belt

V-1-1 Naqu–Luolong Early Mesozoic Arc Front Basin

IV-5-1 South Qinling–North Dabieshan–South Shandong Neoproterozoic–Late Paleozoic Rifted Continental Margin

V-1-2 Bange–Tengchong Cretaceous Magma Arc

IV-5-2 Dabashan–South Dabieshan Late Proterozoic Rifted Continental Margin

V-1-3 Cuoqin–Shenzha Mesozoic Island Arc

IV-6 South China Neoproterozoic–Early Paleozoic Orogenic Belt

V-1-4 Ladake–Gandes–Chayu Mesozoic–Cenozoic Magmatic Arc

IV-6-1 Southeast Coast Mesozoic Magmatic Belt

V-1-5 Shigatse Late Cretaceous Arc Front Basin

IV-6-2 Wuyi–Pearl River Paleozoic Rifting Belt

V-2 Northern Himalaya Middle–Cenozoic Orogenic Belt (Passive Land Edge)

IV-6-3 Guangdong–Hunan–Jiangxi Early Paleozoic Subsidence Zone

V-2-1 Laguigangri Mesozoic Passive Margin Basin

IV-6-4 Wugong Mountain Marginal Subsidence Zone

V-2-2 Northern Himalaya Carbonate Platform (O–E2) (?)

IV-6-5 Yunkai Late Proterozoic Subsidence Zone

V-3 Great Himalaya Land Mass (Part of the Indian Ancient Land Mass)

IV-6-6 Leiqiong Tectonic Uplift Zone

V-3-1 Great Himalaya Basal Thrust Belt V-3-2 Lesser Himalaya Continental Margin Fold Thrust Belt V-3-3 Xiwalike Foreland Basin VI. Pacific Plate VI-1 Taitung Cenozoic Orogenic Belt VI-2 Nadan Hadaling Mesozoic Orogenic Belt VII. Philippine Sea Plate (?) VII-1 South Sea Block

8

faults occurring later, is formed by the (7) Altun and (8) Tanlu faults.

1.1.1.3 Characteristics of the Seven Lithospheric Plates and Its Relations (1) Siberia Plate (Southern Margin) The main part of the Siberian plate is located in Mongolia, Russia, and other countries; the part within China is only the southern margin of the plate. The southern boundary of the Siberian plate is located in North China’s Xinjiang Uygur autonomous region, Inner Mongolia autonomous region, Liaoning province, Jilin province, and Mongolia. The boundary between the Siberian and Tarim plates in the western section of the plate is the crustal convergent zone composed by the southern margin fault of the central Tianshan–Hantenggeli Peak–Baluntai–Kumoshi fault that developed in the Paleozoic (Ren and Huang 1980; Li et al. 1982; He 1994; Liu and Yao 1997, 2015; Figs. 1.1 and 1.2). This boundary extends eastward to the southern margin of the Beishan region of Gansu province (roughly equivalent to the Shibanjing–Xiaohuangshan fault zone) and directly into the Badain Jaran Desert (Zuo and Liu 1987; Wu and He 1992; Wang et al. 1992). The southern boundary of the eastern section of the plate extends to Liaoning and Jilin provinces in general along the crustal convergent zone of Xilamulun. The Siberian plate in Northwest China consists of the northern Tianshan late Paleozoic Island Arc, Junggar Basin, and the Altai Paleozoic Orogenic Belt. The Siberian plate in Northeast China is composed of the Xingmeng Orogenic Belt, Erguna Microcontinent, Songliao Basin, and Jiamusi Microcontinent, which is nearly accordance with the previously boundary between North China and Northeast China. (Ren and Huang 1980; Wang 1985; Cheng 1994). (2) Tarim Plate The north boundary of the Tarim plate is the southern margin fault zone of central Tianshan. The Hantenggeli Peak–Baluntai–Kumoshi fault forms the boundary between the Tarim and Siberian plates (Liu and Yao 1997). Its southern margin is bounded by the Kangxiwa fault zone, a late Triassic closed crustal convergent zone occurring in the western section (Liu and Yao 1997; Xiao et al. 2004) that stretches west from Uytak to the frontiers. The eastern section is bounded by the Altyn Tagh fault zone to the northeastward to the northern part of the Yumen area of Gansu Province. It passes through the Kuantanshan fault and the Badain Jaran Desert, possibly connecting to the Engelwusu Ophiolite Belt. (Wu and He 1992; Wang 1992), and constitutes a large stratigraphic–structural boundary (Fig. 1.2 and Table 1.2). The Tarim plate consists of the South

1 Regional Tectonic Setting and Prototype Basin Evolution

Tianshan and Tarim blocks on the north side, the West Kunlun Mountains on the south side, and the Altun Mountains and Dunhuang blocks to the east (Jia et al. 1997). (3) Qaidam–North China Plate The northern boundary of the Qaidam–North China plate consists of eastern and western parts. The western part forms the southern boundary of the Tarim plate, and the eastern section is connected to the Siberian plate by Xilamulun crust (Wang 1985) (Fig. 1.2 and Table 1.2). The southern boundary of the Qaidam–Huabei plate is also composed of the eastern and western sections. The western section is equivalent to the Xiugou–Maqin fault zone on the southern margin of the Kunlun Mountains, and the eastern section is the Shanyang–Tongcheng fault zone, which turns to the Tanlu fault zone of NNE direction in Anhui Province and the Rongcheng–Wulian fault zone in Shandong Province. The Qaidam–North China plate is mainly composed of North China, Qaidam, Qilianshan, and other blocks. In addition, the northern region includes the Badain Jaran Desert, Tengger Desert, Yinshan, Yanshan, and other areas as well as the Bohai Sea area. The southern region includes the area to the north of East Kunlun, North Qinling, Dabieshan, and the Yellow Sea. (4) Qiangtang–Yangtze–South China Plate The northern boundary of the plate is the Kangxiwa fault zone, adjacent to the Tarim plate (Wang 1985). The western part is located in the Kunlun–Kala Kunlun Mountain area in western Xinjiang. After passing through the Altyn Tagh fault zone, the eastern section of the Kunlun fault zone and the Shanyang–Tongcheng fault zone are adjacent to the Qaidam–North China plate on the north side (Wang 1985; Liu 1994; Pan et al. 2009). The southern boundary of the plate is separated from the Gondwana plate by the Bangong Lake– Nujiang fault zone and enters India and Nepal to the south. The Qiangtang–Yangtze–South China plate is composed mainly of Qiangtang, Yangtze, South China, the southern part of the Yellow Sea, the East China Sea, Taiwan Island, and the South China Sea (Fig. 1.2 and Table 1.2). (5) Gondwana Plate (Northern Margin) The Gondwana plate is located mainly in countries such as India and Nepal; the part in China is only the northern margin of the plate. It is connected to the Qiangtang– Yangtze–South China plate to the north and is bounded by the Bangong Lake–Nujiang fault and enters India and Nepal to the south. The Gondwana plate in the territory includes the Gangdise and the Himalayas.

1.1 Tectonic Framework

(6) Pacific Plate (Western Margin) The Nadan Hada Ridge in the eastern part of Heilongjiang province and its adjacent areas belong to the Pacific plate. The boundary between the Pacific and Qaidam–North China plate is the Tongjiang–Mishan crustal convergent zone of Heilongjiang province (Fig. 1.2). Nadan Hadaling in the northeastern part of Heilongjiang was combined with Eurasia in the middle and late Mesozoic. (7) Philippine Sea Plate (Western Margin) The dividing line between the Philippine Sea Plate and the Qiangtang–Yangtze–South China Plate to the west is the Taitung Longitudinal Valley crustal convergent zone on Taiwan Island (Ren and Huang 1980). This zone was a crustal collision zone in the Cenozoic era, separating the Philippine Sea Plate and Eurasia including the Qiangtang– Yangtze–South China Plate (Fig. 1.2). The western margin of the Philippine Sea Plate is composed mainly of the Hualien Basin in Taiwan province and the volcanic arc of the Coastal Mountains and the nearby seas. The boundary of secondary structural unit may consist of an accretional crustal zone, a major fracture zone, or a large translational fracture. The secondary tectonic unit may a microcontinent, platform, or continental margin in different plates that later formed into orogenic belts of various periods (Tables 1.1 and 1.2). The tertiary structural unit is further divided within the secondary structural unit, considering mainly their positions and roles in the latter, and marks the era of its limited main activity time (Liu and You 2015). For the interior of the plate, the secondary unit is divided into a number of different ancient blocks, massifs, which are relatively stable areas. However, their different locations among periods relate to different activities, resulting in differences between stability and activity. Therefore, when three-level tectonic units are divided into an ancient landmass, some uplifted and depressed areas in different periods, long-term stable land nuclei and landmasses, and rift zones or rift troughs occurring in different geological periods can be distinguished. The different continental margins of the plate are used as the main body of the secondary structural unit, and different times are set to calibrate the time of activity for the continental margin, according to outcrops of stratum and magma. Examples include the Kala Kunlun Paleozoic–Mesozoic active continental margin and the Qianlian Early Paleozoic active continental margin. At the margin of the active continent, different types of active continental margins are present such as Andean, Cordillera, Alpine, and Western Pacific. These are divided into island arcs or magma arcs according to their locations.

9

The different structural units, such as island arc, pre-arc basin, and back-arc basin and the era in which they occur are used as tertiary structural units. An example is the Early Paleozoic arc back basin. The passive continental margin, that is the Atlantic continental margin type, dominated by discrete and tensile activities, can be divided into rift basins or rift zones of different periods. Most of the passive continental margin is shown in continental slopes of different periods or in continental marginal subsidence zones. Meso–Cenozoic large inland basins such as Tarim, Junggar, and Qaidam in the west and Songliao, North China, North Jiangsu, and Jianghan in the east are mostly superimposed on different tectonic units in the Paleozoic period. In the Mesozoic and Cenozoic periods, however, they were obvious negative elements and accepted thick Mesozoic and Cenozoic continental sediments to form large inland basins showing multi-cycle superimposed properties. They are treated as secondary or tertiary structural units.

1.1.2 China’s Main Craton The development of large marine sedimentary basins in China is closely related to the formation and evolution of three major cratons: Yangtze, North China, and Tarim. The basic characteristics of their geological structures are given below (Fig. 1.2, Table 1.2).

1.1.2.1 Yangtze Craton The Yangtze Craton includes almost the entire Yangtze River Basin and the South Yellow Sea from central Yunnan to Jiangsu province. This craton region was formed by the Late Neoproterozoic Yangtze cycle. To the southwest, it is the Ailaoshan–Honghe deep fault which is adjacent to the Sanjiang fold system; to the northwest, it is the Longmenshan deep fault which is connected with the Songpan–Ganzi fold system. At the north side is the Qinling–Dabie fold belt, and the northeast margin is formed by the Tancheng–Lujiang deep fault. The southeast side includes the South China fold system. Its main secondary structural units include the Yanyuan–Lijiang, Longmenshan, and Dabashan–Dahongshan platform margin depressions; the Sichuan syneclise, the Kangdian Earth axis, the central Guizhou–Eastern Yunnan uplift, the Southern Guizhou–Southwest Guizhou depression, the Nanpanjiang depression, the Jiangnan uplift, the Upper Yangtze inner platform depression, and the Lower Yangtze depression. The Yangtze Craton has a crust thickness of 38–46 km and a lithosphere thickness of 160– 180 km. The crust P-wave velocity is 6.35 km/s. The crust has a three-layer structure, and the middle crust has developed a low-velocity and low-resistance layer (Table 1.2).

10

1 Regional Tectonic Setting and Prototype Basin Evolution

Table 1.2 Comparison of geological features of major craters in China Category Geophysical field

Crustal structure and properties

Basement

Cap rock

Tarim

North China

Yangtze

Bouguer gravity anomaly

−130 to −200 mGal

10 to −50 mGal

−80 to −100 mGal

Crustal thickness

42–48 km

30–35 km

38–46 km

Lithosphere thickness

180–200 km

50–85 km

160–180 km

Crustal layering

Supracrust: 27 km; Middle crust: 10 km; Lower crust: 15 km

Supracrust: 15 km; Middle crust: 10 km; Lower crust: 13 km

Supracrust: 12 km; Middle crust and Lower crust: 22 km

P-velocity (Vp)

6.35 km/s; no low-velocity zone

6.39 km/s; low-velocity zone and low-resistance layer in the middle crust

6.35 km/s; low-velocity zone and low-resistance layer in the middle crust

Crust acidity SiO2

65.9%

64.88%

65.98%

Rock association

TTG rock association Trondhjemite– tonalite–granodiorite (TTG) rock combination

TTG; quartz monzodiorite–granodiorite

Granodiorite

Geochemistry characteristics

Characteristics of the Tograk–Bragg group, schist, gneiss

Rich in Fe, Mg, Ca, Na; light in K (Na2O > K2O); low in oxidation; rich in pro-Fe elements; poor in lithophile elements and incompatible elements

Rich in Si, K; light in Fe, Mg, Ca; low in Na2O/K2O; rich in Rb, Cs, Nb, Ta, U, Th, REE. Supracrust is rich in W, Sn, Sb, Bi, and other elements

Beginning development

>2800 Ma

3800 Ma

3000 Ma ±

Main constituent unit

Tarim, Dunhuang, and Alashan. Tarim includes south and north massifs

Western block, eastern block

Upper, Middle, and Lower Yangtze. The Sichuan Massif is divided into three parts: west, middle, and east

Tectonic evolution

2500–2300 Ma bimodal magmatic rock formed the extension system and the Kuluketagexing Formation. The 2000– 1800 Ma tectonic magmatic event is the response of supercontinent convergence in Colombia. The main body of the Middle Proterozoic is a carbonate platform rich in stromatolites. The glaucophane schist in the Early Aksu Rock Group of the Neoproterozoic represents the Neoproterozoic orogeny that converted into a relatively stable landmass

Before 1800 Ma, the five ancient blocks of Yinshan–Northern Hebei, Shanxi– Hebei, Western Shandong, Eastern Bohai, and Shanxi–Henan–Anhui and their oceanic crusts were subducted and converged to form a unified ancient continent. Birth of the ancient and middle Archaic land nucleus ! Neoarchean magma arc ! Paleoproterozoic basement formation stage

About 3000 Ma of land nuclear remnants occur in the Huangling anticline nucleus. The Changchanggian Dahongshan Group represents cracking of the tectonic magmatic event of the Columbia supercontinent. The Mesoproterozoic is a passive continental marginal deposit. The Neoproterozoic Early stage is the Yangtze surrounding arc–basin space configuration. In 820– 760 Ma, oceanic crust subduction and arc–land collision formed a unified ancient continent

Beginning development

820–760 Ma

1800 Ma

820–760 Ma

Main features

In the Late Qingbaikou–Nanhuan system, rifting and glacial rocks were developed in the Nanhuan system. The Dengying–Middle Triassic is a stabilization carbonate platform. Basalt and basic dyke groups were extensively developed in the Early Permian. The southern margin of T3 was developed by delayed arc–continent volcanic rock. Cretaceous rocks are generally composed of a set of red clastic rocks containing gypsum. The Late Cretaceous in the southwestern part of the Tarim was affected by transgression and its environment mainly in the shallow sea, which continued until the end of the Oligocene and the marine environment ended. The facies of the whole area is fluvial and lacustrine in Neogene

In the Changchanggian system (18 Ga), it entered the stage of stable platform development. Intracontinental and continental marginal rifts developed in the Changchanggian–Neoproterozoic system. The Changchanggian system rift event is the tectonic response of the Colombia supercontinent breakup. The Jixian–Middle Ordovician is dominated by epeiric sea carbonate deposits. Most of the uplift in the Late Ordovician and Early Carboniferous was denuded A paralic epeiric sea developed in the Late Carboniferous—Early Permian. The Middle Permian deposits were converted to terrestrial deposition. The Mesozoic tectonic magma event is a sign of involvement in the western Pacific tectonic domain

In the Late Qingbaikou-Early Nanhua system, a superposed rift basin developed after the collision, the Nanhuaian glacial rocks were widely distributed in the landmass area. In Z– O2, an epeiric sea—slope developed. In O3–S, the southeastern part of the Yangtze became the foreland basin; the rest was the epeiric sea. In D–T2, an epeiric sea—slope developed. In the Upper Yangtze area, an intracontinental tensile basal volcanic eruption triggered by the mantle plume occurred in P2-3. In T3–J2, the western part of the Yangtze became the foreland basin; the rest was the intracontinental basin. Beginning in Jurassic, the eastern part of the Yangtze was involved in the western Pacific tectonic domain. In J3–K1, an extensional volcanic sedimentary fault basin developed; during K2–Q, the fault-depression basin developed

1.1 Tectonic Framework

The >3.0 Ga information of the granitic gneiss of the Huangling anticline nucleus represents the remains of the continental nucleus. The Dahongshan Group of the Early Middle Proterozoic represents the structural magmatism of the Colombian supercontinent. In the Middle and Late Mesoproterozoic, the Dongchuan and the Shenlongjia groups recorded sedimentary records of the passive continental margins. The Early Neoproterozoic Huili, Fanjingshan, Lengjiaxi, Shuangqiaoshan, and Shuangxiwu groups are represented by the arc–basin spatial allocation of surrounding the Yangtze; the basement of Yangtze Craton was formed during the 820 Ma when ocean shell reduction and arc–land collision to form a unified ancient continent (Wang 1985; Pan et al. 2013). During the Late Qinghaikou–Early Nanhuan system (820–7500 Ma) in the Yangtze area, a collisional superposed rift basin formed, and Nantuo tillites were widely distributed in the massif (Wang et al. 2001; Pan et al. 2009). During the Sinian–Central Ordovician, the Yangtze area was an epeiric sea–passive continental margin slope, and during the Late Ordovician–Silurian periods, Yangtze was the foreland basin in the southeast; the remaining area was the Epeiric Sea. In the Devonian–Middle Triassic periods, the Yangtze area is an epeiric sea–passive continental margin slope. The Middle–Late Permian in the Upper Yangtze Region shows intracontinental extensional basic volcanic rock eruption triggered by the mantle plume (Liu 1994; He et al. 2014). During the Late Triassic–Middle Jurassic periods Yangtze was a foreland basin to the northwest; the remaining area included an intracontinental depression and a compressional basin. After the Mid-Indosinian movement, the Sichuan syneclise was transformed into a large depression: the Sichuan Basin. Some areas of the Kangdian uplift were transformed into fault basins such as the Chuxiong Basin. The Late Triassic sediments in the area transitioned from marine to continental. Beginning in the Early Jurassic, all of the seawater withdrew from the area, and continental sediments formed, ending the history of the Yangtze Craton marine sediments. Moreover, during the Jurassic, the eastern part of the Yangtze was involved in the western Pacific tectonic domain. In the Late Jurassic–Early Cretaceous, the formation of volcanic sedimentary fault basins peaked in the Yangtze area in the extensional environment. In the Late Cretaceous–Quaternary, the region developed a fault-depression–depression basin (He et al. 2011; Wei et al. 2014; Xu et al. 2014; Zhang et al. 2014). Since the Jurassic, the Yangtze Craton has undergone multiphase strong transformation of Yanshan and Himalayan movement and has developed a multi-period superposed continental fault-depression basin.

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1.1.2.2 North China Craton The North China Craton is bounded by the Tianshan– Xingmeng and Qilian–Qinling–Dabie–Sulu orogenic systems. Its secondary tectonic units can be divided mainly into the Inner Mongolian axis, the Yanshan folding zone, the Jiaoliao fault uplift, the Bohai fault sag (Bohai Bay Basin), the Western Shandong fault uplift, the Henan and Anhui fault sag (South China Basin), the Western Henan fault uplift, the Shanxi fault uplift, the Ordos syneclise (Ordos Basin), the Ordos western margin platform folded zone, and the Alashan anteclise. The North China Craton has a crust thickness of 30–35 km and a lithospheric thickness of 50– 85 km. The crust P-wave velocity is 6.39 km/s. The crust has a three-layer structure, and the middle crust has developed a low-velocity and low-resistance layer (Table 1.2). The basement of the North China Craton consists of Archean and Paleoproterozoic rocks; the basement was consolidated and formed at the end of the Paleoproterozoic. Above the basement lies the Mesoproterozoic–Cenozoic sedimentary caprock (Wang 1985; Table 1.2). The North China Block is a unified ancient continent formed by the five blocks including the Yinshan–Northern Hebei, Shanxi– Hebei, Western Shandong, Eastern Bohai, and Shanxi– Henan–Anhui blocks, which underwent oceanic crust consumption and convergence 1.8 Ga. The formation of the basement has experienced stages of Paleoarchean, Middle Archaic land nuclear nuclei ! Neoarchean magma arc ! Paleoproterozoic basement formation in the Middle Proterozoic (1.8 Ga) before entering a stable development stage. In the Mesoproterozoic–Palaeozoic, the North China Craton generally accepted stable caprock deposits, and its magmatism was weak. In the Early–Middle Triassic, with the subsidence reduction and closure of the Paleo-Qinling Ocean, the compressional orogeny in the southern margin of North China increased, and the foreland basin and depression basin developed gradually from south to the north in North China. The Triassic Yangtze and the North China blocks underwent a “scissors” collision, which formed the Qinling–Dabie orogenic zone (Liu et al. 1997). Owing to compression from the southern and northern borders, the main intracontinental depression basin in North China widely accepted fluvio– lacustrine facies deposition (Hao et al. 2014). Since the Jurassic, the North China Platform has separated the Ordos area from Bohai Bay and southern North China by the Taihang Shan–Lvliang Shan–Yanshan fold belt. The eastern and western regions have very different tectonic settings, with frequent activities in the former and relative stability in the latter. The tectonic magmatic event in eastern North China is a product of western Pacific tectonic

12

domain involvement (Zhai 2010; Zhu et al. 2012). During this period, it experienced the multistage and multi-episodic evolution process of Yanshan and Himalayan movement, and the tectonic pattern changed greatly. After intense destruction and reconstruction, the craton formed an extensive depression–fault-depression, rift, and pull-apart basin in North China (Luo et al. 2014; Xu et al. 2014).

1.1.2.3 Tarim Craton The Tarim Craton area is sandwiched between the South Tianshan and Kunlun Mountain fold belts and includes the Tarim Basin and the Dunhuang–Beishan massif. The Tarim Basin includes mainly secondary tectonic units such as the Northeast depression, Central uplift, Southwest depression, and Southeast fault–uplift. The thickness of the Tarim Craton is 42–48 km, and the lithosphere is 180–200 km thick. The crust P-wave velocity is 6.35 km/s, and the crust has a three-layer structure (Table 1.2). The basement rocks of the Tarim Craton are the pre-Sinian crystalline basement or metamorphic basement rocks, which are composed mainly of Neoarchean, Paleoproterozoic, and Meso–Neoproterozoic rocks. The Late Neoproterozoic Tarim movement consolidated the basement. In the Early Neoproterozoic, the Tarim region was transformed into a relatively stable continental massif during the Jinning orogenic event in about 850 Ma.

1.1.3 China’s Main Orogenic Belt Under the interaction of the ancient plates and through multi-cycle structural evolution, a series of folded orogenic belts were formed between the margins of the ancient plates. These include the Altai–Xingmeng, Tianshan–Junggar– Beishan, Qinling–Qilian–Kunlun, Qiangtang–Sanjiang, Gangdise, Himalayan, Cathaysia, and Eastern Taiwan orogenic belts (Fig. 1.2 and Table 1.3). Based on the tectonic cycle, it is shown as below. (1) The Caledonian Orogenic Belt includes mainly the Ondor Sum–Xar Moron He and Jilin–Yanbian active continental margin accretion fold belts, the Yichun– Yanshou fold belt, the North Qinling–North Dabie continental marginal fold belt, the Central Qinling island arc accretion fold belt, the Zhejiang–Jiangxi and Hunan–Guangxi continental marginal fold belts, the Jiangxi–Guangdong active continental marginal fold belt, the North Qilian continental margin accretion fold belt, the South Qilian fold belt, the Qimantage continental margin accretion fold belt, the Beishan active continental marginal fold belt, the northern West Kunlun island arc accretion fold belt, and the West Junggar accretion fold belt.

1 Regional Tectonic Setting and Prototype Basin Evolution

(2) The Early Hercynian Orogenic Belt includes mainly the Handaqi–Dongwuqi island arc accretion fold belt, the Xiguituqi active continental margin accretion fold belt, the South Tianshan and North Tianshan accretion fold belts, the East Tianshan fold belt, the East Junggar and North Junggar accretion fold belts, and the West Junggar fold belt. (3) The Late Hercynian–Indosinian Orogenic Belt includes mainly the Southern Qinling passive continental marginal fold belt, the Nanpanjiang continental marginal fold belt, the Linxi–Ulanhaote and Jilin–Yanbian fold belts, the Badanjilin continental marginal fold belt, the southern Qaidam–Animaqing accretion fold belt, the Hoh Xil continental marginal fold belt, the Yidun island arc accretion fold belt, the Songpan–Ganzi continental marginal fold belt, and the Southwest Sanjiang fold belt including the Jinsha, Minjiang, and Nujiang rivers. (4) The Yanshanian–Himalayan Orogenic Belt includes mainly the NaDanhada, Bangonghu–Nujiang, and Indus–Yaluzangbujiang accretion fold belts.

1.2

Outline of Regional Tectonic Evolution

The Chinese mainland has experienced a long and complicated evolution consisting mainly of three landmasses with North China, Tarim, and Yangtze as the core and eight orogenic belt including Altai–Xingmeng, Tianshan–Junggar–Beishan, Qinling–Qilian–Kunlun, Qiangtang–Sanjiang, Gangdise, Himalayan, Cathaysia, and Eastern Taiwan tessellated pavement (Figs. 1.1 and 1.2). At present, 21 ophiolite belts and 4 large rift belts have been identified in the stable continental peripheral area of interior China (Fig. 1.3); their development time limits provide important constraints for reconstructing the tectonic evolution history of China. The Jiangnan Rift Belt, located in South China, is the earliest closed rift since the Neoproterozoic in mainland China. It closed at 835–820 Ma under the collision of the Yangtze and Cathaysia blocks. The latest rift record is the current Taitung Longitudinal Valley. Formed in the Miocene as the result of a combination of the Pacific, Eurasian, and Philippine plates, this rift belt is still currently developing. In addition, according to the developmental age and background of the ocean basin and rift, the other ophiolites and rift belts in the Chinese mainland can be classified into three main structures: the ancient Asian Ocean, the ancient Tethys, and the New Tethys. The domain corresponds to the Junggar–Tianshan–Xingmeng, Qinling–Qilian–Kunlun, and Qinghai–Tibet areas in the current geographical position. The ocean basins and rift of the Guttisian tectonic domain include mainly the Kuqian Ocean, the South and North

1.2 Outline of Regional Tectonic Evolution

Altun Oceans, the South Qilian Rift Valley, the North Qilian Ocean, and the Northern Qinling Ocean, most of which formed during the Sinian–Cambrian. The South Altun Ocean closed at 500–462 Ma, and the remaining basin/rift in the area closed during the Ordovician-Devonian, resulting in a collage of the Tarim and North China plates. The Junggar– Tianshan–Xingmeng area belongs to the formation and evolution of the Central Asian Orogenic Belt and is closely related to the subduction and proliferation of the ancient Asian Ocean. In addition to the Late Jurassic–Early Cretaceous activity, the ocean basins in this area were closed in the Carboniferous–Permian. Among them, the South Tianshan Ocean experienced two cycles of opening/closing. The final closure of the Paleo-Asian Ocean marks the completion of the subduction–proliferation–collision orogeny in the northern part of the Chinese mainland. Although the ancient Tethys Ocean is closed, a series of Late Paleozoic rifts have been formed in the present Qinghai–Tibet and peripheral areas of China such as Helan Mountain and Longmenshan Rift and as well as small ocean basins such as the South Qinling, Kangxiwa, and Jinshajiang basins. The rift experienced a long evolutionary stage and eventually closed in the Jurassic–Cretaceous, whereas the oceanic basins developed during shorter periods; all of them closed during the Middle Permian to Late Triassic. At this time, owing to the closure of the South Qinling Mountains, the North China, and Yangtze plates collided. During the middle of the Mesozoic era, basins were still present in the Qinghai–Tibet region, such as the Minjiang, Bangong Nujiang, and Yarlung Zangbo river basins. The Minjiang and Bangong Nujiang river basins closed between the Early Cretaceous and the Paleogene; the Yarlung Zangbo River Basin continued to develop through 65–55 Ma until the Eurasian and Indian plates finally collided. From the closure time of the paleo ocean basins and rifts, the tectonic evolution of the Chinese plate can be divided into the following five stages. (1) Neoproterozoic: The rift in south China closed, and the Yangtze plate collided with the Cathaysia plate. (2) (Middle Ordovician–) Shiliu–Devonian (–Early Carboniferous): The rift and ocean basins in Qinling–Qilian–Kunlun area closed, and the Tarim plate collided with the North China plate. (3) Carboniferous– Triassic/Middle Permian–Triassic: The ocean basins in the Junggar–Tianshan–Xingmeng and Qinghai–Tibet areas closed; the Central Asian orogenic belt accreted to the edge of the Tarim–North China plate; and the North China plate collided with the Yangtze plate. (4) Late Jurassic–Early Cretaceous: The northern ocean basin of the Qinghai–Tibet area closed, and the Qiangtang and the Lasa areas collided

13

with the Yangtze plate. (5) Paleogene: The Yarlung Zangbo River basin in the Qinghai–Tibet area closed, and the Indian plate collided with the Eurasian continent. During the evolutionary stages of these plate tectonics, the corresponding foreland thrusting structures were formed in the same orogenic period in the areas of South China, Qinling–Qilian– Kunlun, Junggar–Tianshan–Xingmeng, and Qinghai–Tibet.

1.2.1 Structural Cycles in Mainland China Table 1.3 shows China’s tectonic development and tectonic cycle division (Liu and You 2015). The country’s tectonic evolution can be divided into five major structural stages, as described below. (1) Archean–Paleoproterozoic cycle, Ar–Pt1 (>1800 Ma) Fuping cycle and older. Different stages or cycles can be further divided according to specific situations, such as the Wutai cycle (Ar23), the Fuping cycle (Ar13), and the Qianxi cycle and older (Ar1-2). (2) Mesoproterozoic–Neoproterozoic Early cycle, Pt2–Pt13 (1800–780 Ma) This can be further divided into Mesoproterozoic (Pt2), Early Neoproterozoic (Pt13), Middle Neoproterozoic (Pt23), and other different cycles. (3) Nanhuan system–Middle Triassic cycle, Nh–T2 (780– 227 Ma) This can be divided into the Caledonian cycle (Nh–PZ1) from the Nanhuan system to the Early Paleozoic and the Haixi cycle of the Late Paleozoic. Some areas include the Early Indosinian cycle (T1–2) of the Early–Middle Triassic. Late Triassic–Early Cretaceous cycle, T3–K1 (227– 99.6 Ma). This cycle includes the Early Yanshan cycle mainly in the Jurassic and the Late Yanshan cycle mainly in the Cretaceous. This cycle is very important for the Yangtze and the North China region. In the Yangtze region, except for the Sichuan Basin, almost all early oil and gas reservoirs were destroyed. In North China, except for the Ordos Basin, this cycle caused uplifting and denudation during almost the entire Paleozoic, followed by faulted depression and subsidence. Later, the basement (buried hill) of the Cenozoic rift basin was formed in eastern China.

14

Late Cretaceous–Present, K2–Q (after 99.6 Ma). Late Cretaceous to present cycle, K2–Q (99.6 Ma– present). Since the Late Cretaceous, the North China Craton has been changed strongly, and the Bohai Bay, Ordos, Alxa, and other areas uplifting to land. The collision between the Indian continent and Eurasia, which started at 65 Ma, severely transformed the western part of China in the Cenozoic, forming a giant basin-mountain system around the Qinghai-Tibet Plateau. While, eastern China was in the post-arc environment of the West Pacific subduction zone, and the post-tensioning belt gradually moved eastward. During the Late Cretaceous–Quaternary period, the Chinese mainland experienced a large east–west direction uplift of tectonic and material changes. The topography evolved from west low east high in the Early to Middle Mesozoic to west high east low in the Late Cenozoic. Its tectonic environment changed to the following three parts: compression in western, extension in east and transition in the middle parts. So, the Paleozoic (to Triassic) marine sedimentary basins were deeply buried or strongly reconstructed.

1.2.2 China’s Tectonic Evolution China is located in the southeastern part of the Eurasian plate, with the Pacific and Philippine Sea plates in the east and the Indian plate in the south (Fig. 1.1). The Cenozoic tectonic activities in eastern China are controlled mainly by interaction of the Pacific, Philippine, and Eurasian plates, and the Cenozoic tectonic activities in Western China are restricted mainly by interaction of the Indian and Eurasian plates (Figs. 1.4 and 1.5). This tectonic evolution of China is more regular and specific in terms of time and space than the global tectonic evolution (Table 1.3).

1.2.2.1 Complex of Several Small Land Masses and Fold Belts Sandwiched Between the Continents of Laura and Gondwana In the Sinian (Ediacaran)–Early Permian, the two continental regions on Earth consisted of Siberia, Eastern Europe (Russia), and North America (Laurun) ancient continent (craton or platform). After the Silurian, North America and Eastern Europe merged into Laurussian ancient land; in the Late Carboniferous–Early Permian, Laurussian, and Siberia merged into the Laurasian continent. China and its neighboring areas, located between the two continental blocks, are composed of a combination of small landmasses (small cratons or quasi-platforms) and numerous micro-blocks and orogenic belts. The size and structural stability of these small blocks and micro-blocks that make up

1 Regional Tectonic Setting and Prototype Basin Evolution

the Chinese complex are small compared to the entire areas of North America, Eastern Europe, and Siberia (Ren et al. 2013, 2016).

1.2.2.2 Three Major Dynamic Systems of Global Tectonic Evolution Since the Sinian, the following three major dynamic systems have been developed: the Paleozoic Proto-Atlantic–Rick Ocean–Paleo-Asian Ocean, the Mesozoic Tethys– Paleo-Pacific, and the Late Mesozoic–Cenozoic Atlantic– Indian Ocean–Pacific. (1) Paleo-Atlantic–Paleo-Asian Ocean Tectonic Domain This includes all Paleozoic orogenic belts and continental marginal activation belts from Appalachia through Central and Western Europe to Tianshan–Xing’an, and Kunlun– Qinling. (2) Tethys tectonic domain This includes all Tethys Meso–Cenozoic orogenic belts from the Alps through the Middle East, Qinghai–Tibet, to Indo-China–Malay Peninsula and Indonesia as well as the Cenozoic recurrent mountain system in Central Asia. (3) Pacific tectonic domain This includes all Phanerozoic structures of the Pacific Rim, mainly the Meso–Cenozoic orogenic belts and the continental marginal activation zone. The evolution of mainland China is controlled by the three major dynamic systems of the world and shows the uniqueness of its own development. China’s landmasses with the main symbols of the Yangtze, North China (China and North Korea), and Tarim are in the transitional tectonic domain between the global continents. In the Paleozoic, the Chinese landmass was located in the southern Paleo-Asian Ocean and was part of the Gondwana continent or constituted a complex continental margin. In the Mesozoic, it was located in the northern Tethys and was part of the Laura continent. In the Cenozoic, it belongs to the Pacific tectonic domain.

1.2.2.3 Regularity and Particularity of Tectonic Evolution of China’s Main Craton Under the influence of the three major dynamic systems (the difference in space), the three major craters of China’s Yangtze, North China, and Tarim have undergone tectonic evolution of five cycles in the Caledonian, Hercynian, Indo-China, Yanshan, and Himalayan, respectively.

1.2 Outline of Regional Tectonic Evolution Table 1.3 China’s tectonic development and tectonic cycle division (after Liu and You 2015)

15

16

1 Regional Tectonic Setting and Prototype Basin Evolution

Fig. 1.3 China’s pristine ocean basin and rift development and closure time

1.3

Formation and Evolution of China’s Major Marine Prototype Basins

As mentioned in the above two sections, the phased time and spatial differences in China’s marine tectonic evolution are the basic structural factors that determined the hydrocarbon accumulation conditions and exploration prospects of China’s marine basins such as Sichuan, Ordos, Tarim, and North China. Therefore, this section discusses the regional structure and formation as well as the evolution of these basins and related areas.

1.3.1 Tectonic Evolution of the Sichuan Basin 1.3.1.1 Overview of the Sichuan Basin Strata Development During the Phanerozoic, the Sichuan Basin was characterized by intracontinental deformation and basin development under plate tectonics limits. Its north side is the Qinling Ocean Basin, which contains the north Qinling Ocean in the Early Paleozoic and the south Qinling Ocean during Late Paleozoic and Trassic periods. The southwestern side includes the Changning–Menglian, Jinshajiang–Mojiang,

and the Ganzi-Litang (mainly the Paleo-Tethys) ocean basins, and the southeast side includes the Jiangnan–Xuefeng intracontinental rift zone (mainly the Early Paleozoic rift) and the northwestern Longmenshan intracontinental rift zone (mainly the Late Paleozoic rift). The opening and closing of these ocean basins or rift belts have led to three evolutionary stages in the Sichuan Basin and its adjacent areas: the Proto-Tethys Ocean (Z-S), the Paleo-Tethys Ocean (D-T), and the Neo-Tethys Ocean (J-Q). Above the Sinian crystal basement in the Sichuan Basin, marine sediments of Sinian–Middle Triassic (or early Late Triassic) and Late Tertiary (Late)-Quaternary continental deposits developed. The sediment thickness is 6000– 12,000 m, and the formation is relatively complete. In the long-term development process, at least 10 large parallel unconformities, including Z/AnZ, Є/Z, O/Є, D/S, P2/AnP, P3/ P2, T3/T2, T3x4/T3x3, J/T, and K/J (Fig. 1.6) can be identified within the basin owing to the influence of surrounding plate tectonic activities and regional transgression and retreat events. (1) Unconformity between Sinian and pre-Sinian (Z/AnZ) The Sinian and pre-Sinian unconformity (Z/AnZ) is the result of the Jinning movement. The Sinian strata is the first sedimentary caprock in the development period of the

1.3 Formation and Evolution of China’s Major Marine Prototype Basins

17

Fig. 1.4 Tectonic diagram of China and its neighboring areas (Ren et al. 2013, 2016)

Aretic Ocean

Mosco

Roman

Pacific Ocea

Siberian Craton

Eastern European Craton

Ulan Bator Alma-Ata

Beijing

Teheran

Arabian Craton

China Korea Craton

Tarim Craton

Middle Iranian Block

Yangtze Craton

New Delhi

Hanoi

Indian craton Rangoon

Indo-China Sea Craton

su

Ma k

oc

Bl

Indian Ocean

Djakarta

Australia Craton

Main suture Modern Benioff zone

Craton Craton in Laurasia

Iapetus-Paleo-Asian Ocean Domain

Orogen

Reactivated belt

Reactivated belt

Pacific Domain

Craton in Laurasia

Orogen

Craton involved in orogen

Reactivated belt

platform and lie in unconformity with the ancient metamorphic rocks of the pre-Sinian and the intrusive rocks of their corresponding ages. Because the unconformity is old and deep, it is difficult to reach the depth of the unconformity by drilling. Moreover, the pre-Sinian is mainly metamorphic, and the stratification is poor. In the seismic section, the event appears as a disorder reflection, and the unconformity features in the seismic section are not obvious and are difficult to track; only the surface outcrops can be seen because the Sinian unconformity covers the pre-Sinian system.

Tethys Domain

Orogen

(2) Unconformity between Cambrian and Sinian (Є/Z) The Cambrian and Sinian unconformity (Є/Z) is the result of the Tongwan movement, and the Cambrian and Sinian are parallel unconformity contacts. The Cambrian is thinned from the east and west sides to the Leshan–Longnusi paleo-uplift in the central Sichuan Basin. In the Daliangshan area, the Lower Cambrian Jiulaodong Formation covers the Sinian Hongchunping Formation in parallel unconformity.

18

1 Regional Tectonic Setting and Prototype Basin Evolution

500 km

rb

asi

n

Junggar basin

sh

an

or

og

en

ic

be

Sa

Tu

ha

lt

nt

bas

an

ng

an

gh

ub

So

Ti

lia

o

H

a ail

in

250

bas

0

as

in

★

roge

nic b

elt

Q ia n g ta n Cuo

qin b

g b as in

ida

Te t h y

Qi

m

ba

s Str

lia

no

sin

uctu

rog

ral D

eni

cb

oma

asin

Bo

Ordos basin

elt

in

Qinl

ing o

roge

an ub asi n

nic b

h ut So u- sin s g a an b Ji sea rth w no ello y

elt

in

La

Th

an eY

np -S im ao

l eB

Ca

oc

a th

ys

k

i

l aB

oc

k

Sh

iw

an

da

sin

sh

ba

an

ing

Yunnan-GuizhouGuangxi basin

gtz

sin

bas

ba

ang

ay

Sichuan basin

gd

g r ig

ib

North China Block

Ch

D in

ha

North yellow n sea basin

eas she t Chin lf b asin a sea

Qa

si ba

The

lun o

in

belt Erl genic n oro a h s n Yi Beijing

in

Tarim basin

Kun

bas

ian

Beibu gulf basin

Pe

l ar

riv

er

m

ou

th

ba

sin

in

Y gg eh

Legend

ai ba si n

main fault

paleo-Asian ocean system

Himalayan epoch suture zone

marine basin

Indo-Chinese epoch suture zone

Hercynian epoch suture zone Caledonian epoch suture zone

marine basin with carton basement basin with fold basement continental basin

(after Chen Huanjiang, 1990; Ding Guidao, 1996; Xu Xiaosong et al., 1997; Ren Jishun, 1999, Institute of Sinopec Star Co. , LTD., 2000) Instructions: Data shortage in Taiwan province. Data shortage in the Hong Kong & Macao Special Administrative Regions.

Zengmu basin

Fig. 1.5 Distribution map of tectonic and sedimentary basins in China and its adjacent areas

(3) Unconformity between Ordovician and Cambrian (O/Є) The Ordovician and Cambrian unconformity (O/Є) is the result of the Mid-Caledonian movement, and the Ordovician strata onlap the Cambrian strata in the local area. In the

chronological stratigraphic section of the southern Longmenshan–East Sichuan fold belt, the Lower Ordovician strata directly covers the Middle Cambrian strata; the two sets of strata are in parallel unconformity contact, and the time of the depositional break is about 25 Ma.

1.3 Formation and Evolution of China’s Major Marine Prototype Basins

(4) Devonian and Silurian Unconformity between Devonian and Silurian (D/S) The Devonian and Silurian unconformity (D/S) is the result of the Late Caledonian movement. The Silurian and Devonian strata are largely missing in the basin and are in parallel unconformity contact. In the Jianshen 1 well, the Middle Devonian and the Lower Silurian units have been penetrated. The two are in parallel unconformity contact, and the time of the hiatus is about 24 Ma. (5) Middle Permian and Pre-Permian Unconformity between Middle Permian and Pre-Permian (P2/AnP) The Middle Permian and the Pre-Permian unconformity (P2/AnP) are regional and parallel unconformities. The Middle Permian directly covers the Cambrian, Ordovician, and Silurian units, showing a truncated reflector. The longest time of hiatus is the Cambrian and Middle Permian sedimentary interval, which is about 240 Ma. It is the result of the Late Hercynian movement; the Middle Permian cutting Ordovician and Silurian strata can be clearly identified in the seismic section. (6) Upper Permian and Middle Permian Unconformity between Upper Permian and Middle Permian (P3/P2) The Upper Permian and Middle Permian unconformity (P3/ P2; Early and Late Permian global structural unconformity in the previous dichotomy of the Permian) was interpreted as a result of Hercynian–Dongwu movement. The two are in parallel unconformity contact. This unconformity was affected by the activities of the “Emeishan mantle plume” in the Late Permian. Owing to the large-scale eruption of the Emeishan basalt, normal fault activity in the basin is frequent. (7) Upper Triassic and Middle Triassic Unconformity between Upper Triassic and Middle Triassic (T3/T2)

19

hiatus is 12.9 Ma, which is characterized by the first member of the Xujiahe Formation directly covering the first member of the Leikoupo Formation. This reflects that the Chuandong fold belt was still developing during this period. However, in the Sichuan Basin, most areas are essentially parallel unconformity contacts. (8) Unconformity between the fourth and third members of the Xujiahe Formation (T3x4/T3x3) The unconformity between the fourth and third members of the Xujiahe Formation (T3x4/T3x3) is the result of the middle Indo-China movement and is known as Anxian movement in western Sichuan. This marks the beginning of the Late Triassic foreland thrusting activity in the Sichuan Basin. In the area of Longmenshan–Longquanshan, T3x4 truncates the T3x3 strata and has a trend of wedge-shaped thinning toward the middle of the Sichuan unit. The lower part of T3x4 also exhibits onlap deposition. According to the large thickness and regional distribution characteristics of T3x4, the foreland basin has reached a large scale in this period, showing a dramatic shift in the properties of the basin. Essentially, all appear as parallel unconformity contacts. (9) Unconformity between Jurassic and Triassic (J/T) The Jurassic and Triassic unconformity (J/T) is the result of the Late Indo-China movement. The low-angle unconformity contact relationship between the Jurassic and the Upper Triassic units can be seen in the western Sichuan depression. The growth axis of the Upper Triassic anticline terminates upward in the lower part of the unconformity but does not clearly indicate the end of the Late Triassic foreland thrusting activity. This indicates that the basin property is about to be converted. At the periphery of the basin, the thick conglomerate of the Lower Jurassic Baitianba Formation is parallel unconformably above the Upper Triassic unit, and the thick lacustrine deposits of the Lower Jurassic in the basin indicate that the basin has entered the development of the Craton depression.

The unconformity between the Middle and Upper Triassic is the result of Early Indo-China movement (Figs. 1.7 and 1.8), which marks the end of the marine sedimentation in the (10) Unconformity between Cretaceous and Jurassic (K/J) basin, and the top of the Triassic Leikoupo Formation is truncated. The time of the depositional break is about The Cretaceous and Jurassic unconformity (K/J) is the result 9.15 Ma. The first member of the Upper Triassic Xujiahe of the Early Yanshanian movement; the unconformity conFormation onlaps the Leikoupo Formation in local areas, and tact is parallel. The Cretaceous unit is missing in the the time of the depositional break is about 13.45 Ma. In the southern part of the Longmenshan and the western Sichuan Chi 7 well in the Yudong area, the Xujiahe Formation shows depression zone. The Upper Cretaceous parallel unconfortruncation with the overlying strata. The minimum time of mity covers the Jurassic unit, and the sedimentary discontithe hiatus is 4.3 Ma, which is characterized by the first nuity is about 40 Ma. The Lower Cretaceous unit is also member of the Xujiahe Formation directly covering the third missing from the Han 1 well. The Upper Cretaceous parallel member of the Leikoupo Formation. The maximum time of unconformity covers the Upper Jurassic unit.

0-380 1.64

Cenozoic

Neogene

0-300 23

Palaeogene

5

0-800 65 Upper 0-1382

Cretaceous

4

Lower Jurassic Mesozoic

154 175

Rhartian Norian Anisian Olenekian Lower Induan Capitanian Capitanian Lopingian Wuchiapingian Wuchiapingian Lengwuan Capitanian Wordian Gufengian Permian Guadalupian Xiangboan Roadian Kungurian Liodianian Longlinian Artinskian Cisuralian Sakmarian Zisongian Asselian Gzhelian Xiaodushanina Dalan Kasimovian Pennsylvanian Moscovian Huashibanian Car Luouan Bashkirian -boniferous Serpukhovian Dewuan Mississippian Visean Jiusian Shangsian Tournaisian Tangbagouan Famennian Famennian Upper Frasnian Frasnian Givetian Givetian Middle Eifelian Eifelian Devonian Emsian Emsian Pragian Pragian Lower Locjkovian Locjkovian

Upper Middle

Triassic

Paleozoic

145

Upper Middle Lower

Pridoli Ludlow Silurian Llandovery Upper Middle

Ordovician

Lower Cambrian

3rd Series 2nd Series

Ediacaran

Ludfordian Ludfordian Telychian Telychian Aeronian Aeronian Rhuddanian Rhuddanian Qiantangjiangian Katian Sandbian Aijiashanian Darriwilian Darriwilian Dapingian Dapingian Floian Floian Tremadocian Tremadocian 5th Stage Maozhuangian Xuzhuangian Longwangmiaoan 4th Stage Canglangpuan 3rd Stage Qiongzhusian

220 240 251.0 260.4 268

0-838 0-466 0-730 0-845 0-120 0-518 0-249

3

2 1

Evolutional Phase

Com -pressional basin Intracraton depression Foreland basin

3

0-148 0-158 299 2

320

0-800

355

0-280 0-522 0-1080 0-1615 0-410 0-2000

385.3 397.5 416 419

460.9

0-15 0-60

471.8

0-208

510

0-228

521 542

Craton edge rifting and intracraton depression

1

0-410 0-668 0-465

444

Sinian

4

Intracraton depression and peripheral foreland basin

3

0-1870 0-1200

2

Intracraton depression and marginal rifting

1

630

Neo -proterozoic

203

0-1862 0-3361 0-450

Basin Property Basin uplifting intra -continental compression foreland basin

Cryodenian

Nanhua 850

Tonian

0-4000

Basin basement

Qingbaikou 1000

Convergent

Thickness/m Tectono-Stratigraphy

Extension

Lithology

Convergent

Age Ma

Tectonic Movement

Main Tectonic Events Longmenshan uplift. Southwest Sichuan subsidence.

Himalayan Movement

Yanshanian Movement

Indo-China Movement

Central and eastern regions uplift and denudation. Jianghan area rift. Basin compression deformation. Eastern sichuan block type fault-fold belt formation.

The western Pacific subducts westward. Helan-Longmen North-South tectonic belt activity. Weak stretched depression in the land, peripheral squeezing. Yangtze/North China block collision. Northern Yangtze developed foreland basin. Carbonate platform,Evaporite basin.

Dong Wu Movement

Large scale eruption of Emeishan basalt. Paleo-Tethys Ocean dive reduction. Kaijiang-Liangping, Chengkou-West Hubei intracontinental depression. Eastern tethys ocean expansion; The south and north margins of the Yangtze form a passive continental margin; Longmenshan formed intracontinental rifting trough.

Extensional cracking

(China)

Caledonian Movement Convergent

Stage

The west margin, north margin and south margin of the Yangtze plate breakup. Foreland basin formation in the southeast margin of the Upper Yangtze,Passive continental margin on the north side of the middle and Upper Yangtze. Jiangnan-Xuefeng intracontinental rift basin closed; The ancient uplift formation.

Carbonate platform

Extensional cracking

Stage

(International)

Pangea extension convergence cycle

Series

Paleo-Tethys evolutionary stage

System Quaternary

Rodinia extension convergence cycle

Erathem

Neo-Tethys evolutionary stage

1 Regional Tectonic Setting and Prototype Basin Evolution

Proto-Tethys evolutionary stage

20

Carbonate platform

Tongwan Movement

Rising ocean current sediment. Rapid transgression.

Nantuo Formation tillite

Underlying rift filling.

Chengjiang Movement

Jiangnan Ancient Land formation.

Jinning Movement

Oceanic crust subduction.

Fig. 1.6 Tectonic–stratigraphic sequence and formation and evolution stages of the Sichuan Basin (after He et al. 2011)

1.3.1.2 Tectonic–Stratigraphic Sequence Framework of Sichuan Basin Based on the aforementioned regional unconformity, the Sichuan Basin can be divided into the following four tectonic–stratigraphic sequences (Figs. 1.7 and 1.8), which correspond to the four major evolution cycles of the basin.

(II2), 500–1400 m in thickness; Ordovician (II3), 100–800 m in thickness; and Silurian (II4), 100–1000 m in thickness. Influenced by the formation and evolution of the Leshan– Longnusi paleo-uplift spread in the NE–E direction, the geological structure of sequence II is extended with uplift and depression segmented in the NE–E direction.

(1) Sequence I

(3) Sequence III

Metamorphic rock of the Qingbaikou and Nanhuan system, which constitutes the basement (basal cycle) of the basin. The fundamental series is distributed in the northeast direction, and the central Sichuan area is a hard basement with a high degree of metamorphism. The top surface is buried at depths of 3–8 km. Western Sichuan and eastern Sichuan are soft bases with lower degrees of metamorphism. The depth of the top surface is 8–11 km.

Upper Paleozoic–Middle Triassic rocks. These include Devonian–Lower Carboniferous (III1), with sediments in the Longmenshan fault-depression and the eastern Sichuan depression, most of which were not deposited inside the basin; Upper Carboniferous–Lower Permian System (III2), where Upper Carboniferous rocks are developed in the eastern part of Sichuan province with a thickness of 10– 60 m, and Lower Permian rocks are distributed only at the edge of the basin; and Middle Permian–Middle Triassic (III3), which is regional transgression (P2-3)–sea retreat (T1-2) sedimentation. In the interior of the basin, the middle and Lower Permian thickness is 400–500 m; the Upper Permian thickness is 400–1800 m, the Lower Triassic thickness is 400–1200 m, and the Middle Triassic thickness is 100–

(2) Sequence II Sinian–Lower Paleozoic rocks composed mainly of marine carbonates and fine clastic sediments in the upper part. These include Sinian (II1), 300–1200 m in thickness; Cambrian

1.3 Formation and Evolution of China’s Major Marine Prototype Basins

21

Sea level (m) Ls 1 2 000 0

50

100 km

1 500 1 000

Ds 1 Ck 1

500

Cj 566

K1 j

Dong 6

LuoG 1

Ms 1

0

Sea level (m) 1 000 500 0

J3 p

-500 -1 000

-500 -1 000

J3 sn

-1 500

T1 j

J2 s J2 q

-2 000

-2 000

P3

J1

-2 500

-1 500

T1f

-2 500

P2

-3 000

T3x

-3 000

S

-3 500

-3 500 O

-4 000

-4 000

-C2+3

-4 500

-4 500

-C1

-5 000

-5 000 Z2

T2l

-5 500

-5 500

Ls1 K1 j

J3 p

J3 sn

J2 s

J2 s

J2 q

J1

T3x

T2l

T1 j

T1f

P

P2

S

O

-C2+3

-C1

Z2

Ck1 Cj566 Ms1 LuoG1 Dong6 Ds1

Fig. 1.7 Northwest–southeast tectonic geologic profile of the Sichuan Basin

900 m. The geological structure of Sequence III reflects strong structural and sedimentary differentiation characteristics. (4) Sequence IV It composed of the Upper Triassic–Quaternary continental fluvial–delta–lacustrine environment sediments. This includes Upper Triassic (IV1), thickened from central Sichuan to western Sichuan; Middle and Lower Jurassic (IV2); Upper Jurassic–Lower Cretaceous (IV3); Upper Cretaceous (IV4); and Cenozoic (IV5). The Upper Triassic thickness is 500–2500 m, which thickens from central Sichuan to western Sichuan. The Jurassic thickness is 2000– 4400 m and is thickest in front of the Ta Pa Mountains. The Cretaceous–Paleogene rocks are distributed in central, western, and southwest Sichuan with a thickness of 950– 1650 m. The Neogene–Quaternary rocks are distributed mainly in western Sichuan with a thickness of 0–350 m.

1.3.1.3 Formation and Evolution of the Sichuan Basin The two global tectonic cycles since the Neoproterozoic, namely the Rodinia continental breakup convergent cycle (1000–250 Ma) and the Pangaea continental breakup convergence cycle (250 Ma–present), constrained the overall structural framework of the Upper Yangtze Craton evolution. Controlled by the aforementioned global tectonic cycle control, the area has experienced three major evolution stages of the Proto-Tethys Ocean (Z-S), Paleo-Tethys Ocean (D-T), and Neo-Tethys Ocean (J-Q), each stage including the extension associated with the ocean basin opening and the convergence compression associated with the ocean basin closing. Under the influence of these tectonics, the extensional and compressional basins are alternately developed within the craton, showing the development cycle of the basin. Accordingly, the Sichuan Basin has experienced three extensional and convergent cycles since the Phanerozoic (Figs. 1.9 and 1.10). The Rodinia supercontinent

22

1 Regional Tectonic Setting and Prototype Basin Evolution

Sea level (m) 1 000

Han1

500

K1 j

0

J2 p

-500

0

Dashen 1

50 Gs 1

Cfeng 188

Sea level (m) 1 000 Chi 7

100 km Zuo 3

Ns 1

Ms 1

500 0 -500

J3 s

-1 000

-1 000

J2 s

-1 500

J1

-1 500

-2 000

T3x

-2 000 -2 500

-2 500 -3 000 -3 500 -4 000 -4 500 -5 000 -5 500

T2l

-3 000

T1 j T 1f P3

S

P2 -C2+3 -C1 Z2

O

-3 500 -4 000 -4 500 -5 000 -5 500

K1 j

J3 p

J3 s

J2 s

J2 q

J1

T 3x

T2l

T1 j

Ns 1

T1f

Ms 1 Dshen 1 Gs 1 Han 1 Cfeng 188

P3

P2

S

O C

-C2+3

-C1

Chi 1

Zuo 3

Z2

Fig. 1.8 Southwest–northeast tectonic geological section of the Sichuan Basin

breakup into the Proto-Tethys evolution stage and intraplate extension occurred between the Yangtze and Cathaysia blocks, which became the Hunan–Guangxi intracontinental rift sea basin. The breakup events at the edge of the middle and Upper Yangtze appear as the intra-cratonic extension and a marginal rift. In the Proto-Tethys tectonic evolution stage from the Sinian to the Silurian, convergence into the South China continent and transformation into the Late Paleozoic Paleo-Tethys tectonic evolution stage occurred from the extensional basin to the Caledonian compressional orogeny (He et al. 2011).

1.3.2 Formation and Evolution of the Ordos Basin 1.3.2.1 Structural—Stratigraphic Sequence and Evolutionary Stages According to lithofacies association characteristics, sedimentary sequences, unconformities, molasses formations, and tectonic deformation features, the Ordos Basin was divided into the following tectonic layers: the Lvliang cyclic tectonic layer, Jinning cyclic tectonic layer, Caledonian cyclic tectonic layer, Hercynian cyclic tectonic layer, Indo-China cyclic tectonic layer, Yanshanian cyclic tectonic layer, and Himalayan cyclic tectonic layer (Fig. 1.11).

1.3.2.2 Formation and Evolution of the Ordos Basin According to the division scheme of the tectonic layer, the formation and evolution of the Ordos basin was divided into the following stages (Fig. 1.12). (1) Basement formation and evolution Before 2500 Ma, the continental nucleus was formed in North China and later cracked into different landmasses and microcontinental blocks. During 2100–1850 Ma, ancient landmasses or microcontinental blocks of varying sizes having the characteristics of the Phanerozoic Orogeny were matched and accreted and eventually formed the North China Craton. The crystalline basement of the Ordos Basin is similar to that of the North China Plate; that of other areas is composed of Archean and the Paleoproterozoic rocks. The Archeozoic basement is a metamorphic complex set containing mainly amphibolite facies metamorphic rocks and partly granulite facies. The metamorphic rock series of the greenschist facies are generally subjected to strong migmatization. The Yimeng uplift of the northern Ordos was formed by the southward accretion of the North China Craton. The crystalline basement is composed of the Jining group ancient granulite facies metamorphic rocks, and its structural feature

H u ay i n g Mountain

Lo ng me n M o un t a i n

1.3 Formation and Evolution of China’s Major Marine Prototype Basins

Songpan NW Deformation Central Sichuan Zone Western Sichuan

Western Eastern Hunan-Hubei Sichuan Fold Belt Fold Belt

Depression

23

Xuefeng Uplift

SE

Central Hunan Depression

100-0 Ma Jiangnan-Xuefeng Intracontinental Orogenic Mevement Longmenshan Songpan Orogenic Belt Central Sichuan Kaijiang Deformation Western Sichuan Depression Zone (Since T ) Depression Paleo-Uplift

Yuanma Basin

Cathaysia Block

3

208-100 Ma Jiangnan-Xuefeng Intermontane Basin Development Middle and Upper Yangtze Songpan Carbonate Platform Carbonate Longmenshan Rift Platform

Jiangnan-Xuefeng Depression

Cathaysia Catbonate Platform C-P

Leshan-Longnvsi Paleo-Uplift

Yangtze Carbonate Platform

Southeast Sichuan Foreland Basin

Jiangnan-Xuefeng Orogenic Belt

Jiangnan Fault Depression

409-208 Ma, D Jiangnan-Xuefeng Intracraton Depression Partial exposure to water

Cathaysia Block 463-409 Ma, O3-S Jiangnan-Xuefeng Intracontinental orogenic belt Foreland basin developed

Cathaysia Platform 800-463 Ma, Nh-O2 Jiangnan-Xuefeng Chasmic

Songpan Block

Yangtze Block

Jiangnan-Xuefeng Jiuling Island Arc Jiangshan-Shaoxing Fault

Cathaysia Block 1 000 Ma The Rodinia ancient land is formed

Fig. 1.9 Northwest–southeast tectonic evolution and archetypal basin evolution profile of the Upper Yangtze (after He et al. 2011)

is high in the north and low in the south. The central uplift in the southcentral part of the Ordos is composed of metamorphic rock series of the Wutai and Lvliang groups (Jia et al. 1997; Zhang et al. 1997, 2003). (2) The Middle Neoproterozoic continental breakup (Pt1-2) In 1850–1600 Ma, the extensional breakup stage of the North China Craton occurred (Li et al. 2001; Hou et al. 2005; Yan et al. 2007). The North China Craton’s entrance into the first set of sedimentary cap rocks is characterized by an aulacogen development period on the basis of a breakup into several massifs. In the aulacogen of the Ordos Massif,

the deposits of the epicontinental neritic facies of the Changcheng and Jixianian systems sedimentary formation became thicker. In 1000 Ma, the Jinning movement ended the sedimentary process of the middle Neoproterozoic. In the Early–Middle Mesoproterozoic, the Ordos Basin mainly followed the evolution characteristics of the North China plate and developed a continental marginal rift and an intracontinental aulacogen. In addition, the Changcheng System coastal clastic rocks and the Jixianian System microbial-laminated dolostone bearing zebraic cherts were deposited. In the Late Mesoproterozoic, the Paleo-Asian Ocean subducted into the North China Plate, and the peripheral

24

1 Regional Tectonic Setting and Prototype Basin Evolution Yunnan-Guizhou-Guangxi Composite Orogenic Belt Daba Mountain

Sichuan Block

K2-Q: Inland subduction Intense extrusion transformation

Intracraton depression of Yangtze

Northern Sichuan Foreland Basin

North China Block T2-3: Peripheral foreland basins and intracratonic depressions developed

Youjiang Basin

Emeishan (-250 Ma) Basalt

Yangtze Craton

Island Arc Volcanic Rocks (318-246 Ma) North China Block South Qinling Ocean C2-T1: The subduction phase of the Paleo-Tethys Ocean

Mojiang Ocean Basin

Youjiang Rift

Passive continental margin of Southern Yangtze

Yangtze Craton

Intracraton depression of Yangtze

South Qinling Ocean

North China Block D-C1: The expansion phase of the Paleo-Tethys Ocean The north-south margin of the Yangtze Block is extensional rifting

North Qinling Ocean Ziyang Northern Qinling Rift Micro-massif

North China Block Z-S: The north and south margin of the Yangtze Block is splitting and intracraton depressions developed

Fig. 1.10 South–north tectonic evolution and archetypal basin evolution profile of the middle and Upper Yangtze (after He et al. 2011)

oceanic basin and rift were closed successively, making the North China block (including the Ordos Massif) part of the Rodinia supercontinent. In the Middle–Late Neoproterozoic, with the disintegration of Pangaea, the North China Craton and the Siberian continent split and formed an independent North China plate. Evidence exists that the north and south sides of the Ordos ancient land developed into a stable passive continental margin at the end of the Precambrian. (3) Regional epicontinental sea development In the Sinian–Early Paleozoic, the Ordos Basin and other parts of the North China Craton on the eastern side entered the stage of regional epicontinental sea development, in which the Ordos Massif entered the evolution stage of the Craton carbonate platform (Feng 1989; Yuxin Wang 1994; Fig. 1.12b). At the beginning of the Paleozoic, many other Mesoproterozoic aulacogens on the North China Craton had ceased activity and had become a regional epicontinental sea together with the North China Craton (Figs. 1.13 and 1.14).

(4) Caledonian uplift–erosion (O2-3–C2) During the Caledonian period, the Ordos Massif was uplifted as a whole and was denuded. In addition, the Upper Ordovician–Lower Carboniferous strata were missing (Fig. 1.12c). In the Early period of the Hercynian movement, the Ordos Basin inherited the collisional uplift of the Caledonian movement, which continued until the Late Carboniferous. The weathering and erosion lasted for 1.5–1.8  108 a, resulting in the loss of the Upper Ordovician, Silurian, Devonian, and Lower Carboniferous strata. At the beginning of the Late Carboniferous, the southern uplift of the basin was denuded, and the Carboniferous deposits were missing. (5) Hercynian and Indo-China marine–terrigenous facies development (P1-T3) In the early Late Paleozoic (400–360 Ma), most of the Ordos was characterized by regional sedimentation affected by the transgression of the Paleo-Tethys Ocean, which was recorded as overall stable subsidence. A sedimentary environment was formed with a gradual transition from the Late

1.3 Formation and Evolution of China’s Major Marine Prototype Basins

Mesozoic

Quaternary Neogene Palaeogene K2 Cretaceous K1

2.588 23.04 65

J3

145.5

J2

162.8

J1

199.6

Jurassic

Indo -Chinese Cycle

T3 Triassic

Permian

T1 P2

Upper

P1 Carboniferous

Paleozoic

Devonian

Silurian

Lower

Caledonian Cycle

T2

Ordovician

C2 C1 D3 D2 D1

Paleo-

Lvliang Cycle

Jingning Cycle

Proterozoic

Yangtzen Cycle

Meso- Neo-

Cambrian

Archaeozoic

Sinian Qingbaikou

247.2

299.0 318.1

O3

443.7 460.9

O2

471.8

Construction Environment and Tectonics

Terrigenous clastics clip of clays

Peripheral faulted

Marginal coarse elastic

Extension after extrusion

Terrigenous clastica Coal-bearing formation

Intracontinental basin

MiddleYanshanian Movement

N

N N

N N

N

N

EarlyYanshanian Movement Indo-China Movement

N N

N

Shanxi formation Taiyuan formation Benxi formation Jingbian formation

Terrigenous clastica Coal-bearing formation

Marine-terrigenous facies Coal-bearing formation Hercynian Movement

Caledonian Movement

Pingliang formation Majiagou formation Liangjiashan formation Yeli formation 488.3 Yeli formation 507 Changshan formation Gushan formation Zhangxia formation 521 Maozhuang formation Xuzhuang formation Mantou formation 541

Marine terrigenous clastic, argillaceous Carbonate formation Xingkai Movement

635

Pt3q Pt2 jx

1 400

Changchengian

Pt2ch

1 800

Hutuo group

Pt1ht

Wutai group

Pt1wt

Jixianian

Anding formation Zhiluo formation Yan’an formation Fuxian formation Yanchang formation

Formation and Sedimentary Facies

359.2 385.3

422.9

-C1 Pt3z

Himalayan Movement LateYanshanian Movement

Zhifang formation N N N N N N NN 252.3 Heshanggou formation Liujiagou formation N N N N N 260.4 Shiqianfeng formation 270.6 Shihezi formation

416

-C2

Quaternary Neogene

Zhidan group

S2 S1

-C3

Tectonic Movement

Lithology

96

S3

O1

Strata

The Paleotethys Ocean and the broad basin developed

Cenozoic

Hercynian Cycle

Yanshanian Cycle

Himalaya Cycle

Age (Ma)

Stratigraphic Unit

The ocean basin subducted and basin uplifted and denuded

Tectonic Cycle

25

2 500

Jinning Movement

Wide epicontinental sea

Lvliang Movement

Hutuo group

Marine clastic rocks

Wutai group

Marine and volcanic sedimentary rocks

Aulacogen

3 000

Fuping group Jining group

V N

V N

V N

V

N

V N

Crystalline basement Miscellaneous rock

Fig. 1.11 Tectonic–stratigraphic sequence and main geodynamic events in the Ordos Basin (after Fu et al. 2012)

Carboniferous fan delta and the coastal and shallow tidal flat to the Permian alluvial plain, swamp, and coastal shallow sea and the Early and Late Triassic fluviatile and lacustrine facies. The Indo-China movement of the Middle and Late Triassic caused the uplift of the North China block and completely ended the history of the Greater North China Basin (Fig. 1.12d). During the Late Carboniferous and Permian, the Ordos Basin developed mainly marine–terrigenous environment sediments. The influence of the Hercynian movement was

generally weak; most of the layers are characterized by conformities or shorter erosional unconformities. During the Triassic, the Ordos Basin and the western margin were still part of the North China Craton Basin; however, the proximal fan, rivers, swamps, deltas, and lakes were all developed. In addition, important hydrocarbon-bearing strata were developed in the Ordos Basin (Fig. 1.15). Even the Jurassic, during the development of coal-bearing strata, these strata layer constituted one of the important hydrocarbon-bearing areas in the Ordos Basin.

26

1 Regional Tectonic Setting and Prototype Basin Evolution E Q Kz K

N C

J C-P-T -C-O Pt2-3 (g) Cenozoic peripheral basin evolution stage (N-Q)

K J C-P-T -C-O Pt2-3 (f ) Extension after extrusion (K)

J C-P-T -C-O Pt2-3 (e) Inland basin evolution stage dominated by intraplate tectonics (J) C-P-T -C-O

Pt2-3

Pt2-3 (d) The Paleotethys Ocean and the broad basin developed (D2-T3) -C-O Pt2-3

Pt2-3

(c) The ocean basin subducted and basin uplifted and denuded (O3-D1)

-C-O Pt2-3

Pt2-3 (b) Regional epicontinental sea development (C-O1-2)

Pt2-3

Pt2-3 (a) Aulacogen (Pt2-3)

Fig. 1.12 Tectonic evolution profile in the Ordos Basin (after Fu et al. 2012)

1.3 Formation and Evolution of China’s Major Marine Prototype Basins

27

Fig. 1.13 Paleogeographic map of the Ordos Basin in the Cambrian (570 Ma; Bai et al. 2010)

No large land deformations and folds occurred in the basin up to the Cretaceous. At that time, the basin as whole was uplifted, and no large tectonic activity occurred. The dip angle of the basin was less than 1°. Only fault terraces and folds developed at the edge of the basin. (6) The Yanshanian period of the Jurassic fluvial, lacustrine and terrestrial basin evolution (J) The Yanshanian period of the Jurassic is another important period for the development of coal-bearing strata in basins. During this time, the coal-bearing strata of the Early Jurassic Fuxian, Middle Jurassic Yan’an, and Late Jurassic Feifanghe formations were deposited (Fig. 1.12e). During the Early Jurassic Fuxian period, the basin as a whole was deposited. The filling leveled the rough paleogeomorphology at the end of the Triassic, mainly by the development of fluvial facies. The sedimentary paleocurrent

direction of the Yan’an period was mainly southward, and the source originated from the northwest and northeast. Rivers, lakes, and marshes were developed in the basin. This period is the main coal-forming period of the basin. The Late Jurassic Fenfanghe Formation is composed mainly of a set of basin-edge piedmont deposits in the southwestern and western areas of the basin. During the Late Jurassic, some parts of the western part of the Ordos Basin formed structural features of the foreland basin, and the thrust activity in the western Ordos Basin was strong. This resulting in high-angle unconformity contact development between the Jurassic and Cretaceous in most areas. (7) Intrabasinal uplift evolution (K) Even after the Yanshanian tectonic movement, almost no land deformation occurred in the entire Ordos Basin; only certain fold deformation occurred at the edge of the basin.

28

1 Regional Tectonic Setting and Prototype Basin Evolution

0

100

200 km Shenyang

te

ia Pla

Siber

ia

-As

Tarim Plate

o ale

P ean n Oc

Yinshan

nsha

o-Tia

Pale

n

ea

c nO

Hohhot Beijing Dongsheng

n Plate iddle Qilia Pal eoQili an Oc

No

Qaidam-M

Xining

r Ordos)

(Greate rth China

Yinchuan

Lanzhou

Taiyuan

Evaporate Platform

ean

North China Plate

Platform Xi’an

Tibetan Plate

Paleo-Qinling Ocean

Yangtze Plate

ancient land submarine uplift paleo-ocean

littoral

Plate Paleo-Pacif ic

Yumen

the direction subduction of transgression collision zone

bathyal

extinct mid-ocean ridge

neritic

Hefei

offshore

ancient extensional belt

Fig. 1.14 Paleogeographic map of the Ordos Basin in the Early Ordovician (500 Ma; Bai et al. 2010)

During the Cretaceous period, the entire basin was uplifted, and no sediment deposited (Fig. 1.12f). (8) Cenozoic Himalayan period peripheral fault basin evolution (N-Q) During the Cenozoic, the central and eastern parts of China, including the Ordos Basin, moved eastward under the influence of the combined effect of the Neo-Tethys and Pacific dynamic systems. The main basin body was relatively uplifted, and the periphery relatively declined to form a series of fault basins including the Hetao, Bayanhaote, Yinchuan, Weihe, Shanxi Graben, and other basins. This period had a lack of magmatic activity within the main basin body, which was dominated by differential uplift (Fig. 1.12g). During the Late Yanshanian movement and the

Himalayan period, only small fault basins such as the Yinchuan, Hetao, and Fenwei basins were formed at the edge of the Ordos Basin; the main body of the basin was dominated by differential uplift. Therefore, the evolution of the Ordos Basin can be roughly divided into three stages: marine strata development, (Early Paleozoic), marine–terrigenous strata development (Late Paleozoic), and terrestrial strata development stages (Mesozoic and Cenozoic). A large depositional break occurred during the Late Caledonian–Early Hercynian, including the Late Ordovician, Silurian, Devonian, and Early Carboniferous. The basement formation period can be considered as the Middle Proterozoic, similar to the Yanshan and Jixian areas of North China. After the Late Yanshanian movement, the stress state in the eastern China continent changed from compression to

1.3 Formation and Evolution of China’s Major Marine Prototype Basins

29

Fig. 1.15 Paleogeographic map of the Ordos Basin in the Late Triassic (228 Ma; Bai et al. 2010)

extension. Small fault basins such as the Yinchuan, Hetao, and Fenwei basins formed at the edge of the Ordos Basin; the main basin body was dominated by differential uplift. In the past studies, studies on the interior of the Ordos Basin have focused mainly on the Mesozoic and Paleozoic regarding oil and gas enrichment. While studies on the Cenozoic tectonic movement and its effects are relatively lacking. The Cenozoic tectonic movement still had a significant impact on the interior of the Ordos Basin. In particular, the Late Cenozoic compression from the southwestern direction has greatly improved the basin uplift direction, the sediment reception range, and the paleo-tectonic features, which caused significant differences in the tectonic stress field in the northern and southern areas of the basin. The extensional movement occurs mainly in the northern area, whereas the

SW-trending stress and dextral strike-slip occur mainly in the south. The NW-trending and nearly E–W-trending faults with sinistral strike-slip characteristics are distributed mainly in the middle areas. The tectonic activity characteristics are different under the control of the tectonic stress field, leading to the formation of the peripheral fault depression and disintegration of the basin periphery. In the Cenozoic, the Yinchuan, Weihe, and Hetao fault basins were formed in the western, southern, and northern parts of the Ordos Basin, respectively. The development of these basins began mainly in the Eocene, in which tensile extension and strike-slip characteristics developed. The formation of these fault basins disintegrated the periphery of the large Ordos basin, which separated the direct connection between the Ordos Basin and the neighboring mountain systems and promoted the asymmetrical uplift of the large basins.

30

1 Regional Tectonic Setting and Prototype Basin Evolution

1.3.3 Formation and Evolution of the Tarim Basin 1.3.3.1 Characteristics of Unconformity in the Tarim Basin The Tarim Basin has undergone multistage basin-forming and multistage tectonic movements to form unconformity surfaces of different scales and strengths with multiple stages of tectonic layers. The unconformity of the Tarim Basin can be divided into two levels: regional unconformity and local unconformity (He et al. 2006). Regional unconformity refers to the existence of structural units in the entire basin or can be traced to one structural unit; a local unconformity surface refers to an unconformity existing in only a few structural units (Fig. 1.16). According to the reflection characteristics of the seismic layers of the Tarim Basin seismic data in different tectonic units, combined with the geological and well-logging data of the key wells of each tectonic unit and the geological data of the outcrops, nine unconformities were identified in the Tarim Basin. From bottom to top, these are Z/AnZ, 2/An2, O2+3/AnO2+3, S/An, D3/AnD3, C/AnC, J/AnJ, K/AnK, and E/AnE. The local unconformity surfaces include S3-D1-2/ AnS3-D1-2, P2-3/AnP2-3, T/AnT, T2+3/AnT2+3, N1/AnN1, and N2/AnN2. These unconformities are described below.

S

Chrono -stratigraphic Quaternary

(Ma)

N Tangguzibas

Tanan Uplift

Tazhong Arc

Northern Depression

Tabei Uplift

Current

Kuche Depression

Tectonic Tectono Movement -Strata

Main Tectonic Events

Basin Evolution

|

Neogene Palaeogene

Cenozoic

(1) The contact relationship between the Sinian and the underlying strata. The Sinian is distributed mainly in the northern part of the Tarim Basin, in which the central–southern part of the Kongquehe Slope and the central–northern part of the Yingjisu Depression are the thickest. The south flank of the Hetian paleo uplift is in contact with the underlying strata at a high angle; that in the Tabei region has a low-angle contact. (2) The contact relationship between the bottom boundary of Cambrian and the underlying strata. The Cambrian and the underlying strata are in low-angle contact, and the local unconformity is a high-angle contact; these strata overlie the Proterozoic and Sinian strata. This unconformity is the result of the Keping movement. (3) The contact relationship between the Upper–Middle Ordovician and the underlying strata. The Upper– Middle Ordovician rocks are distributed mainly in the central–eastern part of the platform area, which is the thickest in the Mangar depression. In most parts of the Tarim Basin, the strata form a low-angle contact with the underlying strata; and a high-angle contact occurs in the central–eastern part of Mangal. (4) The contact relationship between Silurian and underlying strata. The Silurian strata are a set of coastal facies clastic sediments developed on the background of the

23.0

Himalayan Orogeny

Salt lake facies

Fluvial facies-Alluvial plain facies

Foreland basin

Himalayan Movement

66.0

Intracontinental

Delta facies

Middle

Coastal shallow -lake facies

Lower

Lakeshore facies

Fluvial facies

Semi-deep lake facies

Upper

Fluvial facies

Middle Lower Upper

Ordovician

Delta facies

252.2

Late Hercynian Movement

Coastal shallow -lake facies Lower

298.9 Upper

Lower

Opened platform facies

Restricted platform facies Restricted platform facies

Early Hercynian Movement

358.9 Upper Middle

Offshore facies

Offshore facies

Lower

Episode IV of the mid-Caledonian

419.2 O1s O2l O1l O2yl O1-2y O1p Furongian

Diamictic shelf facies

443.4 ? 455.8 460.9 468.1 477.4

Offshore facies

Episode III of the mid-Caledonian Episode II of the mid-Caledonian

Diamictic shelf facies Carbonate platform facies

Shelf slope facies

Episode I of the mid-Caledonian

Carbonate platform facies

Early Caledonian

3rd

Carbonate platform facies

2nd

Surroundings: Fault -Depression Basin, East: Depression Basin, West: Uplift area.

North-Central: Intracraton depression, Southwest Tarim: foreland thrust belt, West and East: Uplift area.

Central and Western: Intracraton depression basin, Southwest: southwest Tarim back-arc basin, East: uplift area.

Intracratonic depression

North:Intracratonic depression, Southwest Tarim: Foreland basin, South:Uplift.

West:Intracratonic depression, East:Craton marginal depression.

485.4

Basin facies

New -foundland

541.0

Sinian

Lower Paleozoic

Semi-deep lake facies

Middle

Silurian

Cambrian

Indo-China Movement

Carbonate platform facies

Keping Movement?

Continental rift filling Tarim Movement

635

Fig. 1.16 Tectonic–stratigraphic sequence and tectonic evolution of the Tarim Basin

Rodnia hypercontinental rift

Carboniferous Permian Devonian

Upper Paleozoic

Triassic

201.3

Upper Proterozoic

depression basin

Neo-Tethys Ocean closed

Neo-Tethys Ocean open, Paleo-Tethys Ocean closed

145.0

Yanshanian Movement

Neo-Tethys Ocean open, South Tianshan Ocean convergence closure

Coastal shallow -lake facies

North Kunlun Ocean convergence closure, Arkin Ocean closed, South Tianshan Ocean open.

Coastal shallow -lake facies Lower

Upper

Jurassic

Mesozoic

Cretaceous

Upper

Continental Rift

1.3 Formation and Evolution of China’s Major Marine Prototype Basins

(5)

(6)

(7)

(8)

(9)

Pre-Silurian strata as a result of regional erosion. It is mainly distributed in the central and northern parts of the basin and forms in low-angle contact with the underlying strata in the northern and Bachu uplift areas. Its contact is formed at a higher angle in the slope area of the depression. The contact relationship between the Donghe sandstone and the underlying strata. During the Early Hercynian movement at the end of the Late Devonian, the extensive uplift was denuded variously, and the Tarim Basin was subsided in the extensional environment, the Donghe sandstone of coastal environment deposited. The sedimentary range of Donghe sandstone is in the north–central part of the Tarim Basin. It is the thickest in the Donghetang area and is in high-angle contact with the underlying strata in the uplift area or tectonic position. The other areas form a low-angle or disconfirmable contact. The contact relationship between the Carboniferous and underlying strata. The Carboniferous–Permian is a sedimentary construction of a complete transgressive cycle. It forms an angular unconformity contact with the underlying strata in most parts of the basin and a disconformity or conformable contact with the Late Devonian in local areas. The contact relationship between the Jurassic and the underlying strata. The Indo-China movement at the end of the Triassic caused regional uplift in the entire basin. The Early Yanshanian movement was dominated by extensional subsidence, and the Jurassic terrestrial clastic rocks were developed and distributed in the central and eastern parts of the basin and in the eastern part of the Kuche and the piedmont rift of the Taxinan. This forms an angular unconformity contact with the underlying strata. The contact relationship between the Cretaceous and the underlying strata. During the mid-Yanshanian movement in the Late Jurassic period, the regional uplift of the Tarim Basin, caused the Jurassic and previous strata to be denuded. Owing to differences in the denudation degree, the Cretaceous and the underlying strata form an angular unconformity or disconformity contact. The contact relationship between the Paleogene and the underlying strata. After the Cretaceous sedimentation was affected by the Late Yanshanian movement, the Cretaceous and previous strata were strongly denuded. The Paleocene extended sedimentation from west to east, resulting in an angular unconformity contact between the Tertiary and the Pre-Tertiary strata.

31

1.3.3.2 Evolution Stages of the Tarim Basin The Tarim Basin is a large composite superimposed basin developed on the pre-Sinian continental crust basement (Jia and Wei 2002; He et al. 2005). It was developed as a result of the superposition of the Paleozoic marine cratonic basin with the Mesozoic and Cenozoic continental foreland basins (He et al. 2010). According to the regional unconformity and the corresponding tectonic layers, the transformation of tectonic regimes, the characteristics of basin tectonic subsidence and the plate movement stage, the evolution of the Tarim Basin can be divided into the following seven stages: • The formation and evolution stage of the basement; • The extension–convergent stage of the basin’s southern margin in the Sinian–Ordovician; • The opposite development stage of southern compression and northern extension in the Silurian–Middle Devonian; • The passive continental marginal stage of the basin southwest margin in the Late Devonian–Carboniferous and the back-arc basin stage in the Early–Middle Permian; • The southwestern marginal back-arc foreland basin stage in the Late Permian–Triassic; • The multiphase extension–convergent stage in the Jurassic–Paleogene; and • The transgression composite foreland basin stage in the Neogene–Quaternary. The tectonic evolution of the Tarim region is constrained mainly by two aspects: mutual conversion between the regional tectonic settings and internal uplift–depression. The relevant structural and sedimentary features of the Ordovician are presented below from the perspective of structural geology.

1.3.3.3 Tectonic–Sedimentary Environment of the Tarim Basin in the Ordovician The Tarim Basin has a unified Pre-Sinian ancient continental crust basement, and the surrounding stratigraphic region includes mainly Kuruketage, Keping–Aksu, Altun, and Tiekelike. Entering the Sinian, the Late Proterozoic Rodinia supercontinent, including small blocks such as Tarim, Junggar, North China, and Yangtze, began to break up, and the craton in the Tarim Basin began to develop. It is worth mentioning that the sedimentary sequence of the Tarim Basin in the Sinian is essentially consistent with that of the Sichuan Basin. At the end of the Sinian, the

32

Keping movement (Tongwan movement in the Sichuan Basin of the Yangtze region) also occurred, resulting in a parallel unconformity contact between the Sinian and the overlying Lower Cambrian strata. During the Sinian, the Tarim region experienced an uplift– depression pattern of differentiation between the southern and northern areas. In the Cambrian–Ordovician, differential evolution occurred in the eastern and western areas (He et al. 2007). From the Early Cambrian to the Late Cambrian, the Tarim region underwent a gradual transgressive process and developed a carbonate platform (Feng et al. 2011). The Ordovician was a critical period for the evolution of the Paleo-Asian Ocean. The periphery of the Tarim experienced the evolution of the ocean basin opening, extension, subduction, closure, and collision in the Cambrian–Ordovician. Also, in the Cambrian–Ordovician, the tectonic evolution of the blocks in the periphery of the Tarim Basin had significant control over the development and evolution of the sedimentary basins and their sedimentary systems in the plate ( Zhao et al. 2009a, b, 2011). The Tarim area underwent an extension–convergence tectonic evolution cycle in the Cambrian–Ordovician owing to the influence of the periphery tectonic environment. The detailed tectonic evolution process is as follows: In the Cambrian–Early Ordovician, the Tarim area developed mainly a complex basin of the intracratonic depression and the craton marginal depression in the extensional tectonic setting, and obvious shallow-water platform sedimentary features in the western craton depression were developed. In the Middle–Late Ordovician, the basin as a whole still contained the complex basin of the intracratonic depression and the craton marginal depression, although the tectonic setting of the Tarim area became the southern compression and northern extension and showed the characteristics of the peripheral foreland basin in the southern margin. Particularly in the Late Ordovician, the tectonic activity in the Tarim Basin was intensified; the structural differentiation increased; and even fault–fold deformation developed. After the Late Ordovician, the tectonic activity gradually weakened. (1) Penglaiba stage of Ordovician The Early Ordovician Penglaiba Formation is equivalent to the Yeli and Liangjiashan formations in North China and to the Tongzi Formation (Nanjinguan Fenxiang) and the Honghuayuan Formation in the Yangtze area. This

1 Regional Tectonic Setting and Prototype Basin Evolution

formation followed the sedimentary features of the Cambrian, although the dolomite was more developed. Owing to the relative sea level decline in the Tarim area at the end of the Cambrian period, extensive exposure occurred in the southwest Tarim area. The parallel unconformity between the Cambrian and Ordovician is exhibited in the Keping outcrop. Under the surface, Cambrian brown dolomite shows cellular dissolution pores. Above the interface, Ordovician gray–white dolomite occurs. Between them is ancient weathering crust, although the strata is obviously missing owing the short exposure time. Along with the new transgression, the western Tarim intracratonic depression was once again developed as a restricted platform environment in the Early Ordovician Penglaiba Formation period. It was filled with a set of white and gray dolomite up to 1000 m thick. The sediment thickness was much thicker than that in the eastern Tarim area, and the western Tarim area became the sedimentary center of the Tarim Basin. (2) Yingshan stage of Early–Middle Ordovician The Early Ordovician Yingshan Formation is equivalent to the Meitan Formation in the Yangtze area, which is also equivalent to the first, second, third, and fourth members of the Majiagou Formation in North China. The segmentation is obvious, and the cycle feature is clear. The Yingshan Formation is the watershed of the Cambrian–Ordovician tectonic–sedimentary framework evolution in the Tarim area. In the sedimentary period of the late Yingshan Formation, at the end of Early Ordovician, the closure of the North Kunlun and North Altun oceans caused structural system reversal in the Tarim area, in which the tectonic environment changed from extensional to southern compressional and northern extensional. (3) Salgan and Yijianfang stage of Middle (Late) Ordovician The Middle Ordovician Salgan and Yijianfang Formation is equivalent to the Miaopo Formation or the Shizipu and Baota formations in the Yangtze area. The South Tianshan Rift is still in the evolutionary stage of continuous extension and is connected to the Tarim Craton by a continental slope to the south. Influenced by the compression caused by the arc–continent collision in the southern Tarim terrane, the tectonic–sedimentary framework in the Tarim intracratonic

1.3 Formation and Evolution of China’s Major Marine Prototype Basins

depression has changed significantly, which is shown as transitional characteristics of uplift–depression formation patterns in the Late Ordovician. In some areas, the Salgan and Yijianfang Formation is missing, and buried hill karstification of the Yingshan Formation began to develop.

33

the Lianglitag Formation were followed. In addition, the tectonic and sedimentary framework of the Tarim area underwent rapid changes under the background of regional compressional tectonics, and the sedimentary infill intensified. In some areas, the black mud shale of the Yingan Formation developed.

(4) Tumuxiuke stage of Late Ordovician (7) Tierekeawati stage of Late Ordovician A tectonic feature of the Tarim Basin is that basin differentiation was intensified beginning in the sedimentary period of the Late Ordovician Tumuxiuke Formation, which strongly influenced later accumulation. During the deposition of the Late Ordovician Tumuxiuke Formation, the arc– continent collision between the Middle Kunlun and Tarim terrenes was intensified. After brief regression in the Middle Ordovician, rapid transgression occurred in the Early Ordovician. The western Tarim platform was affected by the transgression, and submerged platform facies were developed in the northern Tarim and Gucheng areas. Under the influence of the thrust activities of the Tazhong I Fault, the Shunnan area immediately adjacent to the footwall of the fault was connected to Keping Bay from east to west. Under the influence of the compressive stress from south to north, the southwest Tarim–Central Tarim paleocontinent continued to rise; the thrust fault of the Bachu–Southern margin of the Central Tarim continued to be active; and a series of N–S imbricate thrust faults developed in the eastern part of Yubei. The thrust front was denuded by exposure to the surface of the water. The southern Tarim ancient land continued to develop, and the Tumuxiuke Formation was lost in the area. The tectonic framework of the Tarim area changed from E–W to N–S differentiation. This is the most important change in the basin framework in the Tarim area at that time. (5) Lianglitag stage of Late Ordovician During the sedimentation of the Late Ordovician Lianglitag Formation, the syndepositional structure was developed, and basin differentiation was also very obvious. Northern Tarim, Bachu-central Tarim, and southern Tarim are three relatively isolated platforms connected by open seas. This paleo-tectonic framework of uplift alternating with depression controlled the distribution and developmental characteristics of the sedimentary facies belt in the Tarim area. (6) Santamu stage of Late Ordovician During the sedimentation of the Late Ordovician Santamu Formation, the characteristics of the sedimentary period of

During the sedimentation of Late Ordovician Tierekeawati Formation, rock of intermediate acidity intruded the northern edge of the Tarim Basin. The sedimentary waters in the eastern Tarim area were significantly shallower, and the southern part of the Tarim Basin also experienced strong uplift and denudation. (8) Caledonian movement development period At the end of the Ordovician, the arc–continent collision between the Tarim Craton and the Southern Central–Kunlun and the Central–Altun terranes was the strongest of the Middle–Late Ordovician. As a result, the Tarim Craton ended the sedimentary history of carbonates, and the tectonic–sedimentary framework underwent great changes. The middle–south and northern regions of the Tarim area were uplifted and exposed as vast ancient land under strong S– N-trending compression. It was subjected to strong weathering and denudation and formed a large-angle to microangular unconformity between the Ordovician and the Silurian (Lin et al. 2008, 2011, 2013), which caused the Tarim Craton to be deposited only in places such as Keping, South Lunan, and Awati-Manxidiliang. The three paleouplifts in northern Tarim, Central Tarim, and southwestern Tarim were also essentially complete structure formations (Xu et al. 2005; Ma et al. 2006; Lin et al. 2008, 2011, 2013; Wu et al. 2009; Li et al. 2009; Yu et al. 2011). The karst reservoirs were developed as a result of the increased exposure and denudation of the fault–uplift highlands and paleoslopes controlled by the paleo-uplift.

References Bai Y, Wang X, Liu H et al (2010) Tectonic evolution of the western margin of the Ordos Basin and its relationship with adjacent basins. Geological Publishing House, Beijing Cheng YQ (1994) Introduction to regional geology in China. Geological Publishing House, Beijing Feng Z (1989) Lithofacies palaeogeography of Early Paleozoic in North China. Geological Publishing House, Beijing

34 Feng Z, Bao Z, Wu M et al (2011) Lithofacies palaeogeography of the cambrian in Tarim area. J Palaeogeogr 8(04):427–439 Fu J, Bai H, Sun L (2012) Types and characteristics of the Ordovician carbonate reservoirs in Ordos basin, China. Acta Pet Sin 33 (s2):110–117 Hao Y, Luo M, Xu Z et al (2014) Division of sedimentary basins and its tectonic evolution in North China from Newproterozoic to Mesozoic. Earth Sci J China Univ Geosci 39(8):1230–1242 He G (1994) Paleozoic crustal evolution and mineralization in Xinjiang, China. Xinjiang People’s Publishing House, Urumqi He D, Jia C, Li D et al (2005) Formation and evolution of polycyclic superimposed Tarim Basin. Oil Gas Geol 26(1):64–77 He D, Zhou X, Zhang C et al (2006) Characteristics of geologic framework of multicycle superimposed basin in Tarim Basin. China Pet Explor 1:31–41 He D, Zhou X, Zhang C et al (2007) Ordovician Prototype Basins in Tarim Region and Their Evolution. Chin Sci Bull 52(S1):126–135 He D, Li D, Tong X et al (2010) Stereoscopic exploration model for multi-cycle superimposed basins in China. Acta Petrol Sin 31 (5):695–709 He D, Li D, Zhang G et al (2011) Formation and evolution of multi-cycle superposed Sichuan Basin, China. Chin J Geol 46 (3):589–606 He W, Tang T, Le M et al (2014) Sedimentary and tectonic evolution of Nanhuan-Permian in South China. Earth Sci Geol J China Univ 39 (8):929–953 Hou G, Li J, Liu Y et al (2005) North China Craton Extension Event in Late Paleoproterozoic: aulacogen and dyke swarm. Prog Natl Sci 15 (11):1366–1373 Jia C (1997) Tectonic characteristics and petroleum deposits of Tarim basin in China. Geological Publishing House, Beijing Jia C, Wei G (2002) Tectonic characteristics and hydrocarbon potential of Tarim Basin. Chin Sci Bull S1:1–8 Jia J, He G, Li M et al (1997) Structural feature of basement in the Ordos basin and its control to Paleozoic gas. Geol J China Univ 3 (2):144–153 Li T (2010) Principal characteristics of the lithosphere of China. Earth Sci Front 17(3):001–013 Li C, Wang Q, Liu X et al (1982) Tectonic map of Asia. Sinomap Press, Beijing Li J, Hou G, Huang X et al (2001) The constraint for the supercont inental cycles: evidence from Precambrian geology of North China Block. Acta Petrol Sin 17(2):177–186 Li B, Guan S, Li C et al (2009) Paleostructural evolution and deformation characteristics of the Tazhong low uplift in the Tarim Basin. Geol Rev 55(04):521–530 Lin C, Yang H, Liu J et al (2008) Evolution of depositional architecture of the Ordovician carbonate platform in the Tarim Basin and its response to basin processes. Acta Sedimentol Sin 31(5):907–919 Lin C, Li S, Liu J et al (2011) Tectonic framework and paleogeographic evolution of the Tarim basin during the Paleozoic major evolutionary stages. Acta Petrol Sin 27(1):210–218 Lin C, Yang H, Cai Z et al (2013) Evolution of depositional architecture of the ordovician carbonate platform in the Tarim Basin and its response to basin processes. Acta Sedimentol Sin 31 (5):907–919 Liu B (1994) Actively explore new fields of sedimentology research. Proc Chinese Acad Sci 2:18 Liu X, Yao J (1997) The review of tectonic attribution of the Tarim plate. Geol Rev 43(1):01–09 Liu X, You G (2015) Tectonic regional subdivision of China in the light of plate theory. Geol China 42(1):01–17 Liu S, Zhang G, Cheng S et al (1997) Evolution of flexural basin and process of collision orogeny in East Qingling-Dabie Shan and its adjacent regions. Sci Geol Sin 34(3):336–346

1 Regional Tectonic Setting and Prototype Basin Evolution Luo M, Lu L, Jia J et al (2014) Evolution of sedimentary basins in China during Mesozoic. Earth Sci J China Univ Geosci 39(8):954– 976 Ma M, Chen X, Zhang X (2006) Cambrian-Ordovician sedimentary characteristics and tectonic control in Tazhong area of Tarim Basin. Pet Exp Geol 15(6):549–553 Pan G, Wang L, Zhang W et al (2013) Tectonic maps and descriptions of the Qinghai-Tibet Plateau and adjacent areas (1: 1500000). Geological Publishing House, Beijing Pan G, Xiao Q, Lu S et al (2009) Subdivision of tectonic units in China. Geol in China 36(1):1–28 Ren J, Huang J (1980) Tectonics and their evolution in China: 1: 4 million tectonic maps of China. Science Publishing House, Beijing Ren J, Niu B, Wang J et al (2013) 1:5 million international geological map of Asia. Acta Geosci Sin 34(1):24–30 Ren J, Xu Q, Deng P et al (2016) Tectonic cycles and tectonic timescale. Acta Geosci Sin 37(5):528–534 Wang H (1985) Paleogeographic Atlas of China. Geological Publishing House, Beijing Wang Y (1994) Tectonic framework and evolution of Ordos’s massif in Early Paleozoic. Earth Sci Geol J China Univ 19(6):778–786 Wang T, Wang J, Wang S (1992) Discovery of the Engelwusu ophiolite mixed rock in northern Alxa and its tectonic significance. J Lanzhou Univ (Natl Sci) 28(2):194–196 Wang J, Liu B, Pan G (2001) Neoproterozoic rifting history of South China significance to Rodinia breakup. J Min Pet 21(3):135–145 Wang T, Xu M, Wang L et al (2007) Aeromagnetic anomaly analysis of Ordos and adjacent regions and its tectonic implications. Chin J Geophys 50(1):163–170 Wei Y, Zhang Z, He W et al (2014) Neoproterozoic rifting history of South China significance to Rodinia breakup. Earth Sci J China Univ Geosci 39(8):1065–1078 Wu T, He G (1992) Ophiolithic mélange belts in the northern margin of the Alashan block. Geoscience 6(3):286–296 Wu G, Li Q, Xiao Z et al (2009) the evolution characteristics of paleo-uplifts in Tarim basin and its exploration directions for oil and gas. Geotecton et Metallog 33(1):124–130 Xiao X, Liu X, Gao R (2004) Crustal structure and tectonic evolution in southern Xinjiang. The Commercial Press, Beijing Xu X, Wang Z, Wan F et al (2005) Tectonic paleogeographic evolution and source rocks of the Early Paleozoic in the Tarim Basin. Earth Sci Front 12(3):49–57 Xu Y, Liang Y, Jiang S et al (2014) Intraplate extensional magmatism of North China Craton and break-up of three supercontinents and their deep dynamics. Earth Sci Geol J China Univ 13(2):161–174 Yan G, Mu B, Zeng Y et al (2007) Igneous carbonatites in North China Craton: the temporal and spatial distribution, Sr and Nd isotopic charateristics and their geological significance. Geol J China Univ 13(3):463–473 Yu B, Lin C, Fan T et al (2011) Sedimentary response to geodynamic reversion in Tarim Basin during Cambrian and Ordovician and its significance to reservoir development. Earth Sci Front 18(3):221– 232 Zai M (2010) Tectonic evolution and metallogenesis of North China Craton. Min Depos 29(1):24–36 Zhang Y, Zhang H, Sun Z (1997) Prototype analysis of petroliferous basins in China. Nanjing University Press, Nanjing Zhang J, Li Y, Han Z (2003) Deformation response of the Qinghai-Tibet Plateau to the east and tectonic composition of the North-South earthquake zone. Earth Sci Front 10(S1):168–175 Zhang Z, He W, Wei Y et al (2014) Evolution of Mesozoic sedimentary basins in the Lower Yanggtze. Earth Sci J China Univ Geosci 39 (8):1017–1034 Zhang K, Pan G, He W et al (2015) New Tectonic-stratigraphic Division of China. Earth Sci Geol J China Univ 40(2):206–223

References Zhao Z, Pan W, Zhang L et al (2009a) Sequence Stratigraphy in the Ordovician in the Tarim Basin. Geotectonica et Metallogenia 33 (1):175–188 Zhao Z, Wu X, Pan W et al (2009b) Sequence lithofaice paleogeography of Ordovician in Tarim Basin. Acta Sedimentol Sin 27 (5):939–955

35 Zhao Z, Luo J, Zhang Y et al (2011) Cambrian sequence lithofacies palaeogeography in Tarim Basin. Acta Pet Sin 32(6):937–948 Zhu R, Xu Y, Zhu G et al (2012) Destruction of the North China Craton. Sci China Earth Sci 42(8):1135–1159 Zuo G, Liu J (1987) The evolution of tectonic of early Paleozoic in North Qilian range, China. Sci Geol Sin 1:14–26

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Characteristics and Evolution of Lithofacies Paleogeography

Similarities in global tectonics evolution and the unity of global sea level eustasy in the Paleozoic have provided a scientific foundation for sequence stratigraphy research. Since its development in 1987–1988, sequence stratigraphy has been applied in geological research worldwide with astonishing speed and breadth. The important reason for the popularity of sequence stratigraphy is that it has great prediction for chronostratigraphic sequence framework, system tracts, sedimentary systems, and facies as well as microfacies. So, it is of great help to oil and gas exploration and its related sedimentary mineral exploration. In terms of the three very important marine basins in China (Yangtze, North China, Tarim Basin), the research accuracy of sequence stratigraphy has not only completed the study of grades III and IV sequences, but quite a few of them have entered the Grade V sequence or high-resolution sequence stratigraphy to meet the needs of oil and gas exploration and development. This has laid abundant data and scientific foundation for the study of paleogeographic evolution of marine strata in China.

2.1

Particularity and Regularity of Marine Strata Development in China

The distribution and evolution of strata, lithology, lithofacies, sedimentary facies, sedimentary system, and paleogeography are important elements of sedimentology, as well as structural and basin evolution. Accurate stratigraphic division and correlation are crucial for the study of sedimentary sequences and lithofacies paleogeographic characteristics of marine strata in China.

2.1.1 Marine Stratigraphic Division and Correlation 2.1.1.1 Stratigraphic Regionalization Stratigraphic regionalization is a comprehensive summary of regional stratigraphic characteristics based on the study of multiple stratigraphic units. The main factors that determine the regional stratigraphic characteristics include geotectonic characteristics, paleogeography, paleoclimate, and paleontological conditions. Among these factors, tectonic characteristics are the most important. Since the end of the 1950s, China has been involved in a national stratigraphic summary and stratigraphic regionalization study based on the four major factors mentioned above. The stratigraphic regionalization system can be subdivided into four hierarchies including strata-megaregion, strata-region, strata-subregion, and strata-microregion. The strata-megaregion is usually consistent with level I tectonic units and paleobiogeographic provinces and may include stratigraphic regions of different sedimentary types. The boundary of a strata-megaregion is commonly a plate junction zone or a large fracture belt. The strata-region is controlled by the same tectonic unit and is located in a large and stable sedimentary area or an unstable sedimentary area. Its boundary consists of different types of regional structural boundaries, subduction zones or large fracture belts. At present, China has made great achievements in stratigraphic comprehensive research and stratigraphic regionalization. According to the geological characteristics of China, the stratigraphic regionalization in most areas is Marine strata provides favorable conditions for studying marine strata in China. Generally, the stratigraphy is

© Geological Publishing House and Springer-Verlag GmbH Germany 2020 Y. Ma, Marine Oil and Gas Exploration in China, https://doi.org/10.1007/978-3-662-61147-0_2

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2

Characteristics and Evolution of Lithofacies Paleogeography

Fig. 2.1 Outline map of stratigraphic regionalization in China. I. Northern Xinjiang strato-megaregion; II. Inner Mongolia–Xingan strato-megaregion; III. Tarim– Southern Xinjiang strato-megaregion; IV. Qilian– Kunlun–Western Qinling; V. North China strato-megaregion; VI. South China strato-megaregion; VII. Tibetan– Yunnan strato-megaregion

B e ijing

Regional stratification Stratigraphic divisional boundaries Ins tructions : Data s hortage in Taiwan province. Data s hortage in the Hong Kong & M acao Special Adminis trative Regions . Stratigraphic zoning map of China

divided into seven strata-megaregions and several strata-regions and strata-subregions in China (Figs. 1.1 and 2.1; Table 2.1).

2.1.1.2 Stratigraphic Divisions and Correlation China’s obvious stratigraphic regionalism was caused by the amalgamation of many ancient lands including hundreds of strato-microregions. Therefore, the geological nomenclature of marine strata in China, particularly the formation name, has obvious regionalism and geological history timeliness. Sedimentary strata of the same lithology and age might have inconsistent nomenclature across regions owing to stratigraphic facies changes which create challenges in stratigraphic correlation. As shown in Table 2.1, the marine stratigraphic division and correlation for this study were conducted by following a system within the framework of the International Chronostratigraphic Chart (2015) and the Chinese Chronostratigraphic Chart (2012). The correlation

refers to the three major cratons including Yangtze, Tarim, and North China, which represent the plate, platform, and region, respectively. These three cratons cover major areas of China and had relatively stable tectonic movement during the geological history.

2.1.2 Particularity and Regularity of Marine Strata The marine sedimentary rocks are developed mainly in the middle Neoproterozoic–Paleozoic–early Mesozoic units in China. Owing to the characteristics of geological tectonic movement in the Neoproterozoic, Paleozoic, and early Mesozoic, as well as the relatively small area and intense activity of the Chinese geological tectonic units (platform), the marine sedimentary in China, have unique distribution characteristics and evolution rules.

2.1 Particularity and Regularity of Marine Strata Development in China

2.1.2.1 Particularity of Marine Strata (1) The Marine sedimentary strata with the characteristics of small area and large thickness in China

39

indicates the relatively low stability of China’s platforms, which further affects the sedimentary environment with great changes in spatial distribution. (2) Sedimentary environment of marine source rock

The deposition area of marine sedimentary in China, particularly the stable platform, is considerably smaller than that of foreign platforms. The areas of North America, Russia, and Arabia are 12.5 times, 5.1 times, and 4.3 times that of the North China platform, respectively; however, the deposition thickness of the platform in China is larger than that of the aforementioned platforms (Table 2.2). This feature

The distribution of marine source rock in China is closely related to paleotectonics, paleoenvironment, paleoclimate, and paleo-sea level. The strata in which source rocks are developed always occurs in the transition period when the geotectonic framework and basin properties change significantly, such as early Cambrian and Late Ordovician–Early

Table 2.1 Stratigraphic comparison of the Paleozoic strata in China, including the Mesoproterozoic and Neoproterozoic, mainly in the Yangtze, North China, and Tarim regions Erathem

System

Series

Yangtze

North China

Tarim

Mesozoic

Jurassic

Lower

Ziliujing Formation

Xinshikou Formation

Aqia Formation

Triassic

Upper

Xujiahe Formation

Yanchang Formation

Qihuangshanjie Formation

Middle

Leikoupo Formation

Tongchuan Formation

Kelamay Formation

Lower

Jialinjiang Formation

Heshanggou Formation

Feixianguan Formation

Liujiagou Formation

Changxing Formation

Shiqianfeng Formation

Longtan Formation

Upper Shihezi Formation

Maokou Formation

Lower Shihezi Formation

Aqia Formation (Group)

Liangshan Formation

Shanxi Formation

Nanzha Formation (narrow sense)

Chuanshan Formation

Taiyuan Formation

Xiaohaizi Formation

Huanglong Formation

Benxi Formation

Jilake Formation

Ermaying Formation

Upper Paleozoic

Permian

Upper

Middle-Lower

Ehuobulake Formation

Shajingzi Formation

Qixia Formation

Carboniferous

Upper

Lower

Hezhou Formation

Kalashiyi Formation

Gaolishan Formation

Devonian

Jinling Formation

Bachu Formation

Upper

Rongxian Formation

Donghetang Formation

Middle

Donggangling Formation

Keziertage Formation

Changcun Formation Guche Formation Gupi Formation Lower

Dale Formation Changtang Formation Luomai Formation Shuilin Formation Tonggeng Formation Dashanyao Formation

Lower Paleozoic

Silurian

Upper

Fangcheng Formation

Middle

Huixingshao Formation

Yimugantawu Formation

Xiushan Formation Lower

Baisha Formation

Tataaiertage Formation

Machongjiao Formation Shiniulan Formation

Kepingtage Formation

Longmaxi Formation

Yingan Formation

(continued)

40

2

Characteristics and Evolution of Lithofacies Paleogeography

Table 2.1 (continued) Erathem

System

Series

Yangtze

Ordovici an

Upper

Wufeng Formation

North China

Dongcaogou Formation (Linxiang Formation) Middle

Lower

Cambrian

Upper

Middle

Lower

Baota Formation

Fengfeng Formation Upper Majiagou Formation

Guniutan Formation

Miaopo Formation

Dawan Formation

Meitan Formation

Tarim Yingan Formation Qilang Formation Kanling Formation Shaergan Formation Qiulitage Upper Subgroup

Lower Majiagou Formation

Honghuayuan Formation

Liangjiashan Formation

Lianghekou Formation (Tongzi Formation)

Yeli Formation

Fengshan Formation

Fengshan Formation

Changshan Formation

Changshan Formation

Gushan Formation

Gushan Formation

Zhangxia Formation

Zhangxia Formation

Xuzhuang Formation

Xuzhuang Formation

Sangtamu Formation Linglitage Formation Tumuxiuke Formation Yijianfang Formation Yingshan Formation

Penglaiba Formation

Qiulitage Upper Subgroup

Awatage Formation Shayilike Formation

Maozhuang Formation

Maozhuang Formation

Qingxudong Formation Longwasngmiao Formation

Mantou Formation

Wusonggeer Formation

Jindingshan Formation Changlangpu Formation

Fujunshan Formation

Xiaoerbulake Formation

Mingxinsi Formation Qiongzhusi Formation Niutitang Formation Meishucun Formation

Neoproterozoic

Mesoproterozoic

Yuertusi Formation

Eocambrian

Haoyun Stage

Sinian Nanhuan

Upper

Dengying Formation

Qigebulake Formation

Lower

Doushantuo Formation

Sugaitebulake Formation

Upper

Nantuo Formation

Youermeinake Formation

Lower

Liantuo Formation

Qiaoenbulake Formation

Qingbaikou

Haoyun Stage

Banxi Group Lengjiaxi Group

Jingeryu Formation

Haoyun Stage

Akesu Group

Changlongshan Formation Xiamaling Formation

Jixianian

Tieling Formation Hongsheizhuang Formation Wumishan Formation Yangzhuang Formation

Chang-chengian

Gaoyuzhuang Formation Dahongyu Formation Tuanshanzi Formation Chuanlinggou Formation Changzhougou Formation Changzhougou Formation

Paleoproterozoic

Silurian in southern China, Ordovician and late Carboniferous in North China, and Cambrian and Middle and Late Ordovician in the Tarim basin. The marine argillaceous source rocks mainly developed in the sedimentary

environment of low energy, hypoxia and organic matter, including the coastal zone in transgression period; the shallow sea shelf; the delta front; and the bathyal–abyssal sea and so on.

2.1 Particularity and Regularity of Marine Strata Development in China Table 2.2 Comparison of stratum thickness between Chinese and foreign platforms (unit: m)

Yangtze Triassic

41

North China

Tarim

Siberia

10–270,000

Permian

200–1100

Permian

200–1500

700 58–12000

Silurian

400–1700

Ordovician

300–800

100–17000

Ordovician

680–2300

600–850

Sinian

400–1000

Europe–Russia

Arabia

1800

800–1200

200–600

700–900

310 300

500–1000

700

2000

500

100

350

100–2000

1200

120

1600

780–1700

The distribution of marine reservoir is controlled mainly by deposition, diagenesis, and structure. The sedimentary environments of marine carbonate reservoirs in China consist mainly of platform marginal reef flat, intra-platform shoal, platform edge outer reef, and other environments. The sedimentary environments of clastic rock reservoirs are mainly delta, tidal flat, offshore, shallow sea, and clastic gravity flow. The development of marine carbonate reservoirs is closely related to the paleo-sea level and sequence interface (Chen et al. 2006; Ma 2012). The regional high-quality reservoirs in the Middle–Upper Yangtze regions are usually consistent with the second-order sea level change from highstand to lowstand. Among them, the superposition of lowstand on highstand is a beneficial condition for the formation of regional reservoirs. The relationship between reservoirs and sequence interfaces is reflected mainly in the control of reservoir development by weathering crust near an unconformity interface.

continental margins. The lower part of the continental slope is composed mostly of bathyal–abyssal sedimentary and mainly volcanic sedimentary rock assemblages. (2) In terms of geological era, the marine sedimentary environments were developed mainly in the Meso– Neoproterozoic, Paleozoic, and early Mesozoic, but relatively few sedimentary environments occur in Jurassic and later units. Specifically, in most areas north of Qinling, Qilian, and Kunlun, the marine sedimentary stage ended in the Carboniferous–Middle Triassic, and the transgression in South China ended in the Middle– Late Triassic; Mesozoic marine sedimentary rocks are common in the Yunnan–Tibet region. (3) In terms of spatial distribution, the stable marine sedimentary strata are distributed mainly in the Tarim, North China, and Yangtze regions of southern China; whereas the marine sedimentary of transitional and active are distributed mainly in the northern Xinjiang, Inner Mongolia, and northeast China regions.

2.1.2.2 Regularity of Marine Strata The temporal and spatial distribution characteristics of marine stratigraphic sequence in China are as follows:

2.2

(1) Marine sedimentary is divided into three types: stable, transitional, and active, which are regularly distributed. The stable marine sedimentary is formed in a shallow water environment on a continental craton and is composed mainly of carbonate and clastic rocks; it is dominated by the benthic organisms, with little variation of lithofacies thickness, and low degree of late metamorphism. The transitional marine sedimentary usually occurs in the passive continental margin, intracontinental and epicontinental rift, marginal sea, and early stage of the foreland basin, with deepwater deposition, are given priority. Most of the deposits are carbonate and clastic rocks, mainly planktonic–benthonic organisms. Active marine sedimentary are formed mostly in the gulf–arc–basin systems on active

Affected by regional tectonic movement, the Meso–Neoproterozoic was a pan-oceanic period, with more than 90% of the area covered by oceans in China. The Sinian was a confrontation period of land and sea. The Early Paleozoic was an extensive transgression, accounting for 3/4 of the ocean area. The late Paleozoic was the transition period from ocean to land. Basically, the transition was completed from sea to land in the Mesozoic. Twelve lithofacies paleogeographic maps of marine strata in major geological eras in China were compiled based on a large number of relevant documents (Liu 1994, 1955; Guan 1985; Wang et al. 1986; Feng et al. 1994; Tian 1997; Zhai and Gao 2005; Chen et al. 2006; Ma 2007; Zheng and Hu 2010) (Figs. 2.2 and 2.3).

(3) Sedimentary environment of marine reservoir

Lithofacies Paleogeographic Characteristics and Evolution Rules of Marine Strata in China

42

The lithofacies paleogeographic characteristics and evolution rules of marine strata in the main geological ears are briefly described below.

2.2.1 Lithofacies Paleogeographic Characteristics of Marine Strata in China 2.2.1.1 Lithofacies Paleogeographic Characteristics in the Sinian During the Sinian, the main landmasses in mainland China, such as Tarim, North China, Yangtze, Chaidam, Yunnan, and Tibet, were separated by an expanding ocean basin or rift trough, and were scattered mostly by tension. For example, the Tarim, Chaidam, North China, and Yangtze landmasses are separated by Altyn Tagh–Qinling, Qilian, and Kunlun oceans, and the Yangtze platform is separated from the Cathaysia Craton by the Qinzhou–Fangcheng– Ganzhong trough. In this context, the main landmass edge is in the tectonic setting of a discrete passive continental margin; tectonic subsidence occurs mainly at the continental margin. The landmasses generally present a palaeotopography framework with high center and low edge. Moreover, the seawater was constantly invading from the continental margin to the interior and generally resulted in the paleogeographical appearance of platform–platform margin–platform marginal slope–basin (Figs. 2.2 and 2.3). The late Sinian sediments in the Yangtze and Tarim regions are mainly comprised of carbonate rocks including dolomite and a small amount of terrigenous clastic rocks, phosphatic, and siliceous rocks. However, the Sinian sediment is mostly absent in North China, which is a mostly denuded region. During the Doushantuo stage, large areas of carbonate sediment and four carbonate platforms including the Upper Yangtze, Middle Yangtze, Lower Yangtze, and Bayankara– Western Sichuan were developed in the Yangtze region and they were nearly integrated. The southern Kunlun–southern Qinling narrow slope facies deposits developed at the northern margin of the platform; the Jinshajiang–Ailoushan narrow trough developed at the southwestern margin; narrow upper slopes and broad lower slopes developed at the southeast side; and the large argillaceous Hunan–Guizhou– Guangxi bathyal basin and Qinzhou–Fangcheng–Ganzhong trough developed at the outer side of the lower slope. During the same period, three small ancient landmasses were present including Songpan, Central Yunnan, and Luding, and a small amount of terrigenous clastic deposits developed around the landmass margin. In the Tarim region, the ancient landmass was developed in a nearly E–W direction in the southern region, and a large area of carbonate platform deposits developed in its margin. The platform in the northern part of the region was wide and extended northward

2

Characteristics and Evolution of Lithofacies Paleogeography

to the Southern Tianshan–Eastern Tarim bathyal basin. The platform in the southwestern Tarim region was narrow and extended southward to the Western Kunlun ocean. North China was mainly ancient land, and narrow slope and basin facies deposits developed only on the south and north sides (Fig. 2.2). During the Dengying Formation of Sinian, the marine sedimentary in China inherited the tectonic–sedimentary framework of the Doushantuo stage. The transgression area was enlarged; the Songpan ancient landmass was submerged; the Yangtze platform was further extended; the Qilian Ocean basin was stretched; and the slope facies deposition at the southern margin of Alashan developed on the western edge of the ancient landmass in North China. The sedimentary framework in other areas did not change significantly. By the end of the Sinian, the Yangtze and Tarim regions were generally uplifted by tectonic movement, and the Upper Sinian strata experienced denudation and formed an unconformity. The top reservoir of the Dengying Formation in the Yangtze region underwent weathering and leaching to form the weathered crust karst dolomite reservoir, which is an important target for lower exploration assemblage in the marine strata in southern China and one of the main production layers in the Anyue gas field (see Chap. 12). Drilling in the Tarim region revealed few Sinian. However, a parallel unconformity between the Qigebulake Formation of Upper Sinian and the Cambrian is visible in the outcrop profile at the periphery area. The three craton basins of Yangtze, North China, and Tarim embarked on the evolution stage of marine sedimentary environment after Sinian.

2.2.1.2 Lithofacies Paleogeographic Characteristics in the Cambrian During the Cambrian, the marine sediments in China inherited the Sinian pattern, with major ocean basins showing continuous expansion. As a result, the continental margin subsidence was intensified; the transgression area was further expanded to inland; and the carbonate platform was widely developed (Figs. 2.4 and 2.5). Owing to transgression in the southeastern Yangtze region during the early Cambrian Canglangpu–Longwangmiao stage, the area of the platform was smaller than that in the late Sinian, and the platform slope facies deposits extended to Enshi–Jingzhou in a NW direction. The land was distributed mainly in western Songpan–Kangdian, and a narrow rifting trough was formed in the Longmenshan area by extension disintegration. The Tarim ancient land was submerged and disappeared through transgression before developing an extensive shallow carbonate platform, which formed the sedimentary framework of “Western Platform, Eastern Basin.” Because of the increased subsidence, a

2.2 Lithofacies Paleogeographic Characteristics and Evolution Rules …

Fig. 2.2 Tectonic Lithofacies Paleogeographic map of the Late Doushantuo Age in the Early Sinian, China

43

44

2

Characteristics and Evolution of Lithofacies Paleogeography

Fig. 2.3 Tectonic Lithofacies Paleogeographic map of Late Dengying Age in Late Sinian, China

2.2 Lithofacies Paleogeographic Characteristics and Evolution Rules …

shallow sea basin formed in the Manjiaer area of the eastern Tarim ancient land, and minor stable subsidence resulted in the formation of a carbonate platform in the Bachu–Tazhong area of the western Tarim ancient land, in addition, the margin of the platform extended in a nearly N-S direction. Affected by the transgression of the North Qilian–North Qinling ocean, the North China ancient land was gradually reduced, and a large area of platform deposits developed in the eastern–southern–western regions of the ancient land (Fig. 2.4). In the Middle–Late Cambrian, a rift trough closed, which located in Longmenshan, Yushu–Muli, of western Upper Yangtze. The Sichuan–Yunnan ancient land constantly expanded in the areas of Songpan and Kangdian, with sabkha, tidal flat and saline lake around it. Far away from the ancient land, a widespread restricted–open platform was formed. In this region, the area of the platform margin slope facies in the southeastern Yangtze platform retreated to the southeast. The carbonate platform developed under the influence of Sichuan–Yunnan ancient land uplift to the west, which lead to shallower water in the Yunnan–Guizhou– Gaungxi sub-deepwater basin. Western Tarim is a closed carbonate platform, and the eastern and northeastern parts are mainly the open sea shelf facies. In northern China, only the Yimeng, Alashan, and Qingyang areas remain partially exposed. Most of the area is covered by seawater, forming a large-scale shallow platform dominated by carbonate deposits (Fig. 2.5). In the Cambrian, marine sediments in China had two important features. The first is that in the early Cambrian Meishucun (Niutitang and Yuertusi formations) and Qizhusi phases, the Yangtze and Tarim regions deposited a set of dark-colored carbonaceous mudstone and shale, which are important source rocks in the Sichuan and Tarim Basins in China. They are source rocks for the Anyue Gas Field, Tahe Oilfield, Lunnan Oil–Gas Field, and Tazhong Oil–Gas Field (See this chapter and Chaps. 17, 18, and 19). The second is that dolomite reservoir of Cambrian is an important reservoir type in China. The lower Cambrian Longwangmiao Formation in the Yangtze and the Xiaoerbulake Formation in the Tarim Basin are both important reservoirs. The Longwangmiao formation is the main reservoir in Moxi Gas Field of the Sichuan Basin, and industrial oil and gas was also discovered in Lower Cambrian of the Tarim Basin. The grainstone and dolomite reservoirs in the middle Cambrian Yangtze, North China, and Tarim areas are relatively developed. For the Upper Cambrian, Yangtze and Tarim basins are dominated by dolomite reservoirs, while the North China is dominated by limestone reservoirs.

45

2.2.1.3 Lithofacies Paleogeographic Characteristics in the Ordovician In the Ordovician, the Yangtze, North China, and Tarim areas were still dominated by the carbonate platform; however, the regional tectonic framework began to change in the Middle–Late Ordovician. The Paleo-China and Proto-Tethys oceans successively entered the subduction stage influenced by the mid-Caledonian tectonic movement from the Middle– Late Ordovician. As a result, land masses converged and collided, thus forming an uplift at the convergent continental margin, including the Yunnan–Guizhou–Guangxi and southern Tarim regions, and the gradual formation of intracontinental uplift such as the Huaiyuan movement in North China. Under the aforementioned structural background, with the exception of the Qaidam basin as a shallow water carbonate platform, land is gradually increasing and the scope is expanding in the three tectonic areas of Tarim, North China and Yangtze (Figs. 2.6 and 2.7). In the Early Ordovician, the Yangtze areas were still dominated by carbonate platform. The Sichuan–Yunnan ancient land began to crack under the re-extensional movement of the Longmenshan fault. The range of carbonate platform has been expanded and deposits were dominated by limestone. To the southeast China, deposits were transferred to deep-water shale. For the Cathaysia, coarse clastic rock deposits in this area. Tarim basin is dominated by carbonate platform, which is consistent with the sedimentary environment of middle—late Cambrian. The lithology of the Penglaiba and Yingshan formations was dominated by dolomite deposits. The areas of Alashan ancient land in western North China and Funiushan ancient land in the southeast expanded. The platform was distributed mainly in the central and eastern parts of North China, and its range was reduced. The limestone and dolomite deposited in the Liangjiashan and Yeli formations in the above platform area (Fig. 2.6). In the Middle-Late Ordovician, The Yangtze area shows the paleogeographic characteristics of compression and contraction, except the marginal sea in the north margin which remains passive continental margin. Affected by the transfer of compressive stress from southeast to northwest, the South China and the southern Yangtze area were continuously folded into land, and the sedimentary basins gradually migrated to the northwest. From the lithology characteristics, the middle Ordovician is composed of generally shale, siltstone or carbonate interlayers. The lithology of the upper Ordovician varies greatly. The northern Yangtze is composed of interbedded layers of limestone, argillaceous siltstone, and sand shale by unequal

46

2

Characteristics and Evolution of Lithofacies Paleogeography

Fig. 2.4 Tectonic Lithofacies Paleogeographic map of Changlangpu–Longwangmiao age in Early Cambrian, China

2.2 Lithofacies Paleogeographic Characteristics and Evolution Rules …

Fig. 2.5 Tectonic Lithofacies Paleogeographic map of Gushan–Changshan–Fengshan age in Late Cambrian, China

47

48

2

Characteristics and Evolution of Lithofacies Paleogeography

Fig. 2.6 Tectonic Lithofacies Paleogeographic map of Xinchang age in Early Ordovician, China

2.2 Lithofacies Paleogeographic Characteristics and Evolution Rules …

thicknesses, while the southern Yangtze is composed of shale and sandstone. Affected by the West Kunlun-Altun Ocean subduction in the Tarim region, the tectonic framework of “Western Platform, Eastern Basin” that formed in the Cambrina began to differ between the north and the south areas since the Central Ordovician. The Yubei–Hetian–Tazhong and Tabei areas experienced paleo-uplift in an NE–EW direction. Along the paleo-uplift, a narrow reef & shoal belt formed in platform margin. In the Late Ordovician, the paleo-uplift in the southeastern Tarim region continued, and its scope was further expanded. The ancient land in North China continued to rise, dividing the platform into east and west parts (Fig. 2.7). Therefore, the Middle–Late Ordovician was a critical period for the transformation of the paleogeographic framework. The main features were expansion of the ancient land (uplift) in the Yangtze, Tarim, and North China regions, and the Lower Ordovician carbonate deposits subject to weathering and leaching that easily formed high-quality large weathered crust reservoirs., such as the Yingshan and Yijianfang formations in the Tarim Basin and the Majiagou Formation in the Ordos Basin of North China, in which the well-known Tahe Oilfield and Jingbian Gas Field were discovered. By the end of the Late Ordovician, the three major craton basins changed from being dominated by carbonate platform to by mainly clastic rock deposition.

2.2.1.4 Lithofacies Paleogeographic Characteristics in the Silurian The Late Ordovician–Silurian was an important period of late Caledonian tectonic movement. Owing to the gradual reduction and closure of the Paleo-China Ocean, the main land masses such as Tarim, North China, and Yangtze collided and colluded to form a unified Paleo-China land, and the well-known Qinling–Qilian–Kunlun Caledonian collisional orogenic belt formed between them. By affected of subduction from the Proto-Tethys Ocean to the South China continent, the Cathaysia landmass, Hunan & Guangxi ancient land collided with the southeast margin of the Yangtze landmass, forming the late Caledonian orogenic belt along the southeast coastal area in the Yangtze region. Under the pushing action of the orogenic belt to the northwest, most of South China was uplifted into the land, with the sea basin remaining only in Qinzhou–Fangchenggang, southeast Guangxi. In the Tarim area, the West Kunlun– Altyn Ocean was reduced. The Tarim ancient land collided with the West Kunlun–Altyn ancient land. The ancient uplift of Tanan continued to uplift and further expanded in scope. The Silurian shore–shallow sea facies clastic rocks were deposited mainly between the Tabei and Tazhong uplifts,

49

and were mainly red beds. North China continued to rise on the basis of the ancient land at the end of the Ordovician, forming a whole continent. Silurian sediment was essentially absent only in the narrow plateau facies on the northern and southwestern margins of the continent. In the northern Qiangtang–Changdu–Simao area, accretionary orogenesis also occurred owing to the northward dive of the Proto-Tethys Ocean. In addition, north and south Qiangtang may have collided during this period, thus forming a series of uplifted ancient landmasses on the continental margin, which was later fully uplifted to land in the early Devonian. In the south-central part of Tibet, the platform facies on the mainland has been maintained since the Sinian, and the northern Nujiang river was a continental slope facing the Proto-Tethys Ocean (Fig. 2.8). During the Silurian Longmaxi period, the transgression resumed after a brief sea regression at the end of the Ordovician. When the relative sea level was still at a lower level, an occluded stagnant basin environment was formed in the middle and upper Yangtze areas, and a wide range of graptolite-rich black shales developed in the region, which served as another important source rock in South China (see Chap. 23, Fuling Gas Field) This unit is currently the main stratum of shale gas exploration.

2.2.1.5 Lithofacies Paleogeographic Characteristics in the Devonian In the Early Devonian, the Qinling–Qilian–Kunlun Caledonian Orogen was further developed. The Qilian Sea basin was eventually closed and the mountain was formed, which connected the Tarim, Chaidamu, North China, and South China lands. In addition, a terrestrial deposit, the Mountain Front molasse formation appeared along the Hexi Corridor. On the northern edge of Paleo-China, the subduction of the southern branch of the Paleo-Asian Ocean (Tianshan–Beishan–Xilamulun) basin to the Tarim–North China continent was also extinct. The micro-landmasses that previously floated in the Paleo-Asian Ocean, such as the Mingshui– Eiligemiao microland blockchain and the Jiamusi–Xiaoxing’anling Block, were merged into the northeastern edge of Paleo-China and became united. From the north side of Yinshan–Yanshan to the Songliao–Xingkai area, the formerly active deposits were changed to stable carbonate platform deposits; the small ocean basin at the western end of the southern Tianshan post-arc expansion also began to subduct toward the Kazakhstani landmass; it gradually shrank to extinction and was transformed into a residual basin. Thus, the Kazakhstan and Tarim landmasses were united. In southwestern Paleo-China, because the Caledonian subduction of the western Paleo-China Ocean in the Kunlun–West Qinling area did not cease completely, a

50

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Characteristics and Evolution of Lithofacies Paleogeography

Fig. 2.7 Tectonic Lithofacies Paleogeographic map of Late Aijiashan–Early Qiantangjiang age, China

2.2 Lithofacies Paleogeographic Characteristics and Evolution Rules …

Fig. 2.8 Tectonic Lithofacies Paleogeographic map of Longmaxi age in Early Silurian, China

51

52

wedge-shaped residual basin was inserted in the western part of Paleo-China. Therefore, the western Bayan Har–Sichuan– Yunnan area maintained a shallow sea platform facies sedimentary pattern. In the southwestern Paleo-China Ocean, the Qiangtang–Changdu–Simao area represents the Caledonian accretionary orogenesis uplift, where the Proto-Tethys Ocean subducted northward. The tectonic framework of the Tibet–Western Yunnan area is “South–North High and Middle Low,” forming an E–W long and narrow sea basin. The main sedimentary features are the coastal–tidal flat facies on both sides to the south and restricted platform facies in the middle. The petrofacies is characterized by a combination of shore–shallow lake sandstone, mudstone, and carbonate rocks (Fig. 2.9). In the Middle–Late Devonian, the tectonic and sedimentary features of northern China inherited the Early Devonian pattern and developed intermountain or piedmont continental deposits in Qilian, Dunhuang, and other areas within the land. But southern China was affected by the opening of the Proto-Tethys Ocean (Jinshajiang Ocean) and began a new round of large-scale sea invasion. In the Tarim area of western China, sea water intruded from the southwest to the east. Until the Late Devonian in South China, sea water invaded gradually from the west, south, and east to the interior owing to the rift and rift settlement of the southwestern margin. South China formed two sedimentary sea areas with the Jiangnan– Xuefeng uplift as the boundary. The northern area included the middle and lower Yangtze epeiric sea, and the southern area was composed of the Jiangxi–Guangdong epeiric sea and the Yunnan–Guizhou–Guangxi-–Hunan rift basin in the form of an interphase pattern of platform and trough. In the central region, the expansion of the Paleo-Tethys Ocean caused residual basin of the South Kunlun–West Qinling area to start a new tension, and the tensile rifts spread to both sides of the Qaidam area near the north. The seawater invaded northward along the northwest rifting belt and from west to east along the southern front of the Qinling–Dabie–Caledonian orogenic belt, further extending eastward to the northern foothills of Dabieshan. In summary, the tectonic and Lithofacies paleogeographic framework of the Early Devonian inherited the paleogeographic framework of the late Caledonian. Owing to the collision of small landmasses to the north or the union with the northern edge of Paleo-China, the region was further expanded. In the Middle–Late Devonian, the northern Paleo-China was subjected to continuous collisions with the micro-continental block, which was still under a compressional tectonic background. Affected by the opening of the Paleo-Tethys Ocean, the southern region began to develop a tensile stage, and large-scale transgression occurred owing to the settlement of the continental margin.

2

Characteristics and Evolution of Lithofacies Paleogeography

2.2.1.6 Lithofacies Paleogeographic Characteristics in the Carboniferous In the Carboniferous, the first large-scale of transgression occurred after the Caledonian movement in continent in China. The tectonic–sedimentary framework of the Early Carboniferous was essentially similar to that of the Late Devonian (Fig. 2.10). The difference is that its southward subduction produced thrusts on the northern margins of Paleo-China in the north, as the major Paleo-Asian Ocean basin entered the subduction stage. Under this background, the Songliao–Jiamusi area in northeast China underwent uplift and accumulated local continental fluvial deposits. At the same time, shallow marine clastic rock intermingled with carbonate rocks in the western Junggar–Tuha can be found, with continental sediments locally, indicating that uplift occurred in that area. In the central area, affected by the continuous extension and settlement of the southern Kunlun–Southern Qinling area, the sea-intrusion range extended to the north side of the Qilian–Helan–Liupanshan area, whereas the entire North China area was still experiencing uplift and erosion. To the south, the Paleo–Tethys, Lanchangjinag, and Jinshajiang oceans successively developed into mature ocean basins that split the Qiantang–Changdu– Simao blockchain from southern Paleo-China. As a result, in the western margin of the Longmenshan–Kangdian ancient land area near the edge of the ancient continent, an interior platform extensional rift occurred in the Guangxi Youjiang area. Due to the episodic characteristics of tensile activities, the frequent transgressions and regressions lead to the frequent advance and retreat of marine sedimentary shorelines. In the Tibet–western Yunnan region, under the continuous expansion of the Paleo-Tethys Ocean, the structural framework of high north and low south in the early stage was changed again to that of low north and high south. Nujiang and its northern regions became a passive continental margin facing the tension of the Paleo-Tethys Ocean. The tectonic lithofacies paleogeographic framework from south to north was generally as follows: uplifted land-shore facies–shallow sea platform facies–deeper slope facies–basin facies. In the late Carboniferous, based on the early Carboniferous inheritance of the tectonic lithofacies–palaeogeographic framework, the following major changes occurred. The ancient Chinese Ocean approached the stage of extinction. In the Junggar–Tuha area, numerous shallow marine clastic rock–volcanic deposits accumulated as a result of the collapse in the collision zone during the continental “soft collision”. In the North China Craton, depression settlement occurred under the combined action of northern collisional extrusion and southern extension, and transgressions were received from the east (the direction of the Paleo-Pacific) and the west (the direction of Helan–

2.2 Lithofacies Paleogeographic Characteristics and Evolution Rules …

Fig. 2.9 Tectonic Lithofacies Paleogeographic map of Lianhuashan age in Early Devonian, China

53

54

2

Characteristics and Evolution of Lithofacies Paleogeography

Fig. 2.10 Tectonic Lithofacies Paleogeographic map of Late Yanguan age in Early Carboniferous, China

2.2 Lithofacies Paleogeographic Characteristics and Evolution Rules …

Liupanshan). Because the subsidence was concentrated mainly in the eastern part of North China and the southwestern margin of Ordos, seawater overflowed from the eastern and western sides to the Ordos ancient uplift. In North China, owing to the high topography, continental fluvial–delta facies deposits were formed on both sides of the east-west ancient uplift. In the south, the western parts of Sichuan and Yunnan on the western margin of the Yangtze plate were further fractured. The Ganzi–Litang rift formed on the east side of Jinshajiang, which became the harbinger of the Ganzi– Litang Ocean. At the same time, South China was invaded by more extensive sea water invasion. The sea water submerged the previously separated Jiangnan uplift, connecting the central and lower Yangtze with the South China Sea. The Carboniferous strata in Tarim Basin were widely distributed horizontally with a complete vertical sequence and a distribution area of 320,000 km2. The carboniferous system in the Tarim Basin is widely distributed horizontally and has complete vertical sequences, with a distribution area of 320,000 km2. Except for the northern margin, eastern margin, and southern margin of the basin, where there is no deposition or the late uplift and denudation are exhausted, the deposition thickness is generally 400–800 m and the thickness in the Mangjiaer area is 1,200 m. The Carboniferous strata are important for exploration with well-developed source–reservoir–cap rock structures. The Bachu Formation argillaceous source rocks are distributed mainly in the piedmont depression of the southwest Tarim– Maigaiti area and are mainly young source rock. The limestone section of the Bachu and Xiaohaizi formations and the clastic rock section of the Kalasayi Formation are the main reservoirs. The cap rocks consist mainly of three sets of lower, middle, and upper regional mudstone layers in the Bachu and Kalasayi formations. The Carboniferous strata are mostly absent in the Yangtze and North China regions; only the upper Carboniferous strata are locally developed.

2.2.1.7 Lithofacies Paleogeographic Characteristics in the Permian The marine–continental interactive facies deposition is the most obvious characteristic of the Permian lithofacies–paleogeography (Figs. 2.11 and 2.12). In the Early and Middle Permian, the Paleo-Asian Ocean largely vanished, and local residual basins still existed. The Paleo-China and Mongolia–Siberian continental plates eventually merged to form the earliest “Pal–Asia.” The volcanic rift basins within the shallow sea platform and continental marginal collision belts developed along the former Paleo-Asian Ocean structural belts, and continental sedimentary basins were associated with some collage landmasses. With the continuous collision and extrusion of North China, the Tarim and North China regions underwent regional uplift, and the seawater withdrew. The sedimentary

55

environment was transitional from marine to marine–terrigenous facies and continental facies. In South China, owing to the continuous and strong expansion of the Paleo-Tethys Ocean, the western margin of the Yangtze plate suffered from strong cracking, forming a trigeminal rift system centering on the Kangding area. Affected by the expansion of the Kunlun–Animaqing Ocean, the southern Qinling–Dabie area at the northern margin of the Yangtze plate also began to transform from the former depression to a faulted basin, forming relatively deep basin facies deposits. The South China region received the largest transgression since the Late Paleozoic era, resulting in the widespread development of the carbonate platform. Only the Xikang– Yunnan paleocontinent and the Cathaysia ancient land on the southeast coast were still exposed to water. At the same time, owing to the expansion of the Qinzhou–Fangcheng Trough (aulacogen), two sets of conjugate NE and NW Qinzhou–Fangcheng trough-centric intra-platform tensile fault depressions formed in the southern part of South China, Hunan, Guangxi, and Guangdong. Deepwater carbonaceous and siliceous fine clastic rocks and argillaceous carbonate rocks were deposited in the fault trough, which is the area of favored source rock. In the Late Permian, the land area expanded continuously with the final closure of the Paleo-Asian Ocean and the continent–continent collision orogeny in North China; only the Xingmeng and Menggu–Jilin–Heilongjiang areas remained dominated by marine sediments. In South China, the Paleo-Tethys Ocean entered the subduction stage. The Ganzi–Litang rift expanded into the ocean basin, and South China entered the strongest period of tension since the Late Paleozoic era. Affected by the formation of the south Qinling depression trough, the scope of depression in the northern margin of the upper, middle, and lower Yangtze areas was further extended. The interior was accompanied by the development of the E–W-faulted trough, which is a fault– depression basin with deep sedimentary water, black siliceous rocks, and dark limestone. Light-colored limestone developed on the platform, and the reef beach facies limestone was widely developed at the platform edge, which is a favorable location for carbonate reservoir development. At the same time, in southern South China, the extensional rift in the Yunnan–Guizhou–Guangxi and southeastern Hunan–Western Jiangxi–Jiangshao areas also experienced different degrees of development, and the NE and NW fracture trend was still dominant. The subduction of the Paleo-Tethys Ocean also led to the closure of the Qinzhou–Fangcheng Trough and the further expansion of the uplift of the southeast coastal Zhejiang, Fujian, and Guangdong areas (Fig. 2.12). In the Permian, the Liangshan and Longtan formations in the Yangtze area developed thick layers of dark gray, gray, and black shale and mudstone with a very thin coal bed, which are important hydrocarbon source rocks with gas

56

2

Characteristics and Evolution of Lithofacies Paleogeography

Fig. 2.11 Tectonic Lithofacies Paleogeographic map of Zisong–Longlin age in Early Permian, China

2.2 Lithofacies Paleogeographic Characteristics and Evolution Rules …

Fig. 2.12 Tectonic Lithofacies Paleogeographic map of Changxing age in Late Permian, China

57

58

2

Characteristics and Evolution of Lithofacies Paleogeography

Fig. 2.13 Tectonic Lithofacies Paleogeographic map of Lading age in Middle Triassic, China

2.2 Lithofacies Paleogeographic Characteristics and Evolution Rules …

59

Beach Reef

Delta ac be

Reef

SDS Reef

BP

sh

ar

M

Reef

Beach

in

Bar

Organic reef OL Land

Turbidite

PE

G ra

d Ti

Trench

TF h

ek

re

c al

n

o go

Sh

OP

La

el lev ter vel a hw r le hig wate an w Mel n lo e 0m ve ea ac +2 a lem M ase terf se -20 e b X in an av DO e w E M an R Me 0m m 70

DS

H

Beach bar

(intertidal)

Subtidal low energy

Platform edge facies zone PE Platform-shelf facies association PS

Platform facies zone PF Denuded zone OL

Transitional facies association TF

h

Local high energy facies

Vo lc

subtidal low energy Shallow-sea basin facies zone Sh

High energy facies occur in isolated cases

Su bm ar in e

Shelf marginal basin facies delt

-200m

Shallow-sea shelf facies delt

Platform frontslope facies delt

Platform margin shoal facies delt

Subtidal high energy

Shelf inner edge slope facies delt

Delta facies

(supratidal)

Platform margin reef facies delt

Glacial continental debris facies delt Littoral terrigenous debris beach facies

BP

Trough platform facies delt

Mean wave base of platform REDOX interface of platform

OP

Open platform facies delt

(Shoal reef)

Semi-confined platform facies delt

Confined platform facies delt

Coastal beach bar facies delt

Coastal marsh facies delt

Tidal flat lagoon facies delt

Sandbank

an o

Basement Rock

Reef -2000m Volcanic Activity Reef

Shallow trough-basin facies zone SDS

Deep trough-basin facies zone DS Trough-basin facies association TB

Change of local sedimentary boundary

Fig. 2.14 Lithofacies paleogeographic framework map of marine strata in China

source contributions to the Puguang, Longgang, Yuanba, and other gas fields. The Qixia, Maokou, and Changxing formations developed bioclastic limestone and dolomite, which are also important reservoirs. In North China, the Shanxi–Taiyuan Formation developed thick dark shale with a very thin coal bed, which are important source rocks, and the delta and braided channel sandstones of the Shanxi, Taiyuan, and Shihezi formations are the main gas reservoirs.

2.2.1.8 Lithofacies Paleogeographic Characteristics in the Triassic During the Early–Middle Triassic, the seawater withdrew completely from North China, which was dominated by large areas of uplift. The sediments were confined mainly to several areas in North China, Tarim, and Junggar, all of which belong to intracontinental basin deposition. In South China, with the gradual reduction and closure of the Paleo-Tethys Ocean, a strip-shaped uplift was formed in the Qiantang–Changdu–Simao area. The Bayankala–Songpan area expanded as a result of the closure of the Ganzi–Litang and southern Kunlun–Animaqing oceans. The strong tensile action of both sides caused overall settlement and tilting to both sides of the ocean basin, which formed a structural framework that generally tilts from the Yangtze platform to the southwest and northwest. Moreover, a deepwater depression may have also existed in the continental shelf to accumulate a set of deepwater sandstone, shale, and

carbonate rock association. In the Early Triassic, although the late Permian tectonic–sedimentary framework was essentially maintained in the Yangtze and South China regions, the sedimentary water body became shallower than that in the previous period (Fig. 2.13. By the Middle Triassic, the southeastern coastal area and the Jiangnan–Xuefeng area had risen and joined together. The South Qinling– Dabie area also completed its orogeny, and the sea water in the Yangtze and South China became shallower, with sedimentary marine carbonate rocks and continental margin clastic rocks as the main petrofacies features. In Tibet– western Yunnan area, the Neo-Tethys Ocean opening occurred at the same time as the Paleo-Tethys Ocean closure by subduction; this area was composed of the Bangong Lake–Nujiang Ocean and the Yarlung Tsangpo Ocean. In the Middle–Lower Triassic, the Yangtze region formed large and extremely large oil and gas reservoirs and the Puguang, Longgang, and Yuanba gas fields all formed main production layers of Triassic strata (see Chap. 7, Overview of the Sichuan Basin; Chap. 9, The Puguang Gas Field; and Chap. 10, Yuanba). The main reservoir of the Pengzhou gas field is the Middle Triassic Leikoupo Formation reservoir (See Chap. 11, Pengzhou Gas Field). In the late Triassic, the seawater also largely withdrew from Yangtze region, which accepted terrestrial clastic sediment. From the Sinian Doushantuo to the Middle Triassic, mainland China experienced a complete cycle of

60

transgression and regression. Afterward, marine deposits existed only in some areas such as the Qinghai–Tibet Plateau.

2.2.2 Marine Stratigraphic Carbonate Sedimentary Model in China A carbonate sedimentary model of marine strata in China was developed by studying the lithofacies paleogeographic framework of marine strata in China (Fig. 2.14). Except for the sedimentary environment of the ancient land and the slope-bearing basin that developed in a few regions, the marine strata in the Cambrian–Ordovician was essentially dominated by the sedimentary environment of carbonate platforms in China. Compared with other marine sedimentary environment models in the literature (Irwin 1965; Laport 1969; Tucker 1981; Ye 1977; Liu 1980; Feng et al. 1993; Zhao and Zhu 2001; Zhai and Gao 2005), this model is discussed below. Combined with tectonic background and sedimentary characteristics of active and passive continental marginal basins, active geosyncline and stable platform, a unified comprehensive model of the marine sedimentary environment in China is constructed to reflect the depositional characteristics. According to the marine sedimentary geology of the Late Proterozoic to the Permian in China, and combined with turbid water terrigenous and freshwater carbonates, two different types of sedimentary modes are identified. These modes were gradually transitioned and combined in the same composite mode of the depositional environments. According to the Chinese Paleozoic marine sedimentary characteristics, the deeper trough platform facies belts, sometimes referred to as platform basin, platform depression, and basin platform were divided for the first time in the platform facies area. In addition, the isolated platform facies belts and local high-energy facies bodies of shallow water in the deepwater basin were delineated.

2

Characteristics and Evolution of Lithofacies Paleogeography

References Chen H, Hou M, Xu X et al (2006) Tectonic evolution and sequence stratigraphic framework in South China during Caledonian. J Chengdu Univ Technol (Science & Technology Edition) 33 (1):1–8 Feng Z (1994) Comprehensive mapping method of single factor analysis: methodology of lithofacies paleogeography. Sedimentology of China. Petroleum Industry Press, Beijing, pp 662–685 Feng Z, Chen J, Zhang J (1993) Lithofacies paleogeography of Ordovician of Ordos. In: Yang GH (ed) Celebration of the Fortieth Anniversary of the Establishment of Petroleum Higher Institution Collected Works of Petroleum Science Technology. Petroleum University Press, Dongying, Shandong, pp 11–18 Guan S (1985) Mesozoic Cenozoic continental sedimentary basins and oil & gas in China. Science Press, Beijing, pp 1–100 Irwin ML (1965) General theory of epeiric clear water sedimentation. Bulletin AAPG 49(4):445–459 Laporte LF (1969) Recognition of a transgressive carbonate sequence within an epeiric sea. Helderberg Group (Lower Devonian) of New York State, pp 98–119 Liu H (1955) Atlas of Palaeogeography of China. Science Press, Beijing, pp 1–50 Liu B (1980) Sedimentology. Geological Publishing House, Beijing, pp 45–48 Liu B, Xu X (1994) Atlas of Lithofacies and Paleogeography in South of China. Science Press, Beijing, pp 2–85 Ma Y (2007) Marine petroleum exploration of China. Science Press, Beijing Ma Y, Feng J, Mou Z et al (2012) the potential and exploring progress of unconventional hydrocarbon resources in SINOPEC. Eng Sci 14 (06):24–32 Tian Z (1997) Florilegium of TianZaiyi Geological Paper. Petroleum Industry Press, Beijing, pp 6–100 Tucker ME (1981) Sedimentary petrology. Blackwell, An introduction to the origin of sedimentary rocks Wang H, Yang W, Liu B (1986) Tectonic history of the ancient continental margins of South China. Wuhan College of Geology Press, pp 1–272 Ye L (1977) Geohistorical significance in metallogenic age of depositional ore deposits. Scientia Geologica Sinica 12(3):210–218 Zhai G, Gao W (2005) Petroleum geology of China. Petroleum Industry Press, Beijing, pp 11–95 Zhao C, Zhu X (2001) Sedimentology. Petroleum Industry Press, Beijing, pp 229–283 Zheng H, Hu Z (2010) Pre-Mesozoic tectonic-lithofacies paleogeographic Atlas of China. Geological Publishing House, Beijing, pp 11–12

3

Major Source Rocks and Distribution

To evaluate source rocks, their quality and quantity must be known. Quality mainly refers to various organic geochemical parameters, while quantity refers to volume, thickness, distribution, as well as the quantity of hydrocarbon generation and accumulation. It is possible to study only the quality and quantity of source rocks in the Mesozoic and Cenozoic basins with non-cyclic evolution in China. For the Mesozoic and Paleozoic multiple cyclic (residual) basins in China, it may not be sufficient to simply study the quality and quantity of source rocks. To confirm the availability of source rocks and quantitatively evaluate their hydrocarbon resources, the accumulation evolution of basins and their current preservation conditions should also be considered.

3.1

Introduction

The development environment of source rock needs to receive sufficient sunlight to enable the biota to flourish and to provide enough organic matter. In addition, the water should also be anoxic to promote organic matter preservation. Particularly in the geological ages with lower amounts of organisms, sufficient light is beneficial for the development of organisms, and deep water or stagnation anoxic conditions are favorable for the preservation and evolution of organic matter. Source rocks are composed of various rock types, include dark mudstone, shale, carbonates, and coal. From the perspective of sedimentary environments, argillaceous source rocks are deposited mainly in lower slopes and shallowwater shelves. Carbonate source rocks are deposited mainly in tidal flats, evaporative lagoons. Coal seams developed mainly in marsh environments. An abundance of total organic matter (TOC) content is a key index in evaluating the quality of source rocks. According to the author’s latest results, the thresholds of organic matter abundance in shale and coal-bearing strata and in carbonate rocks are 0.5 and 0.4, respectively. This

result is in agreement with the data of large oil and gas fields worldwide in most cases. In the three major craton basins of Yangtze, North China, and Tarim, the maximum thickness of the Paleozoic deposits is nearly 10,000 m, which includes various facies, complex rock types, and repetitive sedimentary cycles to produce several dark-colored sets of source rock. Because the main purpose of this book is a potential evaluation, this chapter is arranged by different geological regions.

3.2

Major Marine Source Rock and Its Distribution in the Yangtze Region

The Yangtze region is a craton formed at the end of the Neoproterozoic. From the Sinian to the end of the Middle Triassic, the Yangtze craton developed two generations of marine-prototype sedimentary basins and several sets of marine source rocks. The major marine source rocks are distributed in the lower Cambrian, upper Ordovician to lower Silurian, and middle and upper Permian.

3.2.1 Doushantuo Formation Source Rocks of the Upper Sinian In the middle and upper Yangtze regions, the Doushantuo Formation of the upper Sinian can be divided into four lithologic sections with two sets of alternating black- and white-colored sections from bottom to top. The first and the third sections of the Doushantuo Formation are composed of white carbonates. The second and fourth sections consist of black-colored carbonaceous shale. Based on the statistics of the outcrop samples from the Hubei, western Hunan, northern Guizhou, and southeastern Guizhou, the organic carbon content of the black muddy source rocks of the Doushantuo Formation is generally between 1.5 and 3.5%,

© Geological Publishing House and Springer-Verlag GmbH Germany 2020 Y. Ma, Marine Oil and Gas Exploration in China, https://doi.org/10.1007/978-3-662-61147-0_3

61

62

3 Major Source Rocks and Distribution

with a few sample sections reaching 8–10%. The organic matter of these rocks is derived mainly from aquatic algae and other low organisms. The microcomponents of kerogen are composed mainly of sapropelic and exinite, with content of 85.3–95.3%. The d13C of the kerogen, ranges from −34.54% to −29.48%. The black muddy source rocks of this formation belong to type I kerogen, and the equivalent reflectance of vitrinite of the kerogen is generally 2.5–3.5%, indicating the post-mature stage (Table 3.1). The argillaceous source rocks of the Doushantuo Formation is distributed mainly in the upper to middle Yangtze region and also found in some areas of the lower Yangtze region. The thickness of the source rock varies greatly. Generally, the thickness is 10–30 m, although it reaches 100 m in some areas (Fig. 3.1). In the Zunyi–Kaili area of the southeastern upper Yangtze, the thickness of the black shale in this formation is 20–70 m. The thickness of black shale is less than 10 m in most areas of Xiushan–Zhangjiajie–Fenghuang. In the Jishou–Zhijiang area of western Hunan, the thickness of black shale rich in carbonaceous rocks of the Doushantuo Formation is 20–30 m (Li and Li 2010; Jing et al. 2015). The thickness of the Doushantuo Formation is 20–80 m in the Enshi–Yichang area of the middle Yangtze region and 20–40 m in the Huangshan and Hangzhou areas of the lower Yangtze. The TOC in the muddy hydrocarbon source rocks of the Doushantuo Formation varies greatly among areas. For example, the TOC value is generally greater than 2.5% in northeastern Renhuai, Meitan, Enshi, Shimen, Taoyuan, and Anhua areas of the southeastern margin of the upper Yangtze region. However, the value is relatively low in the southeastern Sichuan Basin and western Hubei Province, generally ranging from 1.0 to 1.5% (Fig. 3.2).

3.2.2 Dengying Formation Source Rocks of the Upper Sinian The source rocks of the upper Sinian are developed mainly in the third section of the Dengying Formation in the upper Yangtze region, followed by the middle and upper parts of the Liuchapo Formation in the middle Yangtze region. In the lower Yangtze area, upper Sinian source rocks can be found only in local areas of Duchang–Xiuning. Total 70 samples of argillaceous source rock were collected by Liu et al. (2013) and Wei et al. (2015) from wells Hanshen 1, Wei 117, and Gaoke1 in the southern Sichuan, upper Yangtze region. Analyzed results show that TOC content ranges from 0.25 to 4.73% for the upper Sinian source rocks, with an average of 0.8%. Moreover, the kerogen in the source rocks shows relatively light d13C and a high degree of thermal evolution.

3.2.3 Lower Cambrian Source Rock Both the black carbonaceous and argillaceous source rocks are distributed mainly in the lower part of Lower Cambrian. The source rocks are from the Qiongzhusi Formation in the western Sichuan Basin, the Shuijingtuo to Shipai Formations in the Shizhu, Pengshui, and Xiushan areas of the eastern Sichuan Basin and in the western Hubei Province in the middle Yangtze region. Moreover, the Lower Cambrian source rocks correspond to the Niutitang to Mingxinsi Formations in the southern Sichuan Basin, in the Jinsha area of northern Guizhou Province, and the Enshi area of western Hubei Province. Further, these rocks correspond to the Mufushan Formation in the southern and northern parts of Jiangsu Province, lower Yangtze region (Table 3.2).

Table 3.1 Organic geochemical characteristics of muddy source rocks of the Doushantuo Formation in a typical section of the Yangtze region Section

Thickness/m

TOC%

Kerogen

Sample No.

Range

Average

d13 C‰

Equivalent Ro%

a

94

25

0.80–6.05

2.75

−32.53

2.89–3.15

Siduping, Zhangjiajiea

15

4

0.81–3.26

1.88

−30.23

2.81–3.07

Jiulongwan, Yichang

8

5

0.51–1.24

0.77

−29.48

2.82–3.0

52

20

0.15–1.79

0.84

−29.87

2.01–3.05

44

5

4.14–9.64

6.38

−32.18

2.74–3.02

60

4

1.22–2.71

2.01

−29.48

2.06–2.10

21

5

2.30–2.83

2.51

−30.23

2.86–3.59

37

8

0.69–7.60

2.68

−34.42

2.22–2.56

Gaotian, Xiushan

12.8

2

1.86–2.29

2.01

−31.54

2.93–3.01

Zhalagou, Majiangc

64

7

1.76–7.79

4.84

−31.9 to −30.1

3.03–3.12

Lantian, Xiuning

49.2

5

0.26–11.85

4.57

Tianping, Zhangjiajie

b

Baiguoping, Hefengb Majindong, Taoyuan

b

Meiziwan, Meitanb Songlin, Zunyi

b

Yanziping, Zhenyuanb b

Notes aafter Yong et al. (2012) b after Yang et al. (2012) c after Teng et al. (2008)

3.2 Major Marine Source Rock and Its Distribution in the Yangtze Region 300

200

100

0

63 400km

Fuyang Maerkang

Wuhan Guangyuan

Nanjing

Xinyang

Shiyan

Hefei Tongjiang

Ganzi

Xiangfan

Fengjie Nanchong

Chengdu

5 2. 0 2. 5 1.

Enshi

Kangding Leshan

1 .0

Pengshui

Qianjiang

5 1. 0

1.

Jiujiang

Yueyang

Cili

Nanchang

2.

0

Zunyi

2.0 1. 1 5 .0 2.5

2.

5

5

0.

2 .0 . 5 1

1.

Jiangshan

Changsha

Jishou

Junlian Xichang

Bijie

Hangzhou Huangshan

Qijiang

Luzhou

Zhaotong

Yichang

Chongqing

Zigong

Yibin

An’qing

Wuhan

Wanxian

Ji’an

Shaoyang

0 2.5

5

Guiyang

Fuzhou

1.5

Kaili

0.

Panzhihua

1.0

Dali Liuzhou Kunming

Guilin

Legend Shaoguan

ПГ strike-slipe fault

town Changjiang River

Kaiyuan

thrust fault Wuzhou

paleo-uplift

ЙН

0.5

TOC contour

suture zone

Fig. 3.1 Thickness isogram of shaly source rock of the Doushantuo Formation, Sinian system, Yangtze region (Modified after Yang et al. 2012)

3.2.3.1 Organic Matter Abundance The analysis results of 65 samples from the Lower Cambrian sections of Guangyuan and Nanjiangshatan in the northern part of the Sichuan Basin of upper Yangtze region indicate that the TOC content of the argillaceous source rocks is 0.94–7.12%, with an average of 3.25%. By analyzing 249 shale samples from the lower sections of the Qiongzhusi Formation in outcrops of the Sichuan Basin, the highest TOC content is 17.93%, with an average of 3.0%. The 54% of these samples have TOC content greater than 2% (Huang et al. 2012). The analysis results of cores from wells Hanshen 1, Wei 201, and Dingshan 1 in the southwestern part of the basin indicate that the TOC content of the black muddy source rocks in the lower section of the Lower Cambrian Qiongzhusi Formation is 1.5–2.5% (Wang et al. 2009; Dong et al. 2012). However, the TOC content of muddy source rocks of the Lower Cambrian is 0.8–1.2% in Luzhou and its southern area, the southeastern Sichuan Basin. The TOC content of shale source rocks in Lower Cambrian is 4.77–14.35%, with an average of 10.2%, in the

Ganziping section of Zhangjiajie, central Yangtze area (Wang et al. 2007). The TOC content is 0.57–8.35% with an average of 1.96% in the Longbizui section of Jishou of western Hunan Province and the Wangzishi section of Changyang of western Hubei Province (Liang et al. 2008). The black argillaceous source rock of Lower Cambrian generally has a high TOC content in the lower Yangtze region, ranging from 1.5% to 3.5%. In addition, lenticular or layered sapropelite rich in organic matter with TOC >50% is widely distributed in this region. Its thickness is generally 1– 10 m and 10–20 m in the southern and northern areas, respectively, and 30–50 m in some local area (Zhou 1990).

3.2.3.2 Organic Matter Type and Maturity The primitive organic matter of source rocks in the Lower Cambrian is composed mainly of lower aquatic organisms in the basin depositional environment, algae-dominated plant type, and tunicates- and sponges-dominated animal type. The value of d13Ckerogen is −30.46‰ to −34.38‰, which belongs to type I kerogen dominated by sapropelic deposits.

64

3 Major Source Rocks and Distribution 300

200

100

0

400km

Fuyang Maerkang

Wuhan

Nanjing

Guangyuan

Xinyang

Shiyan

Hefei Tongjiang

Ganzi

Xiangfan

Fengjie Nanchong

Chengdu

Yichang

Chongqing

Zigong

30

Luzhou

Yibin

Jiujiang 40

Yueyang

50

10

Qijiang

30

20

50 40

20 Cili Zhangjiajie

Pengshui

40

Qianjiang

60

Leshan

Hangzhou Huangshan

80 70

Enshi

Kangding

An’qing

Wuhan

Wanxian

Nanchang

Xiushan Jishou

Jiangshan

Changsha

Junlian Xichang 40

Bijie Panzhihua

3 0Fenghuang

Zunyi

2 01 0

50

Zhaotong

10

30 20 10

Kaili Guiyang

Fuzhou

70 50 40 30

20 10

Dali

Ji’an

30 Shaoyang 40

Liuzhou Guilin

Kunming

Legend Shaoguan

Kaiyuan

strike-slipe fault

Changjiang River

paleo-uplift

thrust fault Wuzhou

ПГ

town

ЙН

50

TOC contour

suture zone

Fig. 3.2 TOC isogram of argillaceous source rocks of the Doushantuo Formation, Sinian system, Yangzi area (Modified after Yang et al. 2012) Table 3.2 Organic geochemical characteristics of the Dengying Formation source rocks of the Upper Sinian sampled from typical sections of the upper–middle Yangtze region Wells and sections

Lithology

Section

d13C‰

TOC% No.

Range

Average 0.42

−32.53

Wei 117

Mudstone with grayish black color

Third section of Dengying Fm.

2

0.25–0.7

Hanshen 1

Mudstone with black color

Third section of Dengying Fm.

1

0.43

Xianfeng 1

Carbonaceous shale with black color

Third section of Dengying Fm.

1

2.81

Gaoke1

Mudstone with black color

Third section of Dengying Fm.

67

0.5–4.73

0.87

−33.4 to −28.5

Hongping, Jishou

Siliceous rocks with black color

Liuchapo Fm.

2

2.26– 8.46

5.36

−34.38

Siliceous mudstone with black color

Liuchapo Fm.

2

5.96– 10.3

7.76

Gaojian, Shuangfeng

Siliceous rocks with black color

Liuchapo Fm.

2

0.52– 1.74

0.93

Sanjiaoping, Ruanling

Siliceous rocks with black color

Liuchapo Fm.

11

0.79– 4.53

1.87

−33.6 to −35.1

Ganziping, Zhangjiajie

Siliceous rocks with black color

Liuchapo Fm.

20

0.35– 0.90

0.62

−33.15

−31.2 −32.4

3.2 Major Marine Source Rock and Its Distribution in the Yangtze Region

The original components are rich in hydrogen and lipids with a high potential for hydrocarbon generation. The current maturity of the organic matter in the Lower Cambrian source rock has reached an over-maturity stage in the Yangtze region, with Ro value of 2.5–3.5%. This value differs slightly among areas. For example, in the upper Yangtze region, the Ro value is 3.5–4.0% in Chongqing– Luzhou, and the value is generally between 2.2 and 3.0% in the Zigong–Ziyang area. The maturity of the Lower Cambrian source rocks is relatively low in the middle Yangtze region, with Ro value of 2.0–2.5%; its highest value occurs in the lower Yangtze region, at 3.5–4.5%.

3.2.3.3 Source Rock Distribution Source rock in the Yangtze region is widely distributed. The source rocks thickness of the Lower Cambrian ranges from 100 to 150 m, which reaches 200–300 m in some local areas (Fig. 3.3). Affected by the Kang–Dian (Xikang–Yunnan) paleocontinent and the underwater paleo-high of Middle Sichuan, the source rocks can be found in all areas except for western Chengdu–Xichang–Kunming and local areas of Chongqing– Wanxian–Nanchong. In the Zigong–Yibin–Junlian, Majiang, and Jishou–Fengjie areas, the source rock thickness is greater than 200 m. The distribution has a thickness greater than 50 m and an area of 270,000 km2, accounting for 77% of the total area in the upper Yangtze region. The distribution area of source rocks with TOC greater than 2% and thickness of more than 100 m is about 160,000 km2. The Lower Cambrian source rock in the western part of the central Yangtze region has a greater thickness of 250– 300 m in the Fengjie–Cili–Jishou area; that in the central– eastern parts of the Yangtze region is 50–100 m. However, local areas in northern Yichang–Qianjiang contain no source rock as a consequence of the Middle Hubei paleocontinent. The thickness of the Lower Cambrian source rock in the lower Yangtze region is generally 100–150 m, and reaching 150–300 m in the Jiangshan–Hangzhou–Huangshan area and in local areas of Nanjing and 50–100 m in the northern Jiangsu area.

3.2.4 Upper Ordovician–Lower Silurian Source Rocks The biota association of the upper Ordovician and lower Silurian source rocks is mainly graptolite and marine bacteria, with a high content of organic carbon. The average TOC content is 1.86–2.93% in Weiyuan, southwestern Sichuan, and in Changning, southern Sichuan, upper Yangtze region, respectively.

65

3.2.4.1 Organic Matter Abundance The lower part of the Lower Silurian Formation of Well JF 1 of Jiaoshiba structure in eastern Sichuan Basin is composed mainly of black carbonaceous mudstone, gray–black mud shale, gray–black calcareous shale, silt-rich shale, and silty shale with occasional laminated siltstone lenses. Regarding the source rock lithology, the carbonaceous mudstone is rich in graptolites and has banded pyrite. The TOC content in this source rock is between 0.42 and 5.2% and higher than 3.5% for the lowest 30 m of the well (Fig. 3.4). This section of shale is rich in widely distributed organic carbon; therefore, it is an important target for shale gas exploration in eastern Sichuan and serves as a main high-quality source rock for conventional marine gas reservoirs (Table 3.3). xxxIn the sections of the northern margin and eastern outcrop of the upper Yangtze region, black siliceous shale and carbonaceous shale can be found at the bottom of the Wufeng–Longmaxi Formation, with a total thickness of 40– 90 m and an average TOC content of 1.99–3.01%. In Yunnan, Guizhou, and Guangxi Provinces, the organic carbon of this type is 0.76–2.5% with an average of 1.15%. Therefore, these rocks are good source rocks. The average TOC content in the source rocks of the Wufeng and Longmaxi Formations is 2–3% and 1–2%, respectively. Well data indicate that the Wufeng–Longmaxi Formation (Gao Jiabian Formation) source rock is distributed mainly in Jiangsu Province, with a TOC content of 0.5–1.0%; that in sections from Jingxian, Ningguo, and Anji is 1.01–1.26% (Song et al. 2013). 3.2.4.2 Organic Matter Type and Maturity The organic matter of the mudstone source rocks of the Lower Silurian Longmaxi Formation in the Yangtze region are mainly composed of algal debris, animal cortexes, and a matrix of asphalt and secondary organic microscopic components such as asphalt and microsomes. In these source rocks, the kerogen is dominated by algal and cotton-like sapropelic amorphous matter with no exinite or vitrinite. Its d13C value is −28.61‰ to −30.50‰, reflecting that the original organic component was rich in hydrogen and lipids. Therefore, the main type of kerogen is type I; a small amount of type II1 kerogen is also included. The thermal evolution of organic matter in the Wufeng Formation Lower Silurian source rocks in the Yangtze region has reached the high post-mature stage. The Ro values are generally 2.5–3.0% in the southeastern Sichuan and eastern Sichuan regions of the upper Yangtze and 2.0–2.5% in most areas except for the Tongjiang area, northern Sichuan; the Ro if the latter is 1.8–2.2%. In the middle Yangtze region, the Ro is 1.5–2.0% in eastern Yichang to western Wuhan. From Yichang westward to Fengjie, the maturity increases

66

3 Major Source Rocks and Distribution 300

200

100

0

400km

Fuyang Maerkang

Wuhan

Nanjing Hefei

Tongjiang

Ganzi

Xinyang

Shiyan

150

Guangyuan

150 Changzhou 100 50

Xiangfan Changxing Fengjie Yichang 0

2 0 1 0 05 0 5

Enshi

Junlian Xichang

0 10

Zhaotong

Qijiang

20

Jiujiang

Jishou

0

15

0

Yueyang

Cili

0 10 Jiangshan

150 Nanchang

0

3 2 25 00 15 00 0 0

Luzhou

150

50

Pengshui Yibin

Qianjiang

50

350 30 250 0

Chongqing

Zigong

Hangzhou Huangshan

25

Changsha

20

25

Leshan

An’qing

Wuhan

300

0

Kangding

Wanxian

Nanchong

Chengdu

50 25

Zunyi

Ji’an 0

Bijie

Shaoyang

Panzhihua

Kaili

Fuzhou

Guiyang

Dali

0

20

0 150

Liuzhou

50

25

10

0

50

25

Kunming

Guilin

ПГ

Legend strike-slipe fault

town

Shaoguan

Changjiang River

0

Kaiyuan

ЙН Wuzhou

thrust fault

paleo-uplift 50

TOC contour

suture zone

Fig. 3.3 Thickness isogram of the Lower Cambrian source rocks in the Yangtze region

gradually with a value between 2.5 and 3.0%. In the lower Yangtze region, the evolution shows low maturity in northern Jiangsu, with a value of 1.7–2.0%; in southern Jiangsu, the maturity is high, and the Ro value is 2.2–3.0%. The thickness of the Wufeng Formation of the Upper Ordovician is relatively thin, usually several to 20–30 m in the Yangtze region. In most areas of the Yangtze region, there is continuous deposition between the Wufeng Formation in Upper Ordovician and the Longmaxi Formation in Lower Silurian. The Wufeng Formation-Lower Silurian argillaceous source rocks in the Sichuan Basin are distributed mainly in the southeast and northwest with two distribution centers. The first is the surrounding area of Luzhou with a thickness of 180–220 m. In the direction of Zigong, Chongqing and the southern edge of the basin, source rock gradually thinned to 50–100 m, while Zigong and the west of Weiyuan were gradually denuded and pinched out. The second is source rock with thickness of 200–220 m in the Wanxian area, which is gradually thinning to 60–100 m in the direction of Tongjiang–Dachuan–Dianjiang area, and reduced to about

20 m in the area of Yilong on the front of the Daba Mountains (Fig. 3.5). The black mud shales of upper Ordovician and lower Silurian, with a thickness of 20–150 m, can be found in almost all areas of the Central Yangtze region. In Jianghan Plain, the thickness of this source rock is relatively shallow, at generally 50–100 m. In the areas of eastern Chongqing and western Hubei Province, it has a thickness of 80–120 m; that in Jiannan, Hubei Province, and the Longshan–Baojing Counties of western Hunan Province is 150–200 m. Affected by the Jiangnan Uplift, the Tanlu fault, and the Jiangshao fault, the overall distribution of source rocks of the Wufeng and Xisilui Formations in the lower Yangtze region trend northeast, and the distribution center of the source rocks is in the Nanjing Depression. Its thickness is 200–300 m in the Shaoxing, Huangshan, and Nantong areas and 400–500 m in local areas. In the northern part of northern Jiangsu and the eastern part of Jiujiang, these rocks are dominated by shallow-water shelf sediments. The thickness of dark shale is relatively low, and the sedimentary deposit thickness is generally 25–50 m.

3.2 Major Marine Source Rock and Its Distribution in the Yangtze Region

/

2.43

254 3

Depth

stratum

(

Lithofaices

Fm. Sec

AC

m)

content of remnant organic carbon

m ft)

0

%

60

facies

RO 4

%

2.79

mf

sub-f

F

low density turbidity current

48

67

2320

2340

shallow water shelf

silty bearing claystone

2330

2350

silty mudstone

2360

basin

2370

graptolite shale

2400

Lower

Longmaxi

2390

deep water shelf

radiolarian shale

2380

2410 Wufeng Fm

carbonate platform

Dongcaogou Fm

C C

fine sandstone

argillaceous siltstone

silty mudstone

calcareous mudstone

carbonaceous mudstone

mudstone

tuff

argillacous limestone

Fig. 3.4 Characteristics of the shelf source rocks of the Longmaxi Formation, JY 1, Sichuan Basin (after Guo et al. 2014)

68

3 Major Source Rocks and Distribution

Table 3.3 Organic abundance of Upper Ordovician and Lower Silurian source rocks of the Yangtze area Region Upper Yangtze

Middle Yangtze

Well/structures/sections

Thickness/m

TOC%

Equivalent Ro %

Range

Average

0.4– 4.23%

3.04% (19)

1.86–2.11

O3w–S1l

75

Weiyuan structurea, southwest Sichuan

S1l

80–120

0.51–4.24

1.86 (37)

1.95–2.24

Changning structurea, southern Sichuan

S1l

250–300

0.45–8.75

2.93 (153)

2.81–3.31

Nuoshuihe section, Tongjiang county, Sichuan Province

Well Dingshan 1, southeast Sichuan

S1l

140

0.52–2.91

1.14 (20)

2.55–2.78

Well JF1, Jiaoshiba, Eastern Sichuan

S1l

70–90

0.52–5.46

2.75 (162)

2.77–3.05 3.11–3.38

O3w

5–10

4.01–5.89

4.59 (11)

Houtanb section, Xishui, Guizhou Province

S1l

87.29

0.52–6.79

2.77 (15)

O3w

5.83

0.99–3.68

1.99 (6)

Xiushan sectionb, Rongxi, Chongqing

S1l

23.25

0.59–4.94

2.60 (4)

O3w

6.5

3.01–3.20

3.10 (2)

1.62–2.34

Well Jianshen 1 Jiannan, Sichuan

S1l

150

0.41–4.65

1.67 (8)

2.35–2.58

Qiliao section, Shizhu, Chongqing

O3w–S1l

115

0.45– 10.56

3.27 (36)

2.1–2.5

2.24–2.38

Maoba section Lichuan, Hube Province

O3w–S1l

57

0.41–5.25

2.59 (19)

2.3–2.6

Huangchang sectionb, Simen, Hunan Province

S1l

20.50

0.54–0.71

0.61 (6)

1.67–1.88

O3w

7.80

1.78–2.93

3.03 (3)

S1l

54.61

0.58–4.29

1.63 (5)

Wangjiawan sectionb, Yichang, Hubei Province Lower Yangtze

Fm.

2.52–2.79

O3w

15.4

0.65–3.13

1.78 (4)

O3w–S1l

450.0

0.45–1.38

0.63 (13)

3.31

Well N4 , Huangqiao, northern Jiangsu Province

O3w–S1l

75.0

0.65–1.38

0.87 (6)

1.32–1.85

Well ZK10b

O3w–S1l

44.5

0.73–2.08

1.29 (8)

2.74–3.21

Beilinan section, western Zhejiang Province b

Notes Numbers in brackets are sample numbers a after Wang et al. (2009) b after Li et al. (2008)

3.2.5 Middle Permian Source Rocks After the coal deposits accumulated in coastal and marshy areas, large-scale transgressions occurred in the early middle Permian in the Yangtze region. The entire region of southern China was inundated by seawater, which resulted in carbonate deposits of the Qixia and Maokou Formations. In the warm seawater, organisms were prosperous; organic matter in the low-energy facies belt of the carbonate platform was degraded, and a large amount of oxygen was consumed. This led to a deficiency in the supply of dissolved oxygen in the water. A relatively oxygen-free environment was then formed, which is conducive to the preservation of organic matter.

3.2.5.1 Organic Matter Abundance The middle Permian carbonate source rock is widely distributed in the upper Yangtze region with a TOC content of 0.4–0.6%. The analysis results of more than 70 core samples from Hewanchang and Laoguanmiao in the northwestern

Sichuan Basin (Cai et al. 2003) indicate that the TOC content in bioclastic limestone is generally 0.03–7.47%, with an average of 0.58%. The TOC content in the argillaceous limestone ranged from 0.38 to 0.91% with an average of 0.65% in outcrops of the middle Permian Qixia Formation in the Shifang area, western Sichuan Basin. That in the argillaceous and bioclastic limestones ranges from 0.42 to 1.83%, with an average of 0.87%, in the Maokou Formation (Zhang et al. 2012). The total thickness of the carbonate rock of the Permian Qixia and Maokou Formations drilled in Well Heba 1 is 290 m in the northeastern Sichuan Basin. From this well, 17 of 21 test rock samples were dark muddy limestone with a large TOC content of 0.4% and an average of 0.70%. In the Mayanghe section of the Yichang area, western Hubei Province, middle Yangtze region, the TOC content of the carbonate rock source rocks of the Maokou and Qixia Formations ranges from 0.15 to 1.95% and from 0.15 to 1.76%, with average values of 0.48% and 0.53%, respectively (Liang et al. 2008). In the Yanmenzhen section of the

3.2 Major Marine Source Rock and Its Distribution in the Yangtze Region 300

200

100

0

69 400km

Fuyang Maerkang

Gaoyou

Wuhan

Nanjing

Guangyuan 1

Tongjiang

Ganzi

15

0

12

5

25

Xinyang

Shiyan 75

50

Hefei 100

75

75

Xiangfan

10 0

125

Wuhu

Changxing

Fengjie Yichang

Hangzhou Huangshan

Qianjiang

Enshi

Kangding

An’qing

Wuhan

Wanxian

Nanchong

Chengdu

0 20 5 17 0 15 5 12 0 10 75 50

Jiujiang

Luzhou

Yibin

17

25

5

15

0

5

75

Chongqing 0

100 125 150 17 5

12

2 5 50

Zigong

10

Leshan

Cili

Pengshui

50

Yueyang

Qijiang

25

Nanchang

0 20

Jiangshan

Changsha

Jishou Junlian Xichang Zunyi

Ji’an

Zhaotong Bijie

Shaoyang

Legend Panzhihua

Kaili Guiyang

town Changjiang River

Dali Liuzhou

thrust fault Kunming

Guilin

ПГ suture zone Shaoguan strike-slipe fault

Kaiyuan paleo-uplift

ЙН Wuzhou

50

TOC contour

Fig. 3.5 Thickness isogram of the Upper Ordovician and Lower Silurian shaly source rocks in the Yangzi area [Modified from Liang et al. (2009) and Ning Song (2013)]

Jingshan area, central Hubei, the average TOC content in the source rocks of the Qixia and Maokou Formation is 0.33 and 0.61%, respectively, which belongs to low–medium hydrocarbon source rock (Li et al. 2013). Middle Permian carbonate of the Qixia Formation is the main source rock in the lower Yangtze region, and the TOC content was strongly influenced by changes in the sedimentary facies. In the northern part of Jiangsu, the Qixia Formation was deposited in a restricted platform environment and thus has a low content of TOC, with an average of 0.26–0.46%. In the Nanling–Wuwei area of the Nanjing Depression, this formation was deposited in slope environment. The source rocks consist of micrite with chert bands, micrite with chert aggregates, and chert nodule, all with high levels of TOC at generally 1.07–1.31%. According to the distribution area of middle Permian carbonate source rock in the Yangtze area, that with a TOC content of 0.25–0.5% occupies an area of about 150,000 km2, accounting for 20% of the total area. The area with TOC content greater than 0.5% is about 330,000 km2, accounting for 43% of the total area.

3.2.5.2 Organic Matter Type and Maturity The middle Permian carbonate source rocks in the Yangtze area are dominated by algae and cotton-like sapropel amorphs with no exinite or vitrinite. The d13C value of the kerogen is −27.2 to −28.1‰ and belongs to type II1; however, some data indicate type II2. In the upper Yangtze region, the thermal evolution of the organic matter is mainly in the stage of high mature–post-mature, with Ro value of 2.0–2.5%. In some areas of the southeastern Sichuan Basin, the maturity is relatively low, with Ro value of 1.8–2.0%. In southeastern and western Sichuan Basin, the Ro is 2.4–3.2%. In the central Yangtze region, the Ro of the source rock is 1.8–2.6%; the value for the Nanjing–Gaoyou–Hai’an area of the lower Yangzi region and for other areas of the lower Yangzi region is 1.6–2.2% and Ro 2.5–3.0%, respectively. 3.2.5.3 Source Rock Distribution In the Yangtze region, the middle Permian carbonate source rocks show stable distribution with a general thickness of 150–200 m and up to 250–350 m in some areas. The distribution area of the source rock with a thickness exceeding

70

3 Major Source Rocks and Distribution

200 m is approximately 120,000 km2, accounting for 75% of the total Sichuan Basin area. In the Enshi–Fengjie area in the eastern part of the central Yangtze region, the thickness of the carbonate source rock is 150–200 m. In the Yichang– Tongshan, eastern Shaoxing–Huangshan–Nanjing, and other parts of the lower Yangtze region the thickness is 100– 150 m, 50–100 m, and 25–50 m, respectively.

eastern area of Chengdu–Suining–Chongqing, Sichuan Basin of upper Yangtze region, the TOC content of mudstone is 1.5–3.5% in Longtan Formation (Wujiaping Formation). In the Yunnan–Guizhou–Guangxi area, the average TOC content is 1.99% in the argillaceous source rocks of the Longtan Formation (Liang et al. 2008). In the middle Yangtze region, the TOC content of the coal source rocks of the upper Permian is generally 2.0–3.5%, and 4.0–5.0% in some local area. In the lower Yangtze region, the dark mudstone of the Longtan Formation has a high TOC content. The average TOC content of 19 samples obtained from southern Jiangsu is 6.13% (Wu et al. 2013). The d13C of the kerogen in the coal-based argillaceous source rocks is −25.9‰ to −24.2‰ in the upper Permian Longtan Formation, Yangtze region, and is dominated by vitrinite, inertinite, and II2 and III organic matter. The thermal evolution indicates a present stage of generally high maturation–post-maturation. The Ro value is 2.2–3.2% in the eastern and western Sichuan Basin and 1.8–2.0% in Luzhou–Chongqing–Anyue, southwest Sichuan Basin. In the middle Yangtze region, the source rocks are mainly at

3.2.6 Upper Permian Source Rocks The upper Permian source rocks are dominated by dark shaly source rocks in the Yangtze region, although carbonate source rocks are also present. The source rock type varies among formations. For example, The Longtan Formation (Wujiaping Formation) is dominated by coal-derived source rocks, and the Dalong Formation is dominated by marine argillaceous source rocks. Carbonate source rocks can be found in local areas of the Changxing Formation. Generally, the TOC content is 2.0–6.0% in the coal-based argillaceous source rocks of the upper Permian. In the

300

200

100

0

400km

Fuyang

40

Maerkang Guangyuan

Nanjing

Xinyang

Shiyan

Changzhou

Hefei Tongjiang

Ganzi

20 40 60

Xiangfan

00 1 0 01 5 0 2 Changxing

20

60

Chengdu

12

40 Nanchong 80

0 10

Yichang Enshi Qianjiang

Jiujiang

20

Zigong 80

Chongqing Yueyang

Cili

Pengshui Qijiang

10

Luzhou

Nanchang

Jiangshan

0

Yibin

Hangzhou Huangshan

40

Leshan

12 0

An’qing

Wuhan

60 40

100

Kangding

Jingxian

Fengjie

0 80 Wanxian

60

40

Changsha

Jishou

Junlian Xichang Zunyi

Ji’an

Zhaotong Bijie

Shaoyang Kaili

Legend

Guiyang

town Dali

Changjiang River

Liuzhou Guilin

thrust fault

Kunming

ПГ

suture zone

Shaoguan

strike-slipe fault Kaiyuan paleo-uplift

ЙН Wuzhou

Fig. 3.6 Thickness isogram of the upper Permian mudstone source rock in the Yangtze region

50

TOC contour

3.2 Major Marine Source Rock and Its Distribution in the Yangtze Region

TOC content of the Dalong Formation is 2.50–8.96%, with an average value of 4.49%. Its kerogen d13C is −26.5‰ to −27.9‰, and the kerogen type is II1, with a small amount of type II2 (Xia et al. 2010). The maturity of organic matter in source rocks of Dalong Formation in northeast Sichuan is generally between 1.8 and 2.2%, and that in some areas such as Maoba can reach 2.5–2.8%. The drilling data show that the total thickness of this formation in the northern margin of the upper Yangtze region is about 50–80 m and that shaly source rocks are distributed mainly in the lower parts with a thickness of about 15–40 m. In the lower Yangtze region, the thickness of the shaly source rocks is 30–60 m. Overall, the upper Permian argillaceous source rocks in the Yangtze region are distributed stably on the plane at thicknesses of generally 40–80 m, with some areas showing thicknesses of 50–100 m (Fig. 3.6). In the western margin of the Sichuan Basin and in eastern Sichuan and western Hubei, the thickness of the argillaceous source rocks is only 20–40 m; in other parts of the eastern Sichuan Basin,

the high mature stage. Those in the lower Yangtze region show the stage of high maturation–post-maturation in most areas except for the Yangzhong–Danyang and Taihu– Guangde–Ningguo–Gengxian regions in the northern southern and lower Yangtze regions, respectively. Upper Permian source rock can be found not only in the Longtan Formation (Wujiaping Formation), where it is dominated by coal-based argillaceous source rocks, but also in the Dalong Formation, where marine argillaceous source rocks dominate. Distributed in the areas of Guangyuan– Padong–Daxian and the northern margins of mid–lower Yangtze, the Dalong Formation consists of argillaceous limestone, shale, and silica rocks, among which well-preserved marine fossils such as ammonites, radiolarians, and scleres can be found in muddy source rocks. This rock has a high TOC content, and its organic matter types are sapropel and a mixed type of partial sapropel. According to the analysis of black argillaceous rock samples obtained from the lagoon marshes in the Kaijiang–Liangping area, the

0

50

100

150

71

Guangyuan

200 km

N

Tongjiang YB22

YB1

YB4

Chuan36 CS55

Mianyang 0

Yilong

SL4

CY83

LG1

Yanting

CH100

CK1

QS1

CS2

CQ128

Yunyang

4

Wanxian

Nanchong Chengdu Long651 Jianyang

0

Zi2

CF188

Zi1 Zi6

Wei15

Leshan Tie32

Chuan5

Weiyuan ZS1

E’bian

4

WD9

MA1

Linshui

Liang3

JP1

Dianjiang

Tongnan WJ1

4

FS1

NS2

2 MS1

AP1 GK1

Liangping

8

Suining

LS1

YD1

Tai12

2

YA1 Tongliang

Chuan6

2

4

0 Rongchang

Chongqing SH1 8 Baxian

Zigong Chuan13

Yang73 Yun11

GS1

Yibin

Luzhou 2

Qijiang Tang16

Hejiang

Mu17 Da12

Chishui 8 10

Tongzi

Fig. 3.7 Thickness isogram of upper Permian coal in the Sichuan Basin

Legend

HS1

Kaixian

Dachuan

DY1 Deyang Chuan97 MS1 CQ173 CJ566

Bm6 Da15

PL1

0

36

well

city

5

boundary of Sichuan basin

thickness contour/m

72

3 Major Source Rocks and Distribution

however, the thickness is 60–90 m. In the middle Yangtze region, the thickness of upper Permian argillaceous source rocks is low, and generally ranges from 20 m to 50 m. In the lower Yangtze region, the depositional center of the Longtan Formation occurs in the Changxing area. Therefore, the thickness is 200–300 m in the Wuxi–Changshu–Suzhou area westward to the Digang–Chaohu area. The sedimentary facies changes from mudstone to sandstone and siltstone, and coal and interlayers of shale with mudstone occur in local areas. The thickness of the argillaceous source rock is reduced in these areas to 20–40 m. The upper Permian coal deposited in lagoon and swamp environments are relatively developed in the Yangtze region, with a TOC content of generally 70%. Similar to that in the coal-based argillaceous source rocks, the main types of organic matter are types II2 and III. The thickness of coal seam is generally 2–5 m, and the lateral distribution is unstable. Some of them are lenticular or beaded in some local areas, mainly distributed in Tongnan–Nanchong area in the middle of Sichuan, and the total thickness of coal seam can reach 10–15 m (Fig. 3.7). In the middle Yangtze region, the coal seams are relatively thin with a small distribution range. In the lower Yangtze region, they are mostly 1–5 m thick in the areas of southern Anhui, northwestern Zhejiang, and southern Jiangsu Province; the thickness reaches more than 10 m in local areas of Tongling (Wu et al. 2013).

3.3

Major Marine Source Rock and Their Distribution in North China

The mid-Neoproterozoic source rocks in North China are located mainly in the northern region and are exposed in the Yanshan Mountains. The lower Paleozoic strata are composed mainly of carbonate rocks of uncertain potential. Therefore, the upper Paleozoic source rocks are the most significant for current oil and gas exploration. Two directions of hydrocarbon exploration exist for the deep Paleozoic strata in North China, including Neoproterozoic rocks. The first is exploration of deep primary oil and gas reservoirs based on the Paleozoic source rocks, including the buried hill hydrocarbons of which weathered Caledonian crust is the main target. The second is exploration of buried hills based on Mesozoic to Cenozoic source rocks. The Mesozoic source rocks are located mainly in the west, north, and northeast parts of North China, and the Cenozoic source rocks are located mainly in the Bohai Bay areas.

3.3.1 Mid-Neoproterozoic Source Rocks 3.3.1.1 Changcheng System Source Rocks The dark mudstones of the Changcheng system are found mainly in the Chuanlinggou Formation in the northern part of North China, with the thickest area occurring in the Beijing–Tianjin–Tangshan region. In the northern and southern Ordos Basin, a suite of thick dark source rock with a TOC content of 1.5–3.5% has been found that belongs to the Mesoproterozoic Changcheng system. Affected by surface weathering and thermal evolution, this source rock has a low content of free hydrocarbon and pyrolysis yield (Table 3.4). However, regional seismic data confirm that the Neoproterozoic Depression is present in local areas. 3.3.1.2 Source Rocks of the Jixian System The dark mudstones of the Jixian system are distributed mainly in the northern part of North China, in the Tieling Formation and Hongshuizhuang Formation, with a maximum thickness of 300 m (Fan et al. 2002). 3.3.1.3 Source Rocks of the Qingbaikou System The dark mudstones of the Qingbaikou system are found only in the Xiamaling Formation in the Jianping area, with a thickness of 123 m. Dark limestone is distributed mainly in the Beijing–Tianjin–Tangshan area with a thickness of less than 100 m. In general, the abundance of organic matter is high in the shale source rocks of the Xiamaling, Tieling, and Hongshuizhuang Formations. Among them, the shale of the Xiamaling Formation has the highest TOC, at 10.98%; that in the Tieling and Hongshuizhuang Formations is 6.1%. This source rock also has a high content of chloroform bitumen “A” and total hydrocarbon, with average and maximum values of 676–1145 g/g and 2695–10052 g/g, respectively. The average and maximum values of hydrocarbon are 359– 589 g/g and 1509–3110 g/g, respectively. The shale source rock of the Chuanlinggou Formation has a low abundance of organic matter with an average 0.44%, and a chloroform bitumen “A” value of 51 lg/g. Among the formations bearing carbonate source rocks, the Tieling Formation has the highest abundance of organic matter, with average and maximum values of 0.29 and 1.87%, respectively. Moreover, it a high content of chloroform bitumen “A,” with average and maximum values of 5.02 g/g and 3066 g/g, respectively. For source rock of the Xiamaling Formation, the average value of TOC and

3.3 Major Marine Source Rock and Their Distribution in North China Table 3.4 Statistical table of source rocks in the Changcheng system, middle Proterozoic, Ordos Basin

73

Area

Sections

Lithology

TOC (%) Avg/max (No.)

S1 + S2 (mg/g rock)

South margin of the Ordos Basin

Xunjiansi, Luonan

Slate with black color

0.40/1.52 (58)

0.03/0.05 (14)

Shangzhangwa village, Yongji

Slate with black color

0.28/0.44 (10)

0.025/0.03 (4)

Bayannuorigong

Slate with black color

1.83/2.48 (7)

0.01 (1)

Wulateqianqi River bend

Slate with black color, carbonaceous slate

3.65/7.71 (29)

0.01/0.04 (5)

North margin of the Ordos Basin

Shujigou

Slate with black color

3.50/4.29 (8)

0 (2)

Xiaoshetai village

Slate with black color

2.44/3.56 (12)

0 (2)

Bayinbulage

Slate with black color

1.56/2.82 (15)

0.045/0.08 (2)

North Guyang

Slate with black color, carbonaceous slate

7.52/16.99 (43)

0.003/0.01 (4)

chloroform bitumen “A” are 0.23% and 591 g/g, respectively. According to the above data, the carbonate source rocks of the Tieling and Xiamaling Formations reached class II source rock standards, including some type I. The average value of TOC in the Zhuang Formation is 0.20%, and the average value of chloroform bitumen “A” is 129 g/g, which indicates type II source rock.

3.3.2 Lower Paleozoic Source Rocks The Lower Cambrian source rocks has dark carbonates and dark mudstones. The dark limestone source rocks are distributed mainly in the southern North China Basin, with a thickness of up to 200 m. They are also found in local areas of Hefei, east Shandong Province, and Northeast China, with a thicknesses of tens of meters. The dark mudstone is distributed mainly in Beijing, Tianjin, Shijiazhuang, Anyang, Zhengzhou, and Hefei, with thicknesses less than 50 m. The Upper Cambrian dark limestone is thick in the south and north and thin in center of the region. Its thickness is greater than 350 m in the Hefei–Xuchang–Anyang area and 200–300 m in the Tianjin–Baoding area. The Lower Ordovician dark limestone is distributed mainly in the areas of Beijing, Tianjin, Shijiazhuang, Baoding, Jiyang, Dongying, and Weifang with a thickness of more than 300 m. Its thickness is greater than 100 m in the southwest margin and eastern (Mizhi–Yulin areas) of the Ordos Basin, with a residual organic matter abundance of more than 0.25%. This rock has a certain potential for hydrocarbon generation, and the source rock of the Majiagou Formation in the eastern basin is developed mainly in the fifth section and third sections, which are lagoon–evaporation platform facies, with thickness of 30–50 m.

The Middle–Upper Ordovician dark limestone source rocks are concentrated in the central part of North China, including Shijiazhuang, Tianjin, Linqing, and Anyang, with a thickness greater than 300 m; its thickness is 100–200 m in Beijing, Dongying, Jianchang, and other areas. However, the Middle Ordovician dark mudstones developed in the southwestern Ordos Basin have a TOC content of more than 0.5%. These rocks are distributed mainly in the lower part of the Pingliang Formation (Fig. 3.8) and in the Pingliang– Taishan areas on the plane, with a thickness of more than 50 m (Fig. 3.9).

3.3.3 Carboniferous–Permian Source Rocks The Carboniferous and Permian source rocks of the upper Paleozoic are mainly distributed mainly in the Shanxi Formation. The Late Carboniferous was an important coal-forming period in North China. From the perspective of petroleum geology, the Carboniferous system is also an important source rock system. Although the Lower Carboniferous rocks are absent in Beijing–Tianjin–Tangshan, Shijiazhuang, Baoding, Jiyang, Dongying, and Huaihei, the Upper Carboniferous source rocks are extraordinarily widespread, with a thickness greater than 60 m. The lower Permian dark mudstones, including coal seams, are distributed throughout the area, with a thickness greater than 20 m. Their concentration is greater in the southern part of North China, with a thickness of 50–213 m. The dark mudstones of the upper Permian are also concentrated in these areas, with a thickness of 50–236 m. In general, the upper Paleozoic source rocks in North China have a high abundance of organic matter. For

74

3 Major Source Rocks and Distribution 0

20

40

60

80

100km

N

Yitan2 Ke1

Yi4 Yi7

Wuhai

Hangjinqi

Yimeng

Shixiagu

Dongsheng

uplift

Meng2

Laoshidan Huo2 Meng4

Yi8

Shizuishan

Etuokeqi

Yi27

Zhaotan1

Qitan1

Meng8

E6 Le1

Shenmu

Shen1

E12

Yi25

Gu1

E17

E7

Yuli E8

Yutan2

Yutan1

Jiaxian

th ru st

Li1

Kutan1

Huitan1

Er1

Longtan1

Yu9 Chengchuan1

Jingbian

Dingbian

Dingtan1

Suanzaogou Su203

Lutan1

W es te rn

Jiyuan

Tia n h u a n

Wuqi

Shan322

Huanxian

Huan14

Shatan1 Sha2 Xi1

Guyuan

Lincan1

Huachi

Yu49

An’sai

Shan15

Qingshen2

Tanshan

Yu28

Jintan1

Lucaogou

Panzhong1

Shan83

Tao7

n area

1. 00 1.50

n

E19

E9

d e n u d a t io

Ren1

Fu5

0

d e p r e s s io

zo ne

0.5

Ren3

Wuzhong

Shan244

Wushenqi

Yinchuan

Yanchang Shan139 Yi4

Qingshen1

Xiyukou

Yichuan Futan1

Qingyang

Zhentan2

Panzhong2

Xifeng

Ningtan1

Yitan1

Yumenkou

Luo1

Huangtan1

Huangling

Pingliang

Linfen

Xiangning

Fuxian

Hetan1

Zhentan1

W e s te rn S h a n x i fl e x u re fo ld e d z o n e

Su100

Tie1

Yi15

Zhengning

Hejin Hancheng

Jian1

Yindongguanzhuang

Heshi1

Huating

u p l i f t 0.50

Taoqupo Xuntan1

Long2

Binxian

ei We i b

Longxian

Yongcan1

Caojiagou

Yaocan1

Yaoxian Sanmenxia

Fuping Ping1

Qianxian

1.00

Qishan

Baoji

Chuntan1

Huayin Weinan

Xi’an

legend

Pingliang

town

chun2

well

1.0

TOC contour

stratigraphic hiatus boundary

Fig. 3.8 TOC isogram of argillaceous source rock of the Pingliang Formation, Ordos Basin

fault

structural boundary

outcrops

3.3 Major Marine Source Rock and Their Distribution in North China 0

20

40

75 60

80

100km

N

Yitan2 Ke1

Yi4 Yi7

Wuhai

Hangjinqi

Yimeng

Shixiagu

Dongsheng

uplift

Meng2

Laoshidan Huo2 Meng4

Yi8

Shizuishan

Etuokeqi

Yi27

Zhaotan1

Qitan1

Meng8

E6 Le1

Shenmu

Shen1

E12

Yi25

Gu1

E17

n E7

Yuli E8

Yutan2

Jiaxian

Li1

90

Kutan1

Huitan1

Er1

Longtan1

Yu9 Chengchuan1

Jingbian

Dingbian

Dingtan1

Suanzaogou Su203

Lutan1

W es te rn

Jiyuan

Tia n h u a n

Wuqi

Shan322

Huanxian

Huan14

Shatan1 Sha2 Xi1

Guyuan

Lincan1

Huachi

Yu49

An’sai

Shan15

Qingshen2

Tanshan

Yu28

Jintan1

Lucaogou

Panzhong1

Shan83

Tao7

n area

Yutan1

th ru st

30 50 70

E9

d e n u d a t io

Ren1

Fu5 E19

d e p r e s s io

zo ne

10

Ren3

Wuzhong

Shan244

Wushenqi

Yinchuan

Yanchang Shan139 Yi4

Qingshen1

Xiyukou

Yichuan Futan1

Qingyang

Zhentan2

Panzhong2

Xifeng

Ningtan1

Yitan1

Yumenkou

Luo1

Huangtan1

Huangling

Pingliang

Linfen

Xiangning

Fuxian

Hetan1

Zhentan1

W e s te rn S h a n x i fl e x u re fo ld e d z o n e

Su100

Tie1

Yi15

Hejin

Zhengning

Hancheng Jian1

Yindongguanzhuang

Heshi1

Huating

u p l i f t10

Taoqupo Xuntan1

Long2

Binxian

ei We i b

Longxian

Yongcan1

Caojiagou

Chuntan1

Yaocan1

Yaoxian

Ping1

Huayin

30 Weinan

Qianxian

Qishan

Baoji

Sanmenxia

Fuping

Xi’an

legend

Pingliang

town

chun2

well

30

thickness contour

stratigraphic hiatus boundary

fault

Fig. 3.9 Thickness isogram of dark mudstone source rock of the Pingliang Formation, Ordos Basin

structural boundary

outcrops

76

3 Major Source Rocks and Distribution

example, the organic matter abundance of the Carboniferous system is mainly 2– 2.95%, and that of the Permian Shanxi Group is 1.26–2.83%. Both approach or reach the standards of type I source rock.

3.4

Major Marine Source Rock and Its Distribution in the Tarim Basin

The main source rock formations in the Tarim Basin include Cambrian–Ordovician, Carboniferous–Permian, and Triassic–Jurassic. Among them, the Cambrian–Ordovician source rocks are in the widest distribution in the Tarim Basin strata. They are distributed mainly in the lower part of the Lower Cambrian in the Yuertusi/Xidashan Formation; in the Middle–Lower Ordovician in the Saergan/Heituao Formation; and in the Middle–Upper Ordovician in the Lianglitage, Yingan/Queerqueke, and equivalent formations. The above three source rocks are the major source rocks in the Tarim Basin (Table 3.5).

3.4.1 Cambrian Source Rocks The Cambrian source rocks occur most frequently in the Tarim Basin. These rocks have the widest distribution area, a high abundance of organic matter, and the largest amount of resources. They formed during the first extension and stretching period of the Tarim Basin mainly in the Middle– Lower Cambrian, occurring in two basins and one platform

in the plane (Fig. 3.10). The first basin is the slope-basin area of the eastern Tarim Basin, where the rocks are distributed mainly in the Mangar Depression and its surrounding areas. The second is the shelf marginal basin in the Keping Uplift area, which includes the Lower Cambrian Yuertus Formation. The platform refers to the evaporative platform depression of the central and western basins, in which Middle–Lower Cambrian carbonate source rocks are distributed. According to the depositional environment, the source rocks in the Tarim Basin can be divided into the following two types: undercompensated basin source rocks on the craton edge and intraplatform source rocks in the craton depression.

3.4.1.1 Organic Matter Abundance The Middle–Lower Cambrian dark argillaceous source rocks are distributed mainly in undercompensated basins in the eastern and western margins of the basin. Dark mudstone in the eastern basin is distributed mainly in the deep trough-basin facies of the eastern parts of the Mangar Depression, the Peacock River slope, and the Guchengxu Uplift, with a maximum thickness of 300 m (Fig. 3.10). The source rocks in the basin are represented by the Lower Cambrian Yurtus Formation in the Keping Uplift, which includes phosphorus-bearing siliceous rocks and carbonaceous shale deposits. Source rocks of high abundance are distributed mainly in the lower parts, with a thickness of about 6–8 m. The TOC of the carbonaceous shale is 9.80%, with the majority greater than 2%. The equivalent vitrinite reflectance (VRE) is between 2.63 and 2.85%, which

Table 3.5 Distribution and facies of the Cambrian–Ordovician source rocks of the Tarim Basin Source rock

Lithology

Facies

Areas

Typical sections or wells

System

Series

Formation

Ordovician

Upper

Yingan (O3y)

Graptolite shale

Shelf

Keping

Dawangou section

Upper

Lianglitage (O3l)

Shale

Slope

South slope of Lunnan Uplift, North slope of Tazhong Uplift

LN 46, TZ 10, Zhong11 well, et al.

Mid-Upper

Saergan (O2+3s)

Graptolite shale

Basin

Keping

Dawangou section

Mid-Lower

Heituao (O1+2h)

Shale

Basin

East Maijaer Depression

Queerqueke section, TD 1, TD 2, Yuli 1 well

Mid-Lower

Xiaoerbulake Wusonggeer

Carbonate

Restricted platform

Bachu, Tazong

He 4, Fang 1

Lower

Yuertusi (21y)

Shale mudstone

Shelf, basin

Keping, east Maijaer Depression

Xiaoerbulake section, TD 1, TD 2

Cambrian

3.4 Major Marine Source Rock and Its Distribution in the Tarim Basin

Ti a n

mou

ntai

n

77

Mingnan1

Yinan2 Heiying1

Sha3

Baicheng Kuche

Tubei2

Sha6 Dabei1

Akesu

ng

up

Yuenan1

Shengli1

Shun8

Tong1

Anan1

Tadong1

Shun1

88m

Tazhong45 Tadong2

He4 Tazhong32

Qun4

Zhong13

Yingjisha Tacan2

Yingdong2

Shun2

Fengnan1

195m

Kang2

Tazhong12 Tazhong44

Batan5 Badong2

Hetian1

Ruoqiang 85m

Tazhong2

Maigaiti

Yingke1

Tienan1

Daxihai reservoir

Mancan1

Manxi1

Qiao1

Tumushuke

Yuepuhu

Yue1

143m Xuecan1

Aman1

Manxi2

Qun5

Tienan2

Hade4

Acan1

Kashi

Wuqia1 Keke1

239m

Yangwu1

Keping

Bachu

Atushi

Tahe1

Tarim river

Yingmai2

Awati

r

K

i ep

Weili

Cao1

ri ve

m

t lif

Xiang1

Donghe7

Yudong2 Acan2

Kuluketage uplift

Lunnan10 Tashen1

Lunnan2

Shaya

Yangta1

n

Kuerle

ri m

Wuqia

an

ai

Xinhe

Qiucan1

37m

Ce2 Kunan1

Ta

Ti

o

t un

Yaha7 Xinghuo1

Wushi Aheqi

Luntai

C

Tacan1

he

en

ri ve

r

Tazhong28

Tazhong1

He3

ch

Ku

Tabei2

Shache

nl

Ma4

un

Ze1

Macan1

Tangcan1 38m

mo

Ae

Tazhong1

Jiede1

rjin

u mo

nta

in

up

lift

Qiemo

un

Yecheng

tai

Ke1

n Keshen1

Moyu

Yucan1

Cele Minfeng

Sangzhu1 Mincan1

Legend

Yutian

K u n lu

n ta n mou

in claystone source mound source rock in slope rock in basin

gypsum source thickness of rock in lagoon effective source rock

Fig. 3.10 Distribution of effective Cambrian source rocks in Tarim Basin (after Zhang et al. 2001)

indicates a set of high-quality source rock. The thickness of the Middle–Lower Cambrian source rock is 100–200 m; this rock was deposited in platform environment. Its TOC content is generally between 0.5 and 1.0%, which indicates good source rock.

3.4.1.2 Organic Matter Type The hydrocarbon generation material of the Cambrian source rocks is relatively single, and is mainly low-grade aquatic organisms such as algae and plankton. The organic type of the source rocks in undercompensated basin facies belong mainly to type I kerogen in the Manjiaer Depression. The hydrocarbon generation material of the source rocks with evaporative lagoon environment consists mainly of salt algal and spherical dinoflagellates, and the organic type belongs mainly to type I kerogen in the Bachu-Tazhong area of western basin. 3.4.1.3 Thermal Evolution Characteristics The Cambrian strata in the Tarim Basin experienced a long period of burial and currently appear at large depths. Therefore, the degree of thermal evolution of the source rocks is high, with the maturity generally higher in the east than that in the west. The Ro value of the Cambrian source rock is between 2.43 and 3.0% in the eastern Manjiaer Depression, the Kongquehe slope, and the Guchengxu

Uplift; that in the Shaya, Bachu, and Katake Uplifts is 1.94– 3.14%, 1.02–1.52%, and 1.53–2.41%, respectively. Therefore, the Bachu, Tazhong, and other parts of the basin are in the high mature stage, and most of the remaining areas have entered the mature stage. The Middle and Upper Cambrian source rocks are distributed mainly in the eastern Tarim area and in the Well 1 area of the eastern Tarim Basin. The types of organic matter are generally good, mostly type I in the east and types I–II in the west. The maturity level is generally mature and overmature. In short, the Cambrian source rocks are developed mainly in the middle–lower series and are widespread in the eastern and western Tarim Basin. The Middle–Upper Cambrian source rocks are distributed mainly in the Tadong 1 and Kunan 1 well areas of the eastern Tarim Basin. The type of organic matter is generally type I and types I–II in the eastern and western Tarim Basin, respectively, and the maturity has reached high mature and overmature stages.

3.4.2 Ordovician Source Rocks Ordovician dark mudstone is distributed mainly in the Manjiaer Depression and is generally thicker than 200 m. The dark mudstone of the Saergan and Heituao Formations

78

have high organic carbon content and are some of the best source rocks of the Ordovician.

3.4.2.1 Middle–Lower Ordovician Source Rocks The Middle–Lower Ordovician source rocks consist of dark mudstone and dark gray micritic limestone. Argillaceous source rocks, the major source rock in Tarim Basin, are found mainly in the Heituao and Saergan Formations and are distributed in the Manjiaer Depression, Kuruktag, Keping (northwest Tarim Basin), and the Awati Depression. The core of Well Tadong 2 drilled in 56 m of argillaceous source rocks of the Heituao Formation shows lithology of black carbonaceous mudstone and siliceous mudstone in the basin facies. The TOC content of the 32 samples is 0.35–7.62% with an average of 2.84%. Among them, more than 2% of the samples account for 65.6%. The black shales of the Saergan Formation in the western part of the basin were formed by the anoxic event of the Middle Ordovician Period. The Middle and Upper Ordovician Saergan Formation (O2–3s) in the Keping section is a set of 13.4 m thick rock with thin gray layers or lenticular limestone. It has large variations in lateral thickness and a high organic matter abundance. It was measured that the TOC content of muddy source rocks of the Saergan Formation in the Dawangou section ranged 0.74–4.03%, with an average of 2.15%. The Ro values of the Middle Ordovician source rocks in the Tarim Basin are relatively low in the outcrop area of the Yijianfang Formation in the southwestern Tarim Basin, at 1.02–1.52% with an average of 1.32%. However, the Ro value in the Lower–Middle Ordovician is 1.8–1.9% in Kandilike section, southwestern margin of the Tarim Basin. In the Bachu Uplift, the Ro value of wells H3 and H4 is 1.39–1.51%, with an average of 1.46%. In the Shaya Uplift, that of wells LN5 and LN10 ranged from 1.2 to 1.5%. In the Tazhong Uplift, the Ro value of the Lower Ordovician rocks is 1.3–1.5% in well TC 1; the source rock entered the high-to-mature stage gradually northward and eastward. In the Guchengxu Uplift, the Lower Ordovician Ro of well TD 1 is 2.14–2.35%. In the Manjiaer Depression, the Middle–Lower Ordovician strata are buried at depths of 9000–10,000 m, and the current Ro value is 3.0–5.0%. Therefore, the source rock of Middle to Lower Ordovician is in the mature and high mature stages in the Bachu, Katake, and Shaya Uplifts. The remaining areas have entered the post-mature stage. 3.4.2.2 Upper Ordovician Source Rocks The source rocks of the Upper Ordovician are composed mainly of carbonate source rocks of the Lianglitage Formation and argillaceous source of the Yingan/Queerqueke Formation. The TOC content of the carbonate source rocks in the Lianglitage Formation is generally between 0.3 and 0.6%.

3 Major Source Rocks and Distribution

The hydrocarbon generation material mainly includes Tasmanian algae, Gloeocapsomorpha, macroalgae, and some amorphous types; its organic type is types II1–II2. The maturity of the Upper Ordovician carbonate source rocks varies significantly among regions. In the eastern parts of the Tazhong Uplift, the Ro value is between 0.81 and 1.09%, with an average of 0.94%. In the western parts, the value is 0.95–1.3%, with an average of 1.16%. In the Shaya Uplift, the Ro ranged from 1.15 to 1.53%. In the rift areas of Manjiaer and Awati, the value is 1.5–3% in most areas, which are in the mature and high mature stages. In some areas, particularly at the center of the depression, the Ro value is 3–5%, indicating the post-mature stage.

3.4.3 Carboniferous Source Rocks The Lower Carboniferous source rocks are developed mainly in the southwest depression and Bachu area, as well as the northeast Tarim Basin. Dominated by dark mudstone of the Bachu Formation, this source rock was deposited in tidal flat and lagoon environments at a thickness of 20–300 m. In southwestern Tarim and the southern parts of Bachu, its thickness is more than 100 m. The TOC of the Lower Carboniferous mudstones in the western part of the Bachu Uplift is 0.40–4.30%; however, the Ro value is generally 0.5–0.6%, signifying low maturity, and the effective source distribution area is small. At present, the oil and gas discoveries associated with this set of source rocks are distributed mainly in the Hetian–Yecheng area, southwestern Tarim Basin. The Upper Carboniferous dark mudstone is developed mostly in the southwestern depression of the Tarim Basin, although its overall thickness is generally less than 100 m. The Upper Carboniferous dark mudstone is developed mostly in the southwestern depression of the Tarim Basin. The TOC content in the Altash section of the southern margin of the basin is between 0.69 and 1.28%, and its Ro value is 0.91–2.39%, reaching the mature–post-mature stage. The TOC content in the dark mudstones of well LN 16 in the Tabei area is 0.47–5.91%, with an average of 1.40%, indicating good source rock.

3.4.4 Permian Source Rocks Mainly distributed in the eastern part of the Bachu Uplift and the Tazhong area, the Permian dark mudstones have a thickness of 100–340 m. In other areas, its thickness is less than 100 m. This rock has reached the stage of low maturity in the majority of areas in the Tarim Basin. For example, in Bachu Uplift, the Ro value is generally 0.45–0.70%. Owing to its deep burial depth and high thermal evolution degree in the depression area of the southwestern Tarim Basin, the Ro value is

3.4 Major Marine Source Rock and Its Distribution in the Tarim Basin

generally greater than 1.5%, reaching the stage of high mature– post-mature. In general, this indicates poor source rock. Based on the above analysis, the following conclusions have been drawn for the marine source rocks of the Tarim Basin. The development of Cambrian–Ordovician source rocks is mainly controlled by the distribution of sedimentary facies. High-quality source rocks are mainly developed in low-energy sedimentary environments such as platform margin slope facies–basin facies and platform facies. In lithology, it is mainly argillaceous rocks, with some argillaceous limestone and dolomite. In terms of strata, the Middle and Lower Cambrian source rocks are a set of well-developed high-quality source rocks, which are the main source rocks of the main oil and gas fields in the basin. The Ordovician black clay depression is widely distributed in the Eastern Tarim area, with stable thickness distribution and regional correlation. It is a good source rock with high organic carbon content. The Lianglitage Formation is widely distributed in the basin, mainly limestone, with relatively poor hydrocarbon generation capacity. The Sargan Formation is located in the Keping outcrop area in the west of the basin and is also a good source rock. The Carboniferous–Permian source rocks are distributed mainly in the southwestern part of the Tarim Basin. Their organic matter abundance is worse than that of the Cambrian and Ordovician rocks, and the kerogen belongs mostly to types II–III, indicating the stage of premature–low maturity.

References Cai K, Wang Y, Yang Y et al (2003) Evaluation of hydrocarbon source rocks in Permian and Triassic at Guangyuan-Wangcang region in Northwest Sichuan Basin and a primary discussion on gas source. Nat Gas Ind 23(2):9–15 Dong D, Zou C, Yang H et al (2012) Progress and prospects of shale gas exploration and development in China. Acta Petrolei Sinica 33 (S1):107–114 Fang J, Liu B, Jin F et al (2002) Source potential for generating hydrocarbon and exploration prospects of Middle-Upper Proterozoic in the northern China. Acta Petrolei Sinica 23(4):18–23 Guo X, Dongfeng H, Wen Z et al (2014) Major factors controlling the accumulation and high productivity in marine shale gas in the Lower Paleozoic of Sichuan Basin and its periphery: a case study of the Wufeng-Longmaxi formation of Jiaoshiba area. Chinese Geol 41(03):893–901 Huang J, Zou C, Li J et al (2012) Shale gas generation and potential of the Lower Cambrian Qiongzhusi Formation in Southern Sichuan Basin China. Pet Explor Dev 39(1):69–75 Jing T, Yang G, Tuo LIN et al (2015) Geological characteristics and prospective zone prediction of Meso- Epiproterozoic Shale Gas in China. Special Oil Gas Reserv 22(6):5–11

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Li Y, Li J (2010) Exploration Prospects of Shale Gas of Upper Sinian-Silurian in Mid-Yangtze Region. Xinjiang Petroleum Geology 31(6):659–663 Li S, Xiao K, Wo J et al (2008) Developmental Controlling Factors of Upper Ordovician-Lower Silurian High Quality Source Rocks in Marine Sequence. South China. Acta Sedimentologica Sinica 26 (5):872–880 Li T, He Z, He S et al (2013) Characteristics and its petroleum geological significance of the permian Paleo- Oil reservoir of Jingshan area, the north edge of the central Yangtze block. J Jilin Unv: Earth Sci Edn 43(06):1740–1752 Liang D, Guo T, Chen J et al (2008) Some progresses on studies of hydrocarbon generation and accumulation in marine sedimentary regions, southern China (part 1): distribution of four suits of regional marine source rocks. Marine Origin Pet Geol 13(02):1–16 Liang D, Guo T, Chen J et al (2009) Some progresses on studies of hydrocarbon generation and accumulation in marine sedimentary regions, southern China (part 2): geochemical characteristics of four suits of regional marine source rocks South China. Marine Origin Pet Geol 14(01):1–15 Liu D, Xie Z, Li J et al (2013) The inorganic microelement characteristics and hydrocarbon potential prediction of algal dolomite in Dengying formation from Sichuan Basin. Sci Technol Eng 13(10):2791–2798 Song N, Yang S, Hou P et al (2013) Geological conditions of shale gas in the Wufeng-Gaojiabian formations in lower Yangtze area. Sci Technol Rev 31(33):42–46 Teng G, Qin J, Zheng L (2008) Spatiotemporal distribution of Sinian-Permian excellent marine source rocks in southeastern Guizhou Province. Marine Origin Pet Geol 13(2):37–44 Wang J, Chen D, Wang Q (2007) Platform evolution and marine source rock deposition during the terminal Sinian to early cambRian in the middle Yangtze region. Acta Geol Sin 81(8):1102–1112 Wang S, Chen G, Dong D et al (2009) Accumulation conditions and exploitation prospect of shale gas in the Lower Paleozoic Sichuan basin. Nat Gas Ind 29(5):51–58 Wei G, Xie Z, Song J et al (2015) Features and origin of natural gas in the Sinian-Cambrian of central Sichuan paleo-uplift, Sichuan Basin SW China. Pet Explor Dev 42(06):702–711 Wu H, Yao S, Jiao K (2013) Shale-gas exploration prospect of Longtan Formation in the Lower Yangtze area of China. J China Coal Soc 38 (5):870–877 Xia M, Wen L, Wang Y et al (2010) High-quality source rocks in trough facies of Upper Permian Dalong Formation of Sichuan Basin. Pet Explor Dev 37(06):654–662 Yang P, Xie Y, Li X et al (2012) Hydrocarbon-generating potential of the source rocks of the Sinian Doushantuo Formation on the western side of the Xuefeng Mountain. Chinese Geol 39(05):1299– 1310 Yong Z, Zhang X, Deng H (2012) Differences about organic matter enrichment in the shale section of Ediacaran Doushantuo Formation in West Hubei of China. J Chengdu Univ Technol: Sci Technol Ed 39(6):567–573 Zhang Y, Zhang B, Wang F et al (2001) Two sets of marine shoveling source beds in Tarim Basin -1. Properties, development environment and control factors of organic matter. Progress Nat Sci 11 (03):39–46 Zhang C, Liu G, Zeng H et al (2012) Depositional environments and controlling factors of Permian source rocks in Western Sichuan Basin. Nat Gas Geosci 23(4):626–632 Zhou H (1990) On the mechanism and the characteristics of early Cambrian ‘stone coal’ in lower yangtze region and their relation to petroliferous potentials. Pet Geol Exp 12(1):36–42

4

Reservoir Type and Origin

The reservoir, also known as reservoir rock, is one of the basic factors controlling the formation of hydrocarbon reservoirs. Reservoir features, such as the type, internal structure, reservoir properties, horizon, thickness, and distribution patterns, control the type, distribution, and productivity of oil and gas reservoirs. Common reservoir lithologies in marine facies systems include carbonate rock, clastic rock, and unconventional shale. In the past 10 years, considerable progress has been made with respect to the research in the field and breakthroughs have been achieved in many marine oil and gas exploration fields in China. This chapter focuses on the carbonate reservoir research progress. A detailed summary of Chinese marine carbonate reservoir rock types, the reservoir space, genetic distribution, and exploration potential is provided and the development of marine clastic rock and shale reservoirs is briefly discussed. While the identification characteristics of various types of reservoirs, marine layer descriptions, prediction technologies, and other relevant research will be discussed detailly in Part II of this book.

4.1

Overview

4.1.1 Research Progress with Respect to Marine Strata Reservoirs in China 4.1.1.1 Carbonate Reservoirs The oil and gas exploration of deep and ultra-deep carbonate rocks in China in the past 20 years has greatly promoted the knowledge about the genesis of carbonate reservoirs and prediction and evaluation techniques. (1) Dolomitization and reservoir development Dolomitization can improve the reservoir properties; however, large-scale dolomitization requires more intensive evaporation environments (e.g., tidal flat, lagoon, and beach

bar). Limited dolomitization can also occur under post-penecontemporaneous and deep-burial conditions. Based on existing research results, most of the high-quality dolomite reservoirs are related to penecontemporaneous, evaporative pumping, mixing, and adjustment dolomitization, which occurred in the syngenetic, penecontemporaneous, and early post-penecontemporaneous stages and even in shallow burial environments. Examples are the oolitic shoal dolomite of the Lower Triassic Feixianguan Formation in the Puguang gas field, Sichuan Basin, and inner-platform shoal of the Middle and Lower Ordovician Penglaiba–Yingshantai Formation in the Tarim Basin. The true constructive diagenesis in these high-quality dolomite reservoirs is often associated with early freshwater or mixed-water dissolution, hydrothermal dissolution, and tectonic fracture. Recently, hydrothermal dolomites associated with tectonic and magmatic activity have been more frequently discussed. These dolomites form due to the high or abnormal temperatures of diagenetic fluids. (2) Karst reservoirs The term karst does not only describe karstification but also rock solution or dissolution including syngenetic dissolution of the depositional stage, exposed dissolution of the penecontemporaneous stage, early post-penecontemporaneous dissolution, and burial dissolution. To dynamically study karst, the main factors affecting the surface karst and the karstification mechanism and technology must be studied. Large-scale karst reservoirs generally develop under unconformity surfaces. However, not all strata under unconformity surfaces can develop high-quality karst reservoirs. The formation of such reservoirs is to a large extent controlled by the karst paleogeomorphology. Therefore, the restoration of the karst paleogeomorphology has become an important aspect of the identification of favorable karst reservoirs (Xia et al. 1999). The main methods used to

© Geological Publishing House and Springer-Verlag GmbH Germany 2020 Y. Ma, Marine Oil and Gas Exploration in China, https://doi.org/10.1007/978-3-662-61147-0_4

81

82

reconstruct the paleogeomorphology are geophysical, impression, residual thickness, sequence stratigraphy, and sedimentology methods (Zhao et al. 2001, 2003; Bai et al. 2002; Kang and Wu 2003; Dai and He 2005; Wu et al. 2005; He et al. 2006). However, these methods are limited when used independently. Therefore, for the identification of karst reservoirs, the use of a combination of outcrop, drilling, logging, core, well log, seismic, petrological, mineralogical, and geochemical data is necessary. Karstification signatures generally include karst breccia, karst caves, drilling leakage or travel empty, “moniliform”-like seismic reflections, and d13C and d18O reductions.

4

Reservoir Type and Origin

1997; Liu et al. 2008, 2016; Wei et al. 2013a, b). However, whether these rocks are microbial carbonate rocks remains unclear (Mei 2011; Luo et al. 2013). Microbial genesis has an impact on the reservoir’s physical properties but does not control the reservoir development, which is mainly controlled by dolomitization, freshwater dissolution, burial dissolution, and other factors such as tectonic activity. In addition, carbonate rocks are generally developed in Ordovician or older strata with the long history of diagenetic evolution and deeply buried. Therefore, the reservoir development potential must be carefully evaluated. (4) Classification and evaluation of carbonate reservoirs

(3) Relationship between bacterial/microbial carbonates and the reservoir development Based on the taxonomy proposed by Chinese scholars, organisms can be divided into six kingdoms: Archetista, Monera, Protista, Fungi, Plantae, and Animalia. Microorganisms belong to four of the six kingdoms, indicating the importance of microorganisms in nature. In the Middle Neoproterozoic and Paleozoic with relatively few higher organisms on Earth, the influence of microorganisms, especially on the formation and distribution of carbonate rocks, was even greater. Many microorganisms are directly or indirectly involved in the formation of carbonate rocks; they have direct biological effects (microbial remains of the formation of carbonate rock) or indirect biochemical effects (first affecting the microenvironment and then the precipitation of calcium carbonate). Microbialite deposition is defined as the in situ formation of biochemical sediments by the direct or indirect action of a benthic microbial group (including trapping and bonding or calcification) after the formation of rock-forming microbial rock. Microbial carbonate rocks, which can be divided into stromatolites and thrombolites, mainly contain carbonate minerals. Bacteria/microorganisms may be one of the main factors that controlled the formation of carbonate rocks before the Cambrian and are closely related to the early diagenesis of carbonate rocks. Microbial carbonate rock is an important potential high-quality reservoir. At present, China’s marine oil and gas found in microbial carbonate rocks are mainly distributed in the Middle Proterozoic Wumishan Formation in the Renqiu field, Bohai Bay Basin (Fei and Wang 2005); Sinian–Cambrian system of the Tarim Basin (Li et al. 2015); Upper Sinian of the Moxi–Gaoshiti, Weiyuan, and Ziyang gas fields in the Sichuan Basin; and Middle Triassic Leikoupo Formation in the western Sichuan Basin (Wang et al.

Due to the complexity of the genesis and pore types of carbonate reservoirs, the classification and evaluation methods are inconsistent. Domestic scholars put forward a variety of classification schemes based on different aspects. Some scholars classify the advantages and disadvantages of the reservoir space based on the evaluation of the porosity and permeability of the reservoir (Luo et al. 1981; Kong et al. 1998). Other scholars classify the reservoir genesis and main controlling factors by dividing the carbonate reservoirs and reservoir assemblages into several basic genetic types, respectively (Fan 2005; Bai 2006; Luo et al. 2008): granular carbonate rock, reef carbonate rock, dolomite, weathering crust, and fractured carbonate rocks. However, the successful exploration and development of the dolomite and limestone of the reef–shoal complex in the Central Tarim oilfield in the Tarim Basin and Puguang, Yuanba, and An’yue gas fields in the Sichuan Basin (Ma et al. 2005, 2010, 2014; Yang et al. 2015; Wang et al. 2014); buried hill oil and gas fields in the Tarim Basin (Qi and Yun 2010), Ordos (He et al. 2005); oil and gas fields related to fractures (Chen 1995; Ni et al. 2010); and various large carbonate oil and gas fields worldwide (Zhang et al. 2015) have confirmed that the main carbonate reservoir types are reef–shoal (limestone), (reef) dolomite, karst, and fractures. To predict deep and ultra-deep reservoirs, facies prediction, pore system evolution, geophysical technology, drilling reservoir protection technology, testing technology and equipment, and many other aspects must be addressed.

4.1.1.2 Clastic Reservoirs Marine clastic rocks accounted for a certain proportion of marine strata before the Paleozoic in China. Important research progress has been made with respect to the discovery of marine clastic reservoirs in the Tarim, Ordos, and Sichuan Basins.

4.1 Overview

(1) Clastic rock oil and gas exploration gradually expands to a deeper level Clastic reservoir oil and gas exploration is gradually expanding to deep layers such as carbonate reservoirs. The term “deep” refers to different depths in different petroliferous Basins, generally more than 3000, 3500, 4000, 4500, and 5000 m (Zhong et al. 2008; Pan et al. 2014; Jia and Pang 2015; Zhang et al. 2015, 2016). There are notable differences between the development of deep clastic reservoirs and middle and shallow layers, which are usually characterized by a high temperature, high pressure, poor physical properties, complex pore structure and genetic type, strong diagenesis, and strong heterogeneity. The proportion of micropores significantly increases in deep strata, which contrasts the primary and secondary pores in middle and shallow reservoirs. Macroscopic secondary dissolution pores are not very developed. The development of pores in clastic reservoirs is mainly controlled by the following five factors: ① the diagenesis of compaction, pressure solution, cementation, and the mineral volume increase replacement is the main factor reducing the porosity of deep reservoirs; ② the diagenesis of dissolution, fracturing, shrinkage and mineral volume reduction replacement is the main factor increasing the porosity of deep reservoirs; ③ granular coating, oil and gas injection, and fluid overpressure are the main factors preserving pores in deep reservoirs; ④ factors such as early accumulation, tectonic uplift, and rapid deep-burial inhibit the diagenesis and play important roles in the preservation of pores; and ⑤ the dynamics of the basin affects the diagenesis of deep reservoirs (Huang et al. 2007; Zhu et al. 2008, 2009; Sun et al. 2013). (2) Tight sandstone reservoirs A tight sandstone reservoir usually refers to strata with a narrow pore throat, poor connectivity, very low permeability (Feng 1986; Yu et al. 2015), and basic characteristics of tight reservoirs, low resource abundance, large hydrocarbon-bearing area, local enrichment “sweet spot”, complex oil–gas–water relationship, partial control of the trap, abnormal pressure, good crude oil property, high initial production and rapidly decline after the reconstruction, and long production cycle (Zhao and Du 2012). The porosity and permeability of tight sandstone reservoirs are km

Venting, leakage

Convex curve

Declining rapidly or declining rapidly in initial stage, later stage relatively stable

Fractures or cracks, cavities

Fracture

Crack–pore

KR > km

Accelerated during light drilling

Step

Decline in initial capacity, later stage stable

Fractures, pores

Fracture

Pore–fracture

KR >> km

Accelerated when drilling, venting, leakage

Step

Decline in initial capacity, later stage stable

Fractures, pores

Fracture

Table 4.3 Evaluation parameters for carbonate reservoirs

Reservoir classification

Porosity (%)

Permeability (103 µm2)

Median pore throat diameter

Displacement pressure (MPa)

Sorting coefficient

I

 12

 10

2

3

>0.35

>80

>40

Poor reservoir (II)

Microlayered thrombolite, dololaminate, Micro- to powder-crystalline dolomite

3–2

0.2–0.35

50–80

40–100

Non-reservoir or fractured reservoir (III)

Argillaceous, siliceous, micritic carbonate rocks

1.13

Porosity (%) Permeability (10

>5 −3

µm ) 2

>100

Brittle mineral content (%)

>40

Thickness (m)

>30

Depth (m)

14%, section smearing might be continuous. The larger the value is, the stronger is the sealing ability.

5.1.3.2 Analysis of the Effective Fault Plane Stress Fault plane effective stress = geostatic  cosa − pore pressure When the fault plane effective stress is greater than 16.6714 MPa, effective sealing of carbonate docking intervals could be caused by pressure solution along the fault zone. 5.1.3.3 Juxtaposition Sealing Based on the depth of the seismic section and the horizontal position of the breakpoint of the survey line, the elevation depth of each layer on the fault line was marked in the two-dimensional coordinate map. The same layer boundary points on both sides of the fault were connected and plotted. This reflects the relationship between the layers on both sides of the fault, variation along the fault direction, and

133

lateral sealing performance of the fault based on the conventional lithologic sealing concept.

5.1.3.4 Others Other aspects include the influence of the strength of tectonic activity, fault mechanical properties and factors, fault healing time, and fault diagenesis sealing on the sealing.

5.1.4 Cap Rock Hydrogeology Hydrogeology and geochemistry study is the criterion of oil and gas preservation condition. For the purpose of preservation, hydrogeological research is concerned not only with normal formation fluid but also with the depth of atmospheric freshwater infiltration and its influence on oil and gas reservoirs. If the infiltration depth is smaller than the reservoir buried depth and no physical and material exchange with the reservoir occurs, the reservoir is classified as safe, that is, without damage from meteoric water; otherwise, the reservoir is classified as destructive. The analysis of the hydrogeological cycle characteristics suggests that the relatively stable buried stage might be a significant period of hydrocarbon generation, migration, and accumulation; tectonic activities and uplift, and erosion can cause the hydrocarbon to migrate and adjust. However, if the tectonic activities are significant, the hydrocarbon accumulations might be destroyed because of faulting or uplifting and the infiltration of meteoric water below the reservoir buried depth (through fault, unconformity, or other channels). Therefore, oil and gas reservoirs are mainly damaged during periods of strata deformation and uplift and erosion. Two aspects should be considered when studying the damage of hydrocarbon accumulations due to meteoric water: (1) physical (temperature, pressure) or material exchange occurring between the meteoric water and reservoir, and (2) the exchange intensity or degree. In other words, in addition to the infiltration volume, especially the exchange volume with oil and gas, the atmospheric water infiltration depth and probable paths connecting the oil–gas reservoir should be determined (Lou and Zhu 2006; Lou et al. 2008).

5.1.4.1 Vertical Hydrogeological Zonation and Hydrocarbon Preservation Conditions There are three major types of formation water, that is, burial deposition water, meteoric infiltration water, and endogenous water. The former two types account for most of the formation water. The burial deposition water includes sedimentary and formation water (primarily meteoric water) that formed

134

during the hiatus supergene stage. After long periods of water–rock exchange, the water salinity and metamorphic grade increases; the common water type is CaCl2. However, because of the uplift and tectonic activities influenced by meteoric water infiltration, the formation water changes to lower-salinity, lower-metamorphic grade Na2SO4 water; NaHCO3 water represents the transitional type. According to the difference in the degree of closeness between groundwater and surface water, there is more or less connection between groundwater and surface water. In general, the closer the groundwater is to the surface, the closer it is to surface water. Conversely, the deeper the burial, the less contact it has with surface water (Lou and Zhu 2006). Based on the interrelationship level, the formation water can be vertically and laterally divided into three different zones (Hydrogeological vertical zonation), that is, free exchanging zone, exchanging-retarded zone, and exchanging-stagnant zone (Liu and Yan 1991). The free exchanging zone is the active oxidation environment due to the infiltration of large volumes of surface water, the exchanging-stagnant zone is the favorable sealing environment for hydrocarbon preservation conditions because surface water infiltration is difficult, and the lower part of the exchanging-retarded zone is favorable for hydrocarbon preservation. Industrial hydrocarbon accumulations usually occur in the exchanging-stagnant zone, which is characterized by favorable preservation conditions and is separated from the surface, with good sealing conditions. Vice versa, only parts of the heavy oils with more colloids remain in the hydrocarbon accumulations in the free exchanging zone, which is well connected with the surface and influenced by surface factors over the long term. Therefore, the hydrogeological zone in which the hydrocarbon accumulates directly affects the preservation conditions of hydrocarbons.

5.1.4.2 Lateral Hydrodynamic and Hydrocarbon Preservation Conditions Lateral hydrodynamic conditions include the current geohydrological supply–release system, which significantly influences the hydrocarbon preservation (Pan and Yang 1992). For example, the dolomite reservoir of the Jia3 member in the Jiannan gas field has tens of meters of gypsum of the Jia4 and Jia5 members as direct cap rock, The vertical hydrogeological zoning in the Lower Jurassic is already the exchanging-stagnant zone, but the drilling results are all water layers. This is due to the large infiltration of surface water because of the wide outcrop in the anticlinorium belt in the Qiyue and Fangdou Mountains. In addition, the gypsum-rich Jia4 and Jia5 cap rocks situated in the current valley or collection area of the surface runoff form a series of moniliforme swallow holes along the formation, which are

5 Regional Cap Rock and Hydrocarbon Preservation

conducive to the infiltration of large amounts of surface water into the synclinorium (Wu et al. 2012). Serious lateral scour is the major reason that this interval only produces water. The Yanjing structure on the east side of the Jiannan structure is also close to the Qiyue Mountain anticlinorium belt, which is subjected to the strong lateral surface water erosion. The target layer of the Changxing Formation and above is mainly water-producing and loses its exploration value. For most of the major targets in southern China (such as the Chuandong area with gypsum and good preservation conditions), fault activities and tectonic uplifting significantly affect the natural gas preservation conditions. The thinning of cap rock, the existence of fault or micropores and fractures, and infiltration of surface water into the outcrop damage the hydrocarbon accumulations.

5.1.4.3 Relation Between the Preserved Meteoric Water and Hydrocarbon Preservation Conditions The paleometeoric water preserved in the reservoir is called preserved meteoric water. The Ordovician strata in the Ordos and Tarim Basins, including the discovered marine oil and gas fields (Lou et al. 2008), experienced strong long-term uplifting and erosion and developed ancient karst reservoirs with thicknesses of *300 m. In the proven petroleum province with ancient karst reservoirs, part of the initial sedimentary buried water was once displaced by infiltration meteoric water. However, in the latter process, the lower Paleozoic sedimentary buried water carrying hydrocarbons formed a new centrifugal flow and displaced the infiltration meteoric water during the Caledonian, Hercynian, and Indosinian movements. Subsequently, the current hydrocarbon accumulations were formed. On the one hand, this process itself has characterized the oilfield water in the Ordovician reservoir in the Tahe oilfield, which mainly is sedimentary buried water; on the other hand, hydrocarbons migrated and accumulated together with the centrifugal flow during the displacement process. It can be concluded that sedimentary buried water with high salinity and high Na+ and Cl– concentrations is the significant indicator of hydrocarbon preservation conditions and can be used for the evaluation of the hydrocarbon generation, migration, accumulation, and preservation. Therefore, according to the characteristics of the hydrogeological cycle, the relatively stable buried stage might be a significant period of hydrocarbon generation, migration, and accumulation and tectonic activities and uplifting erosion cause the hydrocarbons to migrate and adjust. However, if the tectonic activities are significant, the hydrocarbon accumulations might be destroyed because of faulting or uplifting and the infiltration of meteoric water below the reservoir buried depth (through fault, unconformity, or other

5.1 Summary

fairways). Therefore, the oil and gas reservoirs are mainly damaged during the strata deformation and uplift erosion period. To study the damage of the hydrocarbon accumulations due to meteoric water, two aspects should be considered: (1) physical (temperature, pressure) or material exchange occurring between the meteoric water and reservoir, and (2) the exchange intensity or degree. In other words, the atmospheric water infiltration depth, probable paths connecting the oil–gas reservoir, and infiltration volume, especially the exchange volume of oil and gas, should be determined.

5.1.4.4 Hydrogeological and Hydrogeochemical Index System for Hydrocarbon Preservation Conditions The hydrogeological and hydrogeochemical characteristics of groundwater are closely related to the hydrocarbon migration, accumulation, and damage of oil and gas pools. Based on the study of the hydrogeochemical characteristics of marine oilfields in the Sichuan, Tarim, Ordos, and other basins in combination with the fundamental geochemical characteristics of southern marine strata, a hydrogeochemical index system was established for the hydrocarbon preservation conditions (Ma et al. 2006) (Table 5.2) after comparing and analyzing the geochemical characteristics of rivers, lakes, oceans, and spring waters.

5.1.5 Evaluation System for the Preservation Conditions In addition to the hydrogeological and hydrogeochemical index system for the hydrocarbon preservation conditions, Professor Lou Zhanghua also put forward a comprehensive evaluation index system for the preservation conditions (Table 5.3) (Lou and Zhu 2006; Lou et al. 2008).

5.2

Marine Hydrocarbon Preservation Conditions in Yangtze Area

5.2.1 Cap Rock Type and Distribution As mentioned in the last chapter, there are five major sets of regional cap rock in southern China, that is, Lower Cambrian, Silurian, Middle–Lower Triassic, Upper Triassic– Lower Cretaceous, and Cretaceous–Paleogene cap rocks. “Regional capping” is used here, which only indicates that they are lithologic distribution with capping properties. Whether they can play the role of “regional capping” or not requires the coordination of relevant geological conditions.

135

5.2.1.1 Regional Cap Rock in the Lower Cambrian A huge set of thick organic-rich black mudstone and shale exists in the Early Cambrian in southern China, which can be observed in almost the whole Yangtze area, indicating an anoxic stagnant depositional environment. It constitutes the first set of good regional cap rock with a thickness ranging from 50 to 600 m, with an average of 400 m (Fig. 5.2). The following favorable cap rock areas can be classified based on the mudstone thickness: • Bijie–Yibin–Luzhou area, with 200–400 m mudstone; • Dayong–Jishou–Youyang area, with 300–700 m mudstone; • Da Bashan area, with 300–1000 m mudstone; • Tongshan–Xianning–Yueyang area in the southern Jianghan Basin, with 150–250 m mudstone; • Wannan–Ningguo area, with 200–400 m mudstone; and • Subei area, with 100–150 m mudstone. The data indicate that Lower Cambrian mudstone has a good sealing performance. The results for four mudstone samples from the Niutitang Formation, in well Zhuang1 in the Qiandong area show an average porosity of 1.22%, permeability of 10−6–10−3 lm2, breakthrough pressure of 20.5 MPa, and density of 2.76 g/cm3; the pore analysis of Lower Cambrian mudstone from wells Guo1, Cha1, Li1, Xian1, and Yi4 in the west area of Hunan and Hubei suggests 0.8–3.2 mm micropores of greater than 90% and breakthrough pressures of 13–14 MPa. Nevertheless, the sealing performance of the Lower Cambrian regional cap rock still must be further studied because of its high thermal evolution, Ro above 2%, with a maximum above 5%, and fragile rock properties, which probably cause microfractures. In addition, the gypsum cap rock in the Middle–Upper Cambrian with a certain thickness, particularly in the Shi Lengshui Formation in southern China is also very important (Fig. 5.3). The Middle–Upper Cambrian gypsum belongs to shallow-water evaporation platform deposits, mainly distributed in the Shi Lengshui Formation and lower part of the Lou Shanguan Group, with variable thickness and widespread distribution in the Sichuan Basin. The thickest deposit was observed in the Chongqing–Jiangjin area (>70 m). The statistical analysis of 15 drilling wells for the Dianqian area indicates that the gypsum in the Suiyang– Wuchuan belt has the biggest cumulative thickness (maximum thickness of 59.7 m in the Shi Lengshui Formation and Lou Shanguan Group in well Suiyang 1 (Yang 1999). The lithologies are dominated by gypsum and dolomitic gypsum, followed by gypsum or gypsum-bearing dolomite. Due to the collapse of the gypsum strata caused by freshwater leaching–solution, gypsum breccia occur. The gas layers in the Sinian and Cambrian in the Weiyuan gas field, Sichuan

136 Table 5.2 Hydrogeological and hydrogeochemical index system for marine hydrocarbon preservation conditions

5 Regional Cap Rock and Hydrocarbon Preservation

Origin of the formation water

Fine Class

Good Class II

Medium Class III

Poor Class IV

Sedimentary buried water

Temporarily affected by atmospheric water infiltration

Long-term affected by atmospheric water infiltration

Long-term affected by atmospheric water infiltration

Salinity (g/L)

>40

30–40

20–30

20

1–20

0.2–1

300

>300

300–100

800

>800

500–800

10

5–10

5–2

4000

Outcrop from the target layer (km)

>15

10–15

5–10

40

30–40

20–30

20

1–20

0.2–1

35

Metal mineral

None

None

Sporadic

More

Gamma isoanomaly

None

None

Sporadic

More

138

5 Regional Cap Rock and Hydrocarbon Preservation 0

100

200 km

Xi’an

200 10

20400 0

0

Chengdu

Wuhan

50

50

100 200 300 400

Chongqing

300

400 500

400

0

70

200

Changsha

Guiyang 20

Kunming

0

400

0 30

Legend Areas of denudation or sedimentation 500

Coprock isopach(m) Fault Tectonic Unit Boundary

932.38

Caprock thickness point

Fig. 5.2 Mudstone cap rock distribution in the middle-upper Yangtze region

at the bottom, belongs to source rock characterized by concentration sealing. Its thermal maturity ranges from medium to high, with a common Ro of 1.3–3%.

5.2.1.3 Regional Cap Rock in the Middle–Lower Triassic The major Middle–Lower Triassic regional cap rock is Lower Triassic gypsum, which was primarily deposited in Sabkha or a restricted platform during the marine regression in the late Early Triassic. It was deposited together with the Middle Triassic gypsum-mudstone, which belongs to

continental evaporation salt lake deposits (impacted by the extrusion and convergence of the Tethys and Pacific tectonisms, the whole southern carbonate platform disappeared). Most of South China contains Early–Middle Triassic deposits, except for several minor areas such as the Cathaysian, Yunkai, and Sichuan–Yunnan regions. Due to the strong folding, faulting, and uplift and erosion during the Yanshan–Himalayan period, the Triassic regional cap rocks were severely destroyed and almost absent in the southeastern area.

5.2 Marine Hydrocarbon Preservation Conditions in Yangtze Area

0

40

139

80 km

ie ab ng Qinli - D

Lveyang

Aba Songtan

e app

Maerkang

in ta

en

lt

Be

N

Jiangyou

n ou

Bazhong

Yuankang

nic Belt

Oroge

M

gm

Dangyang

30 20

40

50

60

Nanchong

Chengdu

70

n Lo

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Xu

efe

10

Jia

ng

na

n-

Zhaotong

Legend 10

Fault

The boundary of Sichuan Basin

Salt-rock thickness contour (m)

Fig. 5.3 Gypsum distribution in the Upper Cambrian in the Sichuan Basin

The cap rocks in the Yangtze area are well preserved; however, the Middle–Lower Triassic regional cap rock only partially remained in some synclines in the area lacking Upper Triassic–Paleogene strata. In addition to the Sichuan Basin and its surrounding areas, such as northwestern Guizhou, regions with good preservation include southern Panjiang, Dangyang, Chenhu–Tuditang, southeastern Jiangxi–southern Jiangsu–Anhui, and Lanping–Simao, which is little studied (Fig. 5.5). The Sichuan Basin contains three mudstone and gypsum depositional centers: ① Northwest Sichuan, with 500–700 m cap rock; ② Northeast Sichuan–Nanchong– Leshan–Neijiang, with 700–800 m cap rock; and ③ Fuling

region, with 400 m cap rock. The Liangping–Kaijiang and Yanting uplift has been eroded to T1 and T1+2 with only 100– 300 m cap rock. The thickness is only 19 m in the Liangping– Kaijiang area; nevertheless, the T1+2 cap rock reaches 500– 600 m eastward in the Lichuan Depression.

5.2.1.4 Regional Cap Rock in the Upper Triassic– Lower Cretaceous The Upper Triassic–Lower Cretaceous is widely distributed in southern China. It primarily includes two foreland belts in the south and north and several fault basins of the early Yanshan period.

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Areas of denudation or sedimentation Coprock isopach(m) Fault Tectonic Unit Boundary

932.38

Caprock thickness point

Fig. 5.4 Lower Silurian mudstone cap rock distribution in middle-upper Yangtze region

Larger areas of Upper Triassic–Lower Cretaceous cap rock primarily exist in the Sichuan, Chuxiong, and Shiwandashan Basins in the upper Yangtze region; Jianghan (Dangyang synclinorium and Chenhu synclinorium) an Mayang Basins and southern Poyang Depression in the Middle–Lower Yangtze region; Yanjiang area (Maanshan– Yangzhou belt) and Lanping–Simao Basin in the Tethys region; and Hefei Basin on the North China Plate in the lower Yangtze region.

5.2.1.5 Regional Cap Rock in the Cretaceous– Paleogene Cretaceous and Paleogene deposits in the studied area can be observed in the extensional fault basin formed during the late Yanshan–Himalayan period. The major lithology of the effective cap rock is mud rock, with local salt rock and gypsum mudstone. In the basins of southern China, the Cretaceous often becomes the main sediment of the basin together with the

5.2 Marine Hydrocarbon Preservation Conditions in Yangtze Area

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underlying Jurassic. After the rising and uplift, the Cretaceous is denuded, causing the remaining Cretaceous to be distributed at a local extent of the basin. The Middle Cretaceous–Paleogene in the Lanping–Simao Basin is pervasive, with a common thickness of 50–250 m, but usually disappears at the edge of the basin. The Cretaceous–Paleogene strata are partially distributed in the Sichuan and Chuxiong Basins. The Lower Cretaceous in the Middle– Lower Yangtze region partially occurs, whereas the Upper Cretaceous and Paleogene usually constitute the significant sedimentary deposits in Mesozoic and Cenozoic extensional basins such as the Jianghan, Dongting, Subei, and Hangzhouwan Basins. In the Hefei Basin, the Cretaceous–Paleogene strata dominantly occur in the center and at the partial edge of the basin.

5.2.2.2 Influence of (Hercynian) Indo-China Movement on the Middle–Lower Triassic Regional Cap Rock (207 Ma) The erosion of Middle–Lower Triassic deposits caused by the (Hercynian) Indo-China movement is pervasive. The Middle Triassic is partially eroded in the Yangtze area, Songpan–Ganzi, Simao, and Datian–Zhangping in southwest Fujian, whereas it is completely eroded in central Sichuan. The Middle–Lower Triassic still can be observed in Nanpanjiang and the northern Shiwandashan Basin. In addition to those areas, the Middle–Lower Triassic is almost absent in South China. The stratum deformation caused by the Indo-China movement is also light.

5.2.2 Influence of Tectonic Activities on Cap Rocks Tectonic activities control the basin formation and evolution and play a key role in hydrocarbon generation, migration, accumulation, preservation, and destructive reconstruction. The destructive effects of tectonic activities on regional cap rock primarily include uplifting, erosion, and fault cutting, which damage the hydrogeological conditions to different degrees. The marine hydrocarbon region in southern China has experienced multiple tectonic activities throughout the geological history, primarily including the Caledonian, (Hercynian) Indo-China, Yanshanian, and Himalayan epochs, which had different impacts on different regional cap rocks in different southern areas (Gao and Zhao 2001; Ma et al. 2004; Xiao et al. 2006; Wo et al. 2007; Tang and Cui 2011; Zhang et al. 2007).

5.2.2.1 Influence of the Caledonian Movement on Silurian Regional Cap Rock (409 Ma) The significant influence of the Caledonian movement on Silurian cap rock in the Yangtze area, southern China, is characterized by the uplift of partial areas to land, which is then eroded or lacks sedimentation, and weak tectonic deformation. The weak deformation and strong erosion are characteristic of the Caledonian movement worldwide. The Silurian sediments once deposited in the south Yangtze area, Xuefeng–Jiangnan Uplift, Nanhua area, east Yunnan–central Guizhou Uplift, central Sichuan Uplift, Xixiang–Luangao in Dabashan, and Yongren–Shuangjiang in Yunnan were almost all eroded during the Caledonian epoch. The majority of the Upper Paleozoic overlies the previous Silurian. Currently, Silurian cap rocks primarily exist in the northern Yangtze and the Deqing–Fangcheng area.

5.2.2.3 Influence of the Yanshanian Movement on the Upper Triassic–Lower Cretaceous Regional Cap Rock (97 Ma) The Yanshanian movement resulted in an overwhelming reconstruction of the Yangtze platform, which not only led to series of great geological change, such as fold nappes, erosion and hiatus, volcano eruptions, and magma intrusion but also led to the formation and development of early foreland and late extensional basins. The erosion of the Early Yanshanian regional cap rocks by the tectonic activities of the Middle Yanshanian movement primarily occurred in many regions, in addition to the Sichuan Basin (Fig. 5.6, Table 5.4). In the middle and lower Yangtze area, strong tectonic activities led to the erosion of all Triassic–Jurassic deposits, except for those in the synclinoria of Dangyang– Jingmen and Tianmen–Jiayu in central Jiangxi. Moving eastwards to the lower Yangtze area, regional cap rock can barely be observed. Overall, the damage of the regional cap rocks, which formed in the Early Yanshan period and before, by the Yanshanian movement is fatal in several areas, except for the Sichuan Basin, the upper Triassic and Jurassic area cap rocks are not only subjected to strong thrust nappe, dismemberment, and fragmentation, but they also lose effective sealing effect on natural gas and overall sealing conditions. This will also affect the overall storage conditions of the Silurian regional cap rocks. 5.2.2.4 Influence of the Himalayan Movement (23 Ma to Present) During the Himalayan period, the area south of the Qinling-Dabie orogenic belt, the western part was collided by the Indian Plate, and the eastern part was collided by the Pacific Plate. The vast southern part of the area that was sandwiched between them appeared as the tectonic framework of three uplifts and two depressions striking in NE direction. In the uplift areas, many regional cap rocks, such as the Paleogene, Cretaceous, and Jurassic, eroded, whereas they can be observed in the depression areas. For instance, the Subei and Jianghan Basins in the Middle and Lower

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Isogram (m) Gypsum breccia Gypsum

Fig. 5.5 The Middle–Lower Triassic gypsum distribution in middle-upper Yangtze region

Yangtze area are two larger equipped fault basins overlain by Upper Cretaceous and Paleogene. Although the regional cap rocks (gypsum-rich in the Huaiyin–Hongze area) are effective, the pervasive Late Cretaceous–Paleogene sedimentary sequence in the half-graben rift has protected the previously broken oil-bearing system from scale escaping. Nevertheless, large amounts of seismic data below show that the regional cap rocks (e.g., Lower Cambrian, Silurian, and Permian–Lower Triassic) of the marine Paleozoic were broken and fundamentally. It has become impossible to form

a uniform area cover in three-dimensional space, and basically loses the overall cover preservation condition. The late Himalayan movement has further reconstructed the distribution framework of the marine hydrocarbon-bearing system in the middle and lower Yangtze area. The subsidence of the Neogene–Quaternary in the lower Yangtze area has protected the Late Cretaceous– Paleogene basins and their marine hydrocarbon system; whereas the uplifting resulted in the pervasive erosion of Late Cretaceous–Paleogene basins and marine stratums in

5.2 Marine Hydrocarbon Preservation Conditions in Yangtze Area

143

K1 J3 K J2

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Volcanics

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Conformity

Parallel Unconformity

Angular Unconformity

Fig. 5.6 Relationship between residuals of Yanshanian strata and the Yanshan II stratum in the middle and upper Yangtze area (He et al. 2011)

the south of the Jiangsu and Anhui area, which led to the reconstruction of the hydrocarbon preservation and distribution framework. In the middle Yangtze area, bounded by the Qianbei fault belt, the northern part of the Jianghan Basin was completely uplifted, while the southern part, whose hydrocarbon preservation framework was also notably reconstructed, generally subsided. The northern part lost the sealing and preservation capabilities. In conclusion, the study of cap rocks is only one part of the studies of the preservation conditions in marine hydrocarbon exploration in South China.

5.2.3 Marine Hydrocarbon Preservation Units in South China Emphasis has been placed on studies of the marine hydrocarbon preservation condition in the south of China for a long time. Six units are generally categorized according to the preservation conditions (Yang et al. 2002; Fu et al. 2002; Ma et al. 2006; Zhou and Liang 2007).

5.2.3.1 Continuous Hydrocarbon Preservation Unit The continuous hydrocarbon preservation unit is a sealing and preservation system for hydrocarbon formation and preservation without damage. On the one hand, the marine hydrocarbon system is well preserved without suffering large-scale tectonic reconstruction and the whole sealing system is protected from great damages. On the other hand, the continuous thick continental cap rocks in the Mesozoic and Cenozoic have a good impact on the sealing and protection of the marine hydrocarbon system. For example, in known gas reservoir areas, such as East Sichuan (including the Shizhu syncline), Central Sichuan, West Sichuan, and South Sichuan, of the Sichuan Basin with Jurassic regional cap rock, the preservation characteristics are the Mesozoic regional cap rocks, such as Jurassic and Cretaceous, in a large area above the marine hydrocarbon system, are well preserved; a high-pressure system is commonly observed in marine strata (including the continental Upper Triassic) below the regional cap rocks; and the hydrogeological conditions are good, with CaCl2-type water with a salinity above 35 g/L.

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5 Regional Cap Rock and Hydrocarbon Preservation

Table 5.4 Typical hydrocarbon generation and damage mechanisms in the middle and upper Yangtze area (He et al. 2011) Name

Tectonic Units

Accumulation Period

Destruction period and mechanism

Majiang Ordovician ancient reservoir

Southern Guizhou Depression

(1) Crude oil is initially charged in the Caledonian; (2) The Hercynian period is the main filling period of crude oil; (3) Crude oil is cracked into gas to form the paleo-gas reservoir in the Late Indosinian–Early Yanshanian

(1) Indosinian pyrolysis asphalt; (2) Uplift and denudation during the Yanshanian

Kaili Silurian residual oil and gas reservoir

Southern Guizhou Depression

(1) Early reservoir formation in the Hercynian period; (2) Crude oil cracking into gas in the Middle Indosinian; (3) Secondary oil generation in the Lower Silurian in the Middle Indosinian

(1) Uplift and denudation during the Yanshanian; (2) Uplift and denudation during the Himalayan

Nanshanping Sinian ancient reservoir

Western Hunan–Hubei Fold Belt

(1) Late Caledonian oil generation; (2) Indosinian cracked gas

(1) Indosinian pyrolysis asphalt; (2) Uplift denudation and faulting during the Yanshanian

Tongshan Bankeng Silurian ancient reservoir

Southeastern Hubei Fold Belt

(1) Primary reservoirs were formed in the Early Indosinian; (2) Since the Late Indosinian, the ancient oil reservoirs have been damaged

(1) Late Indosinian pyrolysis asphalt; (2) Yanshanian thermal granite intrusion

Tianjingshan Cambrian ancient reservoir

Longmenshan Thrust Nappe Structural Belt

(1) In the Early Hercynian, the Lower Cambrian source rocks generated oil and the Lower Cambrian rocks accumulated in reservoirs; (2) In the Early Jurassic, the crude oil generated from the Permian source rocks was deposited in the Qixia Formation

(1) During the Indosinian–Early Yanshanian, the Lower Cambrian crude oil suffered from thermal cracking; (2) During the Himalayan, Longmenshan overthrust caused the fault to reach the ground and suffered from air washing

Jingshan Ordovician oil seep

Bahong Thrusting Anticline Belt

(1) In the Early–Middle Triassic, the crude oil generated from the source rocks of the Lower Paleozoic was deposited in the Ordovician reservoir; (2) In the Early Jurassic, the crude oil generated from the Permian source rocks was deposited in the Qixia Formation

(1) Late Jurassic–Early Cretaceous Yanshanian main curtain thrust uplift; (2) Readjustment and partial destruction of the Himalayan movement

Weiyuan Sinian gas field

Central Sichuan Gentle Structural Belt

(1) Formation of early paleo-reservoir in the Caledonian; (2) Uplift and denudation of the Hercynian and early paleo-reservoir damage; (3) Late Permian–Triassic paleo-reservoir formation; (4) Jurassic–Late Cretaceous oil cracking and early gas reservoir formation; (5) In the Himalayan, the uplift in the Ziyang area was adjusted to form a reservoir and the uplift and dissolution in the Weiyuan gas field formed a reservoir

Puguang Permian– Triassic gas field

Northeastern Sichuan High-steep Anticline Belt

(1) Late Indosinian–Early Yanshanian reservoir formation stage; (2) Middle and Late Yanshanian deep-buried oil and gas transformation stage; (3) Formation of the Himalayan

Carboniferous gas field in eastern Sichuan

Eastern Sichuan High-steep Anticline Belt

(1) Indosinian–Early Yanshanian reservoir formation stage; (2) Middle and Late Yanshanian deep-buried oil and gas transformation stage; (3) Formation of the Himalayan

One of the key factors for the formation of a continuous hydrocarbon preservation unit is the relative tectonic stability. The Sichuan Basin (including the Shizhu area) is the most stable and unique composite foreland basin. It maintained a good basin–mountain coupling relationship during the late orogenic period, which resulted in the complete sealing of the gas system and stability of the preservation system. The significant differences between the Sichuan Basin and other

foreland basins in the south are the weak reconstruction and damage caused by late orogenic movement as well as excellent preservation conditions in the late period. Therefore, the Sichuan Basin has become the largest industrial gas region with respect to the Paleozoic and Mesozoic marine deposits in South China. The tectonic stability is the primary cause of the excellent preservation conditions in the Sichuan Basin.

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The continuous hydrocarbon preservation unit has good vertical sealing conditions, with effective regional cap rock as the ultimate stratum of vertical gas migration, which also leads to natural gas accumulation in the underlying adjacent reservoirs without escaping. However, horizontally, it might be affected by surrounding uplift, fault belts, adjacent strata outcrops, and hydraulic heads of the water supply and discharge area such as cross flow. In addition to the Sichuan Basin in South China, several other areas are characterized by stable tectonics such as northwestern or central Guizhou as well as its surrounding areas (Fig. 5.7). Tian et al. (2004) compared the geological conditions of hydrocarbon accumulations in Majiang, which is a paleo-reservoir, and considered that the damage effects of northwestern Guizhou by the Yanshanian movement are small, while up-and-down movement primarily occurred during the Himalayan period. Therefore, the gentle folds, weak fault activities, and gentle stratum occurrences in northwestern Guizhou result in the preservation of primary oil and gas pools that formed in the Indo-China period and before. Because oil and gas seepage is rarely observed on the ground, the current infiltration depth of ground freshwater cannot reach and significantly damage the deep primary reservoirs. The integrated analysis of various data revealed that primary reservoirs that formed in Indo-China period and before probably still exist in the northwestern areas of Guizhou.

not good due to its intricate hydrogeological environment; when tectonic activities destroy the primary hydrocarbon system, a new preservation condition is simultaneously reconstructed in the major part of the fault depression.

5.2.3.2 Reconstructive Hydrocarbon Preservation Unit The reconstructive hydrocarbon preservation unit is a sealing system of hydrocarbon formation and preservation reconstructed after the overlapping of the Mesozoic and Neozoic basins in the late period. After the formation of the marine hydrocarbon system, the system underwent a period of thrust fold, uplift, and erosion, and damages to different degrees. Subsequently, it was overlain by a set of new regional cap rock, which led to the reconstruction of the sealing conditions necessary for hydrocarbon preservation. Nonetheless, the earlier hydrocarbon partially or completely escaped and only that generated or accumulated in the late period remained. Areas, such as the Gourong–Haian thrust fault zone, including the Huangqiao CO2 gas field, and the South Jianghan Basin thrust fault zone with Upper Cretaceous– Paleogene–Neogene regional cap rocks in the Middle and Lower Yangtze area have the following preservation characteristics: a separate hydrocarbon sealing system with extra pressure was formed by Mesozoic and Neozoic regional cap rocks; the underlying marine strata have lost the sealing system, with extra pressure resulting from tectonic uplift and erosion; and the salinity of the stratum water is decreasing. The preservation conditions of the reconstructive hydrocarbon preservation unit are not as good as that of the continuous one. The general hydrogeological conditions are

5.2.3.3 Residual Hydrocarbon Preservation Unit The residual hydrocarbon preservation unit is defined as the unit in which most regional cap rocks were eroded due to strong reconstruction by the Mesozoic and Neozoic tectonic movements, the original hydrocarbon-bearing system was largely uplifted above the erosion and sedimentation base levels, and the destructive degree of the original hydrocarbon system depends on the erosion in different degrees. It includes a set of regional cap rock exhibiting strong tectonic deformation and diagenesis, no extra pressure, and formation water of transitional type. The former deeply buried regional cap rocks are broken due to fold uplifting in the Yanshanian period. Only deep zones far away from faults might still exhibit good preservation conditions. The western Hunan and Jiangxi fault zone in the middle Yangtze area is well developed and includes 217 faults extending over more than 10 km. Most of the faults were simultaneously formed by orogenic movement and folding in the Yanshanian period, while some that formed early show characteristics of multistage activities. The primary distribution areas of bitumen, gas seep, and hydrothermal activities are around the fault zone, which also indicates that faults represent one of the major pathways of fluid migration and dissipation. 5.2.3.4 Retained Hydrocarbon Preservation Unit The retained hydrocarbon preservation unit refers to a unit in which the basin was uplifted and eroded after the formation of the hydrocarbon sealing and preservation system and the buried depth is moderate such as the Nanpanjiang Depression whose regional cap rocks are the Middle and Lower Triassic strata. The current whole sealing conditions of the hydrocarbon preservation unit depend on the original retained degree of the hydrocarbon sealing conditions. In the case of retained hydrocarbon preservation units, the hydrogeological conditions are generally poor, but the existence of a partially closed water chemical environment is not excluded. In particular, the late structural changes have a destructive effect on the preservation of gas reservoirs. 5.2.3.5 Nappe Hydrocarbon Preservation Unit The nappe hydrocarbon preservation unit is a local three-dimensional sealing preservation system that formed by nappe tectonic activities, for example, in the Longmenshan, Dabashan, Xuefengshan, and other large Piedmont nappe structural belts. However, the footwall of the nappe structures above, fundamentally belonging to the parautochthonous system, have great exploration potential.

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5 Regional Cap Rock and Hydrocarbon Preservation

Fangshen 1

SE T P  C Z

Dafang Anticlinal belt

Lizichong Syncline belt

Northern Guizhou Depression

Central Guizhou Uplift SE

Qianxi T P  C Z Central Guizhou Uplift

Lizichong Syncline belt

Qingzhen C P C

Lizichong Syncline belt

C

P

C  C

Z

Z

Zhijin Salient

Central Guizhou Uplift

SE T P  C Z Anshun wide Syncline Southern Guizhou Depression

Fig. 5.7 Geological structure of the Central Guizhou Uplift (Extending over more than 100 km from well Fangshen1 to the Guiyang airport in the three connected profiles)

5.2.3.6 Fragmented Hydrocarbon Preservation Unit The formed hydrocarbon system was cut or separated by thrust faults or strike-slip faults into several faulted blocks. Because of the uneven erosion during differentiated uplifting, the original hydrocarbon system was fragmented or staggered into many residual hydrocarbon systems with different scales such as the Lanping–Simao Basin.

5.2.4 Evaluation of the Preservation Conditions of Marine Deposits in the Mesozoic and Paleozoic Region (Basin) in South China Based on the combination of various characteristics, a fundamental evaluation of the preservation conditions of marine Mesozoic and Paleozoic blocks (basins) in South China was performed, except for the Sichuan Basin.

5.2.4.1 Type I Preservation Unit The preservation unit of type I has good sealing and preservation capabilities, industrial hydrocarbon accumulations, and might form reserves. The two typical preservation units are the Fangxi and Shizhu units in the west of the Qiyueshan anticline belt in western Jiangxi and eastern Chongqing. After the formation of the hydrocarbon system, the continuously deposited regional cap rocks of the Permian, Middle–Lower Triassic, and Upper Triassic–Jurassic had the complete preservation and sealing conditions, and belonged to the continuous preservation unit. The weak tectonic activities during the late Yanshan–Himalayan period led to a series of blocking anticline zones, which protected the original marine hydrocarbon-bearing system. Taking the Eastern Sichuan structural belt as an example, its east extension part is known as an industrial hydrocarbon exploration block. The high-production gas fields such as Dachigan exist in the west, and the Jiannan gas field was discovered in the east.

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5.2.4.2 Type II Preservation Unit Although the preservation unit of type II has sealing capabilities, the geological conditions are complex, making further studies of this type of unit necessary such as the Yancheng–Xiaohai–Haian, Huangqiao–Qutang, and Gourong–Nanling units in the Subei Basin; the depression in the south of the Jianghan Basin; Yunlong–Fawo, Dongshan– Gaoqiao, and Heijing–Molding units in the east of the Chuxiong Basin; as well as the Lichuan unit in the Yudong– Exi blocks.

small basin groups due to rifting, faulting, and depression. Thus, for Paleozoic hydrocarbon exploration, original hydrocarbon accumulation might be the targets in seeking proper buried-depth basins, while buried hill reservoirs might be probed at the edge (or in the deep) of the basin. Therefore, the basin should be the research unit of marine cap rocks in North China. The detailed cap rock distribution is discussed below (Yang et al. 2010).

5.2.4.3 Type III Preservation Unit The preservation unit of type III has no sealing capability because of later reformation. However, partial or larger scale sealing capabilities might exist due to the inhomogeneity of the later reformation. Such preservation units include the Yanfeng–Yongren, Mixing–Xintian, and Sanguozhuang– Hedong units in the north of the Chuxiong Basin; Ningming–Nanping and Dingxi–Xintang units in the Shiwandashan Basin; and Yangba–Lucheng unit in the Yangba block. 5.2.4.4 Type IV Preservation Unit The preservation unit of type IV has all sealing capabilities. However, due to the inhomogeneity of the inner basin structure, local sealing capabilities and thus hydrocarbon prospects might still exist. Such preservation units include the Simao Depression and western Hunan and Jiangxi blocks. Because of the extremely complex geological conditions, the exploration risk of this preservation unit type (such as the Simao Depression) is great.

5.3

Preservation Conditions of Marine Hydrocarbons in North China

5.3.1.1 Cap Rock Conditions of the Paleozoic Strata The Lower Paleozoic contains mainly two sets of (regional) cap rocks with the dominant lithology of tight carbonate and gypsum. In the Upper Paleozoic, various cap rocks primarily consisting of aluminous rocks, bauxitic mudstone, mudstone, coal, and gypsum occur in each stratum. (1) Lower Paleozoic The upper parts of the Majiagou and Fengfeng Formations in the Ordovician of Lower Paleozoic in the Ordos area contain tight carbonate and gypsum deposits, which are the cap rocks of the lower parts. The gypsum in the Majiazhou Formation mainly occurs in the eastern area and plays a role in lateral sealing. A set of 20–100 m thick gypsum exists in the Majiazhou Formation of the Ordovician in the Lower Paleozoic in the Bohai Bay region, primarily in the Linqing, southwestern Jiyang, and Dongpu depressions. The lagoon gypsum, usually 5–30 m thick, can be observed in the east of the Linqing–Huimin area, mainly around Tangyi–Liaocheng. The gypsum, salt rock, or gypsum-containing deposits lead to good sealing conditions in combination with local mudstone and marl in the Lower Paleozoic due to the increasing plasticity with increased buried depth.

5.3.1 Cap Rock Type and Distribution

(2) Upper Paleozoic

The marine–continental alternating deposits in the Upper Paleozoic are the regional cap rock of marine hydrocarbons in North China, except the Mesoproterozoic and Neoproterozoic, which are primarily developed in the Yanshan and Taihang Mountains in the north of North China. The Ordos Basin is a special area, which is particularly favorable for hydrocarbon generation and preservation. In its major part, the Mesozoic and Neozoic are extremely stable, almost without suffering from any reformation and destruction by tectonic activities, and the formation dip is almost less than 1°. The Yanshanian and Himalayan tectonic movements in the east of North China are stronger than those in the Yangtze area, which resulted in several independent big and

The pervasive aluminous rock at the bottom of the Benxi Formation is the significant regional cap rock of the Lower Paleozoic in North China. This cap rock formed by ferruginous and aluminous mudstone with a thickness of 30–70 m. It is primarily distributed in the central and eastern part of the Ordos Basin, directly overlying the Ordovician weathering crust. It is the regional cap rock of the large Ordovician gas fields in Jingbian. This cap rock can also be widely observed in the south of North China and the Bohai Bay region. In the Bohai Bay region, the major lithology comprises bauxite, aluminous mudstone, and dark mudstone, with a common thickness of 5–10 m (maximum thickness of 20 m). Affected by the strata erosion and original depositional environment, the

148

remaining bauxite thickness is relatively larger along the east of the Huanghua and Linqing Subbasins and smaller in the Jiyang and Dongpu Depression ( 1.6%) such that the source rocks still have a good gas generation and accumulation potential. The pyrolysis gas of dispersed liquid hydrocarbons from source rocks in marine superimposed basins is therefore considered to be an important natural gas source (Zhao et al. 2005, 2011; Song et al. 2012). Recently, observations of pores of organic-rich shale reservoirs in the Wufeng–Longmaxi Formation of the Sichuan Basin showed that (Ma et al. 2018) the organic matter pores that formed during thermal evolution of organic matter are not only developed in kerogen, but many organic matter pores are also developed in solid bitumen. The secondary organic matter pore development is heterogeneous. In the shale of the Wufeng–Longmaxi Formation, organic matter pores are concentrated in solid bitumen and hydrogen-rich lipid organic matter. The organic matter-rich shale of the Wufeng–Longmaxi Formation is in the dry gas evolution stage (Ro value 2.2–3.06%, average *2.5%). During the thermal evolution, it has undergone a complex process of organic matter generation of oil, oil cracking into gas, direct gas generation of kerogen, and asphalt pyrolysis to gas. From a microscopic point of view, it has “multihydrocarbon supply” characteristics. In summary, based on the analysis of the source rock hydrocarbon generation history, bitumen pyrolysis simulation experiments, and

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Fig. 6.3 Simulation of the asphalt formation in the Puguang gas field in the northeastern Sichuan Basin. Left: sample 1; right: sample 2

multiparameter geochemical analysis of the discovered oil and gas, the multistage structural superposition in China’s superimposed basin controls the multistage hydrocarbon generation of multiple parent materials. This process differs from the direct thermal degradation of oil and gas from kerogen in basins with a single structural cycle. This proves that China’s marine facies have abundant hydrocarbon sources and great exploration potentials.

6.1.4 Three-Element Controlling Reservoir It is revealed by statistical study conducted by Ehrenberg and Nadeau (2005), Ehrenberg et al. (2006) that the relationship between the porosity and depth of clastic rocks and carbonate reservoirs worldwide has rules as follows: (1) regardless clastic or carbonate rocks, the deeper the burial depth is, the smaller is the porosity. Based on statistics, the porosity (P50) decreases by 1–3% per 1 km increase in the rock depth. At the same depth, the older the rock is, the smaller is the porosity is. The porosity (P50) decreases by 1–2% per every million years of the geological age of the rock; (2) At the same depth, the porosity of carbonate rocks (P90, P50, and P10) is significantly smaller than that of

clastic rocks. Ehrenberg and Nadeau (2005) believed that the rock pore filling notably increases with increasing depth compared with dissolution. Burial dissolution occurs, but the effect of burial dissolution on the porosity in deep reservoirs is insignificant; and (3) Carbonate rocks with a porosity of 0–8% have better exploration prospects than clastic rocks, which is due fractures. Recently, based on the oil and gas exploration in China’s deep–ultra-deep carbonate rocks, billion-ton oil and gas fields, such as the Tahe, Tazhong, Puguang, and Yuanba fields, were discovered. These oil and gas fields are old reservoirs characterized by deep burial, complex diagenesis, strong heterogeneity, and development of various types of reservoirs. The development of effective reservoirs is not notably controlled by the depth. Taking the Puguang gas field in the Sichuan Basin as an example (Ma et al. 2010), 300 core borehole samples from a depth of 5000–5200 m were analyzed using Ehrenberg’s (2005) global carbonate rock porosity statistical method. The porosity of the Puguang gas field is much higher than the global carbonate rock porosity at the same depth (Fig. 6.4). The Yuanba gas field has an average and porosity of 5.18% and a maximum porosity of 23.59% in the reef–shoal facies dolomite reservoir at an average depth of 6600 m. A good

Sample 2 (Puguang 2 well, 4958.01– 4967.51 m)

895.67 1747.74

500

550

679.94 1533.98 1982.50 3941.12 10625.00

350

400

450

500

550

0.00

507.71

450

Original sample

74.42 291.67

0.00

Total gas (m3/t C)

400

Original sample

Sample 1 (Puguang 2 well, 4977.11– 4984.94 m)

Ro (%)

350

Simulated temperature (°C)

Sample name

7433.98

2451.51

785.97

557.25

186.36

0.00

969.54

348.40

137.30

101.68

32.39

0.00

CO2 (m3/t)

700.95

483.54

505.93

561.77

200.15

0.00

116.07

79.27

73.70

73.85

19.58

0.00

H2 (m3/t C)

521.70

490.91

352.19

164.85

29.00

0.00

446.62

393.82

234.87

85.38

8.26

0.00

Hydrocarbon gas (m3/t C)

468.33

482.15

425.39

233.69

35.65

0.00

388.80

384.41

310.79

135.27

10.44

0.00

Hydrocarbon gas (kg/t C)

53.64

75.93

79.15

303.73

215.18

0.00

25.59

19.66

41.40

53.51

56.45

0.00

Condensate (kg/t C)

47.84

63.10

67.83

55.19

64.24

0.00

9.58

8.73

13.91

24.35

125.12

0.00

Light oil (kg/t C)

101.48

139.03

146.98

358.91

279.41

0.00

35.16

28.39

55.30

77.87

181.58

0.00

Draining oil (kg/t C)

Table 6.1 Gas and liquid hydrocarbon yields in different evolution stages of bitumen in the Puguang gas field in the northeastern Sichuan Basin

8.31

3.02

9.84

8.90

13.61

1402.45

1.43

1.19

2.65

3.13

109.55

747.84

Residual oil (kg/t C)

109.78

142.05

156.82

367.81

293.02

1402.45

36.59

29.58

57.95

80.99

291.13

747.84

Total oil (kg/t C)

578.12

624.20

582.21

601.50

328.67

1402.45

425.39

413.99

368.74

216.26

301.57

747.84

Total hydrocarbon production (kg/t C)

6.1 The Particularity of Oil and Gas Accumulation in Marine Strata in China 165

166

6

Reservoir Type and Spatial Distribution

6.1.4.1 The Depositional-Diagenetic Environment Controls the Early Pore Development

(1) The early depositional environment controls the reservoir distribution and scale

Fig. 6.4 Average porosity versus depth for global petroleum carbonate reservoirs (modified from Ehrenberg and Nadeau 2005)

dolomite reservoir was discovered in Tashen-1 well in the northern Tarim Basin at a depth of 8400 m. The reservoir space includes intercrystalline pores, structurally selective intercrystalline dissolution pores closely related to dissolution, selective dissolution pores, and high-angle and horizontal dissolution fractures (Meng et al. 2010). In a high-temperature and high-pressure environment, the temperature is >170 °C at a buried depth >8000 m and the pressure is >80 MPa. The development of dissolved pores, caves, fractures, and other reservoir space is rare worldwide, which also changes Chinese petroleum geologists’ understanding of the effective storage mechanism of ancient carbonate reservoirs. Based on the core and thin section observations, analyses of the porosity and permeability, and the electron microscopy and isotope analysis of the main boreholes in the Sichuan Basin, the formation of deep and ultra-deep high-quality reservoirs is controlled by early sedimentation, late tectonic transformation, and fluid–rock interaction during diagenesis. A “three-element controlling reservoir” theory has been proposed, that is, the depositional-diagenetic environment controls the early pore development, the tectonic-pressure coupling controls the fracture and dissolution, and the fluid–rock interaction controls the deep dissolution and pore preservation.

The difference in the vertical and lateral direction in different sedimentary environments controls the spatial morphological characteristics of carbonate sediments, such as reefs and carbonate sands, and the spatial geometric characteristics of the reservoirs. Based on the statistics of global carbonate fields, the reef–shoal and granular carbonates (carbonate sands) of different environments were divided into several groups according to its spatial geometry of reservoirs (Fig. 6.5). The comparison of the reservoir characteristics of the Yuanba and Puguang gas fields in the Sichuan Basin revealed that there are significant differences in the scale and distribution of the reef–shoal reservoirs due to the differences in the depositional environments of the two gas fields (Fig. 6.6). Drilling and regional seismic data revealed that the Changxing Formation in the Yuanba area located at the steep ramp margin of the west side of the Kaijiang–Liangping shelf. The seawater dynamics were relatively weak, resulting in the decrease in the growth speed of the reef in the Yuanba area. Bafflestone and binding reefs were mainly developed. The thickness of a single reef is small, with an average of 3.57 m. The reef aggraded vertically and laterally migrated, forming a multi-superposition distribution pattern of the single reef and reef body, over a wide range in the plane. The Puguang area is at the steep platform margin with a slope gradient of 15°. The seawater is highly dynamic and is dominated by framework and bafflestone reefs. The thickness of a single reef is relatively large, generally 4.68– 8.63 m. The reefs are mainly aggraded vertically, forming a barrier reef belt with NW–SE orientation. (2) The depositional environment controls the physical properties of the porous reservoir. Based on the statistics for the porous reservoirs in the main marine oil and gas fields in China, it is found that there is a close relationship between the early depositional environment and the reservoir physical properties. The best reservoirs in the Puguang and Yuaba gas fields in the Sichuan Basin are mainly developed in exposed shoals, tidal

6.1 The Particularity of Oil and Gas Accumulation in Marine Strata in China

167

Fig. 6.5 Morphological characteristics of reefs and granular carbonate rocks (carbonate sands) in different environments (after C&C Reservoirs)

Fig. 6.6 Sedimentary pattern of the Changxin–Feixianguan Formations in the Puguang and Yuanba area

channels, barrier rocks, and shoal facies with strong hydrodynamics and repeated erosion due to water flow. The reservoir of the Longwangmiao Formation in the Anyue gas field is mainly distributed in the granular shoal around the paleo-uplift. In the Ma51–Ma54 sub-members of the Majiagou Formation, that is, the main reservoir of the Jingbian gas field, the anhydrite-bearing dolomitic tidal flats represent the most favorable facies zone for the formation of dissolution pores in weathering crust, forming the mud– fine-crystalline penecontemporaneous anhydrite-bearing dolomite and soluble minerals such as anhydrite nodules,

which create favorable conditions for the formation of karst reservoirs. The development of the primary pores of carbonate rocks is controlled by the early depositional environment. It provided the conditions for the formation of dolomite through the interaction between the dolomitization fluid and rocks. Early dolomitization replaced the early pores. Under deep-burial conditions, it is easier to preserve dolomite compared with limestone and the dolomite has a better compaction resistance, which lays the foundation for the dissolution and preservation of high-porosity dolomite in deep-burial environments.

168

6.1.4.2 Structure–Pressure Coupling Controls Fracturing and Dissolution The tectonism controls the carbonate reservoirs on both the macro- and microscale. Microscopically, due to the relatively high brittleness of carbonate rocks, fractures are formed under the fault and fold activity. The deep and ultra-deep oil and gas fields that have been discovered are affected by strong tectonics and many oil and gas reservoirs in which fractures are the main reservoir space can be formed. For deep and ultra-deep oil and gas fields with pores as the main reservoir space, fractures play an important role in the formation and transformation of reservoir pores. First, the fracture itself can be used as storage space; and second, the fractures communicate with the internal reservoir space, which is conducive to underground fluids, especially unsaturated fluids, entering the reservoir for dolomization, dissolution, and other processes, thus further expanding the reservoir space. Macroscopically, tectonism controls the uplift and subsidence of the basin as well as the thermal history of the basin and dissolution and precipitation of carbonate rocks by fluids in the late diagenesis. A simulation showed that, the cementation (precipitation) of the carbonate rock and fluid notably increased with increasing formation temperature and pressure under closed conditions when the basin began to subside under tectonic action. When the tectonic action leads to the formation of faults and fractures, the deep-burial closed environment transitions into an open environment, causing the fluid to become unsaturated, resulting in dissolution. Because of the tectonic activity, the basin begins to rise, which causes the temperature of the hot fluid to continue to decrease and the fluid to become unsaturated. Subsequently, dissolution starts. Based on studies of the burial history of the Puguang and Yuanba gas fields, the depths of the two areas reached 8500 m in the Cretaceous, which was affected by the Late Yanshanian–Himalayan movement. The Puguang and Yuanba areas were uplifted by 2500–3700 m and 1000–1500 m, respectively. This is the reason for the difference in the thermal sulfate reduction (TSR) intensity in the deep-burial environment between the Puguang and Yuanba areas. 6.1.4.3 Fluid–Rock Interactions Control the Dissolution and Preservation of Pores Based on the statistics for the reservoir space types of deep and ultra-deep marine oil and gas reservoirs in China, the reservoir space is mainly dominated by secondary pores and fractures under multistage diagenesis and the original pore structure is filled to different degrees in the early stage; some of them have been completely filled. The alteration of pores by the diagenesis of carbonate rocks is a rock–fluid interaction process and a composite process of the dissolution of original carbonate mineral

6

Reservoir Type and Spatial Distribution

grains and formation of new carbonate mineral grains. The saturation of the mineral phases of carbonate rocks is determined by the chemical properties of the pore fluids, velocity of the flow in pores, and temperature and pressure conditions. When the fluid is undersaturated, the original mineral particles dissolve and the pores increase. When the fluid is supersaturated, new mineral particles crystallize and the pores decrease. As the buried depth of the rock changes from shallow to deep, the rock is dissolved by the fluids including the carbon dioxide in atmospheric water, organic acids generated by the decomposition of organic matter in the rock, and hydrocarbons and hydrogen sulfide formed by sulfate in the rock, which finally results in the formation of a high-quality deep carbonate reservoir. Before the stabilization of minerals in early buried carbonate strata, the dissolution is controlled by individual mineral particles, which leads to the formation of secondary dissolution pores with notable constitutive selectivities. For example, due to the action of atmospheric freshwater in the early burial stage, the original seawater fluid in the pores was replaced by atmospheric freshwater such that biological, oolitic, and other aragonite particles were dissolved, forming moldic pores. The dissolution after the stabilization of the minerals in the late buried carbonate strata is usually non-constitutive. In the buried diagenetic environment, most of the buried diagenetic fluids are in a supersaturated state. However, hydrocarbon maturation, thermal degradation, and the late supply of atmospheric freshwater under tectonic action may lead to the formation of erosive buried fluids, dissolution of carbonate rocks, and formation of many secondary pores. Schmidt and McDonald (1979), Moore (1989), Surdam et al. (1984), Mazzullo and Harris (1992) and other scholars have proven that the decarbonization of organic matter during the maturation process provides a large amount of CO2 and organic acids, which is conducive to dissolution and thus the increase of the pores. Based on studies in the Sichuan, Ordos, and Tarim Basins, Chinese scholars (Zhu et al. 1996; Tan et al. 1995; Fan et al. 2009; Cai et al. 2005) have also confirmed the effect of the dissolution by organic acids on carbonate rocks. Machel (2001), Ding et al. (2005), Hao et al. (2008) systematically summarized the characteristics of the TSR reaction and proposed different TSR stages and reaction types. It has been considered that TSR generally occurs in a high-temperature and deep-burial environment of 80– 100 °C–150–200 °C, with a Ro of 1.00–4.0 and buried depth of 2000–6000 m. Hill (1995) pointed out that there are two H2S dissolution mechanisms in reservoirs: (1) H2S reacts with oxygen-rich formation water to form sulfuric acid and the sulfuric acid dissolves to form dissolution pores; and (2) formation water with two different H2S concentrations

6.1 The Particularity of Oil and Gas Accumulation in Marine Strata in China

mixes to form water with a new H2S concentration. Because this new formation water is not saturated with carbonate, it has a strong dissolution effect on the reservoir. At present, it is widely accepted that H2S generated by TSR reaction reacts with alkali metal cations in the pore water to generate metal sulfide and dissociated H+, which combine with other acid–base ions to form many corrosive acids, dissolve, and form pores. If the number of cations is insufficient, H2S is also soluble in water forming hydrosulfuric acid, which is corrosive to carbonate rocks. Based on simulation experiments regarding the corrosion modification of carbonate reservoirs by hydrogen sulfide, Ma et al. (2007) proved that the porosity and permeability of the reservoir greatly improve by the dissolution of H2S; the porosity increases by 2%. The value is elevated by nearly two orders of magnitude.

6.1.5 Effective Preservation and Compound Accumulation The accumulation of oil and gas in the deep layers of the superimposed basin underwent a complex physicochemical process, which notably differs from the classic model of single-cycle accumulation (oil and gas accumulation through primary migration and secondary migration): (1) The fluid transport framework, paleostructure, and lithology–lithofacies changes at the peak of the hydrocarbon generation in source rocks overlap to form the paleostructure and lithologic trap, which control the formation and distribution of ancient oil and gas reservoirs; (2) The tectonic movement after the formation of the ancient oil–gas reservoir controls the chemical transformation and fluid adjustment of the reservoir; and (3) The neotectonic movement (late tectonic movement) and its controlled fluid transport system and lithology–lithofacies changes control the reaccumulation and final positioning of the oil and gas. This is another characteristic of oil and gas accumulation in old and multi-cycle superimposed marine basins. As discussed in Chap. 1, independent of how many tectonic changes a basin has undergone since its formation, as long as the strongest or last tectonic activity has not caused the loss of oil and gas, the oil and gas may still be preserved. Effective preservation and compound accumulation are the ultimate results of the simultaneous existence and mutual support of various source rock, reservoir, cap rock, trap, migration, and preservation elements. Based on the analysis of the anatomy of typical oil and gas reservoirs in the Sichuan, Ordos, and Tarim Basins, most oil and gas reservoirs have undergone multistage filling processes and structural transformations and adjustments during the formation. Based on geological process recovery and numerical simulations, Ma et al. (2005b, c, 2007a, b,

169

2010, 2014) confirmed three major formation stages for deep carbonate rock reservoirs in the northeastern Sichuan Basin, that is, the enrichment of natural gas in the initial formation stage of reservoir, chemical modification and adjustment of fluids, and enrichment in the positioning stage. The Puguang gas field formed in the late Indosinian–early Yanshanian period. The Permian source rocks entered the liquid window and the liquid hydrocarbons migrated to form a trap reservoir. During the middle and late Yanshanian period, continuous subsidence and deep-burial processes transformed the oil reservoir that formed in the early stage into a gas reservoir due to pyrolysis and pyrobitumen remained in the pores of the reservoir. At the same time, the source rock kerogen pyrolysis gas accumulated in the gas reservoir. In the late Yanshanian–Himalayan period, strong tectonic compression and uplifting changed the gas trap shape and led to gas migration to high pointsmigration, resulting in the adjustment and transformation of the gas reservoir and, finally, the formation of the current Puguang gas field. Zhou et al. (2006), Wang et al. (2011a, b), Yang et al. (2011) studied the geochemical indicators, that is, light hydrocarbons, biomarkers, and isotopes, of source rocks of the large reef–shoal complex gas condensate reservoirs of the Tazhong area and came to the following conclusions: The oil in the reef–shoal reservoirs in the Lianglitage Formation of the Tazhong oilfield is mainly derived from Middle–Upper Ordovician source rocks (mixed with the genesis of Cambrian source rocks). Natural gas mainly originates from Cambrian oil cracking and is filled inward along the fracture of the No. I slope break zone in Tazhong. The reservoir experienced three major hydrocarbon accumulation stages. The first stage is the late Caledonian hydrocarbon accumulation. The oil and gas originated from Cambrian–Lower Ordovician source rocks. The tectonic movement of the early Hercynian period caused damage to the reservoir. The second stage of accumulation is the late Hercynian period, which is also the main period of crude oil accumulation. The crude oil originated from the Middle– Upper Ordovician source rocks. The third stage of accumulation is the late Himalayan period. The rapid and deep burial in this area resulted in the formation of Cambrian crude oil cracking gas and the filling of shallow Ordovician reservoirs along deep faults, which led to the reduction in the oil density in the reservoirs and the increase in the gas–oil ratio, thus forming gas condensate reservoirs. Based on the hydrocarbon generation and burial histories of the Ordos Basin (Yang and Bao 2011; Yang et al. 2013), at least two phases of filling occurred in the Jingbian gas field, that is, at the end of the Late Triassic and at the end of the Early Cretaceous. The peak period of hydrocarbon expulsion started at the end of the Early Cretaceous. At this time, the lithologic trap had been formed and the reservoir conditions were good. The critical accumulation period was

170

6

the end of the Early Cretaceous. The Paleogene tectonic reversal event stopped the hydrocarbon generation and the adjustment period started.

6.2

Oil and Gas Enrichment and Distribution

6.2.1 The Tectonic Evolution Controls the Development of the Prototype Basin and Its Superimposed Structure and also Controls the Distribution of the Reservoir–Cap Combination 6.2.1.1 The Prototype Basin Controls the Structural–Depositional Environment and the Development of Different Source–Reservoir Combinations in Different Periods During the Sinian and Paleozoic marine depositional periods, the source rocks generally developed well in the passive continental marginal basin and intracratonic depression basin due to tectonic–sedimentary differentiation. The platform margin contains a well-developed reservoir and provides favorable conditions for the formation of large oil and gas fields. In the early stage of the evolution of the passive continental marginal basin, hydrocarbon source rocks mainly developed in undercompensated basins and rift of the cratonic marginal depression, continental recession rifts, and shallow and deep ramps such as the Lower Cambrian of the Tarim Basin. In the late stage of its evolution, the gentle-slope ramp evolved into the rimmed platform. When the rimmed platform was submerged, a gentle carbonate ramp with a steep distal end developed, while hydrocarbon source rocks developed at the deep gentle ramp such as the Upper Cambrian–Lower Ordovician in the Tarim Basin. The intracratonic depression basin developed on the paleo-cratonic basement or broad carbonate platform. When large-scale transgression occurred, source rocks with high organic matter concentrations often developed in the intra-craton depression basin such as the argillaceous carbonate source rocks of the Middle Cambrian gypsum-salt rock combination in the central and western Tarim Basin, shale source rock of the Middle–Upper Ordovician Saergan Formation in Keping–Awati in the western Tarim Basin, and gentle-ramp limestone source rocks of the Lower Silurian Shiniulan Formation in the southern Sichuan Basin (Zhang et al. 2005). (1) Yangtze Craton and adjacent areas In the Yangtze Craton and adjacent areas, the marine sedimentary basins are mainly continental marginal rift basins, intra-craton depression basins, passive continental marginal

Reservoir Type and Spatial Distribution

basins, paleo-rift or rift trough basins, residual basins, foreland basins, and flexing basins. The Paleozoic source rocks (including the Middle Paleozoic–Proterozoic) in the Yangtze area mainly comprise black and dark carbonaceous shale and graptolite shale and mudstone and are distributed in the Upper Sinian and Lower Cambrian, Lower Ordovician, Upper Ordovician and Lower Silurian, Permian, and Triassic. The reservoir rocks are mainly controlled by the platform and slope facies. The main rock types are microcrystalline dolomite, medium- to fine-crystalline dolomite, medium- to coarse-grained dolomite, granular carbonate rock, and contourite such as siltstone and sandstone. Throughout the whole Caledonian period, four sets of oil– gas-bearing source–reservoir–cap rock associations were widely distributed. The “four histories” (basin burial history, structural evolution history, sediment filling history, oil and gas evolution history) relationship is well defined. Hercynian (and Indosinian) source rocks developed in different periods and there are many types of reservoir rocks and related sedimentary facies. They provided excellent conditions for the formation of large oil and gas fields such as the Puguang, Yuanba, and Tieshanpo gas fields in northeastern Sichuan. In addition, several large ancient oil and gas reservoirs, such as the Majiang and Yuhang–Taishan ancient oil and gas reservoirs, indicate that large-scale oil and gas reservoirs have formed in the geological history and that similar oil and gas reservoirs may be preserved in areas with relatively weak tectonic activity and relatively good preservation conditions. Except for the vast southern marine areas outside the Sichuan Basin, no substantial breakthroughs have been achieved. Only a few small oil and gas fields have been discovered, such as the Jiannan gas field in the eastern part of western Hubei, Huangqiao CO2 gas field, and Zhujiadun gas field in the lower Yangtze area. Note that a wide range of favorable conservation areas with relatively weak tectonic activities and relatively good preservation conditions were discovered in central Yunnan and its surrounding areas based on regional exploration. Preliminary evaluation suggested that the discovery of large gas fields similar to the Majiang paleo-reservoir (1 bio t of bitumen reserves) is possible. For the vast southern marine areas outside the Sichuan Basin, the preservation conditions, which are directly controlled by the tectonic activity and evolution, are the key issue. Marine oil and gas exploration in southern China is closely related to the basin properties and tectonic evolution. For example, the folds and slight metamorphism of the Banxi Group may have a direct relationship with the evolution of the South China or Jiangnan Basins; Jinning movement (the second stage); and nature, scale, intensity, and influence of the Caledonian movement. From the perspective of paleogeography, the western Kangdian and eastern Cathaysian ancient lands controlled the ancient

6.2 Oil and Gas Enrichment and Distribution

geography of southern China from the Sinian period to the Ordovician. Therefore, carbonate rocks are developed in the Yangtze region, clastic rocks are developed in the Cathaysia and Jiangnan regions, and the South China Basin is in a transitional state in the middle. Although several local or short-term land developments occurred in this period, the paleogeographic pattern remained largely unchanged. It is worth pointing out that the differentiation of the Late Permian and Early Triassic southern tectonic pattern, paleogeographic pattern, paleogeographic unit, and sedimentary facies belt was favorable for the development of dolomitic rock, reef or shoal sedimentary units, or sedimentary microfacies and provided the environmental conditions for the formation and later evolution of reservoirs. At present, the Puguang and Yuanba gas fields discovered in the northeastern Sichuan region are dominated by dolomite, reefs, or shoals. (2) North China Craton Marine sedimentary basins in the North China Craton are mainly composed of intracratonic depression basins, paleo-rift or aulacogen basins, and compressional flexural basins. Although the Meso–Neoproterozoic in this area is old and unevenly distributed, it is often thick in local areas and has a certain oil and gas potential. For example, in the eastern region of the North China Craton, a large amount of Meso–Neoproterozoic oil seepage, bitumen, and crystal liquid oil seepage was found in northern Hebei (Shuangdong anticline) and western Liaoning (Chaoyang region). Previous studies showed that there may be a set of original oil and gas reservoirs in the Bohai Bay Basin and that the northern part of the Cangxian Uplift is key area for the exploration of such oil and gas reservoirs. In the North China Craton, large oil and gas fields have been discovered in the buried hills of the Ordos and Bohai Bay Basins. However, significant exploration of Paleozoic (including Meso–Neoproterozoic) primary reservoirs in the vast Paleozoic marine basins in the central and eastern regions has not led to substantial progress. The Lower Paleozoic (Cambrian and Ordovician) is the main strata for the exploration of marine carbonate reservoirs in this area. It has the basic conditions for the formation of primary oil and gas reservoirs. The buried hill reservoirs, such as Renqiu oilfield, Jizhong buried hill oil and gas reservoir, and Jiyang Depression buried hill oil and gas reservoir, are more important in this region. Many oil seepages and bitumen were found in the Ordovician and Cambrian systems in the Yanliao, Shanxi, Henan, and Huainan areas in the north of North China. Whether the primary oil and gas in the Lower Paleozoic can be preserved and the cap rock conditions are key issues of the exploration of such primary oil and gas

171

reservoirs. In general, the overlying Carboniferous and Permian mud rock sections can be used as regional cap rocks. For example, the Carboniferous and Permian serve as cap rock in the Zhuangxi buried hill gas field in the Shengli oilfield. At the same time, the Lower Paleozoic interior also has indirect cover layers such as a gypsum interlayer and shale layer. The reservoir space mainly comprises diagenetic fractures and dissolution pores. The erosion and weathering caused by three uplifts, that is, that of the top surfaces of the Fujunshan Formation (Changping Uplift), Liangjiashan Formation (Huaiyuan Uplift), and Middle Ordovician (Caledonian Uplift), form reservoirs with well-developed fractures and cavities. In addition, tectonic fissures formed by block faulting and folding in the Indosinian, Yanshanian, and Himalayan periods are also important factors affecting the reservoir conditions. The huge reserves of Carboniferous and Permian coal in the Upper Paleozoic provided a huge material basis for the formation of coal-formed gas and coalbed methane and have good exploration prospects. (3) Tarim Craton The Tarim Basin is a complex superimposed and composite cratonic basin. The marine sedimentary basin types during its evolution mainly include cratonic marginal depression, intracratonic depression, paleo-rift or rift trough, residual, foreland, and compressional flexural basins. The complex tectonic pattern and long evolution history have led to the formation of rich and varied trap types, indicating a wide range of exploration fields. The Tarim Basin has three main hydrocarbon source layers, that is, the Cambrian–Ordovician, Carboniferous–Permian, and Triassic–Jurassic, including dark mudstone and dark limestone. The Cambrian–Ordovician is characterized by a large amount of hydrocarbon generation and a long history of hydrocarbon expulsion, with three hydrocarbon expulsion peaks, that is, in the Late Ordovician, Permian, and Neo-Tertiary. The hydrocarbon-bearing traps are mainly anticline traps. At present, high-yield industrial oil and gas layers have been found in nine sets of layers such as the Carboniferous, Triassic, Ordovician, and Tertiary. The oil and gas reservoirs have a large burial depth. The Tarim Basin has both deep buried high-quality clastic reservoirs and good carbonate weathering karst reservoirs. The Ordovician and Carboniferous are the main exploration targets. The regional cap rocks in this area are the gypsum-salt rock and mudstone layers of the Carboniferous system. The central coal system of the Jurassic and geological mudstone layers of the Lower Tertiary are also important cap rocks. The Tarim Basin contains four sets of reservoir and cap combinations, which are the Cambrian–Ordovician buried hill inner reservoir and cap combination, the Carboniferous and underlying strata

172

reservoir and cap combination, the Jurassic and underlying strata reservoir and cap combination, and the Tertiary reservoir and cap combination. Based on the latest resource evaluation results, the resources of the Tarim Basin are 19.1 bio t including 10.7 bio t oil and 8.4 trio m3 natural gas.

6.2.1.2 The Superposition Compound of Prototype Basins Determines the Distribution of China’s Marine Oil and Gas Areas During the Phanerozoic period, the three major global dynamic systems of the Paleo-Asian Ocean, Tethys–Ancient Pacific & Indian Ocean, and Pacific Ocean intersected with each other and this makes the same zone experienced different dynamic systems in different tectonic cycles and tectonic stages. Thus, a sedimentary basin with a multi-cycle superimposed structure formed. The Junggar, Tarim, and Turpan–Hami basins in northwestern China are multi-cycle superimposed basins that formed after the hercynian orogeny. The post-hercynian sediments in the Tarim Basin are superimposed on the Sinian–Paleozoic sedimentary cap rock. The Himalayan orogeny is responsible for the latest tectonics–geomorphology of these basins. The Sichuan and Ordos basins in central China are multi-cycle superimposed basins that developed after the Indosinian orogeny on the Sinian–Paleozoic sedimentary cap rock. During the Indosinian period, they were the piedmont basins of the Qilian, Qinling, and Songpan– Ganzi Indosinian orogenic belt. At the eastern margin, the littoral Pacific Ocean underwent folding during the Yanshanian orogeny from the Late Jurassic to the Early Cretaceous. At the western margin of the basin, strong overthrusting–thrusting and gravitational sliding occurred during the Himalayan orogeny, which concealed the basin margin under the adjacent orogenic belt. The Songliao, Hehuai, Jianghan, Northern Jiangsu, and South Yellow Sea basins in eastern China are rift basins that formed after the Yanshanian orogeny. The Bohai Bay Basin is a Cenozoic rift basin. The strata underlying these basins in eastern China are often covered with residual Mesozoic and Paleozoic basins. The Paleozoic craton basin formed, with the Tarim, North China, and Yangtze plates as the core. In the Mesozoic, continental sedimentary basins that extended from north to south and from east to west formed on the basement of several small continental blocks and were separated by several orogenic belts that formed during the Hercynian– Indosinian movement. In the Cenozoic, a regenerative foreland basin was formed on the edge of the ancient craton, which was controlled by the giant basin–mountain system of the Qinghai–Tibet Plateau in the west, and a rift basin group was formed by the subduction of the Pacific Plate and the extension of the arc. The three tectonic domains control the

6

Reservoir Type and Spatial Distribution

formation of three types of superimposed basins and passive continental margin rift basins. Controlled by the basin basement, tectonic environment, and geodynamic evolution, China’s sedimentary basins mainly comprise three types of superimposed geological structures (He et al. 2010) (Table 6.2): (1) Foreland–craton superimposed basins: Examples are the Tarim, Junggar, Ordos, Sichuan, and other basins. They are large superimposed composite basins composed of Paleozoic marine craton and Meso–Cenozoic continental foreland basins. The Tarim, Ordos, and Sichuan basins developed on the Precambrian craton. The Junggar and Turpan–Hami Basins developed on the Precarboniferous composite basement. The regional unconformity interface of the craton sequence is the main superposition interface of the prototype basin. (2) Depression/rift superimposed basins: An example is the Songliao Basin. In the Late Jurassic–Early Cretaceous (J3–K1y), a rift basin developed; in the Early Cretaceous–Late Cretaceous (K1d–K2), a depression basin developed; at the end of the Late Cretaceous (K2s– K2m), the basin was reversed and placanticline of Daqing was formed; and the subsidence continued in the Cenozoic. The basins in each period are bounded by regional unconformity. The volcanic fault rocks are dominated by natural gas accumulation. The sequence of the depression is characterized by crude oil accumulation, forming the large Daqing oilfield. Basins such as the Pearl River Estuary, Beibu Gulf, and Qiongdongnan in the sea area belong to this type. (3) Rift–intracratonic depression superimposed basins: Examples are the Bohai Bay, Jianghan, Subei, and Donghai Sea basins. The Early Paleozoic craton platform depression contains marine sequences, the Late Paleozoic craton depression contains marine and continental transitional sequences, the Mesozoic craton comprises intermountain continental sequences, and the Cenozoic craton contains fault depression sequences. Fault depressions represent the main oil-bearing area. The craton sedimentary sequence has a certain hydrocarbon potential. Based on the relationship between the hydrocarbon-bearing and tectonic units and the effects of three tectonic domains on the basin types and combinations, six major oil-bearing areas can be divided from west to east. In the western part, mainly the Northwest China and Qinghai–Tibet oil and gas areas developed. The central part mainly contains the North and South China oil and gas areas. The eastern part mainly comprises the Northeast China Sea area (e.g., Bohai, Yellow Sea, and South China Sea oil and

6.2 Oil and Gas Enrichment and Distribution

173

Table 6.2 Classification of China’s superimposed basins Basement

Underlying prototype basin

Superimposed prototype basin

Superimposed interface

Key structural transition period

Type of basin

Examples

Precambrian craton

Z-D2 marine basin, D3-T marine–continental and continental basin

J-Q continental facies basin

S/O D3/D2 J/T

Late Caledonian Early Hercynia Late Indosinian

Foreland– craton

Tarim

2-S marine basin C-T2 marine basin

T3-Q continental basin

C/S T3/T2

Late Caledonian Late Indosinian

Sichuan

2-O2 marine basin, C2-T2 marine–continental and continental basin

T3-Q continental basin

C2/O T3/T2

Late Caledonian Late Indosinian

Ordos

Precarboniferous composite basement

C-P1 marine–continental basin, P2-T continental basin

J-Q continental basin

J/T

Late Indosinian

Junggar

Hercynian fold basement

J3-K11 Fault depression lake basin volcanic series

K12-Q depression lake basin

K11/k12

Late Yanshanian

Depression– fault depression

Songliao

Precambrian craton

2-O2 marine basin, C2-P marine–continental basin, T-K continental basin

E Fault depression lake basin N-Q depression lake basin

C/O K2/K1 E/K

Late Caledonian Late Yanshanian Late Yanshanian

Fault depression– intracratonic depression

Bohai Bay

gas areas) oil and gas areas (Fig. 6.7). The marine sedimentary basins in China are mainly superimposed basins of forelands/cratons and rift/intercraton depressions. The Northwest China, North China, and South China oil and gas areas are marine oil and gas distribution areas.

6.2.2 The Tectonic Basin Evolution Controls the Subsidence, Burial, Hydrocarbon Formation and Accumulation, and Hydrocarbon Accumulation Location Due to the long evolution history and frequent tectonic movements of China’s marine basins as well as the superposition and strong tectonic deformation of the continental basins in the later stage, the relationship between the tectonic evolution of the basin and the subsidence, burial, erosion, and maturity of the source rocks in thermal history is very complex (Fig. 6.8). These factors directly affect the hydrocarbon generation, migration, accumulation, preservation, and destruction in marine basins. For example, since the Lower Paleozoic Cambrian–Ordovician sedimentation, the

burial–thermal evolution of the Ordos Basin has experienced four stages: The first stage is the differential subsidence stage of the Cambrian–Ordovician during which the intracratonic depression and cratonic marginal depression basins developed. The basins suffered from slow and differential subsidence and received a set of marine sediments with different thicknesses and carbonate rocks from several hundred meters to more than 1000 m. The Early Ordovician basin has a depth of 70–700 m and is buried deep in Mizhi and Yanchi, forming two deep buried cores. The western and southern margins of the Central Ordovician continue to settle, resulting in different tectonic evolution zones in the hinterland of the basin and at the western and southern margins of the basin. The maximum buried depth at the western and southern margins is 1200 m and the maximum buried depth in the basin (taking well Yi 24 as an example) is 800 m. The formation temperature is 35–50 °C, the Ro value is 0.26–0.28%, and the marine source rocks in the whole area are in the immature stage. The second stage is the Late Ordovician–Early Carboniferous Uplift and denudation stage. Influenced by the

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Reservoir Type and Spatial Distribution

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Instructions: Data shortage in Taiwan province. Data shortage in the Hong Kong & Macao Special Administrative Regions. DistributionM apofOil  bearingSteamBasinsandMarineLargeOilandGASAreasinChina

Fig. 6.7 Distribution of oil–gas basins and marine strata in China

Caledonian movement, the interior of the basin and marginal area began to rise in the Late Ordovician. The Ordovician strata were subjected to different degrees of denudation. The

maximum erosion thickness was 200–500 m. Some organic matter was oxidized, retarding or even inhibiting the conversion of organic matter to hydrocarbon.

6.2 Oil and Gas Enrichment and Distribution

The third stage is the Middle and Late Carboniferous– Cretaceous equilibrium-differential settlement stage. In the Middle and Late Carboniferous, the subsidence of the basins continued. The early stage (Carboniferous–Permian) is characterized by equilibrium subsidence, while the late stage (Triassic–Cretaceous) is characterized by differential subsidence. At the end of the Permian, the Ordovician source rocks had a maximum depth of 800–1800 m. They subsided from north to south and were separated by the Qingyang Uplift, forming a “one shallow two deep areas” subsidence pattern centered in Mizhi and Tianshuipu. The ground temperature was 60–80 °C and Ro ranged from 0.38 to 0.64%. In the Early Triassic, the basin started to strongly subside, forming a regional “shallowing northward and deepen southward” subsidence pattern. The maximum buried depth was 2600–2800 m, the formation temperature was 100–110 °C, and the Ro value was 0.6–0.9%. The whole area entered the maturity stage. The Tongchuan–Hancheng area in the south of the basin and Shigouyi area in the western part of the basin have a higher degree of evolution (Ro = 0.8–0.95%). After the temporary uplift of the Indosinian movement and temporary pause of the thermal evolution, the basin continued to subside and the Cretaceous once again experienced severe settlement. At the end of the Early Cretaceous, the maximum buried depth of the Lower Paleozoic carbonate rocks reached 3500–4800 m and a buried depth center formed in Qing–Hua–Wu, with a formation temperature of 120–160 °C. A thermal evolution pattern with a ring-shaped distribution centered in Qingyang, Huachi, and Wuqi formed. Except for the northeastern part of the basin, which is a mature area and in the oil and gas stage, most of the basin is in the high–overmature stage and all enter a large number of gas generating stages. The fourth stage is the Late Cretaceous–Cenozoic relifting stage. After the Late Cretaceous, the basin was dramatically uplifted and subjected to different degrees of denudation. However, except for some areas, the Paleozoic marine source rocks in the basin were mostly buried underground and remained in the gas generation stage. In the Tarim Basin, the main source rocks of the Cambrian–Ordovician marine facies have greatly differing sedimentation, burial, erosion, and maturity histories due to the inconsistent tectonic evolution of different tectonic units. For example, based on the geological interpretation the seismic section EW-500, the burial, erosion, and maturity histories of the Cambrian–Ordovician source rocks in the central Manjaer dDpression are very different from those of the source rocks of the eastern Peacock River slope and the western Manjaer slope–platform due to the varying degrees of influence of the Early and Late Hercynian and Indosinian tectonic movements. In the central Manjaer Depression, the Cambrian–Ordovician was buried for a long time and only suffered from slight denudation. It was calculated that the

175

bottom of the Cambrian began to produce petroleum in the Middle Ordovician (460 Ma) in the deepest part of section EW-500 (*14,000 m deep) and entered the condensate and moisture stage at the end of the Ordovician. The top of the Ordovician began to produce petroleum in the Devonian (375 Ma) and the production ended at the beginning of the Carboniferous (355 Ma). Therefore, the oil generation period of the Cambrian–Ordovician source rocks in the center of Manjaer Depression lasted from the Middle Ordovician to Early Carboniferous. Toward the western slope of the Manjaer Depression, the burial depth of the source rock becomes shallower (*11,000 m in the bottom of the Cambrian). The Cambrian oil generation period lasted from the Ordovician (488 Ma) to Devonian (375 Ma). The oil production period at the top of the Ordovician ranged from the Silurian (429 Ma) to the Neogene (12 Ma). Based on the data of Zhongyi Zhou and others, the peak oil generation period in the area of the Manjaer Depression (wells Manxi 1 and Manshen 1) is the Caledonian period, roughly 330– 445 Ma; the peak oil generation period in the area west of Mangal (including the Tabei Uplift) is the Hercynian period, roughly 238–328 Ma. At the southeastern margin of the Yangtze Craton, the tectonic subsidence history curve from Sinian to Early Paleozoic reflects the tectonic dynamic evolution of the passive continental margin basin. The tectonic subsidence curve at the edge of the Upper Yangtze Craton reflects two distinct settlements from the Upper Yangtze slope to the basin area. One occurred from 700 to 800 Ma in the Early Sinian and the other occurred at *600 Ma between the Late Sinian and Early Cambrian. These two subsidences, representing the rift tension stage of the margin of the Yangtze Craton, especially the latter one, can be regarded as the mark of Pangaea’s disintegration. A large subsidence occurred from the Middle Cambrian to Early Ordovician, which was related to the development of the passive continental margin and thermal dissipation. At the platform margin, the tectonic subsidence transition is not notable due to the cratonic nature of the basement, but the thermal subsidence from Cambrian to Ordovician is more notable than in the slope zone. In the middle and lower Yangtze regions, the above-mentioned tectonic subsidence from 700 to 600 Ma is notable, in addition to an abrupt change of the tectonic subsidence between Ordovician and Silurian. The settlement has a relatively large range and the time interval is short. This is the result of the formation of the foreland basin and downward deflection under the action of structural compression, thrust, and load in the Yangtze marginal basin. In the southwestern part of the Sichuan Basin, the analysis of the subsidence burial–denudation and source rock maturation histories shows that the main source rocks of the Lower Cambrian in the marine area entered the oil generation threshold in the Early Devonian after the Silurian

176

6

Reservoir Type and Spatial Distribution

geological epoch tectonic stage

Caledonian

Hercynian

Indo-Chinese

Himalayan

Yanshan

burial history (m) hydrocarbon injuction diagenesis history diagenesis evnironment source rock evolution

Cambrian basin

penecontemporaneous- epidiagenetic shollow burial stage

sea water

fresh water

epidiagenetic stage

shollow - medium burial

burial fluids

mature

hydrocarbon injuction

hydrocarbon injuction undulatory burial - deep burial burial fluids

fresh

over mature

high mature mature

prematurity-low maturity prematurity

platform

high mature

over mature low maturity

mature

micritization

cementation

dissolution

recrystallization compection/ pressolution

dolomitization silification tectonic fracture weathered fracture pyritization

bitumen infilling

constructive diagenesis

destructive diagenesis

no effect on porosity

strong diagenesis

weak diagenesis

Fig. 6.8 Map of the tectonic movement, diagenetic evolution, and hydrocarbon accumulation of marine strata in China

regional cap rock was deposited. At this time, the burial depth was *3300 m and the burial temperature was *97.5 °C. The Caledonian movement caused the basin to uplift, the Devonian and Carboniferous strata were missing, and the main source rocks of the Lower Cambrian were pushed into the peak oil generation window until the Middle Permian. The oil generation process was completed in the Middle Triassic. In the Middle Jurassic, liquid hydrocarbons formed, migrated to reservoirs in the Lower Cambrian, and started to crack into natural gas. Thick Jurassic and Cretaceous deposits covered the Upper and Lower Cambrian source rocks and Sinian reservoirs,

characterized by the largest burial depth (*7790 m) and highest temperature (*210 °C) in the geological history. Subsequently, the uplift and denudation stage of the surface layer began. The methane gas stored in Sinian reservoirs may be the product of thermal cracking of liquid hydrocarbons. In the Nanpanjiang Depression, the Late Paleozoic marine basin originating from the Devonian had the characteristics of continental marginal rifting, forming a series of tectonic paleogeographic characteristic of “scattered platforms in basin”. It evolved into a large depression basin in the Early–Middle Triassic. Generally, the subsidence and

6.2 Oil and Gas Enrichment and Distribution

burial histories of different tectonic units in this area are very similar but, at the same time, show some differences. The burial depth and rate of the platform basin facies area adjacent to deep and large faults are higher than those of the horst or mound platform areas in the same period. Taking the subsidence–burial–erosion history curve of Yang well 1 in the Yangba sag as an example, there are two rapid subsidence and burial stages; one occurred in the Devonian and the other occurred in the Middle Triassic (the latter is more intense). The Carboniferous–Lower Permian between the two is characterized by a relatively moderate subsidence stage and burial rate and reflects a relatively quiet period of tectonic activity. The Dongwu movement at the end of the Middle Permian may be the most important sedimentary discontinuity and erosion event during the development and burial of the basin. After the main tectonic movement of the Indosinian in the Late Triassic, it began to suffer from multiple periods of extensive uplift and denudation; the late denudation generally ranged between 1000 and 3000 m. Due to the old sedimentary strata and long-term evolution in China’s marine sedimentary basins, characteristic of superimposed basin, intense deformation and erosion in the later. This led to a considerably complex thermal history of the marine basin, which complicates studies of the history of the source rock. Based on the geodynamic settings and evolution of this paleo-marine basin, a more accurate understanding of the paleothermal and source rock histories can be obtained. The marine sedimentary strata of the Paleozoic in central and western China are mainly distributed in the Tarim, Sichuan, and Ordos Basins, and are the main areas for the preservation of marine source rocks. The Paleozoic marine hydrocarbon accumulation has undergone multistage formation, transformation, and postformation (Fig. 6.8). Four accumulation models were established (Dou et al. 2004): (1) Early formation of heavy oil reservoirs an later destruction: For example, the Tarim Basin has an extensive distribution of asphalt sands in the Silurian, which have characteristics similar to steroid and terpane in oil sands of Tabei and Tazhong, indicating that they are all derived from Paleozoic source rocks. Silurian asphalt sands and bitumen parent materials are marine lower organisms with high maturity and significant migration characteristics, undergoing peroxidation and biodegradation. The main period of bitumen formation is the end of the Silurian (Late Caledonian movement) during which mainly the bitumen formed by the degradation of normal crude oil; (2) Early formation and later migration and accumulation of reservoirs: In the southern part of the Tabei Uplift, the Carboniferous oil and gas reservoirs in the Hadexun area are one-stage accumulation, formed in the Quaternary (Himalayan Movement), and similar to the Donghetang Carboniferous crude oil, the

177

Carboniferous crude oil in the Hadexun area is in good analogy to the Carboniferous crude oil in the Donghetang and Tazhong 4 well areas. It is the same oil source and comes from the Cambrian–Lower Ordovician marine muddy source rock. There may be primary ancient reservoirs beneath the Carboniferous reservoirs in this area, which originated from Cambrian–Lower Ordovician source rocks and whose maturity is at the peak of oil generation. However, the primary paleo-Carboniferous reservoirs in the Hadexun area were destroyed, migrated and adjusted, and then accumulated in the Carboniferous reservoirs, forming the present oil and gas reservoirs; (3) The oil reservoir that formed in the early stage is further cracked into a gas condensate reservoir or dry gas reservoir: As the depth of the burial increases after the formation of oil and gas reservoirs, the oil in the oil layer is further cracked, the specific gravity and sulfur content of the crude oil decrease, and the gas–oil ratio increases, eventually forming a dry gas reservoir and pyrobitumen. The dry gas formed by thermal alteration of oil and gas reservoirs is generally covered with pyrobitumen or bitumen, which precipitated in the pore throats and at the particle surfaces of the reservoir. Examples are the Paleozoic gas field in the Sichuan Basin and Hetianhe gas field in the Tarim Basin. During the Paleozoic history, the basin experienced a multi-cycle and extensive accumulation period, forming a series of reservoirs. Oil and gas migrated and were accumulated in the Upper Paleozoic. This indicates that the early Mesozoic tectonic–thermal events caused all Paleozoic reservoirs and source rocks to enter the high–overmature stage and the oil and gas in the reservoirs were thermally cracked to form the present dry gas reservoirs. Pyrobitumen is generally developed in the gas reservoirs. The distribution of today’s gas reservoirs is controlled by the source rocks and distribution of ancient reservoirs; and (4) Highly mature or overmature kerogen cracking into gas condensate or dry gas reservoirs: The results of thermal cracking experiments on kerogen and crude oil in a closed system showed that the composition and isotopic change of the primary cracking gas and crude cracking gas of kerogen differ. The C2/C3 ratio of the primary cracking gas of kerogen remains the same, while the C2/C3 ratio of crude cracking gas continuously increases. The change of the C1/C2 ratio is the opposite, that is, the C1/ C2 ratio of kerogen degradation gas gradually increases, while that of crude oil cracking gas remains unchanged. The natural gas fields in Lunnan, Sangtamu, eastern Jiefangqu, and Girak in the eastern part of the Tarim Uplift of the Tarim Basin contain kerogen cracking gas. The Ln (C2/C3) value of natural gas is generally 0–1.5% and only slightly changes. The Ln (C1/C2) value varies greatly (2.2–5.6%). These values are typical for kerogen cracking gas. These characteristics significantly differ from that of Hetianhe crude oil cracking gas.

178

6.2.3 Structural Paleo-Uplift Controls the Oil and Gas Migration Direction and Enrichment Zone The significance of the paleo-uplift to hydrocarbon accumulation can be explained using four aspects: the uplift in the depositional stage affects the development of the source– reservoir–cap rock association; the uplift in the accumulation stage restricts the transport and accumulation of oil and gas; the uplift during the adjustment stage affects the oil and gas redistribution; and the uplift during the positioning stage determines the final accumulation location of oil and gas (He et al. 2008).

6.2.3.1 Genesis of Tectonic Paleo-Uplift in Marine Basins During the tectonic evolution of marine sedimentary basins in China, tectonic paleo-uplift belts of different scales developed. In particular, paleo-uplifts develop on a large scale in marine cratonic basins (Ran et al. 1997; He et al. 2008). According to genesis, there are two main types of primary paleo-uplifts: paleo-uplift associated with plate divergence or regional extension and paleo-uplift associated with plate convergence or regional extrusion. The first type of paleo-uplifts includes the Huanxian–Qingyang–Huangling paleo-uplift, isolated platform of the Nanpanjiang Depression, and marginal platform in the Ordos Basin. The second type of paleo-uplifts includes the Tazhong and Tabei Uplifts in the Tarim Basin; Qiongzhong, Leshan–Longnusi, and Luzhou–Kaijiang paleo-uplifts in the middle and Upper Yangtze region; and the Jiangnan–Xuefeng paleo-uplift belt at the southeastern edge of the Yangtze region. However, these paleo-uplifts generally undergo multistage tectonic evolution, often including structural superposition and migration, and it is sometimes difficult to determine the origin of their original structure. The central Wushenqi–Qingyang paleo-uplift began to develop in the Meso–Neoproterozoic in the Ordos Basin. The formation of the uplift was related to the large-scale rifting and disintegration of the interior of the Ordos platform and its margins after the Luliang–Zhongtiao movement. The intracontinental aulacogens mainly include the Helan and Linxian–Binxian aulacogens, which are inserted into the interior of the paleocontinent perpendicular to the southwestern and southern margins of the paleocontinent in the near-northern and northeastern directions, respectively. They exhibit a wedge-shaped outline that narrows in the northern and northeastern directions and widens in the southern and western directions, respectively. The Helan aulacogen has the thickest Meso–Neoproterozoic strata (4000 m), followed by the Linxian–Binxian aulacogen with

6

Reservoir Type and Spatial Distribution

a thickness of 2500 m. The Wushenqi–Qingyang area in between is a flat platform (fault block uplift area) with a “higher north and low south” tectonic setting, which is covered by the Changcheng–Jixian sediments with a thickness of only hundreds of meters. In the Early to Middle Cambrian, this tectonic framework was inherited, which was characterized by a “higher in the northern part, lower in the southern part, and central uplift (Wushenqi–Qingyang central paleo-uplift)” tectonic setting. The east and west were characterized by depressions, but the depression degree in the later stage of Helan aulacogen in the west was much higher than that in the east. From the Late Cambrian to Early Ordovician, the tectonic framework significantly changed due to the subduction of the Qinling–Qilian Ocean to the north and the subduction of Inner Mongolia Ocean to the south. On the southern side, the west–northwest Qinqi back-Arc aulacogen developed from the south to the north and the west–northwest Huanxian–Qingyang low uplift separated from the inner Ordos Basin. During this period, a paleo-uplift with an “L-shaped uplift” shape developed in the Huanxian–Qingyang–Huangling area. This paleo-uplift may be related to the balanced uplift of the shoulder at the edge of the shelf. In the Middle and Late Ordovician, the Qinhuangdao arc collided with the North China Block. Large-scale retreat occurred, the continental shelf was exposed at the surface, and the shoulder uplift disappeared. In the Tazhong area of the Tarim Basin, Cambrian–Early Ordovician strata were located in the carbonate platform facies area without a central paleo-uplift. At the end of the Early Ordovician Takang movement, the tectonic framework of the Tazhong area changed due to the closure of the Kunlun Ocean Basin in the West Kunlun–Alkin area. The Middle Ordovician strata in the Tazhong area overlaid the Early Ordovician strata and the Early Ordovician, Middle– Late Ordovician, Silurian, and Devonian strata were denuded. The Qiemo–Minfeng area and southwestern rim of the Tarim Basin are the source supply areas, the southwestern rim of Tarim and the Altun area are the orogenic belt uplift areas, and the center of Tarim is the forebulge. The foreland basin is in between these areas. The Tazhong forebulge began to form a rudiment at the end of the Early Ordovician, followed by a northwestward uplift at the end of the Middle and Late Ordovician. The Silurian Devonian continued to develop until the Devonian northeast–eastward uplift was superimposed on the northwestward uplift. The main body of the Late Permian–Triassic Tatbei Uplift also belongs to the forebulge. Its formation is mainly related to the final collision and formation of the South Tianshan orogenic belt. It separates the Kuche foreland basin in the front of the South Tianshan orogenic belt from the Mangaer Depression after the forebulge and forms a foreland basin system.

6.2 Oil and Gas Enrichment and Distribution

In the Sinian–Middle Ordovician, the Leshan–Longnvsi Uplift in the Sichuan Basin presumably was a widely developed epicontinental sea platform sedimentary facies uplift. It is a small-scale carbonate platform including dolomite, gypsum, and tidal flat–bank of clastic rocks and limestone, open platform limestone, and marginal reef oolitic shoal. In the Late Ordovician–Silurian, the Qinling– Dabie Ocean at the northern margin and the South China Ocean at the southeastern margin of the Yangtze Platform were subducted and subsided to the east, forming the southeast Yangtze and Qinlin–Dabie flysch foreland basins at the northern and southeastern margins of the continental mass. The Qianzhong and Leshan–Longnvsi east– west-oriented forebulges in the Yangtze Platform are associated with the foreland basin. At the end of the Silurian, the Caledonian movement caused the closure of the residual Qinlin Basin in the northern part of the craton and the folding of the southeast foreland basin of the Yangtze region; the Yangtze Craton was uplifted. The Leshan– Longnvsi and Qianzhong Uplifts further suffered from compression uplift and severe erosion. The formation of the Leshan–Longnvsi paleo-uplift is related to compressive stress that was generated at the continental margin and may also be related to the uneven degree of rigidity of the Yangtze Platform. The Jiangnan–Xuefeng paleo-uplift belt at the southeastern margin of the Yangtze Craton may have been a tensional passive continental margin during the Sinian–Early and Middle Ordovician, mainly developing terrigenous clastic rocks and argillaceous rocks dominated by aulacogen and continental slope subdeepwater facies. The formation of the paleo-uplift embryo in this area may have begun during the Middle Caledonian movement at the end of the Middle Ordovician. The Middle Caledonian movement in the late Middle Ordovician was called Duyun movement in the middle–southern region of the Guizhou Province (Yu and Wang 1995). The movement caused sedimentary discontinuities, which led to the loss of the Upper Ordovician, in addition to the loss of erosion of the Middle Ordovician, different degrees of erosion of the Lower Ordovician, and a Silurian and Middle–Lower Ordovician parallel unconformity–small-angle unconformity contact. Due to regional compression, wide and slow folds and corresponding fractures formed. The paleostructure and paleogeomorphology played important roles in controlling the sedimentation of the Early Silurian; the tectonic framework laid an important foundation for the structural development of the Late Caledonian and controlled the formation and evolution of the Caledonian oil and gas reservoirs in this area. The Late Caledonian movement at the end of the Silurian shaped the Jiangnan–Xuefeng paleo-uplift, which suffered from extensive erosion. At the beginning of the Late Paleozoic Devonian, the edge was gradually subjected to transgression. During the Carboniferous–Permian, the

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transgression gradually expanded until the paleo-uplift was covered. At the end of the Middle Triassic to the Late Triassic, the strong Indosinian movement caused the paleo-uplift to deform and rise again, which led to multiple structural deformations and transformations.

6.2.3.2 Paleo-Uplift is Conducive to Reservoir Development The underwater paleo-uplift is characterized by shallow water and high energy and often leads to the development of carbonate reservoirs in high-energy environments such as sparry sand, gravel-sized grain carbonate rock and oolitic limestone. Primary pores develop in this environment, which is conducive to the formation of secondary dissolution pores during the diagenesis and formation of favorable carbonate rock reservoirs. In addition, between the platform and slope-basin, a platform margin reef often develops, the geomorphology of which is higher than that of the platform and slope and thus reef reservoirs are formed. Based on the paleotopography of the Cambrian, the paleotopography of Ordovician is further differentiated in the Tarim Platform in China. It is a carbonate sedimentary system with an undulating platform in a humid climate consisting of coastal belts, algal reef–shoales, shallow seas, platform margin reef–shoales, slopes, and basins. Reef reservoirs are developed in the platform margin reef. The North China Platform is a wavy platform carbonate sedimentary system that formed under arid climatic conditions and includes the Sabha evaporation platform, shoal, slope, and basin facies. In the Ordos Basin, in the west of the Qingyang plaeouplift in the Gansu Province, in the Yinchuan–Pingliang area, the Majiagou Formation consists of shallow sea limestone, and the sedimentary environment of eastern Yulin area is the salt lake. A large amount of gypsum, rock salt, and shoal developed in the paleo-uplift, which is beneficial for the reservoir. Because the paleo-uplift often emerges at the water surface, dolomite reservoirs are favored to form. The dolomite formed by mixed dolomization and evaporating pump is a good reservoir. The development of uplift above water is conducive to the development of ancient weathering crust and karst dissolution pores. The large-scale dissolution due to the leaching of atmospheric freshwater often leads to the formation of a regular distribution of dissolution pores, vugs, and caves. The ancient weathering crust can be divided into four structural layers, that is, weathered eluvium, fractured zone, vadose zone, and phreatic zone. Based on research on the ancient weathering crust at the tops of the Ordovician Ordos Basin and Lower Paleozoic Tarim Basin, the fractured zone is composed of lime-breccia, dolomite, and calcareous dolomite, which formed by weathering and dissolution. Vertically and horizontally karst caves are mainly developed in the vadose zone and phreatic zone, respectively. It has

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been proven by exploration cases that the caves of fractured zone and phreatic zone are the main reservoir space for natural gas.

6.2.3.3 Paleo-Uplift is Conducive to Oil and Gas Migration and Accumulation Oil and gas often migrate from the hydrocarbon-bearing depression area to the uplift area. In addition to the development of reservoirs in the paleo-uplift area, the paleo-uplift structure in the marine basin is conducive to oil and gas accumulation, especially in the paleo-uplifts located inside or at the margin of the hydrocarbon generation center. The tectonic, stratigraphic, and lithologic–structural complex traps developed in the early period of the paleo-uplift area are often favorable locations for oil and gas enrichment under the regional cap rock. The source rocks of the Tarim Basin underwent three hydrocarbon expulsion periods in the Middle–Late Ordovician, Permian, and Early Cenozoic. The Tazhong and Tabei Uplifts began to develop in the Caledonian period. They were eventually formed in the Early Hercynian and Late Hercynian stage and were the main areas for oil and gas migration and accumulation. The oil and gas in the Tabei and Central uplifts vertically migrated and accumulated in the overlying strata due to fracture cutting and damage to the regional cap rock. Based on the geochemical characteristics of natural gas, the condensate and natural gas reservoirs distributed in the Shaya Uplift area of Tabei can be divided into two categories: (1) highly mature condensate and oil-type gas, which are derived from Lower Paleozoic marine source rocks in the Manggar Depression. The natural gas transported to the Shaya Uplift experienced two migration periods. The first migration period occurred earlier, that is, in the Late Hercynian–Indosinian, and the second natural gas migration period occurred in the Cenozoic; and (2) natural gas and condensate produced by Triassic–Jurassic source rocks in the Kuche Depression. The migration mainly occurred from the center of the depression to the Shaya Uplift. The central paleo-uplift and slope area of the Ordos Basin were the main directions of natural gas migration before the Indosinian period. The Ordovician weathered and eroded carbonate reservoir is mainly developed in the uplift and the karst slope (paleo-buried hill platform) reservoir is the highest-quality reservoir. The Jingbian gas field is at the Jingbian karst slope in the central part of the basin. Because of the superposition of the Mesozoic–Cenozoic foreland basin after the Indosinian period, the eastern part of the basin was uplifted, the western part settled, and the eastern flank of

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Reservoir Type and Spatial Distribution

the paleo-uplift transformed into a western inclined slope. The newly generated natural gas and the natural gas that was accumulated in the Ordovician weathering crust reservoir migrated eastward to form a central gas field. The low-permeability gypsum-salt layer in the salt sag on the east side of the paleo-uplift became an obstructing body in the upward tilting direction and the Middle Carboniferous bauxite served as cover layer. The Leshan–Longnvsi paleo-uplift in the Sichuan Basin in the Upper Yangtze region that formed during the Caledonian movement and the Luzhou–Kaijiang paleo-uplift that formed during the Middle Triassic Indosinian movement were the main areas of oil and gas migration. Several gas fields and gas-bearing structures, such as Weiyuan, Longnvsi, and Moxi, have been discovered in the ancient and modern tectonic traps at the slope of the Leshan–Longnuasi paleo-uplift. Caused by the Luzhou and Kaijiang paleo-uplifts, the Carboniferous updip pinchout led to the formation of several large stratigraphic–tectonic paleo-traps. The ancient trap area of the Kaijiang paleo-uplift has a size of 2812 km2, which was beneficial for large-scale discharge of hydrocarbons from the Middle Triassic to the Himalayan movement. After the Himalayan fold deformation, the paleo-uplift and ancient gas reservoir were disintegrated. After the disintegration, some natural gas accumulated in traps in these ancient gas reservoirs that formed during the Himalayan period and secondary accumulation occurred in situ such as in the Wubaiti, Longmen, Shuangjiaba, Dachiganjing, and Wolonghe gas fields. The reserves of these in situ secondary reservoirs are large. Some natural gas in ancient gas reservoirs migrated to different places and secondarily accumulated in traps that formed during the Himalayan period near the ancient gas reservoirs. Gas fields that formed this way include the Gaofengchang, Fuchengzhai, and Tieshan gas fields. Of course, a considerable amount of natural gas may have been lost during open-fault migration. Known paleo-reservoirs in South China mainly include the following two zones (Zhao et al. 2003, 2004): (1) Qianzhong uplift and the northern margin of the Jiangnan Uplift belt, which mainly include reservoirs in the Upper Sinian Dengying Formation and Lower Paleozoic. The source rock is the Lower Cambrain and the traps are structural traps; and (2) Nanpanjiang Depression and adjacent areas, which mainly include ancient reservoirs in the Upper Paleozoic that are mainly distributed in the carbonate platform and at the isolated platform margin. The hydrocarbon source rocks are the Upper Paleozoic, mainly the Middle and Lower Devonian and Permian. The traps are lithological and structural traps.

6.2 Oil and Gas Enrichment and Distribution

6.2.4 The Basic Pattern of Oil and Gas Loss and Preservation is Controlled by Late Tectonic Movement and Tectonic Deformation and the Relatively Stable Preservation Unit Controls the Final Positioning of Marine Oil and Gas In the Mesozoic–Cenozoic, after the end of the development period of the main marine basins in China, intense tectonic movements and tectonic deformations occurred in the Indosinian, Early Yanshanian, Late Yanshanian, Early Himalayan, and Late Himalayan. The Yanshanian movement of Jurassic–Cretaceous led to the formation of a notable paleogeographical pattern with eastern, central, and western divisions of the Chinese mainland. In the east, a large northeastern anticline and a syncline were formed. At the same time, a series of rifting basins with different sizes developed. Northern and southeastern China was characterized by an uplift structure. In central and western China, a series of large offshore, inland depression basins and small and medium-sized lake basins developed. The sedimentary conditions and lithofacies paleogeography during this period were extremely favorable for oil and gas formation. In the late Early Cretaceous–Late Cretaceous, the large Songliao lacustrine Basin formed in the northeast, except for the Tethys Sea area, which shifted southward and shrank. The whole Chinese crust was uplifted. The continental basin had a small water area, showing a large area of fluvial and foothill deposition, which is not good for oil and gas production. The Himalayan movement in the Cenozoic had a major impact on the appearance of the Chinese mainland. The western crust was intensely uplifted. The eastern extension of the block was shifted to the east and a series of lake basins developed in the eastern sea, which is the main area of oil and gas exploration. On one hand, these tectonic movements have construction significance and can form structural traps; on the other hand, they transform, adjust, and destroy ancient oil and gas reservoirs. The latter functions are more prominent. Therefore, these post-structural movements and structural deformations control the basic pattern of oil and gas loss and preservation. Generally speaking, the oil and gas storage conditions are relatively good in areas in which later structural deformation is relatively weak and large-scale and big thickness Mesozoic–Cenozoic continental basins covered areas such as the intenral Tarim Basin and the internal Ordos Basin in the western North China Craton and Sichuan Basin in the Yangtze Craton. In contrast, the preservation conditions are relatively poor and the oil and gas loss is high in areas with intense tectonic deformation and intense fault block cutting or stripping such as in the east of the North

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China Craton and in the Yangtze Craton, except for the Sichuan Basin. In the eastern part of the North China Craton, the intense tectonic activity in the Late Indosinian–Early Yanshanian caused the original platform deposition to disintegrate, resulting in a series of folds and faults and intense denudation of the stratum. The oil and gas generated in the early stage were lost to the surface through exposed “structure window” and faults. A large amount of oil and gas was lost in the area of intense denudation. This period was mainly characterized by two intense uplift belts extending northeast or north–northeast, which are equivalent to the intense eroded zone of the Triassic and Upper Paleozoic, representing the region with the largest loss of oil and gas in the early period. The eastern belt includes the Liaohe, Liaodong Bay, Bozhong, and Jiyang Depressions and Luxi uplift. At the northern end of the belt, the Upper Paleozoic erosion is exhausted, the Lower Paleozoic remnant is incomplete, and the granite rock basement is exposed in most areas. The early oil and gas disappeared. At the southern end, the Triassic is missing and the Upper Paleozoic is only locally distributed. The oil and gas generated in the early stage were lost. The Jiyang Depression in central China with a large residual area is well preserved, but the Triassic was denuded and a large number of fault activities aggravate the loss of oil and gas; therefore, the preservation of early oil and gas is difficult. The western belt includes the Yanshan fold belt, middle and western parts of the Jizhong Depression, and the Taihangshan uplift belt. In most of the area, the Upper Paleozoic was completely eroded. Only in the area with Late Jurassic–Early Cretaceous strata in which the Shijiazhuang sag was deposited in western Jizhong, Upper Paleozoic strata were preserved, but the distribution range is very limited. Two depression zones correspond to the above-mentioned uplift belts. The eastern zone is located between the two uplifts. From the south to the north, the depressions can be divided into Kaifeng–Jiyuan, Dongpu, Linqing, southcentral part of the Huanghua, and eastern Jizhong Depressions. The thickness of the Mesozoic strata is large. The Triassic and Upper Paleozoic deposits in this zone are well preserved and have a large-scale contiguous distribution. The oil and gas loss in the early stage can only be dispersed through fault overflow; therefore, a certain amount of oil and gas generated in the early stage may be retained. The depression also contains a local low bulge. At present, the northern end of the Changxian bulge, Minghuazhen bulge, and northern end of the Tangyi bulge can be observed. From the late Indochina to early Yanshanian

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periods, the remaining Upper Paleozoic sediments in these areas gradually thickened toward the wing and dipping end. This type of low bulge is conducive to the migration of oil and gas and retransformation of the Lower Paleozoic weathering crust reservoirs. The western zone mainly refers to the Qinshui area of Shanxi, which belongs to a compound syncline belt, and the overall uplift in the Middle and Late Yanshanian. Although the Jurassic and Cretaceous are missing in this zone, the Triassic and strata below are relatively intact, with large-scale contiguous distributions, less internal large-scale faults, and weak structural tectonic failure. This zone is favorable for early oil and gas preservation. The Indosinian and Yanshanian tectonic movements led to the formation of a series of north–northeast anticline structures, which are conducive to the accumulation of early oil and gas (mainly natural gas). From the Late Yanshanian (J3-K)–Himalayan, the area was generally in the development stage of the superimposed rift basin, especially the Cenozoic rift basin in which the Paleogene is filled with faulted basins divided by each other. The depression can deposit several thousand thick layers. On one hand, the residual stratum in the early stage can be preserved. On the other hand, the source rock is buried deep, the thermal evolution degree increases, and secondary gas generation is possible. At the same time, the target layer is further denuded and the loss of oil and gas (mainly natural gas) continues in areas with strong uplift and high faulted blocks the target layers were denuded seriously. Therefore, this stage is characterized by the coexistence of secondary gas generation and natural gas loss. Therefore, the Lower Paleozoic (including the Mesoproterozoic and Neoproterozoic) and Upper Paleozoic have been affected by the Caledonian and Early Hercynian movements since the formation of the basement of the North China Platform. The Upper Ordovician, Silurian, Devonian, and Lower Carboniferous are missing, creating a large-scale parallel unconformity contact in the region. The Indosinian movement led to a difference in the east (eastern part of the North China Platform, i.e., the North China basin in a narrow sense) and west (western part of the North China Platform, i.e., the Ordos Basin) and to fault block activity in the east of North China during the Mesozoic and Cenozoic (the fault block activity was the most intense during the Yanshanian and early Himalayan movements), which continued until the late Himalayan period. In other words, the Yanshanian movement (and Himalayan movement) has a significant effect on the preservation of the marine hydrocarbon accumulation in North China. The Yanshanian movement (and Himalayan movement) has no destructive effect on the marine oil and gas reservoirs in the Ordos region. Therefore, the Ordos region still contains large marine oil and gas resources.

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Reservoir Type and Spatial Distribution

In China’s Yangtze Craton and its adjacent areas, regional tectonic evolution has played a more significant role in controlling the oil and gas accumulation, deformation, and destruction. Tectonics movement of pre-Indosinian period mainly plays a constructive role in the accumulation of oil and gas. While, tectonic movement of Yanshanian period, especially the Late Jurassic–Early Cretaceous, mainly plays a distructive role for oil and gas accumulation. The Himalayan movement has both destructive and constructive effects on the hydrocarbon accumulation. It is shown from analysis that Zhao et al. (2003b) bounded by the Jiangshao and Sandu–Dayong faults during the Indosinian and pre-Indosinian period, tectonic framework of “massive uplifts and massive depression” formed in the northwestern Yangtze plate and conformable and parallel unconformity surface can be found between formations. Based on this, the following paleo-reservoirs formed: Lower Paleozoic-Sinian paleo-reservoirs along the northern parts of Jiangnan–Jiuling–Wuling–Xuefeng Uplift, Upper Paleozoic-Lower Trassic paleo-reservoirs of isolated platform and platform margin in Nanpanjiang-Shiwandashan area, Sinian paleo-reservoirs of Leshan-Longnvse Uplift in Sichuan basin, and Carboniferous-Lower Trassic paleo-reservoirs of Luzhou Uplift and Kaijiang Uplift, also in Sichuan Basin. All those paleo-reservoirs are large or extra-large oil and gas reservoirs. The Yanshanian tectonic movement, especially the Late Jurassic–Early Cretaceous tectonic movement, caused intense thrust folds and uplift and erosion in the southern part of the Sichuan Basin, except for the west of the Qiyueshan fault, which resulted in a difference between the Jurassic and Cretaceous strata contact in the Sichuan Basin and other areas in South China and caused the intense deformation and destruction of the above-mentioned paleo-oil and gas reservoir groups in other areas in South China, except for the Sichuan Basin, many of which became paleo-oil and bitumen deposits. As the Jurassic–Cretaceous deposits were buried deep, the paleo-oil and gas reservoirs of the Leshan–Longnvsi, Luzhou, and Kaijiang Uplifts in the Sichuan Basin were preserved and transformed into natural gas reservoirs. In the Himalayan, the foreland sedimentation continued in the southwestern regions, such as the Sichuan and Chuxiong Basins, but the main Himalayan movement at the turn of the Paleogene and Neogene led to the formation of Mesozoic and Paleozoic folds (thrusts), oil and gas structural traps, and large-scale uplift and erosion in the Sichuan Basin. The early formed (oil) gas reservoirs, especially natural gas, were redistributed and migrated or were predissolved in the “degassing” natural gas in the formation water and released and transported to the structural trap. Thus, many secondary Mesozoic and Paleozoic gas fields formed in the eastern and western Sichuan regions.

6.2 Oil and Gas Enrichment and Distribution

In the middle–eastern parts of the South China, local areas were rifted because of the thrust uplift and erosion in the Yanshanian period, forming Paleogene rift basins such as the Jianghan, Northern Jiangsu, and Baise Basins in which the Paleogene contains the primary reservoirs (mainly oil reservoirs) that are self-generated and self-accumulated. This rifting and deep sedimentation of the Paleogene caused the generation of secondary hydrocarbons of the Mesozoic and Paleozoic source rocks in areas with lower thermal evolution such as the Subei Basin, Chenhu area of the Jianghan Basin, and southern Poyang Basin, which resulted in regenerated hydrocarbon reservoirs such as the Zhujiadun gas field in the Yancheng sag of the Subei Basin and the Kaixian-Taixi oil reservoir in the Chenhu area of the Jianghan Basin. The areas with secondary hydrocarbon generation in the Mesozoic and Paleozoic source rocks are mainly distributed in the middle and lower Yangtze regions. Paleozoic source rocks experienced the first hydrocarbon generation before the Yanshanian period. The hydrocarbon generation was terminated by uplift and denudation in the Yanshanian period. The deep burial increased again in the Himalayan period, resulting in an increased thermal maturity and “secondary hydrocarbon,” for example, in the northern Jiangsu region. The Upper Yangtze area is not suitable for the formation of regenerated hydrocarbon reservoirs because it reached the highly mature–overmature stage before the Mesozoic and Paleozoic Yanshanian period and the deep burial in the Himalayan period has not resulted in the increase of its thermal maturity. Therefore, in general, the relationship between the tectonic evolution and oil and gas in southern China (marine) has very notable stages in time. In addition to the formation stage of the basin basement, the Indosinian movement of the Middle Triassic was an important stage of basin development and reservoir formation and preservation. The Yanshanian and Himalayan movements are the main stages of basin superposition and reconstruction and reservoir reconstruction, adjustment, and, especially, damage. In particular, the end of the Middle Jurassic to Early Cretaceous is the most important period of Yanshanian tectonic deformation. Although these movements are important accumulation movements, they caused the reservoirs to undergo strong transformation and/or destruction. Most experts believe that the marine basins in southern China are multi-cycle superimposed (residual) basins, which are mainly based on the Yanshanian movement. The preservation conditions are the key to marine hydrocarbon accumulation in southern China.

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6.3

New Understanding of the Hydrocarbon Accumulation Theory

6.3.1 Oil and Gas Geological Theory of Ultra-Deep Fracture-Cavity Marine Carbonate Rocks in the Tarim Basin In recent years, the most exploration advance in the Tarim Basin is in the marine carbonate strata, which is mainly distributed in the marine Middle Neoproterozoic–Early Paleozoic marine strata in the Craton area, with a depth of 4900–12,000 m. The favorable exploration area is in the ultra-deep range >6000 m. The thickness of the Cambrian– Ordovician carbonate strata is 2000–3200 m and the area exceeds 41
104 km2. Due to the intensive diagenesis of ultra-deep ancient marine carbonate rocks, the matrix pores disappeared and the role of the sedimentary facies in controlling the reservoir was greatly weakened. The basement of the Tarim Basin presents an uplift and depression pattern. After the Caledonian, Hercynian, Indosinian–Yanshanian, and Himalayan movements and the development of multistage unconformity, reservoir heterogeneous karst fracture-cavity reservoirs formed, which are closely related to exposure, weathering, and erosion. Therefore, the ultra-deep fracture-cavity marine carbonate rock has the following characteristics: old age, large burial depth, low matrix porosity, multistage unconformity, intense reservoir heterogeneity, and fractures, vug, and cavity as the main effective reservoir space. The exploration in the Tarim Basin is characterized by a repeated process of exploration practice— understanding—re-exploration practice—re-understanding, improving the geological understanding, innovating and developing key technologies, and forming the oil and gas geological theory of and technology for ultra-deep paleo-marine carbonate rocks.

6.3.1.1 The Large Platform Reef–Shoal Body is an Important Foundation for Reservoir Development The Ordovician reef–shoal body in the Tarim Basin is mainly distributed in areas with steep platform margins, gentle platform margins, and slope break zone of intra-platform geomorphology such as the Tazhong, Lunnan, Bachu, and Maztag areas. It is mainly distributed in the Middle Ordovician Yijiangfang and Lianglitage Formations. In the early stage of the Late Ordovician, the Tazhong area still had a framework of “deeper in the east part and

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Reservoir Type and Spatial Distribution

Sedimentary Characteristics of the Reef–Shoal Body The reef–shoal complex is a sedimentary complex composed of biological reef and grain shoal. The water becomes shallower upward. The reef is composed of a skeleton reef and lime-mound and the single-reef thickness is 33 m. Based on single-well core studies, well logging, and seismic data, the Ordovician reef–shoal complex is characterized by vertical multi-cycle superposition, horizontal multi-period accretion, and an “small-scale reef and big scale shoal” structure.

in Tazhong well 82 is vertically dominated by lime-mound, forming three sets of reef–shoal bodies including grain shoal, lime-mound, and mound subfacies. The lime-mound in the Liang 2 member, which is the core sedimentary segment of the reef body, is 50 m thick. In general, the Lianglitage Formation exhibits the depositional process from transgression to retrogression: the early stage is characterized by a transgression system tract and the development of a deposition and accretion quasi-sequence, with low energy, high shale content, and thin reef–shoal body; the middle and late stages are characterized by a highstand system tract, with three to four reef–shoal body stages; in the bottom two reef–shoal body stages, a vertical accretion quasi-sequence developed, and in the upper one to two reef–shoal body stages, a progressive sequence developed, which indicates the advance and accretion of the upper reef–shoal body stages toward in the slope and basin direction. The development of the reef–shoal body in the upper stage 4 is controlled by secondary tectonic subsidence and sea level change. During the sea level rise, sediments are formed between the frame reefs, lime-mounds, and reefs (mounds). With the upward construction of the reefs and the relative decline of the sea level, the waterbody becomes shallower, the wave energy increases, and the development of reef (mounds) stops. Then, it was replaced by medium- and high-energy grain shoals. Following the next cycle of sea level rise, a new stage of reef and shoal complex develops and grows again.

(1) Vertical characteristics of the sedimentary facies

(2) Lateral characteristics of sedimentary facies

The Upper Ordovician Lianglitage Formation in the Tazhong-I slope break zone is a steep platform marginal system. The middle and upper parts of the Lianglitage Formation are characterized by a vertical multi-cycle grain shoal, lime-mound, and reef-mound combination. The single reef–shoal complex represents the lower grain shoal subfacies, upper lime-mound subfacies, and/or mound subfacies, which are covered by the grain shoal subfacies of the next cycle, but the vertical combination of the sedimentary facies differs in different well areas. The Tazhong-44 well is in the main part of the platform margin reef–shoal body in the Tazhong-I slope break zone. The Liang 2 member is the main body of the reef, which includes two reef stages. The upper sponge reef is 43.5 m thick and the lower cryptophyta bonding reef is 72 m thick. The total thickness of the two reef stages is 115.5 m. The lithology is mainly sparry limearenite, biocalcirudite, framework reef, and bindstone. Due to the denudation of the argillaceous strip limestone at the top of Tazhong-44 well, only thin intershoal deposits remain and four sets of reef–shoal body cycles occurred from Liang members 1–4 (Fig. 6.9). The sedimentary facies

In the parallel direction of the Tazhong-I slope break zone, many sets of reef–shoal complexes can be found in the outer zone. The shoal is dominated by medium- to high-energy bioclast and calcarenite shoal and the lateral correlation is good. The inner belt is dominated by multi-cycle sedimentation of the mound–shoal complex and intershoal sea and the shoal are dominated by medium- and low-energy sandy shoales (Fig. 6.10). The sedimentary facies are zonal and the sedimentary characteristics and types differ in different well areas. The Tazhong 62–Tazhong 44 well area is located in the main part of the reef. It is characterized by the development of mounds. Biological and algal-bonding biological psammitic–psephitic shoals are mainly developed along the periphery of the reef. The topography of the sediments of the Lianglitage Formation in the Tazhong 82 and Zhonggu 2 well area is relatively flat and wide, consisting of several linear lime-mounds, small patch mounds, and a gentle and wide grain shoal. The area is relatively short and wide and the slope is gentle. The sedimentation mainly comprises the mound–shoal complex. The reef–shoal complex and grain bank deposits are locally developed and the grain bank is

shallower in the west part,” which was characterized by a regional slope with an inclination to the NW-SE ward. During this period, the seawater became shallower and the energy increased. A strip-shaped platform marginal deposit formed on the west side of the Tazhong-I slope break zone. The tectonic settings were early and the platform marginal uplift still existed. The period was characterized by the development of a thick multilayered reef–shoal complex with a thickness of 21.5–931.5 m. The average thickness was 278.3 m and the lithology mainly consisted of bio- and granular limestone. The reservoir space was mainly composed of dissolved pores and formed a high-quality reservoir–cap rock association with a thick layer of mudstone overlying the Sangtamu Formation. The characteristics, distribution, and control factors of the reef–shoal complex in the Tazhong-I slope break zone are described below (Wang et al. 2010, 2011a, b; Liu et al. 2009; Zhang et al. 2007).

lithological section

core

SOAG

facies

lithological description

microfacies

subfacies

gray to greyish-green, thin layer of calcareous claystone and silty claystone 2

Depth: 4818-4824m, gray thin layer of mudstone Depth: 4824-4829.5m, gray calcarenite Depth: 4829-4854m, 24.5m in thickness gray, light gray medium - thick layer of algae bonding limestone, with thin layer of sponge framestone and micrite- sparry calcarenite, with geode structure developed

mudstone intershoalsea

sandy- granuleshoal shoal

sandy-gravel shoal

4

granule shoal

Depth: 4889-4909m, 20m in thickness light gray thick- massive layer of reef breccia, with algae bounding structure. Reef breccia mainly consists of sponge and coral bioclasts, with content of 55%

Ordovician Upper Ordovician Lianglitage

Liang2

Depth: 4854-4889m, 35m in thickness gray, light gray medium - thick layer of cryptalgal bonding limestone, sponge framestone, with thin layer of micrite- sparry calcarenite. a small number of vug can be found, with facial porosity of 2-3.5%

framework reef

reef

3

facies

reef knoll

Liang1

Sangtamu claystone

grain contents

diamictic continental shelf

strata Syst- Ser- Form-Sect- Layem ies ation ion er

185 reservoir

6.3 New Understanding of the Hydrocarbon Accumulation Theory

4988.1m, 9.9m in thickness

7

Depth 4997.53 5007.00m, Gray thick-massive micrite calcarenite, cryptalgal clot limestone

sandy shoal mudstone

4978.91

Depth 4988 4997.5m, Gray thick-massive micrite calcarenite, cryptalgal clot limestone

intershoal sea

Depth

sandy shoal

6

granule shoal

Depth 4954 4978.91m, Gray medium-thick layer of micrite-sparry algae calcarenite, sparry bioclastic calcarenite

5

granule shoal

Depth: 4931-4954m, 23m in thickness Gray - light gray thick- massive layer of cryptalgal bonding limestone

platform margin

reef

Depth: 4925.4-4931m, 5.6m in thickness

mound

Depth: 4909-4925m, 16.4m in thickness light gray thick- massive layer of cryptalgal bonding limestone

reef

sandy shoal

granule shoal

Depth 5068 00 5095.00m,27 00m in thickness Gray medium-thick layered mudstone

10

mudstone

Liang3

Depth 5037 00 5068.00m,31 00m in thickness Gray in color, medium-thick to massive layer, sparry and micrite calcarenite and cryptophyta thrombolite with gray color

9

intershoal sea

Depth 5014 00 5037.00m,23 00m in thickness Gray cryptalgal mudstone, cryptalgal clot limestone, a small number of crystal caves can be found, 1 × 2cm ~ 5 × cm, half or full filled with fine crystal euhedral calcite, two high-angle cracks can be found, slit width 0.15 ~ 0.5cm, full filled by calcite

8

mound

Depth 5007 00 5014.00m,7 00m in thickness Gray medium-thick layer of bioclastic calcarenite, with algae bonding structure

Legend calcrudite

arenaceouscalcrudite

bioarenaceous- cryptalgalmudstone calcrudite

spongeframestone

algaeboundstone

mudstone

Fig. 6.9 Detailed description profile map of microfacies of the Lianglitage Formation, Upper Ordovician in Well Tazhong44

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Fig. 6.10 Correlation between the Ordovician reef–shoal body facies in the outer zone of the Tazhong-I slope break zone

mainly developed between the reefs and inner side. The outer margin of the Tazhong 86 well area is characterized by a combination of high-energy grain shaols and lime-mounds. The inner zone of the platform margin mainly comprises a combination of medium- and low-energy grain shoals and lime-mounds.

platform margin is narrow, the reef–shoal complex is thick, and the parallel platform margin reservoir continuity is good. The lateral facies change rapidly, the lithology and lithofacies are highly heterogeneous, the high-energy facies belt is located on the outside, and the reef–mound combination is characterized by rimmed platform, mainly by vertical accretion.

(3) Establishment of the reef–shoal body sedimentary model

(4) Spatial distribution of reef–shoal body

The development of the reef–shoal body in Tazhong-I slope break zone is mainly controlled by the tectonization, sea level change, hydrodynamic condition, and other factors. During the sedimentation stage of the Lianglitage Formation, the waterbody in the southern part of the Tazhong-I fault became shallow, forming banded platform margin high-energy sediment adjacent to the west side of the fault. It was characterized by a reef–shoal complex and mound– shoal complex. The thickness of the reef–shoal complex increases along the margin of the platform increases, which leads to the formation of a transition zone at the platform margin, that is, the Tazhong-I slope break zone. Intra-platform depressions and open platform deposits are on the inside of the platform margin, while slope and basin facies are on the outside of the platform margin. The slope type on the outside directly affects the distribution of the high-energy facies zone, lithology, and lithofacies. The developmental characteristics of the reef–shoal in the Tazhong-I slope break zone agree with the steep-slope platform margin sedimentation model (Fig. 6.11). The

The Ordovician reef–shoal reservoirs in the Tarim Basin are widely distributed, mainly in the Tazhong low uplift, Bachu faulted uplift, Tabei Uplift, and at the northern slope of the Manjiaer sag. The Tazhong reef–shoal complex is characterized by lateral contiguous and vertical superposition and large zonal distribution along the steep platform margin. The reef–shoal body has a length of 220 km from east to west, a width of 5–18 km from north to south, and a thickness of 120–180 m (Fig. 6.12). The main reef area of Tazhong well 54–26 is 3–5 km wide and the reef body is developed along the platform margin. The shoal facies are distributed on the inside of the main reef and the low-energy belt is widely distributed behind the reef in the inner zone of the shoal facies. The facies in the outer zone of the main reef are slope facies and the outer slope facies are basin facies. The range of the reef–shoal body development varies in different sedimentary periods. The range of the reef–shoal body development gradually decreases from the third to the first member of the Lianglitage Formation; it gradually reduces toward the Tazhong-I slope break zone. Reefs, mounds, and

6.3 New Understanding of the Hydrocarbon Accumulation Theory

187 sea level fair-weather wave base

intershoal-sea

shoal

reef & shoal complex in platform margin

low energy sediments of back-reef

open platform

platform margin

slope

Fig. 6.11 Platform margin facies model of the Middle and Late Ordovician in the Tazhong area

shoals in different well areas comprise different combinations. The Tazhong 62 well area is dominated by reef–shoal complexes. The reef is a biological skeleton reef. The main reef body is high and narrow and the slope is steep. The Tazhong 82 well area is dominated by a shoal–mound complex and lime-mounds are relatively developed. The main mound body is short and wide and the slope is gentle. The Tazhong 24 well area is also dominated by the mound– shoal complex. Behind the reef (mound)–shoal complex is the low-energy (inter)reef zone, which is mainly composed of intershoal sea sediments with scattered shoal–mound complexes and an isolated reef–shoal body. Reservoir Characteristics of the Reef–Shoal Body The reef–shoal body reservoirs of the Lianglitage Formation in the Tazhong are formed in the sedimentary environment at the platform margin with medium and high energy. They are mainly composed of reef and granular limestone. Because of the superposition of penecontemporanceous and late dissolution and transformation, they have relatively uniform and high-quality dissolution pore layers. (1) Reservoir petrological characteristics The main rock types of the Tazhong reef–shoal body reservoirs are bio- and granular limestone, followed by micritic limestone. Bioclastic bindstone, bioclastic limestone, and biosandy sandy limestone are the main rock types of the karst-vuggy reservoirs, while calcarenite, sand–gravel sizelimestone, and oolitic limestone are the main rock types of porous reservoirs.

Biolimestone The limestones primarily formed by biological and biological processes. The organisms in the rock mainly grew in situ and their content is generally greater than 15%. Based on the type, content, characteristics, and function of the organism, the biolimestone can be divided into framestone, bafflestone, bindstone, cryptoalgal limestone, etc. Framestone is mainly coral, stromatoporoid, sponge, bryozoan, or composite framework rock formations with two to three types of framed organisms (Fig. 6.13). Framestone mostly formed in the shallow water environment with medium and high energy and are important types that constitute the reef core microfacies. Bafflestone in the Tazhong area includes fasciculate rugose coral and dendritic bryozoa. Coral bafflestone are common and relatively well-preserved ostracodes and a small number of miarolitic structures can be observed. Bafflestone generally forms in weakly turbulent environments with moderate to low energy and often appears in the bottom of reef mounds or reef flank microfacies. The bindstone is mainly composed of cyanobacteria, Girvanella, Sphaerocodium, and other microorganisms that play a bonding role. Algae-bonded biological debris, sand-size clastics, silt-size clastics, pellets, and lime mud with a notable algal-bonding structure. The distribution area of the algal-bonding structure in the rock is larger than 50% and the algae content is >15%; therefore, the rock is called binstone. Cryptoalgal limestone is mainly composed of cryptoalgae, which can also be classified as bindstone. According to the ecology and characteristics, the rock can be divided into cryptoalgal-clotted limestone, algal-laminated limestone, algal-oncolith limestone, and cryptoalgal micrite.

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Fig. 6.12 Map of the distribution of the reef–shoal facies of the Lianglitage Formation in the Tazhong area

Fig. 6.13 Coral framestone, Tazhong 30 well, 5045.72 m (left); Stromatopora framestone, Tazhong 822 well, 5700.01 m (right)

It is one of the important rock types in reef limestone because of its abundant biological types, which mostly form in shallow-water environments.

develop in relatively low-energy zones and mainly include micritic algal arenaceous limestone, micritic bioclastic limestone, micritic peloid, and micritic silty limestone.

Granular limestone Granular limestone mainly comprises sparry granulites deposited at medium and high energy including sparry algal sand-sized and gravel-sized limestone, sparry biological gravel-sized limestone, and sparry algal sand-sized and sparry oolitic limestone. Micritic granulites

Micritic limestone Micritic limestone is mainly deposited at low energy. The granule content is 90%, and a small amount of silty, peloid, and biological clastics can be observed. The bioclasts mainly include ostracoda, brachiopods, cryptoalgae, and spicules,

6.3 New Understanding of the Hydrocarbon Accumulation Theory

189

Fig. 6.14 The filling characteristics of the large-scale karst cavity at the bottom of the Lianglitage Formation in Tazhong-82 well

which transform into argillaceous micritic limestone and argillaceous limestone when the argillaceous content increases.

(2) Reservoir space The effective reservoir space of reef–shoal body reservoirs is mainly composed of intergranular dissolution pores, intragranular dissolution pores, and uniform dissolution vugs with fabric selectivity. The thickness of the pore layer is generally 0.8–20 mm and the filling rate is 2–60%. The pores are well preserved, followed by karst cavity and fractures. Karst cavity It is defined that cavity with a diameter greater than 500 mm. Large cavity is filled and the medium and small pores are well preserved, forming an effective reservoir space. During the drilling, the mud leakage and travel empty often be found. The filling of the pores can be observed in the cores. The core success rate is low and the cores are broken. In the 4920.85–4923.84 m section of Tazhong-44 well, nearly 3 m large karst cavity are developed, which are filled with calcareous claystone containing pyrite. In the 5359.6–5360.6 m section Tazhong-82 well, a *1 m karst cavity developed. The karst cavity is filled with debris, mud, and laminated calcite. The well diameter significantly increased in a box shape and the resistivity (Rt) and acoustic time (AC) increased and the density (DEN) decreased, representing typical logging response characteristics of karst cavity. The FMI image shows a dark band with local bright spots (Fig. 6.14). Vugs Vugs are generally the products of primary pores by the secondary dissolution. The core observations of the reef– shoal body show that the dissolution vugs & pores are

honeycomb-shaped and round, elliptical, and irregular. The diameter of the vugs and pores varies from millimeters to tens of millimeters and the plane porosity is generally 1–2%, reaching up to 10%. The dissolution pores in FMI images are generally irregular dark-colored spots (Fig. 6.15), representing the main reservoir space of reef–shoal bodies. The microscopic reservoir space mainly includes intragranular dissolved pores, intergranular dissolved pores, biological pores, framework pores, and cracks. Biological framework pores represent the pore type of reef limestone, which are primary pores that are not filled with calcite in the framework of reef-building organisms or bindstone. The pore size varies greatly, ranging from less than 1 mm to more than 5 cm (Fig. 6.16). Intergranular dissolution pores are mainly developed in calcite with fine grains between the dissolution grains. When the dissolution is strong, fibrous calcite or even grain edges can be dissolved, making the grain edges irregular (Fig. 6.17). The pore diameter varies greatly, ranging from 0.1 to 0.5 mm, with a maximum value >1 mm. Intragenic pore dissolution is mainly found in arenaceous and bioclastic limestone. They are caused by the selective dissolution of atmospheric freshwater during the syngenetic period. The diameter of intragenic pore dissolution is small, ranging from 0.01 to 0.04 mm. The diameters of larger pores range from 0.5 to 0.8 mm. Fractures constitute important reservoir space in carbonate rocks and the main seepage channels. High-angle structural fractures and microfractures can be found in the reef– shoal reservoir. Unfilled fractures are occupied by high-conductivity mud after drilling and the imaging logging (FMI) indicates black linear characteristics. Filling fractures appear in deep to light colors on imaging logging images depending on the degree of fracture filling and the composition of the filling. Generally, fractures filled with

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Reservoir Type and Spatial Distribution

Fig. 6.15 Vug and pore characteristics of the Ordovician reef–shoal body in the Tazhong-I slope break zone

argillaceous and pyrite show dark high-conductivity characteristics similar to those of unfilled fractures, while calcite-filled fractures (calcite veins) show white high-resistivity characteristics. Core fractures are mainly 0.1–1 mm wide, accounting for 63.9%; fractures with a width greater than 1 mm account for 25.8%; completely filled fractures account for 35.4%; and half-filled fractures account for 64.6% of all fractures. (3) Reservoir physical characteristics

Fig. 6.16 Intragranular dissolved pores, pores in bivalve, sparry echinoderm-clastic limestone, Tazhong-621 well, 4872.40 m, Lianglitage Formation, casting thin section

Fig. 6.17 Intergranular dissolved pores, small amount of intragranular dissolved pores and microfractures, sparry echinoderm-clastic limestone, Tazhong-621 well, 4872.08 m, Lianglitage Formation, casting thin section

The range of matrix physical properties in reef-bank reservoirs is large. They are heterogeneous and the distribution abruptly changes. This indicates that the reef–shoal reservoirs are good reservoirs with uniform honeycomb dissolution and have no dissolution. The drilling of fractured pores and core collection is often difficult. Therefore, the evaluation of the reef–shoal reservoir cannot be limited to physical analysis. It should be described by comprehensive means such as seismic, drilling, logging, and well tests, which can truly reflect the oil and gas reservoir performance. Based on the analysis of the physical properties of the reef–shoal reservoirs of the Lianglitage Formation in Tazhong, the maximum porosity is 12.74%, the minimum porosity is 0.05%, the average porosity is 1.66%, the maximum permeability is 840
10−3 lm2, the minimum permeability is 0.013
10−3 lm2, and the average permeability is 5.5
10−3 lm2. In general, the porosity and permeability are relatively low. Based on the data obtained from pressure and well tests in 20 wells, the interpretation was mainly based on the radial composite model using a formation

6.3 New Understanding of the Hydrocarbon Accumulation Theory

191

Fig. 6.18 Distribution map of the reef–shoal of the Ordovician Lianglitage Formation, Tarim Basin

coefficient between 1.07 and −4230 mD  m, with an average of 426 mD  m. The permeability is 0.0267–73
10−3 lm2, with an average of 15.5
10−3 lm2. (4) Seismic response characteristics of the reef–shoal reservoir The multiphase reef–shoal complex shows a notable response in the seismic profile, that is, a mound-shaped, blank, and disorderly weak reflection. Fine-grained sediments with granular limestone mixed with micritic limestone developed in the platform in intershoal zones between reefs and granulite shoals. The seismic reflection features mainly have moderate to intensive amplitudes, continuous to relatively continuous parallel reflections, and mound reflections. In the main part of the reef mound–shoal complex, the lithology mainly comprises unequal, thick interlayers of reef limestone and granular limestone and the seismic response has a medium to weak amplitude, showing mound and random reflections. The blank reflection in the thickening area is characteristic. The slope facies of the outer margin of the platform are dominated by claystone and micritic limestone and medium–intensive amplitudes and oblique reflections are visible in the seismic profile. (5) Distribution characteristics of reef–shoal reservoirs Reef–shoal reservoirs are characterized by multistage superposition in the vertical direction, laterally contiguous and large-scale distribution along the slope break zone, and a platform margin in the lateral direction. The strong hydrodynamic conditions at the time of the deposition provided a

favorable material foundation for dissolution and transformation in the later stage. The superimposed transformation created favorable conditions for the formation of high-quality fracture and pore reservoirs after the deposition stage such as near-surface karst, fractures in the burial stage, and tectonic uplift and dissolution. Therefore, the reef–shoal reservoirs generally have a large thickness. At present, there are five slope break zones in the Ordovician of the Tarim Basin: Tazhong-I slope break zone, Lunnan–Yingmaili, Lungudong–Gucheng, Tangnan, and Luoxi slope break zone. Reef–shoal reservoirs are distributed along the slope break zone in groups and bands (Fig. 6.18). During the sedimentation of the Lianglitage Formation, the Tarim Plate split into three platforms located near the equator. The climatic conditions were suitable for the development of a reef–shoal body. The extent of the tectonic uplift of the platform was consistent with the rate of the sea level rise, which contributed to the rapid growth of the reef–shoal body at the platform margin and the formation of a long and narrow reef–shoal body sedimentary zone with a thickness of 200–500 m. The Tazhong-I slope break zone comprises a good combination of reservoir and cover and is close to the basin-derived oil rock, forming the largest gas condensate field in the world, with the largest depth and oldest age.

6.3.1.2 The Paleokarst Fracture-Cavity are the Main Reservoir Space for Oil and Gas Karstification is one of the key factors for the formation of ultra-deep fracture-cavity marine carbonate reservoirs. In recent years, many studies have been carried out on carbonate karst and karst reservoirs in the Tarim Basin. A more feasible scheme has been established for the classification of

192

karst and karst periods. The scheme clarifies the main factors controlling the karst reservoir development and guides the continuous exploration of carbonate rock, providing a theoretical basis for the exploration and development of marine carbonate rocks in the Tarim Basin and other areas. Various types of karstification occurred in the Tarim Basin including reservoirs that are formed by different types of karsts such as reef–shoal body karst, interlayer karst, and buried hill karst (Wang et al. 2015). (1) Karst classification Reef–shoal body karst It formed in the syngenetic period (pene-sedimentary karst) or during early diagenesis. It is the dissolution phenomenon of shallow water sediments, such as the platform marginal granule shoal and the skeleton reef that were eroded by the temporary relative decline of the sea level, and the leaching of the exposed sea surface by atmospheric freshwater. The main characteristics include short exposure, fabric-selective, preferential dissolution of unstable aragonite and magnesium calcite, forming uniform pores or small karst– fissures–cavities. The pores and cavities are lenticular in the lateral direction. This type of reservoir is controlled by the sedimentary facies and is mainly distributed in Tazhong-I slope break zone and at the southern margin of Tabei. The karst of the reef–shoal body in the Tazhong area is the most developed at the platform margin, followed by the inner platform zone. It was a favorable area of atmospheric freshwater dissolution in the quasi-synchronous period. Interlayer karst Interlayer karst is weathered karst that formed by short-term formation missing caused by tectonic uplift. The stratigraphic loss is small and is characterized by an uplift hiatus and exposure leaching between the layers in the Ordovician and a parallel or low-angle unconformity contact between the upper and lower strata. The scale of the dissolution is relatively small. The dissolution is nonuniform and the vertical zoning of the karst is not notable. The reservoir space is dominated by large pores and karst– fissures-cavities and the reservoir is widely distributed under the unconformity surface. This type of karst is mainly distributed in the central and southern parts of Tabei and at the northern slope of Tazhong. The reservoirs in the Harahatang area of Tabei are developed along the top surface of the Yijianfang Formation. The reservoir types are cavity and fractures-cavities. The cavity reservoirs are developed vertically and the fracture–cave reservoirs are generally located at the top of the cave reservoir. The upper karst reservoirs in the lateral direction are controlled by large-scale strike-slip faults, which have a patchy, strip-shaped, or partially flaky distribution. The karst development of the Yingshan Formation in the Tazhong area is controlled by the

6

Reservoir Type and Spatial Distribution

paleogeomorphology and the Late Caledonian fault. Favorable development areas are present mainly in the karst slope area, karst subhighland, and fault overlap area. Buried hill karst Buried hill karst is weathered karst that formed by long-term stratum loss caused by tectonic uplift. Carboniferous, Silurian, or newer strata are overlying Ordovician limestone and the strata of different periods have a very clear high-angle unconformity contact. The weathered surface is uneven. The dissolution is extremely nonuniform. Vertical karst zoning is notable. The reservoirs have large cavities and large fractures and the cave filling is great. The reservoirs are widely distributed under the buried hill surface, mainly in the Lunnan, Tazhong, and Yingmaili area and in the periphery of Hetianhe. (2) Main factors development

controlling

the

karst

reservoir

There are many types of reservoirs in the Cambrian–Ordovician carbonate rocks in the Tarim Basin. Combined with the comprehensive analysis of reservoir characteristics in different regions and different intervals, the development of carbonate reservoirs is mainly controlled by the following factors. The control of the unconformity surface The unconformity surface represents the long-term exposure of the underlying strata to atmospheric water. It is a natural location in which karstification occurs. The multi-cycle structural evolution of the superimposed Tarim Basin is characterized by the formation of unconformity surfaces in different periods and levels, which led to the intense paleokarstic transformation of carbonate rocks. First, the development time of the unconformity surface controls the development scale of the karst reservoir and directly determines the dissolution time of the carbonate rock. The development of karst reservoirs controlled by short-term unconformity (high-frequency sequence correlation) is mainly controlled by the lithofacies. The karst reservoirs controlled by the mid-term unconformity surface (interlayer karst) have a quasi-stratified distribution along the unconformity surface. Long-term unconformity (deep mountain karst)-controlled karst reservoirs have vertical zoning. Second, the unconformity topographical differences control the distribution characteristics of karst reservoirs and the occurrence of karstification is closely related to the direction of the water flow. The buried hill karst can be divided into karst highlands, slopes, and basins in the lateral direction. Taking the Tabei Lungu and Tahe oilfields as examples, karst-cavity reservoirs are mainly developed on karst slopes. The inclined topography provides the water potential for the lateral downward flow of the groundwater and represents the groundwater runoff area, which is conducive to the formation

6.3 New Understanding of the Hydrocarbon Accumulation Theory

193

of large-scale pipeline cave systems. The karst highland is an important recharge area for atmospheric water and sinkholes are most developed.

reef (mound) are the most favorable reservoir facies, followed by reef and shoal and calcarenite shoal microfacies. In contrast, the properties of mudstone, cryptophyte, and wackestone, which formed in low-energy environments, are relatively poor. Therefore, reef and shoal at intra-platform of the large carbonate platform and high-energy reef and shoal at platform margin control the distribution of favorable facies zone and the development of the favorable reservoir zone. The microgeomorphic uplift caused by the reef–shoal in multiple stages provides a favorable area for later dissolution. The Cambrian intra-platform shoal and the platform margin reef–shoal are favorable facies belts for the development of large-scale dolomite reservoirs. Before the sedimentation of the Shaoerbulake Formation, the paleotopography was controlled by the “fault–slope” paleotopography and the sedimentary compensation of the Yuertuos Formation. The paleotopography framework has characteristics of “higher in the south part and lower in the north part & higher in the west part and lower in the east part”. Large-scale intra-platform mound–shoal deposits have been formed around the inner depressions, leading to “small-scale reef and big-scale shoal” distribution in the lateral direction. Regional drilling confirmed that the reservoir rocks of the Shaoerbulake Formation are crystalline dolomite, algal dolomite, and residual granular dolomite and dissolved pores represent the reservoir space. The reservoir has a high degree of development, with an average ratio of reservoirs and layers of *42.2%, with a maximum of 80%. The average thickness of type I and II reservoirs is *23.2 m and the maximum thickness is 53 m. The Cambrian platform sediments laid a material foundation for the development of large-scale reservoirs in the Shaoerbulake Formation (Du and Pan 2016).

The control of the fault system The carbonate rocks in the Tarim Basin are dominated by secondary dissolution pores, vugs, caves, and fractures. The faults play important constructive roles in the development and distribution of the reservoir. First, weathering karst is mainly developed along the weak zone near the unconformity surface and faults and fractures are the main channels for the dissolution fluid. During the formation of weathering karst, the fault activity controls the distribution of the paleo-water system or changes the characteristics of the paleogeomorphology, which facilitates the transport of fluid along the slope of the terrain, forming a favorable karst reservoir development zone. The faults are also the stress release zones, which are beneficial to the development of fracture zones as favorable areas for atmospheric freshwater dissolution. Second, karst fissures and caves mainly develop along the faults during the burial period. The carbonate rocks in the Lower Paleozoic underwent long burial diagenesis and the primary pores were mostly filled due to multistage cementation and compaction. The multistage burial karstification was mainly controlled by the acidic solution fluid that formed by stara compaction fluids of basin scale, organic acid carried by hydrocarbon, TSR, and the hydrothermal fluid. The fault zone and its associated fracture zone are not only favorable channels for fluid transport but also favorable locations for organic acid dissolution. Based on the early pore layers and fractures, dissolution in the buried stage occurs along fracture bodies, pore beds, and fracture zones near the fault zone and effectively improves the reservoir space.

The control of large carbonate platforms The evolution of large Cambrian–Ordovician carbonate platform in the Tarim Basin consists of several stages. From the north–south differentiation in the early stage to the east–west differentiation, different platform types form different rock combinations and different degree of reservoir. The high-energy reef–shoal deposit at the platform margin of the Ordovician is the basis for the formation of reservoirs. During the depositional period of the Lianglitage Formation, a sedimentary sequence of multiple reefs (mounds) and shoal bodies developed at the rimmed platform margin in Tazhong area and single reef (mound) shoal bodies are favorable reservoirs. Collectively, the microfacies control the fabric and lithology of the rock, thereby controlling the development of the primary pores of the rock and secondary dissolved pores. Based on previous research, the physical properties of granular limestone are notably better than those of mudstone. The bioclastic shoal microfacies associated with the

6.3.1.3 Quasi-stratified Reservoir Model of Fracture-Cavity Carbonate Rock Quasi-stratified oil and gas reservoirs refer to the oil-bearing fracture-cavity system with a certain thickness (usually 100– 200 m) along the regional cap rock, unconformity, or tight limestone layer in the extremely thick paleo-marine carbonate rocks. The top and bottom of the reservoir are uneven. The section does not contain unified bottom water with quasi-layered features. This type of oil and gas reservoir has a large distribution area (up to 10,000 km2) and a large oil column height (*3000 m). This is a special type of oil reservoir that is different from the layered edge water and the massive bottom water of the clastic rock. It is widely distributed in the buried hills, reef–shoal body, and interbedded karst of the Ordovician carbonate rocks in the Tarim Basin. Oil and gas in the quasi-stratified oil and gas reservoirs in the Tarim Basin mainly exist in the fracture-cavity system and their distribution is not controlled by the local structure. There may

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be a unified oil–water interface in the fracture-cavity system, but the entire oil and gas reservoir has no uniform oil–water interface and the oil–water distribution is complex. Macroscopically, it is characterized by large-scale distribution and local enrichment of quasi-layered reservoirs. The gas layer thickness of the gas condensate reservoir of the reef–shoal of the Tazhong-I slope break zone is 150–300 m. The reservoir is gas-bearing, oil-bearing in parts areas, partially contains sealed water, and there is no notable edge and bottom water. The gas layer height difference is greater than 2400 m, the formation pressure is 60–70 MPa, and the pressure coefficient is 1.15– 1.26 (Fig. 6.19). The oil and gas of the Lugu buried hill oil and gas reservoir is distributed within 200 m below the unconformity surface, and the area is large and contiguous. There is no uniform oil, water, and gas–water interface. The karst landform and size of the fractures and cavities jointly control the oil and gas enrichment. The interlayer karst reservoirs in Harahatang also exhibit the characteristics of heterogeneous, large quasi-stratified oil and gas fields with integral oil and local enrichment. The oil and gas are mainly distributed within a depth of 150 m below the top of the Yijianfang Formation. It has been confirmed that the reservoir height difference is larger than 2700 m. At present, a boundary to the south of the reservoir has not been found and the reservoir scale is huge.

6.3.1.4 The Stabilized Paleoslope and Paleo-Uplift is an Important Area for Oil and Gas Accumulation The formation of quasi-stratified carbonate oil and gas reservoirs is dominated by in situ hydrocarbon generation and reticulated vertical migration and accumulation of

superimposed contiguous reservoirs under tight limestone unconformity surfaces or regional cap layers. The accumulation is controlled by five factors: (1) Following the “source control accumulation,” large-scale high-quality source rock areas control the in situ hydrocarbon generation and accumulation. The Cambrian–Ordovician source rock is distributed over a large area and multistage accumulation ensures the complete filling with oil and gas. The source rocks are dominated by slope, basin, and lagoon facies. The large Tazhong, Tabei, and Hetianhe oil and gas fields, which were recently discovered, are distributed in the high-quality source rocks of the Cambrian Yuertus Formation; (2) The stable paleo-uplift and its large-scale slopes are the main areas of hydrocarbon migration. The paleo-uplift and its slopes are effective allocation areas for source rocks, favorable reservoir facies, and multi-type trap development areas with good oil and gas preservation conditions; (3) Karst fracture-cavity reservoirs develop under multi-period unconformity control. The Lower Paleozoic carbonate rocks in the Tarim Basin experienced multiple periods of tectonic uplift and exposure and multiple unconformities and karst zones developed. Examples are the reef–shoal reservoirs of the Lianglitage Formation, the interlayer karst reservoirs of the Yingshan Formation, and the interlayer karst reservoirs of the Harahatang Yijianfang Formation in the Tazhong area; (4) The strike-slip fault system controls the three-dimensional (3D) migration network of oil and gas. The Cambrian–Lower Ordovician is the main hydrocarbon source rocks in the platform basin area. The platform basin area also contains multiple sets of reservoir and cap associations in the Lower Paleozoic. The

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multistage active strike-slip fault system connects the hydrocarbon source rock. Together with multiple sets of reservoirs, it forms a 3D transport network, which controls the oil and gas migration and accumulation; and (5) The two sets of regional cap rock controls the preservation of main oil and gas. The giant Upper Ordovician claystone of black color and Cambrian gypsum and salt rock of white color are regional high-quality cap rocks in which a number of favorable reservoir–cap combinations with karst reservoirs formed. Therefore, the paleoslope is an important area for oil and gas accumulation, which is located on massive source rocks, and multistage fault development, especially x-type strike-slip faults, provides an important oil and gas transport system, leading to the scale distribution of karst fissures and caves where oil and gas occur.

the northwestern margin of the Upper Yangtze region were identified and a facies–logging phase–seismic response standard and template were established. The dynamic sedimentary evolution of the gentle ramp in the Wujiaping period in the Yuanba area-the bioclastic shoal developed into a distal steep gentle ramp in the early Changxing-three stages of organic reefs were developed to form the rimmed platform in the middle and late stage was restored. The regional sequence framework was reconstructed and the deep–ultra-deep macro-reef development model of “shoal developed in early stage and reef developed in late stage and multiple stage stacking in rows and belts” was established. This changed the previous assumption that the area is a deepwater deposit of the Guangwang trough (Guo 2011, 2014, 2019; Guo et al. 2018).

6.3.2 New Understanding of the Oil and Gas Theory of Marine Deep Carbonate Rocks in the Sichuan Basin 6.3.2.1 Sedimentary Model of the Platform Margin Reef–Shoal on Both Sides of the “Kaijiang–Liangping Shelf” in Northeastern Sichuan In previous studies of Puguang gas field, the standard fossil association of the Permian Changxing Formation was found in the Lower Triassic and classified for the first time, which redefined the stratigraphic stratification and refuted the stratigraphic basis for the existence of the “Kaijiang– Liangping trough.” Based on a large number of field outcrops, seismic sections, and drilling data, the Sinian–Triassic Yangtze Block is in the passive continental margin evolution stage, which refutes the tectonic and paleogeographic settings of the “Kaijiang–Liangping trough.” A variety of shallow water sedimentary markers were discovered in the deepwater” trough” area classified by predecessors including high-energy sediments such as oolite-pisolite dolomite. Based on the above work, the model for the development of high-quality reservoirs in the Changxing–Feixianguan Formations in the northeastern Sichuan Basin was reestablished. Based on this model, the Puguang area is in the favorable facies belt for reservoir development, which solves fundamental exploration issues and expands the exploration field (Ma 2006). In the early stage of the exploration of the Yuanba gas field, the distribution of the ultra-deep reef sedimentary facies belt was unclear, which greatly affected the evaluation and optimization of favorable targets. Based on high-level and detailed sequence analysis and seismic sedimentology research on outcrops, five types of genetic combinations and 11 genesis markers of the Wujiaping–Changxing period at

6.3.2.2 Development and Preservation Mechanism of Deep–Ultra-Deep Carbonate Reservoirs in the Sichuan Basin Main factors controlling the development of high-quality carbonate reservoirs: Three-element controlling reservoir Based on a large number of field and laboratory studies during the exploration and research of the Puguang gas field, it has been confirmed that three important processes are the main factors controlling the development of high-quality carbonate reservoirs: ① The depositioanl–diagenetic environment controls the early pore development; ② Structure–pressure coupling controls the fractures and shallow dissolution; and ③ Fluid–rock interactions control the deep dissolution and preservation of pores. The three factors are related to each other: The depositional–diagenetic environment controls the distribution of the reef and syngenetic dolomite; tectonic stress and formation fluid pressure together control the fracture behavior of the buried rocks and the initial stage of the development and distribution of pores; and the initial stage of the buried pore distribution, rock fracture behavior, and fracture distribution control the dissolution. Therefore, the evolution of the porosity and permeability of deep–ultra-deep carbonate rocks in superimposed basins is the result of multilayer coupling of hydrocarbon–water–rock systems during the evolution of specific lithologies and temperature–pressure fields. Due to the development of the reef and dolomite and fracture and organic–inorganic complex interactions as well as fluid–rock interactions, deep–ultra-deep carbonate rocks can develop multiple pore types and maintain high porosities and permeabilities. The three-element reservoir control mechanism directly guides the exploration of the Puguang gas field and can be further confirmed by the exploration results (e.g., the porosity of the 5089.86 m carbonate reservoir in Puguang well 2 reaches 28.86% and the permeability is 1720.8
10−3 lm2); it has practical significance in guiding

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the deep–ultra-deep oil and gas exploration in China’s vast carbonate development areas (Ma et al. 2010, 2011). Construction of a heterogeneous “dual pore–fracture structure model” reservoir model for reefs. Based on studies of the reservoir petrology, diagenetic pore evolution, and carbon and oxygen isotopes and simulations of the carbonate karst erosion dynamics, the development mechanism of high-quality reservoirs in the ultra-deep reef cap dolomite of the Changxing Formation in the Yuanba area, that is, “overpressure forming fracture, coupling of pores and fractures,” was identified. The analysis of the physical properties shows that the reef reservoir has a poor porosity and heterogeneity and that a large number of fractures effectively improves the filtration capacity of the low-porosity reservoir. Based on the microscopic observation and analysis of cores and rock mechanics experiments regarding the crack formation, hydraulic pressure fractures are developed in the reservoir. Based on a paleo-pressure test and numerical simulations of reservoir fluid inclusions, the pressure coefficient of liquid hydrocarbon in the relatively closed system of the organic reef reaches up to 1.77 during the deep-burial cracking of liquid hydrocarbon into gas. The formation mechanism of overpressure cracking caused by deep-burial cracking of liquid hydrocarbon was proposed. Early exposure dissolution and shallow-burial dolomization form the basis of the matrix pore development. The overpressure fracture caused by the deep liquid cracking of pore liquid hydrocarbons is the key to improve the reservoir permeability. “coupling of pores and fractures” controls the development of ultra-deep reservoirs. On this basis, a heterogeneous “dual pore–fracture structure model” reservoir model of the reef can be constructed, which lays the theoretical foundation for the prediction of reef reservoirs.

6.3.2.3 Natural Gas Accumulation and Enrichment Mechanism of Deep Marine Carbonate Rock Reef and Shoal Facies in the Sichuan Basin Superposition-compound control accumulation mechanism.

(1) Paleostructures in the main oil-generating period control the accumulation of crude oil. Based on forward and inversion analysis, the main oil generation period and the hydrocarbon generation history of the main source rocks in northeastern Sichuan were studied: The Permian source rocks in the northeastern Sichuan Basin entered the hydrocarbon generation threshold in the Late Indosinian (215 Ma) and reached the peak of oil production in the Middle Jurassic (175 Ma). Therefore, the Yanshanian

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period is a critical period for the formation and accumulation of liquid petroleum. This was confirmed by the drilling results: the use of uniform temperature dating technology for fluid inclusions proves that the crude oil was charged at 167– 161 Ma (equivalent to the middle–late stage of the Yanshan movement), which coincides with the peak oil generation period of the source rock. The structural framework and fluid transport system during the critical period of crude oil accumulation (Yanshanian period) were restored. During the main oil generation period of the source rock, fractures developed in the study area, which represent a good oil and gas transport system connecting the source rock and the reservoir of the Feixianguan Formation. This proves that the Puguang belt structure is a favorable crude oil accumulation area. (2) Late and early tectonic superposition control the chemical modification and fluid adjustment of oil and gas reservoirs. The Middle and Late Yanshanian movements and the Himalayan movement controlled the chemical transformation of the oil and gas reservoirs. Based on the anatomy of the discovered oil and gas reservoirs in the Sichuan Basin, three geochemical processes occurred after the accumulation of crude oil: crude oil cracking, reservoir bitumen cracking, and TSR reactions. These three chemical processes simultaneously modify the properties of the reservoir fluid and the reservoir properties, which is collectively referred to as the chemical transformation of the reservoir. The Middle and Late Yanshanian movements and the Himalayan movement controlled the adjustment of the oil and gas reservoirs. Based on the research progress with respect to the 3D geometrical shape of the top transport layer controlling the hydrocarbon migration channel, the 3D geometry of the top surface of the Feixiang–Dongyuzhai structure of the Feixianguan Formation was restored. The current structural maximum of the Puguang–Dongyuzhai structure is in the southwestern part of the structure. During the formation of ancient oil reservoirs (early Yanshan movement), the Puguang–Dongyuezhai structure of the Feixianguan Formation was high in the northeast and low in the southwest and contained slopes in the southwest, which is exactly the opposite of the current structure. (3) A late tectonic–lithologic complex controls the reaggregation and final distribution of natural gas. The effective reservoir of the Feixianguan Formation is not developed at the maximum of the Puguang–Dongyuezhai structure. The current position of the Puguang gas field is more than 1300 m lower than the maximum. Therefore,

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under the influence of the “great potential energy,” the Puguang gas field first formed a lithologic reservoir. It changes accompany with later structure changing. In the end, the current Puguang gas field was formed under the joint action of structural–lithologic traps. Ultra-deep reef accumulation model (“three micro-migration, near-source enrichment, and persistent preservation”). During the exploration of the ultra-deep reef and shoal Yuanba gas field, an ultra-deep reef accumulation model was established, which is characterized by three processes, that is, “three micro-migration, near-source enrichment, and persistent preservation.”

with a thickness of 30–80 m and an average organic carbon content of 2.63%. Based on the drilling data obtained in Yuanba well 3, the lower strata of the Wujiaping Formation in the Yuanba area contain dark mudstone and marl and the cumulative thickness of the TOC above 0.5% can reach 80 m. The hydrocarbon generation intensity of the two sets of high-quality hydrocarbon source rocks is 30– 70
108 m3/km2. The Yuanba gas field is adjacent to the hydrocarbon generation center of the Permian Wujiaping Formation and has sufficient oil and gas sources.

(4) Located at the edge of the hydrocarbon generation source with high hydrocarbon generation intensity and near-source enrichment characteristics. The studies of the carbon isotopes of the natural gas, reservoir asphalt, and source rock show that the oil sources of the Changxing Formation in Yuanba mainly are Wujiaping and Dalong Formations in the Late Permian deepwater shelf area in the Guangyuan–Wangcang area in the north. The lithology is dominated by black claystone and shale with a thickness of 60–110 m and the kerogen type is I–II1. The gas field has a “lateral near-source, vertical near-source” distribution. “lateral near-source” refers to the distribution of gas fields near the hydrocarbon generation center of the Dalong Formation. The mudstone of the Dalong Formation is *20–30 m thick and its average organic carbon content is 2.38%. “Vertical near-source” refers to the development of the source rocks of the Wujiaping Formation at the bottom

(5) Microfault, microfracture, and interlayer fracture (“three micro-migration”) transport systems connect the source rocks and reservoirs and are important channels for hydrocarbon migration. The Yuanba ultra-deep reservoir lacks superior transport conditions such as faults or an unconformity surface. However, the relationship between the generation and reservoir configuration indicates (Fig. 6.20) that the source rocks of the Upper Permian Longtan Formation entered the oil generation window in the Late Indosinian period, the tectonic activity was weak in the Yuanba area at this time, and no vertical oil and gas migration channel existed. In the Early Yanshanian period, the source rocks of the Upper Permian Longtan Formation entered the early stage of the oil generation peak. Affected by orogenic compression at the basin margin, microfaults, microfractures, and interlayer fractures developed in the area, which were vertically connected with the source rocks of the Longtan Formation. The reef–shoal facies reservoirs and fractures in the Changxing Formation formed a transport system of vertical and lateral

Fig. 6.20 Hydrocarbon generation history and transportation system evolution of the hydrocarbon source rocks in the Yuanba area and their control over oil and gas filling

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migration of oil and gas, which enabled the crude oil to accumulate in the Changxing Formation to form lithologic reservoirs. (6) Undeveloped faults and the closure of intact gypsum claystone allow the natural gas to be preserved during adjustment and reaggregation. The amount of crude oil cracking gas calculated from the restoration of paleo-oil reservoirs is *330 bio m3. The proven natural gas reserves in the Yuanba gas field are *200 bio m3, indicating that the natural gas reserves during the adjustment and reaggregation were good. The total accumulated thickness of the Jialingjiang–Leikoupo Formations in the Yuanba area is 300–600 m. The structural deformation is weak in this area. Faults do not cut through the overlying cap rock of the Jialingjiang–Leikoupo Formations, which is the key to the preservation of natural gas.

6.3.2.4 “Four-Paleos Controlling Reservoir” Theory of the Anyue Gas Field in the Central Sichuan Uplift Area After five times of research, PetroChina discovered that the Anyue area is adjacent to the hydrocarbon generation center of the paleo-depression. The Anyue gas field is an inherited paleo-uplift (probably a superposition of the Tongwanian build up and Caledonian structure) and contains two sets of paleo-reservoirs (Sinian and Cambrian). Two types of large-scale tectonic–lithologic strata are developed. The effective spatial and temporal allocation of paleo-depressions, paleo-bioherm–shoal complex, paleo-traps, and paleo-uplifts is the most important factor controlling the formation and enrichment of large-scale gas fields in Anyue. Taking the “four paleos” as the core, PetroChina has established the “four paleos controlling reservoir” theory for ancient carbonate rocks (Du et al. 2014; Du 2015; Zou et al. 2014; Wang et al. 2016): Paleo-depressions are developed in the paleo-craton platform, which is the core of the hydrocarbon accumulation control. They control the hydrocarbon generation center, distribution of the bioherm–shoal complex, source and storage configuration, and lateral-sealing. At the flank of the paleo-depression, a large-scale bioherm–shoal complex developed at the platform margin, which controls the distribution of large-scale high-quality reservoirs, formation of paleo-traps, and accumulation of oil and gas. The paleo-uplift controls the hydrocarbon accumulation and formation and evolution of large paleo-reservoirs. The lithologic–stratigraphic paleo-traps control the large-scale distribution of lithologic–stratigraphic reservoirs and thus the formation and preservation of today’s gas reservoirs. The new theory effectively guided the discovery of the Anyue gas field and

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promoted the oil and gas exploration in the Chuanzhong paleo-uplift (from high to low parts, from structural to lithologic–stratigraphic gas reservoirs, and from single to multiple gas layers).

6.3.2.5 Enrichment Regularities of Gas Reservoirs in the Leikoupo Formation of the Sichuan Basin After years of exploration, a number of large and medium-sized gas fields were discovered in the Leikoupo Formation in the Sichuan Basin (Fig. 6.21). In the plane, they are mainly concentrated in the Lei 1 and Lei 3 members and in the Lei 43 sub-member (top of the Leikoupo Formation); in lateral direction, they are mainly distributed in the Longmen piedmont belt in the western Sichuan depression and in the Chuanzhong uplift belt. (1) Source control accumulation There is a good correlation between the hydrocarbon generation strength and source rocks and large and medium-sized oil and gas fields, high-abundance gas reservoirs, and high-yield wells (Fig. 6.22). The Upper Permian area with strong hydrocarbon generation is mainly distributed in the central part of western Sichuan, Central Sichuan, and northeastern Sichuan. The Upper Triassic area with strong hydrocarbon generation is mainly distributed in western Sichuan. The greater the hydrocarbon generation intensity is, the higher is the abundance of the corresponding gas reservoirs and the higher are the yield and quantity of high-yield wells. For example, the hydrocarbon generation intensity of the Longtan and Xujiahe Formations in the Zhongba Leisan gas reservoir is 10–20
108 m3/km2 and 20–120
108 m3/km2, respectively. Although the gas-bearing structural area is only 13.4 km2, 8.63 bio m2 of proven reserves have been reported. However, the hydrocarbon generation intensity of the Yuanba Lei 4 gas reservoir is only 4–6
108 m3/km2. The gas-bearing area of wells Yuanba 22–Yuanba 2 is *80 km2 and the proven reserves are only 10.665 bio m2. The hydrocarbon generation intensity and hydrocarbon supply mode of the source rocks differ in different reservoir formations; they have important effects on the gas reservoir size and productivity. With respect to the source–reservoir assemblages of source rock below the reservoir and source rock above the reservoir, it belongs to the typical secondary gas reservoir, which are shown as leap-forward contact between source and reservoir. Natural gas can only migrate upward into rich integrated reservoirs in the reservoir section if the hydrocarbon source faults are connected. Therefore, the hydrocarbon generation intensity may not be positively correlated with the distribution of the gas fields. The main reason is the

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migration channel of natural gas in the accumulation system. The natural gas accumulation is notably related to the area that contains the hydrocarbon source fault. If the area containing the hydrocarbon source fault is more developed, the gas reservoir size or single-well productivity is notably higher. For example, in the Longgang Lei 4 gas reservoir in the northeastern Sichuan Basin, the wells LG161 and LG21 near the connected source rock faults have industrial capacity, while the wells far away from the connected source rock fault, such as well LG18, have no capacity. Because the upper source–lower reservoir type (reverse irrigation or lateral migration) has more severe requirements on the migration channel, the lower source–upper reservoir type is more favorable to gas pool formation. For example, the Lei 1 gas reservoir in the Moxi gas field in Central Sichuan is a

typical reservoir-forming assemblage of the lower source– upper reservoir type. Its gas pool size and gas reserves are larger than those of upper source–lower reservoir-type Longgang and Yuanba Lei 4 members, which are dominated by reverse irrigation or lateral migration. The source rock and reservoir are the same strata and the gas reservoir has the advantage of near-source accumulation. The size and productivity of the gas reservoir are notably and directly related to the hydrocarbon generation intensity of the source rock. The gas reservoir size is controlled by the hydrocarbon generation intensity. This is reflected in the relationship between the distribution characteristics and hydrocarbon generation intensity of the corresponding source rock in the Lei 43 sub-member in Xinchang. The gas reservoir has a hydrocarbon generation intensity ranging

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Fig. 6.22 Relationship between the high-yield gas area and hydrocarbon generation strength of the Upper Permian source rock in the Sichuan Basin

18–38
108 m3/km2. The hydrocarbon generation intensity of the source rock is large and the distribution range is wide, which is conducive to the close coverage and strong filling of source rocks, thus forming large and medium-sized gas fields. In general, the source control conditions of this source–reservoir-assemblage are good, but the effect of the hydrocarbon generation intensity is notable. There are two types of source–reservoir assemblages, that is, “source–reservoir in the same strata & source rock below reservoir” and “source rock above reservoir & source rock below reservoir”. Under the action of a multi-source hydrocarbon supply, the scale or productivity of the gas reservoir is notably higher, but this reservoir-forming assemblage also requires the connection of the

hydrocarbon source and faults to achieve a high yield and gas reservoir enrichment. The Lei 3 member gas reservoirs of the Zhongba gas field and the Lei 43 sub-member gas reservoirs of Pengzhou are located in the Longmenshan piedmont tectonic belt. The high abundance of the gas reservoir is related to the development of faults in the piedmont zone. The Pengxian and Zhangming faults are faulted to hydrocarbon source rock formation and their formation time matches the peak of the hydrocarbon generation. These faults provide good channels for the high production and enrichment of gas reservoirs. Because the gas reservoir is in the hydrocarbon generation center and has a multi-source mixed hydrocarbon supply, the abundance of the gas reservoir is significantly higher. This is also reflected

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(2) Facies control accumulation

by the single-well production of the gas reservoir, for example, a high-yield industrial gas flow has been obtained in wells PZ1, YS1, YaS1, and Z2. In general, the hydrocarbon generation intensity of the source rock, hydrocarbon supply mode of different reservoir types, and development degree of the source faults control the distribution range, scale, and productivity of the gas reservoir. The types of “source–reservoir in the same strata & source rock below reservoir and source rock above reservoir & source rock below reservoir” gas reservoir types have the largest scale or productivity, followed by the types of “source–reservoir in the same strata and source rock below reservoir” The type of “source rock above reservoir” is relatively small in scale or capacity.

There are three types of reservoirs in the Leikoupo Formation gas reservoir in the Sichuan Basin (Fig. 6.23): (1) the shoal facies granular carbonate reservoir controlled by the sedimentary facies (Zhongba Leisan, Moxi Leiyi, Wolonghe Leiyi); (2) the carbonate layer controlled by the karst system at the top of the Leikoupo Formation (Yuanba, Longgang Leisi); and (3) the tidal flat porous carbonate reservoir formed by the top-surface homogeneity–shallow-burial dissolution of the Leikoupo Formation controlled by the facies (e.g., Pengzhou and Xinchanglei Lei 4 member gas reservoirs). The Lei 1 member contains a wide range of developed granular shoales, mainly distributed in Ziyang–Moxi–

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supratidal zone

intertidal zone

subtidal zone

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denudation zone city

Fig. 6.23 Relationship between the sedimentary facies and high yield and enrichment of the Middle Triassic Lei 43 sub-member in the Sichuan Basin

202

Xichong, with an area of *3
104 km2. The restricted platform (algae) dolostone flat of the Lei 43 sub-member is mainly concentrated in western Sichuan. A. The distribution of favorable facies determines the distribution of the reservoirs and gas reservoirs. The favorable (micro)facies are the basis for the reservoir pore development and the degree of reservoir development largely determines the abundance and distribution of gas reservoirs. Based on the statistical analysis of the lithologies of many gas reservoirs, favorable reservoir rocks are mainly developed in favorable sedimentary (micro)facies belts such as the tidal flat, platform margin, and intragranular shoal. In these sedimentary facies, the primary pores of the reservoir are relatively developed and provide a good lithological basis for the occurrence of various stages of dissolution, thus forming a large number of secondary pores. The tectonic stress at the pore development site is relatively weak, which provides the conditions for the development of fractures and a fracture porosity reservoir with a good reservoir performance can form. The statistics also show that the reservoir pore development and reservoir performance are significantly reduced farther away from favorable sedimentary (micro)facies belts. Therefore, the distribution of the gas reservoirs is largely controlled by the spatial distribution of favorable sedimentary (micro)facies belts. The tidal flat algae dolomite and grain dolomite microfacies are the most favorable sedimentary microfacies and distribution areas of the Pengzhou Lei 43 and Xinchang Lei 43 sub-member gas reservoirs. During the deposition of the Lei 43 sub-member in the Sichuan Basin, the sediments of the algae-dolostone flat in western Sichuan were widely developed (e.g., the Pengzhou Lei 43 sub-member gas reservoir). The lower reservoir interval has an average porosity and permeability of 5.39% and 7.30 mD, respectively, representative for medium- to high-porosity reservoirs. There are various types of reservoir storage space including intergranular (dissolved) pores, inter-algae dissolved pores, intergranular dissolved pores, bird’s eye pores, and karst caves, providing good storage space for natural gas accumulation. The platform margin and intra-platform grain shoal are the main areas in which the sedimentary microfacies and gas reservoirs of the Zhongba Lei 3 member gas reservoir and the Moxi and Wolonghe Lei 1 member gas reservoirs are distributed, respectively (Li et al. 2016; Wang et al. 2015a, b). B. The distribution of constructive diagenetic facies determines the distribution of high-quality reservoirs. The Leikoupo Formation is deeply buried; it underwent complex diagenetic stages and processes. Destructive

6

Reservoir Type and Spatial Distribution

diagenesis, such as compaction, pressure dissolution, and cementation, is strong and the matrix pores of the reservoir are underdeveloped. Without constructive diagenesis, the formation of good reservoir space is impossible. An example is the constructive diagenesis in the Pengzhou Lei 43 sub-member gas reservoir. Dolomitization, dissolution, pressure dissolution, and fracturing play crucial roles in the formation of secondary pores. Intergranular pores that formed by penecontemporaneous and shallow-burial dolomitization transformed the matrix pore permeability of the rock, which laid a foundation for the pore formation and development of high-quality reservoirs. The superposition of multiple dissolution processes, such as penecontemporaneous and burial dissolution, resulted in the formation of high-quality reservoirs with good pore and fracture connectivities. On one hand, fenestral, anhydrite, and intergranular residual pores, which were not completely cemented and filled after penecontemporaneous dissolution, are now preserved as effective storage spaces. On the other hand, the late burial dissolution diffused the pores that formed by penecontemporaneous dissolution and expanded the dissolution of the edges of some pores that formed by weakly exposed karstification in the early Indosinian period, which further improved the reservoir quality. Observations under the microscope show that the saddle dolomite was dissolved in the burial stage, bitumen impregnation occurred at the edge of dissolution pores, and dolomite filled with bitumen was redissolved, indicating that buried dissolution has reformed the reservoir. Therefore, the superimposed area preserved in the fracture development area and the pre-existing pores represent a developmental area of constructive diagenesis and a favorable area for the development of high-quality reservoirs, thus controlling the enrichment area of the gas reservoir. (3) Location control accumulaiton A. The inherited paleo-uplift and paleoslope are favorable gas accumulation areas. The formation of the Sichuan Basin is mainly controlled by the evolution of the surrounding mountain system, which is closely related to the activities of the ancient Yangtze Plate. The division of the tectonic units in the entire Sichuan Basin shows that the main uplift belts are developed in western, central, southern, and southeastern Sichuan. The tectonic uplift of the Indosinian, Yanshanian, and Himalayan periods played a crucial role in the Leikoupo gas reservoir. During the Caledonian period, the basin was affected by large uplifts and depressions and the Leshan–Longnvsi and Tianjingshan paleo-uplifts and southern Sichuan Depression formed. From the Late Paleozoic to Middle Triassic, the basin was in

6.3 New Understanding of the Hydrocarbon Accumulation Theory

203

Fig. 6.24 Relationship between the paleo-uplift and large and medium-sized oil and gas fields, high-abundance gas reservoirs, and high-yielding wells in the Sichuan Basin (revised by Wang)

an extensional environment and the local area showed micro-paleo-uplift. At the beginning of the Late Triassic, the Indosinian paleo-uplift was formed in southern and eastern Sichuan and a depression was formed in western Sichuan. During the Yanshanian period, the Jiangyou–Mianyang and Daxing paleo-uplifts were formed (Fig. 6.24). High-abundance oil and gas reservoirs can form in inherited uplift zones. The Pengzhou Lei 43 sub-member and Xinchang Lei 43 sub-member gas reservoirs are located in the Yanshanian Daxing paleo-uplift belt of the Longmen piedmont belt. Nowadays, the Longmen piedmont and Xinchang tectonic belts have high tectonic locations, which is conducive to the accumulation of oil and gas. The Moxi and Wolonghe Lei 1 gas reservoirs are located at the slopes

of the Luzhou–Kaijiang paleo-uplift that was formed in the Indosinian period. The Moxi anticline has taken shape in the Late Triassic. It inherited the ancient tectonic pattern of the Indosinian period during the Yanshanian and Himalayan tectonic evolution. Moreover, the tectonic formation occurred earlier than the peak period of the hydrocarbon generation and discharge, which is conducive to the migration and accumulation of oil and gas. The Zhongba Lei 3 member gas reservoir is located in the Indosinian uplift belt of Tianjingshan and Yanshanian uplift of Jiangyou–Mianyang. The Zhongba structure was uplifted in the Indosinian period and the Yanshanian structure accepted sediment along with the regional subsidence. The Himalayan period is again raised with the Longmenshan nappe structure. During the

204

development of this topography, the Zhongba structure has maintained an uplift state relative to the surrounding area; it is an inherited paleo-uplift, which is beneficial to oil and gas accumulation. B. An effective source rock–fault–trap configuration is the key to natural gas enrichment. The trap types of the Leikoupo Formation gas reservoirs in the Sichuan Basin can be divided into two different categories: (1) the inner structure trap which is mainly controlled by the structure (Zhongba Lei 3, Moxi Lei 1, Wolonghe Lei 1); and (2) tectonic–stratigraphic (lithologic) gas reservoirs (Yuanba, Longgang, Pengzhou, Xinchang Lei 4). The trap formation occurred earlier than or at the same time as the peak period of hydrocarbon generation and hydrocarbon expulsion, ensuring that the generated hydrocarbon migrates to the trap. Previous studies showed that the formation of gas traps in the Leikoupo Formation of the Sichuan Basin occurred before the peak period of hydrocarbon generation and hydrocarbon expulsion and the relationship between the source rock and trap is good. For “source rock and reservoir not in the same layer” type reservoirs, the connection of hydrocarbon source faults with hydrocarbon sources and traps is the basis for a combined accumulation. An effective source–fault–trap configuration is the key to gas enrichment. The Pengzhou Lei 43 sub-member gas reservoir in western Sichuan is a “source rock and reservoir in the same layer & source rock below reservoir” assemblage. On one hand, the dark source rocks of the Leikoupo Formation continue to generate hydrocarbons. On the other hand, the Pengxian Fault communicated with the underlying Permian hydrocarbon source and the Pengxian Fault faulted down into the Sinian–Cambrian system and ended up in the Jurassic system. This is also conducive to the migration and accumulation of oil and gas in the uplift and slope zones. C. The degree of fracture is the key to high gas reservoir production. It is shown from previous studies that the natural gas production capacity positively correlates with the degree of fracture development. The development of fractures or faults improves the reservoir conditions of tight reservoirs and creates conditions for the enrichment of natural gas. It is also a channel for hydrocarbon migration and plays a role in communicating hydrocarbon sources. Most of the reservoirs in the Leikoupo Formation of the Sichuan Basin are deeply buried and generally dense and have relatively poor physical properties. Statistically, it is difficult to obtain high productivity, even in relatively

6

Reservoir Type and Spatial Distribution

high-quality reservoirs, without fracture superposition, which shows that the fracture development plays a crucial role in improving the reservoir performance and thus controls the scale of the gas reservoir. The Lei 43 sub-member gas reservoir of the Pengzhou gas field is located in the Longmen piedmont tectonic belt. Based on core and thin section observations, at least two stages of effective fracture formation occurred in this zone. Most of the first-stage effective fractures are perpendicular to the suture line, which is related to the formation of unconformity, tectonic uplift, denudation, and unloading. In this stage, fractures provide effective fluid pathways for supergene karst, thus leading to numerous karst pores and the redissolution of early pores, which makes up for the low porosity of the reservoir matrix, to some extent. The second stage of effective fracture formation occurred in the reburial stage. In this stage, the fractures were preserved as currently available reservoir space and provide a fluid passage for burial dissolution, resulting in thick and large reservoirs with good pore–fracture connectivities. The Lei 43 sub-member gas reservoir of Xinchang is relatively far away from the Longmen piedmont tectonic belt and the development degree of fractures is relatively low. The corresponding reservoir development is weaker than that of the Pengzhou gas field in the Longmen piedmont tectonic belt. The statistics regarding the reservoir thickness and gas reservoir size show that the reservoir thickness in wells YaS1 and PZ1 of the Pengzhou gas field is 104.15 m and 90.12 m, respectively. The natural gas reserves of the Jinma–Yazihe structural core area of the Pengzhou gas field are 111.295 bio m2 and the predicted natural gas reserves are 129.07 bio m2. The reservoir thickness of the Lei 43 sub-member gas reservoir of Xinchang in wells XS1 and XaS1 is 70.34 m and 49.5 m, respectively, and the predicted gas reserves are 79.534 bio m2. Based on the comparison of the statistical results, there is a good correlation between the reservoir thickness and gas reservoir scale, indicating that the fracture development is the key to gas reservoir enrichment.

6.3.3 Main Factors Controlling the Silurian Marine Shale Gas Accumulation

(1) “Sedimentary facies and preservation conditions” are prerequisites for the formation and selection of shale gas reservoirs. Sedimentary facies are the basis of shale gas accumulation and deepwater sedimentation is the premise of high-quality shale formation. Note that deepwater hydrostatic sediments,

6.3 New Understanding of the Hydrocarbon Accumulation Theory

205

such as lagoon, swampor shelf, but an environment rich in biomass and preserved conditions is the fundamental requirement for the development of shale source rocks. In addition, the shale of the main basins in the United States is widely distributed and the burial depth is moderate. Shale oil and gas can be found in shale-bearing locations. However, most of the shale strata in southern China underwent intensive tectonic transformation and the oil and gas preservation conditions are an important factor affecting the shale gas accumulation. For example, high-quality shale has been encountered in shale gas wells, such as Heye 1, in the Longmaxi Formation, but due to fault only little SOAG (show of oil and gas) was found and the formation produces freshwater due to fault damage. Although the Sangyuping syncline in the Pengshui shale gas field is small, drilling has confirmed that it has oil and gas preservation conditions. The formation water mineralization degree can reach 40–50 g/L and the water is of calcium chloride type. Therefore, the formation of shale gas reservoirs is not necessarily possible in areas with high-quality shale in southern China. Thus, the “sedimentary facies and preservation conditions” control the shale gas reservoir, which are the premises of the shale gas area selection.

sides of the Qiyueshan fault are the same, but the shale gas production significantly differs. Based on a comparative study of the carbon isotope composition and fluid inclusion homogenization temperature of wells Jiaoye 1 and Pengye 1 of the Lonemaxi Formation and the Middle and Lower Silurian wells Wuke 1 and Jianshen 1 in the adjacent area in combination with the analysis of the tectonic type, tectonic evolution, and oil and gas generation and migration times, high-yielding shale gas accumulation patterns were put forward for regions with complex structures, high evolution degrees, and late and strong uplifts (Guo 2014): ladder-like migration, anticline convergence, fault–slide-controlled fractures, and box-like accumulation. The patterns can be explained as follows: (1) The oil and gas supply range is large. Because of the low porosity and permeability and the lack of a regional unconformity surface and other transport systems, the sufficient gas sources depend on microfracture connection to achieve “ladder-like migration”; (2) Because the shale gas is mainly free gas, it undergoes multistage structural transformation and requires the dynamic balance of natural gas accumulation and dispersion. A positive structure with an anticline is the most favorable structure, that is, an “anticline (forward structure) is beneficial to natural gas convergence”; (3) To obtain a high and stable yield, interconnected fractures must be developed on a large scale in shale reservoirs. The combined action of the fault system and bottom slippage (“fault– slide-controlled fractures”) of the Longmaxi Formation (two-stage system) is conducive to the formation of network fractures and the maintenance of overpressure, which are the keys to the enrichment and high yield of shale gas; and (4) After the formation of the network fracture system, good top and bottom conditions are required to keep the gas reservoir intact. The argillaceous siltstone or silty mudstone in the upper part of the Longmaxi Formation and the dense limestone of the Jiancaogou Formation at the bottom of the Wufeng Formation provide good isolation. Together with lateral reverse faults, they form a closed box-like system, that is, they lead to “box-like accumulation.”

(2) The “tectonic type and tectonic process” control the shale gas enrichment and sweet spot selection. Shale gas accumulation, enrichment, and a high yield are the premises of commercial development. Guo and Zhang 2014; Guo and Zeng 2015; Guo 2016 repeatedly discussed the main factors controlling the shale gas enrichment and emphasized the effects of the tectonic type, tectonic processes, and mode of tectonic action on shale gas enrichment and preservation under the present tectonic conditions of shale gas preservation and distribution in southern China. The tectonic type determines the distribution of the enrichment zone, the tectonic processes control the enrichment mode (overpressure maintenance and fracture development mode, location and strength); thus, the shale gas enrichment depends on both the tectonic type and tectonic processes. Therefore, the accumulation and enrichment of Chinese shale gas are based on two aspects: reservoir control and enrichment control. The “sedimentary facies and preservation conditions” control the location of oil and gas reservoirs, that is, the selection offavorable shale gas areas. The “tectonic type and tectonic processes” control the enrichment of oil and gas reservoirs, that is, the selection of the sweet spot (enrichment zone) (Guo 2014, 2016; Guo et al. 2014). (3) High-yield enrichment mode of shale gas reservoirs The sedimentary environment, organic carbon content, thermal evolution degree, brittle mineral content, thickness, and buried depth of shale in- and outside of the basin on both

6.3.4 New Understanding of the Oil and Gas Geological Theory of Marine Carbonate Rocks in the Ordos Basin 6.3.4.1 The Accumulation in Lower Paleozoic Carbonate Rocks is Supplied by Two Sets of Hydrocarbon Source Rocks: Upper and Lower Paleozoic The natural gas accumulation in the Lower Paleozoic carbonate strata of the basin is supplied by two sets of hydrocarbon source rocks, that is, the Upper and Lower Paleozoic.

206

The distribution characteristics of the two sets of hydrocarbon source layers are different from each other. The large-scale and widely distributed coal-series source rocks in the Upper Paleozoic represent the first set of source rocks. They represent the main hydrocarbon supply of the Lower Paleozoic carbonate strata. The Lower Paleozoic marine strata represent the second set of source rocks. They include two hydrocarbon sources, that is, the Middle–Upper Ordovician hydrocarbon source in the southwest and the confined sea hydrocarbon source in the central and eastern basin. They also have a certain hydrocarbon generation capacity (Figs. 6.25 and 6.26). For the Lower Paleozoic reservoirs in the Ordos Basin, it is better to have characteristics of “source rock and reservoir in the same strata”. Even if there is only Upper Paleozoic hydrocarbon source rock, the amount of hydrocarbon generation is huge because it is a large area with widely distributed coal-bearing hydrocarbon source rock. The reservoir formation mechanism in the Jingbian gas field is very clear; it is a buried hill reservoir of “source rock above reservoir” type. Many buried hill reservoirs can be found in Renqiu, Dagang, Huanghua, and Shengli, which all are the combination of “source rock above reservoir” type. The source, reservoir, cover, trap, migration, and preservation are known including the weathering crust-type and fault system-type oil and gas migration channels. Important coal-bearing source rocks of the Upper Paleozoic The Early Carboniferous–Permian in the late Middle Paleozoic was the best coal-forming period in the Ordos Basin and northern China in general characterized by an extensive development of the coal strata of barrier lagoon, tidal flat, and delta plain swamp sediments. The coal strata are the main source rocks of the Upper Paleozoic in the basin and have a broad distribution pattern. The source rocks are mainly composed of coal, dark claystone, and limestone and are mainly distributed in the Upper Carboniferous Benxi Formation and Permian Taiyuan and Shanxi Formations. The cumulative thickness of the coal seam is 8–20 m; in the west and northeast of the basin, the thickness is >25 m. In the middle and south of the basin, the thickness mainly is 4–10 m. The organic carbon content reaches 70.8–83.2%. The coal strata represent one of the hydrocarbon source rocks that contributed the most to the generation of natural gas in the Upper Paleozoic. Dark claystone (mostly carbonaceous claystone) is influenced by the sedimentary facies. Except for the accumulated thickness of 200 m in Wuda and Weizhou, the thickness is generally 60–100 m in the west. In the east, the thickness is 100–140 m

6

Reservoir Type and Spatial Distribution

(generally 1.0%) and have good prospects of shale gas resources. The Wufeng and Longmaxi Formations have been commercially exploited for shale gas and the Fuling and Changning shale gas fields have been built. (1) Discovery and exploration of the Fuling shale gas field The Fuling shale gas field is in the west of the Qiyueshan fault at the eastern boundary fault of Sichuan Basin at the junction of several tectonic units such as the Shizhu synclinorium, Fangdoushan anticlinorium, and Wanxian synclinorium in the south of the barrier fold belt in eastern Sichuan (Guo and Liu 2013; Guo 2014). The Fuling shale gas field is a continuous shale gas reservoir with an elastic gas drive, middle–deep-buried stratum, high-pressure self-generation and self-storage. The discovery well Jiaoye 1 was deployed in 2011. The main reservoir is the Wufeng and Longmaxi Formations and the test gas production is 20.30
104 m3/d. Well Jiaoye 1HF has been producing for more than 540 days, with stable production and pressure. In the Jiaoshiba area, 106.75 bio m3 of proven shale gas reserves were reported to the state in July 2014. At the end of 2015, a total of 3805.98
108 m3 of gas reserves were reported, with a 50
108 m3 production capacity. By 2017, 100
108 m3 production capacity and 6008
108 m3 of proven reserves were reported. Therefore, the goal of industrial production of shale gas in the Sichuan Basin was achieved and a historic turning point was reached in the exploration and development of shale gas in China. (2) Discovery and exploration of the Changning shale gas field The Changning shale gas field is in the transition area between the low gentle fault–fold zone in the southern Sichuan Basin and the Lushan fold belt in the northern Yunnan–Guizhou Depression. It is affected by the west extension of the Chuandong fold– thrust belt in the north and by the Laoshan fold belt in the south. The gas-bearing area of this medium-deep, high-pressure,

7.2 Oil and Gas Discovery Process and Exploration Results in Sichuan Basin

self-generating, and self-storing continuous shale gas reservoir is 229.62 km2. The discovery wells are Ning201 and Wei201 and the main gas reservoir is the Wufeng–Longmaxi Formation. In August 2015, PetroChina Southwest Oil and Gas Field Branch reported 163.531 bio m3 of proven reserves of shale gas in the Wufeng–Longmaxi Formation of the Changning shale gas field including 136.18 bio m3 new proven reserves in the Ning201– YS108 well block of the Shangning Block and 27.351 bio m3 new proven reserves in the Wei202 well block of the Weiyuan Block (Zou et al. 2015). At present, there are 83 opening wells in the Changning– Weiyuan national shale gas industrial demonstration area in Sichuan. On January 13, 2016, the daily and annual production of shale gas in the demonstration area reached 7 million m3 and 2 billion m3, respectively. The production results are better than expected. The production that gives consideration to both size and benefit has been achieved.

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Progress and Theory of Marine Strata Oil …

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8

Wubaiti Gas Field

The Wubaiti gas field is the largest Carboniferous gas field that has been discovered in the Sichuan Basin. The first discovery well, that is, Tiandong 1, was completed in September 1989. Based on a test in the Carboniferous, natural gas reserves of 111.81
104 m3/d were reported. By the end of 1993, 12 evaluation and exploration wells had been completed. It was confirmed that the gas reservoir is a large-scale tectonic–lithologic stratigraphic composite trap gas reservoir with a gas-bearing range exceeding the closed line of the buried structure. The proven gas area and reserves are 140.45 km2 and 539.88
108 m3, respectively. The exploration is efficient with average reserve of 57.56
108 m3 for each exploration well (Zhang and Li 1992).

8.1

Basic Geological Characteristics

8.1.1 Structure and Trap Characteristics The Wubaiti structure is in Kaijiang and Kai counties in the eastern part of Sichuan Province. The structure which locates at the northeastern upper slope of the Kaijiang paleo-uplift in the eastern part of the Sichuan Basin, is the northeastern pitching end of Datianchi structural belt. It is a buried anticline structure with multiple high points and short-axis which has been complicated by faults (Fig. 8.1). The long and short axes are 26.0 km and 7.0 km, respectively. The altitude of high point is −3620 m.The closure is 1080 m with trapping area of 135.25 km2, respectively. The structure is box-shaped on the section and the lowest closed contour is −4300 m. The Wubaiti structure is in the vicinity of the Carboniferous erosion window. In the updip direction of the structure, the porous dolomite of the Carboniferous pinches out laterally and is sealed by the tight limestone. The Carboniferous outside the structural trap with well-developed

reservoir contains gas. The gas-bearing area of the Wubaiti Carboniferous system which exceeds the structural trap area makes a large-scale structural–lithologic stratigraphic composite trap of gas reservoir.

8.1.2 Carboniferous Division and Its Distribution In the Wubaiti area, the Upper Carboniferous Huanglong Formation (C2h) is separated from the underlying Silurian by a disconformity. Due to long-term weathering and denudation, the Silurian with uneven terrain is partially filled in by Upper Carboniferous. Meanwhile, affected by the paleogeomorphology, sediment thinning or hiatus occur. The top surface of the Carboniferous is an erosion surface that formed by Yunnan movement in Early Hercynian. After the deposition of Upper Carboniferous, the upper part of Upper Carboniferous was partially eroded during the weathering period over 15–20 Ma. The thickness of the Carboniferous ranges from 0 to 93 m. The strata overlying the Carboniferous are Middle and Lower Permian (P1–21) which are mainly argillaceous. The Upper Carboniferous Huanglong Formation can be divided into three lithologic sections, that is, limestone, dolomite, and limestone, from the bottom to the top (Table 8.1). These three sections are equivalent to the sediments of the lowstand, transgressive, and highstand system tracts, respectively. The characteristics of each lithological section are as follows: (1) First section of the Huanglong Formation (C2h1) Section of brecciated limestone and dolomite: The sediments overlie gray-green or variegated mudstone of Middle Silurian with thickness of 2.3–6.5 m. The lithology comprises a

© Geological Publishing House and Springer-Verlag GmbH Germany 2020 Y. Ma, Marine Oil and Gas Exploration in China, https://doi.org/10.1007/978-3-662-61147-0_8

229

230

8

500

86-D4G4 line 500

450

0

Wubaiti Gas Field

0

0

Yihechang

5000

Datian 2

3000

Tiandong 17

Datian 3

450

0

45

Tiandong 2

00

400

0

Tiandong 1 Tiandong 8

Wubaiti

340

0

Nanyachang 3700 Tiandong 21 4700

450

cross section of 86-D4G4 line

0

Well

Pinchout zone of Carbonifous Fault

City

Fig. 8.1 Schematic diagram of the composite structural–lithologic stratigraphic trap of Wubaiti structure (the top of the Carboniferous)

Table 8.1 Thickness of the Carboniferous sections in the Wubaiti structural belt Wells

C2h section

Thickness (m)

C2h2 section

Thickness (m)

C2h1 section

Thickness (m)

Tiandong 1

4212.5–4243

30.5

4212.5–4238.7

26.2

4238.7–4243

4.3

Tiandong 2

4433.5–4467

33.5

4433.5–4464.7

31.2

4464.7–4467

2.3

Tiandong 7

4595–4625

30

Tiandong 22

4456.5–4473.5

17

C2h3 section

4595–4599

Thickness (m)

4

4599–4621.8

22.8

4621.8–4625

3.2

4456.5–4470.7

14.2

4470.7–4473.5

2.8

Tiandong 11

4664.5–4696.1

31.6

4664.5–4688.5

25

4688.5–4695

6.5

Tiandong 15

4557–4587

30

4557–4582

25

4582–4587

5

Tiandong 16

5023–5058.5

35.5

5023–5053.9

30.9

5053.9–5058.5

4.6

Tiandong 17

4774–4797.5

23.5

Tiandong 21

4959–4996.5

37.5

4959–4962.3

3.3

4774–4789

19

4786–4797.5

4.5

4962.3–4991.5

29.2

4991.5–4996.5

5

8.1 Basic Geological Characteristics

231

combination of (degypsification) secondary limestone, (secondary) limy karst breccia, micritic dolomite, and argillaceous dolomite. (2) Second section of the Huanglong Formation (C2h2) Section of dolomite, granular dolomite, and breccia dolomite: Dissolution pores and vugs are developed in this section, which is in conformity contact with C2h1 with thickness of 19.0–31.2 m. It is the most abundant lithological section in the tectonic belt. The lithology comprises argillaceous or micritic-silty dolomite, fine-crystalline dolomite, cryptomonad dolomite, and various types of granular muddy fine-crystalline dolomite interbedded with dolomite karst breccia and micritic dolomite (mudcrack or mudcrack breaking), dolomite karst breccia, and, locally, thin layers (secondary) of limestone. In the fine-crystalline dolomite, all types of granular dolomite and dolomite karst breccia, various types of solution pores, vugs, and fracture-caves which are semi- or incompletely filled are developed with good porosity. This section is an important kind of reservoir.

8.2

Basic Characteristics of the Reservoir

The main producing layer of the Wubaiti gas reservoir is the second lithologic section of the Huanglong Formation (C2h2), which is mainly dolomite in tidal flat environment, with limestone in the middle parts. The thickness varies greatly, ranging from 8.5 to 37.4 m. The reservoir space is mainly of fracture-pore type, with porosity ranging from 4.4 to 8.1% and an average of 6.04%. The average permeability is 0.77
10–3 lm2. The average fracture rate is 0.22%. The matrix permeability ranges from 0.01 to 22
10–3 lm2 (the characteristic parameters of permeabilities under confining pressure are shown in Table 8.2), and the fracture permeability varies from 0.62 to 9.18
10–3 lm2. Statistics of the relationship between the lithology and porosity based on 13 wells show that the granular dolomite (including bioclastic dolomite and doloarenite) has the highest porosity, mainly ranging from 2 to 10%, with an average of 6%. The brecciated dolomite has a porosity of 2– 6%, with an average of *4%. The porosity of crystalline dolomite mainly ranges from 2 to 8%, with an average value of *5%. The limestone porosity is the lowest, mainly ranging from 0.5 to 3%, with an average of *1.5%.

(3) Third section of the Huanglong Formation (C2h3) Section of limestone, granular limestone, and breccia limestone: This section is in conformity contact with the C2h2 section. Most of the section is missing except the Tiandong 7 and Tiandong 21 wells with a thickness of 3.3–4.0 m. The rest of the section was eroded. The lithology is dense microcrystalline limestone, micritic-powdered granular limestone interbedded with limy karst breccia and local micritic dolomite, fine-crystalline dolomite, and granular dolomite. The upper and top parts are dominated by limy karst breccia. It is separated from the overlying Middle and Lower Permian Liangshan Formation, which is dominated by black claystone and shale, by a parallel unconformity.

8.2.1 Main Reservoir Space Type 8.2.1.1 Pores

(1) Intercrystalline pores and intercrystalline dissolution pores: these pores are commonly associated in the fine-crystalline dolomites. Based on the statistical results, intercrystalline dissolved pores is the main pore type of the fine-crystalline dolomite. They are preserved from the intercrystalline pores that formed by the dolomitization and undergo various dissolution and

Table 8.2 Characteristics of the Carboniferous reservoir under the confining pressure of the Wubaiti structural belt No

Wells

Samples

Well depth (m)

Lithology

Physical property

Permeability under confining pressure

Porosity (%)

Permeability (
10–3 lm2)

Effective stress (MPa)

Permeability under geological conditions (
10–3 lm2)

Permeability reduction (%)

1

Tiandong 7

118

4608.52

Brecciated dolomite

4.01

0.083

72.62

0.0083

90

2

Tiandong 7

93

4605.6

Brecciated dolomite

2.79

0.015

73.57

0.0006

96

3

Tiandong 11

49

4668.89

Brecciated dolomite

3.6

0.036

74.58

0.00126

96.5

4

Tiandong 11

137

4677.95

Fine–silty dolomite

8.69

0.225

74.73

0.0225

90

5

Tiandong 11

162

4679.8

Bioclastic dolomite

7.4

3.2

74.75

1.92

40

6

Tiandong 11

241

4687

Bioclastic dolomite

6.01

0.0462

74.87

0.0051

88.96

232

transformation processes during the diagenesis (Zhang and Fu 1993). (2) Inter- and intraparticle dissolved pores: these pores are only observed in granular dolomites. The intergranular dissolved pores have weak dissolution in the early stage according to cathodoluminescence observations. The luminescence of the cement is discontinuous. This phenomenon was not observed in intragranular dissolved pores. These two pore types mainly developed in the karst stage. Inter- and intragranular dissolved pores are the main types of reservoir space (Zhang and Fu 1993). (3) Dissolved pores: these pores related to biology are only found in foraminifera-dolomites but not in foraminifera-limestone. (4) Dissolved pores in inter- and intrabreccia: this type of pores is mainly found in karst breccia but not in breccia caused by drying cracks. The pores in the intrabreccia, such as fine-crystalline and granular dolomite breccia, are caused by meteoric water in the epidiagenetic stage. The interbreccia dissolved pores modified by karstification are not filled with interstitial material. These breccia represent another important type of reservoir space in the region.

8.2.1.2 Vugs Vugs are mainly *0.3–1 cm in size and often filled with freshwater dolomite partially. 8.2.1.3 Fractures Fractures mainly include structural fractures. Based on the core fracture statistics, the effective fracture density is 2.1– 20.9 m−1, with an average value of 9.6 m−1, and the fracture distribution is heterogeneous. The fractures at the top of the structure and in the axial region are more developed. 8.2.1.4 Combination of Reservoir Space The statistics based on the casting thin section observations indicate the presence of the following types of reservoir space combinations in the Carboniferous reservoirs: (1) Combination of intergranular, intragranular, and intercrystalline dissolved pores, with common fractures: this combination mainly comprises intergranular dissolved pores, followed by intragranular dissolved pores. A small amount of intercrystalline dissolved pores can be found. The granular dolomite in this area mainly includes such pores. (2) Combination of intercrystalline dissolved pores, intercrystalline pores, and intra- and intergranular dissolved pores, with common fractures: this combination mainly comprises intercrystalline dissolved pores, followed by

8

Wubaiti Gas Field

intercrystalline pores. A small amount of intra- and intergranular dissolved pores can be found. This combination is mainly found in strongly cemented granular dolomite. (3) Combination of intergranular dissolved pores, vugs, and intercrystalline pores, with common fractures: This combination mainly comprises intercrystalline dissolved pores, followed by vugs, intercrystalline pores, and common fractures, representing a common type of pore combinations of fine-crystalline material. (4) Combination of interbreccia pores, intrabreccia dissolved pores, and dissolved pores, with large dissolution pores and fractures: Interbreccia and intrabreccia dissolved pores with abundant solution pores, vugs and fractures are relatively developed in this combination, which is common for dolomite karst breccia.

8.2.2 Relationship Between the Porosity and Water Saturation The porosity–water saturation diagram for the gas wells (Fig. 8.2) shows that the two parameters are exponentially negatively correlated, that is, as the porosity increases, the water saturation decreases. This feature reflects the accumulation of natural gas in the Carboniferous reservoirs mainly from secondary migration is based on a certain amount of gas water differentiation.

8.3

Main Factors Controlling the Reservoir

The development of the Carboniferous reservoirs of the Wubaiti structure was controlled by the lithology, sedimentary facies, diagenesis, and tectonic activities. The sedimentary facies controlled the distribution of the lithology. Dolomitization was the basis of the reservoir pore development, and karstification was the key to expanding the reservoir range and improving the reservoir quality. The tectonic activities led to the increase in the reservoir permeability. (1) Lithology and facies The reservoirs in this area mainly developed in granular dolomite, fine-crystalline dolomite, and dolomite karst breccia. The pore type and characteristics of the three reservoir rock types differ, reflecting the influence of different original sedimentary fabrics, which is most notable in the granular dolomite and dolomite karst breccia. The fine-crystalline dolomite is related to the environment and dolomitization. The distributions of the granular and

8.3 Main Factors Controlling the Reservoir

233

lagoon, and intertidal flat. The rock types principally include granular dolomite, fine-crystalline dolomite, and dolomite karst breccia. The sedimentary facies and rock types are favorable for the formation of reservoirs. Based on the comprehensive map of the Carboniferous gas reservoir in the Tiandong 1 well (Fig. 8.3), most of the C2h2 section can be treated as good and great reservoir except some intervals with poor porosity and permeability.

100 Tiandong 1 well, Tiandong 2 well and Tiandong 3 well

Sw (% )

80 60 40 20

(2) Diagenesis 0

2

4

6

8

10

12

14

16

φ (%)

Fig. 8.2 Relationship between the porosity and water saturation in the Wubaiti structure

fine-crystalline dolomite were controlled by the sedimentary facies. The sedimentary environment of the granular dolomite was a high-energy shoal and tidal channel. Fine-grained marl was removed and coarse-grained intraclasts were deposited by the winnowing and transformation of waves and tides. Thus, the original porosity was high. The shoal and tidal channels were favorable environments for the development of granular dolomite reservoirs. Fine-crystalline dolomite was mainly deposited in a restricted lagoon environment. Although the water energy was low in this environment and there were little grains, it was beneficial for dolomitization under evaporation conditions. The seawater with high salinity caused the dolomitization of the sediments and intercrystalline pores developed in the dolomite. In the later uplift exposure stage, many dissolved pores were formed in the fine-crystalline dolomites, leading to a better reservoir (Table 8.3). The C2h2 section is a barrier coastal sedimentary system in TST. The sedimentary facies are mainly barrier beach,

Diagenesis favorable for Carboniferous reservoir development mainly includes metasomatism and dissolution. During the sedimentary period, due to exposure and evaporation, the shoal facies sediments can form karst and dolomization (mixed dolomization) in the syngenetic and quasi-syngenetic stages. After the sedimentary period, the karstification of the epigenetic period caused by the early Caledonian movement not only superimposed the early exposed dissolution development zone but also modified the early dissolution of the undeveloped zone, generating crystalline dolomite. Dissolved pores were further developed. Karstification had a great impact on the reservoir. For example, the thickness of a single layer of dolomite karst breccia is generally *1–3 m. The cumulative thickness can reach 5–10 m and the porosity is 2–6%, with an average of 4%, representing good reservoir. According to the karst development characteristics, the karst effect is stronger in areas with good original porosity and permeability and vice versa. The change in the karst distribution is caused by the episodes of the uplift of Carboniferous strata. The original submerged zone rises into a seepage zone, which increases the depth of the karst to penetrate the entire Carboniferous system, causing two reservoir development sections including the upper and lower zones.

Table 8.3 Relationship between the sedimentary environment and porosity (%) Facies

Shoal

Intertidal sandy flat

Lagoon

Intertidal mudflat

Supralittoral zone

Rock type

Sandy– burrow dolomite

Silty– sandy dolomite

(Algae breccia) Sandy dolomite

(Grain) Silty dolomite

(Desiccation) Breccia dolomite

(Algaeclastic) Silty mudstone

Degypsumization limestone

(Quartzic arenaceous) Silty mudstone

Tiandong 1

8.5

5.65

8.38

6.83

3.87

4.72

1.06

3.22

Tiandong 2

8.2

6.84

6.32

5.44

5.9

4.63

1.68

1.81

Tiandong 7

6.5

6.85

5.09

3.65

3.94

2.93

1.51

1.78

Tiandong 11

5.3

2.26

4.5

1.07

2.57

Weighted mean

7.25

5.2

4.7

3.33

6.24

5.2

4.35

1.81

234

8

0 50

35 500

5 000

Test

Facies

(Ω · m)

Reservoir

60 2.55 2.65 9

(μs ft)

(%)

Sw

K

Lithofacies

30

(g cm3)

R11 5

Depth/m

(API)

R11 d

DT

N

Series

GR

Wubaiti Gas Field

(%) 0

4

8

12

( 16

20 0

10 2μm2) 2

4 0 20

(%) 60 100

P11

104m3 d =111.81 R open hole

supratidal

intertidal

lagoon

27.4 19.5 8.04 6.15

72.8 6.73

barrier beach

C22

24 8.37

34.9 24.1

lagoon

barrier beach

supratidal intertidal

barrier beach

non coreing

4 212.5

3.32 4.04 22.0 0.7 28.4 31.3 48.0 6.35 5.17 13.0 68.7

evaporate flat in supratidal zone

4 238.5

C21

4 243

S

Fig. 8.3 Comprehensive map of the Carboniferous gas reservoir in the Tiandong 1 well in eastern Sichuan Basin

8.4

Analysis of Gas Source Rocks

The d13C2 of the Carboniferous gas reservoir is lighter (−40 to −35), while the d13C2 of the Lower Permian gas reservoir is heavier (−34 to −32‰). Compared with lower Permian and Silurian bitumen, the infrared spectra and aromatic ultraviolet spectra of Carboniferous reservoir bitumen are different from lower Permian and similar to Silurian

bitumen. The distribution of biomarkers in the Carboniferous reservoirs (Sterane, Terpane) and Silurian is also comparable; however, significant differences were observed when compared with the Lower Permian, Cambrian, and Sinian. Therefore, the gas of the Wubaiti gas field may mainly originate from the underlying Silurian system. The underlying Silurian source rock with sapropel-type kerogen, TOC value of 1.2%, Ro value of *2.5%, is great source rock.

8.5 History of Gas Migration and Accumulation

8.5

History of Gas Migration and Accumulation

(1) History of oil generation, oil discharge, and exhaust from source rocks The Silurian source rocks began to enter the oil-producing threshold at 210 Ma (Late Middle Triassic) and were at the peak of the oil production at 180–165 Ma (Early and Middle Jurassic period). The oil discharge threshold and the peak of oil discharge were reached at 175 Ma and 170–150 Ma, respectively. The Silurian source rocks generally started to generate gas at 171 Ma (Early Middle Jurassic) and reached the peak of gas generation at 169–159 Ma (Middle Jurassic); the exhaust of gas from source rock is at 167 Ma, and approached the peak stage between 166 and 161 Ma. (2) History of hydrocarbon accumulation The numerical simulation results for the oil and gas migration show that the oil began to accumulate in the Kaijiang paleo-uplift at *172 Ma. The oil accumulation reached a peak quickly, forming an ancient oil reservoir at 172– 165 Ma. Based on the continuous supply of gas, a large amount of gas displaced the accumulated crude oil in the trap at 165–160 Ma. At 150 Ma, the Carboniferous reservoirs reached *5000 m in depth and a high ground temperature. The crude oil that had accumulated over a relatively long period of time was cracked into natural gas. Except for local areas, the Carboniferous reservoirs were basically free of crude oil accumulation after 150 Ma and mainly charged by gas. The crude oil and gas accumulation curves of different structural parts of the Carboniferous reservoir show that the accumulation history of crude oil in the high structure is short. The peak of gas accumulation occurs earlier, and the time to reach the accumulation peak is short. This shows that the gas was mainly originated from source rocks that have displaced the crude oil that already accumulated in a short period of time. In the lower part of the reservoir structure, the oil accumulation lasts a long time. The peak of gas accumulation (150–135 Ma) is generally later than the exhaust of the source rock (166–161 Ma), and the gas accumulation lasts a long time, indicating that this part of natural gas is mainly formed by cracking of the oil that has been accumulated. The natural gas accumulation history of the Wubaiti Carboniferous gas reservoir can be divided into two stages. In the first stage between 160 and 165 Ma, the gas that was discharged from the source rock displaced the already accumulated crude oil. This portion of the gas is mainly concentrated in the high structure. In the second stage from

235

160–135 Ma, the accumulated crude oil was cracked into natural gas. The following transformation occurred: ancient oil reservoirs ! ancient oil and gas reservoirs ! ancient gas reservoirs. (3) Influence of stratum erosion and fault activity on the hydrocarbon accumulation After the source rock was deposited, five regional uplift and stratigraphic erosion processes occurred in the eastern Sichuan region, resulting in oil and gas losses. Multiple movements occurred in some faults in study area. The tectonic activities of the Himalayan period (at 28– 20 Ma) affected the preservation of the gas reservoirs, such as the amount of gas aggregation decreased in reservoirs due to the activities of nearby faults. These fault activities are consistent with the regional uplift and erosion of the stratum. Therefore, the opening of faults increased the loss of accumulated natural gas. However, the faults stay closed from 20 Ma to the present so that the undiscovered natural gas could be preserved to form the distribution pattern of the current natural gas reservoirs.

8.6

Main Controlling Factors

(1) Prolific source of petroleum The Carboniferous system in eastern Sichuan is a set of sediments in tidal flat. The lithology mainly comprises breccia dolomite with dissolved pore interbedded with limestone, providing very poor hydrocarbon generation conditions. Previous studies have confirmed that the main gas source of the Carboniferous in eastern Sichuan is the underlying Silurian source rock. The Silurian system is 500– 600 m thick in this area. The source rock is *300 m thick, mainly comprising black shale with an average organic carbon content of 0.48%. Based on the latest research results, the total hydrocarbon generation of the Silurian source rocks in the eastern Sichuan Basin (converted to natural gas) is 1745
1012 m3 and the average hydrocarbon generation intensity is 33.56
108 m3/km2, indicating that the Silurian oil and gas sources are extremely abundant. This is the basis for the enrichment of the Carboniferous natural gas in the Wubaiti gas field. (2) Good reservoir Previous studies showed that the area including the Wubaiti buried structure is an inherited paleo-uplift belt. The Caledonian movement caused long-term sedimentary discontinuities in the area, and formed uplifts and geomorphic high

236

zones in some areas. The central uplift belt formed along the Kaijiang and Liangping areas divides the Carboniferous into two parts, east and west. The Wubaiti structure is located on the northeastern edge. In terms of the thickness of Carboniferous, the Datian 1 and Deng 1 well in the uplift zone are 6.5–14.5 m thick, the Tiandong 7 and 21 wells in the slope zone are 27–37.5 m thick, and the Men 2 and Yunan 3 wells in the southeast are more than 50 m thick. The stable distribution of porous reservoirs is one of the important factors controlling the formation of large gas fields. The Carboniferous in the Wubaiti area is tidal flat sedimentary environment. It experienced a large sea level undulation which resulted in the alternation of lagoon, lagoon shoals, evaporation flats, and algal flats. Micrite carbonate with grained clast and bioclast interbedded with little gypsum salt and argillaceous sediments deposited during this period. In the tidal flat environment, the sediments undergo complete leaching, dissolution, and alternating of salty and freshwater due to the frequent exposure of the sediment surface, which promotes the dolomitization of the sediments in the Early Carboniferous. At the end of the Carboniferous, the Yunnan (Hercynian) movement exposed the Carboniferous system for a long time. The erosion and leaching of Carboniferous resulted in many dissolved pores and vugs, which further optimized the pore structure and reservoir system and led to a set of reservoir rocks dominated by doloarenite, brecciated dolomite with dissolved pore, and fine-grained crystalline dolomite. (3) Good sealing and preservation conditions The Wubaiti Carboniferous gas reservoir has a height of 1080 m and filling degree up to 100%. The ability to close such a high gas column is mainly attributed to two sets of cap rocks. One is the direct cap rock of the Carboniferous trap. The argillaceous rocks of Liangshan Formation in Middle and Lower Permian are 10–15 m thick and homogeneously distributed. There is a significant difference of pressure between the Carboniferous reservoirs and Liangsan mudstone, and the displacement pressure is large. The capping conditions are good; the other cap rock is the indirect well preserved cap rock above the direct cap layer (including the gypsum-salt layer of the Jialingjiang Formation). The fold strength of the Wubaiti buried structure is low–medium. The faults are of small scale, and the structure is relatively complete. The exposed stratum is mainly Jurassic argillaceous rock. Vertically, from Feixianguan Formation in Lower Triassic to Maokou Formation in Middle and Lower Permian, the overlying strata have high pressure coefficient. According to the drilling fluid density and display conditions, the pressure coefficient of the Maokou Formation

8

Wubaiti Gas Field

reached 1.65, which proves that the indirect cap rock is well preserved. (4) The Indosinian paleo-uplift is beneficial for Carboniferous hydrocarbon enrichment The Indosinian movement at the end of the Middle Triassic was a crustal movement dominated by vertical elevation and lateral compression. In Sichuan Basin, large-scale uplifts occurred such as the Luzhou paleo-uplift in the southwest of the basin. The uplift amplitude of the Kaijiang paleo-uplift is greater than 400 m. The Wubaiti structure is located on the northeastern slope of the paleo-uplift. It has the opportunity and location for capturing oil and gas preferentially (Fei 1989). The gas in the Carboniferous gas reservoirs originates from the Silurian, and the source rocks have entered the mature stage and gradually generate abundant gas. Simultaneous with the vertical migration of oil and gas, the second migration started. Oil and gas accumulated in favorable reservoirs to form enrichment zones around the paleo-uplift. (5) The large-scale structure-lithologic stratigraphic composite trap is conducive for gas fields The Wubaiti buried structure is on the east side of the northeast-tilting end of Datianchi structural belt. The bottom structure of Lower Permian is a northeast-oriented short-axis anticline. The northeastern end of the structure is stretched, while the southwest end converges. The southeastern wing slowly descends to the southeast at an inclination of 8°–10°. The northwestern flank of the structure is enclosed in the footwall of No. 2 fault. The minimum closure depth of the structure is −4400 m, and the closure is 700 m. The long axis is 24.0 km, and the short axis is 4.2 km with closed area of 83.2 km2. The Yihechang structure is a high point at the north dip end of the main structure of Datianchi structural belt. The closure depth is −3700 m, and the closure is 80 m with closed area of only 1.5 km2, which is separated from the Wubaiti structure by No. 2 fault. However, the No. 2 fault throw at the northeastern end of the structure is only 40–50 m, which has no separation effect on oil and gas system. Hence, the above-mentioned two structures belong to one pressure system. The Wubaiti Carboniferous gas reservoir is a tectonic– lithologic composite gas reservoir (see Fig. 8.1) (Zhang 1993). The trap are limited by structural contour lines on the southeast and northwest sides, and the Carboniferous pinchout zone as the sealing condition on the southwest side. The pinchout zone extends from Dayian 1, Deng 1 to the southern end of Wushankan structure and crosses the northern end of Dayianchi structure. The gas trap extends from the Deng 1 well at the southern end to the Tiandong 15 well at the

8.6 Main Controlling Factors

northern end, with a long axis of 26 km. The east–west section extends from the Datian 2 well to the Tiandong 21 well, with a short axis of *8.5 km. The minimum closure depth of the composite trap is −4700 m and the closure area is 161.45 km2 (including the Yihechang structure). The large-scale oil and gas migration in the eastern Sichuan region started from the Yanshanian-Himalayan period. The Wubaiti structure is an inherited fold (uplift) with great conditions for capturing oil and gas in time and space. In conclusion, Carboniferous gas is enriched in the Wubaiti gas field. In addition to abundant hydrocarbon sources, good reservoir and capping conditions, two aspects are important: first, the Wubaiti structure locates at the overlapping parts of the inherited paleo-uplift and the present structure. The development of uplift match with the evolution history of hydrocarbon source forms a superimposed arrangement of ancient and modern gas reservoir with high fullness of oil and gas Secondly, the fold is moderate

237

and the composite trap area formed by the structure and Carboniferous system is large (up to 161.5 km2). The preservation conditions are good, which is important for the formation of the Wubaiti gas field.

References Fei H (1989) an approach of micro-geomophic characteristics and distribution regular of oil—gas pools of carboniferous in East Sichuan. Pet Geol Mar Sediment Area 3(1):85–91 Zhang G (1993) Classification and character study of carboniferous gas reservoir in East Sichuan. Nat Gas Ind 13:33–41 Zhang R, Fu J (1993) Discriminating the pore types of carbonate reservoir in carboniferous in East Sichuan. Nat Gas Ind 13(6): 35–41q Zhang G, Li Z (1992) Depending on scientific and technical progress to efficiently develop the gas fields in East Sichuan. Nat Gas Ind 12(4):37–44

9

Puguang Gas Field

9.1

Location and Geological Setting

9.1.1 Location The Puguang gas field is located in Xuanhan County in the Sichuan Province. This gas field is in the middle–low mountainous area with a ground elevation of *300–900 m. Overall, the terrain is steep and the relative height difference is 20–200 m. The climate is warm and humid, with an average annual temperature of 13.4 °C, a minimum temperature of −5.3 °C, and a maximum temperature of 41.3 °C. The climate is characterized by rain in spring, drought in summer, waterlogging in autumn, and arid winters. The region is rich in products, rural roads are crisscrossing the area, and transportation is convenient, which is beneficial for the exploration and development of gas fields.

9.1.2 Geological Setting 9.1.2.1 Stratigraphic Characteristics The main reservoirs of the Puguang gas field are the reef– shoal complex dolomite of the Upper Permian Changxing Formation and oolitic shoal dolomite of the Lower Triassic Feixianguan Formation. Outcrop and drilling data reveal that the stratigraphic system in the Daxian–Xuanhan area developed normally. The Lower Paleozoic is continuously deposited, and only the Upper Silurian system is missing. The Devonian and Lower Carboniferous are missing in the Upper Paleozoic, and only the Upper Carboniferous Huanglong Formation is present. The Permian deposition is complete. The Triassic, Jurassic, and Lower Cretaceous are intact, but the Upper Cretaceous is absent. The Cenozoic has few sediments remained (Table 9.1, see also Table 2.1). Affected by regional tectonic movement, several unconformity surfaces developed among the strata (see Chap. 1

and Fig. 1.6). For example, parallel unconformity surfaces can be found in marine strata between the Silurian and Carboniferous, Carboniferous and Permian, and Middle Permian and Upper Permian, which are due to the Caledonian, early Hercynian (locally also known as Yunnan movement), Hercynian, and Dongwu movements. Due to the Indosinian movement, which occurred at the end of the Triassic, the whole Sichuan Basin was uplifted and resulted in the Mesozoic lake–delta–river deposition dominated by continental clastic.

9.1.2.2 Structure The Puguang gas field is located in the northeastern part of the Sichuan Basin. It is located in the northeastern section of the East Sichuan fault–fold belt, and on a nasal structure of the Shuangshimiao–Puguang northeast-trending belt (Fig. 9.1). The western part of the tectonic belt is controlled by three faults and the eastern part is adjacent to the northwest-oriented Qingxichang–eastern Xuanhan and Laojunshan tectonic belts. The Puguang gas field experienced three-stage tectonic deformation during the Yanshanian and early and late Himalayan movements, which led to the formation of two groups of structures (i.e., north–northeast and northwest). Overall, strong folds and fault developed. The most important slip layer in the longitudinal direction is the upper part of the Jialingjiang Formation and lower part of the Leikoupo Formation. The Silurian shale constitutes the secondary slip layer, forming the upper, middle, and lower deformation layers (Fig. 9.2). The shallow layers are incompatible with the deep layers because of tectonic deformation. The lower deformation layer, including the Sinian– Ordovician, is mainly composed of carbonate and clastic rocks. Because the Silurian and Lower Cambrian are the top and bottom slip layers, the tectonic deformation is weak, the undulation is gentle; anticlines are occasionally extremely wide and gentle; and thrust faults are less developed.

© Geological Publishing House and Springer-Verlag GmbH Germany 2020 Y. Ma, Marine Oil and Gas Exploration in China, https://doi.org/10.1007/978-3-662-61147-0_9

239

Lower Paleozoic

Silurian

Carboniferous

Middle

Middle

Lower

Upper

Permian

Upper Paleozoic

Black shale, claystone with lithic sandstone, coal seam in the middle to upper parts; gray, block-like fine-grained lithic sandstone interbedded with dark gray, gray claystone; coal seam in the middle to lower part, black shale in the bottom

468–1000

12–333 55–590 32.5–243 88–673

100–230 99–211

T3x

T32l T22l T12l T4-5 1j

T31j T21j

Third Second First Fourth– fifth Third Second First

Grey chert limestone with a chert layer and black shale at the bottom

Dark gray limestone with siliceous material on the top and argillaceous limestone in the lower part Dark gray limestone with chert nodules

91–210

181–270 100–130

Hanjiadian

S2h

C2h

P1-2l

Liangshan

Huanglong

P1-2m P1-2q

Maokou

Qixia

P3l

Longtan

Gray biogenic limestone and/or dissolved- pore dolomite with chert layer

92–240

P3ch

Oolitic dolomite and gray limestone (locally); gray limestone purple-gray marlstone and oolitic limestone in the upper parts (locally)

400–640

T1f1-3

Third– first

Black shale with sandstone Dolomite with limestone

Gray-green, brown-gray sandy, silty claystone; claystone; black, dark gray shale

5.5–7.5 5–70

600–900

Gray-purple claystone and anhydrite, gray dolomite

25–74

T41f

Fourth

Interbedded layers of dark gray, purple-gray limestone and marlstone

263–382

T11j

Dolomite, doloarenite, intercalated with anhydrite

Gray dolomite with anhydrite and doloarenite

Anhydrite and salt rock interbedded with dolomite, gypsum-dolomite, dolo-limestone, and lime-dolomite. Mainly composed of gypsum in the upper part and dolomite with ooids and doloarenite (locally)

Anhydrite with dolomite and doloarenite, Hydromica clay rock; (altered tuff) at the bottom

Dark gray dolomite, limestone interbedded with anhydrite

Dark gray limestone and dolomite with anhydrite limestone

Taupe coquina at the top, gray-green, gray claystone interbedded with gray lithic sandstone

253–464

J1z

Changxing

Feixianguan

Jialingjiang

Leikoupo

Middle

Lower

Xujiahe

Ziliujing

Shelf

Shallow platform with intertidal zone

Shoreland

Shallow platform

Shallow platform

Shallow platform with intraplatform depression

Shelf– shallow platform

Shelf– platform margin–platform

Evaporate platform

Platform

Intertidal zone

Platform

Intertidal zone

Intertidal zone

Intertidal zone

Shoal, intertidal zone

Braided river delta

Lacustrine and fluvial facies

Shallow lake and lakeshore facies

Brown and gray claystone interbedded with light gray, gray-green fine–medium lithic sandstone, unequal in the middle to lower parts, dark gray and black shale in the middle

274–504

J2q

Qianfoya

Lacustrine and fluvial facies

Brown-purple mudstone and fine-grained lithic feldspar sandstone, unequal thickness, black shale at the top and thick sandstone at the bottom

327.5–530

J2x

Shallow lake and fluvial facies

Brown-purple claystone and gray-green lithic feldspar– quartz medium- and fine-grained sandstone interbedded with calcium matrix

13.5–2273

Lower Shaximiao

Shallow lake and lakeshore facies

Brown-red claystone with fine-grained lithic sandstone

310–420

J2s

Shallow lake and fluvial facies

Brown- gray, brown- red claystone and brown-gray, purple lithic feldspar sandstone

Shallow lake and fluvial facies

Lithofacies characteristics

600–1000

Upper Shaximiao

Upper

Lower

Middle

Mesozoic

Triassic

J3s

Suining

Mesozoic

J3p

Penglaizhen

Upper

Jurassic

Lithological description Brown-red claystone and gray-white lithic feldspar quartz sandstone

Thickness (m) 680–1100

K1j

Code

Jianmenguan

Section

Cretaceous

Formation

Mesozoic

Series

System

Era

Table 9.1 Stratigraphy of the Xuanhan–Daxian area

Hercynian orogeny (Sichuan and Guizhou Shallow platform with intraplatform depression

Early stage of the Indo-China orogeny

Middle stage of the Indo-China orogeny Early stage of the Indo-China orogeny

Early stage of the Yanshan orogeny Late stage of the Indo-China orogeny

Late stage of the Yanshan orogeny Middle stage of the Yanshan orogeny

Tectonic events

Chuanyue83 Chuanyue84 Chuanfu85 Shuangshi1 Puguang1 Puguang2 Puguang3 Puguang4 Puguang5 Puguang6 Puguang7 Maoba1 Maoba2 Maoba3 et al.

Outcrop data

Source

240 9 Puguang Gas Field

9.1 Location and Geological Setting

241

The central deformation layer is a high-strain layer consisting of the Silurian–Middle Triassic, that is, Middle and Lower Triassic gypsum-salt rocks, limestone and dolomite, Permian and Carboniferous limestones, and Silurian shale. The Silurian shale and fourth and fifth sections of the Jialingjiang Formation, representing the main slip layer, contain multiple secondary slip layers, which are characterized by the interbedding of strong and weak layers. The structure is characterized by a series of reverse faults and associated folds, forming a shingle slip-on belt. The reverse faults are steep and slow. They disappear in the Silurian shale layer or cut down the Sinian–Cambrian system and disappear on the slip surface of the cover layer and base. During the detachment and slippage along different slip surfaces, reverse faults often form for adjustment. The upper deformation layer, which includes the Leikoupo Formation as the slip layer, is mainly developed in the continental sequence and characterized by high and steep fold deformation.

Third stage (1981–1990): Structural survey, detailed construction of local structures, and deep exploration stage With the major breakthroughs in the natural gas exploration in the eastern Sichuan region in the 1980s, the Daxian and Xuanhan areas became an oil and gas exploration hot spot areas. A two-dimensional (2D) digital seismic survey covering the whole area was carried out. The survey network extended over an area of 2 km  4 km. The detailed seismic investigation of the Dongyuezhai structure was completed, and the measured network reached 1.5 km  1.5 km. Three-dimensional (3D) seismic exploration (25.6 km2) was carried out in the Shuangmiaochang (Leixi) structure. The well of Chuanyue 83 was deployed in the Dongyuezhai structure and a fracture-type gas layer was discovered at 4719.7–4727 m of the second section of the Lower Triassic Feixianguan Formation. The daily gas production was 13.97  104 m3. The Dongyuezhai gas-bearing structure was discovered. In the Shuangshimiao structure, the wells of Shuangshi 1, Leixi wells 1 and 2 were completed by deep drilling through the Carboniferous system.

9.2

Fourth stage (1991–1999): Relative stagnation stage In the early 1990s, 11 2D seismic lines were implemented in Qingxichang, covering an area of 1.5 km 1.5 km. The wells of Chuanyue 84, Chuanfu 85, and Qili 23 were drilled in the Dongyuezhai, Fujiashan, and Xuanhandong structures, respectively, but no substantial breakthroughs were achieved. The oil and gas exploration entered a stagnant stage in the mid–late 1990s.

Gas Field Discovery

The large-scale oil and gas exploration in this area started in 1955 and can be divided into six stages (Ma et al. 2005b; Ma 2006): First stage (1955–1959): Oil and gas geological survey stage The main tasks completed in this stage included 1:200,000 geological survey, 1:50,000 structural survey, 1:500,000 gravity survey, and magnetic survey. The ground structures, including the Shuangshimiao and Huangjinkou structures, were discovered. In addition, the construction of the local structure was completed, including the Shuangshimiao and Dongyuezhai structures. Second stage (1960–1980): Regional structure review and structural pre-exploration stage The key work of this period is to find oil and gas and to explore the local structure, especially the ground structure. More than ten shallow wells drilled in the Shuangshimiao, Leiyinpu, Dongyuezhai, and Huanglong structures, and a weak oil and gas display was discovered in Lower Jurassic strata. The well of Chuan 1 was drilled in the Shuangshimiao structure with a well depth of 2252.08 m, and weak gas flow was observed in the Lower Jurassic and Upper Triassic. The Chuan 25 well was drilled in the Fujiashan structure with a depth of 3830 m. The well of Chuan 64 (well depth of 5005 m) was drilled in the watershed structure. In the whole area, seismic exploration has been carried out in someplace, laying a foundation for the structural investigation.

Fifth stage (2000–2007): Discovery and confirmation stage of the Puguang gas field Based on the analysis of 21 wells that were drilled in the previous period, the original exploration target of using structural traps as drilling targets were changed. The “structural–lithologic” traps were identified as the key exploration targets in 2000. In the second half of 2000, 54 high-resolution 2D seismic survey lines with a length of 680.112 km and a main survey line density of 1.5–2 km were deployed in the Xuanhan– Daxian area. In August 2001, wells of Maoba 1, Puguang 1, Dawan 1, Laojun 1, and Qingxi 1 were drilled (Fig. 9.3). In November 2001 and January 2002, Puguang well 1 and Maoba well 1 were drilled, respectively. From January 15 to January 21 in 2003, a gas test was carried out in the 4324–4352 m section of Maoba well 1. A 22 mm diameter orifice plate was used in the test. The daily natural gas production was 32.58  104 m3, and the pressure coefficient was 1.89 Mpa. From July 30–August 5 in 2003, the section of 5610.3–5666.24 m in Puguang well 1 was tested. The oil pressure was 19 MPa; the daily gas production was 42.37  104 m3; and the pressure coefficient

242

9 Puguang Gas Field

was 1.09. A breakthrough was achieved in the natural gas exploration in the Feixianguan Formation in the Xuanhan– Daxian area, and the Puguang gas field was discovered. After the breakthrough in the Maoba 1 and Puguang 1 wells, three phases of exploration were carried out within four years. By the end of 2007, proven natural gas reserve of 4059.09  108 m3 was reported, and the overall exploration of the Puguang gas field was realized safely, quickly, and efficiently (Table 9.2). Sixth stage (2005–present): Development stage of the Puguang gas field After two rounds of exploration, proven reserves of 2510.70  108 m3 within 45.6 km2 of the Puguang structure were reported, providing a solid foundation for development. In December 2005, production wells were drilled and it put into operation and production in 2009. In 2010, the first high-sulfur gas field in China over 10 billion m3 was built. The “Sichuan East Gas Transmission Project” was officially completed and put into operation (Ma et al. 2010b).

9.3

Characteristics of the Puguang Gas Field

9.3.1 Structural Characteristics The Xuanhan–Daxian Block contains multiple secondary structural units such as the Shuangmiaochang–Maobachang, Leiyinpu–Dawan, Shuangshimiao–Puguang, and Qingxichang tectonic belts from west to east. Three types of traps can be found, including structural–lithologic, lithologic, and structural traps. The Puguang gas field consists of three structural–lithologic composite traps, that is, the Puguang, Dawan, and Maoba traps, which are controlled by the sedimentary facies boundary between the Feixianguan and Changxing formations (see Fig. 9.3).

that is, the Puguang and Dongyuezhai traps. Therefore, the Puguang structure is a tectonic–lithologic composite trap controlled by the structure and lithofacies. The trap is cut by two faults and can be divided into three sub-traps, and they are the well area of Puguang 2 trap, well area of Puguang 7-side 1 trap, and well area of Puguang 7 trap. (2) Maoba structure The Maoba structure is located at the north end of the Shuangmiao–Maoba tectonic belt and is characterized by a form of a long-axis anticline in the NE direction. The trap is also a structural–lithologic composite trap that is controlled by both the structure and lithology. The eastern, southern, western, and northern part of the trap is bounded by the eastern Maoba fault, the sedimentary facies, the structural trap line, and the Huangcaoliang fault, respectively. (3) Dawan structure The Dawan structure is the southern flank of the Tieshan slope structure, which extends into the area. The structure has a high north–low south pattern. The Dawan structure includes two faults, that is, the eastern and western Dawan faults, and is connected to the Maoba and Puguangxi structures. Its tectonic position is lower than that of the Maoba structure; it is an axial NNE-trending anticline, with the long–short axis ratio of >8. The sedimentary environment of the Feixianguan Formation in the Dawan tectonic area is similar to that of the Puguang Formation and the traps are tectonic–lithologic composite traps.

9.3.2 Gas Field Fluid Characteristics

(1) Puguang structure (1) Natural gas components Based on the detailed interpretation of the 3D seismic data, the Puguang–Dongyuzhai tectonic belt is characterized by a large-scale long-axis anticline structure with a NNE trend in the northern section of the structural belt. The Puguang structure is *1000 m lower than the southeastern Dongyuemiao structure. Seismic data show that a variation belt of sedimentary facies extending in direction of NWW occurs between the Puguang and Dongyuemiao structures, which represents the sedimentary facies from the platform margin with oolitic shoal dolomite facies of the Puguang area to the limestone shelf in the Dongyuezhai area (Fig. 9.3). The facies transition zone divides the Puguang–Dongyuzhai structure into two traps,

The hydrocarbon gas accounts for *83% of the natural gas of the Feixianguan and Changxing formations in the Puguang area. Among them, the relative gas content of methane is >99.5%. The component of heavy hydrocarbon (above C2+) is 90%. At the same time, dissolution is very strong, leading to the formation of four stages of dissolved pores. The dissolved pores of the first and third stages are almost completely filled with calcite; those of the second stage are partially filled with asphalt; and those of the fourth stage are almost all unfilled. The dissolved pores of the fourth stage form a very rich and effective reservoir space. The fracture effect is strong and five-stage fractures formed. The number of fractures is large. The fractures of the first and fourth stages are all filled with calcite, those of the second stage are partially filled with asphalt, and those of the fifth phase are almost all unfilled. A certain reservoir space formed in the second and fifth stages. The recrystallization is strong,

shoal Sinopec mining

restricted platform

shoal

Guang’an

Bazhong

shoal

Tongnanba block

Nanjiang block

Yuanba block

Guangyuan shoal

Ningqiang block

Fig. 9.8 Facies distribution in the third member of the Feixianguan Formation, northeastern Sichuan

open platform

reef

Legend

Deyang Sanhe Zhongjiang

Luojiang

Mianyang

An’xian

shoal

Pingshang

Pingwu

Qingchuan

Kaijiang

northern block of SE Sichuan

Dazhou

restricted platform

Xixiang block

a

bl oc

k

western Hubei and eastern Chongqing block

Kaixian

nb

Zh e

shoal

Pingxi

Fengjie

open platform

254 9 Puguang Gas Field

9.4 Main Gas Layer Characteristics

255

Table 9.3 Characteristics of the constructive diagenesis of the reservoirs in the Puguang gas field Constructive diagenesis

Diagenetic characteristics

Dolomitization

Changxing Formation: strong, reservoirs are dominated by dolomite First and second members of the Feixianguan Formation: strong, reservoirs contain dolomite Third member of the Feixianguan Formation: medium, reservoirs are dominated by dolomite and lime-dolomite

Fracture

Stage

Recrystallization

First

Fourth

Fifth

Fracture strength

Medium

Strong

Weak

Strong

Fracture

Abundance

Medium

Rich

Few

Rich

Infill

Calcite, dolomite

Bitumen in most parts, little–no infill

Calcite, dolomite

Non

Stage

First

Second

Strength

Strong

Weak

Crystal characteristics

Changxing Formation: fine crystals, followed by medium crystals First and second members of the Feixianguan Formation: fine–medium crystals, followed by coarse crystals; Third member of the Feixianguan Formation: powder, rich in organic matter, dark color

Changxing Formation: powder to medium-sized crystals, followed by coarse crystals First and second members of the Feixianguan Formation: fine– medium crystal, followed by coarse crystals Third member of the Feixianguan Formation: powder, followed by fine crystals, calcsparite, light color

Pores

Rich

Rich

Partially filled with bitumen, partially no infill

Non

Second

Third

Abundance Infill

Dissolution

Second–third

Stage

First

Strength Dissolved pores

Fourth

Weak

Strong

Weak

Strong

Abundance

Few

Rich

Few

Rich

Infill

Calcite, dolomite

Bitumen

Calcite, dolomite

Non

Relationship to hydrocarbon activities

Prior to the hydrocarbon generation

Liquid hydrocarbon phase

Hydrocarbon gas phase

Tectonic activity time

Indo-Chinese Epoch

Yanshan Epoch

Himalayan Epoch

leading to the formation of two types of crystals. The color of the crystals of the early stage is dark, while the color of late-stage crystals is bright.

9.4.3.2 Diagenesis of the Third Member of the Feixianguan Formation The reservoir of the third member of the Feixianguan formation belongs to oolitic shoal facies in a restricted platform and the reservoir lithology is dominated by oolitic dolomite.

The physical properties of the reservoir correspond to those of type III reservoirs, followed by type II reservoirs. The favorable diagenesis of the reservoir includes dolomitization, fracture, recrystallization, and dissolution. The dolomitization is more intense and most of the reservoir is composed of dolomite. The dissolved pores are relatively developed. The second and especially the fourth stage dissolution leads to the formation of effective reservoir space. The fracture effect is strong, forming five-stage

256

cracks. The second stage and fifth stage cracks form effective reservoir space. The recrystallization relatively developed, mainly forming powder- to fine-crystalline dolomite.

9.4.4 Reservoir Physical Characteristics and Main Controlling Factors 9.4.4.1 Reservoir Physical Characteristics The reservoirs of the Feixianguan and Changxing formations of the Puguang gas field have a burial depth of 4800–6100 m and porosity of up to 28.86%. They are high-quality reservoirs with large thicknesses. Type I reservoirs can reach nearly 100 m in some wells and the effective reservoir thickness is continuous (>300 m). Based on the analysis of the burial history (Zhu et al. 2006), the Feixianguan formation reached a depth of 8000 m at the end of the Cretaceous, which is conducive for the preservation of higher-developed pores. The formation mechanism is not simple compaction and pressure dissolution can be explained. (1) Physical properties of the Changxing Formation Drilling data for the Puguang area reveal that a large set of dissolved pore reef–shoal complex dolomite reservoirs (composite type) with large thicknesses developed in the Changxing Formation. The reservoirs, which are mainly high-porosity and high-permeability reservoirs, contain well-dissolved pores and have good physical properties. The porosity of the Changxing Formation ranges from 1.11 to 23.05%, with an average of 7.08%. The average porosity of the reservoir porosity >2% is 7.66%. It is mainly distributed between 5 and 10% and >10%, accounting for 48% and 22%, respectively. The minimum and maximum permeability are 0.0183  10−3 lm2 and 9664.887  10−3 lm2, respectively. Permeability >1.0  10−3 lm2 accounts for 62%, representing a good permeability. The reservoir porosity and permeability are linearly and positively correlated, that is, the permeability increases with increasing porosity (Fig. 9.9). The pores (dissolved pores) are mainly distributed in the middle and lower parts of the second member and in the upper part of the first member of the Changxing Formation. The lithology consists of reef dolomite. In other parts of the reservoir, the correlation between the porosity and permeability is poor, that is, the porosity insignificantly changes while the permeability increases exponentially. These parts of the reservoir belong to the fracture–pore reservoir type. These parts are distributed throughout the Changxing Formation, mainly in the

9 Puguang Gas Field

upper part of the second member and in the middle and upper members of the Changxing Formation. The lithology consists of reef limestone. (2) Reservoir characteristics Formation

of

the

Feixianguan

The drilling data for the Puguang gas field reveal that the Feixianguan Formation contains a large set of dissolved-pore dolomite reservoirs (composite type) with large thickness and good physical properties. The reservoir rock types mainly include oolitic dolomite, residual oolitic dolomite, saccharoidal residual oolitic dolomite, oolitic dolomite with rudaceous grains, muddy dolomite with rudaceous grains, and crystalline dolomite. Oolitic dolomite and residual oolitic dolomite are the two most important types. (A) Reservoirs dominated by medium and high porosities and permeabilities The Feixianguan Formation has a porosity between 0.94 and 25.22%, with an average of 8.11%. The average value of porosities above 2% is 8.64%. Porosity of 2–5, 5–10% and above 10% accounts for 17, 45, and 30% of the total porosity, respectively. The permeability is 0.0112– 3354.6965  10−3 lm2, with an average value of 94.4234  10−3 lm2. It is mainly distributed in 0.002– 0.25  10−3 lm2 and above 1.0  10−3 lm2. The latter value (better permeability) dominates. (B) Main pore (dissolved pores) reservoirs with a certain correlation between the porosity and permeability The analysis shows that the porosity and permeability are positively and linearly correlated in most reservoirs (Fig. 9.10), that is, the permeability increases with increasing porosity. Pore (dissolved pore) reservoirs represent the main reservoir type, mainly distributed in the first and second members of the Feixianguan Formation. The correlation between the porosity– permeability is poor in other parts of the reservoir, that is, the porosity insignificantly changes, but the permeability increases exponentially, indicating the action of fractures, which are mainly distributed in the third member. In some parts of the reservoir, the permeability does not change with increasing porosity because isolated pores dominate the reservoir and the connectivity is relatively poor. Although the porosity is relatively high and the permeability is relatively low, the reservoir is a pore-type reservoir. It is mainly distributed in the second member and lower parts of the first member of the Feixianguan Formation.

9.4 Main Gas Layer Characteristics

257

Fig. 9.9 Relationship between the porosity and permeability in Puguang well 6 of the Changxing Formation, Sichuan Basin

Fig. 9.10 Relationship between the porosity and permeability in Puguang well 2 of the Feixianguan Formation

9.4.4.2 Main Reservoir Factors (1) The physical properties of the reservoir are controlled by the sedimentary environment. The statistics on the relationship between the carbonate facies and porosity & permeability (Table 9.4) indicates a strong correlation between the sedimentary environment and reservoirs. Reservoirs are mainly developed in a sedimentary environment with strong hydrodynamic force, which are repeatedly scour by water flow, and easy to be exposed. (2) Dolomitization is the basis for the formation of high-quality reservoirs. The statistics regarding the reservoir lithology and porosity and permeability for the Puguang gas field show that high-quality reservoirs are dominated by dolomite. Dolomite

reservoirs are superior to limestone reservoirs. Based on the statistics obtained for 349 samples of limestone and dolomite in the 4864–5393.15 m section of well Puguang 6, the dolomite porosity is mainly 6–12%, that is, much higher than the limestone porosity (1–4%). Based on the observations and quantitative analysis of cores and casting thin sections, the dolomite of the Puguang gas field formed in the early stage of diagenesis. This result is based on the following evidence: (1) Based on core observations, the oolitic limestone suture is fully developed, but the oolitic dolomite suture is undeveloped and the ooids are not flattened, confirming that the dolomitization occurred before the burial compaction of the reservoir and pressolution. This also confirms the anti-compacting properties of dolomite, inhibiting the damage of the reservoir by compaction and pressolution. (2) The C and O isotope analysis shows that the d13C value is between 2 and 5‰. The d13O value ranges from −3 to −5.8‰. This value is a representative of low-temperature dolomite that formed in a shallow burial diagenetic environment. (3) Based on the analysis of the Sr isotopes, the isotope values of the dolomite fluid are close to those of the seawater from the same period. The high-energy reef–shoal facies reservoirs are in a diagenetic environment characterized by geomorphic highs, dissolution, and a shallow water body in the early diagenesis stage. In such an environment, freshwater, mixed water, or brines develop, which is beneficial to the occurrence of dolomitization. Based on the statistics regarding the residual structure and reservoir regularity of dolomite in the Puguang gas field, the high-quality type I reservoir (porosity u  12%, permeability K  20  10−3 lm2) is dominated by residual grains and ghost structures. For example, the porosity

258 Table 9.4 Statistics regarding the sedimentary environment and physical properties of the reservoirs of the Changxing and Feixianguan formations in the Puguang area (Ma et al. 2010a)

9 Puguang Gas Field Facies

No. Exposed shoal

Permeability ( 10−3 lm2)

Porosity (%) Min–Max

Average

No.

Min–Max

Average 157.8231

925

1.11–28.86

8.38

842

0.0163–7973.7685

Framestone

70

1.12–8.38

2.19

70

0.0116–129.1227

Bafflestone

109

1.27–14.51

6.5

108

0.0148–223.2907

7.1924

65

3.12–23.05

8.47

63

0.0599–9694.887

265.8044

Evaporative flat

465

0.45–17.24

3.76

402

0.0001–5418.85

Exposed shoal

277

1.11–23.05

5.83

260

0.0191–7973.7685

Tidal channel

2.1079

46.1705 177.902

Shallow gentle slope

44

0.47–1.83

1.02

44

0.0101–0.3777

0.0492

Lagoon

46

0.28–8.91

2.11

28

0.0108–0.7155

0.095

measured on saccharoidal dolomite with a ghost structure from the first member of the Feixianguan Formation reaches up to 28.86%. However, the residual granular dolomite (well-preserved original structure) is weaker due to the weak erosion and recrystallization and the reservoir properties are relatively poor. This indicates that dolomitization is one of the prerequisites for the development of deep carbonate reservoirs, but the dolomite must undergo significant modification after late cracking and multistage fluid dissolution.

the cracks form a unified system, indicating that such cracks contribute to the improvement of the porosity and permeability of the reservoir. The existence of cracks has a dual effect on the carbonate reservoirs. On one hand, the cracks themselves represent reservoir space; on the other hand, the cracks are passages for diagenetic water, which is conducive to dissolution, and therefore, beneficial (Ma et al. 2007b). (4) Fluid–rock interaction controls the dissolution and preservation of pores.

(3) Tectonization improves the reservoir permeability. The statistical analysis indicates a positive linear correlation between the porosity and permeability of the Puguang gas field, belonging to a fracture–porosity (dissolved pore)-type reservoir. In the Puguang gas field, mainly two types of fractures are developed, that is, compressive microfractures and tensional fractures. The amount and type of fractures differ in different regions and intervals. In some regions, horizontal fractures or flat, oblique, and vertical fractures are developed and cross each, forming a net shape. Two stages of compressive cracks are formed by the extrusion of the structure. The fractures are characterized by a width below 0.5 mm, with linear appearance, and small amounts of carbonaceous asphalt and carbonate cement filling. Extensional fissures are formed by tensional action. They are 2–10 mm wide and can be divided into three stages. The tensional fractures of the early two stages are filled with calcite and late-stage fractures are unfilled. Microscopic observations show that small cracks and microcracks developed in the dolomite reservoir, which play important roles in improving the porosity and permeability of the reservoir. The microcracks mainly form an irregular network in the reservoir. For example, the microcracks in the oolitic dissolved dolomite with sparry cement and powder- to fine-crystalline dolomite (gravel–sandy-sized grains) show net and banded shapes under the microscope. Along the cracks, the diagenetic sequence of dissolution followed by asphalt fillings can be found and the pores on both sides of

The reservoir space of the Changxing and Feixianguan formations in the Puguang gas field is extremely developed. The reservoir space mainly consists of intercrystalline, intergranular dissolved, intragranular dissolved, and dissolved enlarged pores, followed by cracks and stylolites (Fig. 9.11). Moldic, intracrystalline, and crystalline moldic pores can also be found. Due to the influence of the multistage diagenetic transformation, the original rock pore structure has been destroyed, sometimes completely. Based on the analysis of the reservoir rock structure, pore structure, cement (interstitial), the isotopes and fluid inclusions, reservoir was mainly affected by the following types of dissolution (Ma et al. 2010a). (A) Meteoric water dissolution A large number of selective intragranular pores (including moldic pores) and the geopetal structure and fibrillar–ctenoid cement in the thin sections confirm the widespread dissolution of meteoric water in the study area. The degree of freshwater dissolution is affected by factors such as the sedimentary environment, paleogeomorphology, and sea level. The core and thin section observations show that the porosity is better in the upper middle part of the high-frequency system in the high-level system domain. The shallower the waterbody locates, the stronger the energy is. It results in the deposition with higher porosity. In addition, it is easier to form a large number of secondary dissolution pores in the partially exposed layer.

9.4 Main Gas Layer Characteristics

259

fabric-selective

1-interparticle 2-intraparticle 3-intercrystalline

1

not fabric-selective

partly fabric-selective 4-enlarge

5-vug

6-cavern 7-channel 8-fracture 9-breccia

3

8 7

A

6

5

2

enlarged intraparticle

B

9

4

enlarged interparticle

400 400¦µm m

400 µm 400¦ m

C

enlarged intercrystalline

400 µm 400¦ m

Fig. 9.11 Pore types of the dolomite reservoir in the Puguang gas field

(B) Dissolution of organic acids The underlying source rock enters the early stage of the late diagenesis, begins to produce oil, and generates a large amount of organic acids. The underlying acid-containing fluid enters the reservoirs of the Changxing and Feixianguan formations, leading to dissolution. Dissolution often occurs before the liquid hydrocarbons enter the reservoir in the burial stage or during the filling of the liquid hydrocarbons. The organic acids and CO2 in the fluid cause the partial dissolution of the rock, forming dissolution pores, caves, and dissolved pores. The pores are filled with asphalt, semi-filled, or have a bitumen film on the walls; in addition, a small amount of dolomite grows on the walls. Intercrystalline dissolved pores, caves, and dissolution joints formed by the dissolution are partially retained by dolomite crystals and asphalt and a large amount of storage space is created.

(C) TSR dissolution Based on the core, thin section, and electron microscopy observations, the TSR dissolution is dominated by non-selective dissolution, leading to the formation of

dissolved pores, caves, and dissolution fractures. Compared with the pores formed by organic acid dissolution, the filling of the dissolved pores is different. In addition to a small amount of dolomite crystals on the pore walls, spherical elemental sulfur filling can be observed. The results show that the ruthenium particles contaminated by asphalt were re-eroded to form dissolved pores, which indicates that the asphalt was formed before the dissolution pores. Macroscopically, almost all pore gas reservoirs in the Sichuan Basin have higher hydrogen sulfide contents, better reservoir permeabilities, and a higher daily gas well production (Zhu et al. 2006).

9.5

Hydrocarbon Accumulation Process

9.5.1 Burial and Hydrocarbon Generation The age analysis based on the fission track data shows that the Puguang area in the northeastern Sichuan Basin has been denuded since the Late Cretaceous (*105 Ma). According to the fission track calculation, the total denudation thickness of the area is *2868 m. The burial history of the Puguang well 2 and thermal evolution history of the source rock are as follows (Fig. 9.12):

260

9 Puguang Gas Field

Fig. 9.12 Dynamic analysis of the hydrocarbon accumulation in the Feixianguan Formation of the Puguang gas field

(1) The Silurian source rock started to generate hydrocarbon after the deposition of the Early Triassic, and the vitrinite reflectance reached 0.5%. In the early Middle Jurassic, the peak of oil production was reached, and the vitrinite reflectance was 1.0%. In the middle stage of the Jurassic, the rock entered the mature stage (*40 Ma) and the vitrinite reflectance reached 1.5%. The Silurian source rocks entered the high-maturity stage in the late Middle Jurassic (*20 Ma) and the vitrinite reflectance reached 2.0%. This set of source rock has evolved to a mature stage since the end of the Middle Jurassic, mainly producing dry gas. It reached the maximum depth (*9600 m) at the end of the Early Cretaceous. (2) The Permian source rocks started to produce hydrocarbon in the Late Triassic. The peak of the oil production was reached in the middle stage of the Middle Jurassic, and the vitrinite reflectance was 1.0%. The high-maturity stage was reached in the Early Jurassic. Since the late

stage of the Late Jurassic to the present, the rock has been in the overmature stage. The mature stage of organic matter is similar to that of the Silurian source rocks. The maximum depth (*8300 m) of the source rock was reached at the end of the Early Cretaceous. After the Late Jurassic, both the Silurian and Permian systems were overmature, mainly producing dry gas.

9.5.2 Accumulation Period The dolomite reservoirs of the Changxing and Feixianguan formations in the Puguang gas field contain a large amount of asphalt. The cumulative maximum thickness of the asphalt-bearing formation can reach 300 m. The natural gas in today’s gas reservoirs is mainly the secondary pyrolysis gas of crude oil produced by the Upper Permian source rocks. The reservoirs contain a small amount of oil but many

9.5 Hydrocarbon Accumulation Process

asphalt inclusions. Taking Puguang well 2 as an example, two filling periods of ancient reservoirs can be described (Fig. 9.12): the first period occurred at 179–189 Ma (Late Triassic to Early Jurassic); the second period occurred at 170–176 Ma (Early Jurassic). The second stage of the oil accumulation was caused by the higher temperature and might have been mainly a condensate accumulation period. The drilling well data for the Puguang gas field show that the accumulation period of the Changxing and Feixianguan formations is concentrated in the 200–175 Ma, corresponding to the Late Triassic to Early Jurassic and is characterized by multiple stages of oil filling (Ma et al. 2007a).

9.5.3 Recovery of the Accumulation Process Based on the above-mentioned analysis of the thermal evolution, fluid inclusions, and reservoir asphalt and the evolution of the Puguang gas reservoir, the accumulation process can be divided into the following four stages (Ma et al. 2005a, b, 2005e, 2007c) (Fig. 9.13): (1) Ancient primary lithologic reservoir stage The residual thickness of the Leikoupo Formation indicates that a low-amplitude paleo-uplift occurred in the southeast of the Puguang structure in the early stage of the Indosinian– Yanshan Epoch (T–J1-2) in the northwestern flank of the Kaijiang paleo-uplift. The reservoir space of the oolitic shoal in the Feixianguan Formation formed and the organic matter of the Permian source rock matured and produced oil. The hydrocarbon expulsion intensity reached >200.0  104 t/km2. The lithologic traps was located at the periphery of the Kaijiang paleo-uplift, conducive to the migration and accumulation of oil and gas. Crude oil was mainly transported into the shoal reservoir along the pores, stratigraphic interfaces, and fractures. The Puguang ancient primary lithologic reservoir formed. (2) Tectonic–lithologic composite paleo-gas reservoir stage In the Late Jurassic, the source rock reached the overmature stage and began to generate the gas. The buried depth reached *6300 m and the formation temperature of the original reservoir was 170 °C, respectively. The thermal stability of the crude oil was destroyed, pyrolysis began (i.e., pyrolysis into wet gas). The thermochemical sulfate reduction (TSR) is primarily related to gaseous hydrocarbons, and therefore, occurs in the early stages of crude oil pyrolysis. It was altered by weak TSR action. Due to the strong activity of the Xuefeng (mountains) thrust nappe structure, an

261

embryonic anticline structure formed in the Puguang area and the natural gas generated by the crude oil pyrolysis formed a tectonic–lithologic composite paleo-gas reservoir. (3) Formation stage of tectonic–lithologic composite gas reservoirs The Late Cretaceous orogenic activities of the Xuefeng Mountains and the Yanshan movement, which spread to the Xuanhan–Daxian area, shaped the main body of the NE structure and the Puguang structural–lithologic trap. At this time, the natural gas in the paleo-gas reservoir began to adjust and was in place. Some of the source rocks reached the gas peak and the faults are gathered and mixed in the trap. Natural gas was mainly transported to the Puguang structure along the faults, unconformity surface, pores, and stratigraphic interface, forming a tectonic–lithologic composite gas reservoir. (4) Gas reservoir adjustment, transformation, and reformation stage During the Himalayan period, the uplifting orogenic activities of the Daba Mountains at the northeastern margin increased and the NE–SW compressive stress affected the Xuanhan–Daxian area. The NW-oriented thrust fault was superimposed on the previously formed NE-trending structure. The structure underwent adjustment and transformation. Due to the small influence of the structure, the overall closed environment was not destroyed. The gas reservoir of the Puguang Feixianguan Formation was locally adjusted and finally positioned.

9.5.4 Main Factors Controlling the Oil and Gas Accumulation 9.5.4.1 Hydrocarbon Is Highly Abundance in the Center of the Permian Hydrocarbon Source The center of the hydrocarbon source is the area with the highest gas generation intensity, reflecting the thickness of the source rock, abundance of organic matter, type of organic matter, and maturity. The gas generation center and its surrounding areas are characterized by a continuous high abundance of gas sources and a short oil and gas migration distance. Therefore, the loss of oil and gas during transportation can be avoided, facilitating the enrichment of oil and gas and thus the formation of large oil and gas fields. In the Puguang area, there are many sets of high-quality source rocks in the Silurian and Permian, and the Upper Permian Longtan Formation coal-bearing strata are the main

262

9 Puguang Gas Field Chuanyue84 Puguang2

Puguang2

Depth(km)

Maoba1 Dawan1

Depth(km)

In the late stage of Yanshan to Himalayan epoch, structure adjusted intensivly, reservoir transported in lateral side and the current gasreservoir formed Chuanyue84 Puguang2 Puguang2 Maoba1 Dawan1

Depth(km)

In the late stage of middle Yanshan epoch, structure adjusted slightly, paleo oilreservoir splitting, reservoir transported in lateral side and the paleo gasreservoir formed Chuanyue84 Puguang2 Puguang2 Maoba1 Dawan1

Inthe late Indo-Chinese to early Yanshan epoch, source rock of Permian matured. Efficience passage system were composed of fault, fracture and reservoir and the paleo oilreservoir formed source rock

cap rock

gas reservoir

paleooil reservoir

fracture

reservoir

fault

migration path

Fig. 9.13 Natural gas accumulation process and model of the Changxing Formation in the Puguang gas field, Sichuan Basin

source rocks in the area, with wide distribution and large continuous thickness. For example, the Longtan Formation of well Puguang 5 is *160 m thick and the average organic carbon content is 2.27%. Based on the hydrocarbon evolution, the organic matter of the Permian source rocks began to mature in the late Indosinian Period. It entered the early maturity stage in the early Yanshan and the high-maturity stage in the mid-Yanshan Period, which was a period of hydrocarbon generation. The structure formed in the background of the paleo-uplift. In lithologic traps, ancient oil reservoirs (Puguang reservoirs, and their formation period

may be earlier, almost close to the same post-penecontemporaneous period) and asphalt can be widely seen in reservoirs. In the late Yanshan Period, the rock entered the maturity stage. Nowadays, the Ro value is 2.5–3.3%. The rock entered the middle and late maturity stages. The early formed ancient oil reservoirs have been pyrolyzed into natural gas with the increase of buried depth. Regional studies have shown that the hydrocarbon generation center of the Upper Permian Longtan Formation is located in the Tongnanba–Luojiazhai area. The maximum gas intensity is 125  108 m3/km2, which leads to the

9.5 Hydrocarbon Accumulation Process

formation of a large high-abundance gas reservoir in the northeastern Sichuan and Puguang areas, providing an adequate gas supply.

9.5.4.2 High-Energy Facies Control the Development of High-Quality Reservoirs and Multistage Dissolution Provides Space for the Formation of Gas Fields The formation of gas fields requires reservoirs with good porosities and permeabilities. The development scale of high-quality reservoirs determines the scale of the gas reservoir. The Puguang gas field is located on the eastern bank of the “Kaijiang–Liangping” shelf. The sediment of the Changxing and Feixianguan formations is in the exposed shoal facies of the platform margin, which is conducive to the formation and development of reservoirs and provides excellent conditions for pore formation such as meteoric water dissolution and dolomitization (e.g., penecontemporaneous, post-penecontemporaneous, and mixed-water dolomitization). Multistage dissolution during diagenesis is a key factor for further optimization of the reservoir performances of the Puguang reservoirs. The huge Changxing– Feixianguan reef–shoal complex reservoir forms the high-abundance, large-scale Puguang gas field. 9.5.4.3 An Effective Transport System is One of the Key Factors for Hydrocarbon Migration and Accumulation in the Puguang Gas Field The reservoir lithology of the Changxing and Feixianguan formations in well of Puguang 2 consists of a large set of gray, light gray dissolved-pore oolitic dolomite with limestone-bearing dolomite and dolomite-bearing limestone, mainly composed of residual oolitic dolomite. The thickness of the effective reservoir is large. The reservoir has a wide lateral distribution and good connectivity, which is the main channel for the lateral migration of natural gas. The Puguang gas field is in the high-steep tectonic belt of eastern Sichuan and deep and large faults are developed. These faults connect the hydrocarbon source with the reservoir, forming a high-efficiency transport system dominated by fault storage. The Puguang area is located in the northwest of the Kaijiang paleo-uplift, which is the direction area for oil and gas migration and accumulation and is conducive to the integration of oil and gas. The reverse fault does not cut the main caprock of the area (gypsum layer in the Jialingjiang and Leikoupo formations), which guarantees the integrity of the tectonic–lithologic composite trap and constitutes a key factor for the formation of the Puguang gas field.

263

9.5.4.4 Effective Storage Conditions are the Key to the Late-Stage Adjustment and Positioning in the Puguang Gas Field Because the Puguang gas field is located in the high–steep tectonic belt of eastern Sichuan, deep faults developed in this area. These faults represent not only a high-efficiency transport system but also channels for oil and gas loss. Therefore, the effective preservation conditions in this area are the key to the preservation of the gas field. Gypsum layers are fully developed in the second and fourth members of the Lower Triassic Jialingjiang Formation and the second member of the Middle Triassic Leikoupo Formation. The gypsum layers have greater plasticity when they are affected by tectonic pressure, it still maintains lateral continuity and has a large sealing capacity. The analysis of the drilling data shows that the thickness distribution of the gypsum layers is relatively stable. The gypsum layers constitute the complete caprock of the natural gas reservoir of the Changxing and Feixianguan formations. The CaCl2type formation water can be found in the northeastern part of the Xuanhan–Daxian area. The rNa+/rCl− (0.77–0.91) and rSO42−  102/rCl− (0.45–1.28) ratios are the lowest in the study area, indicating good sealing conditions. This guarantees the late accumulation of gas in the Puguang gas field. Therefore, effective preservation conditions are one of the most critical factors for the accumulation of natural gas in the Puguang structure.

References Ma Y (2006) Cases of discovery and exploration of marine fields in China (Part 6): Puguang gas field in Sichuan Basin. Marine Origin Pet Geol 11(2):35–40 Ma Y (2007) Generation mechanism of puguang gas field in Sichuan Basin. Acta Petrolei Sinica 28(2):9–14, 21 Ma Y (2008) Geochemical characteristics and origin of natural gases from Puguang gas field on eastern Sichuan Basin. Natural Gas Geosci 19(1):1–7 Ma Y, Mu C, Guo T et al (2005a) Sequence stratigraphy and reservoir distribution of the Changxing Formation in northeastern Sichuan Basin. Earth Sci Front 12(3):179–185 Ma Y, Mu C, Guo T, Tan Q, Yu Q (2005b) Sequence stratigraphy and reservoir distribution of the Changxing Formation in northeastern Sichuan Basin. J Mineral Petrol 25(4):73–79 Ma Y, Fu Q, Guo T, Yang F, Zhou Z (2005c) Pool forming pattern and process of the upper permian-lower Triassic, the Puguang gas field, northeast Sichuan Basin, China. Pet Geol Exper 27(5):455–461 Ma Y, Guo X, Fan R (2005d) Reservoir prediction of Feixianguan formation in Puguang gas field, northeast Sichuan Province. Pet Explor Dev 32(4):60–64 Ma Y, Guo X, Guo T et al (2005e) Discovery of the large-scale Puguang gas field in the Sichuan Basin and its enlightenment for hydrocarbon prospecting. Geol Rev 51(4):477–480

264 Ma Y, Mou C, Tan Q, Yu Q, Wang R (2007a) Reef-bank features and their constraint to reservoirs of natural gas, from Permian Changxing Formation to Triassic Feixianguan formation in Daxian-Xuanhan area of Sichuan Province, South China. Earth Sci Front 14(1):182–192 Ma Y, Guo T, Zhao X et al (2007b) Formation mechanism of high quality dolomite reservoir in deep of puguang gas field. Sci China (Ser D) 37(3):43–52 Ma Y, Cai X, Guo T (2007c) Main control factors of oil and gas charging and enrichment in Puguang large gas field, Sichuan Basin. Chin Sci Bull 52(A01):149–155 Ma Y, Chen H, Wang G et al (2009) Sequence stratigraphy and paleogeography in southern China. Science Press, Beijing

9 Puguang Gas Field Ma Y, Cai X, Zhao P, Zhang X (2010a) Formation mechanism of deep-buried carbonate reservoir and its model of three-element controlling reservoir: a case study from the Puguang oilfield in Sichuan. Acta Geol Sin 84(8):1087–1094 Ma Y, Cai X, Guo X et al (2010b) The discovery of Puguang gas field. Eng Sci 12(10):14–23 Ma Y, Cai X, Zhao P (2014) Characteristics and formation mechanisms of reef-shoal carbonate reservoirs of Changxing-Feixianguan formations, Yuanba gas field. Acta Petrolei Sinica 35(6):1001–1011 Zhu G, Zhang S, Liang Y, Ma Y et al (2006) Dissolution and alteration of the deep carbonate reservoirs by TSR: an important type of deep-buried high-quality carbonate reservoirs in Sichuan Basin. Acta Petrologica Sinica 22(8):2182–2194

10

Yuanba Gas Field

10.1

Geographical Location and Regional Geological Background

10.1.1 Geographical Location The Yuanba gas field is located in the mountains area, with the topographic features of north high and south low, in the Langzhong and Cangxi County, Sichuan Province. In the south, the terrain is relatively gentle with a height difference ranging from 400 to 750 m. In the north, steep mountains and deep gullies make the terrain undulating. The climate in the mountainous area varies greatly, ranging from subtropical humid monsoon to mountain climate. The region below 800 m above sea level (a.s.l.) is characterized by mild continental monsoon climate, abundant rainfall, four distinct seasons, late spring, early autumn, early and short summer, without a notable high-temperature period in summer. The region above 1,000 m a.s.l. is characterized by cool climate and poor sunlight conditions. The whole area is rainy in spring and summer. The Jialingjiang River and Ba River systems and their tributaries extend throughout the entire study area from north to south.

10.1.2 Stratigraphic Features Based on regional and drilling data (Bureau of geology and mineral resources of Sichuan Province 1981), the strata in this area can be divided into the following formations, from top to bottom: Cretaceous Jianmenguan Formation; Jurassic Penglaizhen, Suining, upper Shaximiao, lower Shaximiao, Qianfoya, and Ziliujing Formations; Triassic Xujiahe, Leikoupo, Jialingjiang, and Feixianguan Formations; Permian Changxing, Wujiaping, Maokou, Qixia, and Liangshan Formations; and Silurian Hanjiadian Formation (Table 10.1).

Influenced by multi-episode tectonic movements, the unconformable contacts exist between the (1) Lower Silurian Hanjiadian and Middle and Lower Permian Liangshan Formations, (2) Middle Permian Maokou and Upper Permian Wujiaping (Longtan) Formations, (3) Middle Triassic Leikou and Upper Triassic Xujiahe Formations, (4) Xujiahe and Lower Jurassic Ziliujing Formations (the changes between the Middle and Upper Jurassic are insignificant), and (5) Upper Jurassic Penglaizhen and Cretaceous Jianmenguan Formations. Affected by the overall uplift of Caledonian tectonic movement, Devonian and Carboniferous were mostly absent in Northeast Sichuan Basin.

10.1.3 Tectonic Characteristics The Yuanba area is a large low-gentle tectonic belt, which is the southwest tilting end of Jiulongshan anticlinal tectonic belt in the northwest, the southwest tilting end of Tongnanba anticlinal tectonic belt in the northeast, and the north slope of the Chuanzhong gentle tectonic belt in the south. Several structural belts are joined by saddles. The structure of marine strata is relatively gentle with small folds and no faults in the Yuanba area. Small skirt hem-shaped nosing structures are only developed in the northern part of the Chuanzhong gentle tectonic belt and in the southeast part of the Jiulongshan anticlinal tectonic belt. For example, several local highs and nosing structures developed along the direction of NW at the top Changxing Formation, which were mainly caused by the late extrusion of the Dabashan Mountain. The local highs are mainly distributed in the northeast of Yuanba well 102, southeast of Yuanba well 11, and regions of Yuanba well 204 and 27. The nosing structures in the NW direction are mainly distributed in the area of Yuanba well 1–side well 1–Yuanba well 101.

© Geological Publishing House and Springer-Verlag GmbH Germany 2020 Y. Ma, Marine Oil and Gas Exploration in China, https://doi.org/10.1007/978-3-662-61147-0_10

265

266

10 Yuanba Gas Field

Table 10.1 Stratigraphy of the Yuanba area, Sichuan Basin System

Series

Formation

Cretaceous

Lower

Jurassic

Upper

Thickness (m)

Horizon Code

Lithology Overview

Sedimentary Facies Characteristics

Jianmenguan

0–967

K1j

Brown-red mudstone with gray-white lithic arkose quartz sandstone

Shallow lake and fluvial

Penglai Town

564–1,360

J3p

Brown ash, brown-red mudstone and brown ash, purple gray feldspar lithic sandstone

Shallow lake and r fluvial

Suining

248–440

J3s

Reddish-brown mudstone with fine-grained lithic sandstone

Shallow lake and shore

Shangshaxi Temple

1,300– 1,500

J2s

Brown-purple mudstone with ash, gray-green lithic feldspar quartz sandstone

Shallow lake and fluvial

Xiashaxi Temple

230–350

J2x

Brown-purple mudstone with fine-grained feldspathic lithic sandstone with black shale on top

Lake and fluvial

Qianfuya

185–320

J2q

Green-gray mudstone with light gray fine-medium lithic sandstone with black shale

Shallow lake and shoal

Lower

Ziliujing

410–570

J1z

Gray grayish-green mudstone intercalated with lithic sandstone and black shale and topped with shell limestone

Lacustrine

Upper

Xujiahe

450–700

T3x

Middle and upper black shale lithic sandstone, lower grayish lithic sandstone with black shale

Lacustrine swamp and fluvial facies

Middle

Leikouzu

Fourth

70–270

T42l

Dark gray mica with anhydrite and limestone

Evaporate platform

Third

140–260

T32l

Dark gray limestone with anhydrite and dolomite

Shoal, intertidal

Second

110–130

T22l

Dark gray mica interbedded with anhydrite

Evaporate platform

First

120–190

T12l

Anhydrite with mica, the bottom is “mung bean rock”

Evaporate platform

Fifth

110–120

T51j

Upper part of anhydrite, lower part of dolomite with dolarenite

Salty lagoon

Fourth

100–280

T41j

Upper part of anhydrite and carbonate rocks, lower part of dolomite with clastic dolomite

Salty lagoon

Third

160–180

T31j

Limestone with gypsum and arenaceous limestone

Shallow marine platform

Second

130–160

T21j

Anhydrite interbeds with mica and arenaceous mica

Shoal

First

190–240

T11j

Dark gray limestone intercalated with gray limestone

Shallow marine platform

Fourth

60–100

T41f

Grayish-purple marble with anhydrite

Intertidal lagoon

Third– first

400–550

T31f–T11f

Gray limestone, purple-gray argillaceous limestone, upper intercalated oolitic limestone, bottom gray marl, oolitic cloud rock and limestone

Shallow platform and shoal

Middle

Triassic

Lower

Jialingjiang

Feixianguan

Section

(continued)

10.2

Gas Field Discovery History

267

Table 10.1 (continued) System

Series

Formation

Permian

Upper

Lower

Silurian

10.2

Lower

Section

Thickness (m)

Horizon Code

Lithology Overview

Sedimentary Facies Characteristics

Changxing/Dalong

40–360

P2ch/P2d

Gray limestone, marl-bearing limestone, biogenic limestone, platform edge reef–shoal facies with developed dolomite, reef limestone/carbonaceous shale, siliceous shale and siliceous limestone

Shallow platform and reef/shelf marshes

Wujiaping/Longtan

50–200

P2w/P2l

Gray-black carbonaceous shale, gray-black mudstone, gray limestone, gray-black siliceous shale, gray-white aluminous mudstone, green-gray tuff at the top

Carbonate platform/swamp

Maokou

180–200

P2m

Dark gray limestone, biolimestone with siliceous rock on top, argillaceous rock in the lower part

Platform– swamp

Qixia

100–150

P1q

Dark gray limestone sandwiched with biological limestone, containing flint nodules

Shallow platform

Liangshan

0–20

P1–2l

Black shale intercalated with sandstone

Shore marsh

Hanjiadian

600–900

S1–2h

Mainly grayish-green, brownish-gray, dark gray shale, sandy shale, and argillaceous siltstone or sandstone

Shed

Gas Field Discovery History

The oil and gas exploration of the Yuanba gas field can be divided into four stages: early geological survey, finding lithologic or structural–lithologic trap, exploration breakthrough, and discovery expansion (Guo et al. 2014, 2018; Ma et al. 2014). (1) Early geological survey stage In the 1950s, a petroleum geological survey and other works were carried out in the Yuanba area. From 1967 to 1999, the main target layer was the continental clastic rock of the Lower Jurassic Zilijing Formation. The drilled four shallow continental wells discovered good oil and gas display in the Da’anzhai section of the Zilijing Formation, but industrial gas flow was not obtained during testing. Due to the lack of commercial discovery and unclear exploration potential, the exploration started a stagnate stage in Yuanba area.

(2) Changing exploration direction and lithologic or structural–lithologic trap stage (2000–2006) In 2000, it has been suggested that the sedimentary environment of the Permian–Triassic in the Yuanba area provided the basic conditions for the formation of a pore-type dolomite reservoir in the reef–shoal facies and the lithologic trap or tectonic–lithologic trap development area based on preliminary exploration and research results, the detailed outcrop analysis of high frequency sequence, seismic sedimentology, the restoration of dynamic sedimentary evolution of the isoclinal gentle slope–striped platform and regional sedimentary framework in the Late Permian. According to the new understanding, the exploration idea of structural trap in the early stage was adjusted, and the following exploration target was proposed: “Permian and Triassic reef–shoal pore-type dolomite reservoir and the main lithologic or structural–lithologic traps.” In 2002, the general distribution of the reef–shoal facies belt at the margin of the platform was preliminarily identified by reprocessing and

268

comprehensively interpreting the digital and simulated seismic survey lines across the surveyed blocks in the Yuanba area. New seismic surveys were carried out in 2003 and 2006, which further identified the distribution of the platform margin facies and discovered a number of favorable reef–shoal traps in the Yuanba area. In March 2006, the first ultra-deep exploration well, Yuanba 1, was proposed for the reef–shoal lithologic trap of the platform margin in the Changxing Formation in the Bazhong Block. On May 26, 2006, the Yuanba 1 well started to drill, marking beginning of the exploration of the Yuanba gas field in the ultra-deep carbonate reservoir. (3) Exploration breakthrough and evaluation stage (2007–2008) In November 2007, Yuanba well 1 drilled in the section 7330–7390 m of dolomite reservoir of reef cap at the platform margin in the Changxing 2nd member, and discovered good oil and gas display. On November 19, the test in the Changxing 2nd member yielded an industrial gas flow of 50.3  104 m3/d, representing a major breakthrough for the Changxing Formation gas reservoir in the Yuanba gas field. In April and June 2008, the industrial gas flow of Yuanba well 2 in the Changxing 1st and 2nd member was tested. Based on the data from the Yuanba wells 1 and 2, a new round of research identified the large-scale platform marginal facies in the Changxing and Feixianguan Formations in the Yuanba area, in which the exploration targets of reef–shoal composite and reef-back shoal reservoirs are developed. The favorable facies belt extends over more than 500 km2, and tests confirmed that the reef is a high-yield oil and gas enrichment zone. According to the new understanding, the second and third phases 3D seismic of 1571.56 km2 were deployed and implemented in Yuanba area in 2008. In succession, some wells were drilled to control the distribution framework of the reef–shoal facies reservoir in the Changxing Formation in Yuanba area. A batch of wells testing, including Yuanba wells 12 and 101, obtained medium and high -ield industrial gas flows in the reef–shoal and shoal facies of the platform edge in the Changxing Formation, which marked that large-scale Yuanba gas field is emerging. (4) Exploration and development integration stage (2009–2014) After the discovery of the Yuanba gas field, an evaluation was carried out according to the following exploration and deployment targets: “regional exploration, integrated exploration plan, and progressive implementation.” Good oil and gas exploration results were successively obtained in the

10 Yuanba Gas Field

Changxing, Feixianguan, and Fujiaping Formations. In May 2009, 13 exploration wells, including Yuanba well 27, were drilled. In addition, four development preparatory wells, including Yuanba well 103H, were drilled in order to explore the development mode of ultra-deep and high-sulfur gas field and evaluate the technical indicators of gas reservoir development. In addition to Yuanba well 27, another 8 Wells successively tested the high-yielding industrial gas flow >1 million m2 in the Changxing Formation. It was the first time that the two-layer test of a single well, that is, Yuanba 205, showed a high-yield gas flow of more than 1 million m2. The high-yielding enrichment zone of the reef–shoal facies was further expanded in Yuanba area, which laid a solid foundation for the construction of the production capacity of the Yuanba gas field. During the same period, a breakthrough was also achieved with respect to the exploration of the Feixianguan Formation. An industrial gas flow of 3–10  104 m3/d was obtained in Yuanba wells 204 and 27 in the Feixianguan Formation. In 2011, a high-yield industrial gas flow with a daily output of 135.9  104 m3 was obtained in Yuanba well 29 in the Wujiaping Formation, demonstrating favorable hydrocarbon accumulation conditions and the exploration potential of the Wujiaping Formation.

10.3

Gas Field Characteristics

The Yuanba gas field is an ultra-deep lithologic gas reservoir with a high hydrogen sulfide content. The gas reservoir is composed of several relatively independent reefs and bioclastic shoals. The gas accumulation of the reservoir is controlled by the lithology with the distribution characteristics of “one reef or one shoal forming one trap and one gas reservoir;” each gas reservoir unit has a slightly different of gas-bearing height, gas– water relationship, and fluid properties. By the end of 2014, the proven gas-bearing area of the Yuanba gas field was 320.42 km2 and the proven reserves were 2303.47  108 m3, with an average of 7.19  108 m3/km2. By the end of 2015, the production capacity of mixed gas accounted for 36.3  108 m3, with a cumulative production capacity of mixed and purified gas of 18.2  108 m3 and 16.4  108 m3, respectively.

10.3.1 Lithologic Reef–Shoal Gas Reservoir of the Changxing Formation The gas reservoir in the Yuanba Changxing Formation is a stratiform lithologic gas reservoir that developed on paleotectonic high background by superimposed and contiguous

10.3

Gas Field Characteristics

269

Fig. 10.1 Diagram showing the overlap of the lithologic trap and top boundary structure of the Changxing Formation in the Yuanba gas field

reef–shoals of the platform margin. The gas reservoir is distributed in northwest–southeast direction and the gas layer is controlled by the distribution of reef–shoal facies reservoirs and back-reef bioclastic shoal reservoirs at the platform margin (Fig. 10.1). The buried depth of the gas reservoir is highly variable (high west, low east, high south, and low north). The buried depth of the central part of the Changxing Formation ranges from 6327.9 to 6897.5 m, with an average of 6600 m. The maximum depth of the gas reservoir is 7013.7 m and the height of the gas reservoir is 48.7–481.8 m. The gas reservoir of the Yuanba Changxing Formation is 1000–1500 m deeper than that of the Puguang Changxing Formation, representing the deepest gas reservoir that has been discovered in the Sichuan Basin. Drilling indicated that the lithologic gas reservoir is highly filled (without water) at the high-structure area, and is the characteristics of bottom and edge water, the buried depth of the gas–water interface in different gas reservoirs differs in the low-structure area. Calculated according to the relationship among the formation temperature, pressure, and buried depth, the geothermal gradient of the gas reservoir is 19.4–20.5 °C/km.

The pressure coefficient is 1.01–1.12, representative of an atmospheric-pressure low-geothermal gradient system. The natural gas hydrocarbon component is mainly methane, while the non-hydrocarbon components are mainly H2S and CO2. The average methane, H2S, and CO2 contents are 88.35%, 5.22%, 6.43%, respectively. The stable output of a single well is 20–240  104 m3/d. To sum up, the gas reservoir of the Yuanba Changxing Formation is a fracture porosity large-scale biological reef and beach lithologic gas reservoir with a high H2S content, medium CO2 concentration, ultra-deep layer, medium–high yield, elastic gas flooding, and partial edge/bottom water; it is the main development body of the gas field (Ma et al. 2014; Guo 2011a).

10.3.2 Oolitic Shoal Lithologic Gas Reservoir of the Feixianguan Formation The Feixianguan Formation in the Yuanba gas field is a lithologic gas reservoir that formed by stacked slabs of oolitic shoal of open platform to platform margin facies on a

270

high paleotectonic background. The gas layer is mainly controlled by the distribution of oolitic limestone reservoirs. The central part of the Feixianguan Formation gas reservoir is buried at a depth of 6317–6387.5 m and the gas reservoir height is 284–425 m. A water layer has not been found based on the analysis and interpretation of drilling and logging data. The gas reservoir is driven by an elastic gas drive. The gas reservoir pressure coefficient is 1.95–1.96 and the average geothermal gradient is 21.1 °C/km, representative of a high-pressure low-geothermal gradient system. The average methane, H2S, and CO2 contents of the natural gas are 94.21%, 1.72%, and 3.35%, respectively. The output per well is 3.6–10  104 m3/d. The gas reservoir of the Feixianguan 2nd member in Yuanba is a fracture porosity oolitic lithologic gas reservoir with an ultra-deep layer, high-pressure and low-temperature gradients, elastic gas flooding, and medium H2S and CO2 contents (Ma et al. 2014; Guo 2011a).

10.3.3 Natural Gas Source Solid asphalt is commonly found in the Changxing Formation reservoirs in the Yuanba area, indicating that crude oil cracking has produced cracking gas, and cracking gas may also exist in source rock. These two types of natural gas can be distinguished by the lnC1/C2 and lnC2/C3 ratios (Fig. 10.2). In general, the natural gas of the Changxing Formation in the Yuanba area is characterized by high lnC1/C2 and low lnC2/C3 ratios. The lnC1/C2 ratio is >4.8, while the lnC2/C3 ratio is 10% are 58.55%, 15.69%, and 9.60%, respectively. The permeability is between 0.0026 and 2385.4826  10−3 lm2, with an average value of 0.2752  10−3 lm2. It is mainly distributed in two intervals, that is, 0.002–0.25  10−3 and >1  10−3 lm2. The former is the main interval, which is characterized by obvious permeability differentiation (Ma et al. 2014). The analysis of the core samples of the shoal of the Changxing Formation in the Yuanba area shows that the porosity and permeability of the reservoirs are positively correlated, mostly showing a linear relationship. However, when the porosity is below 5%, the correlation between the porosity and permeability is poor, which reflects the development of cracks in some samples. Comprehensive analysis indicates that the reservoir types are dominated by porosity and fracture-porosity reservoirs (Fig. 10.8).

10000

1000

Permeability (10 3μm2)

Fig. 10.8 Relationship between the porosity and permeability of shoal facies reservoirs of the Changxing Formation in the Yuanba gas field

correlation between porosity and permeability is poor, which reflects the development of cracks in some samples. Comprehensive analysis indicates that the reservoir types are dominated by porosity and fracture-porosity reservoirs.

100

10

1

0.1

0.01

0.001

0

5

10

15

Porosity (%)

20

25

10.4

Main Gas Layer Characteristics

279

Fig. 10.9 Hydrocarbon accumulation in the Changxing Formation of the Yuanba gas field

Table 10.4 Petrophysical properties of different sedimentary facies belts in the Changxing Formation of the Yuanba area

Property

Platform margin reef–shoal facies

Platform margin shoal facies

Open platform facies

Local platform facies

Slope-Shelf facies

Porosity (%)

0.59–23.59/5.24 (329)

0.99–20.51/4.87 (365)

0.62– 19.98/2.71 (70)

0.95–3.59/1.53 (43)

1.02–3.01/1.56 (21)

Permeability (mD)

0.003– 1720.719/40.165 (329)

0.003– 2385.483/38.053 (365)

0.002– 224.757/4.3 (70)

0.003– 253.504/15.59 (43)

0.004– 945.48/60.698 (21)

Note The number after “/” is the average value and the number in parentheses is the number of samples Table 10.5 Statistics of the thickness and porosity of reefs with different microfacies in the Changxing Formation in the Yuanba area

Vertical location of the reef

Total thickness

Type I

Type II

Type III

Reef cap

40

2.5

18.2

19.3

Reef-core

14.8

0

2

12.8

3.2

Reef-crest

86.80

43.02

Reef-base

0.6

0

0.1

0.5

0.5

Back-reef

88.55

25.20

Reservoir thickness (m)

Average porosity (%)

Lateral location of the reef

Reservoir thickness (m) Average value

Types I + II

5.2

Fore-reef

38.00

10.60

280

10.4.4.3 Main Factors Controlling the High-Quality Reservoir The formation of high-quality reservoirs was affected by early atmospheric freshwater dissolution, dolomitization, multi-phases tectonic fracturing and deep-burial dissolution of organic acids and TSR (thermochemical sulfate reduction) in the Changxing Formation of the Yuanba area. Based on the cores and thin sections observation, analysis of geochemical data, and statistics, the main reservoir space consists of intergranular pores and intergranular dissolved pores formed by dolomitization, and biocavities, intragranular pores formed by selective dissolution of early atmospheric freshwater. The proportion of fractures and non-selective pores formed by deep-burial dissolution is relatively low in the Yuanba gas field (Guo and Guo 2012; Guo et al. 2017; Guo 2011c; Ma et al. 2014). (1) The reef–shoal facies at the margin of the platform are the basis for the formation of high-quality reservoirs The sedimentary environment controls the sedimentary facies, sedimentary microfacies, and types of original sediments and early diagenesis, which are the basic factors controlling the formation of high-quality reservoirs. The analysis of data obtained for cores from the Yuanba area shows that reef–shoal facies at the margin of the platform are the most favorable facies belts for the formation of high-quality reservoirs (Fig. 10.9). Correlation statistics of microfacies and reservoirs encountered by drilling in the Yuanba area show that, vertically, the favorable reservoirs are mainly developed at the reef cap in the reef; Laterally, the favorable reservoirs are developed at the reef-crest and back-reef (Tables 10.4 and 10.5). The shoal facies can be divided into high- and low-energy shoals. Based on the statistics of the types and thickness of well-drilled shoal facies reservoirs, favorable reservoirs are mainly developed at the “shoal core” of high-energy shoals, followed by “shoal edge” and low-energy shoals; “intra-shoal” reservoirs are relatively poor. High-quality reservoirs are mainly developed in the sedimentary environment with a strong hydrodynamic force and prone to exposure and dissolution. (2) Constructive diagenesis further increases the reservoir porosity Based on the analysis of the relationship between the dolomite content and the porosity of the thin sections of the Changxing Formation in Yuanba well 2, the reservoir properties are closely related to the degree of dolomization. When the dolomite content is less than 80%, the sample porosity is below 4%. The dolomite content of type I and II

10 Yuanba Gas Field

reservoirs with porosity greater than 5% is mostly above 90%. The average porosity of dissolved pore bioclastic dolomite, residual bioclastic dolomite are 9.03%, and the average porosity of crystalline dolomite is 6.65%. The average porosity of sponge reef dolomite and sponge reef limestone is 5.0% and 2.97%, respectively. The reservoir properties of bioclastic dolomite and residual bioclastic dolomite are the best, followed by crystalline dolomite and reef dolomite, while the properties of the sponge reef limestone are poor. Some selective dissolution pores formed by early exposure and dissolution during the unconsolidated or semi-consolidated rocks of the penecontemporaneous stage. Although completely cemented by later filling, they are prone to late dissolution, which is beneficial to the formation of massive dissolved pores. With the increases in the burial depth, temperature, and pressure, the rocks underwent large-scale dissolution by hydrothermal fluids, such as a large amount of organic acids released by tectonic activities and organic maturation. In addition, dolomite and calcite fill a small number of pores and fractures in the late diagenetic stage, which is destructive with respect to the reservoir properties. However, this destructive effect on the reservoir properties is much less than that of dissolution and neomorphism. (3) The three phases of fractures improve the reservoir properties Based on the comprehensive analysis of FMI images and cores, thin sections, and seismic data, the three phases of fractures play important roles in improving the reservoir pores and permeability in the Changxing Formation in the Yuanba area. As the migration pathway for fluids of oil and gas or organic acids, fractures are conducive to the occurrence of dissolution and have an obvious indirect effect on the reservoir space. On the other hand, the permeability of the reservoir is obviously improved by the communication of fractures because the reservoir space is mainly composed of micro- and thin throats in the Changxing Formation. (4) The late closed diagenetic environment and hydrocarbon charging are favorable for pore preservation During the deposition of the Feixianguan 4th member and subsequent depositions, the northeastern Sichuan area was mainly composed of sedimentary purple-red mudstone, marl, gypsum, and dolomite. Although this composition is not conducive to reservoir development, it provides extremely important regional cap-rock. As a result, the reservoir was in a relatively closed environment, in which it was difficult for external fluids to enter the reservoir and thus the fluid

10.4

Main Gas Layer Characteristics

281

activity was weak in the later period and it was difficult to produce large-scale precipitation cementation. After hydrocarbon charging in the early stage, the reservoir was divided into an oil-bearing zone and aquifer zone. In the oil-bearing zone, hydrocarbons displaced the fluid in the pores or altered the properties of the original fluid. The associated organic acids and CO2 carried by hydrocarbons made the pore water slightly acidic, and inhibited diagenetic cementation, thus effectively preserving the pores and reservoirs. Late oil cracking caused a significant increase in the reservoir pressure and natural gas drove out pore fluids, which inhibited the water–rock interaction, and then protected the reservoir.

middle Yanshan movement (Duan et al. 2013; Li et al. 2016).

10.5

10.5.2 Recovery of the Accumulation Process

Dynamic Analysis of the Accumulation Process

Based on the burial and thermal histories of the source rocks, the Easy%Ro model was adopted to simulate the change of the vitrinite reflectance with time. The Ro value is used to determine the maturity time, depth, temperature of organic matter and to identify the hydrocarbon threshold and evolution stage of resource rocks. Taking Yuanba 2 well as an example, the hydrocarbon evolution of the source rock by one-dimensional profile was simulated using IES software. The source rocks include the Silurian, Middle and Lower Permian, and Upper Permian Longtan and Dalong Formations, Upper Triassic Xujiahe Formation, and Jurassic in this area. Among them, especially the high-quality mudstone of Permain Longtan and Dalong Formations with high content of organic matter have great potentials for hydrocarbon generation. Based on the single-well burial and thermal histories and analysis of the thermal evolution (maturity history) of organic matter, the Ro value of the source rocks of the Middle and Lower Permian and Silurian Dalong and Longtan Formations exceeded 0.5% and thus entered the oil generation threshold in the Late Indosinian period (200 Ma). In the early Middle Jurassic (175 Ma), the oil generation reached a peak. In the early Late Jurassic (155 Ma), the source rocks of the Middle and Lower Permian Dalong and Longtan Formations entered the high maturity stage, with a Ro value >1.25%, and the condensate wet oil–dry gas hydrocarbon generation. While the Silurian source rocks entered high- to over maturity stage, with a Ro value >1.5%. Subsequently, with the increase in the burial depth, the Ro value of the source rocks continuously increased. Due to the middle Yanshan movement, the uplift of the Yuanba area was subjected to denudation and hydrocarbon generation of the source rocks gradually stopped. The maturity of the source rocks of each layer was the same as that during the

10.5.1 Accumulation Time and Period The study of fluid inclusions in samples from the Yuanba gas field shows that the crude oil of the Changxing and Feixianguan Formations underwent two stages of oil filling from the Late Triassic to Early Jurassic (equivalent to the Late Indosinian–Early Yanshanian movements; Fig. 10.9), which matches the oil generation peak of the Upper Permian source rocks.

The Yuanba gas field is now found to be gas reservoirs, and the Changxing Formation reservoir contains a large amount of filling asphalt, indicating that there was an oil and gas charging to form an ancient oil reservoir, and then the ancient oil reservoir was cracked into a gas reservoir. Although the reef and shoal lithologic traps are independent, many fractures were generated by the late tectonic uplift and the stratum heights differed. Under the action of buoyancy, secondary migration of some oil and gas could occur along the fractures. Based on the cross section of Yuanba wells 27–204–2–21–102–11–124–16–9 and the relationship among the structural evolution, hydrocarbon generation, expulsion history of source rocks, and evolution of the transmission system, the accumulation process of the Yuanba gas field can be divided into the following four stages: lithological trap formation, paleo-oil reservoir accumulation, paleo-gas reservoir accumulation, and natural gas adjustment and re-accumulation (Fig. 10.10). However, the accumulation process has always been completed in the initial lithological trap (Guo 2009, 2011a; Duan et al. 2013; Wang et al. 2014). Lithologic trap formation stage (Late Permian–Triassic): The Kaijiang–Liangping shelf was formed due to the Emei taphrogenic movement and the high-quality hydrocarbon sources of the Longtan Formation developed. The platform margin reef–shoal reservoirs of the Changxing and Feixianguan Formations developed on both sides of the continental shelf, representing the material foundation and reservoir space for oil and gas accumulation. In the Middle Triassic, regional well-developed gypsum cap-rocks developed, and then lithologic traps formed in the reef–shoal at the platform margin. Paleo-oil reservoir formation stage (Late Triassic–Early Jurassic): The source rocks of the Upper Permian Longtan Formation (Wujiaping Formation) matured and entered the

282

10 Yuanba Gas Field (m) Yb27

Yb204

Yb2

Yb21

Yb102 Yb11

Yb124

Yb16

Yb9

Yb3 T1f4

-5800 -6000 -6200 -6314.9m Paleo-OWC -6367m

-6400 -6600

0

1

2

P 2c P2w

3 km

-6800

-4400

T1f4-3

-6163.5m Paleo-OWC -6212.1m

P2d

(c) Current gas reservoirs adjusted for tectonic movements during the Himalayan period Yb27

Yb204

Yb2

Yb21

Yb102 Yb11

Yb124

Yb16

Yb9

Yb3 T1f4

-4600 -4800

T1f4-3

-5000 P2c

-5200

-2200

P2w

(b) During the Middle Yanshan tectonic movement period (at the end of the Shaximiao Formation), the ancient oil reservoirs were cracked into oil and gas reservoirs, with local adjustments.

-5400

Yb27

Yb204

Yb2

Yb21

Yb102 Yb11

Yb124

Yb16

P2d

Yb9

Yb3 T1f4-3

-2400

Paleo-OWC P 2c

-2600 P 2w

P2d

-2800 Yb204 Yb27 Yb29 Yb2 Yb21

(a) Formation of lithologic paleo-reservoirs at the end of the Xujiahe Formation Yb102 Yb11Yb16Yb3 Yb9 Yb124

Fracture

Oil layer

Gas layer

Water layer

Migration path

Source rock

Fig. 10.10 Natural gas accumulation process and model of the Changxing Formation in the Yuanba gas field

oil generation stage. Adjacent to the northern hydrocarbon generation center, the hydrocarbon generation intensity in the Yuanba area reached 100–210  104 t/km2 and the hydrocarbon expulsion efficiency was *30 to 40%. Discharged crude oil vertically migrated to the reservoir along with fractures, pores, and joint fissures. The crude oil generated from the source rocks of the Dalong Formation laterally migrated to the reservoir, forming several independent reef–shoal lithologic reservoirs. Independent paleo-oil–water interfaces were found in the Yuanba 9 and 123 well areas using core and thin section observations. Paleo-gas reservoir formation stage (Middle Jurassic– Early Cretaceous): The ancient crude oil was cracked and the paleo-lithologic gas reservoir was formed. With increasing

buried depth, the temperature of the reservoir gradually increased to and exceeded 150 °C; it exceeded 200 °C during the period with maximum buried depth (Early Cretaceous). Based on previous studies, 150 °C is the upper limit of the stable existence of crude oil in formations. Therefore, the crude oil must undergo cracking and the phase transition from oil to gas. In the process of crude oil cracking, overpressure may occur and some natural gas may re-migrate along with fractures. Since the formation of the paleo-oil reservoir, fractures widely developed in the dolomite reservoir of the Changxing Formation in the Yuanba area due to the effect of the multi-period Yanshan movement. The reservoir space was mainly dominated by pores during the filling with crude oil, which evolved into

10.5

Dynamic Analysis of the Accumulation Process

structural fractures and pores, enhancing the connectivity of the reservoir. Natural gas adjustment and re-accumulation stage: Since the Late Cretaceous, the natural gas has been adjusted and re-aggregated due to late tectonic movements. Under the influence of the uplift of the Jiulongshan anticline in the north, the strata in the Yuanba well 27 area continued to rise as a whole, natural gas migrated and gathered again in the north, and the lithologic gas reservoir finally formed. Due to the influence of natural gas adjustment and re-accumulation, there is no formation water in Yuanba wells 27, 204, and 2, which are located at a relatively high position of the structure at present. Bottom water was found in Yuanba wells 9, 16, and 123, which are located at a low position of the structure at present. At this stage, the lithologic traps of every reef– shoal still had independent gas–water interfaces. For example, the gas–water interfaces of the traps in Yuanba wells 16 and 9 differ. The H2S content of the natural gas trapped at the high position is lower than that of the water-bearing traps at the low position of the structure.

References Bureau of geology and mineral resources of Sichuan province (1981) Regional geology of Sichuan province. Geology Press, Beijing Cai X, Guo X, He Z et al (2016) Dynamic accumulation of natural gas in Sichuan Basin. Science Press, Beijing Duan J, Li P, Chen D et al (2013) Formation and evolution of the reef flat facies lithologic gas reservoir of Changxing formation in Yuanba gas field, Sichuan Basin. Lithol Reserv 25(3):43–47 Guo T (2009) Gas accumulation conditions and key exploration & development technologies in Yuanba gas field. Acta Pet Sin 40 (6):748–760

283 Guo T (2011a) Sequence strata of the platform edge in the Changxing and Feixianguan formations in the Yuanba area, northeastern Sichuan Basin and their control on reservoirs. Acta Pet Sin 32 (3):387–394 Guo T (2011b) Basic characteristics of deep reef-bank reservoirs and major controlling factors of gas pools in the Yuanba gas field. Nat Gas Ind 31(10):12–16 Guo T (2011c) Reservoir characteristics and its controlling factors of the Changxing formation reservoir in the Yuanba gas field, Sichuan Basin, China. Acta Petrol Sin 27(8):2381–2391 Guo X, Guo T (2012) Exploration theory and practice of large gas fields at the edge of Puguang and Yuanba carbonate platforms. Science Press, Beijing Guo X, Guo T, Huang R et al (2014) Cases of discovery and exploration of marine fields in China (Part 16) Yuanba gas field in Sichuan Basin. Mar Orig Pet Geol 19(4):57–64 Guo X, Hu D, Huang R et al (2017) Developing mechanism for high quality reef reservoir (Changxing Formation) buried in ultra-depth in the big Yuanba gas field. Acta Petrol Sin 33(4):1107–1114 Guo X, Hu D, Li Y et al (2018) Discovery and theoretical and technical innovations of Yuanba gas field in Sichuan Basin, SW China. Pet Explor Dev 45(1):14–26 Li P, Guo X, Hao F et al (2016) Paleo-oil-reservoirs reconstruction and oil correlation of Changxing formation in the Yuanba gas field, Sichuan Basin. Earth Sci J China Univ Geosci 41(3):452–462 Ma Y, Mu C, Guo X (2006) Characteristic and Framework of the Changxingian Sedimentation in the Northeastern Sichuan Basin. Geol Rev 52(1):25–29 Ma Y, Cai X, Zhao P (2014) Characteristics and formation mechanisms of reef–shoal carbonate reservoirs of Changxing-Feixianguan formations, Yuanba gas field. Acta Pet Sin 35(6):1001–1011 Pu Y (2011) Multi-scale seismic identification of deep reef-bank reservoirs in the Yuanba area. Nat Gas Ind 31(10):27–31 Wang L, Zou H, Duan J (2014) Study of carrier system and its control on hydrocarbon reservoirs, Yuanba gas field. Pet Geol Recover Effic 21(5):40–44 Xiao Q, Li L, Qu D et al (2012) Fine description on the seismic facies of reef-beach reservoir in Changxing formation, YB area. Geophys Prospect Pet 51(1):98–103

Pengzhou Gas Field

11.1

Geographical Location and Regional Geological Settings

11.1.1 Geographical Location The Pengzhou gas field is located in Pengzhou and Dujiangyan in the Sichuan Province, *45 km southeast of Chengdu. The geographical coordinates are 103°36ʹ–104° 06ʹ E and 30°50ʹ–31°12ʹ N. The gas field is at the western edge of the western Sichuan plain with convenient transportation conditions and plentiful industrial and agricultural production.

11.1.2 Regional Structure The Pengzhou gas field is situated in the western part of the Sichuan Basin, with the Longmenshan thrust structure belt and central Sichuan uplift on the western and eastern sides, respectively. The structural unit is in the central part of the western Sichuan depression. The area is mainly controlled by the Longmenshan thrust structure belt. The Longmenshan thrust structure belt and foreland area have complex structures; the deformation intensity gradually decreases from west to east. The structural framework was controlled by several major fault zones, which can be divided into three level I and five level II structural units (Fig. 11.1a). The characteristics of the major structural belts are as follows: (1) Songpan–Ganzi fold belt. It is located in the west of the Qingchuan–Maowen fault zone. The strata exposed on the surface are mainly Silurian, Devonian and Triassic, and partially Carboniferous and Permian, and contain granite bodies and fold faults. The fold belt is the joint between the Songpan–Ganzi Block and the Longmenshan thrust belt. (2) Thrust–nappe belt. It is located between the Qingchuan–Maowen and Beichuan–Yingxiu fault zones.

11

The Beichuan–Yingxiu fault zone contains two faults, that is, the Tongjichang and Guankou faults. The Silurian system and Paleozoic are mainly exposed in the northern and southern parts, respectively, and the middle part is characterized by a multi-period volcanic rock body. The fold deformation of the Silurian is strong and thrust faults are relatively developed, indicating ductile deformation. (3) Thrust fold belt. It is located between the Beichuan– Yingxiu and the Guanxian–Anxian fault zones. The Triassic, Permian, and Devonian systems and Triassic and Permian systems are mainly exposed in the northern and southern parts, respectively. The tectonic belt contains many thrust faults and fold structures. The stratum, with northwest orientation, has a large dip angle and gradually decreases downward. Many klippe structures are developed in the tectonic belt, indicating notable gravity slumped overthrust characteristics. The slumped overthrust structure formed relatively late. (4) Concealed foreland fault–fold belt. It is the thrust front structural belt, which mainly contains a series of fault-related folds. The fault is not exposed on the surface (Pengxian fault, Fig. 11.1b) and the shape of the anticline can be observed in Cretaceous strata. The strata involved in deformation include the Upper Triassic-Quaternary, and the Pengzhou gas field is part of this structural unit. (5) Foreland depression belt. It is an area east of the Pengxian–Dayi concealed fault. The structural deformation of this belt is weak. The belt is mainly a detachment layer in the Middle Triassic in which a series of low-amplitude structures are formed by regional slippage. Based on the structural characteristics of the Leikoupo Formation, the structural units can be divided into “two uplifts, two depression, and two slopes,” that is, the Longmenshan piedmont and Xinchang structural belts, Yuantong–Ande and Mianzhu depressions, and Guanghan–Zhongjiang and Wenxing–

© Geological Publishing House and Springer-Verlag GmbH Germany 2020 Y. Ma, Marine Oil and Gas Exploration in China, https://doi.org/10.1007/978-3-662-61147-0_11

285

286 Fig. 11.1 Division of the structural elements (a) and sectional view (b) of the Longmenshan thrust belt and western Sichuan Foreland Basin1. Wenchuan–Maowen fault 2. Beichuan–Yingxiu fault 3. Tongjichang fault 4. Guankou fault 5. Pengxian fault 6. Longquanshan fault belt

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Pengzhou Gas Field

11.1

Geographical Location and Regional Geological Settings

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Mianyang slopes. The structural and slope belts are conducive to the development and accumulation of lithologic traps in the Leikoupo Formation (T2l; Fig. 11.2).

11.1.3 Stratigraphy The western Sichuan depression has experienced the main sedimentary evolution stages of the Sinian–Middle Triassic marine facies, Late Triassic early marine–continental transitional facies, and Late Triassic–Quaternary continental facies. The stratigraphic development is relatively complete and the total thickness is >10,000 m (Fig. 11.3). The Ordovician to Carboniferous are missing in most areas, and

only in areas west of Guanxian–Anxian fault, the strata of Devonian–Carboniferous can be found (Fig. 11.1). The Leikoupo Formation (T2l), the main producing layer of the Pengzhou gas field, consists of dolomite, limestone, gypsum rock, and claystone. From the bottom to the top, it can be divided into four members. The lithology is dominated by dolomite, followed by limestone and gypsum rock.

11.1.4 Structural Evolution History The western Sichuan area, which contains the Pengzhou gas field, has experienced many tectonic movements among which the Chengjiang, Indosinian, Yanshan, and Himalayan movements have been the most important (Fig. 11.3).

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Fig. 11.3 Stratigraphic development and lithology characteristics of the western Sichuan depression in the Sichuan Basin

Pengzhou Gas Field

11.1

Geographical Location and Regional Geological Settings

289

Fig. 11.4 Pre-sedimentary paleogeological map of the Sichuan Basin in the Late Triassic

Chengjiang movement. It was a fold movement during the Nanhuan system after the formation of a strong fold base in the Jinning period and is *750 million years old. The Chengjiang movement led to the gradual stabilization of the crust in the Sichuan Basin. The sedimentary strata of Sinian (Doushantuo and Dengying formations) on top of the Sichuan Basin has a relatively stable lithology and thickness and became the first set of sedimentary cap rocks after the formation of the ancient Yangtze Plate. Indosinian movement. It can be divided into the early and late Indosinian movement. Early Indosinian movement. It includes two episodes, that is, Indosinian I and II. During the Indosinian I (T3/T2) period, the Yangtze Plate collided with the North China

Plate and the South Qinling was fully orogenic and thrust southward, which resulted in an extensive angular-parallel unconformity contact between the Middle and Upper Triassic in the Sichuan Basin and the extensive shrinking of the sea area from east to west. This revolutionary movement is the main episode of the Indosinian movement, also known as the “Xinchang movement” (Yang 2014). During this period, the Luzhou–Kaijiang paleo-uplift formed, the seawater exited the basin to the west, and the Leikoupo Formation (T2l), the main producing layer of the Pengzhou gas field, suffered from varying degrees of erosion (Fig. 11.4) in the Sichuan Basin, except for the Luzhou–Yongchuan area. The Leikoupo Formation (T2l) in the western Sichuan depression is the most complete, with a thickness of up to 1200 m.

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Based on the residual structure of the Leikoupo Formation in the Sichuan Basin, the karst highland–karst slope–karst depression of the Early Indosinian movement can be further divided from west to east. The western, northern, and southwestern Sichuan areas are at the paleo-karst slope area. The Indosinian episode II was a minor tectonic activity during the Late Triassic, that is, between the Late Triassic Xiaotangzi period (T3t) and the second member of the Xujiahe Formation (T3x2). The Xiaotangzi Formation is the first stage of the Late Triassic. The Ma’antang Formation may be older. Both groups contain carbonate and carbonaceous claystone, claystone, quartz sandstone (deposits of lowstand system tract/LST). As for the Xujiahe Formation, it is composed mainly of clastic rocks. While the strata of T3t is missing in the Pengzhou area. Late Indosinian movement. It includes episodes III and IV. The Indosinian episode III is the tectonic movement between the fourth and third member (T3x4/T3x3) of the Upper Triassic Xujiahe Formation. The Indosinian episode IV is characterized by an extensive angular unconformity between the Upper Triassic Xujiahe Formation and Lower Jurassic (J1/T3) and the main formation stage of the western Sichuan foreland basin. During the Indosinian episode IV, the tectonic deformation was strong, the northern branch of the Paleo-Tethys closed, the Songpan–Ganzi Block was folded inversion, the tectonics reversed, the Longmenshan progressively thrust from the northwest to southeast, and tectonic deflection occurred in the piedmont area, which resulted in the formation of the Western Sichuan foreland basin (Fig. 11.5). Yanshan movement. In the early Yanshan movement, the foreland basin changed into an intracontinental shallow depression basin. In the late Yanshanian movement, the Yangtze Block began to subduct into the northwest, and the paleo-Longmenshan formed during the Indosinian movement re-emerged. The basement bulge of the back range belt was “squeezed out” and the front range and foreland belts continued to squeeze into nappe to the continental sedimentary basin and formed a new provenance. A rejuvenated foreland basin was also developed in the front- range belt in the Late Cretaceous–Paleogene (Fig. 11.5). Himalayan movement. Longmenshan was strongly uplifted, thrust over the basin, and the deformation was finalized (Fig. 11.5).

11.2

Exploration and Discovery Process

In 2006, a new round of oil and gas exploration of marine strata in western Sichuan was launched. Based on the new results regarding the basic geology, reservoir forming conditions, and zone evaluation, the Permian and Triassic marine strata in the western Sichuan Basin belong to the

Pengzhou Gas Field

most important hydrocarbon-bearing strata. The unconformity surface at the top of the Leikoupo Formation (T2l) and reef–shoal facies that developed in the Permian are the two most promising areas for oil and gas exploration breakthroughs (Xu et al. 2012; Zhou et al. 2010) and the Xinchang and Longmenshan foreland concealed tectonic belt are the most favorable exploration targets. Therefore, the scientific exploration well CK1 was deployed in the Xinchang structural belt in 2007. In 2010, the well CK1 at the top of the Leikoupo Formation (T2l) was tested. A natural gas flow of 86.8  104 m3/d was obtained, representing the new discovery of natural gas exploration in the “unconformity surface” of the Leikoupo Formation (T2l) in western Sichuan. In 2012, well XS1 was deployed in the eastern section of the Xinchang structural belt. Natural gas reserves of 68  104 m3/d were reported. The gas reserves predicted for the Xinchang structural belt were 795  108 m3. The gas reservoir in the 4th member of the Leikoupo Formation, Xinchang structural belt, (T2l) was discovered. To expand the exploration results of the 4th member of the Leikoupo Formation (T2l), Sinopec decided to expand the deployment area and take the Longmenshan foreland concealed tectonic belt as a target. From 2014 to 2015, wells PZ1, YaS1, and YS1 were deployed in the Longmenshan foreland concealed tectonic belt. Industrial gas flow was obtained in the 4th member of the Leikoupo Formation (T2l). Predicted and controlled gas reserves of 1,290.7  108 m3 and 1,112.95  108 m3 were reported for the main part of the structural belt. Subsequently, the Pengzhou gas field was discovered. In 2016, Sinopec started the development and construction of the Pengzhou gas field and planned to establish an annual production capacity of 50  108 m3. The first phase is planned at the main part of the Jinma– Yazihe uplift belt, with the actual reserves of 1,900  108 m3 and the production capacity of 20– 30  108 m3/year. In the second phase, the Juyuan, Shibantan, and Dayi structures outside the main Jinma– Yazihe structure were evaluated. At the same time, the Xinchang structural and slope belts were evaluated, striving to realize the reserves of 700–1,000  108 m3 and provide resources guarantee for the production capacity construction of 20  108 m3 in the second phase.

11.3

Geologic Characteristics of the Pengzhou Gas Field

11.3.1 Structural Features The Pengzhou gas field is located in the concealed foreland fault-folded structure belt. The top interface of the Leikoupo Formation is a large forward structure with a northeastern distribution (Fig. 11.6). The Guankou and Pengxian faults are

11.3

Geologic Characteristics of the Pengzhou Gas Field

0

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Legend Fig. 11.5 Tectonic evolution history of typical sections in the Longmenshan area of the Sichuan Basin

boundary faults on both sides of the structural belt, which play important roles in the formation and evolution of the structural belt. Both the Guankou and Pengxian faults have a northeastern trend. The Pengxian fault section has a northwestern

trend and the fracture zone ranges from the Lower Paleozoic to the Quaternary, but the fault throw is small. The faults are multiphase active faults that developed in the Late Indosinian to Yanshan periods. They are the main channels for the

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11.3.2 Trap Features

upward migration of underlying hydrocarbon sources. The structural belt area has a size of *1,050 km2 and the relative height difference of the structure is more than 1,000 m. The structural belt contains seven local structures: Bailuchang, Yazihe, Jinma, Juyuan, Shiyangzhen, Shibantan, and Jiezi. The local structural types are anticline and fault anticline, which mainly formed in the Indosinian–Yanshan periods.

Based on the data of drilling, seismics, and tests, it is shown that the 4th member of the Leikoupo Formation (Lei 4) gas reservoir of the Pengzhou gas field is a “structural–lithologic trap gas reservoir,” which consists of the Jinma (653.02 km2), Bailuchang (51.7 km2), and Shibantan (67.7 km2; Fig. 11.6)

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Fig. 11.6 Top surface structure map of the Leikoupo Formation in the Longmenshan front tectonic belt, Sichuan Basin

11.3

Geologic Characteristics of the Pengzhou Gas Field

structural–lithologic traps. *7,382.63  108 m3.

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11.3.3 Gas Reservoir Characteristics (1) Formation pressure. The original formation pressure of the Lei 43 gas reservoir of the Pengzhou gas field is 63.57–67.81 MPa and the original formation pressure coefficient of the gas reservoir is 1.11–1.12. It is a normal-pressure gas reservoir. (2) Formation temperature. The formation temperature of the Lei 43 gas reservoir of the Pengzhou gas field is 143.11–151.7 °C and the geothermal gradient is 2.27 ° C/100 m–2.33 °C/100 m, with an average of 2.29 ° C/100 m, representing a normal geothermal gradient. (3) Fluid properties. The natural gas has a methane content of 89.15%, ethane content of 0.12%, propane and higher-alkane contents of zero, carbon dioxide concentration of 5.22%, nitrogen content of 1.36%, and hydrogen sulfide content of 4.06% (58.2594 g/m3), showing that the Lei 43 gas reservoir of the Pengzhou gas field is a high-sulfur gas reservoir. The relative density, critical temperature, and critical pressure of the natural gas are 0.5956 g/m3, 190.18 K, and 4.5941 MPa, respectively. Currently, the Pengzhou gas field contains three wells, all of which are free of water. Based on the results of the formation water analyses in wells TS1 and XaS1 of the Leikoupo Formation, the formation water is of CaCl2 type and the total salinity of the water sample mainly ranges from 50,725 to 114,614.5 mg/L, with typical long-term highly closed-water chemistry characteristics, indicating that the gas storage conditions are good. In summary, based on the three wells of the Pengzhou gas field, the fourth member of the Leikoupo Formation has a large thickness, stable distribution, no water-bearing characteristics, normal temperature, normal pressure, high sulfur content, and medium carbon dioxide content; it is a structural–lithologic trap gas reservoir (Fig. 11.7).

11.4

Geological Characteristics of the Main Oil and Gas Intervals

11.4.1 Stratigraphic Profiles The top of the Middle Triassic Leikoupo Formation (T2l) in the Sichuan Basin is a regional unconformity. The Upper Triassic Ma’antang and Xujiahe Formations are overlying the interface from northwest to southeast (Fig. 11.8). Due to the different degrees of erosion caused by the Xinchang

movement, most areas of the Leikoupo Formation are incompletely preserved. The thickness ranges from 0 to 1200 m, with a thinning trend from west to east (Fig. 11.8). Vertically, T2l can be generally divided into four lithological members (T2l1–T2l4). Among them, the 4th member of the Leikoupo Formation (T2l4) is mainly distributed in the central and western parts of the basin, with a thickness of 0–570 m (Fig. 11.9). Member T2l4 in western Sichuan can be further divided into three sub-members (Fig. 11.10). The sub-member Lei 41 is completely preserved in western Sichuan, with a thickness of *100–220 m. It is dominated by very thick gypsum rock, with some microcrystalline dolomite. The sub-member Lei 42 is *60–80 m thick with gypsum rock and microcrystalline dolomite; it has an unequal thickness and is interbedded. The sub-member Lei 43 is *0–150 m thick and mainly composed of micro- to fine-crystalline dolomite, limy dolomite, dolomitic limestone, and algae calcarenite. It is mainly distributed in the west of well CH100 and gradually pinching out to the eastward. However, the oil and gas layers that currently are being discovered are mainly distributed in sub-member Lei 43 (Song et al. 2013).

11.4.2 Stratigraphic Sequence and Facies 11.4.2.1 Sequence Features The sedimentation of the Middle Triassic Leikoupo Formation (T2l) in the Sichuan Basin lasted for *5–6 Ma. The formation experienced two major transgressive and regressive cycles. Two sets of third-order regressive carbonate– evaporite sequences developed, that is, SQ1 (Sequence1) and SQ2 (Sequence2) (Fig. 11.10). SQ1 is composed of T2l1 carbonate and T2l2 evaporite. SQ2 is composed of T2l3 carbonate and T2l4 evaporate–carbonate rock (Li et al. 2016). The transgressive system tract (TST) of SQ2 in the western Sichuan region mainly consists of a set of crystalline powder dolomite, gray microcrystalline limestone, limy dolomite, and gray mud crystalline powder dolomite. The highstand system tract (HST) contains a set of algae-clastic dolomite, which changes upwards into gypsum dolomite. The muddy dolomite at the bottom of T2l4 represents the maximum flooding surface (MFS). The sequence can be found in the whole region. The deposition of HST is thick, reaching 300–450 m. The top boundary of the sequence is an unconformity surface. Due to partial erosion in the later stage, the HST is incompletely developed. The main gas interval of the Pengzhou gas field developed in the HST of SQ2, corresponding to the sub-member Lei 43. Vertically, two fourth-order sequences, XI and XII, are developed in the sub-member Lei 43 and the top and bottom interfaces of the sequence have high electric resistance (Rt) characteristics, which reflect two fourth-order sea level

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Fig. 11.7 Gas reservoir profile of the Lei 4 Formation in the Pengzhou gas field

Fig. 11.8 Contact between the Middle and Upper Triassic in the Sichuan Basin

shallowing cycles. The lithology of XI is mainly algal and crystalline dolomite, with interbedded dedolomitization limestone at the top. The lithology of XII is mainly algal sand limestone, algal limestone, algal dolomitic limestone, and algae limy dolomite (Fig. 11.11).

11.4.2.2 Sedimentary Characteristics In the Early–Middle Triassic, the Sichuan Basin was located at 26.68° N (Lin et al. 2002) and the climate was arid and hot. Affected by the Xinchang movement, the Xuefeng Mountains in the east of the Sichuan Basin were uplifted once again. The western part of the basin was Kangdian ancient land. Together with the barrier function of the surrounding seabed uplift, the entire Sichuan Basin formed a semi-restricted pattern. During the Middle Triassic Leikoupo period, the Sichuan Basin was in an epicontinental marine environment with good sealing conditions and the sediment was mainly affected by the interaction of tides and waves (Chen et al. 2017). The lithology of the Leikoupo Formation was characterized by frequent interbedding of dolomite, limy dolomite, limestones, dolomitic limestones, and gypsums.

Gypsum-salt rocks developed in various intervals and the gypsum block mass are commonly found in limestone. When the Lei 4 member was deposited, the western Sichuan area was affected by barriers such as shoals and islands. Thus, the movement of seawater was restricted, the water circulation was poor, the water was shallow, the energy was low, the salinity was large, and the biological species were monotonous (blue-green algae, ostracods, and lamellibranch). Due to the large amount of sunshine, algae flourished and an ecosystem consisting of algae and microbial bacteria formed. Various types of carbonates formed by algal activities in the sediments, mainly including stromatolites, algal clastics, laminate, and oncolites. Some scholars also referred to this combination as microbial reef and shoal (Liu et al. 2016). When the Lei 41 and Lei 42 sub-member were deposited, the evaporation was strong, the major sedimentation in Pengzhou and its surrounding areas included a large set of gypsum dolomites, the evaporative lagoon of the gypsum rocks, and the evaporative tidal flat. At the time of the deposition of Lei 43, a sublevel transgression occurred and

11.4

Geological Characteristics of the Main Oil and Gas Intervals

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Fig. 11.9 Thickness map of the Lei 4 member in the Sichuan Basin

the seawater gradually faded. The sediments were dominated by dolomite, algae dolomite, and dolomitic limestone tidal flats. The lithology mainly included dolomite, algal dolomite, and dolomitic limestone and mudstones. Due to the shallow waterbody and flat terrain during this period, the short-term evaporation led to salty seawater. At the same time, slight changes in the sea level caused a large area of the platform to flood or become exposed at the surface. Therefore, the tidal flat was the main sedimentary facies type of the sub-member Lei 43 in the Pengzhou area (Fig. 11.11); algal sand shoal could also be found. Based on the characteristics of the sediments and sedimentary structures, three subfacies could be identified (tidal, intertidal and subtidal), in addition to limestone flat, algae limestone flat, dolomitic

flat, algae dolomitic flat, dolomitic limestone flat, and algal sand shoal microfacies. In the supratidal zone, dolomitic flat microfacies most likely developed and the lithology was mainly characterized by penecontemporaneous mud–muddy dolomite, limy dolomite, and argillaceous dolomite. The sedimentary structures mainly included laminate and mud-crack structures. Sedimentary microfacies, such as algae sand shoal, limy dolomite flat, and algae dolomite flat, developed in the intertidal zone and ostracods, foraminifera, and lamellibranch were identified. The lithology was mainly algal limestone, algal clast limestone, algal dolomite, and algae clast dolomite. Horizontal bedding, mud-crack, birdeye, and fenestral structures developed. Sedimentary microfacies,

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Fig. 11.10 Sequence division of the Leikoupo Formation in well CK1 in the Sichuan Basin and comparison with the seismic sequence of section 2006–l4

such as algae limestone flat and shoal microfacies, developed in the subtidal zone. The lithology was mainly characterized by a thick layer of microcrystalline limestone, algae-bearing clast limestone, and algal limestone. When sub-member Lei 43 was deposited, the western Sichuan area was overall relatively stable; large uplift or depression did not occur, and it has a similar sedimentary environment background (Fig. 11.12). Vertically, dolomite flat microfacies dominated in the early and middle stages of the Lei 43 deposition and algae flourished. Dolomite limestone flat, algal limestone flat, and algal sand clast shoal microfacies dominated in the late sedimentary stage and lateral changes were notable, reflecting the sedimentary response characteristics of frequent sea level changes. In the horizontal direction, shoal facies developed on the western margin of the basin and doloarenite and sparry doloarenite were deposited. In the basin, dolomite flat and algal dolomite flat mainly developed.

11.4.3 Reservoir Characteristics 11.4.3.1 Upper and Lower Reservoirs Vertically, the reservoir of Lei 4 member in the Longmenshan foreland concealed tectonic belt mainly developed Lei 43 sub-member (Fig. 11.11). The Lei 43 lithology was limestone at the top (the higher, the more limestone) and dolomite at the bottom (mainly dolomite) and the reservoir petrophysical properties of dolomite were better than that of limestone. The total reservoir thickness of sub-member Lei 43, which can be vertically divided into two sets, was *90– 104 m. The upper reservoir was thin, with a total thickness of 20–35 m, and was mainly a type III reservoir. The type I reservoir was thin; a single layer was 1–2 m thick. The lower reservoir was thick, with a total thickness of 55–84 m. It was mainly a type II–III reservoir, which was interbedded with a type I reservoir with a thickness of 2–5 m. An interlayer

11.4

Geological Characteristics of the Main Oil and Gas Intervals

Fig. 11.11 Profile of the Lei 43 sub-member in the Pengzhou area (well YaS1)

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Fig. 11.12 Sedimentation of the Lei 43 sub-member in wells YaS1–XaS1–CK1–XS1 in the Sichuan Basin

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298 11 Pengzhou Gas Field

11.4

Geological Characteristics of the Main Oil and Gas Intervals

299

a. Microcrystalline dolomite, intercrystalline (dissolved) pore development, well YaS1 5768.3 m, T2l4, casting thin section, 100× (-)

b. Algal laminae dolomite, birdeye - fenestrate pores development, YS1 well 6219.9 m, T2l4, cast thin section, 100× (-)

c. Algal arenaceous clastic dolomite, intergranular dissolution pore and micro-dissolution seam development, YS1 well 6234.08 m, T2l4, cast thin section, 20× (-)

d. Sparry algae cluster containing calcareous dolomite, unfilled fractures, well YS1 6192.58 m, T2l4, cast thin section, 40 (-)

e. Honeycombed dissolution pore and small dissolution pore are developed, well YS1, 6200 m, T2l4, core photo

f. Algal lamellar dolomite, honeycombed dissolution pores distributed along layers, well YS1 6219.7 m, T2l4, core photo

Fig. 11.13 Storage space types and characteristics of the Lei 43 member of the Longmenshan foreland concealed tectonic belt

composed of dolomitic limestone and dolomite algae sand clast limestone with a thickness of *20–25 m was present between the upper and lower reservoirs. The lateral distribution of the interlayer was stable.

11.4.3.2 Dolomite Is the Main Reservoir Lithology There are seven reservoir lithology types: (dissolved pore) muddy powder-crystalline dolomite (microcrystalline, cryptocrystalline; now usually called micrite), (dissolved pore) algae sand muddy and crystalline dolomite, (dissolved pore) algal dolostone, algae-bearing sand muddy powder-crystalline dolomite, limy (included) muddy powder-crystalline dolomite, dolomitic muddy powder-crystalline limestone, and algal sand micrite limestone. The dolomite reservoir has a large total thickness and good physical properties, the average porosity is >5%, and the average permeability is 2.79–3.84  10−3 lm2, a representative for a type I or II reservoir. A limestone-bearing dolomite reservoir forms the type III reservoir, which has an average porosity and permeability of 3.82% and 0.38  10−3 lm2, respectively. Most of the limestone reservoir contains a

non-reservoir layer with an average porosity and permeability 10  10−3 lm2 is 65.4%, 24.3%, and up to 10.3%, respectively. There porosity and permeability are positively correlated (Fig. 11.14).

11.4.4 Reservoir Formation Mechanism 11.4.4.1 The Tidal Flat Environment and Early Dolomitization Are Important Foundations for the Development of Dolomite Reservoirs It is shown from statistics that the porosity of the reservoir is directly proportional to the dolomite content. The rock with a dolomite content over 50% has a porosity above 2%, which is conducive to the formation of an effective reservoir. The distribution of dolomite distribution controls the distribution of the reservoir. When the Lei 4 member was deposited in the Pengzhou area, a tidal flat environment mainly developed and large-scale dolomitization occurred. The high Mg2+ content and highly saline interstitial water derived from the sea provided important conditions for penecontemporaneous and shallow-burial dolomitization. The dolomite crystals were small, mainly micritic–powder-crystalline. In large crystals of micritic–powder-crystalline dolomite, cloudy core-clear rim was common, the degree of crystallinity was good (often subhedral and euhedral), the degree of order was low (the average degree of ordering is 0.655), and the color under cathodoluminescence was weak, mainly dark orange and brown. The above-mentioned characteristics are typical features of penecontemporaneous–shallow-burial dolomite under the control of a tidal flat sedimentary environment. In short, intercrystalline pores that were produced after dolomitization modified the porosity and permeability of the matrix and created favorable conditions for the secondary reformation of the reservoir, that is, the formation of

301

intercrystalline dissolved pores. Therefore, the evaporation environment and the role of freshwater and mixed water are keys to the development of dolomite reservoirs in this area.

11.4.4.2 Penecontemporaneous Dissolution Leads to the Formation of Many Early Dissolution Pores Many penecontemporaneous exposure signs, such as birdeye structures, vadose pisolite, calcium crust structures, collapsed breccia, and slaggy layers, can be found in the Leikoupo Formation in the Longmenshan foreland concealed tectonic belt. Early dissolution pores, such as in corrosion surfaces parallel to the horizon, coelom dissolution pores, moldic pores, fenestral pores, and gypsum solution pores can be observed under the microscope. Multiple sets of upward shallow cycles can be identified; dissolution pores are not developed in the exposed surface of the calcareous crust. Based on the comprehensive evaluation of the reservoir, the reservoir belongs to type III. Algae laminal dolomite, algae sand dolomite, and micritic–powder-crystalline dolomite can be observed below the exposed surface. The pores and vugs are densely developed and most of the pores have lateral orientations. Based on these observations, the reservoir is a type I or II high-quality reservoir. The exposure and dissolution in the penecontemporaneous period play important roles in controlling the distribution of high-quality reservoirs and are the main causes of the reservoir heterogeneity. After multiple phases of penecontemporaneous exposure and dissolution, the superimposed vertical distribution of high-quality reservoirs is established. The more frequent the shallower cycle is, the better is the vertical continuity of the high-quality reservoirs. Conversely, high-quality reservoirs are distributed in type II and III reservoirs. Therefore, the main mechanism for the formation of dissolution pores in the high-quality dolomite reservoirs in the Longmenshan foreland concealed tectonic belt is the dissolution of the penecontemporaneous period. 11.4.4.3 Burial-Dissolution and Surface Karst Further Improve the Reservoir Quality The dissolution during the burial period of the Leikoupo Formation has a strong inheritance and the amount of cementation of preserved pores is small based on the observations under the microscope. The pores that formed during the burial period were mostly expanded by the pores that formed from the pores preserved in the early stage or were modified from the microcracks that formed in the early stage. Finally, high-quality reservoirs with good porosity– fracture connectivities formed. The analysis of the characteristics of the dissolved minerals and the uniform temperature of the brine enclosure indicate that three stages of burial-dissolution occurred. In the first stage, the fluid temperature was 90–120 °C. The dissolved minerals were mainly low-temperature filling

302

Fig. 11.15 Tectonic evolution profile of the Longmenshan foreland concealed tectonic belt in the Sichuan Basin

11

Pengzhou Gas Field

11.4

Geological Characteristics of the Main Oil and Gas Intervals

materials such as vadose silt and fragments in the supergene period. In the second stage, the fluid temperature was 130– 160 °C. The dissolved minerals were fine–coarse crystals automorphic granular texture or saddle dolomite that formed during the burial period and the modification of the predissolved pores. According to the geothermal gradient of 2.4 ° C/100 m in the Sichuan Basin, the first and second stages of dissolution occurred at a buried depth of 3,750–5,000 m and 5,400–6,600 m at the top of Leikoupo Formation, respectively, corresponding to the hydrocarbon generation stage of the middle and lower source rocks of the Late Indosinian Leikoupo Formation and late hydrocarbon generation peak of the Early Jurassic Leikoupo Formation. The dissolution fluid was mainly hydrocarbon generated from mature organics. The CO2 released by the decarboxylation of the hydrocarbon was dissolved in the formation water. Thus, the water became acidic. When the acidic formation water flowed into the predissolved pores, the dissolution increased the predissolved pores and new dissolved pores were created. In the third stage, the temperature was 180–210 °C and pores were partially filled with quartz and fluorite, mainly related to hydrothermal dissolution. Based on the distribution frequency of the enclosures and the characteristics of the pores observed under the microscope, organic acid dissolution dominated in the first and second stages; hydrothermal dissolution was rare in the third stage. Therefore, the high-quality reservoirs of the Leikoupo Formation formed on the basis of the pre-existing pores and fractures that developed in the Late Indosinian period and underwent two-stage organic acid dissolution modification during the burial period.

11.5

Main Control Factors and Enrichment Rules of the Accumulation

11.5.1 Gas Source Comparison of the Leikoupo Gas Reservoir in the Sichuan Basin Several small- and medium-sized gas fields and gas-bearing structures have been discovered in the Leikoupo Formation of the Sichuan Basin. The geochemical characteristics and gas source comparison of the natural gas show that the natural gas in the Leikoupo Formation is derived from the source rocks of the underlying marine strata as well as the Leikoupo Formation itself (Xu et al. 2013; Xie 2015). The marine source rocks under the Leikoupo Formation are generally considered to have good hydrocarbon generation potentials (Teng et al. 2008). Recent studies suggested that the Leikoupo Formation in the western Sichuan Basin also developed a set of lagoon carbonate source rocks with good hydrocarbon generation potentials (Yang 2016).

303

Based on the comparative analysis of the basic characteristics of the gas source, such as the natural gas composition, drying coefficient, natural gas isotopes, biomarker compounds, and maturity, it is believed that the gas reservoir of the Lei 43 sub-member of the Pengzhou gas field is dominated by mixed source gas and the source gas mainly originates from the Middle Triassic Leikoupo Formation and the Permian.

11.5.2 The Main Controlling Factors of the Leikoupo Formation in Pengzhou Gas Field 11.5.2.1 Accumulation Process The top anticline of the Leikoupo Formation in the Longmenshan piedmont structure belt has taken shape in the late Indochina, and the structural inheritance of the Yanshanian has developed, forming structural traps matching the hydrocarbon generation and gas generation peaks of the Leikoupo Formation and Permian hydrocarbon source rocks, which are conducive to oil and gas migration and accumulation. In the Himalaya Period, the structural traps were reconstructed and finalized. The main tectonic activities that affected the gas reservoir of the Leikoupo Formation were the late Indosinian, mid– late Yanshan, and Himalayan movements. Studies of the tectonic evolution study showed that the Longmenshan foreland concealed tectonic belt has a large forward tectonic prototype since the Late Indosinian. Based on the analysis of the evolution of the hydrocarbon source of the Leikoupo Formation, it is in the stage of liquid hydrocarbon production from the source rock, which is accumulated in the high part of the structure in the Longmenshan foreland concealed tectonic belt. The accumulation continued in the Yanshanian Period. Due to the increased burial depth (>5,500 m), pyrolysis started in the early paleo-reservoirs under high-temperature conditions and natural gas was generated, while the underlying Permian pyrolysis of natural gas began to move upwards due to the connection of fractures, which led to the formation of an ancient gas reservoir in the favorable part of the structure. The ancient gas reservoir was adjusted and finalized in the Himalayan stage. The Longmenshan foreland concealed tectonic belt has long been at a high position of the structure, which is conducive to the accumulation of oil and gas (Fig. 11.15). The Guankou and Pengxian faults are two important large faults in the area, both of which are reverse faults. In addition, within the main part of the Longmenshan foreland concealed tectonic belt, several small interlayer faults with a length of less than 2.5 km and fault distance 40 cm). Because the features of this claystone layer in the section and seismic response are clear, it has important significance for the stratigraphic correlation and can be used as an independent lithology section. The 4th Member of Dengying Formation: it is characterized by massive dolomite with siliceous bands or siliceous aggregates and many bacterium and algae which is not as abundant as the 2nd Member of Dengying Formation. The thickness is relatively stable (200–350 m). At the top, a disconformity or conformable surface between the Dengying Formation and Lower Cambrian Maidiping, Zhujiatun, Kuanchuanpu, and Yanjiahe Formations can be observed. It is equivalent to the upper dolomite layer with siliceous bands of Dengying Formation, as classified by the Nanjing Institute of Geology and Paleontology (Nanjing Institute of Geology and Palaeonotology, CAS, 1974, 1979; Table 12.1). Because of the influence of the second stage of the Tongwan movement, the development of the four members of Dengying Formation varies in different districts with uniform surface, which is mainly due to late erosion. The drilling in Weiyuan and Ziyang areas revealed only ten meters of deposits, or even hiatus (Fig. 12.2).

12.2.2 Maidiping Formation (1) Characteristics of the Maidiping Formation The lithology of the Maidiping Formation is dolomite, siliceous-banded dolomite intercalated with phosphorite sandy and gravel bioclastic dolomite or phosphorite sandy and gravel dolomite. Small shell fossils are abundant. The Maidiping Formation overlies the Dengying Formation with a conformable or disconformity contact, and underlies the Qiongzhusi Formation with a disconformity contact. It is widely distributed in the outcrops and coverage areas of Leshan–Yilong, Leibo, and Xishui–Shizhu stratigraphic communities. The thickness is generally 30–50 m. The thickness of the profile where the formation was named is 38.42 m (Yin et al. 1980). (2) Correlation and distribution The outcrop, sedimentary area drilling, and seismic profile data in the periphery of Sichuan Basin indicate that the Maidiping Formation is widely distributed in Sichuan Basin and its periphery, but the thickness varies greatly in different

309

places. There is a large-thickness area in the basin, represented by the Zi 4 well, Gaoshi 17 well between the Moxi– Ziyang sedimentary area, Leibo–Yunshan, Yunnan, and Huidong, Yunnan, etc. and the Maidiping Formation is generally distributed in a north–south direction with a maximum residual thickness of 200 m. However, the thickness in Hanyuan, Ebian, Ziyang (except Zi4 well), Weiyuan and other places in western Sichuan is 0–30 m. The thickness of Moxi–Gaoshiti area is generally less than 20 m, with local area with complete erosion (such as Gaoshi1 well). The thickness in Nanjiang in northern Sichuan and Ningshan in southern Shaanxi is generally less than 10 m.

12.2.3 Longwangmiao Formation The terminology “Longwangmiao” Formation, named after Lu (1941) at Longwang Temple on the western bank of Dianchi Lake, Yunnan Province, is now widely used in Sichuan Basin and its surrounding areas. In the section where the formation has been built, the Longwangmiao Formation consists of dolomitic, argillaceous limestone and argillaceous dolomite with little sand and shale. The formation is continuously deposited with the underlying Canglangpu Formation and covered by Douposi group with a thickness of 176 m, Trilobites and brachiopod fossils can be found in this formation. In Sichuan Basin and surrounding areas, the names of the strata which are contemporaneous of Longwangmiao Formation include the Qingxudong and Shilongdong Formations. However, the general sedimentary sequence and lithological characteristics are clear. Therefore, this formation is easy to be identified correlated at outcrops, drilling, and seismic profile. The Longwangmiao Formation of the An’yue gas field contains granulated dolomite with good reservoir properties. The Longwangmiao Formation in the Weiyuan–Ziyang– Moxi–Gaoshiti area has a residual thickness of *50–100 m, generally 80–90 m. The thickness of the Longwangmiao Formation is approximately 130 m thick in the Shizhu Shuangliuba area on the southeastern edge of Sichuan Basin.

12.3

Sinian–Cambrian Lithofacies Paleogeography

The An’yue gas field contains two main gas-bearing strata, that is, the Sinian Dengying Formation and Cambrian Longwangmiao Formation. The two main gas-bearing strata notably differ with respect to the sedimentary background, sedimentary facies distribution, and reservoir genesis and distribution.

town

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elt

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Source R

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12

Fig. 12.1 Geographical location of the giant An’yue gas field in Sichuan Basin

Ganluo

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Laolong 1 well

Fig. 12.2 Comparison of the Sinian system in Sichuan Basin and its surrounding areas

substratum

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C am br i an

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12.3 Sinian–Cambrian Lithofacies Paleogeography 311

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12

12.3.1 Characteristics of the Lithofacies Paleogeography of the Sinian Dengying Formation Based on the combination of sedimentary facies of the outcrop and drilling core data with seismic facies analysis, the lithofacies paleogeography map of Dengying Formation in Sichuan Basin and its surrounding areas was compiled. Figure 12.3 shows the lithofacies paleogeography map of the 4th Member of Dengying Formation. The paleogeographic pattern is characterized by the inner craton trough and rimmed platform margin around the trough–open platform–restricted platform–evaporation platform, as well as the craton edge– rimmed platform margin, slope, and basin. The petrographic paleogeographic features can be summarized as follows: (1) The general characteristic of the Dengying Formation lithofacies paleogeography in Sichuan Basin and its

An’yue Gas Field

surrounding area is that the Sichuan–Guizhou platform is surrounded by western Sichuan-South Qinling, Wushan–Baoji, and Xianggui slopes-sea basins. (2) The prominent features of the lithofacies paleogeography during this period include a rimmed platform with a ring zonal pattern at the edge of the craton and a rimmed platform along the edge of E’bian–Kangding– Beichuan–Qingchuan–Ningqiang–Hanzhong–Zhenba– Chengkou–Fengjie–En’shi–Lijiang–Zuny. The rimmed platform of the inner craton along the cities of Deyang– Ziyang–Weiyuan–An’yue–Langzhong–Guangyuan is “U” shaped. The two rimmed platforms are connected and twisted leading to a significant increase of the high-energy zone at the platform margin. (3) Both the rimmed platforms at the craton margin and in the inner craton are controlled by the passive continental margin, activity of the syndepositional edge fault, and sedimentation. The development and

Yangxian Kuanchuanpu

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Fig. 12.3 Lithofacies paleogeography of the Member 4 of the Dengying Formation in Sichuan Basin and its surrounding areas

12.3

Sinian–Cambrian Lithofacies Paleogeography E’bian XianfengLaolong 1

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Fig. 12.4 Sedimentary profile of the Dengying–Qiongzhusi Formation integrating outcrop, drilling, and seismic data

distribution of the slope–basin and trough–platform of the inner craton are controlled by the footwall of the syndepositional edge fault and sedimentation. The hanging wall of the syndepositional edge fault controls the development of the carbonate platform, especially the high-energy zone at the platform margin. (4) Mound and shoal complexes are developed at the margin of the platform (Figs. 12.3 and 12.4), which are composed of benthic microorganism community and its biochemical buildup. Benthic microorganisms include viruses, mycoplasma, rickettsial bodies, bacteria, actinomycetes, fungi, cyanobacteria, and small lower algae. Because of the existence of the Deyang–An’yue inner craton rift in the central basin, sedimentary facies differentiation can be observed. In the rift zone, dolomicrite and nodular muddy dolomicrite of the rough–basin facies are developed such as in wells Gaoshi 17 and Heshen 1 (Fig. 12.5a). The hanging wall of the syndepositional edge fault on both sides of the rift is a high-energy belt, forming a mound and shoal complex at the platform margin that horizontally spreads over 500 km. It is U-shaped, and has a large thickness (650– 1,000 m). The lithology of the complex is characterized by microbial framework dolomite (e.g., thrombolites, foam sponge layer, and stromatolites) and granular dolomite (Fig. 12.5b–f). In the seismic section, the mound and shoal complex at the platform margin has mound-like, disorderly reflections and large thickness; whereas the basin facies exhibit layered continuous reflections and small thickness (Du et al. 2016a).

12.3.2 Characteristics of the Lithofacies Paleogeography of the Cambrian Longwangmiao Formation Based on the combination of the analysis of the sedimentary facies of the outcrops and the drilling core data with seismic facies analysis, the lithofacies paleogeography map of the Longwangmiao Formation in Sichuan Basin and its surrounding areas was compiled. Figure 12.6 shows the lithofacies paleogeography map of the Longwangmiao Formation, revealing the distribution characteristics of sedimentary facies under the paleo-tectonic background of uplift and depression. It can be summarized as follows: (1) The sediments of the Longwangmiao Formation are irregularly and semi-circular distributed around the western Sichuan paleo-uplift. The paleo-sea is shallow in the northwest and deep in the northeast and southeast. The hydrodynamic intensity is strong in the northwest and weak in the northeast and southeast. From west to east, the following facies developed: mixed tidal flat of the inner ramp, grain shoal (upper shoal) intershoal sea of the inner/shallow ramp–, open deepwater bay, evaporative lagoon–evaporative tidal flat of the platform depression in the inner ramp, tempestite–barrier beach of the middle ramp, and mound and shoal (lower shoal) of the outer ramp–basin (Du et al. 2016b). There are at least two seaward transgressions, that is, one from the southern Qinling Basin

314

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An’yue Gas Field

Fig. 12.5 Main rock types, sedimentary characteristics, and reservoir space types of the Dengying Formation in Sichuan Basin. a Nodular muddy dolomite, no reservoir, plane polarized light, Gaoshi well 17, 5465 m in the Member 2 of the Dengying Fm; b thrombolite lattice dolomite, dissolution pores are developed in the framework, Moxi well 9; c thrombolite lattice dolomite, dissolution pores are developed in the framework, plane polarized light, Gaoke well 1, the Member 4 of the

Dengying Fm, 5032 m; d foam sponge lattice dolomite, dissolution pores are developed in the framework, (pink) the cast is monopolarized, Gaoke well 1, the Member 2 of the Dengying Fm, 5446 m; e stromatolite (laminated) lattice dolomite, dissolution pores are developed in the bedding layer, Gaoke well 1, the Member 4 of the Dengying Fm, 5158 m; and f sandy dolomite, dissolved pores are developed, Zi well 4, the Member 2 of the Dengying Fm, 4533.1 m

in southwest direction and the other from the Jiangnan (Hunan and Guangxi) Basin in the northwest direction. (2) Controlled by the fault activity on both sides of the platform depression and the high-frequency sea level cycle, the Wanxian–Yibin sag experienced a multi-cycle sedimentary evolution from low-energy, open deepwater to restricted evaporation and low-energy environment, which controlled the multi-cycle high-energy shoal distribution on both sides of the platform depression. Figure 12.7 shows the results for the entire Longwangmiao Formation, revealing the fourth-order sequence 1 and 2, especially the sedimentary evolution from the fourth-order sequence Ssq3 or Ssq4 or Ssq5 transgression system tract (TST) into a highstand system tract (HST).

gypsum-salt rock of the semi-restricted to restricted, low-energy evaporative tidal flats, and evaporative lagoons were deposited in the HST stage. Around the two sides of the depression, open shallow high-energy grain shoal developed in multiple cycles on underwater paleo-high. In addition, Lin well 7 revealed that evaporites characterized by salt rock developed in the evaporation lagoon of the HST, indicating the existence of deep depressions in local areas of the platform depression.

Figures 12.6 and 12.7 show that a depression has formed in the Wanxian–Yibin area since the fourth-order cycle Ssq3, which extends in the northeast–southwest direction. The fossilized muddy limestone of the open deepwater, low-energy, and bay subfacies was deposited in the TST stage. The gypsum-dolomite, gypsum-mudstone, and

(3) The high-energy facies belt is mainly developed around the Central Sichuan syndepositional paleo-uplift. The upper shoal is the most prominent in the high-energy shoal facies belt of Longwangmiao Formation. The upper beach in a semi-annular belt is adjacent to the Motianling–Pengguan–Baoxing Island chain, and develops around the paleo-uplift in western Sichuan. The distribution area can reach 80,000 km2 in the current Sichuan Basin, which is close to 1/2 of the basin area. In addition, it is also developed on the syndepositional paleo-uplift on the outer side of the Wanxian– Yibin depression (i.e., the lower shoal).

12.3

Sinian–Cambrian Lithofacies Paleogeography

315 Qiang1 Zeng1

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plaster dolomite shoal, mound, tidal flat shoal

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shoal, tidal flat

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Back ramp

Inner ramp: shoal and intershoal sea

Lower shoal

Platform depression in inner ramp

Middle ramp: tempestite-barrier shoal, mound

Outer ramp basin: lamina, nodular limestone and claystoen

Fig. 12.6 Lithofacies paleogeography and sedimentary facies profile (C–C′) of the Lower Cambrian Longwangmiao Formation in Sichuan Basin and its surrounding areas

316

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An’yue Gas Field

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outer ramp basin siltstone

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limestone

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Fig. 12.7 Sedimentary evolution of the transgressive and highstand system tracts in high-frequency sequence in the Wanxian–Yibin depression and underwater paleo-high on both sides

Structural Characteristics and Evolution of the Paleo-Uplift Area …

12.4

12.4

Structural Characteristics and Evolution of the Paleo-Uplift Area in Central Sichuan

the southern part of the area is relatively shallow, ranging from 7,000 to 8,000 m. The “one uplift” is the central Sichuan paleo-uplift, which is characterized by a nose-like structure with northwest–southeast orientation. It is high in the southwest and low in the northeast. The buried depth is 3,000–7,000 m and the highest part is in Weiyuan. The present tectonic morphology of the Cambrian Longwangmiao Formation is inherited from the Sinian top (Fig. 12.9). The Central Sichuan Uplift area has expanded compared with the Sinian system. The Weiyuan–Ziyang area in the southwest of Central Sichuan is the highest part of the uplift. It has shallow buried depth of only a few hundred meters. In contrast, the Bazhong area in northern Sichuan has buried depth of almost 10,000 m. The top boundary structure of the Longwangmiao Formation is an incomplete nose-like structure distributed in northeast–southwest direction. The western, northwestern, and eastern Sichuan regions are equivalent to the flank of the nose-like structure. The buried depth gradually increases from the main part of the nose-like structure to the flank and the deepest areas are located in northwestern and northeastern Sichuan.

12.4.1 Features of Paleo-Uplift in Central Sichuan The present Central Sichuan paleo-uplift, which formed due to the Caledonian movement, can be observed on the paleo-geologic map before the Permian and on the Sinian– Lower Paleozoic tectonic map. The current structure of the Dengying Formation can be described as “one uplift between two sags” (Fig. 12.8). The “sag” on the west side is located in the western Sichuan depression and extends northward into the northern Sichuan area. The Dengying Formation is buried at a depth of 7,500–13,500 m. The middle of the western Sichuan depression has the largest buried depth. The “sag” on the east side is located in the eastern to southern parts of Sichuan and has a depth of 7,000–10,500 m. The largest buried depth that exceeds 9,000 m is in the northeastern part of Sichuan. The depth of

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Fig. 12.8 Top surface of the Dengying Formation in Sichuan Basin

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An’yue Gas Field

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Liangping

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Meishan Hanshen 1

Guang’an Moxi 23 Lezhi Moxi 47 Baolong 1 Gaoshi 21 Guiyang An’yue Gaoshi 1 Zi 1 Hechuan Zuo 3 Zi 2 Gaoshi 17 Wei 28

Leshan

Weiyuan

Dazu Heshen 1 Chongqing Pan 1 Dongshen 1 Lin 7

Fushun Yangtan 2

Woshen 1 Gongshen 1

Legend Dingshan 1

Changning Ning 2 Ning 1

wedge out

Lin 1

well

town

Fig. 12.9 Top structure of the Cambrian Longwangmiao Formation in Sichuan Basin

12.4.2 Formation and Evolution of the Paleo-Uplift in Central Sichuan According to the analyses of the Sinian–Cambrian strata, tectonics and sedimentation in the Chuanzhong paleo-uplift area, the paleo-tectonic and lithofacies paleogeography maps of the Dengying and Longwangmiao Formations are systematically compiled using seismic data. The maps reveal that the Central Sichuan paleo-uplift has experienced a five-stage tectonic evolution.

12.4.2.1 Intracraton Rift Stage of the Sinian– Early Cambrian Based on regional tectonic analysis, the paleocontinental plate of South China split due to the structural dynamics of the Rodinia supercontinent breakup. An intracontinental rift developed in the interior of the Upper Yangtze craton during the Nanhua Period. This extensional tectonic effect was also evident in the Sinian-early Early Cambrian. Using earthquake and drilling data of Sichuan Basin, the target horizons were seismically interpreted, and the pinchout

lines and stratigraphic thickness maps of each layer were compiled. These target horizons include the bottom boundary of the Sinian Dengying Formation, Cambrian, Qiongzhusi Formation, Canglangpu Formation, Longwangmiao Formation, Middle Ordovician, Silurian, and Permian, etc. A dark and black carbonaceous shale thickening zone of Maidiping, Niuhutang, and Qiongzhusi Formations of Lower Cambrian can be observed in the central basin areas (e.g., An’yue, Deyang) with up to several hundred meters in thickness and an area of 6
104 km2. Notably, this source rock is not only the main source of hydrocarbon in the An’yue giant gas field but also an important source rock for the area surrounding the central Sichuan uplift (Figs. 12.4 and 12.10).

12.4.2.2 Tongwan Movement and Differential Denudation Paleo-Uplift The paleo-uplift of differential denudation is an ancient uplift that formed by the differential erosion of the stratum and controlled the deposition of overlying strata. In general, such paleo-uplifts are mainly formed in the context of overall uplift or sea level decline. Regional exposure and erosion

12.4

Structural Characteristics and Evolution of the Paleo-Uplift Area …

319 Xi’an

Western Sichuan-Southern Qinling Continental Margin Basin Wudang Block

Hanzhong

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Rift

ton Rift

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Wushan

Wanxian

Upper Yangtze craton Chongqing

Middle Yangtze Craton Yichang

Intr acra

Chengdu A

Deyang-An’yue Rift

Intracraton

Mianyang

Shiyan

Nanjiang

Guangyuan

Shimen

Yibin

Kangdian Paleoland

Baojing Xichang

Upper Yangtze Craton Panzhihua

Tongren

Zunyi

Dongkou Liupanshui

Taijiang Guiyang

Panxian

Kunming

Hunan & Guangxi Continental Margin Basin

Sandu

Ziyun

Xing’an Tongchi

Longlin

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0 Canglangpu Fm

Gaotai Bottom of the Longwangmiao Fm

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Canglangpu Fm

Qiongzhusi Fm Bottom of the Qiongzhusi Fm Dengying Fm

Bottom of the D3 Fm

Maidiping Fm

Bottom of the Dengying Fm 500

5

Fig. 12.10 Prototype of the Sinian Basin in the Upper Yangtze Region

which is effected by lithology and stratum thickness result in significant differences in the paleotopography of the residual strata. The Tongwan movement was a regional tectonic movement that occurred between the Sinian and Cambrian in the Yangtze craton. It was a regional ascending movement, which caused a disconformity contact between the Sinian

and Cambrian. The Tongwan movement in Sichuan Basin and its surrounding areas can be divided into three stages (Wang et al. 2014; Li et al. 2014). The first stage of the Tongwan movement occurred at the end of the 2nd Member Dengying Formation. A disconformity surface can be found in the western part of the Upper Yangtze Craton between the Dengying 2nd and 4th Member,

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new trough-200

0 Jiange

Wenchuan

An’yue Gas Field

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Jiangyou Mianyang

Kaijing NC1

Chengdu

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Suining

Deyang

Liangping

Guang’an Lezhi MX51 BL1 MX23 Guiyang MX47 GS21 An’yue GS1 Hechuan Z3 Z1 Z4 Z2 GS17 Dazu W28 HS1 Chongqing Weiyuan P1 DS1 ZS1 L7 Fushun YS2

HS1 Meishan Leshan

WS1 GS1

Changning N2

N1

DS1 L1

Fig. 12.11 The paleogeomorphology map before Cambrian deposition

which caused the formation of weathering crust in the upper parts of the 2nd Member of Dengying Formation. The second stage of the Tongwan movement took place at the end of the Dengying Formation. It is represented by a disconformity contact between the Dengying Formation and the Lower Cambrian, which is widely distributed in the Yangtze Craton (Fig. 12.8). The third stage of the Tongwan movement occurred at the end of the Early Cambrian Madiping Period or at the end of the Niutitang Period. It is also represented by the disconformity contact between the Lower Cambrian Maidiping Formation and Qiongzhusi Formation. Based on the analysis of the distribution of the residual strata and unconformity, the Tongwan movement is the main stage, which affected widely. Affected by the Tongwan movement II, the Dengying Formation experienced different degrees of denudation and two paleo-uplifts were formed, namely Ziyang and Moxi, which are separated by paleo-rift. Figures 12.10 and 12.11 show the paleogeomorphology map (based on seismic data) before the Cambrian deposition. The map shows that the two paleo-uplifts of Moxi and Ziyang cover areas of 3.0
104 km2 and 2.5
104 km2,

respectively. At the end of the Dengying Formation, the Deyang–An’yue area was uplifted and the platform margins on both sides were denuded. The thickness of the residual stratum at the platform margin was large. For example, the thickness of the residual strata in the 4th Member of Dengying Formation in the Moxi area was 200–320 m. The 4th Member of Dengying Formation in the Deyang–An’yue area was completely eroded and the residual thickness of the 3rd Member of Dengying Formation was only 0–30 m. At Early Cambrian, the thickness of the Lower Cambrian Madidiping Formation was only 0–50 m in the two paleo-uplift areas, but 100–200 m in Deyang–An’yue area. The thickness of Qiongzhusi Formation in Deyang–An’yue area was 500–800 m, while 200–300 m in the paleo-uplift area.

12.4.2.3 Early Cambrian to Silurian Syndepositional Paleo-Uplift The Early Cambrian Canglangpu Period is an important structural transition period of the Upper Yangtze Craton, which is characterized by the transition from early

12.4

Structural Characteristics and Evolution of the Paleo-Uplift Area …

extensional tectonic environment to compressional tectonic setting. The regional extrusion structure caused the unbalanced uplift of the Upper Yangtze Craton. The uplift speed in the western areas was fast and ancient land, such as the Baoxing ancient land, started to form. The core of the Baoxing ancient land is located in the west of Baoxing– Ya’an and extends into the Nanchong and Guang’an areas. It is characterized by syndepositional paleo-uplift with a distribution area of 6–8
104 km2 (Fig. 12.12), which controlled the sedimentation from Canglangpu period to Silurian. The main features are as follows:

321

Basin is 100–200 m and 200–400 m, respectively. The thickness of Longwangmiao Formation is 70–120 m in the central Sichuan Basin but larger in the southeastern Sichuan Basin (160–200 m). The thickness of the Middle Cambrian (Gaotai, Shilengshui, and Pingjing Formations) is 0–100 m in the central Sichuan region and 120–200 m in the southeastern Sichuan region. The Middle–Upper Cambrian Xixiangchi Formation is 0–150 m thick in the Central Sichuan area. The formation is thicker in the southeastern Sichuan area (200–600 m). The Ordovician system is 0–150 m thick in the central Sichuan region but thicker in the southeastern Sichuan region (200–500 m).

(1) Stratum distribution characteristics of the syndepositional paleo-uplift

(2) Granular shoal in the syndepositional paleo-uplift area

Based on the drilling and seismic data, we compiled the isopachous maps of the Canglangpu, Longwangmiao, and Xixiangchi Formations and the Lower Ordovician. The strata in the Central Sichuan paleo-uplift are relatively thin, while thick in the eastern depression and southeastern Sichuan Basin. The thickness of the Lower Cambrian Canglangpu Formation in the central and southeastern Sichuan

The syndepositional paleo-uplift developed on the carbonate platform due to the high sedimentary paleogeomorphology and shallow water and was conducive to the formation of granular shoal bodies surrounding the paleo-uplift. Seismic data showed that the granular shoal of the Longwangmiao Formation in the central Sichuan region is distributed around the paleo-uplift, covering 8000 km2. Drilling data obtained

Fig. 12.12 Distribution of paleo-uplifts in different periods (from Cambrian to Silurian) in Sichuan Basin

322

in Moxi area confirmed that granular shoal developed in at least three stages in Longwangmiao Formation, with a single layer thickness of 10–30 m, cumulative thickness of 30– 70 m; and continuous horizontal distribution. (3) The granular shoal in different layers of the syndepositional paleo-uplift zone migrates toward the slope zone With the continuous growth of the Central Sichuan paleo-uplift, the granular shoal of different layers migrated eastward based on the lithofacies paleogeographic maps. The near-eastern–western section of the paleo-uplift reveals that the granular shoal of the following formations has a tendency to migrate eastward (Fig. 12.13): Lower Cambrian Longwangmiao Formation, Middle–Upper Cambrian Xixiangchi Formation, and Lower Ordovician Tongxin and Honghuayuan Formations. (4) The development of the multi-period exposure surface or temporary erosion unconformity surface in the highland of the syndepositional paleo-uplift is conducive to the formation of karst reservoirs Based on the drilling and seismic data, at least two unconformities including surface between the Longwangmiao and Gaotai Formations and between the Ordovician and Silurian can be identified. Based on the logging and drilling data of the Moxi–Gaoshiti area, layers with dissolution pores are generally developed in the middle and upper parts of the Longwangmiao Formation. The pores which are 2–30 mm and honeycomb-shaped are filled with pyrite and asphalt. Several large-scale caves can be found, for example, in Moxi wells 17, 19, and 202. These caves are filled with late claystone, breccia, and pyrite. In the seismic section, onlap can be observed between the Silurian and Ordovician unconformity and the Silurian is superimposed on the Ordovician, from east to west.

12.4.2.4 Folding Paleo-Uplift at the End of the Silurian The Guangxi movement, which occurred at the end of the Late Silurian, was the strongest tectonic movement in the Caledonian Period in southern China. In the Upper Yangtze region, large-scale northeastward tectonic deformation occurred including the Central Sichuan (also known as Leshan–Longnvsi paleo-uplift) and Central Guizhou paleo-uplifts. Based on the missing Silurian boundary line,

12

An’yue Gas Field

the area of the Central Sichuan paleo-uplift, which is the most important positive tectonic unit of the Paleozoic in Sichuan Basin, is 6.25
104 km2. It is generally believed that the paleo-uplift is a large nose-like structure with northeastward plunge (Fig. 12.12). It is worth emphasizing that the Longwangmiao Formation reservoir in the An’yue area has a good quality because it is associated with the Caledonian karst. Devonian and Carboniferous sediments are completely missing in the An’yue area. Granular and dolomitization shoals are extremely developed in the An’yue area, providing a good initial pore system for the development of dissolution in the later stage. Figure 12.10 shows that the Sinian and Lower Paleozoic strata in the paleo-uplift area are exposed from the west to the east (from old to new). This indicates that the Leshan– Longnvsi paleo-uplift was once again uplifted by the Late Caledonian tectonic movement and a certain degree of fold occurred, followed by erosion. On the other hand, the paleo-uplift zone has an asymmetrical, large nose-like structure. The southeastern flank is narrow and steep, while the northwestern one is gentle. The axis of the paleo-uplift coincides with the Ziyang–Suining–Nanchong area. The above-mentioned observations show that the Central Sichuan paleo-uplift experienced multi-cycle tectonic movement from the sedimentary paleo-uplift of the extensional environment to the tectonic-type paleo-uplift of the compression environment, and from two ancient uplifts to a unified large paleo-uplift. The scale of the paleo-uplift continues to expand from 1–2
104 km2 in the early sedimentary paleo-uplift to 6–8
104 km2 in the late paleo-uplift.

12.4.2.5 Tectonic Deformation and Adjustment in the Yanshanian–Himalayan Stage During the Permian and Triassic, the basin was deposited as a whole, the stratum thickness was relatively uniform, and the entire Sinian system was deeply buried. Despite the Hercynian and Dongwu movements, the Sinian structure in the Central Sichuan paleo-uplift was relatively stable. During the Indo Chinese–Yanshanian Period, the axis of the paleo-uplift shifted to the southeast due to the rapid subsidence and thick deposition of the western and northern Sichuan foreland basin. The Weiyuan–Ziyang paleo-uplift was reconstructed. Weiyuan became a tectonic height and Ziyang gradually changed to be a slope zone, and the Gaoshiti–Moxi paleo-uplift has stable structure shape and inheritable development. During the Himalayan Period, the

12.4

Structural Characteristics and Evolution of the Paleo-Uplift Area … MX21

P O

Liangshan to bottom of Qixia

Tongzi/ Nanjinguan

GR

GR

GT2 GR

RLLD

RLLD

GR 4400

4400

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5050 Huanglong Formation

4650

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4600 4500

bottom of Qixia Liangshan Formation

4600 4550

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RLLD

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323

4700

Longmaxi

Linx

inag

5150

-Ba

4650

C

4550

4750

4600

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ota

Wufeng form atio n

5200

Gaotaizi

4700 Shizipu 5250

Longwangmiao

4650

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4900

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Longtan Formation

Hon

5 6 7 8 9

ghu

any

uan

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mat

ion

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zi F

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n

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5550

Douposi

Lo

ng

wa

ng

mi

ao

Fo

rm

ati

on

Fig. 12.13 Distribution of granular shoal in different layers of the Central Sichuan syndepositional paleo-uplift (see Fig. 12.10 for the drilling locations)

Central Sichuan paleo-uplift was transformed due to the regional tectonic stress. Seperated by Moxi–Gaoshiti, the western part of the paleo-uplift was rapidly uplifted to form the large Weiyuan anticline. In contrast, the paleo-uplift was retained in the eastern part. As a result, the uniform Central Sichuan paleo-uplift was reconstructed, forming a large nose-like structure with the Weiyuan structure as highland. In contrast, the paleo-structure of the Gaoshiti–Moxi area was still well preserved, providing favorable conditions for the preservation of the giant An’yue gas field.

12.5

Discovery of the Giant An’yue Gas Field

The discovery of the giant An’yue gas field is the result of continuous exploration of the Cambrian and Sinian in Sichuan Basin. It can be divided into four stages: the Weiyuan gas field discovery stage (1940–1964); continuous exploration stage (1965–2005); risky exploration stage (2006–2011), and overall exploration stage (2012–present) (Du et al. 2014; Luo et al. 2015).

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12.5.1 Discovery of the Weiyuan Gas Field (1940–1964) The exploration of the Sinian in Sichuan Basin started in the 1940s. After the investigation and evaluation of the surface structure, the Weiyuan anticline was selected as the exploration target. After 24 years and three exploration phases in the Weiyuan anticline, the first gas field was discovered since the founding of New China. In 1940, during the first exploration phase of the Weiyuan anticline, well Wei 1 was drilled to the end of the Yangxin series (mainly equivalent to the Qixia and Maokou Formations) with only micro-gas obtained. In 1956, during the second exploration phase of the Weiyuan anticline, well Weiji was drilled, marking the end of drilling of the Lower Cambrian without industrial gas flow. In 1963, during the third exploration phase of the Weiyuan anticline, the drilling in the Weiji well continued. In September 1964, gas cut and well leakage were found at 2848.5 m on the top of Dengying Formation of upper Sinian. Based on the drill stem test, the daily gas production was 7.98–14.5
104 m3, marking the first breakthrough in the Sinian system. Subsequently, gas was obtained in 12 wells with proven gas area of 216 km2 and geological reserves of 400
108 m3. China’s first fully assembled marine gas field was discovered. The Weiyuan gas field is dominated by the Sinian Dengying Formation. The reservoir is a structural gas reservoir with unified bottom water and low fullness which is 25% of the trapping amplitude. At this stage, the geological understanding was “tectonics control the oil reservoir.”

12.5.2 Difficult Exploration Stage (1964–2005) From the discovery of the Weiyuan Sinian gas reservoir to the end of 2005, the exploration potential of the Sinian– Cambrian system in the Central Sichuan paleo-uplift has been favored by geologists and the system has been continuously explored. In the early 1970s, the Central Sichuan paleo-uplift (also known as the “Leshan–Longnvsi paleo-uplift”) was discovered using gravity, magnetic, and seismic surveys. It is a large nose-shaped paleo-uplift (Fig. 12.14), which is 320 km long, 160 km wide, and covers 6.25
104 km2; the Sinian depth is 2,500–5,500 m. The ancient uplift has a long succession development and the basic geological conditions for the formation of extra-large gas fields. Subsequently, 21 exploration wells were drilled and gas was obtained in 4 wells. Small gas-bearing structures, such as the Ziyang, Gaoshiti, An’pingdian, and Longnvsi structures, were discovered. The estimated reserves of natural gas in the Ziyang area were

12

An’yue Gas Field

102
108 m3 and the prognostic reserves were 338
108 m3. In wells Gaoke 1, An’ping 1, and Nvji of other structures, only low gas flow was obtained and the exploration did not lead to a breakthrough. During this period, the oil and gas geology research of Sichuan Basin and Lower Paleozoic strengthened. The basic understandings were: (1) the Lower Cambrian Qiongzhusi Formation, which is distributed over a large area, is the main source rock; (2) the vuggy dolomite reservoir of the Sinian Dengying Formation is developed in a large area, but the heterogeneity is strong; and (3) the basin–margin structure is poorly preserved; the Dengying Formation is generally water-bearing; tectonics control the oil reservoir in the high parts of the paleo-uplift (e.g., Weiyuan structure), but the fullness is low. The paleo-uplifted slope and tilting end have reservoir-forming conditions, but the reservoir conditions are poor. Based on the exploration, the large-scale paleo-uplift has exploration potential, but the conditions for reservoir formation are complex and the exploration and deployment are difficult.

12.5.3 Risky Exploration Stage (2006–2011) In 2006, the discovery and successful exploration of giant– supergiant fields, which are deep to ultra-deep lithologic and structural–lithologic reservoirs, such as the giant Puguang, Longgang, and Yuanba gas fields, provided examples for hydrocarbon exploration in Central Sichuan. In 2006, the Sinian and Lower Paleozoic in the Central Sichuan paleo-uplift were listed as key risky exploration areas by the China National Petroleum Corporation. The China Petroleum Exploration and Production Company selected a number of companies and universities to carry out systematic research and interpret old seismic data. Based on the review of old wells, the study of outcrops, and the prediction of seismic reservoirs, the following three important conclusions were drawn: first, two large-scale low-amplitude structures have developed in the Gaoshiti and Moxi area in the tilting end of the Central Sichuan paleo-uplift, which have good preservation conditions and good exploration potentials. Second, the weathering crust reservoir of the Dengying Formation is regionally distributed and still one of the main target strata with high heterogeneity. Third, a granular dolomite reservoir of the Longwangmiao Formation can be found in some wells and outcrops, which has good physical properties and thickness of 20–30 m. It is a potential high-efficiency target layer in this area. Based on the above-mentioned conclusions, the exploration targets were changed and the Gaoshiti and Moxi

12.5

Discovery of the Giant An’yue Gas Field

325

Suining Xinjin Jianyang

Nvji well An’ping 1

Dashen 1

You 1

Gaoke 1

Zi 1

Han 1 Zhougong 1

Tongnan

Tongliang

Zizhong

Neijiang Leshan Panlong 1

Zishen 1 Laolong 1

Woshen 1

Schematic diagram of the top seismic reflection structure Gongshen 1

of the Sinian system in the Leshan-Longnvsi paleouplift

Fig. 12.14 Early exploration results for the central Sichuan paleo-uplift in Sichuan Basin

structure at the tilting end of the Central Sichuan paleo-uplift was confirmed as risky exploration target. Both the Dengying and Longwangmiao Formations were selected as target layers. After multiple cycles of evaluating the risky exploration target, six risky exploration wells were designed. From 2007 to 2008, the risky exploration wells Moxi 1, Baolong 1, and Hanshen 1 were successively deployed based on the regional development ideas. The drilling in Moxi well 1 was finished early because gas was obtained in the Changxing Formation. The reservoir of the Cambrian Longwangmiao Formation in Baolong 1 well was poor and low yielding gas was found in Xixiangchi Formation. Reservoir of Dengying Formation was detected in Hanshen 1 well, but the tests indicated water production due to the poor preservation conditions. Although the drilling of the main target layer in these three exploratory wells failed, the Sinian Dengying Formation and Cambrian are gas-bearing. Thus, the reservoir heterogeneity represents a real problem and the detection of favorable reservoir development zones and inherited structures with good preservation conditions is the key to a breakthrough in this area. In 2009, the following work was performed in the Sinian and Cambrian strata: stratigraphic comparison; analysis of the tectonic evolution, sedimentary facies, and reservoirs;

and old well review. To address issues related to the reservoir heterogeneity and difficult prediction of the main layers, a number of units were selected and parallel processing and reservoir prediction techniques were used for the analysis of 3D seismic data of the Moxi structure (area: 215 km2) and 2D seismic data of the Gaoshiti structure (length: 1,100 km). Based on comprehensive research, the hydrocarbon accumulation conditions in the Gaoshiti–Moxi area are favorable. Although it is located in the low part of the present structure in the central Sichuan paleo-uplift, it is on the axis of the paleo-uplift and inherited the development. A structural trap with a complete shape, large area, and good source conditions developed, providing the hydrocarbon source conditions for the formation of large gas fields. Sinian reservoirs are of strong heterogeneity. Porous reservoir with hydrocarbon was detected in the Cambrian Longwangmiao Formation. On the basis of further implementation of structural traps, three exploration targets of Gaoshiti, Moxi, and Luoguanshan were locked (Fig. 12.15), and three risky exploration wells were deployed. Gaoshi 1 and Luoguan 1 wells were decided to be deployed, while Moxi 8 well should be drilled depending on the result of Gaoshi1. Gaoshi well 1 is located in the Gaoshiti structure. It was drilled on August 20, 2010. On June 17, 2011, it was drilled

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12

Fig. 12.15 Seismic reflection structure of the Cambrian bottom boundary in the Gaoshiti–Moxi area (2009)

An’yue Gas Field

Suining 0

5

10

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20 km

Baolong 1

Moxi 1 Moxi 8

An’ping 1 Tongnan

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to 5,841 m and the drilling was stopped in the layer of the Sinian Doushantuo Formation. Based on the wireline logging interpretation, the Dengying Formation contains 13 gas layers at 4,956–5,390 m with total thickness of 150.4 m, and 12 poor gas-bearing with total thickness of 41.9 m. The Cambrian Longwangmiao Formation has two poor gas-bearings at 4,501.5–4,544 m, with total thickness of 15.8 m and porosity of 4.6%. In July 2011, the Dengying 2nd Member of the Sinian was tested using perforation and acidification and a daily natural gas flow of 102.14
104 m3 was obtained. High-yield gas flow was obtained in Gaoshi well 1 in the Sinian Dengying Formation, marking a breakthrough in the Sinian natural gas exploration in the central Sichuan paleo-uplift. Moxi well 8 is located in the high part of the Sinian top structure of the latent Moxi–Anpingdian buried structure. Drilling was started on September 8, 2011, and finished on April 14, 2012. The drilling depth was 5920 m and the

town exploration well

stopped in the Dengying 1st Member of the Sinian. During the drilling, abnormal gas logging was observed twice in the Cambrian Longwangmiao Formation. In the 4,646.4– 4,714.8 m section, two gas layers were detected, with total thickness of 34.6 m and porosity of 4.8–7.2%. In addition, one poor gas-bearing layer was found, with total thickness of 15 m and porosity of 4%. On September 9, 2012, an oil test was carried out in the first layer of the lower section of the Longwangmiao Formation (4,697.5–4,713 m); the gas production was 107.18
104 m3/day. On September 28, 2012, an oil test was carried out in the second layer in the upper part of the Longwangmiao Formation (4,686.5–4,675.5 m) and the gas production was 83.50
104 m3/day. High-yield industrial gas flow was obtained in the Longwangmiao Formation in Moxi well 8, representing a historic breakthrough in the oil and gas exploration of the Cambrian Longwangmiao Formation.

12.5

Discovery of the Giant An’yue Gas Field

12.5.4 Overall Evaluation Stage (2012 to Present) After the major discovery in Gaoshi well 1, PetroChina established the following exploration target for the large-scale Central Sichuan paleo-uplift: “overall research, overall deployment, overall exploration, stepwise implementation, and optimization.” An integrated research project “Research on the hydrocarbon-bearing zone and supporting technology in the Central Sichuan paleo-uplift, Sichuan Basin,” was established and overall research on the paleo-uplift and stepwise deployment were carried out based on the geological understanding at this stage. From July 2011 to September 2012, 23 exploration wells were deployed in two lots. The Dengying Formation in Gaoshiti–Moxi and Cambrian were the main and secondary targets. In August 2011, the Gaoshiti and Moxi structure were selected as the main target based on the potential of containing a large-scale low-amplitude structure-controlled reservoir and seven exploration wells were deployed in the first round of exploration. The drilling revealed stably distributed gas layers with thicknesses of 50–123 m in the 2nd and 4th Member of the Dengying Formation. The logging interpretation of Longwangmiao Formation reveals thick gas layer. Based on the macroscopic judgment of the geological conditions in multiple layers at the tilting end of the Central Sichuan paleo-uplift, 16 wells were deployed in May 2012 during the second round of exploration. The drilling and exploration were further expanded and important breakthroughs with respect to the geological understanding were achieved. From October 2012 to December 2013, the deployment and confirmation of the Moxi Longwangmiao Formation in the Moxi structure and evaluation of the Dengying Formation as a whole were planned. In September 2012, high-yield gas flow was obtained in Moxi well 8 in the Cambrian Longwangmiao Formation. Based on the geological understanding that “Reservoirs in the Longwangmiao Formation are very thick, stably distributed, and have good reservoir properties and a high hydrocarbon yield,” the third round of exploration and deployment was carried out in the Longwangmiao Formation and 12 exploration wells were deployed to speed up the exploration of the Moxi structure in the Longwangmiao Formation. Based on the general consensus that the Cambrian Longwangmiao gas reservoir is a tectonic–lithologic gas reservoir, while the Sinian Dengying gas reservoir is a lithologic–stratigraphic gas reservoir due to the large-scale paleo-uplift, the following global aims were established in April 2013: overall control of the regional gas-bearing area and acceleration of the exploration of the gas reservoir in Moxi structure of the Longwangmiao Formation. In total, 27 exploration wells were designed. Based

327

on the drilling, the gas-bearing area was confirmed and the main gas reservoir of the Longwangmiao Formation was identified. Since January 2014, the exploration has focused on the platform margin belt of Dengying Formation in Gaoshiti– Moxi area. The stratigraphic distribution law of Longwangmiao Formation in longnvsi area was summarized. Based on the conclusions that prolific wells and hydrocarbon are distributed at the platform margin and the main reservoir of the Longwangmiao Formation in the Longnvsi area is a lithological reservoir, 15 exploration wells and 868 km2 3D seismic network were deployed. Based on the drilling, the Sinian platform margin and its scale were confirmed and the gas-bearing scale of the Longwangmiao Formation was controlled. After the overall deployment in four stages, the exploration of the Sinian–Cambrian trillion cubic meters large gas reservoirs area of the paleo-uplift has been achieved, and the high-production gas reservoir of the Longwangmiao Formation in the Moxi Block has been efficiently identified.

12.6

Geological Characteristics of the An’yue Giant Gas Field

12.6.1 Reservoir Characteristics The Lower Paleozoic–Sinian system of the Giant An’yue gas field contains many sets of reservoirs. The main gas-bearing strata include the Cambrian Longwangmiao Formation and Dengying 2nd and 4th Member of the Sinian (Zou et al. 2014; Zhou et al. 2015; Wang et al. 2016; Zhang et al. 2017; Li et al. 2019).

12.6.1.1 Reservoir of the Sinian Dengying Formation

(1) Reservoir characteristics of the Dengying Formation There are two sets of reservoirs in the Dengying 2nd and 4th Member. The reservoir rocks are mainly composed of algal clastic dolomite, algal laminated dolomite, algal framestone, and dolarenite. The reservoir space is dominated by intergranular and intercrystalline dissolved pores, followed by intercrystalline, intergranular, and framework pores (Fig. 12.16). The development of small and medium pores and fractures leads to the formation of important reservoir space in the reservoirs of the Dengying Formation. The dissolution layer can reach 300 m below the surface of the Sinian erosion surface in the longitudinal direction. The porosity in the 4th Member of the Dengying Formation is

328

2.10–8.59%, with an average of 4.34%. The horizontal permeability mainly ranges 0.01–10
10−3 lm2, with an average value of 4.19
10−3 lm2. The porosity in the 2nd Member of the Dengying Formation is 2.68–4.48%, with an average of 3.73%, and the horizontal permeability ranges 1– 10
10−3 lm2, with an average of 2.26
10−3 lm2. A rimmed platform developed in the Dengying stage. Multiple phases of an algae-mound and shoal complex are vertically stacked in the platform margin belt. High-quality reservoirs are concentrated in this area, which is a high-yield enrichment area for gas reservoirs. The area of the platform margin has area of 1,500 km2 and reservoir thickness of 60– 110 m. The area of the favorable gas-bearing intraplatform to the east of the platform margin is 6,000 km2. The reservoir in the 4th Member of the Dengying Formation is distributed in a thin layer with a thickness of less than 40 m. Reservoir with a relatively stable lateral distribution developed in the upper parts of the 2nd Member of the Dengying Formation. Based on the drilling results, the effective reservoir thickness above the gas–water interface is 5.1– 69.1 m, with an average value of 34.3 m. (2) Main factors controlling the reservoir of the Dengying Formation Karst reservoirs developed close to the weathering crust in the Dengying Formation of Sichuan Basin. These reservoirs have large thickness, good physical conditions, and high well production. The formation of this set of high-quality reservoirs was controlled by the sedimentary facies and karstification. The reservoirs in the marginal zone and shoal are notably superior to the intraplatform facies. The reservoirs in the mound and shoal complex are dominated by algal clots, algal clastic, and algal laminated dolomite and mainly fracture-vug and -porosity reservoirs. The reservoir thickness ranges from 60 to 180 m and the porosity is 3.8– 6.0%. In contrast, the reservoirs of the intraplatform facies are dominated by algal laminated and argillaceous dolomite, with an average porosity of 10%. The average permeability of a single layer is generally 0.3–5  10−3 lm2 and can locally reach >10  10−3 lm2. The Ma 521, Ma 512, and Ma 522 reservoirs have relatively poor physical properties, with an average porosity of 3%–6% and permeability of 0.1–1  10−3 lm2. However, good physical properties are observed in some areas. Core observations, comprehensive analysis of thin sections, and scanning electron microscopy show that the reservoir space of the weathering crust reservoir of the Ordovician Majiagou formation in the Jingbian gas field is mainly composed of solution, intercrystalline and gypsum (salt)-moldic pores, and various types of microfracture. The pore genesis is mainly related to the dissolution in the supergene stage and weathering crust stage, quasi-synchronic and early post-synchronic dolomitization, tectonic stress in the diagenetic and weathering crust stages, and weathering fracture making (Fu et al. 2012).

14.3.3.1 Spherical Dissolution Pores The dissolution pores in the Ordovician dolomite reservoir in this area are mainly mineral-selective dissolution pores. Their formation is mainly related to the freshwater dissolution of soluble gypsum salt minerals. The main spherical (porphyry) dissolution pores formed by leaching and dissolving of gypsum nodules or gypsum–dolomitic nodules in the early supergene or weathering crust stage. Therefore, it seems more appropriate to call them “core-moldic pores or gypsum-moldic pores.” Pores with sizes of 3–5 mm are mainly distributed in the Ma 531 and Ma 514 reservoirs. They are almost circular or elliptical and their sizes are relatively uniform. These pores are the dominant reservoir space in the dolomite reservoirs in this area. Porphyritic dissolution pores are very well developed in these two main reservoirs. Dissolution pores account for *10%–30% of the core area. Most of them are semi-filled with micritic dolomite, calcite, and authigenic quartz. In some areas, they are completely filled with calcite and dolomite. Notable characteristics of the geopetal structures are shown in Fig. 14.6. 14.3.3.2 Crystal Moldic Pores Crystal moldic pores are common in the dolomite of the Majiagou Formation. Gypsum moldic pores are the most developed and form effective reservoirs in the concentrated distribution area. For example, gypsum moldic pores with a porosity of 3%–6% are the main reservoir space in the Ma 522 dolomite reservoir in the Jingbian area. In addition, salt-moldic pores that had formed by the dissolution of salt crystals can also be observed in local layers, but they are notably less common than gypsum moldic pores. Apart from the type shown in Fig. 14.6, there are two types of gypsum moldic pores in this area, that is, lath-shaped and needle-like pores. Some layers are filled with calcite or authigenic quartz, which become gypsum pseudocrystals. Lath-shaped gypsum moldic pores are formed by the dissolution of gypsum slabs containing larger crystals. The pore morphology is regular, the pore size ranges from 0.3 to 0.6 mm, and the length/width ratio of the pores is generally less than 5/1. Calcite filling is the main filling type, followed by dolomite and a small amount of

14.3

Geological Characteristics of Weathering Crust Gas Reservoirs …

361

Fig. 14.5 Sedimentary facies sequence evolution histogram of the Ordovician Ma 5 member in the Shancan1 well in the central Ordos Basin

362

14 Jingbian Gas Field

Fig. 14.6 Characteristics of spherical dissolved pores in the Ma 5 Formation of the Ordovician Majiagou Formation, Ordos Basin

Shan 181, 3549.00 m, Ma51, Columnar gypsum-moldic pores

Shan 30, 3629.10 m, Ma54, hair-like gypsum-moldic pores

Fig. 14.7 Characteristics of gypsum moldic pores in the Ma 5 member of the Ordovician Majiagou Formation, Ordos Basin

authigenic quartz. Needle-like gypsum moldic pores are formed by the dissolution of needle-like (or hair-like) gypsum and have notable unidirectional elongations. The long axis, short axis, and length/width ratio of the pores are generally 0.3–0.5 mm, 0.02–0.05 mm, and >10/1, respectively. Calcite is the main type of local filling, followed by authigenic quartz (Fig. 14.7).

14.3.3.3 Intergranular and Intergranular Dissolution Pores Intergranular pores of dolomite are ubiquitous in the dolomite of the Majiagou formation. The development of pores is

closely related to the genesis and structure of the dolomite. The intergranular pores with oil and gas reservoir significance are mainly developed in coarse- and fine-grained dolomite. The support framework comprises the euhedral– subhedral dolomite crystals. The pores have polyhedral or tetrahedral geometries. The pore walls are straight and smooth, the pore size is generally 10–50 lm, the pore area is *1%–5%, and a few pores can reach areas >15% such as in the Ma 541 member of well Yu 3 (Fig. 14.8). Intergranular dissolution pores are formed by the enlargement of intergranular pores during freshwater dissolution or the selective dissolution of minerals such as

14.3

Geological Characteristics of Weathering Crust Gas Reservoirs …

363

interlayer fractures and sutures, The physical properties of the reservoirs play a key role in weathering fractures (Fig. 14.9), structural fractures and interlayer fractures. In addition, various fractures can become so-called “dissolution fractures” due to expansion by dissolution, further improving their storage performance and connectivity (Huang et al. 2012).

14.3.4 Main Controlling Factors of the Reservoir Development

Fig. 14.8 Characteristics of intergranular pores in the Ma 5 member of the Ordovician Majiagou Formation

Fig. 14.9 Characteristics of weathering fractures in the Ma 5 member of the Ordovician Majiagou Formation

carbonates. Microscopically, common dolomite crystals are dissolved into harbor-shaped, irregular pore morphology. The pores are unevenly distributed and the pore sizes differ; they generally are 30–200 lm. The degree of pore development depends on the rock structure and strength of the dissolution. The intergranular solution pores of fine-crystalline dolomite are more developed than that of mudstone and coarse-grained dolomite.

14.3.3.4 Microfractures Micro-fractures generally develop in the reservoirs of the Majiagou Formation. From the genesis type, although there are many types of fractures such as structural fractures, diagenetic shrinkage fractures, weathering fractures (gravity fractures),

The reservoir development is controlled by many factors such as the sedimentary facies belt, Caledonian weathering crust karst palaeogeomorphology, and Hercynian burial and filling. The sedimentary facies belt is the most important controlling factor.

14.3.4.1 Effective Reservoir Concentration in the Gypsodolomite Flat Sedimentary Facies Belt The study on the sedimentary facies characteristics of the Ordovician weathering crust reservoir sections in the Jingbian gas field shows that the reservoirs such as Ma 531 and Ma 514 have developed effective reservoirs spaces, which are mainly formed in the richly soluble minerals such as gypsum salts (in the supratidal zone) in the gypsodolomite flat facies zone (Fig. 14.10), However, in the intertidal-subtidal environment, the porosity of clay and crystal powder dolomite is usually undeveloped due to the lack of gypsum-salt mineral components in the original sediment. Due to the periodicity of the relative sea level changes, the sedimentary facies show notable cyclicity in the vertical direction, which is conducive to the formation of effective reservoir rock sections that are mostly generated in the late stage of the sea level change cycle (equivalent to the high-level system tract of the sequence cycle). Because the sedimentary rate is often greater than the rate of the sea level rise, the waterbody gradually becomes shallow. With the increasing limitation of the restricted sea, the salinity of the seawater increases, which leads to the precipitation of evaporative minerals, such as gypsum and gypsum salt, and the formation of gypsum, gypsum salt crystals, or their nodules, which are more evenly distributed in the penecontemporaneous dolomitic matrix with a micrite crystal structure, It laid the material foundation for the formation of dissolution pore intervals. Although the evaporite strata formed in the same period, their sediment characteristics horizontally differ due to the different geographical locations in which they were deposited. The most prominent feature is the circumferential facies belt differentiation pattern around the periphery of the paleotopographic depression in the southeast of the Ordos Basin. For example, in the Ma 531, limy dolomite basins,

364

Fig. 14.10 Sedimentary microfacies map of the Ordovician Ma 51 member in the Ordos Basin

14 Jingbian Gas Field

14.3

Geological Characteristics of Weathering Crust Gas Reservoirs …

365

Fig. 14.11 Sedimentary model map of the Ma 51 sub-member of the Ordovician Majiagou Formation in the middle–eastern Ordos Basin

dolomite flat, gypsodolomite flat, basin margin dolomite flat, and circumcontinental mudstone flat successively developed from the depression to the outside (Fig. 14.11). The gypsum-dolomite flat facies belt can be further divided into three subzones, that is, inner, middle, and outer zones, according to the development degree of the gypsum. In the middle zone of the gypsodolomite flat, gypsum developed and was uniformly and steadily distributed. Thus, the middle zone, which contains the main body of the Jingbian gas field, became a sedimentary interval conducive to the formation of gypsum-soluble porous reservoirs. Because of its proximity to the paleo-uplift area, the outer zone is susceptible to the desalination of atmospheric freshwater and its gypsum content is relatively low. The inner zone is affected by regular seawater; the seawater concentration is lower than that in the middle zone and the gypsum content is relatively low.

14.3.4.2 Karst Palaeogeomorphology in the Weathering Crust Stage Controlling the Development of Karst Pores in Pore Intervals At the end of the Middle and Late Ordovician or the end of the Caledonian movement, the whole Ordos area began to uplift and weathering and denudation occurred for *150 million years. By the time the Late Carboniferous again accepted large-scale depositions, karst paleomorphic features of ravines and gullies criss-cross and alternating trough and platform (distribution between erosion troughs and karst platforms) had been formed on the top surface of the Ordovician. Influenced by the paleotectonic pattern of the western high and eastern low at that time, paleogeomorphic units such as karst highlands, slopes, and basins successively developed from west to east, and the intensity of karstification on top of the Ordovician decreased from west to east (Fig. 14.12). The western area of the Jingbian gas field belongs to karst highland. Most of the main reservoir sections are completely denuded because of the strong uplift and denudation in the region. The north-south area between Jingbian and Hengshan belongs to the karst slope area. The

Ma 51–Ma 52 strata are well preserved and karstification is notable. The gypsum-bearing mud–fine-crystalline dolomite deposited in the Ma 531 and Ma 512 gypsum-dolomite flat facies belts was dissolved, leading to the formation of the main reservoir section of the Jingbian gas field. The eastern area of Hengshan–Ansai belongs to the karst basin area; the karstification intensity of Ma 51 and other main reservoirs notably weakened. It can be seen from Fig. 14.13 that the influence depth of the weathering crust in Jingbian area is generally 60–80 m (the bottom boundary of the weathering crust is the appearance depth of the anhydrite mineral). In the eastern part of the basin, the influence depth of weathering crusts is mostly between 30–50 m, which also reflects the trend of weakening of weathering and karst intensity from west to east.

14.3.4.3 Hercynian-Indosinian Burial Filling Affects Later Pore Preservation After the Caledonian tectonic uplift period, the Ordos area began the overall subsidence in the Middle Hercynian (Late Carboniferous) and Carboniferous–Permian deposits developed until the end of the Triassic. Because of the influence of burial diagenesis in the Hercynian and post-Indosinian periods, dissolved pores that formed in the weathering crust period were filled by later diagenetic minerals, which reduced the reservoir permeability of the pore intervals. The main pore intervals in some areas even lost their effective reservoir permeability due to the filling with diagenetic minerals. Comprehensive analysis shows that the main pore filling minerals during the burial period are calcite (partly iron-bearing calcite), freshwater dolomite, and secondary authigenic quartz. Small amounts of fluorite, pyrite, anhydrite, and karst can also be found. The distribution of buried filling minerals also has a certain regularity on the plane. Dolomite filling is dominant in the Jingbian gas field and its adjacent eastern area and the degree of the pore filling is relatively low. The eastern part of the basin is dominated by calcite filling, with a relatively high filling degree. Locally, the preformed pore filling is exhausted and the reservoir properties are lost (Fig. 14.14) (Ren et al. 2012). The study shows that the pore filling of

366

14 Jingbian Gas Field

Fig. 14.12 Distribution of the dissolution intensity in the Ordovician Ma 51–Ma 54 members in the Ordos Basin

weathering crust reservoirs in this area is mainly controlled by the paleotopography of the Carboniferous–Permian sedimentary period. The paleotopography of this period is mainly affected by the inheritance of the karst paleotopography of the weathering crust period, exhibiting the western high–eastern low distribution, which results in the diagenetic pressure increase and releases water of the overlying strata during the Carboniferous–Permian burial period. The water converges to the pore intervals of the Ordovician weathering crust in the eastern part of the basin, resulting in a large

amount of calcite precipitation in the pore intervals of the Ordovician system and reduction of the storage and permeability of the early pore interval.

14.3.5 Analysis of the Gas Accumulation Process Since the discovery of the Jingbian weathering crust gas reservoir, there has been controversy with respect to its gas source. Some people believe that the main gas source is

14.3

Geological Characteristics of Weathering Crust Gas Reservoirs …

367

Fig. 14.13 Cross section of the Ordovician karst reservoir in the central Ordos Basin

Carboniferous–Permian coal-derived gas above the unconformity surface, but others believe that the main gas source is Ordovician self-generated and self-stored oil-type gas (others believe that there are different mixing ratios in different regions) (Dai et al. 1999). Based on years of continuous research, exploration, and development, more data are available. The gas isotope characteristics show more similarities with that of clastic rock gas reservoirs of the Upper Paleozoic. Self-generating and -storing gas reservoirs that have been found, especially in the deep Ordovician, and their isotope characteristics notably differ from those of the two types of gas reservoirs mentioned above (Table 14.1). Therefore, the gas sources of the weathering crust gas reservoir on top of the Ordovician mainly are the coal-bearing Carboniferous–Permian source rocks, which has become the consensus among most scholars. The Ordovician carbonate-gypsum deposits of the Majiagou Formation developed in the central and eastern parts of the basin, laying a foundation for the formation of carbonate reservoirs. After weathering and denudation occurred in the Caledonian period, a large-scale weathering crust reservoir formed at the top of the Ordovician in the middle and eastern parts of the basin. In the Late Hercynian, Carboniferous– Permian coal-bearing strata were deposited. Therefore, the Ordovician weathering crust reservoir formed a good contact with the Upper Paleozoic coal-bearing source rocks, Carboniferous–Permian argillaceous rocks became the caprock of the weathering crust gas reservoir, and buried hill traps related to the karst paleogeomorphology formed (Fig. 14.15). Based on the basin simulation, the organic matter of the Carboniferous–Permian source rocks in the Hercynian cycle was not mature. The burial depth of the source rocks reached

*2,600 m in the Indosinian and they began to enter the stage of pyrolysis hydrocarbon generation. The Ro was 0.6%–0.7%. The hydrocarbon generation intensity in the middle of the basin was only 2–5  108 m3/km2. The Yanshanian was the main stage of gas accumulation. In the Early Jurassic, the burial depth of Carboniferous– Permian source rocks in the Upper Paleozoic was 3,000 m and the thermal evolution of organic matter increased, with Ro reaching 1%–1.4%, In the beginning of the condensate-wet gas stage, the cumulative hydrocarbon generation intensity reached 20–24  108 m3/km2 and the hydrocarbon expulsion intensity was 4  108 m3/km2. This shows that the coal-bearing source rocks of the Upper Paleozoic Carboniferous–Permian strata entered the main hydrocarbon generation period. At the end of the Early Cretaceous, the burial depth of Carboniferous–Permian source rocks in the Upper Paleozoic was *3,900 m, Ro reached 1.4%–1.8%, and the wet gas stage began. The source rocks entered the peak period of hydrocarbon generation and the hydrocarbon generation intensity reached 24–28  108 m3/km2. At present, the cumulative hydrocarbon-generating intensity is 25– 45  108 m3/km2 in the central part of the basin and 25– 35  108 m3/km2 in the western part. Three hydrocarbon-generating centers were formed, that is, in the east, west, and a small one in the north (Fig. 14.16), laying a foundation for the formation of Ordovician weathering crust reservoirs. As shown in Fig. 14.16, the Carboniferous–Permian hydrocarbon generation centers are mainly located in the central and eastern parts of China. The hydrocarbon expulsion process started in the Early Jurassic and peaked after the

368

14 Jingbian Gas Field

Fig. 14.14 Distribution map of the filling types of weathering crust reservoirs on top of Ordovician in the Ordos Basin

Early Cretaceous. According to the calculation of the gas phase potential at the top of the Carboniferous and Ordovician systems and the development characteristics of pressure-released karst, there are three main transverse migration and accumulation pathways of natural gas from the Carboniferous and Permian to the Ordovician weathering crust (Li et al. 2004). Firstly, when the concentration of natural gas at the bottom of the Carboniferous system is higher than that at the top of the Ordovician ancient

weathering crust during the hydrocarbon expulsion in the Carboniferous and Permian, Carboniferous natural gas diffuses to the Ordovician because of the concentration difference. Secondly, after the deposition of the Triassic Yanchang Formation, the gas phase potential in the middle part of the Carboniferous system is larger than that on top of the Ordovician system due to the deepening of the burial and the increase in the overpressure in the middle part of the Carboniferous system, thus generating the potential energy

14.3

Geological Characteristics of Weathering Crust Gas Reservoirs …

Table 14.1 Gas isotope comparison between Ordovician weathering crust gas reservoirs and upper Paleozoic clastic rock gas reservoirs in the Ordos Basin

Well

Formation

369

d13C(PDB) (‰)a C1

C2

Note C3

iC4

nC4

−21.05

−21.84

−19.27

−20.45

Z94

Ma 54

−33.38

−23.27

S277

Ma 51

−32.74

−25.26

−24.52

S430

Ma 51

−31.21

−32.66

−26.2

L1

Ma 57

−39.26

−23.78

−19.72

Y1

Kelimoli

−38.92

−27.17

−25

Western Ordovician

S377

Shihezi

−31.85

−22.94

−24.66

S127

Shanxi

−27.57

−26.78

−29.41

S399

Shanxi

−29.06

−34.20

Upper Paleozoic (Carboniferous— Permian)

S285

Benxi

−33.62

−33.92

−33.02

S377

Shihezi

−31.85

−22.94

−24.66

S176

Shihezi

−27.79

−23.64

−27.85

S340

Benxi

−27.84

−32.15

−29.81

Weathering crust

−30.36

−30.02

−26.40

−26.99

a 13

Ordovician pre − salt

d C(PDB) (‰) is the stable isotope value of the sample C13 treated by the international standard PDB

Fig. 14.15 Structural evolution and Ordovician accumulation in the Ordos Basin

c

370

14 Jingbian Gas Field

Fig. 14.16 Intensity map of Upper Paleozoic hydrocarbon generation in the Ordos Basin

for the downward migration and accumulation of natural gas in the strata. Thirdly, controlled by the abnormally high temperature and decarboxylation of Carboniferous and Permian organic matter, acid compaction released water transported hydrocarbons into the weathering crust reservoirs during the invasion of the Ordovician. The three above-mentioned migration processes determine the migration pathway to the Ordovician paleoweathering crust reservoir during the peak period of hydrocarbon generation and expulsion of Carboniferous and Permian natural gas.

From the horizontal change characteristics of paleofluid potential and anomalous pressure, it can be seen that the favorable zones for the development of pressure-release water is exactly the location where the Carboniferous and Permian natural gas migration and accumulation across layers to the Ordovician. Because the pressure at the bottom of the Carboniferous system is greater than that in the middle and upper parts, it is generally difficult for pressure-released water and natural gas to penetrate downward into the Ordovician system. Because the karst terraces surrounding the eastern karst basins

14.3

Geological Characteristics of Weathering Crust Gas Reservoirs …

are in contact with different strata of the Carboniferous, the Carboniferous sandstone reservoirs and Ordovician paleoweathering crust are the “windows” of pressure-released water intrusion and natural gas migration. Thus, the Carboniferous–Permian hydrocarbon source rocks provide a sufficient gas source for paleoweathering crust reservoir formation.

References Bao H, Yang C, Huang J et al (2004) “Evaporation drying” and“reinfluxing and redissolving”: a new hypothesis concerning formation of the Ordovician evaporites in eastern Ordos Basin. J Palaeogeogr 6(3):280–288 Bao H, Yang F, Bai H et al (2017) Sedimentology study on sub-member lithofacies paleogeography mapping and its petroleum exploration significance: taking Ma 5 member of Lower Ordovician Majiagou Formation in central-eastern Ordos Basin. Acta Petrologica Sinica 33(4):1094–1106 Dai J, Xia X et al (1999) Research on source rock correlation of the Ordovician reservoir, Changqing gasfield. Earth Sci Front 6 (z1):195–203 Fu J, Bai H, Sun L et al (2012) Types and characteristics of the Ordovician carbonate reservoirs in Ordos Basin. Acta Petrolei Sinica 33(z2):110–117 Fu J, Fan L, Liu X et al (2019) New progresses, prospects and countermeasures of natural gas exploration in the Ordos Basin. China Petr Explor 24(4):418–430

371

He Z, Zheng C, Chen A et al (2001) Distributive configuration of ancient valley-trough on Ordovician erodion surface in ChangQing gas field and its control over gas accumulations. Acta Petrologica Sinica 22(4):35–38 He Z, Zheng C, Wang C et al (2005) Cases of discovery and exploration of marine fields in China (Part 2): Jingbian Gas Field Ordos Basin. Marine Origin Pet Geol 10(2):37–44 He Z, Huang D, Zheng C et al (2006) Modification and geology implication of ordovician Paleogeomorphology and Paleogeosyncline distribution models in Ordos Basin. Marine Origin Pet Geol 11 (2):25–28 Huang Z, Chen T, Ren J et al (2012) The characteristics of dolomite reservoir and trap accumulation in the middle assemblages of Ordovician in Ordos Basin. Acta Petrolei Sinica 33(z2):118–124 Li Z, Li L, Jia J et al (2004) Analysis of dolomite reservoir controled by structural slope break. XinJiang Geology 22(1):73–75 Ren J, Bao H, Sun L et al (2012) Characteristics and mechanism of pore-space filling of Ordovician Wethering crust karst reservoirs in Ordos Basin. Marine Origin Pet Geol 17(2):63–69 Yang J (1991) Discovery of the natural gas in lower Palaezoic in Shanganning Basin. Nat Gas Ind 11(2):1–6 Yang J, Pei X (1996) Natural Gas Geology in China, vol 4. The Petroleum Industry Press Yang H, Zheng C, Xi S et al (2000) The geological characteristics of natural gas accumulation in Lower Paleozoic of the Ordovician in Ordos Basin. Low Permeability Oil & Gas Fields 5(3):6–19 Yang H, Fu J, Bao H et al (2010) Sedimentary characteristics and gas accumulation potential along margin of Ordovician trough in Western and Southern Parts of Ordos. Marine Origin Pet Geol 15 (2):1–13

15

Daniudi Gas Field

15.1

Geographic Location and Regional Geological Setting

The Daniudi gas field is located in the intersection of Shenmu County, Yulin, Shaanxi Province, and the Uxin Banner and Yih Ju League, Ejin Horo Banner, Inner Mongolia Autonomous Region (Fig. 15.1) with the geographic coordinates of 109°30ʹE–110°00ʹE and 38°45ʹN–39°10ʹN (Wang 2012). The gas field is located in the eastern part of the Maowusu Desert. The terrain is relatively flat. The ground is covered with sand and dunes, and the height of the dunes is generally 5–10 m. There are highways passing through the area, and the town-level simple highways are basically connected to the network, and the traffic is more convenient. The area is rich in other mineral resources, including thenardite, gypsum, salt and alkali, and there are coal mines in the eastern neighborhood. The Daniudi gas field is structurally located in the northeast of the Yishan Slope in the Ordos Basin. The Ordovician weathering crust gas reservoir is a gas reservoir formed on the structural background of the Yishan Slope. The Yishan Slope is the east wing of the asymmetrical large syncline in the basin. It is known for its structural monotony and gentle inclination. The area is a very gentle southwestern dip and its local structure is not developed. The top structural features of the Ordovician in the Daniudi gas field is also a gentle west-dipping monocline in which multiple rows of NE-oriented nose structures with low amplitudes are developed (Hao et al. 1991; Zixin He et al. 2003). The Ordovician in the Daniudi gas field is characterized by the outcrop of the top of the Majiagou Formation. The sediments of the Ma 1–Ma 5 members have been preserved, while the sediments of the Ma 6 member are erosion. The Ma 5 member has been eroded to different degrees in different areas; its thickness ranges from 60 to 100 m (Fig. 15.2).

15.2

Exploration of the Gas Field

The discovery of the Daniudi gas field started in well Yi 24 in 1985. Gas was detected in the well in the Lower Shihezi and Shanxi Formations in the Middle and Lower Permian, Taiyuan Formation in the Carboniferous, and Majiagou Formation in the Ordovician. The regular tests were carried out in the Majiagou Formation and Lower Shihezi Formation and obtained a gas yield of 280 m3/d and 458 m3/d, respectively, was obtained. Limited by the technology at that time, fracturing reformation was not conducted. However, the discovery implied a good gas exploration potential of the Ordovician weathering crust. During the Eighth Five-Year Plan, the Ordovician weathering crust was treated as the major exploration target. In total, 1448 km of 2D seismic and 9 wells were deployed. The industrial gas flow in the Ordovician in wells E 5 and E 8 confirmed the good exploration prospects of the Ordovician weathering crust. A controlled gas reservoir of 43.8  108 m3 was submitted in 1995. From 1999 to the present, the Daniudi gas field underwent a fast development in terms of gas exploration. The clastic rocks in the Upper Paleozoic were the main target, followed by the Lower Paleozoic. At the end of 2015, an accumulative proven gas reservoir of 4,545.63  108 m3, including seven members (Tai 1, Tai 2, Shan 1, Shan 2, He 1, He 2, and He 3), was reported. In 2015, the annual gas yield reached 33  108 m3 in the Daniudi gas field. The accumulative gas yield was 253  108 m3 at the end of 2015. Horizontal well drilling and progress with respect to acidification and sand fracturing led to new opportunities to reevaluate the Ordovician weathering crust in the Daniudi gas field. Horizontal wells were deployed in the Ordovician weathering crust in the Daniudi gas field (targets: Ma 51, Ma 52, and Ma 55) to obtain breakthrough with respect to the single-well productivity.

© Geological Publishing House and Springer-Verlag GmbH Germany 2020 Y. Ma, Marine Oil and Gas Exploration in China, https://doi.org/10.1007/978-3-662-61147-0_15

373

374

15

15.3

Daniudi Gas Field

Geological Characteristics of the Gas Field

15.3.1 Trap Characteristics in the Gas Field The gas field is dominated by stratigraphic–paleotopography and lithological traps (i.e., karst buried hill traps).

15.3.1.1 Stratigraphic–Paleotopography Traps These traps are nonstructural traps composed of strata and paleo-troughs. Because of the existence of paleo-troughs, gentle paleotopography salient formed between the troughs. Although the reservoirs in the troughs have been eroded, the reservoirs are still developed and preserved in the paleotopography salient area, and then they are covered by bauxite or mudstones at the bottom of the Carboniferous to form traps. The characteristics are as follows: 141

Fig. 15.1 Geographic location of the Daniudi gas field

(1) Traps developed between troughs, which separate the reservoir. The abundant coal-derived gas of the Upper Paleozoic migrated into the traps through unconformities and troughs. (2) A reservoir developed and was preserved on the salient, covered with a convex sealing layer with good sealing conditions. (3) The traps are irrelevant for the structure. Various reservoir occurrences in the paleotopography salients can be observed (e.g., horizontal, monocline, syncline, and anticline). As shown in Fig. 15.3, in the north of well Da 61, the Ma 52 member is locally eroded and in contact with the bauxite layer of the Benxi Formation, which seals the gas reservoir of the Ma 52 member. The sealing layer at the bottom of the Carboniferous covers the highland to form traps, which are irrelevant for the structure.

15.3.1.2 Lithological Traps Main characteristics:

Fig. 15.2 Distribution of the Ordovician weathering crust in the Daniudi gas field

(1) The variation in the sedimentary microfacies provided favorable conditions for lithological traps. Mud, dolomite, and calcium–dolomite flats developed in the Ma 51–2 member. During the Yanshanian, a structural “high in the east and low in the west” pattern developed. The lithological variation from dolomite to mudstone created a lithological seal of the gas reservoir in the weathering crust in the upward dip direction (Huang et al. 2012); (2) The development of the Ma 51–2 reservoir was mainly controlled by karst in the Caledonian. The differences in

15.3

Geological Characteristics of the Gas Field

375 NE 11

40 95

D61-13

61

101

5 1 1

Fig. 15.3 Section of gas reservoir between well #D61-13-D101

the intensity and style of the karst led to a strong heterogeneity of the reservoir. Corrosion pores with good physical properties developed in the area in which the dolomite in the Ma 51–2 layer was reformed by corrosion, forming a dolomite reservoir with corrosion pores. In the area in which micrite/microcrystalline dolomite was not transformed by corrosion, few corrosion and intercrystalline pores developed and the physical properties were poor. When the micritic–microcrystalline dolomite without corrosion pores occurred in the updip location, a lithological seal of the reservoir could be formed; (3) The Ma 55 member is composed of gray, dark micrite with local dolomitization. The reservoir in the Ma 55 member is controlled by dolomitization and the reservoir pore types include intercrystalline and corrosion pores in dolomite. When the updip direction of the reservoir without dolomitization, a lithological seal of the reservoir could be formed.

15.3.2 Fluid Characteristics of the Gas Field 15.3.2.1 Gas Composition The gas reservoir in the Ordovician weathering crust is mainly composed of hydrocarbon gas, with little CO2. The CH4 content is greater than 95%, which indicates a dry gas reservoir. The production and test gas statistics show that some wells contain very small amounts of H2S (Tables 15.1 and 15.2).

15.3.2.2 Characteristics of the Formation Water The formation water in the gas reservoir in the Ordovician weathering crust is CaCl2-type water with a salinity of 176,000 mg/L (Table 15.3).

15.3.3 Production and Exploitation Before 2011, the evaluation of the Ordovician weathering curst reservoir in the Daniudi gas field was mostly conducted in vertical wells. Many vertical wells in the weathering crust showed good test results. The vertical wells that were drilled in the Ma 51+2, Ma 514, and Ma 55 members had gas layers with average thicknesses of 6.367 m, 1.735 m, and 6.458 m, respectively, and an open flow of 1.042  104m3/d, 0.651104m3/d, and 0.617104m3/d, respectively. Horizontal well tests were conducted from 2011 to 2013 in 10 wells and an average open flow of 4.55  104 m3/d was obtained. In 2014, reformation technology dominated by acidification and sand fracturing was applied to full segments of horizontal wells. A breakthrough was achieved in terms of the capacity of the gas wells, with an average open flow of more than 7  104 m3/d. The tests indicated a high production for wells DP 102S and PG 18, with an open flow of 16  104 m3/d and 18  104 m3/d, respectively. In 2015, horizontal wells were drilled in the Daniudi gas field. Acidification and sand fracturing were applied. The oil and gas wells were deployed in the Ordovician weathering crust, with an average open flow of 17.4225  104 m3/d.

376

15

Daniudi Gas Field

Table 15.1 Composition of the gas reservoir in the Ordovician weathering crust Composition

Methane

Ethane

Propane

Iso-butane

n-butane

Isopentane

n-pentane

C5 + heavy hydrocarbon

CO2

Relative density

Content (%)

95.366

2.101

0.664

0.158

0.175

0.074

0.04

0

1.429

0.63

Table 15.2 H2S statistics of the gas reservoir in the Ordovician weathering crust Well name

Formation 531

H2S content (ppm)

Data source

D 12-47

Ma

20

Gas testing

D 61-15

Ma 5

3 1

tiny

Production well

Ma 5

1 2

6

Gas testing

D 106

Ma 5

1 2

9

Gas testing

D 66-52

Ma 5

1 2

tiny

Production well

D 66-191

Ma 5

1 4

40

Gas testing

D 66-195

Ma 5

1 4

8

Gas testing

D 114

Ma 5

1 4

8

Gas testing

D 105

Ma 5

1 5

35

Gas testing

39

Gas testing

tiny

Gas testing

50

Gas testing

18

Gas testing

D 66-147

525

D 66-217

Ma

D 30

Ma 5

2 5

D 61-21

Ma 5

1 4,

D 66-187

Ma 5 14, Ma 5

PG 4

Ma 5

28

Production well

D 98

He 1 + Shan 2 + Ma 5

15

Production well

Ma

525 2 5

D 12-8

Shan 2 + Shan 1 + Ma 5

PG 18

Ma 5

2 1

52

Production well

15

Production well

Table 15.3 Characteristics of formation water in Ordovician weathering crust Formation

K+ + Na+

Ma 51+2

11,549.2

32,587.27

6,030.36

1,567.71

93,218.07

236.19

1,658.72

150,259.8

Ma 5

10,170.07

43,395.27

6,010.48

1,184.22

113,118.59

408.93

1,519.7

176,356.83

10,859.635

37,991.27

6,020.42

1,375.965

103,168.33

322.56

1,589.21

163,308.32

7.35

5

Average

Ca2+

Mg2+

Ba2+ + Sr2+

Cl-

The tests yielded an open flow of more than 50  104 m3/d in wells DPF-201 and PG 26.

15.4

Characteristics of the Main Gas Layer

15.4.1 Strata The Ma 5 member can be divided into ten sub-members (i.e., Ma 51, Ma 52 … Ma 510). The major reservoir includes the Ma 51–Ma 55 members at the top. Each sub-member can be divided into 2–4 layers according to the lithology and reservoir properties (Xiong et al. 2014).

HCO-3

SO24

Salinity (mg/L)

Ph

Water type

Density

7.35

CaCl2

1.09

7.35

CaCl2

1.1

CaCl2

1.095

The Ma 511 layer at the top of the Ma 5 member in the Daniudi gas field has been almost completely eroded. The preservation conditions improve and the distribution area increases downward. The most productive layers are the Ma 521 and Ma 531 layers, followed by the Ma 541, Ma 522, and Ma 514 layers. The lithology of the gas layers comprises fine-crystalline dolomite with anhydrite nodules and columnar crystals, in addition to coarse dolomite. The Ma 5 member developed four main marker layers from the bottom to top as described below (Table 15.4 and Fig. 15.4). K 4 (black belt/Ma 55): This is a relatively stable and thick layer of dark gray limestone, which shows a block/box shape and low GR(gamma-ray logging), negative SP

15.4

Characteristics of the Main Gas Layer

377

Table 15.4 Lithologies of different layers in the Ordovician Ma 5 member of the Majiagou Formation in the Daniudi gas field, Ordos Basin Sub-member

Layer

Main lithology

Ma 51

Ma 511

Micro- and fine-crystalline and silty limestone, intercalated by silty limestone with anhydrite, locally intercalated by dolomitic limestone and oolitic dolomite. Karst is developed and weathering crust eluvial rock occurs at the top of several wells

Ma 521

Dominated by fine-crystalline and silty dolomite with anhydrite nodules or columnar crystals. Sometimes. The lower part contains argillaceous dolomite, local spatulate dolomite, and rocks with vertical and small karren rock/karst pipe formation rock

Ma 531

Dominated by silty dolomite with anhydrite nodules or columnar crystals, intercalated by moderately thick–thin-layered dolomite. Sometimes, they interbed with different thickness. Locally, folia-like dolomite and vertical, small karren rock/karst pipe formation rock are developed

Ma 541

Dominated by fine crystalline to silty dolomite, intercalated by silty dolomite with anhydrite nodules or columnar crystals. Locally, dolomitic limestone is developed. The karst rock is on the top, while tuffaceous rock is at the bottom

Ma 512

Dominated by fine-crystalline to silty dolomite. Silty dolomite with anhydrite nodules is developed in the middle and at the top. Moderately thick karst formation rock occurs in the middle and at the bottom

Ma 522

Silty dolomite with anhydrite nodules or columnar crystals develops in the middle and at the top. A moderately thick tuffaceous layer can be found at the bottom in some wells

Ma 513

The upper part is microcrystalline to silty dolomite. Karst rock with 1–3 layers and a thickness of 1–5 m can be found in most wells. The lower part is micro- to fine-crystalline dolomite intercalated by silty dolomite with anhydrite nodules or columnar crystals

Ma 523

Microcrystalline dolomite with local fine-crystalline to silty dolomite. A small amount of dolomitic anhydrite intercalates the middle strata. More than half of the strata are composed of karst formation rock, with 5–6 layers in some wells

Ma 533

Dominated by micro- to fine-crystalline dolomite intercalated by silty dolomite with anhydrite nodules. A moderately thick layer of anhydrite is developed locally. Most of the anhydrite was transformed to karst formation rock

Ma 514

The upper part is silty dolomite with anhydrite nodules, intercalated by silty to microcrystalline dolomite. The lower part is fine-crystalline to sily dolomite with anhydrite and spatulate dolomite. The middle part is 1–5 m karst rock with 1 m tuffaceous rock at the bottom

Ma 524

Dominated by micro- and fine-crystalline and silty dolomite. The middle and lower parts are interbedded with silty dolomite with anhydrite nodules. The upper part is folia-like dolomite with 0.3–1 m karst formation rock

Ma 534

Dominated by microcrystalline dolomite and intercalated by fine-crystalline dolomite. The upper and middle parts are intercalated by anhydrite. Folia-like dolomite can be found in the upper part in some wells. Karst formation rock is locally developed

Ma 515

Microcrystalline to silty dolomite turns downward into coarse–silty dolomite

Ma 525

Black microcrystalline limestone with columnar stromatolite and sandy dolomite at the bottom

Ma 52

Ma 53

Ma 54

Ma 55

(self-potential logging), extremely high RT(resistivity logging), and AC(acoustic travel time logging). It is horizontally stable and its thickness and lithology insignificantly vary. Its characteristics make it an important marker bed of the Ma 5 member in the Ordovician of the Daniudi gas field. K 3 (Ma 514): This layer comprises black tuffaceous mudstone, which is stable in the whole Ordos Basin, especially in the center. The well logging shows a high GR and AC and low RT. This marker bed is evident as tuffaceous layer in North Hubei, which is stable and can be treated as the marker bed of the Upper Ordovician. K 2 (Ma 522): This layer is pure dolomite. The well logging shows a low GR (generally smaller than 25 API), box shape, low PE(photoelectric absorption logging) and density, and high RT. This layer can be used as marker bed or

assistant marker bed for the stratigraphic correlation of the Ordovician Ma 5 member. K 1 (Ma 541): The lithology comprises dark gray argillaceous dolomite and dolomitic mudstone with lime dolomite and angular dolomite. This layer is evident and stable in Xiangfen, North Shanxi. It can be treated as a marker bed of Ordovician weathering crust.

15.4.2 Sedimentary Features The sedimentary environment of the Ma 5 member is a carbonate tidal flat with micritic to microcrystalline, fine-crystalline, gypsum, lime, argillaceous, and stromatolite dolomites. The sedimentary structures include bird-eye

Grey bauxitic mudstone

Subtidal

2940

Ma51

2930

51

52

2950

53

Gray-black limestone with local powder dolomite.

Ma51 Ma52 Ma53

2960

54

K3

K4

55

2970

56 57

2980

58

Black tuffaceous mudstone,high GR,high AC,low RT

Pure dolomite, low GR, low AC, high DEN, Low PE

Caledonia

50

Intertidal-supratidal

2920

Ma55-2

49

K2

Black tuffaceous mudstone,high GR,high AC,low RT

Subtidal

Ma54-1

46

Limestone, light grey dolomite, limestone, mudstone, limestone-bearing dolomite and mudstone are partially mixed with grey black mudstone.

Carbonate platform at epicontinental sea

2910

Ma54

45

48

Ma55-1 Ma55

K1 44

Ma53-3

Ma54-2

52698 m3/d

43

47

Ma53-2

Ma54-3

Ma56

42

2900

Ma52-2

2890

Ma52-1

2880

Ma51-3 Ma51-4

Open flow

Bauxite mudstone, Ultra-high GR, High CNL with low RT

41

Ma51-2

Tectonic stage

AC

Characteristics of mark layer

Perforated interval

10000 240

Thick coal layer on the top with gray black mudstone, carbonaceous mudstone,light gray fine sandstone underneath. The bottom is gray limestone

Subfacies

Mark layer

LLD

CNL

Facies

10000 45

Sedimentary facies

Hercynian

40

10

LLS

Dolomite 0 100 Coal 0 100 Lime 100 -15 0 Sand 0 100 Mud 140 0 100 3

Daniudi Gas Field

Supratidal

39

Lithological description 10

DEN

Supratidal

2870

Lower

38

Microsphere Resistivity 10000 2

10

Tidal Flat

Tai1

Majiagou Ma5

200

Depth(m)

Sub member

Tai2

Ma53-1

Lower Paleozoic Ordovician

GR 0

Middle Benxi

Upper

Layer

150

2860

Taiyuan

SP 0

50

Upper Paleozoic Carbonferous

Erathem System Series Formation Member

Stratum

Lithology

15 Logging display

378

Grey-black micrite limestone, low GR,High RT,Low CNL

Limestone, light grey limestone, limestone and limestone-bearing mudstone.

59

2990 30

60 61 62 63

Fig. 15.4 Integrative column of the Ordovician weathering crust in well #D98 in the Daniudi gas field, Ordos Basin

structures, stromatolites, and laminates as well as corrosion vugs and gypsum-moldic pores (Figs. 15.4 and 15.5). According to the water and lithology, the sedimentary environment can be divided into supralittoral, intertidal, and sublittoral facies. Based on the sediments, it can be categorized into gypsum dolomitic flat, gypsum-bearing dolomitic flat, lime dolomitic flat, argillaceous dolomitic flat, and muddy flat. Research showed that the seawater is supplied from the east to the Ma 5 member. The basin is a semi-restricted environment because of the central paleo-high. At that time, the eastern paleo-high was supralittoral, with a gypsum

dolomitic flat, due to extremely strong evaporation. Because big storms or waves and strong eastward evaporation had no influence, the gypsum-bearing dolomitic flat formed (e.g., the fine-crystalline to silty dolomite with gypsum in well Da 98). Intertidal facies were composed of dolomitic and lime dolo-flats. The sublittoral consisted of a limestone flat. The Ma 51–2 and Ma 55 layers are treated as the key research layers in the Daniudi gas field and sedimentary models of these two layers were established (Fig. 15.6). The sedimentary environment of the Ma 51–2 layer in the research area was supralittoral–intertidal, mainly composed of silty dolomite with gypsum and dolomite with limestone.

15.4

Characteristics of the Main Gas Layer

379 E

Supratidal zone

Anhydrite dolomite flat

Intertidal zone

Anhydrite-bearing dolomite flat

Dolomite flat

Subtidal zone

Calcite dolomite flat

Limestone flat

HT

Anhydrite powder dolomite, with anhydrite content>20%

Anhydrite-bearing powder dolomite, with anhydrite content20%

Core photo

Anhydrite-bearing powder dolomite, with anhydrite content1 mm), medium (0.1–1 mm), small (70°), angled fractures (5°–70°), fractures with opening degrees

18

Tahe Oilfield

below 0.1 mm, cracks from 0.1 to 1 mm, and fractures larger than 1 mm accounting for 33%, 41.04%, 68.14%, 26.62%, and 5.24%, respectively. The average fracture density is 8.78 bars/m and the single-well fracture density is 26.51 bars/m (well T 401). Most of the fractures are effective fractures; only 9.4% of the fractures are filled with calcite and argillaceous minerals. The above-mentioned data do not reflect the overall development of the fractures due to the low recovery of the stratigraphic cores. However, the statistics indicate the importance of fractures in this area. They are important reservoirs and channels for fluids. The fractures have three main strike directions in the FMI (imaging logging), that is, NEE–SWW, N–S, and NW–SE, followed by NNW–SSE and E–W. The NEE–SWW strike is the most developed. The fractures in this period are the products of Early Hercynian movement. They are dominated by high-angle fractures, which is consistent with the core observations. All FMI data, such as those for the Sha 66 and Sha 67 wells, show this feature. The suture line is caused by pressure dissolution during diagenesis. Their widths range from a few micrometers to several tens of micrometers and they mainly are horizontal (small amount of oblique or vertical sutures). They were observed in 14 drilling cores; their local development is very strong. For example, 398 suture lines can be found in the section between 5,667.19–5,675.56 m in well Sha 61 (7.37 m of core), with a density of 54 bars/m. Approximately, 95.3% of the sutures in the fluorescent thin sections showed oil and gas, indicating that they have a certain reservoir capacity. The more significant diagenetic fractures in this area are mainly weathering fractures near the unconformity surface. The extension of these fractures is generally short and they are confined to layers. They are connected with each other and form breccia-like pores. Pores often develop along with these tensile fractures. The caves are filled with various types of sand and mud; however, the effective pores remain after a considerable part of the filling, forming a good reservoir space. Many wells in the Tahe area contain oil and gas layers near the unconformity surface (e.g., the Lunnan 1, Lunnan 18, Sha 34, T 301, and T 401 wells), which also indicates the significance of the fractures. • Cavity Cavity represents an important reservoir space in the Ordovician carbonate reservoir in the oilfield. Their formation and development are mainly related to karstification and their distribution is extremely heterogeneous. They often develop along the seepage zone (paleogeomorphology, fault zone) and form cavities reservoir together with the fractures.

18.4

Pay Interval Characteristics

439

Based on their size, the cavity can be divided into dissolution cavities and large cavities. a. Dissolution cavities Dissolution cavities generally form due to dissolution in the early permeable zone (mainly fractures, microfractures, or sutures) and represent an important reservoir space of the Ordovician carbonate reservoirs in the Tahe area. Based on their diameter, they can be divided into large (>10 mm), middle (5–10 mm), and small ( 2000 m formed. The Cambrian paleo-ancient uplifted carbonate rocks were buried deep in the ancient uplift, the structure morphology and distribution remained unchanged, and inheritance was developed. In short, the middle Tarim paleo-uplift formed and was shaped early. The Middle Ordovician formed mainly due to fault movement. The Silurian system was characterized by fold movement and shaped before deposition. The formation and evolution of the Tazhong paleo-uplift occurred early in the north and late in the south and the tectonic action was weak in the west and strong in the east. The Tazhong paleo-uplift experienced multi-period tectonic superposition, but the morphology of the Lower Paleozoic carbonate anticline paleo-uplift, which was an inherited paleo-uplift, remained unchanged (Zhou et al. 2011; Ran 2017).

19.3.4.5 Geophysical Identification Technology and Methods for Oil and Gas Reservoirs The main oil and gas reservoirs in the Tazhong gas condensate field were interbedded karst reservoirs of the Ordovician Yingshan and Yijianfang Formations and reef– bank karst reservoirs of the Lianglitage Formation. The drilling results showed that the favorable and effective Ordovician reservoirs are mainly characterized by a “beaded” strong-amplitude reflection in the seismic profile and horizontal “speckle” or “lump” distribution. The development degree of the reservoir can be described with the geophysical properties. At present, the comprehensive application of seismic “sweet spot” properties better predicts the development of carbonate reservoirs. The hydrocarbon-bearing properties of the reservoir can be used to better reflect the variation in the oil, gas, and water by using the characteristics of the amplitude of the pre-stack gather and the offset and variation in the mid-intercept gradient (see the “Introduction” in Chap. 17).

19.4

Exploration and Development Enlightenment

19.4.1 Breakthrough in the Understanding of Quasi-Stratified Oil and Gas Reservoirs, Guiding the Discovery of Large Oil and Gas Fields The oil and gas exploration in Tazhong, also from successive failures of the structural exploration of the large anticline and the ancient buried hill, has carried on the deeping consideration. Therefore, new research on the Tazhong I fault zone regarding the modeling, structure, stratum, sedimentary reservoir, hydrocarbon accumulation and other systems was carried out. Based on the results, the new Tazhong I belt was proposed as sedimentary slope (Yang et al. 2011). The

Tazhong I Condensate Gas Field

results showed that a marginal reef shoal reservoir of the Lianglitage Formation developed along the slope break zone. The mid-slope break zone of the Tazhong was considered to be a steep slope platform edge belt. The reservoir was vertically overlapped and laterally contiguous. A 600 m thick reef beach body fracture and cave reservoir formed along the platform break zone. The late tectonic activity resulted in an east–west elevation difference of 1800 m. Based on detailed basic research, oil and gas accumulation occurred in irregular karst fracture caves, which were not controlled by the height of the local structure, mainly intermittently distributed within 150 m below the unconformity surface. Oil and gas were transported along strike-slip faults and fracture systems in a three-dimensional network, which was characterized by the overall oil content and local enrichment of a large area of continuous slices. A fracture-cavity is a relatively independent oil–water system lacking a macroscopic uniform oil–water interface. It is characterized by a low abundance and the scale distribution of giant quasi-stratified oil and gas reservoirs. It represents a quasi-stratified hydrocarbon accumulation model, which is controlled by the oil and gas and reef and beach body and not by the local structure. These results led to the “along the edge of the platform, drill reef beach” oil and gas reservoir exploration target. By analyzing multiple field outcrops, comparing the drilling data, interpreting seismic profiles, and studying the sequence stratigraphy, at least five stages of unconformity were identified in the thick carbonate rock interior. Short-term tectonic uplift and a parallel and low-angle unconformity of the overlying strata were discovered, and the inside of the buried hill has the exploration potentiality. This changed the previous understanding that the carbonate rock does not contain a good reservoir; a sedimentary background was proposed for the large platform, which was more conducive to the large distribution of interlayer karst and indicated that a reservoir was widely distributed in the Tazhong area in horizontal direction. The exploration target “drilling along the interlayer karst reservoir and drilling the scale fracture & cave reservoir” was gradually established. Since 2008, a number of exploratory wells have been deployed in the Tazhong area and a large karst gas condensate field has been discovered in the Yingshan Formation of the Tazhong area.

19.4.2 Reef–Shoal Karst and Interlayer Karst Fissure Cavities Are Primary Drilling Targets Based on the exploration of the interlayer karst oil and gas reservoir, the exploration of the interlayer karst in the Tazhong area expanded northward.

19.4

Exploration and Development Enlightenment

Guided by the geological knowledge, structure interpretation, fine characterization of the fracture-cavity system, and high-productivity and enrichment target description technology of the carbonate rock, reservoir identification, characterization, and description techniques were pioneered for the “large-scale fracture–cave reservoir” based on the karst Formation theory. The fracture-cavity belt, fracture-cavity system, fracture-cavity body (unit) were divided and evaluated and an irregular well pattern and well distribution technology were used to realize the exploration and development of the complex carbonate reservoir. Based on the fractures and the associated fracture dissolution system, the development area of the dissolution fractures–caves was divided into fracture-cavity zones, which are important units for oil and gas pre-exploration. The fracture zone was evaluated based on the size and development degree of the fracture zone and reservoir formation conditions. Within the same fracture zone, fractured cave concentration development zones with similar fluid properties were divided into fracture-cavity systems, which are important units for the reservoir evaluation. According to the development degree, scale, and accumulation of the fractures–cavities in the fracture-cavity system, a high-yield and stable production well group was quickly established in the class I fracture-cavity system. The fracture-cavity unit is a set of single or multiple fracture–hole bodies, which is an important target for well deployment and an important basis for the division of flow units.

19.4.3 Improving the Quality of 3D Seismic Data Is the Eternal Theme of Fracture-Cavity Marine Carbonate Rocks The karst fracture caverns in the Tarim Basin are generally buried at depths below 6000 m and the size of a single fracture cavern varies from a few meters to several hundred meters. By tackling the key problems, the carving technology of fracture-cavity marine carbonate rock was established, supporting the discovery and integrated production of large oil and gas fields. However, due to the small geological body of the fracture-cavity body and the limitations with respect to resolution of current seismic data, the carving results of the fracture-cavity body often have different degrees of amplification. It is very difficult to predict the effective connectivity of the fractures between and within the fracture-cavity body. Thus, the continuous improvement of the quality of seismic data is necessary. Based on acquisition procedures, such as increasing the coverage times, shot and trace density, and azimuth angle,

467

the acquisition of seismic data in areas with a high seismic signal-to-noise ratio, such as farmland, can meet the requirements of anisotropic pre-stack depth migration processing, fracture identification, and slot–hole carving. However, in desert regions with low seismic signal-to-noise ratios, it is still necessary to continue to make progress through acquisition techniques, for example, continuous improvement of the surface element accuracy, coverage times, and shot and trace density, and to continuously widen the azimuth to improve the seam hole information precision, satisfy the anisotropy of pre-stack depth migration processing requirements, and improve the accuracy of fracture-cavity reservoir and effective crack imaging to meet the requirements of effective fracture identification and fracture-cavity connectivity prediction (Wang et al. 2011).

19.4.4 The Fine Description and Target Technique for the Fracture-Cavity Are the Keys to Improve the Drilling Success Rate The matrix porosity of marine carbonate rocks with ultra-deep fractures and caverns is generally below 2%, which makes it difficult to effectively store oil and gas. The reservoir space is mainly composed of caves, holes, and cracks, which are unevenly distributed and complex. In the reservoir space, multiple caves and holes are often connected with each other through cracks, forming a large collection of fractures and holes. This type of fractured cave body has a large scale, large reservoir space, good sealing properties, and mudstone and marl cap layer. The oil and gas are enriched in the upper part of the fracture-cavity; thus, it is easy to obtain a high and stable production by drilling. The Ordovician carbonate fractures–cavities in the Tarim Basin are deeply buried and the high-resolution 3D seismic data have highly fidelity, providing rich, and real information on the ultra-deep carbonate fractures. Heterogeneous cave-, pore-, and fracture-type carbonate reservoirs are characterized by three characteristics in high-resolution 3D data, that is, they are beaded, flaky, and chaotic. By using the slot–hole engraving technique, 3D space engraving of the fractured hole body was carried out to depict the 3D space position and shape, effective reservoir spatial distribution, and connectivity of the slots–holes. Therefore, it is possible to drill into the fracture-cavity. In other words, to improve the success rate, the key problems must be continually studied and addressed.

468

19.4.5 Perseverance and Indomitable Spirit Are the Keys to the Success of Large Oil and Gas Fields The carbonate rocks in the Tarim Basin are thick, widely distributed, and have a large resource potential. These favorable conditions have strengthened the confidence of petroleum geologists in searching for large oil and gas fields in carbonate rocks. However, these reservoirs have a deep burial depth, strong heterogeneity, and complex distribution of oil, gas, and water. Their particularity and complexity also determine the difficulty and long-term nature of carbonate exploration and development. The tortuous exploration, development, and practice associated with carbonate rocks show that the new theoretical understanding, progress in tackling key technical problems, and unremitting and indomitable spirit are the keys to the discovery of large oil and gas fields.

References Han J, Han J, Jiang J et al (2013) Cases of discovery and exploration of marine fields in China, part 15: Ordovician Yingshan condensate gas field in north slope of Tazhong uplift, Tarim Basin. Mar Orig Pet Geol 18(3):70–78 Jia C, Zhang S, Wu S et al (2004) Stratigraphy of the Tarim Basin and adjacent areas. Science Press, Beijing

19

Tazhong I Condensate Gas Field

Miao J, Jia C, Zou C, et al (2007) Characteristics and exploration fields of Paleo-Karst reservoirs at the top of early ordovician in central Tarim uplift. Nat Gas Geosci 18(4):497–500 + 606 Ran Y (2017) Tectonic evolution of marine carbonate composite basin in Tazhong. Liaoning Chem Ind 46(9):894–896 Wang T (2009) Overcoming world-class technical bottlenecks. China Foreign Energy 14(5):1–8 Wang Z, Yu H, Ji Y et al (2011) Key technologies for discovery of giant marine carbonate oil-gas fields in Tazhong Area, Tarim Basin. Xinjiang Petroleum Geology 32(3):218–223 Wu G, Li Q, Zhang B, et al (2005) Structural characteristics and exploration fields of no. 1 faulted slope break in Tazhong area. Acta Petrolei Sinica 26(1):27–30+37 Yang H, Han J, Sun C, et al (2011) Exploration of reef-flat complex giant oil-gas field in Tazhong no.1 slope break in Tarim Basin: theory and technology. Xinjiang Pet Geol 32(3):224–227 Yang H, Wu G, Sun L et al (2007) Condition and explorative direction of lithologic reservoir of silurian in northern slope of Tazhong uplift. Xinjiang Pet Geol 28(3):286–288 Zhao Y, Zhang G, Xiao J et al.(2000) Paleozoic stratigraphy and conodonts in Xinjiang, Petroleum Industry Press, Beijing Zhou X, Li B, Chen Z et al (2011) The tectonic genesis and exploration targets of large oil-gas fields in Tazhong area, Tarim Basin. Xinjiang Pet Geol 32(3):211–217 Zhou X, Wang Q, Yang W, et al (2005)The resource and exploration of natural gas in Tarim Basin 16(1):7–11 Zhou X, Wang Z, Wang H, et al (2006a) Cases of discovery and exploration of marine fields in China, part 5: Tazhong Ordovician condensate field in Tarim Basin. Mar Orig Pet Geol 11(1):45–51 Zhou X, Yang H, Wu G, et al (2006b) The experiences and targets for exploration of large oil-gas field in Tazhong area, Tarim Basin. Xinjiang Pet Geol 30(2):149–152

20

Hadexun Oilfield

20.1

Regional Geographic Location and Geological Background

Hadexun oilfield is China’s first ultra-deep large-scale marine sandstone oilfield of multi-million-ton. It is located in Shaya County, Aksu Prefecture, Xinjiang Uygur Autonomous Region, on the south bank of Tarim River, about 16 km southwest of Hadexun township. The structural location is located in the Hadexun nose-shaped uplift structural belt on the south slope of Lunnan low uplift of the Tabei Uplift. In February 1998, the first exploratory well (HD 1) drilled in the Hade 4 structural belt obtained high-yield industrial oil flow in the middle mudstone member of the Carboniferous, and the Hade-1 thin sandstone reservoir in the Hadexun oilfield was discovered. In the same year, the HD 1-2 and HD 4 wells successively obtained industrial oil flows in the Donghe sandstone member, and the Hade-4 Donghe sandstone reservoir was discovered. The Donghe sandstone reservoir is a structure–stratigraphic composite reservoir (sharply tilted oil–water contact) and the thin-layer reservoir in the middle mudstone member is a layered edge water reservoir. The proven reserve is 8,202  104 t, and the proven and probable reserve is 11,022  104 t in Hadexun oilfield. Horizontal well water injection is adopted for overall development, and the annual production reaches 200  104 t.

20.2

Exploration and Development History

20.2.1 Drilling the Low-Relief Anticline and Discovering a Thin Sandstone Reservoir in the Middle Mudstone Member In 1990 and 1993, during the oil and gas exploration in Tarim, marine sandstone oilfields were discovered successively in the Donghetang Structure on the north Tarim Uplift

and Tazhong 4 Structure in the desert hinterland. Thus, the exploration of the Carboniferous Donghe sandstone reservoir started. Based on the 2  2 km seismic survey in 1996, two Carboniferous Donghe sandstone low-relief anticline structural traps, that is, Hade-1 and Hade-2, were discovered. On February 21, 1998, the HD 1 well drilled in the HD 1 structure trap was used for testing of the thin sand layer section of the Lower Carboniferous mudstone member (C5). The high-productivity oil flow of 103 m3 was yielded by producing with a 7.94 mm choke. Although the HD 1 well made the first oil and gas exploration breakthrough in the Mangar Sag and discovered the thin sand reservoir of the Hadexun oilfield, the high-quality reservoir of the Donghe sandstone member (C9) at the bottom of the Carboniferous system designed for exploration target was missing in the well. Later, HD 2 well was deployed in the north high point of HD 1 structural trap, and industrial oil flow was also tested in the thin sand section of middle mudstone section. The Donghe sandstone section was also missing as well as HD 1. In October 1998, the controlled reserves of the reservoir in the middle mudstone section of Carboniferous in well block HD 1-HD 2 were 1008  104 t, and the oil-bearing area was 61.5 km2. (Zhou et al. 2007).

20.2.2 Drilling Stratigraphic Traps to Achieve a Breakthrough in the Donghe Sandstone Although exploration for low-relief structural traps in the Donghe sandstone in HD 1 and HD 2 wells has failed successively, the Hadexun pre-Carboniferous paleo-uplift was discovered. Combining the characteristics of the deposition and distribution of the Donghe sandstone in the Tarim Basin controlled by the pre-Carboniferous paleo-nose uplift, an integrated study suggests that the down-dip direction of the pre-Carboniferous paleo-nose uplift is likely to contain high-quality marine sandstone reservoirs of Donghe

© Geological Publishing House and Springer-Verlag GmbH Germany 2020 Y. Ma, Marine Oil and Gas Exploration in China, https://doi.org/10.1007/978-3-662-61147-0_20

469

470

sandstone and develop overlying traps in the Donghe sandstone Formation. Therefore, in September 1998, well HD 4 was frilled at the relatively low south point of the low anticlinal structural trap of HD 4 Donghe sandstone to continue exploring the Donghe sandstone reservoir. Then the HD 4 well made a breakthrough in the Donghe sandstone, and found the high-quality Donghe sandstone reservoir in the Mangar Sag for the first time, which greatly expanded the exploration scope of the Carboniferous Donghe sandstone reservoir in the Tarim Basin. After high industrial oil flow was obtained in the Donghe sandstone in well HD 4, the exploration in this area was carried out as a whole. At the beginning of 1999, reservoir evaluation and progressive development planning schemes were developed and three evaluation wells (HD 401, HD 402, and HD 403) and two development wells (HD 1-2, HD 4-2) were drilled. The evaluation in January 2000 indicated proven oil geological reserves of 3,068.1  104 t and dissolved gas reserves of 7.94  108 m3 (Zhou et al. 2007).

20.2.3 Integration of Progressive Exploration and Development Massively Improving Reserves and Production Hadexun oilfield is characterized by deep burial depth, low structural amplitude, thin reservoirs, and difficult identification of the Donghe sandstone pinchout line. The Tarim oilfield branch decided to implement an integrated exploration and development to ensure the continuous increase of reserves and production by scientific research, progressive exploration, and deepened understanding, which change marginal oilfield into efficient oilfield. During the progressive exploration and development, the deployment of key wells was of great significance for the expansion of the range and scale of the Donghe sandstone reservoir. The HD 1-9 well, drilled in late 2000, was originally expected to have a thickness of 3 m in the Donghe sandstone reservoir and an actural drilling oil column height of 12.5 m (an increase of 9.5 m), extending the oil-bearing range of the Donghe sandstone reservoir to the east and south. At the end of 2001, the proven reserves of the oilfield reached 4130  104 t (Zhou et al. 2007). On the premise of further understanding the geological characteristics of the reservoir in Hadexun oilfield, the 80  104 t capacity expansion and development plan for the whole oilfield were compiled and completed in May 2001. At the end of 2002, the accumulative proven oil reserves of the oilfield reached 4,869  104 t, and the actual production capacity reached 85  104 t, and the crude oil production reached 816  104 t in this year. At the end of 2002, the HD 11 well in the north of the Hadexun oilfield was drilled into the Donghe sandstone

20

Hadexun Oilfield

member (C9) and low yield oil flow was obtained in the Carboniferous stratigraphic traps. In early 2003, the evaluation well HD 111 was drilled in the Donghe sandstone member also encountered a reservoir of 3.7 m. With the increase of data, the concept of “post-reservoir” and the theory of “non-steady dynamic accumulation” were creatively proposed after an in-depth analysis of the oil–gas charging and accumulation process of Donghe sandstone reservoir in Hadexun oilfield (Sun et al. 2008, 2009). This concept reasonably explained the formation mechanism of the OWC tilt in the Donghe sandstone reservoir, predicted that the Donghe sandstone reservoir in the Hadexun oilfield will continue to expand to the northwest, which guided the progressive exploration and development of the Donghe sandstone reservoir. In particular, the successful drilling of HD 4-30, HD 4-44, HD 4-46, HD 112, HD 113, HD 404, HD 17, and HD 171 has enabled the Donghe sandstone reservoir to expand its oil-bearing area and reservoir size in the Hadexun oilfield. By the end of 2015, the accumulated oil area was 236.35 km, the proven petroleum reserves were 8,202  104 t, and the proven and probable reserves were 11,022  104 t (Zhou et al. 2007).

20.2.4 Optimization and Adjustment of Development to Maintain the Stable Production in the Million-Ton Oilfield The Hadexun oilfield was developed in three stages: continuous production expansion and reserve growth, 150  104 t stable production, and development adjustment and optimization. Continuous production expansion and reserve growth stage: from 2000 to 2004, the proven oil reserves increased from 3,068.4  104 t to 8,202  104 t and the scale of production capacity increased from 30  104 t to 170  104 t. Stable production stage: horizontal well development was used in the Donghe sandstone reservoir and dual step horizontal well water injection development was used in the thin sand layer reservoir. From 2004 to 2012, stable production of more than 150  104 t oil was realized in the oilfield. The annual oil production reached the highest peak of 224  104 t in 2008. Development adjustment and optimization stage: in February 2012, “Hadexun Oilfield Development Adjustment Scheme” was compiled. It mainly focused on the well pattern infill and expansion of the water injection. Based on the use of two sets of development layers and two sets of well networks, 92 wells were drilled (76 oil wells, 16 injection wells). An increase in the recovery rate from 3.5 to 38% by 2015 was predicted, which is now gradually being realized.

20.3

20.3

Reservoir Geologic Characteristics

471

Reservoir Geologic Characteristics

20.3.1 Sequence Stratigraphic Characteristics 20.3.1.1 Stratigraphic Division and Lithology Characteristics of Carboniferous (1) Lithology characteristics The Carboniferous can be divided into four formations and nine lithologic members in the Tarim Basin, that is, the limestone member of the Xiaohaizi Formation, limestone member, sand and mudstone member, upper mudstone member, standard limestone member, middle mudstone member, bioclastic limestone member, and lower mudstone member of the Kalashayi Formation, gravel sandstone member of the Bachu Formation and Donghe sandstone member of the Donghetang Formation (also known as “Bachu Formation Donghe Sandstone member”). In the area of the Hadexun oilfield, the thickness of the Carboniferous ranges from 540 to 722 m. The bioclastic limestone member and lower mudstone member (Table 20.1) are missing and the gravel sandstone member became the breccia member and unconformity contact with the underlying Lower Silurian. First lithologic member (C1): “Limestone member:” the thickness ranges from 20 m to 68 m, and lithology is Table 20.1 Summary of the Carboniferous lithology in the Hadexun oilfield, Tarim Basin

System

Carboniferous

Formation

off-white cryptite mixed with purple-brown mudstone, unconformity contact with the overlying Permian. Second lithologic member (C2): “Sand and mudstone member:” the thickness ranges from 340 to 366 m; brown, brown-red, and gray mudstone and silty mudstone interbedding with a thin layer of siltstone, cryptite, and gypsum-mudstone. Third lithologic member (C3): “Upper mudstone member:” the thickness ranges from 88 to 110 m; brown, gray-green and gray mudstone, silty mudstone and a thin layer of shallow gray argillaceous siltstone. Fourth lithologic member (C4): “Standard limestone member:” the thickness ranges from 22 to 31 m; the upper member comprises a thick layer of gray-brown micrite; and the lower member contains a thick layer of gray-white gypsum rocks, which is sandwiched between mudstone. The gypsum rocks are widely distributed in the eastern of the HD 18 well area and in the HD 10 well area. A “salt bun” appears in the north of the HD 18 well, which gradually thins and is scattered in the south. Fifth lithologic member (C5): “Middle mudstone member:” the thickness ranges from 68 to 83 m; mainly gray, brown, and gray-yellow mudstone, with a thin layer of light gray, brown-gray fine sandstone and siltstone. Eighth lithologic member (C8): “Gravel sandstone member (breccia member):” the thickness ranges from 2 to 12 m;

Lithologic member Tazhong

Serial number

Hadexun

Xiaohaizi Formation

Xiaohaizi limestone member

C1

Limestone member

Kalashayi Formation

Limestone member Sandstone–mudstone member

C2

Sandstone–mudstone member

Upper mudstone member

C3

Upper mudstone member

Standard limestone member

C4

Standard limestone member

Middle mudstone member

C5

Middle mudstone member

Bioclastic limestone member

C6

Missing

Lower mudstone member

C7

Gravel sandstone member

C8

Breccia member

Donghe sandstone member

C9

Donghe sandstone member

Bachu Formation

Donghetang Formation

472

20

green-gray, light gray and gray argillaceous siltstone, fine sandstone, gravel fine sandstone, and medium sandstone. Ninth lithologic member (C9): “Donghe sandstone member:” the thickness ranges from 0 to 57.5 m; brown oil-bearing quartz sandstone and light gray quartz sandstone. Silurian (S): Light gray, purple, and yellow-brown argillaceous siltstone, in unconfirmed contact with the overlying Carboniferous. The target strata of the Hadexun oilfield are the thin sand of the middle mudstone member in the Kalashayi Formation and the sandstone member of the Donghetang Formation of the Carboniferous. (2) Carboniferous sequence characteristics With respect to the Carboniferous sequence division, predecessors proposed different sequence division schemes. Guo et al. (1996) divided the Carboniferous into five sequences, and Zhu (2003) divided it into four third-order sequences. Wang et al. (2004), Gao et al. (2003) divided the Carboniferous into five third-order sequences. This section follows the sequence division scheme by Wu et al. (2008) and Wang et al. (2004). The Carboniferous is divided into a super-sequence, which was formed during the second-order cycle of relative sea level change in the Hadexun oilfield. Its top and bottom boundaries are obvious unconformities formed by the decrease in the sea level. It consists of two megasequences and five sequences, but one sequence is missing in the Hadexun area (Table 20.2).

Hadexun Oilfield

20.3.1.2 High-Frequency Cycle and Sandstone Member Division in the Objective Layer (1) Sequence division of the middle mudstone member Based on the principle and method of sequence division, combined with the core and logging curve characteristic of the boundaries, one complete third-order sequence, two parasequence groups, five parasequences, seven stratum groups, and 16 strata (Fig. 20.1) were identified in the middle mudstone member of the study area. The 3-2 single layer, 4-2 single layer, 5-2 single layer, and 5-3 single layer are called the second sand layer, third sand layer, fourth sand layer, and fifth sand layers, respectively. At the initial stage of the middle mudstone member deposition, the seawater invaded from the southwest due to the rise of relative sea level. The Hadexun area was basically absent of the lowstand systems tract, and the transgressive system tract directly covered the lower unconformity surface. The main sediments were the argillaceous sediments in the supratidal zone and intertidal zone, and the thin sandbody was scattered sporadically. In the area of the transgression system tract, a regressive parasequence group developed including three parasequences. Parasequence I and II were mainly developed in the supratidal zone, with brown and gray mudstone. Parasequence III, mainly developed in the intertidal zone and tidal channel, was characterized by small size, small thickness, and poor continuity distribution of the thin sandbody, and only the 5-3 single layer (fifth sand layer) and the 5-2 single layer (fourth sand

Table 20.2 Summary of the Carboniferous sequence and system tract division in the Tarim Basin System

Carboniferous

Formation

Lithologic member Serial number

Hadexun

Xiaohaizi Formation

C1

Limestone member

Kalashayi Formation

C

2

C

3

Bachu Formation

Donghetang Formation

Upper mudstone member Standard limestone member

C5

Middle mudstone member

C6

Missing

C

7

C

9

Sequence

System tract

Megasequence II

Sequence IV

HST

Sequence III

HST

Sequence II

HST (TST)

Sequence I

HST (TST)

Sandstone and mudstone member

C4

C8

Megasequence

Breccia member Donghe sandstone member

Note The Bachu Formation sequence is almost missing in the Hadexun area

Megasequence I

TST TST

20.3

Reservoir Geologic Characteristics

473

Stratigraphic division

Sequence division Se System -quence tract

Parasequence

Stratam group

2

Stratam

Interface characteristics

Cycle characteristics

Single layer

Sand Layer

1

2-1

Unconformity surface

1-1

1-2

Sedimentary erosion surface

2-1

1

Group

Member

S1 2

1-1

Lithological rhythm difference surface

2-2

2-2

General flooding surface

3-1

2-1

Lithological rhythm difference surface

3-2

1-2

Sedimentary erosion surface

4-1

1-1

Lithological rhythm difference surface

4-2

1-7

Maximum flooding surface

5-1

1-6

Lithological rhythm difference surface

5-2

1-5

Lithological rhythm difference surface

5-3

1-4

Lithological rhythm difference surface

5-4

1-3

Lithological rhythm difference surface

5-5

1-2

Lithological rhythm difference surface

5-6

1-1

Lithological rhythm difference surface

5-7

1

1-1

General flooding surface

1

1-1

General flooding surface

HST

1

1

TST

3

S2

Middle Mudstone Member

Tertiary Sequence

2

4

5

S3

6-1

6

S4

7-1

7

S5

Unconformity surface

Fig. 20.1 High-resolution sequence unit division of the middle mudstone member in the Hadexun oilfield, Tarim Basin

layer) have better continuity. The fifth sand layer is divided into upper and lower two single sandbodies by the middle argillaceous interlayer. The upper sandbody is pinched out locally, and the lower sandbody is distributed in the whole area. The thickness of lower sandbody is stable at 0.5–1.0 m. The fourth sand layer gradually thickened from south to north, the thickness ranged from 0.36 to 1.50 m, with an average of 0.67 m. A progradation parasequence group, which can be divided into two parasequences, developed in the highstand

system tract. Due to the deep water, strong hydrodynamic force, and sufficient supply of detrital sources, Parasequence I deposits two phases of thin sandbodies with stable distribution and good connectivity, namely 4-2 single layer (third sand layer) and 3-2 single layer (second sand layer). The third sand layer is gradually thinned from south to north in a strip shape, with a thickness ranging from 0.50 to 2.20 m, with an average of 1.50 m. The second sand layer is thinned from the middle to the north and south, and pinchout to the north of the HD 11–HD 118 well area in the north, the

474

thickest layer is 1.89 m, with an average of 1.11 m. The argillaceous sediments deposited between the two thin sandbodies when the relative sea level drops. Due to the relatively shallow water, Parasequence II only deposits a set of thin sand layers at the bottom, that is, the 2-2 single layer (first sand layer), and the water was shallower upward rapidly. The middle and upper parts are mainly brown and gray mudstone sediments dominated by mudflats on the supratidal zone. At this point, the third-order sequence cycle of the middle mudstone member has ended. (2) Sequence division and correlation of the Donghe sandstone member A sequence was identified in the Donghe sandstone, which is an incomplete sequence under the control of the fourth-order cycle. The bottom was the overlying unconformity and the top was the truncated unconformity. In this sequence, the lowstand system tract and transgression system tract at the bottom are not developed; only the highstand system tract is developed, and two parasequence groups (Parasequence I and Parasequence II) are basically equivalent to the upper Donghe sandstone member and the lower Donghe sandstone member in the development plan. Based on high-resolution sequence stratigraphy and core, logging, and seismic data, two parasequences were identified. Six sets of stratum groups were identified in Parasequence 1, corresponding to the 12-7 stratum. Six sets of stratum groups were also identified in Parasequence II, corresponding to the 6-1 stratum (Fig. 20.2). Based on the single-well sequence stratigraphic unit division and sedimentary characteristic of the Donghe sandstone, four contras models were identified, that is, the isopachous contrast mode, facies transition contrast mode, sandbody overlapping mode, and undercutting contrast mode. The above model is used to compare the profiles of the Donghe sandstone reservoir. By comparing the electrical measurement curve characteristic of the non-cross section wells (drilling wells that are not in the cross section) with the adjacent cross section well curve, the sequence elements of the non- cross section wells can be divided into the standard of sequence unit division. The results show that the sections of the Donghe sandstone member in the study area are highly contrasting. In the Hadexun area, the bottom of the Donghe sandstone sequence overlapped the underlying Silurian, and the top was partially truncated. The Parasequence I in the Hadexun area was mainly a sedimentary stratigraphic unit in the early stage of the highstand system tract in the third-order cycle. During the deposition of Parasequence 1, the Hadexun area was at the

20

Hadexun Oilfield

margin of the basin, only a short period of the marginal facies zone deposition. The Donghe sandstone continued to onlap sediment from southwest to northeast, and the coastline gradually moved eastward to northward to form a set of retrogradation parasequence with the characteristics of the large thickness of the northwest well area and the thin thickness of the eastern part. Its internal 12-7 layers cover the underlying stratum by layer from southwest to northeast.

20.3.2 Sedimentary Facies Characteristics 20.3.2.1 Overview of the Regional Sedimentary Environment The Tarim intracratonic depression is a stable sedimentation zone in the Carboniferous Tarim Basin, which was deposited in a paleotectonic background at the end of the Devonian. The deposition thickness in the subsidence sedimentation center, in which the Hadexun oilfield is located, is 1200– 1400 m. The Donghe sandstone at the bottom of the Carboniferous Hadexun oilfield is a high-quality reservoir with high porosity and high permeability. Several large and medium-sized oil and gas fields were found in the Donghe sandstone. In other areas, such as Donghetang, Tazhong, and Manxi, several middle–large scale oil and gas fields were discovered in the Donghe sandstone. The tectonic background of the Late Devonian to Carboniferous played an important role in controlling the deposition and distribution of the Donghe sandstone. The Donghe sandstone was deposited in Mangar Sag and the peripheral of the paleo-uplift of the Late Devonian to early Carboniferous. The development of the paleo-uplift provided abundant material for the deposition of the Donghe sandstone and controlled the distribution of the Donghe sandstone pinchout line. In addition, the tectonic activity of the Late Devonian to Carboniferous also played a role in controlling the sediment thickness and its variation. The Tadong area is a stable uplift area. The central uplift area is rapidly settling under the background of the pro-phase uplift. The Tabei and Taxi areas also show the characteristics of a stable settlement. The Mangar Sag has a relatively large tectonic subsidence in the early Carboniferous, so the thickness of its Donghe sandstone deposit is also relatively thick. In the Hadexun area, the seawater generally transgressed and regressed from the southwest to the northeast in the Carboniferous. The study area experienced a decrease in relative sea level and denudation of the strata before the deposition of the middle mudstone member. After the filling and leveling of the surface, a set of tide flat sediments was deposited in the Hadexun area with the flat terrain and relatively shallow water.

Reservoir Geologic Characteristics

3

4

5

Donghe Sandstone

6

7

Lower Donghe Sandstone

8

9

10

11

12

Silurian

group

Parasequence

Stratam group

Stratam Sequence rhythm

sequence

set

Parasequence

Stratam group

Stratam

1-1

Truncated unconformity

II6-4

1-2

Stratam interface

II6-3

1-3

Stratam interface

1-4

Stratam interface

II6-1

2-1

Stratam group interface

II5-4

2-2

Stratam interface

2-3

Stratam interface

2-4

Stratam interface

II5-1

3-1

Stratam group interface

II4-4

3-2

Stratam interface

3-3

Stratam interface

3-4

Stratam interface

4-1

Stratam group interface

4-2

Stratam interface

4-3

Stratam interface

4-4

Stratam interface

II3-1

5-1

Stratam group interface

II2-4

5-2

Stratam interface

5-3

Stratam interface

5-4

Stratam interface

II2-1

6-1

Stratam group interface

II1-4

6-2

Stratam interface

6-3

Stratam interface

6-4

Stratam interface

7-1

Marine-flooding surface

7-2

Stratam interface

7-3

Stratam interface

7-4

Stratam interface

8-1

Stratam group interface

8-2

Stratam interface

8-3

Stratam interface

8-4

Stratam interface

I5-1

9-1

Stratam group interface

I4-6

9-2

Stratam interface

I4-5

9-3

Stratam interface

9-4

Stratam interface

9-5

Stratam interface

9-6

Stratam interface

I4-1

10-1

Stratam group interface

I3-4

10-2

Stratam interface

10-3

Stratam interface

10-4

Stratam interface

I3-1

11-1

Stratam group interface

I2-4

11-2

Stratam interface

11-3

Stratam interface

11-4

Stratam interface

I2-1

12-1

Stratam group interface

I1-4

12-2

Stratam interface

12-3

Stratam interface

12-4

Stratam interface Overlap unconformity

II6

II5

II4

II6-2

II5-3 II5-2

II4-3 II4-2 II4-1

II

II3-4 II3

II2

II1

System tract

II3-3 II3-2

Late Highstand System Tract

Upper Donghe Sandstone

2

sequence

Sequence Unit Para-

II2-3 II2-2

II1-3 II1-2 II1-1 I6-4

I6

I6-3 I6-2 I6-1 I5-6

I5

I4

I5-3 I5-2

I4-4 I4-3 I4-2

I

I3

I2

I1

I3-3 I3-2

I2-3 I2-2

I1-3 I1-2 I1-1

Early Highstand System Tract

1

Single Layer

Para-

Progressive Subsequence Set

Sand layer

Sequence Unit Cycle Interface characteristics

Donghe Sandstone Sequences

Group

Member

System

Formation

Stratigraphic Unit

Carboniferous

Fig. 20.2 High-resolution sequence unit division of the Donghe sandstone member in the Hadexun area, Tarim Basin

475

Bachu Formation

20.3

476

20

20.3.2.2 Types and Characteristics of the Sedimentary Facies (1) Sedimentary facies types and characteristics of the thin sand layer in the middle mudstone member

description and analyses of the cores, outcrop, regional geological data, and previous sedimentary facies research, the Donghe sandstone in the Hadexun area is considered as sandy coastal deposits controlled by non-barrier waves. The coastal facies can be further divided into 4 subfacies and 12 microfacies based on the shore facies research, modern sediment analysis results, and sedimentary characteristics of the Donghe sandstone. The four subfacies from the shore to the sea are the coastal sand dune subfacies, backshore subfacies, foreshore subfacies, and shoreface subfacies. The shore sand dune subfacies can be divided into three microfacies: shore dunes beach, shore dunes trough, and shore dunes ridge. The backshore subfacies can be divided into three microfacies: backshore beach, backshore shallow trough, and backshore dam. The foreshore subfacies can be divided into three microfacies: foreshore beach, foreshore groove, and foreshore dam. The shoreface subfacies can be divided into three microfacies: shoreface beach, shoreface groove, and shoreface dam (Li et al. 2008). Based on the analysis of the microfacies of the cores, conventional logging data, and the establishment of the logging model for sedimentary microfacies, the sedimentary subfacies and microfacies of the single wells can be divided. The results show that vertically the sedimentary microfacies evolution of the upper Donghe sandstone member underwent a transgressive–regressive cycle, from the backshore at the bottom to the foreshore to the shoreface. And then, the

The sedimentary facies are summarized from five aspects: color, rock composition, lithology and structure, grain size characteristics, and sedimentary structure. Based on the regional geological sedimentary background, the terrigenous clastic tidal flat facies, including two subfacies of the epilittoral zone and intertidal zone, can be identified in the thin sand layer in the middle mudstone member of the Carboniferous in Hadexun oilfield. The epilittoral zone subfacies mainly develops supratidal mud-flat microfacies, the intertidal zone subfacies develops intertidal mud-flat, mixed flat, sand flat, and tidal creek microfacies. The thin sand layer of the Carboniferous middle mudstone member of the Hadexun oilfield belongs to the intertidal zone and sand flat and tidal creek microfacies deposition (Fig. 20.3). (2) Types and characteristics of the sedimentary facies of the Donghe sandstone Based on the color, rock composition, lithology and structure, grain size characteristics, sedimentary structure, sedimentary cycle, and sedimentary sequence, the sedimentary facies characteristics has been summarized. Through the Fig. 20.3 Sedimentary microfacies of the sandstone layers 2–5 in the middle carboniferous Hadexun oilfield in the Tarim Basin

Hadexun Oilfield

A:No.2 Layer

Intertidal mud flat

B:No.3 Layer HD118

Tidal creek

Tidal creek

Intertidal sand flat Intertidal sand flat

l sa

nd

fla

t

Intertidal sand flat

cree

k

Int

ert

ida

Tida l

Intertidal sand flat

k

cr

ee

k

f la t

t

d

al

fla

an

ee

nd

ls

Ti d

sa

da

cr

al

rti

al

rtid

te

Ti d

e Int

In

Intertidal sand flat

Intertidal mixed flat

Intertidal sand flat

Tid a

lc

ree

k

C:No.4 Layer

D:No.5 Layer Intertidal mixed flat

Intertidal sand flat

al Tid

ek

cre

Tidal creek Tidal creek

Intertidal mixed flat

20.3

Reservoir Geologic Characteristics

477

and nearshore sand dams. The sand dam can rarely be distinguished based on underground core observations, which could be that the backshore deposit in the early stage was transformed by the waves in the process of retrogradation during the sedimentary process of a transgression sequence in the Donghe sandstone. Therefore, the characteristics of the backshore are not obvious. Perhaps the backshore nearing the bank position is higher and is subject to denudation or is sedimentary discontinuity. The coastal sand dam of Hade-4 oilfield mainly is a nearshore–foreshore deposit. The transition zone mainly developed in the area south of Hade-4 oilfield is the same layer but different facies deposit with the Donghe sandstone (Fig. 20.5).

water retreated transition to the foreshore, backshore. Individual wells also retained coastal sand dune deposits at the top.

20.3.2.3 Vertical and Horizontal Characteristics of the Sedimentary Facies and Sedimentary Models Vertically the three lithologic members are the coastal, restricted platform, and tidal flat facies from the Donghe sandstone member to the breccia member to the middle mudstone member (Fig. 20.4), reflecting the evolution of the open sea to the sea–land transition zone. A large-scale transgression that occurred in the Carboniferous after prolonged exposure and denudation of the Silurian–Devonian in the Manxi area. The Donghe sandstone member represents the early deposition of the marine transgression. Controlled by paleogeomorphy, the Donghe sandstone is characterized by the filling and leveling. The seawater invades the Hadexun tectonic belt with the characteristics of the low southern part and high northern part from the southwest and forms the coastal environment, in which the northeast is the land, the southwest is the sea. When the sea level continued to rise, the shore sandbody was overlain in the northeast direction and the Donghe sandstone formed. Based on the lithofacies and well logging facies characteristics, the Donghe sandstone member can be divided into three subfacies in the Mangar Sag, that is, the shore sand dam, transition zone, and offshore zone, which can be further subdivided into five microfacies. The shore sand dam subfacies mainly developed in Hade-4 oilfield, mainly comprising fine quartz sandstone and developing resembles massive, parallel, and low-angle inclined bedding. The logging curve is box-shape, low in gamma, negative abnormal in spontaneous potential, and low value and high amplitude difference of double induction resistivity curve. The shore sand dam includes the backshore and foreshore Manxi1

Hade5

Hade4 Hade1 Hade2

20.3.3 Characteristics of the Sandstone Reservoirs 20.3.3.1 Characteristics of the Reservoir Petrology (1) Thin sand layer Lithology characteristics: The sandstone layer lithology of the middle mudstone member comprises gray, gray-brown fine-crystalline sandstone. The rock type is mainly fine feldspar sandstone, with a small amount of feldspar stone and feldspar quartz sandstone. The quartz content is low (50–75%) and the feldspar content is 17–32%. The cuttings content is 10–20%, with an average of 15.6%, mainly comprising magmatic and metamorphic rock cuttings and relatively few sedimentary rock cuttings. Interstitial material characteristics: The average content of interstitial material, including miscellaneous material and cementation, is 10.5%. The content of the matrix is low and the cementation mainly contains calcite and small amounts of dolomite, iron calcite, and iron dolomite. The total content

Yangwu1

Tid

Flat Tidal

al

Fla

t

Tahe1

Lunnan46

Lunnan16

Evaporation Lagoon Center (Salt rock)

Sand Sheet

Fan Delta Restricted Platform Subfacie (Briccia Section)

Coast Facie (Donghe Sandstone Member)

S O2+3

Fig. 20.4 Schematic pattern of Carboniferous sedimentary facies in the Tuha 4 oilfield, Tarim Basin

O1

478

20

Hadexun Oilfield

Coastal Sand Dune Offshore Shelf Mud

Backshore

Foreshore

Shoreface

Transition Zone

Mean High Water Mean Low Water

Wave Base

Coastal Coastal Coastal Sand Dune Sand Dune Sand Dune Sand Beach Beach Ridge Trough

Backshore Shallow Trough Foreshore Groove

Shoreface Groove

Shoreface Beach

Foreshore Dam

Backshore Dam

Backshore Beach

Foreshore Beach

Shoreface Dam

Fig. 20.5 Model of the non-barrier bank sedimentary microfacies in the Donghe sandstone reservoir of the Hadexun oilfield, Tarim Basin

of dolomite, iron calcite, and iron dolomite is *2–3%. Calcite is very unevenly distributed and locally enriched, with content ranging from 0 to 32%. The matrix content is 1–4% and the composition is mainly mud. Rock structure characteristics: Based on thin sections observations, the content of fine–middle sandstone is 84– 96%. The silt component in siltstone accounts for 95%. The particle sorting is good, subangular to subround. The sandstone is characterized by low component maturity and high structure maturity. The cementation types include porous matrix, point-to-line contact, and dense cementation. (2) Donghe sandstone Lithology characteristics: The rock type is mainly rock lithic quartz sandstone, with a small amount of feldspathic lithic sandstone. It has high component and structure maturities. The Donghe sandstone has high component maturity, the quartz and feldspar content is generally 69–90% and 6–14%, respectively. The rock cuttings content is 5–26%, mainly comprising sedimentary and metamorphic rock cuttings and a small amount of magmatic rock cuttings. Interstitial material characteristics: The interstitial material content is low, with an average of 9.7%. The cement mainly contains calcite and small amounts of dolomite iron calcite and iron dolomite. The calcite distribution is very uneven. The calcite content is 0–30%. The matrix content of 2–5% is only the same and the composition is mainly mud.

Rock structure characteristics: The core observations and thin sections data show that the Donghe sandstone granules are well divided, the degree of roundness is medium to good, subround to subangular; the structure maturity is higher. The clay content is very low and the cement mainly comprises calcium and silica. The cementation type is mainly pore type cementation, ranging from loose to dense distribution. The difference is very large and the distribution is complex. The support type of the clastic structure is particle support; the particles are mainly point and line contact particles.

20.3.3.2 Reservoir Space Types and Characteristics The thin sand layer in the Hade-4 oilfield is dominated by interparticle dissolution pores, followed by primary pores. A small amount of intragranular dissolution pore and a small amount of the micropores can be found in the muddy miscellaneous material, with better connectivity (Fig. 20.6). In the Donghe sandstone member of the Hade-4 oilfield, the reservoir pores are mainly primary pores, followed by interparticle dissolution pores, few intraparticle dissolution pores and micropores. Microfractures formed by tectonic activity and diagenesis can also be observed. There has been controversy about the pore types of the Donghe sandstone. Currently, most of the researchers suggest the dominance of primary pores. Based on the analysis of casting thin sections of some wells before 2001, the Donghe sandstone was has a high intragranular dissolution pore content of 90%.

20.3

Reservoir Geologic Characteristics

479

Fig. 20.6 Casting thin sections of the sandstone reservoir in the Hadexun oilfield, Tarim Basin

Nowadays, a considerable proportion of primary pores is considered, which are modified by dissolution, representing the main reservoir space (Fig. 20.7).

20.3.3.3 Reservoir Properties (1) Thin sand layer Based on the analysis of the properties of the core samples from the thin sand layer of the Hadexun oilfield, the reservoir porosity and permeability in the middle mudstone member are relatively concentrated. The histogram shows a normal distribution. The maximum, minimum, and mean porosity is 20.4%, 3.94%, and 12.24%, respectively. The porosity distribution peak ranges from 12 to 16%. The permeability mainly varies from 10 to 100  10−3 µm2. The highest, lowest, and the average value is 449  10−3 µm2, 0.2  10−3 µm2, and 62.5  10−3 µm2, respectively. The permeability is at 10–100  10−3 µm2 of the sample number of samples accounts for 53.51% of the total samples, to medium pore, middle permeability reservoir mainly.

(2) Donghe sandstone The properties analysis of the cores shows that the porosity of the Donghe sandstone mainly ranges from 12.5 to 20%, with an average of 13.8%. The permeability varies from 50 to 1000  10−3 µm, with an average of 222  10−3 µm and a maximum permeability of 10  10−3 µm, mainly representing middle and high permeability.

20.3.3.4 Reservoir Diagenesis and Main Controlling Factors The main diagenesis associated with the reservoir includes compaction, pressure dissolution, cementation, and dissolution in the Hadexun oilfield. The dissolution plays an important role in constructive diagenesis in the reservoir. The diagenetic sequence and pore evolution characteristics of the reservoir are as follows: Hercynian: The reservoir is in the syndiagenetic stage and early diagenetic A-phase in the study area. At this stage, the matrix fills the intergranular pores and forms a clay ring edge

480

20

Hadexun Oilfield

Fig. 20.7 Casting thin sections of the Donghe sandstone reservoir in the Hadexun oilfield, Tarim Basin

on the outer edge of the particles. Micritic calcite and the early quartz enlargement edge also develop, causing the primary porosity to decrease 3–8%. The compaction effect causes the porosity to decrease 8–12%. The late Hercynian tectonic uplift causes stratum denudation, which is affected by the atmospheric freshwater. The micritic carbonate cementation and several particles are dissolved to produce secondary pores. The early diagenetic B-phase, poecilitic and intergrowth calcite cementation, and secondary feldspar enlargement lead to a significant reduction of the primary porosity to about 10–15% and inhibit the further strengthening of the mechanical compaction. Late diagenetic Phase A: With the increase in the burial depth, organic matter begins to mature and organic acids are formed in the strata, resulting in the dissolution of many clastic particles and the calcite cementation. However, the dissolution is uneven; porosity increases about 5–10%. Subsequently, the dissolution gradually weakens and iron calcite and pyrite are precipitated. Thus, porosity decreases to the current porosity of about 4–25% (Fig. 20.8).

20.3.4 Characteristics of the Trap (Structure) 20.3.4.1 Tectonic Evolution History During the early Caledonian Movement, the Tabei area began to develop an uplift zone. From the Cambrian–Early Ordovician, the extremely thick carbonate platform was deposited. During the Middle Caledonian Movement, with the closure of the Kuche-Manjiaer aulacogen, the unified northern uplift of the Tabei formed and a large southward slope formed in the Lunnan–Yingmaili region. This period was influenced by tectonic activity and the development of the Hadexun region from west to east along the Cambrian gypsum salt rock of the detachment and thrust structure. The formation of the Hadexun nose uplift started. The Hadexun area is located on the southern edge of the denudation zone of the Tabei Uplift before the Santamu Formation was deposited. The thin-layer energy beach deposits at the bottom of the Lianglitage Formation remain in most areas. However, when the exposure time was short, it settled rapidly forming the thick deposits of the Santamu Formation and the Tireke Avati Formation.

20.3

Reservoir Geologic Characteristics Diagenetic Stage

481

Early Diagenetic Stage

Late Diagenetic Stage

Syndiagenetic Stage A

Diagenetic Evolution

B

A1

Temperature (°C)

65

85

Ro(%)

0.35

0.5

Compaction and Pressolution

A2 110 0.7

Mechanical Compaction

Pressolution Clay film

Cementation and Metasomatism

Quartz increase Feldspar increase Spontaneous Kaolinite Calcite cementation Iron-containing Calcite Dolomite Zeolite Pyrite Recrystal Clay -lization Recrystallization Clay Mineral Conversion

Denudation

Illite increase Chlorite increase Component dissolution Secondary pore

Hydrocarbon entry

40 History of pore evolution

30 20 10

Fig. 20.8 Formation and pore evolution history of the reservoir diagenesis in the Tarim Basin

During the late Caledonian movement (Silurian–Devonian), the Luntai Uplift formed in the northern part of the northern uplift of the Tazhong region due to the activity of the Luntai fault and the continuous Lunnan low uplift led to the formation of the Lunnan buried hill. The Hadexun region was affected by north-south extrusion stress. A left-lateral strike-slip fault developed in the north–south direction, the early thrust fracture was reconstructed, and the latent Hadexun paleo-uplift started to form. In this period, the Silurian system was eroded from the south to the north and the Carboniferous was deposited directly over the system from west to east and from south to north.

During the Hercynian–Indosinian movement (late Carboniferous–Triassic), the middle Tianshan paleo-island arc collided with the Tarim Plate from east to west, the southern Tianshan Ocean closed, and a thrust nappe structure in the north of the Tabei area, and a giant left-lateral strike-slip fault tectonic deformation belt with the Xinhe, Erbatai, Yingmaili, Lunnan, and Kuala–Kongquehe slopes as the main body developed. The low-uplift of the Yingmaili was affected by the strong uplift of the intrusive basement rock, resulting in the erosion of the Carboniferous in the northern part from the south to the northwest. South of the Tabei Uplift, a three-convex structure formed from west to east,

482

20

that is, the Yingmaili low uplift, Lunnan low uplift, and Kuala nose-like uplift. The Hadexun region was affected by regional compression after Triassic deposition, forming many low-relief folds and a low-relief Silurian anticline band. Since the Neogene, the northern part of the Tabei gradually became the leading uplift and foreland slope of the Kuche foreland basin due to the intense subsidence of the Kuche depression. The upper Paleozoic and Mesozoic strata at the southern margin have been tilted and showed a large regional northward-trending single oblique with the Cenozoic. However, the Lower Paleozoic still showed a regional southward inclination with a smaller dip. The low-relief structural traps strengthened in the Silurian, and the present tectonic pattern of the Hadexun region formed.

20.3.4.2 Trap Characteristics The Hadexun tectonic belt comprises two traps, that is, the Hade-1 and Hade-4 traps. The Hadexun oilfield mainly comprises two reservoirs, that is, from top to bottom, the thin sand layer and Donghe sandstone reservoir in the Carboniferous Middle mudstone member. The former is mainly distributed in the Hade-1 trap; the latter is distributed in both traps. The structural morphology of the top surface of the second thin sand layer is a nose structure that is inclined to the north and west in the Carboniferous middle part of the Hadexun oilfield. The Hade-1 anticline trap is in the shaft of the nose structure and the Hade-4 anticline trap is at the southwestern flank. Hade-1 is a NW–SE anticline trap, with an aspect ratio of about 2:1, a −4070 m closed line, maximum elevation of −4044 m, trap amplitude of 26 m, and a total area of 97.9 km2. The trap is relatively slow at the southeastern flank. The northwestern flank is steeper. The trap has five local highs and is a small dome-like low-relief anticline. The Hade-4 trap closed as NE–SE anticline trap. The northern and southern flanks are relatively slow. The east–west flank is steeper, with a −4066 m closed line, maximum elevation of −4056 m, trap amplitude of 10 m, and trap area of 11.9 km2.

20.4

Hadexun Oilfield

Reservoir Characteristics

20.4.1 Fluid Properties The thin sand layer oil reservoir is characterized by a medium density, medium viscosity and contains low-sulfur and medium-waxy, medium-colloid bitumen. The crude oil of the Donghe sandstone reservoir has a medium–high viscosity and low freezing point and is sulfur-containing waxy medium oil (Table 20.3). The natural gas is characterized by typical moisture in the Donghe sandstone and thin sand layer reservoirs, which is dissolved gas separated from the reservoir. Its physical properties are shown in Table 20.4. The total salinity of the formation water in a thin sand layer reservoir ranges from 22.6–13.8  104 mg/L, Cl:13.8  104 mg/l, the density is 1.15 g/cm3, and the water is of CaCl2 type. These properties are similar to the physical properties of the formation water in the Donghe sandstone reservoir (Table 20.5).

20.4.2 Reservoir Types The thin sand layer lithologic reservoir is a multilayered bottom water reservoir with a wide oil–water transition zone in the Hadexun oilfield. The distribution of oil and water is affected by the dual control of structure and reservoir. The wells of thin sandy layer reservoir on structural high around HD1 does not drilled the oil/water contact, while the wells at low position drills at dry or water layer. The second sand layer OWC is −4070 m, the third sand layer OWC is −4074 m, and the fourth and fifth sandstone layers are lithologic reservoirs without a constant OWC (Fig. 20.9). The Donghe sandstone reservoir is a structural and lithological recombination trap that is controlled by the strata, tectonics, and fluid factors in the Hadexun oilfield. The oil-bearing range in the low-relief anticline is controlled by the East River sandstone tip-off line and inclined OWC. The upper part is an oil zone, the lower part is an oil–water

Table 20.3 Physical properties of the Carboniferous oil and gas reservoirs in the Hadexun oilfield, Tarim Basin Density (g/cm3)

Viscosity (mPa
s)

Freezing point (°C)

Wax content (%)

Asphaltene and Resin (%)

Sulfur content (%)

Thin sandstone layer

0.8654– 0.8839

7.64–11.75

−39.2–2

2.34–8.54

6.95–15.7

0.1–0.95

Donghe sandstone

0.9039– 0.9373

13.98–14.21

−30 to −18

2.35–8.97

18.02–20.62

0.47–0.71

Strata System

Formation (Member)

Carboniferous

20.4

Reservoir Characteristics

Table 20.4 Physical properties of the Carboniferous hydrocarbon reservoirs in the Hadexun oilfield, Tarim Basin

Table 20.5 Physical properties of the formation water the Carboniferous reservoirs in the Hadexun oilfield, Tarim Basin

483 Strata

HD2

Hydrocarbons CH4

Non-hydrocarbons

System

Formation (Member)

Carboniferous

Thin sandstone layer

0.82–1.2

17.64– 53.68

Donghe sandstone

1.02– 1.23

15.46– 53.58

System

Formation (Member)

Density (g/cm3)

Chlorine ions (mg/L)

Total salinity (mg/L)

Water type

Carboniferous

Thin sandstone layer

1.15

13.8  104

22.6  104

CaCl2

Donghe sandstone Hadexun-1 Area

1.18

4

16.8  10

27.2  104

CaCl2

Donghe sandstone Hadexun-4 Area

1.16

14.3  104

23.2  104

CaCl2

Strata

0 HD4-50H

Component content (%)

Relative density (g/cm3)

HD1-22H

HD1-15H

HD1

1 HD1-5H

C2H6

10.87– 26.6

C3H8 and heavier

9.42– 21.37

H2S

0– 2.7

2 km HD4-71 HD4-2H

CO2

Others

0.21– 16.13

12.74– 56.93

0.21– 16.13

17.48– 46.46

S HD4-3H

HD1-8H

HD4-28H

HD1-30H

HD1-13H

-4 040

-4 040

-4 050

-4 050

-4 060

-4 060

-4 070

-4 070

-4 080

-4 080

Legend -4 090

-4 090 Oil layer Pooroil layer Oil-water Layer Dry layer Water layer

Fig. 20.9 Reservoir section of the HD4-50 h–HD1-13 h wells in the thin sand layer reservoir of the Hadexun oilfield in the Tarim Basin

transition zone. The reservoir type is a composite reservoir with an inclined OWC controlled by the structure (Fig. 20.10). The OWC gradually decreases from southeast to north. The inclined OWC of the HD 405 well at the southeastern end is −4,107.51 m and that of the HD 113 well at the northwestern end is −4,185.37 m. The OWC tilt range reaches up to 77.86 m.

20.4.3 Accumulation Period and Main Controlling Factors Based on the petroleum geology conditions of the Hadexun area and the data in Figs. 20.9 and 20.10, the reservoir formation process in the Hadexun oilfield is as follows:

① In the late Hercynian, oil and gas from Middle and Upper Ordovician source rocks entered the Ordovician karst fractures-cavities and the Silurian sandstone reservoir along the Ordovician carbonate karst transportation layer or fractures. The reservoirs were not formed in the Carboniferous Period because the overburden layer on the Donghe sandstone and Carboniferous thin sand layer were thin and traps did not exist. The K-Ar age of autogenic illite in the reservoirs indicates the entry of oil and gas in the late Hercynian period in the Hadexun area. However, because of the shallow burial of the Donghe sandstone at this time, the oil and gas generally did not reach depths of more than 1000 m. The diagenesis in the syngenesis—epidiagenetic stage was weak. Therefore, there is hardly any direct evidence (inclusion) for the entering or passage of oil and gas; ② Before the Triassic

484

20 0 HD11-8H

HD4-53

HD1-3H

1 HD1

2 km

-4 080

5 030

5 030

5 030

5 030

5 040

5 040

5 040

5 040

5 050

5 050

5 050

5 050

5 050

5 060

5 060

5 060

5 060

5 060

-4 110

5 070

5 070

-4 130

5 080

5 080

-4 140

5 090

5 090

-4 120

-4 170 -4 180

HD1-9H

HD4-38H

HD1-14H -4 080

5 030 5 030

5 040

5 040

5 050

5 5

section Breccia2 3 4 050 5 6 7 8 060 9 10 11

5 070

5 060 Original Oil/Water Contact

5 070 5 080

5 040

5 040

-4 090

5 050

5 050

-4 100

5 060

5 060

-4 110

5 070

5 070

-4 120

5 080

5 080

-4 130

5 090

5 090

-4 140

5 100

-4 150 -4 160

5 070

SE

HD4-71 HD4-87

-4 090 -4 100

Hadexun Oilfield

Bre

tion sec ccia 4 5 6 7 8 9 10

-4 150

5 110 5 120

Legend

5 130

Oil layer Water layer Inter layer

-4 160 -4 170 -4 180

Fig. 20.10 Reservoir section of the HD11-8 k–HD1-14 h wells of the Donghe sandstone reservoir in the Hadexun oilfield, Tarim Basin

Period, the structure was uplifted, the Permian cap rock was eroded, asphalt sandstone formed in the Silurian, and Ordovician crude oil was degraded and destructed to a certain degree; ③ Since the Kangcun period, the Carboniferous stratum has reversed due to the continuously settling in the Kuqa Depression, and formed a pattern of high in the south and low in the north, and a nasal trap. Oil and gas in Ordovician reservoirs migrated from north to south through unconformity, faults, and sandstone transport layers, forming Carboniferous secondary reservoirs in the Hadexun area. Based on the study of the inclusions in the oil and dry layers (Zhao and Tian 2002; Mi et al. 2008), the crude oil composition, characteristics of the biomarker, and carbon isotopes of the crude oil, the hydrocarbon accumulation period in the Hadexun region is the late Himalayan period. The uniform temperature of the inclusions in the layer reflects the temperature of the reservoir at the time at which the crude oil entered the tertiary period; ④ Today, the “lower in south and higher in north” pattern of the Carboniferous strata is more pronounced and the Hadexun reservoir is still migrating southward. Oil and gas are still in the process of unsteady adjustment, leading to the characteristic tilted OWC. Based on the comprehensive study of the tectonic, diagenetic, and reservoir evolution and sedimentary reservoirs in the Hadexun region, the main factors controlling the formation of the Carboniferous reservoir in the Hadexun area are as follows:

20.4.3.1 Ultra-late tectonic movement The Tarim Basin belongs to the basin–mountain system around the Qinghai–Xizang Plateau, and its Cenozoic evolution mainly originates from the long-distance effect of the collision between the Indian and Eurasian Plates, which was controlled by the uplift and northward pushing of the Qinghai–Xizang Plateau (Li et al. 2007; Jia et al. 2008; Jia 2009). Previous studies showed that the uplift and northward pushing of the Qinghai– Xizang Plateau occurred in multiple stages and unequal and

nonuniform evolution processes. The intense uplift started in the Upper Miocene (since about 5.3 Ma) and continues to this day, which caused the intense subsidence in the periphery of the Tarim Basin. The unbalanced sedimentation led to the tilting of the traps and migration of the oil and gas in the foreland slope area and paleo-uplift area, and the change in the fluid potential and the re-adjustment of oil and gas in the ancient reservoirs. Moreover, the reservoirs are still being adjusted because of the tectonic movement that continues to this day, tilting and migrating of traps. Therefore, the advanced tectonic movement that started in the Pliocene and is continuing to this day is the primary factor affecting the formation of the Hadexun unsteady oil and gas reservoirs.

20.4.3.2 Heterogeneity of the reservoir The Donghe sandstone is an important oil-bearing system and an important layer for the development of non-steady-state oil and gas reservoirs in the Tarim Basin, which is widely developed in the whole basin and includes five stage sandbodies. The sedimentary environment mainly includes the littoral facies and estuarine facies environment. The sedimentary facies distribution and diagenesis are beneficial to the development of mud and calcite interlayers in the Donghe sandstone reservoir. The reservoir physical properties differ in the vertical direction due to the change of the facies, leading to a heterogeneous reservoir. The heterogeneity of the reservoir has an important influence on the hydrocarbon accumulation. Within the scope of the micro, the dynamic change of the oil and gas migration is small. Its migration path of oil and gas in the heterogeneity of conducting layer under the control of the migration resistance distribution, preferred by migration resistance the smaller part of the conducting layer (channels), led to the same high hole high permeability reservoir in the oil and gas layer tend to have higher oil saturation, and low hole part of low permeability oil saturation is low or even no oil. In the micro scope,

20.4

Reservoir Characteristics

485

the dynamic change of oil and gas migration is small. The migration path of oil and gas in heterogeneous transport layer is controlled by the distribution of migration resistance. Oil and gas preferentially pass through the migration layer (dominant channel) with small migration resistance, which leads to high oil saturation in high porosity and permeability reservoirs, while low porosity and low permeability reservoirs have low oil saturation or even no oil. The rhythm in the layer is an important factor affecting the hydrocarbon accumulation, that is, the bottom of the positive rhythm reservoir is favorable for hydrocarbon accumulation and high oil saturation. The high oil saturation at the top of the counter-rhythmic reservoir and the particle size difference are the main factors causing the influence degree to be different. The reservoir interlayer plays an important role in hydrocarbon accumulation. On the one hand, it will prevent oil and gas from continuing to move to the top of the reservoir when the interlayer does not form an effective sealing, which is unfavorable to hydrocarbon accumulation or may cause the formation of large unsaturated oil (gas) water in the reservoir longitudinal layer. On the other hand, oil and gas may accumulate and form small reservoirs when the interlayer forms effective traps. The influence of the interlayer heterogeneity on the hydrocarbon accumulation is mainly manifested as “interlayer interference” (Yu and Lin 2007).

drilling results of HD 4 well, the Donghe sandstone reservoir was found and the pinchout line of Donghe sandstone was identified, and the range of Donghe sandstone reservoir was preliminarily determined. In 2000, according to classical reservoir theory, the oil-bearing area of Hade-4 traps was determined. During the development and construction period of Hadexun oilfield, with the increase of drilling data, it was found that the oil–water contact height of Hade-4 trap and Hade 1-2 trap was not consistent. Based on the understanding of the oil–water contact level of the reservoir, it puts forward the understanding that Hade-4 reservoir and Hade 1-2 reservoir are independent of each other. The fine structure interpretation and the drilling of HD 405 well enlarged the Hade 1-2 structural traps, and the oil-bearing area of the two traps was determined in 2001. On the premise of further understanding the geological characteristics of Hade-4 oilfield, the 80  104 t capacity expansion and development plan for the whole oilfield was compiled and implemented in May 2001. 45 wells are deployed as a whole, with a design capacity of 80  104 t. Priority was given to the implementation of wells aiming at the thin sand layer reservoir and the Donghe sandstone reservoir was evaluated progressively. At the end of 2002, the total proved reserves were 4,869  104 t, and the production capacity of 85  104 t was built. The crude oil yielding in that year was 81.6  104 t.

20.5

20.5.1.2 Theoretical Innovation of the “Unsteady Dynamic Accumulation” Has Promoted the Continuous Expansion of Progressive Exploration and Development in Hadexun Oilfield At the end of 2002, the HD 11 well in the north of Hade-4 oilfield was drilled in the Carboniferous and encountered Donghe sandstone and obtained low production oil flow. In the practice of progressive exploration and development, it is gradually realized that the oil–water contact of Donghe sandstone reservoir in Hadexun oilfield is inclined to the northwest. The concept of “post-reservoir” and the theory of “unsteady state dynamic accumulation” was creatively proposed (Sun et al. 2008, 2009). It is believed that with the tectonic high point of Hadexun Donghe sandstone migrating southward, oil and gas also migrated southward under the action of buoyancy. It is predicted that the Donghe sandstone reservoir in Hadexun oilfield will continue to expand to the northwest. And successively deployed and implemented appraisal wells such as HD 111, HD 4-44, HD 112, HD 113, and HD 404 (Yan et al. 2008). According to the evaluation results, the structural form and oil-bearing range of the Carboniferous Donghe sandstone reservoir are reconfirmed, and it is clear that the Carboniferous Donghe sandstone reservoir in Hadexun oilfield is a reorganized reservoir with tilted oil–water contact (Fig. 20.11).

Enlightenment of the Exploration and Development

20.5.1 Progressive Exploration and Development Is the Guarantee for the Successful Exploration and Development of Ultra-Deep and Complex Reservoirs 20.5.1.1 The Hadexun Oilfield Was Discovered Based on Traditional Petroleum Geological Theory, and Innovative Progressive Exploration and Development Helped to Increase the Reserve and Production As an ultra-deep and complex gas reservoir, the success of the exploration and development of Hadexun oilfield can be attributed to the integrated strategy of progressive exploration and development at the very beginning of discovery. At the beginning of 1998, after the discovery of thin sand reservoirs in the middle mudstone member of the Carboniferous in the HD 1 and HD 2 wells, the development immediately involved in the formulation of reservoir evaluation and deployment plans and progressive development plans. The first development well, HD 1-2 well, was drilled in the reservoir of Donghe sandstone. Combined with the

486

20 400

-4

-4 42 5

-4 400

-4 375

-4 375 -4 350 -4 325

-4 300

300

-4 275 HD17

-4

-4 250

-4 275 -4 2

-4

325

5

-4 400 HD21

-4 35 0

-4 47

-4 45 0

-4 350 -4 325

HD173

Hadexun Oilfield

-4 250

-4

275

25

-4

250

-4

225

-4 225

20

0

YW2

0

17

HD13

-4

-4

-4 20

HD117

5

200

-4

0 30

HD171

-4 175

-4

15

0

-4

HD113

5

-4

HD11

27

HD119

HD2-1H HD111

-4 150 HD2-12

HD172

-4

25

0

25

2

-4

200

-4

HD112

5

-4

HD2

-4 1

-4

HD10

HD115

25 17

5

HD4-44H

HD4-24H HD1 HD4-20H

HD4-66H

0 15 -4

-4 2

HD1-2

HD4-21H

HD4-3

-4

HD4-26H HD4-10

HD4-12H

75 -4 1

HD1-9H

HD402 HD4-33

25

HD3

-4 1

0

10

HD4-13H

HD404 HD4-8H

HD121

HD4-49

HD4-30H HD4-46H

HD120 HD10-1

HD1-22H

HD4-23H

00

HD2-6

12

HD1-27H

5

HD4 HD4-29H HD4-39H HD4-9H HD4-19H

HD405

-4 125

-4

12

HD4-48H HD408

YW3

0

2

HD401

4 km

-4 125

-4 1

50

HD403

HD8

D

HD4 Well Location Oil-bearing Area Oil-bearing Area New Oil-bearing in 2003 Area in 2005 and well Name in 2002

Donghe Donghe Donghe Sandstone Sandstone Sandstone Physical Tight Zone Pinchout Line Pinchout Line in 2002 in 2002 from 2000 to 2001

Donghe Sandstone Pinchout Line in 2003

Fig. 20.11 Changes in the oil-bearing area of Donghe sandstone reservoir in the Hadexun oilfield, Tarim Basin

Donghe Sandstone Pinchout Line in 2005

Mining Right Line

20.5

Enlightenment of the Exploration and Development

On the other hand, according to the understanding of the buoyancy and capillary resistance of the ancient oil reservoir, it was concluded that the velocity of the oil and gas migration in the reservoir with good physical properties is greater than that in reservoirs with poor physical properties. Therefore, the reservoirs with poor physical properties had a higher oil saturation than the reservoir with better physical properties during ancient reservoir migration. Based on these results, HA 17 well and HA 171 well were successfully deployed in the vicinity of the Hadexun oilfield in the Donghe sandstone at the top of the low permeability of the target layer from 2003 to 2004 and the oil-bearing area was further expanded (Fig. 20.11). In 2004, the controlled reserves increased by 17.56 million tons, plus the thin sand reservoir reserves in the middle mudstone member of the Carboniferous. So far, the proved and controlled petroleum geological reserves of Hadexun oilfield exceeded 100 million tons, making it the first 100-million-ton marine sandstone oilfield in Tarim Basin and even in China. Under the guidance of the unsteady state theory, the reserves of Hadexun oilfield increased by 4,072  104t and the production capacity increased by 1.2 million tons, ensuring the continuous high and stable production of Hadexun oilfield.

20.5.2 Deep and Thin Marine Clastic Rock Reservoir Has Been Developed Efficiently by Horizontal Well Technology Hadexun oilfield is a heterogeneous multi-reservoir oilfield, and its development objects are thin sand reservoir in the Carboniferous middle mudstone member and Donghe sandstone reservoir. According to the theory and experience in the division of oilfield development strata at home and abroad, this oilfield is divided into two development strata and two independent well patterns. ① Double-step horizontal well water injection development technology has realized high-yield and high-efficiency development of the marginal reservoir. In view of the layered bottom water reservoir controlled by lithology and structure in Hadexun oilfield, a set of double-step horizontal well water injection development technology has been developed after years of exploration, and the reservoir has achieved the high and stable yield target of 30  104 t for 3 consecutive years and the efficient development of 22  104 t for 8 consecutive years. ② Horizontal well development is adopted to achieve high-yield and high-efficiency in complex reservoirs with tilted oil–water contact. The Donghe sandstone reservoir has the following characteristics: thin reservoir thickness (0.6– 29 m, average 5.7 m), buried deep (>5000 m), low structure amplitude (the structure trap amplitude is less than 34 m), large oil-bearing area (154.4 km2), tilted oil–water contact

487

(phase difference of 90 m), low reserves abundance (50  104 t/km2), high porosity and high permeability reservoir, and it is a concealed reservoir controlled by the structure, formation, and tilted oil–water contact. In view of the above practical conditions, the overall adopts horizontal well development, irregular thin pattern staggered deployment, spacing of 750–1000 m. The pure oil area is developed by water injection, and the bottom water area is developed by natural energy. A total of 73 development wells have been deployed in the Donghe sandstone reservoir program, with the completed production capacity of 140  104 t and the realization of high-yield and high-efficient development over 10 years of stable yield of 100  104 t. Based on the progressive exploration and development and the deployment of horizontal and double-step horizontal wells in the Hadexun oilfield, the highest annual output of 224  104 t was reached. Hadexun oilfield has a stable production of 150  104 t for 9 years, and has accumulated oil production of 2360.8219  104 t until now. A recovery rate of 38% was predicted and high and stable production and efficient development were achieved in the Hadexun oilfield. Hadexun oilfield is China’s first 100-million-ton marine sandstone oilfield; it is also a progressively developed model oilfield mainly developed by horizontal wells and double-step horizontal wells.

References Gao Y, Zhao X, Zhang W et al (2003) Sequence stratigraphic characteristics and non-structural trap exploration in Tarim Basin. Petroleum Industry Press, Beijing Guo JH, Zeng YF, Zhai YH et al (1996) On the carboniferous sequence stratigraphy in the Tazhong Area, Xingjiang-a model of the sequence stratigraphy framework of intracratonic depressional basins. Acta Geol Sin 70(04):361–373 Jia C (2009) The structures of basin and range system around the tibetan plateau and the distribution of oil and gas in the Tarim Basin. Geotectonica et Metallogenia 33(1):1–9 Jia C, Yang S, Wei G et al (2008) Structure characteristics and petroleum-bearing prospects of cenozoic circum-tibet plateau basin and range system in China. Nat Gas Ind 28(8):1–11 Li B, Jia C, Pang X et al (2007) The spatial distribution of the foreland thrust tectonic deformation in the circum-tibetan plateau basin and range system. Acta Geol Sin 81(9):1200–1207 Li G, Xu H, Liu X et al (2008) Microfacies characteristics of donghe and their control on flow units in Hudson Area. Pet Geol Recovery Effic 15(05):34–37+113 Mi J, Zhang S, Chen J et al (2008) Carbon isotope characteristics and the influencing factors of the oils from Lunnan and Hadexun oi1 fields. Acta Sedimentol Sin 26(6):1071–1076 Sun L, Jiang T, Hanlin X et al (2008) Exploration and practice for theory of unsteady-state hydrocarbon accumulation. Marine Origin Pet Geol 13(03):11–16 Sun L, Jiang T, Hanlin X et al (2009) Unsteady reservoir in Hadson oilfield, Tarim Basin. Pet Explor Dev 36(01):62–67

488 Wang Z, Tian J, Shen Y et al (2004) Sedimentary facies of Donghe Sandstone during the late Devonian to early carboniferous in Tarim Basin. J Palaeogeogr 6(3):289–296 Wu Y, Sun L, Gu J et al (2008) Sedimentary sequence analysis and reservoir evaluation of the Donghe Sandstone of Carboniferous in Manxi area of Tarim Basin. J Palaeogeogr 10(1):13–24 Yan C, Shang E, Zheng X et al (2008) Integration to boost the storage and production of Hade 4 oilfield-investigation on the storage and production of Hade 4 oilfield (Part 1). China Petrochem 9(06):66– 67

20

Hadexun Oilfield

Yu C, Lin C (2007) Advancement of reservoir heterogeneity research. Pet Geol Recovery Effic 14(04):15–18+22 Zhao J, Tian J (2002) Geochronology of petroleum accumulation of Hade 4 oilfield, Tarim Basin. Acta Petrologica Et Mineralogica 21 (1):62–68 Zhou X, Yang H, Cai Z et al (2007) Cases of discovery and exploration of marine fields in China (Part 10): Hadexun sandstone oilfield in Tarim Basin. Marine Origin Pet Geol 12(04):51–60 Zhu X (2003) Sequence stratigraphy. China University of Petroleum Press, Dongying

21

Bohai Bay Basin

21.1

Progress of the Petroleum Exploration in the Bohai Bay Basin

21.1.1 Geographical Location and Regional Geological Conditions The Bohai Bay Basin is in the eastern part of mainland China, between 114°–124° eastern longitude and 35°–42° northern latitude. It includes five provinces and cities including Beijing, Tianjin, Hebei, Liaoning, and Shandong, as well as the Bohai Sea, that is, a total area of *17
104 km2. The Bohai Bay Basin is rich in oil and gas resources. Based on the results of resource evaluation, the oil and natural gas resources in the Bohai Bay Basin are 325
108 t and 2.16
1012 m3, respectively. After 60 years of exploration and development, ten sets of hydrocarbon-bearing strata have been discovered in the Archaeozoic, Proterozoic, Paleozoic, Mesozoic, and Cenozoic. By 2013, the proven reserves of oil and natural gas were 140
108 t and 3500
108 m3, respectively. The Bohai Bay Basin is also the largest oil-producing basin in China. Since 1986, the crude oil production has reached 6000
104 t/a for 30 consecutive years. In 2014, the crude oil production was 7521
104 t. The various types of oil and gas resources discovered in the Bohai Bay Basin are widely distributed. The discovered oil and gas are mainly concentrated in Mesozoic and Cenozoic continental sediments. Large oil and gas fields have also been found in the basement of the Paleozoic– Proterozoic marine stratigraphic system, forming a multilayer oil pattern in the longitudinal direction. Based on the statistics, most oil and gas resources were discovered in the Cenozoic in the Bohai Bay Basin, accounting for 80.2% of the total proven reserves. The Proterozoic marine oil-bearing strata account for 12.3% of the total proven reserves. Recently, great progress has been made in the oil and gas exploration of marine sequences in the Bohai Bay Basin and remarkable achievements have been made in the exploration

of subtle buried hills in the Paleozoic and Proterozoic. Large and medium-sized oil and gas reservoirs represented by the Niudong and Qianmiqiao buried hills have been discovered. The 5641.5–6027 m section of the Proterozoic Wumishan Formation was tested in well Niudong 1, indicating a daily crude oil and natural gas production of 642.9 m3 and 56.3
104 m3, respectively (Zhao et al. 2011a), which confirmed that the ultra-deep marine carbonate reservoir in the Bohai Bay Basin still has the enrichment and high-yield conditions. These new discoveries have led to a new phase of pre-exploration and reservoir increase in the buried hill area of the Bohai Bay Basin.

21.1.1.1 Macrostructure and Main Structural Units The Bohai Bay Basin is a large inland fault basin that developed in the background of the disintegration of the North China Platform. The basin has an “inverted Z” shape and the boundary and internal structural division of the basin are controlled by NE-trending discordogenic faults, such as Tanlu and Liaolan, and faults in the eastern Taihang Mountains. The basin is bounded by the Tanlu fault and is adjacent to the Liaodong–Jiaodong Uplift in the east. It is bounded by the faults in the eastern Taihang Mountains in the west, close to the Taihang Mountain Uplift belt, Yanshan orogenic belt in the north, and western Shandong Massif in the south. Controlled by Mesozoic and Cenozoic differential fault depressions, six large depressions can be observed in the basin, that is, the Liaohe, Bozhong, Jiyang, Huanghua, Central Hebei, and Linqing Depressions (Fig. 21.1). The Chengning–Shaleitian, Neihuang, Xingheng, and Cangxian Uplift belts are in the center of the basin, which has become an important watershed of the Cenozoic Basin. Macroscopically, the uplifts and depressions in the Bohai Bay Basin are diagonally distributed toward the northeast, forming three subsidence zones and two uplift belts (Zhou 2004). The large depressions and uplifts can be further divided into 54 sags and 39 bulge structures.

© Geological Publishing House and Springer-Verlag GmbH Germany 2020 Y. Ma, Marine Oil and Gas Exploration in China, https://doi.org/10.1007/978-3-662-61147-0_21

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Fig. 21.1 Division of the tectonic units in the Bohai Bay Basin

shenyang

0

40

80km Jinzhou

Tangshan

Langfang

Tianjin Dalian Baoding

Lvshun

Shijiazhuang

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Dongying Dezhou

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Handan

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The western subsidence belt, including the central Hebei Depression as the main body, is generally distributed in the NNE direction and is separated from the central Huanghua– Linqing Depression zone by the Cangxian–Xingheng Uplift. Controlled by the listric fault in the eastern Taihang Mountains and the hanging wall linkage fault system, the faults in the basin display an en echelon arrangement. They control the half-graben sags, which rupture in the west and overlap in the east, and the half-horst salients. Under the influence of inhomogeneous extension, several NW-trending adjusting structural systems formed inside the depression, which separate the secondary salients and sags. The central subsidence belt is mainly composed of the Huanghua and Linqing Depressions. It is controlled by the Cangdong and Lanliao faults, which are two sinistral strike-slipping echelon fracture basement faults, controlling the structure of the downthrow block. The Huanghua Depression on the northern side of the subsidence belt presents a tectonic “faulted western part and superimposed eastern part” pattern and the multiple secondary fault systems of the Cangdong listric fault hanging wall control the

basinboundary favourable belts

gasfiled

fault

sag

deepsag

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extension of the pull-apart semi-graben and graben. Taking the Kongdian–Yangsanmu salient as the boundary, the north–south structure of the Huanghua Depression notably differs. The northern Qikou Depression is an asymmetrical dish fault depression. The maximum buried depth of the Paleogene in the deep-seated area reaches more than 12000 m. Large slope structures are developed in the transition area from the center of the depression to the surrounding uplift. These slopes are cut by NE-trending faults and the fault downthrown block forms several secondary semi-graben depressions that are connected to each other. The extensional structure of the Linqing Depression in the south is more complex; the narrow asymmetric graben and gentle salient structure alternate. The secondary salients and sags are mostly echelon-distributed, indicating that the deep basal strike-slip structure plays an important role in controlling the depression structure. In addition to the NE-trending torsional fault, the NW-trending structure is also developed in the Linqing Depression, resulting in a complex geological structure framework in which salients and sags are echelon-distributed.

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The main body of the northeast subsidence belt is composed of the Liaohe, Bozhong, and Jiyang Depressions. It is characterized by a strike-slip pull-apart and tectonic “narrow north and wide south” framework. The extensional tectonics of the important depression unit are characterized by the NW- or near-EW-trending structure, with alternating troughs and horsts in the NS direction, which is separated by an adjusting structure in the EW direction. The two large uplifts of the Bohai Bay Basin are generally distributed in the northeastern direction. The Cangxian Uplift is an important positive element in the central part of the basin. The northern part of the uplift is connected to the Yanshan fold belt, the southern part is connected to the Xingheng Uplift via a shallow sag transition, and the inner secondary salients and shallow sags represent the NNE-trending sinistral strike-slipping echelon. The Chengning–Shaleitian Uplift belt is between the central and eastern subsidence belts and controls the distribution of the macrostructure in the eastern part of the Bohai Bay Basin. Within the uplift belt, en echelon shallow sags and salients are developed in the NWW direction, showing a ridge-like distribution, and the southern part of the uplift belt is cut off by the Lanliao fault. Generally, the internal structure of the Bohai Bay Basin is characterized by “the west–east belt and the north–south dividing block.” The large northeastward basement fault and northwestward adjusting basement fault intersect and control the distribution of secondary structural units in the basin. Because of the strong stretching–torsion movement of basement faults, most of the secondary tectonic units show lateral adjoin en echelon characteristics, while large shovel fault activities create a typical semi-graben, semi-horst tectonic basin, and ridge alternation framework.

basement. The present Bohai Bay Basin is at the southern slope of the aulacogen. The Proterozoic strata overlap and become thinner toward the south and east. Based on the structure and sedimentation characteristics, the Meso–Neoproterozoic can be divided into the Changcheng, Jixian, and Qingbaikou systems, which are in angular unconformable contact with the overlying Paleozoic and underlying Archean. The marine sedimentation of the Changcheng system included two transgressive cycles. The early transgressive cycle was dominated by marine clastic rock sedimentation. The marine sandstone of the Changzhougou Formation at the bottom moved upward to the black shale of the swamp facies of the Chuanlinggou Formation (algae). After the Tuanshanzi Formation of the Changcheng system deposites, the Meso–Neoproterozoic in the Bohai Bay area entered the sedimentary stage dominated by marine carbonate rocks. In the early Jixian Period, thick dolomite and siliceous dolomite strata of the Wumishan Formation were deposited. In the middle and late Jixian Period, the seawater became shallow. During the Hongshuizhuang and Xiamaling Periods, a set of marshy (algal and grass marshes, corresponding to the swamp coal series dominated by higher plants) black shale strata was deposited. In the Late Mesoproterozoic, affected by the Jixian tectonic movement, the evolution of the ancient rift trough was completed and the depression-type Qingbaikou Formation was deposited, with shallow sea sandstone and a thin layer of carbonate strata. In terms of the distribution area, the Jixian and Changcheng systems are mainly concentrated in the sedimentary center of the Yan-Liao aulacogen. The residual thickness is large in the western and northern parts of the current Bohai Bay Basin. The distribution range of the Qingbaikou system is much wider than that of the Jixian and Changcheng systems. The strata are also distributed in the Huanghua Depression and southern Cangxian Uplift. The Meso–Neoproterozoic represent the first set of marine cap rock deposits in the Bohai Bay area and the first set of marine oil-bearing sedimentary formations. The black shales of the Chuanlingou, Hongshuizhuang, and Xiamaling Formations are marine source rocks with extremely high organic matter contents. The organic carbon content of the shale of the Xiamaling Formation is 3–21% and the hydrocarbon generation potential is 361–560 mg/g (Zhang et al. 2015). So far, industrial-scale primary Proterozoic reservoirs have not been discovered in the Bohai Bay Basin, but Proterozoic paleo-reservoirs have been reported in the Proterozoic outcrop area in the northern Bohai Bay Basin (Hao 1984). For example, it has been confirmed that the Tieling Formation oil show of the Shuangdong anticline in northern Hebei originates from Proterozoic marine source rock. Proterozoic marine reservoirs are also developed. At present, the oil and gas layers discovered by drilling are mainly concentrated in the Wuyueshan and Tieling

21.1.1.2 Basin Tectonics and Sedimentary Evolution The Bohai Bay Basin is a typical superimposed basin, which experienced the Caledonian, Hercynian, Indo-China, Yenshan, and Himalayan movements or the evolution process of multi-screen tectonic basins such as the ancient rift trough, intercratonic depression, and strike-slip and pull-apart faults. It underwent the whole formation and cracking process of the North China Platform. Meso–Neoproterozoic, Lower Paleozoic, Upper Paleozoic, Mesozoic, and Cenozoic strata were deposited in the basin. The Proterozoic, Lower Paleozoic, and Upper Paleozoic are marine sediments. (1) The Precambrian aulacogen evolution stage After the Lvliang Movement, a large marine sedimentary basin, with Yan-Liao aulacogen as the center, was formed by early rift extension and thick Meso–Neoproterozoic marine strata were deposited on the Qianxi Group crystalline

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Formations of the Jixian system and Gaoyuzhuang Formation of the Changcheng system. The oil and gas reservoirs mainly comprise dolomite and siliceous dolomite. The physical properties of the reservoirs are the best in weathering- and leaching-modified areas. In the Bohai Bay Basin, the Meso–Neoproterozoic represent the main strata of buried hill exploration and development in the central Hebei and Liaohe Depressions. Large paleoweathering crust-type oil and gas fields were discovered in unconform buried hill strata of the Renqiu oilfield and Liaohe Damintun buried hill, respectively. (2) Early Paleozoic platform deposition stage The Early Paleozoic strata in the Bohai Bay area are typical epicontinental platform deposits composed of Cambrian and Ordovician. The Cambrian is mainly composed of marine shale and carbonate sediments. The Middle and Lower Cambrian marine mudstone strata are more abundant and the Upper Cambrian is dominated by carbonate rocks. The Middle and Lower Cambrian lithology is complex, with dolomite of the Fujunshan Formation, purple-red shale of the Mantou Formation, shale of the Xuzhuang Formation, and oolitic limestone of the Zhangxia Formation, and has a cumulative thickness of *380 m. The dolomite and dolomitic limestone sandwiched between thick shale are important hydrocarbon-bearing reservoirs in the Bohai Bay area. High industrial oil and gas yields were obtained in the Wen’an buried hills in the central Hebei Depression and the Baogu 2 buried hills in the Nanpu Depression. The Upper Cambrian is mainly composed of marine carbonate rocks including tidal flat dolomite and flat pebble limestone. The Ordovician mainly comprises carbonated sedimentary formations of epicontinental neritic platform facies and can be divided into the Lower and Middle Ordovician according to the paleontology and sedimentary cycles (Jin et al. 2002). The Middle and Lower Ordovician are in parallel unconformity. Influenced by the Caledonian Movement, the Upper Ordovician and parts of the Middle Ordovician were denuded. It is mainly represented by the Middle (Lower) Ordovician and Upper Paleozoic Carboniferous or Mesozoic Cretaceous, which are in parallel or angular unconformity. The Lower Ordovician includes the Yeli and Liangjiashan Formations and the first–fourth members of the Majiagou Formation. The Yeli Formation is *70–100 m thick and belongs to restricted sea carbonate deposits. The lithology consists of dolomitic and argillaceous limestones. The lithology of the Liangjiashan Formation is dominated by dolomite or argillaceous dolomite, with a thickness of *170 m. The Liangjiashan Formation and overlying Majiagou Formation are in parallel unconformity, which is the result of the Caledonian Huaiyuan Movement. Basal

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conglomerates can be found in Shandong (Feng et al. 1990; Zou et al. 2001; Jin et al. 2002). The Middle and Lower Ordovician are divided into lower and upper Majiagou Formation and Fengfeng Formation. The lower Majiagou Formation is *250 m thick, the upper Majiagou Formation is *300 m thick, and the Fengfeng Formation is *0–200 m thick. Ordovician carbonate rocks are also the sequences with the most oil and gas in the marine strata of the Bohai Bay area. They represent major buried hill hydrocarbon reservoirs in the central Hebei, Huanghua, and Jiyang Depressions. The discovered oil and gas are mainly concentrated in the strata near the weathering crust. The dolomites of the upper Majiagou and Fengfeng Formations represent the largest oil and gas reserves. (3) Late Paleozoic transitional facies evolution stage After the Caledonian Movement, the Bohai Bay area experienced nearly 150 Mio years of uplifting and erosion. The Upper Ordovician, Silurian, Devonian, and Lower Carboniferous are missing. The upper Paleozoic strata were unevenly distributed in the Bohai Bay area. The top was eroded by subduction due to the Indo-China and Yanshanian movements. The residual stratigraphic distribution was controlled by the Mesozoic paleostructure. Since the Late Carboniferous, the Bohai Bay and entire North China areas have suffered from transgression and Upper Carboniferous and Permian were deposited. The Benxi Formation of the Upper Carboniferous is mainly composed of shallow-sea bauxite mudstone, with tidal flat swamp coal and a small amount of marine carbonate rock. During the deposition of the Late Carboniferous–Early Permian Taiyuan Formation, frequent transgression and retreat occurred in the Bohai Bay area and a set of strata represented by marine mudstones (platform carbonate rocks) and littoral swamp coal was deposited. The coal strata of the Lower Permian Shanxi Formation are typical reverse-cycling strata. They are thin at the bottom and thick at the top, which is the result of the progradation of a large delta from northwest to southeast. The lower part of the Shanxi Formation is a set of delta plain swamp environment which contains coal deposites. The thickness of the coal bed greatly varies and the facies change quickly. The upper part is a clastic littoral sandstone deposit. In the late Middle Permian, the seawater retreated from the Bohai Bay area and the evolution of the large-scale continental facies depression started. The Middle Permian lower and upper Shihezi Formations were successively deposited. During the deposition of the lower Shihezi Formation, transgressions occurred in some areas and gray and aluminous mudstones were deposited. Afterward, the stratigraphic color changed to red and the sedimentary

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Progress of the Petroleum Exploration in the Bohai Bay Basin

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environment changed to interior arid lacustrine facies. With respect to the lithology, the lower Shihezi Formation is dominated by braided river delta deposits and the thickness of the sandstone is large, exhibiting the characteristics of “thick layers of sandstone with thin layers of mudstone.” The Upper Permian is dominated by flood plain meandering river facies characterized by “thick layers of mudstone with thin layers of sandstone.” The main lithology is purple-red mudstone, sandy mudstone, and thin sandstone. The Upper Paleozoic is an important exploration stratum of clastic buried hills in the Bohai Bay Basin. The Upper Carboniferous–Lower Permian marine–transitional facies coal strata are important natural gas source rocks in the Bohai Bay area of the North China Platform. The Suqiao, Wengu 2, and Wumaying gas reservoirs are related to this set of source rocks. The hydrocarbon source rocks of the coal in the Upper Paleozoic transitional facies of the Bohai Bay Basin have a high content of hydrogen-rich micro components. Locally, coal condensate has been found such as the Kongxi buried hill. There are various types of Upper Paleozoic reservoirs including the Taiyuan formation coastal carbonate rock and barrier island sandstone reservoirs, Shanxi Formation delta front sandstone reservoirs, Lower Shihezi Formation braided river delta sandstone reservoirs, and the Upper Shihezi Formation meandering channel sandstone reservoirs.

been deposited. In the Early Jurassic, small grabens and sags controlled by the NW-trending fault occurred in the southern Bohai Bay area and coal-bearing sedimentary structures dominated by intercontinental fluvial facies were deposited. The strata in the Jiyang Depression and southern part of the Huanghua Depression were well preserved. Channel sandstone has become an important buried hill oil reservoir such as the Dongguan buried hill of Huanghua Depression. Since the Late Jurassic, the Bohai Bay Basin has experienced uplifting and transtensional faulting. The strong activity of the bedrock fault caused the strong intermediate–acidic volcanic eruption during the Late Jurassic–Early Cretaceous, forming the second inner set of reservoirs in the Mesozoic. Subsequently, under the control of the strike-slip movement of basement faults, several small strike-slip pull-apart basins appeared in the central and eastern parts of the Bohai Bay Basin and Lower Cretaceous pyroclastic rocks were deposited. The thickness and lithology of this set of strata greatly vary and most areas are dominated by fine red deposits. In the late Early Cretaceous, the late Yanshanian Movement uplifted the Bohai Bay Basin again and the Paleogene strata of the Himalayan Period declined again to deposite, forming a large unconformity between the Paleogene and Jurassic and Cretaceous. Overall, the Mesozoic Indo-China Movement, especially the Yanshanian Movement, is an important formation stage of marine residual basins in the Bohai Bay Basin. It has laid a foundation for the Cenozoic rifting, while causing Paleozoic differential erosion. The Mesozoic paleotectonics and Cenozoic tectonics in the Bohai Bay area are generally mirror-inverted. The “ancient high and now low” pattern dominated different buried hill strata and the internal structure changed. The negative reversal of the ancient thrust faults led to extensional faults in the Cenozoic Basin margin. It also controlled the sedimentation and structure of the Cenozoic basin.

(4) Mesozoic craton disintegration stage The Mesozoic differential tectonic evolution of the Bohai Bay Basin began with the Indo-China Movement in the Middle and Late Triassic. The original Paleozoic craton base experienced early compression and late stretching–torsion. During the Indo-China Movement, the Bohai Bay Basin was affected by basal sinistral strike-slip of the Tanlu and Lanchao faults. Many compression overthrust structures appeared inside the Bohai Bay Basin such as the Zhuangxi ancient thrust belt in the Jiyang Depression of the Shengli Oilfield and the Wumaying ancient thrust belt in the Nanpi Sag, Cangzhou, Hebei. At the same time, regional uplift under the action of compression caused the differential erosion of the Paleozoic, which led to the formation of a paleotectonic framework of uplift alternating with depression in the Bohai Bay Basin. Therefore, uplifted structure units represented by the central Hebei (intense Paleozoic denudation) and Hebei–Liaoning anticlines and depressions represented by the Cangjin and Huanghua–Linqing synclines were formed. This evolution stage directly affected the main target layer of the buried hill exploration in the Bohai Bay Basin. Since the Yanshanian Movement, the Bohai Bay Basin has experienced basal strike-slip and pull-apart faults and Jurassic and Cretaceous continental volcanic strata have

(5) Cenozoic rift basin evolution stage Since the Paleocene, the Bohai Bay area in North China has not only been affected by the extrusion of the Pacific Plate and Indian–Qinghai–Tibet Plates into the Eurasian Plate but also by the arching of the deep mantle. This caused the right lateral translation of the Tanlu Fault, strong uplifting of the Earth’s crust, and reversed collapse, which is generally manifested as the extensional rift under the background of compression and arch tension. Large depressions began to develop in the southern part of the Huanghua Depression in the Bohai Bay Basin and early Kongdian reservoirs were deposited. Since the Eocene, large semi-graben depressions and uplifts have gradually been formed due to the listric activities of large faults such as the Cangdong and Lanliao faults.

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The Late Eocene rifting extended to the entire Bohai Bay Basin and the Shahejie Formation was deposited. In the Late Oligocene, the basin subsidence center began to migrate to the east due to the increase of the tectonic fault strength in the Bohai Sea and the early rift basin was transformed into a strike pull-apart basin. The structural events in this stage led to the finalization of the structure of the marine residual basin in the Bohai Bay Basin.

21.1.2 Oil and Gas Discovery Process and Exploration Results The oil and gas exploration in the Bohai Bay Basin began in 1955. In the early stage, the North China Petroleum Census Brigade of the former Ministry of Geology led the oil census. In April 1961, after the discovery of industrial oil flow in the Hua-8 well in the Dongying Sag, the oil and gas exploration and development in the Bohai Bay Basin were officially launched. In December 1958, the Hua 4 well was drilled in the Carboniferous, Permian, and Ordovician oil and gas fields, for the first time revealing the oil and gas potential of the marine facies and marine–transitional strata in the Bohai Bay Basin. In 1963, the Ordovician carbonate strata in the Huang 5 and Huang 8 wells in the northern Dagang buried hill belt of the Huanghua Depression were blowout in drilling, and this stands for the successive exploration in the Ordovician carbonate strata of the Bohai Bay Basin. The oil exploration history of the marine strata in the Bohai Bay Basin can be roughly divided into the following stages:

21.1.2.1 Delimiting the Depression and Uplift/Regional Exploration Stage (1955–1961) Since the founding of People’s Republic of China, the former Ministry of Geology has established the North China Petroleum Survey Team in 1955. At that time, field outcrop geological mapping, oil and gas show census, geophysical methods, such as gravity and magnetic exploration, and electrical exploration were mainly used to carry out basin structure research and oil and gas resource potential evaluation. During the stratigraphic survey from 1955 to 1957, liquid crude oil was found in the Ordovician limestone of the Zhaogezhuang quarry in Tangshan, Langmoshan in Shandong, and Longyaoshan in Hebei and the possible oil and gas field of marine strata was proposed firstly. During the coring of Carboniferous, Permian, and Ordovician marine strata in 1959, oil-bearing fractures were found in the Hua 4 well, which was drilled in the Tangyi structure of the Linqing Sag. This well is the first marine oil and gas display well in the Bohai Bay Basin. Although no substantial

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Bohai Bay Basin

discoveries were made in marine strata, Paleozoic strata were implemented and the macrostructural units of uplift and depression in the Bohai Bay Basin were preliminarily defined in this stage. It was recognized that Paleozoic marine carbonate strata are widely developed under the Cenozoic in the Bohai Bay area and it was suggested that the Ordovician, Upper Carboniferous, and Permian may be oil-bearing strata in the Bohai Bay Basin.

21.1.2.2 Detailed Prospecting of the Depression/Exploration Stage of the Secondary Structural Belt (1962–1972) In 1961, industrial flow was obtained in well Hua 8 in the Guantao and Minghuazhen Formations and the discovery of the Shengli oilfield was announced. Subsequently, the oil and gas exploration stage was entered, with the Dongying Sag as the main target, and the Dongxin and Shengtuo oilfields, with the Shahejie Formation as the main reservoir, were discovered. While prospecting the Dongying Sag in detail, the exploration work was extended to other depressions in the Bohai Bay Basin. In 1963, blowouts occurred in wells Huang 5 and Huang 8, which were drilled in the northern Dagang structural belt of the Huanghua Depression when encountering the blowout in Ordovician carbonate rocks. Thus, the Lower Paleozoic Ordovician became the main exploration target layer. Oil and gas exploration was carried out in four uplift areas such as in the Fengheying structural belt in the central Hebei Depression and the western Dagang, Kongdian, and Xuyangqiao uplifts in the Huanghua Depression and 10 wells were drilled. Industrial oil flow was obtained in the top weathering crust of the Ordovician limestone in well Gang 1, with a daily oil production of 3.85 t. Ordovician oil-bearing limestone was found in well Shanghe 1 in the Fengheying buried hill. The well section was 450 m long; only a small amount of natural gas was obtained. The drilling results showed that the Paleozoic carbonate rocks exhibit some reservoir and accumulation conditions. However, due to the limited understanding at that time, it was believed that the Paleozoic had undergone many tectonic activities and long-term erosion, resulting in oil and gas loss, which was unfavorable for oil and gas preservation (Fei and Wang 2005). Because of the discovery of the oil and gas reservoirs in the Guantao and Shahejie Formations in wells Gang 2, Gang 3, and Gang 5 and the northern Dagang oilfield, the Tertiary became the exploration target. At this stage, the complexity of the oil content of marine carbonate formations was recognized and it was clear that the Cenozoic continental petroleum system represents the main strata for oil and gas exploration in the Bohai Bay Basin.

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Progress of the Petroleum Exploration in the Bohai Bay Basin

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21.1.2.3 Exploration Stage of the Middle and High Buried Hills of the Renqiu Oilfield (1972–1984) In 1972, oil and gas were found in the Ordovician marine limestone reservoir in well Zhan 11 in the Zhanhua Sag. A high-yielding oil flow (935 t/d) was obtained and thus it was realized that the marine carbonate strata in the Bohai Bay Basin provide geological conditions for enrichment and high production. Based on analogy analysis, the five bulges of Gangxi, Xiaohanzhuang, Laowangzhuang, Xingji, and Dacheng saliencies were selected for the deployment and drilling in Ordovician strata (Fei and Wang 2005). Only a small amount of natural gas was obtained in well Da 3 of the Dacheng saliency. Since no breakthrough had been made in the exploration of Paleozoic marine limestone, it was once again recognized that the hydrocarbon accumulation of Paleozoic marine strata in the high buried hill belt is complex and diverse. In 1974, the Hebei Provincial Geological Bureau drilled the Jimen 1 well in the Renqiu structure and oil and gas were found when drilling into the carbonate strata. However, due to the limited understanding of the stratum, it was not taken seriously. In February 1975, the former Ministry of Petroleum deployed well Ren 4 in the Renqiu buried hill structural belt. After significant acidification of the Wumishan Formation, the oil pipe produced 1014 t of oil per day (Du et al. 2002). The large high-yield oilfield in the carbonate rock buried hill in the Wumishan Formation of the Renqiu Jixian system was discovered. The discovery of the Renqiu buried hill oilfield led to the exploration of carbonated buried hills in the Bohai Bay Basin. In 1976, the former Ministry of Petroleum Industry organized a battle of exploration work in the Jizhong Depression. In accordance with the understanding of oil-bearing in the structural highs of the fault blocks and fault nose, several exploration works in the middle to top area of buried hill were carried out. Seven buried hill oilfields, such as Longhuzhuang and Nanmeng, were discovered during the exploration of the billion-ton Renqiu buried hill oilfield. During the petroleum exploration in this stage, it was realized that the Proterozoic marine carbonate rocks in the central Hebei Depression had experienced long-term weathering and leaching transformation, the weathering crust karst reservoir was very developed, and the buried hill surrounded by Paleogene source rocks exhibited the conditions for the abundant of “Source rock in new strata and reservoir in old strata” to be accumulated. Thus, from 1975 to 1985, 740 mio t of accumulated oil and gas reserves were discovered in the buried hills of the Proterozoic and Paleozoic marine strata. In 1979, the crude oil output of the North China Oilfield reached 17.07 mio t/a,

which laid the foundation for the North China oilfield. In addition to the depression–uplift buried hills, the Ordovician Liuqiying fault block buried hill oilfield and Suqiao buried hill gas reservoir were discovered during the exploration in the slope area. The discovery of the Suqiao gas reservoir confirmed that the Upper Paleozoic coal source rocks have a hydrocarbon generation capacity in the Bohai Bay area. On the other hand, a new exploration target was revealed, that is, the “Both of source rock and reservoir were in old strata” type of primary oil and gas resources. Based on the idea of “Exploring the Slope Area and Drilling into the Depression” in the buried hills of the fault block, 349 wells were deployed in the Jiyang Depression. Five Ordovician marine carbonate buried hill oil and gas reservoirs, including Yihezhuang, Kenli, Pingnan, Taoerhe, and Zhuangxi, were discovered, with accumulated proven geological reserves of nearly 45 mio t (Ma et al. 2004; Li et al. 2004). The geological structure and stratigraphy of the basement rock in the Liaohe Depression have been systematically studied. The results showed that the carbonate residual fault block buried hills in the Meso–Neoproterozoic may have developed in the western depression slope belt. In 1979, the Shugu 1 well began to drill in the Shuguang buried hill. After acidification, the well yielded 447 t crude oil per day, initiated the exploration of marine carbonate hills in the Liaohe Depression. Subsequently, drilling was carried out in the buried hills in the western slope area, confirming that the composition of the buried hills is complex and varied, including both marine dolomite and quartz sandstone. The residual stratigraphy of the Meso–Neoproterozoic in the Liaohe Depression was determined, which differs from that of the Renqiu buried hill. In 1983, the main target area of buried hill exploration was changed to the Damintun Sag. However, with the discovery of the Archean mixed granite in the Sheng 3 well, the main exploration target layer was changed to Archean metamorphic rocks. Generally, the exploration of buried hills in the Bohai Bay Basin was the most effective from 1975 to 1984. Large-scale reserves were found in the central Hebei Depression and an oil and gas accumulation model for the “Source rock in new strata and reservoir in old strata” of the Renqiu weathering crust buried hill was established. However, the exploration of buried hills in other exploration areas based on the Renqiu model did not lead to similar results. It was further confirmed that the difference in the paleotectonics of the Pre-Cenozoic in the Bohai Bay Basin controls the distribution of the marine strata in the Meso– Neoproterozoic and Paleozoic, resulting in vast differences in the lithologies of buried hills (Hu et al. 1981).

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21.1.2.4 Exploration Stage of the Complex Structure Buried Hill and Coal-Forming Natural Gas (1985–1995): Wandering Stage In 1985, the Paleogene exploration in the Bohai Bay Basin entered a period of high tide. Based on the theory of composite oil and gas accumulation, a stage of oil and gas exploration dominated by secondary structural belts started. Correspondingly, the oil and gas exploration of buried hills dominated by marine strata has also still-stand. Although the results were not very effective, there are still some findings of various depressions, especially in the Indo-Yanshan ancient thrust nappe structure. The finding led to a breakthrough in the understanding of the oil content of the weathering crust of ancient buried hills with fault block structures. In 1985, the exploration focused on the Zhuangxi buried hill in the Shengli oilfield and complex buried hill reservoirs controlled by Paleozoic inverted folds were discovered. It was recognized that axial fractures developed in the Indosinian palaeo-fold structure, oil and gas were enriched, and the reservoir heterogeneity was strong. Among the exploratory wells drilled in the Zhuangxi buried hill structure, six wells obtained a thousand tons of high-yield oil flow, such as well Zhuanggu 10, and the Ordovician weathering crust produced 3600 t crude oil per day. The proven oil reserves were 4200
104 t. In 1992, well Konggu 3, which was deployed in the Kongxi buried hill of the Huanghuan Depression, was drilled in the paleo-thrust sheet structure. The Ordovician Fengfeng Formation was tested. After acid fracturing treatment, the daily oil production was 7.34 t. Based on a comparative analysis of the oil source, it was confirmed that the oil originated from Paleozoic source rock (Wang et al. 2000) and that the Paleozoic coal and carbonate rocks have the conditions for the formation of oil and gas. In this stage of the marine oil and gas exploration, it became clear that oil and gas can be accumulated in the fractured thrust nappe structure reservoir, expanding the theoretical system of carbonate karst weathering crust reservoirs. 21.1.2.5 Exploration Stage of Thrust Folding in Buried Hill Reservoirs (1996–2005) Because of the development of 3D seismic exploration technology, the imaging accuracy of the inner and deep buried hills has been greatly improved since 1996. The exploration of buried hills in Bohai Bay area entered the stage of genetic mechanism and deep inner buried hill exploration and important progress was made in the Jiyang and Huanghua Depressions. Based on the Jiyang Depression, the theory of multiplex buried hill compound accumulation was proposed. Based on this theory, 32 buried hill reservoirs were discovered during this stage and the billion-ton Zhuanghai and Bonan buried

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Bohai Bay Basin

hill oil and gas reservoirs were discovered. The newly discovered three-grade oil reserves reached 2.6
108 t. Based on the study of the Mesozoic paleotectonics in the Huanghua Depression, the viewpoint of controlling the erosion of Paleozoic strata by large-scale uplift in the Indosinian Period was put forward. Based on this knowledge, the Wumaying ancient thrust nappe structure was identified in the south of Kongdian and the inverted Qianmiqiao buried hill was found in the Banqiao Sag in northern Beidagang. Subsequently, wells Banshen 7 and Wushen 1 were deployed and industrial oil and gas were discovered in the Ordovician (Wu et al. 2000, 2002). Well Banshen 7 yielded a daily oil and natural gas production of 143 m3 and 27
104 m3 in the Ordovician, representing a new breakthrough in the marine carbonate rock buried hills in the Huanghua Depression. After the successful drilling of the Banshen 7 well, the buried hill in northern Beidagang was immediately pre-explored and evaluated and 14 exploration and evaluation wells were deployed. Among them, 9 wells obtained high-yielding industrial oil flow, with new condensate reserves of 661
104 t and geological reserves of natural gas of 266
108 m3. In the same year, the Wushen 1 well deployed in the Jidong Sag also yielded industrial gas flow in the Ordovician, confirming that the Ordovician marine strata in the Huanghua Depression have the conditions for the formation of large gas reservoirs. The exploration of oil and gas focused on the Mesozoic paleo-thrust nappe structure and the deep burial reconstruction of the inner fracture buried hills in the late stage. Drilling revealed the strong heterogeneity and complexity of oil and gas accumulation in the inner reservoir of the Paleozoic marine carbonate buried hill and the importance of marine stratigraphic karst and structural fractures for the development of the inner reservoir.

21.1.2.6 Exploration Stage of Overall Understanding and Systematic Evaluation (2006–Present) Since 2006, 3D seismic (full) coverage of the main tectonic belts of the Bohai Bay Basin has been achieved. Based on the use of high-resolution 3D seismic data, the geological structure of the basement rock was systematically studied and carbonate reservoirs were predicted. The exploration direction changed from the exploration of the second-level tectonic belt and the Mesozoic paleo-thrust nappe structure buried hill reservoir to the exploration of the subtle buried hill reservoir (low deep buried hill and inner buried hill reservoir). New discoveries were made in the central Hebei and Huanghua Depressions, indicating good prospects for the exploration of the subtle buried hill reservoir. In the central Hebei Depression, the study of the reservoir-forming conditions was deepened and a new model of the accumulation in the subtle buried hill was established. New

21.1

Progress of the Petroleum Exploration in the Bohai Bay Basin

497

exploration discoveries were made in the Changyangdian and Suning buried hill belts in the Raoyang Sag and in the Niudong and Wen’an buried hill belts in the Baxian Sag. The fine structure of the top of the Wumishan Formation in the Changyangdian buried hill belt of the Raoyang Sag was studied and the inner fault of the southern dip buried hill in the northern part of the Ren 96 well was identified: The Qingbaikou system developed in the downthrown block of the above faultand lateral sealing formed on the strata of the Wumishan Formation on the northern side. The buried hill accumulation model of “Paleo-reservoir/Paleo-sealing” was established (Zhao et al. 2012). Two sections of the Wumazhan Formation were tested in well Chang 3 and a high-yield industrial oil flow of 408 and 518 m3 per day was obtained, respectively. A new type of buried hill oil and gas accumulation was discovered. The analysis of the accumulation conditions of the Suning buried hill belt in the Raoyang Sag showed that the eastern side is adjacent to the main oil-generating trough of Hejian, although the top of the buried hill covers the “red” stratum of the Kongdian Group–fourth member of the Shahejie Group. Oil and gas generated from source rocks of the third member of the Shahejie Group laterally move to the reservoir and accumulate at the top of buried hill along the fault surface and unconformity surface, representing the “Red cap–Lateral transport” buried hill accumulation model. The Ninggu 8X well drilled in the high part of the buried hill yielded 253.2 m3 oil and 6364 m3 gas per day in the Wumishan Formation. At the same time, high-resolution fine processing and interpretation of 3D seismic data were carried out in the Niudong buried hill belt in the western Baxian Sag. The ultra-deep buried hill tectonic geometry was proven and it was discovered that the Niudong buried hill belt is covered and surrounded by high-quality source rock of the deep Kongdian Group–fourth member of the Shahejie Group, which has good conditions for accumulation. Based on these results, a new breakthrough was made in the Niudong 1 well, which produced 642.9 m3 crude oil and 56.3
104 m3 natural gas per day in the Wumishan Formation. In particular, the pre-exploration of the buried hill greatly expanded the exploration of marine buried hills and strengthened the confidence in deep buried hill exploration. Therefore, to prove the new model of oil and gas accumulation in the Cambrian Fujunshan Formation inner buried hill in the inner Wen’an slope zone of the Baxian Sag, well Wengu 3 was drilled and an industrial oil and gas flow of 302.64 m3/d and 94643 m3/d, respectively, was obtained in the Fujunshan Formation, representing a breakthrough in the exploration of ultra-deep inner buried hill oil reservoirs. Based on detailed studies of Ordovician buried hills since 2009 where it covers the area in the Huanghua Depression, it was recognized that Ordovician carbonate rocks have the

geological conditions for the development of fractured reservoirs due to the superimposition and transformation of multi-stage fault folds in the Mesozoic and Cenozoic. The Chenghai and Wangguantun buried hills were selected for pre-exploration. In wells Haigu 1 and Wangu 1 high-yield natural gas flow was obtained in the Ordovician; the newly predicted natural gas reserves were 225
108 m3. Based on the exploration of the middle and low buried hills, it was recognized that the primary oil and gas system of the Paleozoic marine and transitional facies in the Huanghua Depression is an important area for the increase in the natural gas reserves and production in the Bohai Bay area.

21.2

Renqiu Oilfield (Buried Hills of the Wumishan Formation in the Jixian System)

21.2.1 Oilfield Location and Regional Geological Background The Renqiu oilfield is in Renqiu City, Hebei Province, in the central buried hill structural belt of the Raoyang Sag in the central Hebei Depression in the western Bohai Bay Basin. It is distributed in the northeast direction (Fig. 21.1). The Renqiu oilfield is also the largest marine carbonate buried hill oilfield in China. The main producing formations of the oilfield are the marine carbonate rock of the buried hill reservoir and the sandstone of the Paleogene reservoir. Marine carbonate reservoirs are mainly distributed in the Mesoproterozoic Wumishan Formation of the Jixian System, Lower Palaeozoic Cambrian Fujunshan Formation, and Ordovician Yeli, Majiagou, and Liangjiashan Formations.

21.2.1.1 Regional Stratigraphic Characteristics The Renqiu buried hill structural belt includes two sets of strata, that is, the continental clastic rock formation of Cenozoic overlying buried hill strata and buried hill strata composed of Lower Paleozoic–Mesoproterozoic–Neoproterozoic marine carbonate rocks. The two sets of strata are in angular unconformity contact. The buried hill strata in the area are dominated by Meso– Neoproterozoic and Lower Paleozoic marine carbonate rocks with stable sedimentation and small thickness variations. The main structural belt is the Wumishan Formation of the Jixian system in the Meso–Neoproterozoic. Northward, it transforms into the Cambrian and Ordovician Qingbaikou system. The Meso–Neoproterozoic strata extend to the west, to western Baoding, and the outcrops become older to the west. The Cambrian and Ordovician strata are distributed at the northern slope of the Renqiu buried hill structural belt. The exposed strata in the east successively changed and the Carboniferous and Permian strata at the top of the buried hill

498

were denuded. The Meso–Neoproterozoic of the Qingbaikou system is very thin (170 m). The Xiamaling Formation of the Qingbaikou system and the Tieling and Hongshuizhuang Formations of the Jixian system are missing. The thicknesses of the Wumishan, Yangzhuang, and Gaoyuzhuang Formations are large and the apparent cumulative drilling thickness of the Wumishan Formation in the oilfield is 2476 m (not drill out). The predicted total thickness of the Wumishan, Yangzhuang, and Gaoyuzhuang Formations is >4000 m. The Cambrian is mainly distributed in the east of the Renqiu tectonic belt. From the bottom up, it includes the Fujunshan, Mantou, Maozhuang, Xuzhuang, Zhangxia, Gushan, Changshan, and Fengshan Formations, with a thickness of *500–600 m. The Ordovician is mainly distributed in the northeast. Due to the later erosion, it is incompletely preserved and the Fengfeng Formation on the top is missing. From the bottom up, it includes the Yeli, Liangjiashan, Majiagou, and upper Majiagou Formations, with a thickness of *600–700 m. The Tertiary of the Renqiu oilfield includes sedimentary strata of the basin fault depression, which directly overlap the buried hill. From top to bottom, it is divided into the Neogene Minghuazhen and Guantao Formations and the Paleogene Dongying and first–fourth members of the Shahejie Formations. The fourth member of the Shahejie Formation only exists at the hillside of the buried hill and the top is missing. The Paleogene comprises lacustrine to fluvial facies sedimentation and the lithology alternates between sand and mudstone. The oil shale and marl are sandwiched in the lower first member of the Shahejie Formation and the biolimestone is sandwiched between the third and fourth members of the Shahejie Formation. The thickness of the Paleogene in the Renqiu oilfield is small (630–2100 m) (Du et al. 2002).

21.2.1.2 History of the Tectonic Evolution The tectonic development history of the Renqiu tectonic belt, from the Mesoproterozoic to the Quaternary, generally includes four structural development stages, that is, the stable subsidence of the Mesoproterozoic–Late Paleozoic (platform), Mesozoic fold–fault, Paleogene fault depression, and Neogene Depression. Stable subsidence stage from the Mesoproterozoic to the end of the Paleozoic: At this stage, from the Mesoproterozoic to Middle Ordovician, relatively stable subsidence occurred and marine strata, including dolomite, siliceous dolomite, and limestone, with a thickness of 7500 m were extensively deposited. The dolomite deposition thickness of the Gaoyuzhuang and Wumishan formations is large, reaching 2000–5000 m, constituting the foundation for the carbonate reservoir of the ancient buried hill in the later stage. The Caledonian Movement at the end of the Early Paleozoic caused an overall rise in the area. The Upper

21

Bohai Bay Basin

Ordovician, Silurian, Devonian, and Early Carbon deposits are missing. From the Late Carboniferous to the end of the Permian, large-scale settlement occurred and a set of marine–continental strata and continental clastic rocks were deposited. Fold–fault development stage in the Mesozoic: During the Mesozoic Period, the tectonic movement in the area intensified, mainly characterized by folds and faults. Based on the regional drilling data, the Triassic is missing and the Mesozoic was only deposited in the intermontane depression around the uplift, indicating that the crust had risen during the Mesozoic. At this stage, the tectonic movement caused the uplift of the Renqiu area in the central part of the central Hebei Depression, forming the Pre-Tertiary bedrock block of the Meso–Neoproterozoic to Paleozoic. Due to the thick marine carbonate rock layer and the large-scale and long-term exposure to the surface, weathering, erosion, leaching, and buried hill dissolution, a highly developed paleokarst landform and reservoir space for fractures–holes were generated. Based on the migration and accumulation of oil and gas in the ancient buried hills, a huge seam reservoir system was created. Fault depression development stage in the Paleogene: Entering the Paleogene, the tectonic movement was characterized by fault depression and block warping. At the same time, the ancient buried hill oilfield was formed. At this stage, the fault blocks continued to move and develop due to the Yanshan Movement. The stage was characterized by normal fault activity, resulting in a drop of more than thousands of meters, the height of the great differential between different sizes of fault block. Due to the different subsidence speeds of different parts of the fault block rock mass, a monoclinic tilting block formed. On the downthrown block of the fault block, sedimentation formed the oil sag. The upthrown block was also covered and a buried hill formed. The lateral relationship is based on the distribution between the Lower Tertiary oil-bearing rock mass and ancient buried hill reservoir rock mass. The result was the petroleum-bearing combination of “Source rock in new strata and reservoir in reservoirs in the older strata.” At this stage, the tectonic activity was controlled by the Paleogene strata overlying the different strata from the Meso–Neoproterozoic to the Mesozoic in the depression. Reservoirs developed in the buried hill due to the large amount of local depositional discontinuities. In short, the tectonic block faulting activity controlled the hydrocarbon reservoir development including hydrocarbon generation, migration, accumulation, and preservation. Regional depression stage in the Late Neogene: From the end of the Paleogene to the present, regional subsidence occurred, the tectonic activity was weakened, faults disappeared, and magmatic activity was rare. The weakening of the tectonic activities is conducive to the preservation of oil

21.2

Renqiu Oilfield (Buried Hills of the Wumishan Formation …

and gas in the buried hills. The tectonic activities may have caused the formation of several secondary oil and gas reservoirs in the buried hills and Paleogene, along the faults or unconformities to the Neogene traps. These four tectonic evolution stages can also be divided into the developmental stages (mainly before the Himalayan Movement) and formation stages of buried hill reservoirs (during the Himalayan Movement).

21.2.2 History of the Discovery of Oil and Gas Fields As mentioned above, the discovery process of the Renqiu oilfield can be roughly divided into three stages, that is, regional geological survey, major breakthrough in the exploration and efficient exploration, and construction and production, from the beginning of oil exploration in the North China Plain in 1955 to the discovery of the buried carbonate oilfield in Renqiu in 1975 and the complete exploration, construction, and production in 1976.

21.2.2.1 Regional Geological Survey Stage (1955–1972) In the early stage of carbonate oil and gas exploration in the central Hebei Depression, a large number of primary oil seepage were found in the Ordovician limestone geode in the Tangshan area, indicating oil and gas in Paleozoic carbonate rocks in North China. During the Sixth National Petroleum Exploration Conference held by the General Administration of Petroleum Administration of the former Ministry of Fuel Industry and the First Oil Census Work Meeting held by the former Ministry of Geology in 1955, oil and gas surveys and exploration in the North China Plain were planned. Subsequently, 1:1000000 gravity, 1:200000 magnetic, electrical, and two-dimensional seismic exploration work were carried out in the area. The distribution range of the central Hebei Depression and secondary structural units was determined and the central and eastern parts of the depression were defined; six depressions, including the Langgu, Wuqing, Baxian, Raoyang, Shenxian, and Shulu Sags, were identified (Du et al. 2002). From 1968–1970, the exploration focus shifted from the Beijing–Tianjin area in the north to the Baxian and Raoyang Sags in the center. The area of *450 km2 comprises four structural belts (Baxian, Zhangzhou, Nanmazhuang, and Renqiu). Ten wells were drilled and it was confirmed that oil and gas layers with exploration prospects are widely distributed in the depression (Huabei Oilfield Petroleum Geology Writing Group 1988). Wells Ren 1 and 2 were drilled in the Renqiu structural belt, which is a complete central structural belt, but no important results were obtained.

499

21.2.2.2 Major Exploration Breakthrough Stage (1973–1975) In June 1973, the Planning and Research Institute of the former Ministry of Petroleum Industry organized a “breakthrough” meeting with respect to the exploration in the central Hebei Depression and identified four favorable structures, that is, Gaojiapu, Renqiu, Gaoyang, and Liulu, as exploration breakthroughs. The Hebei Provincial Geological Bureau drilled well Jingu 1 in the Renqiu structure through the Paleogene into the carbonate formation at 2981 m. Oil was found in fractures of 0.93 m thick siliceous limestone by coring and oil was observed on the trough surface during the drilling up to 40% (Yang 2010, 2013). However, at that time, the age of carbonate strata is unknown. The main target layer was the Paleogene and little attention was paid to the oil and gas in carbonate rocks. In February 1975, well Ren 4 was drilled in the Renqiu tectonic belt. During the drilling to 3151.55 m in June, Paleogene strata and the carbonate interval were penetrated and four fractured oil-bearing segments with siliceous dolomite and up to 5% oil cuttings were detected between 3161 and 3184.6 m. At the same time, mudstone loss occurred in the well section from 3177 to 3184 m; in total, 14 m3 of mudstone was lost. After several discussions, it was decided to place a cement cap on the top of the buried hill to protect the oil layer below, the upper 5 1/2′′ oil layer casing, and then drill into the cement cap to test the oil. After large-scale acidification, the daily output of crude oil after the pipe blowout was 1014 t/d in July. Thus, a high-yielding reservoir was discovered in the Renqiu buried hill belt of the Wumishan Formation in the Jixian system (Du et al. 2002). After making a breakthrough in well Ren 4, the well spacing method of “Locating the buried hill, Drilling for the high point, and Exploring the oil boundary” was adopted and 14 exploration wells were deployed. The anatomy of the ancient buried hill reservoir of the Wumishan Formation in Renqiu was evaluated. 21.2.2.3 Efficient Production Stage (1976–1979) In the first half of 1976, seven drilling rigs were used to drill three hills in the northern, central, and southern areas. Only 7 wells were used to explore the type, shape, and oil–water contact of the superlarge ancient Renqiu buried hill reservoir. The proven oil reserves were 3.9
108 t, providing a reliable data and resource basis to determine the development and production capacities. Therefore, in the second half of the year, the principle of “Lean Wells and High Yield” was adopted and 46 wells were deployed. In total, 17 wells were put into production and an annual production capacity of 10 million t and crude oil production of 609
104 t were reached. In 1979, the crude oil production increased to a maximum of 1707
104 t. By the end of 2015, a total of

500

306 wells had been drilled, including 273 production wells and 33 water injection wells. The cumulative oil recovery was 13019.1
104 t.

21.2.3 Characteristics of Oil and Gas Fields 21.2.3.1 Trap Characteristics The Renqiu oilfield buried hill belt is a large buried hill structural belt in the central uplift structural belt in the Raoyang Sag. The structural belt is oriented northeast, 38.5 km long, 6–7.5 km wide and has a trap area of 210 km2 and closure range of 1912 m. It is the largest buried hill structural belt in the central Hebei Depression. The two sides of the buried hill are asymmetrical. The northwestern side is cut by the main Renxi fault, forming a cliff with a large slope angle of 60°–70°. The southeastern side is an eroded gentle slope with a slope angle of 20° to 25°. The top of the buried hill is round and extends along the main broken edge on the west side. The inner structure of the Renqiu buried hill is a semi-anticline (Huabei Oilfield Petroleum Geology Compilation Group 1988). The inner strata of the Renqiu buried hill are old in the south and young in the north. From the south to the north, they include the Jixian (Wumishan Formation), Qingbaikou, and Cambrian to Ordovician of the northern slope. The inner high is not in the northern part of the high point of the buried hill but at the southern end of the buried hill. The inclination of the inner stratum is 20°–30°. Due to the large dip angle of the inner stratum, the buried hill strata are deeply weathered, which plays a key role in forming a good reservoir with overall connectivity. At the same time, the top Cambrian at the northern slope of the Renqiu tectonic belt was denuded and exposed, causing the denudation and pinching of the top of the Ordovician. The upper part of the Ordovician was in unconformable contact with the Tertiary sandstone below. Thus, the weathering bodies of the Wumishan Formation at the top of the buried hill, stratiform traps of the Fujunshan Formation, and Ordovician slope layer (wedge) traps with corresponding buried hill reservoir sequences formed. There are three types of carbonate rock buried hill reservoirs in the Renqiu oilfield including the Wumishan Formation buried hill reservoir, Cambrian Fujunshan inner buried hill reservoir, and Ordovician buried hill reservoir. The buried hill trap of the Wumishan Formation in the Renqiu oilfield was controlled by the Renxi fault in the west and the interior was divided by the secondary fault, forming four different buried hill structures or four buried hills with different heights, that is, the Ren 11, Ren 7, Ren 6, and Ren 9 buried hills, respectively (Fig. 21.2, Table 21.1). Well Ren 7 had the largest scale, with an area of 67 km2; the closure of well Ren 11 was the largest, reaching 1912 m.

21

Bohai Bay Basin

The Ordovician oil reservoir in the Renqiu oilfield is in the north of the Renqiu buried hill and is not connected to the Wumishan Formation reservoir. It is an independent hillside reservoir. The northern slope of the Renqiu buried hill is a conclinal slope that formed after long-term erosion. The top is denuded and wedge out and the upper part is directly covered by the Paleogene sandstone and mudstone. An interbedded layer of carbonate rocks, mudstones, and sandstones of the Cambrian and Qingbaikou systems is underneath the Ordovician. It is an impermeable layer, which is separated from the Wumishan Formation reservoir. The west wing of the buried hill is the Renxi fault, which is also connected to the Tertiary sand and mudstone below, forming an independent stratigraphic hillside trap. The Ordovician exhibiting a thickness of 0–740 m is distributed in the area below 2900 m and the northern and eastern wings of the buried hill are fan-shaped. The Fujunshan Formation reservoir is located at the circumferential slope of well Ren 11 and is a buried hill reservoir. The structure of the Fujunshan Formation is an east-sloping monocline with a steep top wing, top inclination of 20°, and wing inclination of 33°. It was cut into three well blocks (Ren 8, Ren 80, and Ren 41) by three faults.

21.2.3.2 Reservoir Characteristics and Development Status (1) Wumishan Formation reservoir in the Jixian system The Wumoshan Formation reservoir in Renqiu oilfield is characterized by a large oil-bearing area, high reservoir height high abundance, and high single-well production. This reservoir has a proven oil-bearing area of 56.9 km2, proven oil reserves of 3.7
108 m3, and recoverable reserves of 1.2057
108 m3 and is the main large oil reservoir of the Renqiu oilfield. The oil-bearing height at the top of the hill of well Ren 11 is 923 m. The oil-bearing height of the other hills is 642, 470, and 576 m, respectively. The reserve abundance of the whole reservoir is 925
104 m3/km2. The daily output of oil in a single well is >1000 t; the maximum daily output of 5435 t was observed in well Ren 9 (Fig. 21.3, Table 21.2). The reservoir is a large bottom–water block reservoir with a low saturation pressure, low oil-gas ratio, and “Five Unifications” characteristics, that is, unified connective body, oil– water interface, pressure system, hydrodynamic system, and thermal system. Although the whole reservoir hill has various height, the fault blocks are divided. However, the exploration and development have proven that the reservoir space is a unified connective body, the oil–water interface is 3510 m, the pressure coefficient is 1.03–1.05, the saturation pressure is 1.32 MPa, the stratigraphic saturation differential pressure is 30.7–31.1 MPa, the reservoir temperature is 110–125 °C, the reservoir internal geothermal gradient is only 1.7 °C/100 m– 1.8 °C/100 m, and the oil/gas ratio is only 4 m3/t.

21.2

Renqiu Oilfield (Buried Hills of the Wumishan Formation …

Fig. 21.2 Oil-bearing area distribution in the Wumishan Formation, Renqiu oilfield, Hebei Province

501

502 Table 21.1 Buried hill trap elements of the Wumishan Formation in the Renqiu oilfield

21

Bohai Bay Basin

Strike direction (°)

Lengh (km)

Width (km)

Area (km2)

Top depth (m)

Relief (m)

Dip (°) Top

Flank

Entire buried hill

NE30

38.5

6–7.5

210

2587

1912

3–4

11–37

Ren 11

NE30

7

6

42

2587

1912

4

11–37

Buried hill

Ren 7

NE30–40

16

7.5

67

2868

1632

3

16–24

Ren 6

NE30–40

4

6

22

3028

1472

5

20

Ren 9

NE40

5.5

6

25

2934

1566

5

16

※The area and relief were calculated using the 4500 depth contour lines

Fig. 21.3 Renqiu oilfield buried hill reservoir section

The variation of the fluid properties is very little in the Wumishan Formation reservoir. The crude oil is medium-density and medium-viscosity crude oil (Table 21.3) and has a high freezing point, high-wax content, low-sulfur content, low saturation pressure, very low gas content, and low oil–gas ratio. The properties of the crude oil vary little throughout the reservoir. The formation water is NaHCO3-type water, with a chloride ion content of 1867 mg/L and a total salinity of 3795 mg/L, representing slowly alternating formation water. The reservoir of the Wumishan Formation in the Renqiu oilfield was developed by the initial open-hole completion, water injection to maintain the pressure, and continuous infill and grid connection. The development started in September 1975 and the output increased rapidly. In October 1980, the output began to decline. From 1985 to 1986, the decline showed an increasing trend. In 1990, the decline gradually slowed down. By the end of 2015, the total number of wells in the Wumazhan Formation reservoir was 219. A total of 174 wells were open, the daily oil production was 481 t, the cumulative oil production was 1.2
108 t, the recovery degree of geological reserves was 32.1%, the comprehensive water content was 96.82%, and the number of water injection

wells was 18. Open 8 wells, daily water injection 17836 m3, cumulative water injection 26071
104 m3. (2) The Ordovician reservoir The top of the Ordovician reservoir is controlled by the denudation line and the two wings are controlled by faults. It is an edge water-driven layered reservoir. The proven oil area of the reservoir is 20.9 km2, the proven oil reserves are 2208
104 t, and the recoverable reserves are 742
104 t (Table 21.2); the oil–water contact is 4100 m, which is 590 m lower than that of the Wumishan Formation reservoir. The saturation pressure is 6.08 MPa, the original oil–gas ratio is 37.1 m3/t, and the total salinity of the formation water is 20250 mg/L, which is much higher than that of the Wumishan Formation reservoir. This shows that it is an independent reservoir, which is not connected to the oil reservoir of the Renqiu Wumishan Formation. The reservoir was developed by early open hole completion and pattern flooding with 600m well spacing and triangle well pattern. The production started in October 1978. By the end of 2015, 47 production and 13 injection wells were deployed, the daily output of oil was 141 t, the oil

21.2

Renqiu Oilfield (Buried Hills of the Wumishan Formation …

503

Table 21.2 Basic parameters of buried hill reservoirs in the Renqiu oilfield (modified from Fei and Wang 2005)

Reserves

Reservoir characteristics

Reservoir characteristics

Formation water properties

Wumishan Formation reservoir

Ordovician reservoir

Fujunshan Formation reservoir

Proven reserves

3.7463
108 t

2208

583
104 t

Reserve abundance

658.4
10 t/km

106
10 t/km

91
104 t/km2

Recoverable reserves

1.2007
108 t

742.0
104 t

184.0
104 t

Trap type

Top of the buried hill

Slope of the buried hill

Hillside of the buried hill

Trap formation time

Oligocene

Oligocene

Oligocene

Closed area

210 km2

210 km2

–

4

2

4

2

Closed height

1100–1900 m

1365 m

–

Reservoir depth

3250 m (middle)

3444 m (middle)

3227 m (middle)

Reservoir thickness

167.1 m

28.9 m

28.3 m

Oil–water contact

3510 m

4100 m

3500 m

Oil-bearing area

56.9 km2

20.9 km2

6.4 km2

Oil source

Paleogene Shahejie Formation

Paleogene Shahejie Formation

Paleogene Shahejie Formation

Type of crude oil

Low-sulfur and high-wax terrestrial crude oil

Low-sulfur and high-wax terrestrial crude oil

Low-sulfur and high-wax terrestrial crude oil

Crude oil density

0.8887 g/cm3

0.8818 g/cm3

0.8765 g/cm3

Underground viscosity

8.21 mPa s

3.14 mPa s

6.57 mPa s

Reservoir pressure

32.558 MPa

33.166 MPa

31.40 MPa

Pressure coefficient

1.022

1.053

1.03

Cap rock

Argillaceous rock of the Paleogene Shahejie– Dongying formations

Argillaceous rock of the Paleogene Shahejie–Dongying formations

Argillaceous rock of the Paleogene Shahejie– Dongying formations

Formation

Wumishan Formation of the Jixian system

Ordovician Majiagou Formation, Liangjiashan Formation

Cambrian Fujunshan Formation

Sedimentary environment

Intertidal facies and subtidal cryptalgal reef flat

Open sea

Dolomitic limestone– mudstone tidal flat

Total thickness

1900–2300 m

477 m

41–56 m

Total thickness

167.1 m

28.9 m

28.3 m

Main lithology

Dolomite

Dolomite, limestone

Dolomite

Pore type

Combination of fractures, cavities, and pores

Intercrystalline pores, intercrystalline corroded pores, bedding solution pores and cavities, functional joints, dissolution fractures, etc.

Intercrystalline pores, intercrystalline corroded pores

Porosity (average)

6.43%

5.95%

6.00%

Permeability (average)

1243.4
10−3 lm2

296.1
10−3 lm2

1401.4
10−3 lm2

Oil saturation (average)

75%

80%

65%

Formation water salinity (mg/L)

3795

20250

2176

Formation water type

NaHCO3

NaHCO3

NaHCO3

504

21

Bohai Bay Basin

Table 21.3 Change of the crude oil properties in the Renqiu oilfield Hill

Density Surface

Viscosity Subsurface

Surface

Subsurface

Solidifying point (°C)

Gum asphalt content (%)

Paraffin content (%)

Sulfur content (%)

Saturation pressure (MPa)

Gas–oil ratio (m3/t)

Ren 11

0.8813

0.8148

41.07

4.88

36

24.33

17.8

0.27

1.4

5

Ren 7

0.8903

0.8341

67.31

10.85

35

27.46

18.14

0.32

1.3

4.5

Ren 6

0.8899

0.8178

68.29

8.53

35

30.65

16.95

0.33

1.4

4

Ren 9

0.8950

0.8372

63.89

8.59

34

27.95

15.73

0.31

1.3

4

recovery speed of geological reserves was 0.25%, and the comprehensive water content was 85.75%. (3) The Cambrian Fujunshan Formation reservoir The Cambrian Fujunshan Formation reservoir is a mountainside (inside) layered reservoir. The proven oil area is 6.4 km2, the proven oil reserves are 582
104 t, and the recoverable reserves are 184
104 t. The oil–water contact is consistent with that of the Wumishan Formation, that is, 3510 m. The fluid properties are basically consistent with those of the Wumishan Formation. The reservoir was developed by maintaining the pressure using wide-spaced wells and high-yield production. Since September 1976, industrial oil flow has been obtained in 10 wells. The production was started in June 1977. The water injection began in May 1979. By the end of 2015, 7 production wells had been installed and 41 t of oil were produced per day. The comprehensive water content is 90.43% and the cumulative oil recovery is 2.05 mio t.

21.2.4 Characteristics of the Main Reservoirs 21.2.4.1 Lithologic Characteristics of the Oil and Gas Reservoirs The Wumishan Formation in the Jixian system of the Middle Proterozoic is the main oil-producing stratum of the Renqiu oilfield. The rock types mainly include argillaceous dolomite, and sand–gravel mixed dolostone in the supra-intertidal or supratidal zones as well as stromatolitic dolostone and thrombolite (algo-clastic) or oncolite dolostone in the lower intertidal or subtidal zones. They alternate in the longitudinal direction, forming a complete or incomplete layer of transgressive to regressive strata; several form a third- or second-order cycle. Based on the electrical and lithological characteristics, the formation can be divided into ten oil groups from top to bottom, with a total thickness of 2341 m. The main lithology of the Cambrian Fujunshan Formation comprises dolomite and limestone sandwiched between

two layers of argillaceous dolomite and mudstone. Based on the statistics of 14 wells, the reservoir occupies 47.9% of the thickness of the formation. The physical properties of the reservoir vary greatly. Because there are mud barriers in the upper and lower layers of this formation, the dissolution of the bedding layer is remarkable. In addition, faults, fractures, and the distance from the denudation datum are affected, leading to great differences in the reservoir’s physical properties, which can be divided into three types: strong, medium, and weak weathering. The Ordovician reservoir includes the Yeli, Liangjiashan, lower Majiagou, and upper Majiagou Formations from the bottom to the top. It can be divided into 3 cycles and 19 small layers and the lithology comprises bioclastic and breccia limestones, dolomite, and mudstone limestone. The physical properties of the reservoir are mainly affected by the lithology, fault fracture, and degree of dissolution. The Liangjiashan and Majiagou Formations are good reservoirs and the limestone of the Yeli Formation is heavy and has no reservoir capacity.

21.2.4.2 Tectogenesis and Diagenesis (1) Tectogenesis and fracture development The carbonate rocks of the Wumishan Formation in the Renqiu oilfield experienced many tectonic events during the long geological evolution, especially the Indosinian and Yanshanian movements characterized by folds and faults as well as the Himalayan Movement characterized by fault block lifting activities, which resulted in multi-phase fault and joint systems that are of great significance for the formation of a good buried hill reservoir. The Renqiu buried hill contains six groups of main tectonic joints. There are two sets of orthogonal joints with NW–SW and NW–SEE orientations. The other four groups are two pairs of X conjugated joint system a pair of near-EW and near-SN, the other pair is NEE–SWW and SEE–NWW. The six sets of structural joints and faults are consistent with each other and form a fault fracture network system. The

21.2

Renqiu Oilfield (Buried Hills of the Wumishan Formation …

more the faults are developed, the more the fractures are developed. (2) Diagenesis The diagenesis of the Wumishan Formation in Renqiu Oilfield mainly included dolomitization, silicidation, compaction and pressure dissolution, recrystallization, dissolution and filling, epigenetic karstification, and tectonic disruption, which have important effects on the formation of carbonate reservoirs in buried hills.

21.2.4.3 Analysis of the Reservoir Physical Characteristics and Main Controlling Factors (1) Reservoir physical characteristics The Wumishan Formation in the Renqiu oilfield experienced strong tectonic events and karstification and developed 14 types of reservoirs in three major categories, that is, pores, fractures, and cavities, which vary in size and shape. The above-mentioned various reservoir spaces were combined in different forms and three types of reservoirs were formed: large fracture–cavity, combination of fractures–cavities– pores, and microfractures–pores. The large fracture–cavity-type reservoirs are mostly developed in areas or intervals with strong fractures and deep weathering. Network joints with slot widths greater than 100 lm are used as channels and large and medium-sized fractured pores are connected to form a combination of reservoir and permeation. This type of reservoir has a good connectivity and high permeability. The pressure in the production well can be quickly restored. The pressure recovery curve is a line, the production pressure difference is small, generally 1.7–2.3
10−1 MPa, and the oil production index is high, generally 137–178 t/10−1 MPa d. The combined fracture–cavity–pore-type reservoir is composed of the above-mentioned large fracture–cavity and microfracture–pore types. Large and medium-sized cavities, fractures, small holes, microcracks, and pores coexist in the reservoir. The porosity and throat size are extremely uneven, indicating a strong reservoir heterogeneity. The water flooding efficiency is 80% in the large fractured cavity and the water displacement efficiency is only 10% to 20%. The pressure recovery curve shows double and multi-medium characteristics. The Wumishan Formation in the Renqiu oilfield is dominated by these reservoirs and the output is high. However, various measures are needed to improve their development. In the microfracture–pore-type reservoirs, with intergranular pore throats and microcracks with a width of 100–0.2 lm as the throat, various pores and small dissolved pores are connected, forming a combination of reservoir and

505

permeation. These reservoirs typically have a higher porosity, lower permeability, lower yields, and slower pressure recovery. Based on the large-diameter core measurement, caving of wells and mud leaking statistics, logging, well testing, development dynamics, and ground simulation surveys in similar areas, the maximum porosity of different blocks of the Wumishan Formation in the Renqiu buried hill oilfield is 9.94% (If there is a big hole and a large hole development, it is another question). The minimum porosity is 2.51%, ranging between 8.07% and 2.78%, and the weighted average of the whole field is *6.0%. The permeability greatly varies from 8450–8.8
10−3 lm2 or low, typically ranging from 1000–500
10−3 lm2. The thickness of the reservoir in the Cambrian Fujunshan Formation accounts for 47.9% of the total thickness of the formation. The reservoir property is good, the pressure recovery is fast, and the oil layer is well connected. Based on the core analysis, the average effective porosity is 4.3% and the effective permeability is 635–2280
10−3 lm2, with an average of 1288
10−3 lm2. The physical properties of the Ordovician reservoir vary greatly. The porosity of the limestone is 0.41–5.4% and the permeability is 39–2140
10−3 lm2. The porosity of the dolomite is 0.60–11.3% and the permeability is 0.01– 9.97
10−3 lm2. (2) Analysis of the main controlling factors The formation of the ancient Renqiu oilfield buried hill carbonate oil and gas reservoir was controlled by many factors, which can be summarized as follows: sedimentation, diagenesis, tectonic stress, and karstification. These factors constrain each other and act together, forming the large and small dissolved pores and caves in the oil and gas reservoirs that can be observed today. The crisscross structural fractures have laid a reservoir foundation for the formation of buried hill carbonate reservoirs. The influences of dolomitization, silicification, compaction and dissolution, and recrystallization and filling on the diagenesis of the carbonate reservoirs of the buried hill have been discussed before and will not be further discussed here. A. Sedimentary microfacies control fracture–cave distribution The sedimentary facies determine the original pores and permeability of buried hill carbonate rocks. However, more importantly, the sedimentary facies factors directly or indirectly affect the developmental degree and evolution direction of other transformational forces, thus controlling the distribution of the fractures–caves in buried hill carbonate reservoirs. The Wumishan Formation in the Renqiu oilfield is in a sedimentary tidal flat–algae reef (beach)–tidal flat

506

21

Bohai Bay Basin

Table 21.4 Lithology and physical data of the Wumishan Formation in the Renqiu oilfield Facies belt

Tidal–flat facies

Lithology

Porosity (%)

Plane porosity of fractures– cavities (%)

Thickness of oil-bearing cores (%)

Fractures

Oiliness

Cavities

Total

Oil spot, oil traces

No display

Mud dolomite

1.12

0.53

0

0.53

0

0.5

99.5

Intraclastic dolomite

1.74

0.95

0.12

1.07

6.8

60.8

32.3

Micrite and powder crystal dolomite

1.95

1.04

0.08

1.12

0.8

66.3

32.9

Lamellar dolomite

1.42

0.95

0.08

1.03

5.1

64.3

30.6

Algal reef\algal beach facies

Clotted dolomite

3.56

1.12

0.82

1.94

10.7

84.4

4.9

Pyramidal stromatolite dolomite

3.33

0.85

1.88

2.73

Remarks

Based on the core data statistics

environment. Based on the core observations and physical property data (Table 21.4), the high-energy algal reef (beach) facies algae dolomite in the middle of the sequence has a coarse structure, intercrystalline pores, and dissolution pores and fractures are relatively developed. The porosity is generally greater than 3% and the oil content is high. However, the upper and lower parts of the sequence comprise low-energy tidal flat facies with a fine structure, intercrystalline pores, and no dissolution pores. The reservoir space is dominated by fractures. The plane porosity is less than 1% and most of them are non-reservoirs with poor oil-bearing display. This indicates that the primary sedimentary environment and facies belt control the distribution of the reservoir and that the algal reef (beach) facies are favorable facies zones for reservoir development. At the same time, the development and distribution of tectonic joints are also controlled by factors such as the lithology, rock texture, and strata thickness. The characteristics are as follows: ① The lithological sequence of the fracture development is as follows: argillaceous dolomite ! algae dolomite ! siliceous rock; ② Coarse texture rock cracks are common; fine texture rock cracks are less common; and ③ There the thin layer contains many fractures, which are narrow and short and mostly inner fractures. The fractures in the thick layer are small, the scale is large, and most of them are transverse fractures. B. Karstification controls the development and distribution of dissolved fractures–caves The Yanshanian Movement has resulted in extensive folding and block faulting of the Mesoproterozoic and Neoproterozoic–Lower Paleozoic massive thick carbonate rocks buried deep in the inner parts of the area and exposed at the surface before the deposition of the Tertiary, subject to weathering and erosion. The karstification lasted 1.48
108 and led to

the formation of many dissolution fractures–caves in the Mesoproterozoic and Neoproterozoic–Lower Paleozoic carbonates in this area, laying a foundation for the formation of buried hill reservoirs (Du et al. 2002). The karst of the carbonate rocks in the Renqiu buried hill is relatively developed and can be divided into three karst zones in the longitudinal direction. The general trend is “upwards strong and downwards weak”: First karst zone: from the weathering shell into the hill; more than 310 m thick. The blowout, leakage, and diameter enlargement phenomena during drilling were large in scale and frequency, accounting for 73.3% of the total. This shows that the fracture–cave network system is the most developed and the main reservoir section. Second karst zone: from the top of the buried hill down to *420–53 m, the thickness is *110 m. During the drilling, many blowout, leakage, and diameter enlargement phenomena occurred, accounting for 13.9% of the total. Third karst zone: from the top of the buried hill down to *620–670 m or even below 860 m. Blowout, leakage, and loss occurred during the drilling, accounting for 5% of the total and indicating the existence of a fracture–cave system, which can also be used as a reservoir.

21.2.5 Analysis of the Hydrocarbon Accumulation Process The central buried hill structural belt including the Renqiu oilfield experienced the following development stages: early uplift, middle burial, and late stability. The unique tectonic development history and tectonic features control the formation of the ancient buried hill tectonic belt, development of the fracture–cave reservoir, and distribution of hydrocarbon generation series of the semi-deep–deep lake facies, with superior hydrocarbon generation,

21.2

Renqiu Oilfield (Buried Hills of the Wumishan Formation …

Table 21.5 Variation of the uplift relift of the ancient Renqiu buried hill block (modified after Du et al. 2002)

507

Geologic epoch

Before the Kongdian Formation

Uplift relief (m)

1400

Relift varies (m)

/

migration–accumulation, and preservation conditions, thus forming the richness paleo-buried hill oilfield of great scale. Early uplift: The early uplift refers to the Renxi and Maxi faults, which control the formation of the buried hill structure and began to move violently, resulting in high mountains in the ancient geomorphology and forming the prototype of the ancient buried hill in the beginning of the Himalayan Period. At the same time, the Mesoproterozoic and Neoproterozoic carbonate rock experienced the Qinyu, Jixian, Caledonian, Hercynian, Indo-Chinese, Yanshanian, and Himalayan Movements, forming multi-stage ancient karst. In particular, the strong faulting–folding activities of the Yanshanian Movement resulted in strong uplift and denudation in this area, leading to the denudation of the Upper Paleozoic and the damage of the Lower Paleozoic, Mesoproterozoic, and Neoproterozoic. Thus, the carbonate rocks of the Mesoproterozoic and Neoproterozoic suffered from long-term weathering, denudation, and leaching, representing an important period of ancient karst development. Therefore, the early uplift of the ancient Renqiu buried hill led to the formation of the prototype of the buried hill structure and a reservoir with connected pores, holes, and fractures. The formation of this reservoir played a key role in the formation of the Renqiu oilfield. Middle burial: During the continuous activities of the mountain-controlling fault, the Paleogene Shahejie and Dongying Formations overburdened or covered the ancient buried hills and gradually buried them. In the early stage of the Paleogene fault depression, before the E3s2 deposition, the ancient mid-lake island of Renqiu was exposed and surrounded by the inherited Maxi, Mozhou, Renxi, and Hejian sedimentary fault troughs. Lacustrine oil-bearing rocks of the Eocene–Oligocene Es 3 and Es 1 were deposited. These strata were overlain on Renqiu high by the old to the new, gradually burying it. Until the middle and late sedimentary Es 2 period, the strata covered the ancient buried hill and the structural belt of the Renqiu buried hill was shaped. During this period, four oil-rich hydrocarbon sags, that is, the Maxi, Renxi, Hejianxi, and Luzhou Sags, formed around the Renqiu buried hill. The main aquifers of the first and third members of the Shahejie Formation have a high organic matter content and high conversion rate. The oil source is rich, the average content of organic carbon is 0.68– 3.01%, the average content of asphalt “A” is 0.05–0.48%, and the average potential pyrolysis yield of hydrocarbons

Before the Es 3

Before the Es 1

Before the Guantao Formation

Current

3000

3300

4300

4000

+1600

+300

+1000

−300

(S1 + S2) is 4.4–21.2 kg/t. The hydrocarbon content ranges from 257 to 2693 ppm. The thickness of the oil-generating strata accounts for 49.1–98.5% of the formation thickness and the oil-generating intensity reaches 500–1000
104 t/km2, providing a rich oil and gas source for the Renqiu oilfield. Because of the differential movement of the block faulting, the elevation of the uplift during the gradual burial of the Renqiu buried hills (Table 21.5). The subsidence of the surrounding sags resulted in the unconformity of Tertiary hydrocarbon source beds’ layers over the carbonate reservoir of the ancient buried hill, forming a direct connection between the hydrocarbon source rocks and reservoir rocks. The area of the source–reservoir connection on the unconformity surface (i.e., the northern, eastern, and southern sides of the buried hill) is *450 km2. The area of the source– reservoir connection of the Renxi fault section in the west is *90 km2 (Yi et al. 2010), thus forming an oil and gas migration channel with unconformity supplying oil to the buried hill and a relationship between the new source rocks and old reservoir rocks. At the same time, during the gradual deep burial of the Renqiu buried hill, its spatial position was in a relatively low potential energy zone, while the oil source rock was in a relatively high potential energy zone. Because of this great difference in the potential energy (at present, the minimum burial depth of the ancient Renqiu buried hill is 2587 m, while the maximum depth of the surrounding oil-generating sag is 5400–7000 m), the buried hill became the direction of long-term migration of oil and gas in the surrounding sags. Late stability: In the Neogene, the mountain-controlling fault became weak or stopped its activity when the area entered the depression development stage such that the tectonic activities in the area were stabilized and the ancient Renqiu buried hill could be well preserved. Since the Neogene, the ancient Renqiu buried hill has been further buried because of its weak tectonic activity and steady subsidence. On one hand, the oil and gas generated from the source rocks of the Lower Tertiary continue to accumulate in the ancient buried hill and the scale and enrichment degree of the reservoir are constantly increasing. On the other hand, the cap rock of the buried hill thickened, which led to a tight seal of the buried hill oil and gas reservoir. The ancient Renqiu buried hill was covered with two sets of regional cap rocks in the E3s2 and E3s1 periods of the Paleogene and two sets of local cap rocks in the E3d3 and E3d1 periods. The thickness

508 Table 21.6 Characteristics of the Tertiary cap rock overlying the ancient Renqiu buried hill (modified after Du et al. 2002)

21

Bohai Bay Basin

Formation

Thickness (m)

Sand/ground (%)

Thickness of the argillaceous rock (m)

Sedimentary microfacies

E3d1

200±

180

Interfluvial lowlands-lacustrine swamp microfacies

E3d2

300±

10±

270±

3

Shore–shallow lacustrine microfacies

E3d

300±

270

Upper E3s1

400±

320

Lower E3s1

180±

150

E3s2

200±

140

Total

1580±

15.8

>1330

of the cap rock is >1500 m (Table 21.6), the sand/ground ratio is very low (average of 15.8%), and the argillaceous rock is thicker than 1330 m, representing a shore-shallow lacustrine microfacies deposit. Therefore, it shows a good sealing performance. In addition, the E3s3, E2s4, and E2k lacustrine facies oil-generating strata are distributed at the slope of the buried hill, which also plays an important role in the sealing of oil and gas in these areas. In summary, there are three sets of hydrocarbon source layers around the Renqiu buried hill, that is, the Es 4–to Kongdian Formation, Es 3, and Lower Es 1. The main hydrocarbon source layer belongs to the Es 3 and Lower Es 1. Based on the results of oil generation research, the main oil-generating, oil drainage, and migration–accumulation periods of the source rocks of the Es 4–Kongdian Formation are the middle Paleogene Dongying (E3d) to Early Neogene Guantao Periods. The main gas-generating and drainage period occured from the end of the Neogene Minghuazhen Period to the Quaternary development period. The main oil generation period of Es 3 source rocks occurred from the end of E3d to the end of Ng and has not yet entered the mature gas stage. The main oil generation period of the Lower Es1 hydrocarbon source rocks started in the end of Ng and continued until now. This shows that the hydrocarbon source rocks around the ancient Renqiu buried hill began to enter the oil drainage period in the middle E3d (until now), but the main oil generation and migration periods occurred from the end of the Dongying Period to the Guantao Period. The ancient Renqiu buried hills mainly formed before the Cenozoic and the traps were shaped in the middle and late Es 2 stages and were inherited until the deposition of the Guantao Formation. In the Neogene, the ancient buried hills subsided with the overall depression of the central Hebei Depression and the uplift of the uplift was slightly reduced. Thus, the buried hill traps are formed first and the hydrocarbon generation, hydrocarbon drainage, migration, and aggregation periods are formed later than the traps. At the same time, the

depositional thickness of the strata in the sags in the periphery around the ancient buried hills increased during the Paleogene sedimentary process and the uplift of the buried hills increased. The hydrocarbons discharged from the hydrocarbon source layer in the high-energy zone were continuously transported and enriched in the ancient buried hill reservoirs in the low-energy zone, thus forming the ancient Renqiu buried hill enriched in high-yield and large oilfields.

21.3

Niudong Gas Field

21.3.1 Geographical Location and Regional Geological Background 21.3.1.1 Geographical and Regional Structural Locations The Niudong buried hill oil and gas field (reservoir) is in Xiongxian County, Hebei Province, and tectonically located on the downthrown block of the steep side boundary fault, that is, the Niudong Fault, in the west of the Baxian Sag, central Hebei Depression, Bohai Bay Basin (Zhao et al. 2011b). The Baxian Sag is a Cenozoic dustpan-like fault depression in the north–central part of the central Hebei depression, which is NE-striking, faults in the west and overlaps in the eastward. The Niutuozhen Uplift is in the west and north of the sag. The Wen’an slope in the southeast of the sag transferred to the Dacheng Uplift and the Raoyang Sag is connected to the sag in the southwest (Fig. 21.4), with an area of *2,400 km2 and a maximum deposition thickness of *10,000 m. The main exploration targets are the Neogene Guantao, Paleogene Dongying, and Shahejie Formation and the basement of the buried hills of the Ordovician, Cambrian, and Jixian Wumishan Formation. On May 11, 2010, well Niudong well 1 in the Cha 71 buried hill traps in the Niudong buried hill belt was deployed in the Wumishan Formation to a well depth of 6200 m. The

21.3

Niudong Gas Field Ba28

Xiong11

0

Cha33-19

Cha38

509 Niudong1

Wengu3 Wan'an1 (projection)

Xinglong1

Wen48 Su68

Wen51 Wen102

Wen20-20

Su71

Da6(projection)

Wen95

2000

0

NQ

N Q

1000

1000

NQ Jx w Jx y Ch g-

Es

N Q

Mn

Ch t

Mn

Ch ch c Ch

2000

Ed

Ar

CP

3000

CP

3000

Es1 O

Es2

4000

4000

1f

Qb

Legend

5000 6000

1m

3f

Es3

5000

Jxw

Scale

Es4 Ek caprock

7000 oil reservoir

mature high maturity source rock source rock

gas reservoir

sand layer

low maturity metamorphite source rock fractures and pores

Niutuozhen Salience

0

2.5

5km

6000 7000

glutinite

Jxw

Baxian Sag

Wen’an Slope

Dacheng Salience

Fig. 21.4 Hydrocarbon accumulation profile for the Bazxian Sag Fig. 21.5 Structural map of the buried hill top in the Niudong area

well was drilled at a depth of 5639 m and encountered the carbonate buried hill of the Jixian system Wumishan Formation, has a drilled depth of 6027 m, the thickness of the Wumishan Formation was drilled to be 388 m. On May 1, 2011, a large-scale deep acid fracturing transformation was carried out in the 5641.5–6027 m well section. A 16 mm choke and 63.5 mm orifice plate were used for the production. The daily crude oil was 642.9 m3, the natural gas was 56.3
104 m3, and the bottom hole temperature was 201 °C. The carbonated ancient buried hill reservoirs with the highest depth and highest temperature in the Bohai Bay Basin, and even in eastern China, were discovered (Fig. 21.5).

21.3.1.2 Regional Strata The Niudong buried hill oil and gas reservoir is in the deep sub-sag of the Baxian Sag. Although it has been subjected to long-term weathering and erosion, the distribution of the buried hill strata in the Baxian Sag has a certain regularity. From west to east and from low to high, it includes the Jixian, Qingbaikou, Cambrian, Ordovician, and Carboniferous–

Permian, with an inverted wedge distribution. The exposed surface layer at the top of the Niudong buried hill comprises the carbonate rock of the Wumishan Formation in the Middle and Upper Proterozoic, with a thickness of 250–500 m. The buried hill’s direct draping and lateral juxtaposition strata are the Paleogene Es 4 and Kongdian Formation. The thickness of the overburden layer is *5640 m including 1468–1935 m thick Neogene fluvial facies and 2600– 3987 m thick Paleogene fluvial–lacustrine facies strata.

21.3.1.3 History of the Tectonic Evolution The Baxian Sag is similar to the Raoyang Sag. Both are in the central Hebei Depression. They are inherited single-fault dustpan-like sags, which rupture in the west and overlap in the east controlled by the Niudong Fault. The complex geological structure of the Baxian Sag is characterized by the superposition of the Paleozoic–Mesoproterozoic, Neoproterozoic craton, and Paleogene and Neogene faulted rift– depression. The tectonic evolution of the Baxian Sag is the same as that of the Renqiu buried hill in the central Hebei Depression (see above).

510

21.3.2 History of the Discovery of Oil and Gas Fields The Niudong 1 buried hill oil and gas reservoir is not only buried deep, but, more importantly, is in the “sag (depression)” and has a strong concealment. Therefore, the exploration and discovery were relatively long. They can be roughly divided into four stages.

21.3.2.1 Failed in the First Exploration (1977–1978) In 1975, the Renqiu oilfield was discovered in the central Hebei Depression, that is, the first large high-yield oilfield of Mesoproterozoic marine carbonate buried hills in China, which initiated a new field for oil exploration in buried hills. The theory of “New source and Paleo-reservoir” buried hill reservoir formation was established, laying the practical and theoretical foundation for the exploration and development of buried hill oil and gas reservoirs. After the discovery of the Renqiu oilfield, a set of buried hill oil and gas fields, such as Nanmeng, Longhuzhuang, Balizhuang, Xuezhuang, Yanling, Hejian, Liubei, and Suqiao, w discovered in less than ten years. The first peak of reserve growth in the exploration of buried hills in the Central Hebei Depression was reached. During this period, the Niudong area of the Baxian Sag was also one of the main exploration areas for buried hills. Based on the structural anomaly of the residual gravity discovered using 1:100000 and 2D seismic exploration between 1977 and 1978, three buried hill wells, that is, wells Jia 4, Jia 6, and Xinjia 4, were drilled in the Niudong area (Du et al. 2012). Limited by the data at that time, the deep buried hill structure high point was not accurate, the drilling load capacity was insufficient, and the buried hill stratum was encountered in none of the three wells. Subsequently, the exploration of buried hills in the area had been in a state of stagnation for more than 20 years. 21.3.2.2 Re-Failed in the Second Exploration (1998–2004) In the 1990s, the development of 3D seismic exploration technology and high-precision gravity, magnetic, and electric exploration technology provided new technical support for deep buried hill exploration. From 1997 to 1998, the Su 49 buried hill condensate gas reservoir with a depth of 4743.5 m was discovered in the Xin’an Town area, Baxian Sag, using high-precision gravity, magnetic, electrical, and 3D seismic data. Based on the oil test, crude oil content per day was 50.1 t and the natural gas content was 16.3
104 m3, which revived the deep buried hill exploration that had been stagnant for many years. Based on the successful exploration experience with the Su 49 buried hill, 15000 high-precision gravity and magnetic

21

Bohai Bay Basin

exploration covering an area of 343.25 km2 was redeployed in the Niudong area (then called Xinglonggong area) from 1998 to 2002 and three 41 km continuous electromagnetic array CEMP profiles and one 23.4 km wide 2D seismic profile were completed. The new round of exploration studies indicated the existence of buried hill traps in the Niudong area. However, because the area is close to the Niutuozhen bulge, the gravity, electromagnetic, and seismic wave fields were shielded or serious interfered by the bulge. The depth of the buried hill was far higher than that of the Su 49 buried hill. Therefore, two interpretation schemes were established, that is, the interpretation scheme of a fault terrace mountain with a buried depth between 5500–6500 m (referred to as “Deep Scheme”) and the interpretation scheme of a fault horst mountain with a buried depth between 4500–5000 m (referred to as “Shallow Scheme”), which were highly controversial and led to great difficulties regarding exploration decisions. In 2002, to further implement buried hill traps, conventional 3D seismic data in an area of 87.6 km2 were collected during the deployment of the 3D seismic blank area in this region and the data were processed by merging with existing 3D seismic data for the surrounding area. The merged 3D seismic data covered 520 km2, that is, the potential development area of buried hills. The data processing focused on deep reflection and the data were interpreted using the new merged data. It was recognized that the “Deep Scheme” fault terrace mountain is more likely, but it was also recognized that the “Deep Scheme” buried hill is covered by the strata of the Es4–Kongdian Formation. Because a set of sediments formed in the early stage of the fault depression, the hydrocarbon source layer of the Es4–Kongdian Formation is generally poor in quality and unstable in the whole area of the central Hebei Depression. The strata that were revealed around the Baxians are mostly red or red and interstratified layers, which are poor hydrocarbon to non-hydrocarbon source layers, directly leading to the uncertainty in the oil and gas source conditions of the “Deep Scheme” buried hill in the area, and the drilling of the “Deep Scheme” buried hill investment is huge, making drilling work again failed.

21.3.2.3 Renewed Hope (2005–2006) In 2005, the Xinglong 1 well was deployed in the Niudong area of the Baxian Sag, aiming at the Es 3 stratum–lithology trap. When the Xinglong 1 well was drilled to 4780 m, the drilling technology and casing procedure were simplified in view of the gypsum rock layer, which was thought to exist, and to deepen the drilling of the “Shallow Scheme” buried hill. The drilling results confirmed that the “Shallow Scheme” buried hill did not exist, but medium–good source rock of the ES 4–Kongdian Formation was discovered. The

21.3

Niudong Gas Field

thickness of the ES 4–Kongdian Formation in the Xinglong 1 well is 1071 m (not penetrating; according to seismic data, it was estimated that the thickness can reach 2500 m). The strata include the lacustrine facies. The dark and carbonaceous mudstones are 574 m thick, the average organic carbon content is 2.05%, the hydrocarbon generation potential is 3.74 mg/g, the chloroform asphalt “A” content is 0.1389%, and the organic matter type is type II2, indicating that the maturity–high maturity stage was entered. The drilling of the Xinglong 1 well changed the previous understanding that there may be a lack of oil and gas sources in the deep layer and the ES 4–Kongdian Formation was determined to be the main source rock of the deep layer. It was confirmed that the deep layer oil and gas resources in the Baxian Sag are very rich, thus leading to new hope regarding the exploration of the ultra-deep buried hills in this area.

21.3.2.4 Major Breakthroughs (2007–2011) Since 2007, the fine secondary exploration project characterized by high-precision secondary 3D seismic exploration in some oil-rich sags has been vigorously implemented in the central Hebei Depression and the deep buried hill and its interior have been identified as key fields. Based on high-precision secondary 3D seismic data acquisition and large-area data merging, research on “Four Fine studies and One Innovation” of the fine stratigraphic contrast, fine structure interpretation, fine reservoir evaluation, fine oil source analysis, and innovative accumulation model has been vigorously carried out. A series of new models got concealed deep buried hills and interior buried hill accumulation, such as “old reservoir– & old sealing,” “red cap & rock lateral migration,” “slope flank stratified reservoir,” and “huge burial hill–& top accumulation” were proposed. Several high-yield concealed buried hill oil and gas reservoirs, such as Changyangdian, Suning, Wen’an, and Sunhu were discovered. The exploration of these hidden buried hill oil and gas reservoirs led to a new geological understanding of oil and gas accumulation, but also greatly increased the confidence in continuing to enter the ultra-deep hidden buried hill oil and gas reservoirs. In 2009, it redeployed and implemented high-precision acquisition of secondary 3D seismic data with full coverage (an area of 218 km2) in Niudong area and pre-stack depth migration processing was conducted in a 125 km2 target area of the Niudong buried hill. The quality of the newly collected and processed data had greatly improved. The characteristics of the reflected wave group of the Niudong deep buried hill were determined. It has a fault terrace mountain structure. Based on the fine structural interpretation of the seismic data, the Niudong buried hill structural belt is composed of three large-scale fault terrace buried hills

511

covering a total area of 58 km2 (Figs. 21.4 and 21.5). The Cha71 buried hill head is the shallowest, with a high point of 5640 m, which is basically consistent with the high point and buried depth indicated by high-precision gravity and magnetic exploration. The comprehensive evaluation of the buried hill indicated early uplifting, burial, and stabilization. It is directly covered by high-quality source rocks of the Es 4–Kongdian Formation with favorable oil and gas sources and preservation conditions. Based on these results, the risk exploration well Niudong 1 was drilled and the daily oil and gas (equivalent) output beyond 10,000 cubic meters in Jixian County was obtained, representing a major breakthrough in the oil and gas exploration in ultra-deep buried hills. Well Niudong 1 was deployed and a daily oil and gas (equivalent) production of more than one thousand square meters was obtained, that is, high-yield industrial oil and gas flow, in Wumishan Formation Jixian system, representing a major breakthrough in the exploration of oil and gas in ultra-deep buried hills (Zhao et al. 2011a).

21.3.3 Characteristics of the Niudong Buried Hill Oil and Gas Reservoir 21.3.3.1 Trap Characteristics of the Oil and Gas Fields (Reservoirs) The Niudong buried hill structural belt is a fault terrace buried hill structural belt with a downthrown block of the Niudong Fault in the steep belt of the western Baxian Sag, which is distributed in a NNE-trending strip. It mainly includes three fault noses, that is, the Niudong 1, Xinglong 1, and eastern Xinglong 1 buried hills. It is notably inclined from north to south. It is entered into the main Baxian Sag in the north and Modong Sag in the south. The faults of the Niudong buried hill structural belt are relatively developed, mainly including the large sag-controlling boundary faults of Niudong and their derivatives and the NNE–NEE-trending mountaincontrolling Cha 71, Xinglong 1, and Xinglong 1 east faults (Table 21.7). The faults mainly formed in the early stage of the sag activity, ending in the middle–end stage of the Paleogene, with large fault distances and long extensions. At the same time, a set of NW-trending faults was developed, which control the sedimentation of the Paleogene Es4–Ek strata in the Baxian Sag. The Niudong 1 buried hill is in the western part of the Niudong buried hill structural belt. It is a fault-nose hill controlled by the Cha 71 fault and buried hill dip toward the north, west, and south. The strata in the main part of the buried hill comprise the fourth member of the Wumishan Formation. The high point of the trap is 5600 m, the amplitude is 740 m, and the trap area is 13.2 km2.

512

21

Bohai Bay Basin

Table 21.7 Fault elements of the Niudong buried hill belt Fault number

Fault name

Fault property

Fault throw in aimed layer (m)

Dip strike

Penetration well

Strike

Trend

Dip (°)

1

Niudong

Normal fault

5000–7000

NNE

SEE

40–45

2

Cha 71

Normal fault

550–1050

NNE

SEE

45–55

3

Xinglong 1

Normal fault

250–700

NEE

SE

35–55

4

Xinglong 1 east

Normal fault

150–650

NEE

SE

35–45

5

Gaojiapu

Normal fault

200–1700

NW

NE

40–55

21.3.3.2 Reservoir Characteristics and Development Status The Niudong 1 buried hill reservoir of the Wumishan Formation is a condensate gas reservoir without an oil ring. It was predicted that the reservoir has an oil-bearing area of 13.2 km2, condensate gas reserves of 368.26
108 m3, and condensate oil reserves of 3274
104 t, equivalent to 6208
104 t oil. Based on the parameters of the Su1 buried hill gas reservoir in the Suqiao gas field, Wen’an slope, Baxian Sag, the natural gas recovery rate is 60%, the condensate recovery rate is 40%, the recoverable reserves of natural gas are 220.96
108 m3, and the technically recoverable reserves of condensate are 1309.6
104 t. The depth of the Niudong 1 buried hill gas reservoir is 5835.2 m, the formation pressure is 57.60 MPa, the pressure coefficient is 1.01, and the formation temperature gradient is 2.79 °C/100 m, representing a normal pressure and temperature system. An evaluation well was drilled in the Niudong buried hill oil and gas reservoir, that is, the Niudong 101 well, and a production test was performed in September 2011. In the initial stage, the oil and gas output in the well was 40–60 t/d and 9–12
104 m3. In the later stage, the daily output of oil and gas was *8t and 0.2–2
104 m3, respectively. After 3 years of production, the oil pipe was shut down due to paraffin clogging. The cumulative oil and gas production was 4.06
104 t (oil) and 1.03
108 m3(gas).

21.3.4 Characteristics of the Main Oil and Gas Reservoirs 21.3.4.1 Lithologic Characteristics of Oil and Gas Reservoirs The main oil-bearing strata of the Niudong 1 oil and gas field is the Wumishan Formation of the Jixian system. Based on the fine stratigraphic comparison, it belongs to the fourth member of the Wumishan Formation. Based on the logging, cuttings, and thin sections of the Niudong 1 well, the Wumishan Formation mainly comprises micritic to fine-crystalline dolomite, micritic to granular dolomite, breccia dolomite, and

Xionggu 1 Xinglong 1 Jia 16, new Jia 4

medium-fine–medium-coarse dolomite. The micritic to fine-crystalline dolomite is mainly composed of micrite and micro- to fine-crystalline dolomite, often with lamelliferouslayers. The original rocks are mostly (or rich) algae dolomite and dissolution pores are not developed. The micritic to granular dolomite mainly comprises sand cuttings and oolites due to the relatively high hydrodynamic condition of the tidal flat facies epeiric sea environment. Early dissolution pores are developed and the adjacent micritic to fine-crystalline dolomites are again subjected to long-term surface solution, causing the dissolution, collapse, and formation of breccia dolomite. The lithology mainly includes medium-coarse unequal dolomite crystals and fine–medium-coarse dolomite crystals, but the degree of crystal automorphism is low, mostly xenomorphic, with a small amount of subhedral.

21.3.4.2 Diagenesis The diagenesis of the Wumishan Formation in the Niudong buried hill oil and gas field mainly included dolomitization, silicidation, compaction and pressure dissolution, recrystallization, dissolution and filling, and structural rupture (slightly). The dolomitization, dissolution, and structural rupture are extremely important for the reservoir development. 21.3.4.3 Analysis of the Reservoir Physical Properties and Main Controlling Factors (Sedimentation, Diagenesis, and Pore Evolution) Based on the thin sections data, the main reservoir space of the Wumishan Formation in the Niudong 1 well includes the structural and tectonic-dissolving fractures; dissolved pores are rare (Table 21.8) because the observed sample is a cuttings sample. Based on the logging interpretation, the reservoir is a fractured reservoir, the porosity is generally 4–12%, the permeability is 1–500 mD, and the reservoir performance is relatively good. Based on the drilling data, the Niudong 1 well’s cumulative loss of drilling fluid is 93.50 m3 in the 5639.00–5641.57 m section and the leakage velocity is 2.5 m3/h. The cumulative loss of drilling fluid in the 6003– 6004 m section is 120.65 m3 and the leakage velocity is

21.3

Niudong Gas Field

513

Table 21.8 Statistical table of the main reservoir space of the rock in the Wumishan Formation of well Niudong 1 (cuttings samples) Layer

The first oil group of the fourth member

Second oil group of the fourth member

Depth (m)

Lithology

Fracture

5640

Including fine-crystalline, micritic dolomite

Tectonic fracture

5676

Including fine-crystalline, micritic dolomite

5700

Type

Width (lm)

Filling ingredient

Filling method

5

40– 400

Dolomite, calcite, siliceous

Full

Tectonic solution fracture

1

10– 250

Dolomite, muddy organic matter

Full

Including fine-crystalline, micritic dolomite

Tectonic fracture

1

60–90

Dolomite

Full

5761

Micritic dolomite

Tectonic, tectonic solution

12

10– 250

Dolomite

Full

5824

Calcsparite grain dolomite

Tectonic fracture

2

10–20

Dolomite

Full

5832

Fine-crystalline, micritic dolomite

Tectonic solution fracture

2

50– 200

Siliceous dolomite

Semi-filling or complete filling

1.0%)

Biogenesis, pyrolysis (Ro >0.4%)

Tectonic reformation

Several strong tectonic movements since the Later Paleozoic

Several strong tectonic movements since the Mesozoic

Several strong tectonic movements since the Late Mesozoic

Formation stress

Low–normal

Normal–high

Normal–high

Development scale

Regional, badly eroded

Regional

Local, affected by the current basin

Main distribution

South China, NW China, Tibet

North China, South China

East China, NW China

Storage medium for free gas

Dominated by fractures and micropores

Pores and clastic interlayers

Fractures, pores, and clastic interlayers

thick layers of dark shale. The association of marine carbonates with shale results in the considerable calcareous shale content. A large amount of plankton provides abundant organic sources, providing the basis for the generation of hydrocarbon. The major rock types contain marine, calcareous, calcium, and siliceous shales. Most of the shale is black, gray black or dark gray and rich in dispersive and disseminated organic matter. Most of the kerogen is sapropelic (type I) and mixed (type II). The argillaceous content is low, while brittle material dominated by calcareous and siliceous minerals is abundant. Lamellar and strawberry-like pyrite is common. The development of marine organic-rich shale in China mainly occurred in the Early Paleozoic. It is primarily distributed in western and southern China in the Lower Cambrian, Upper Ordovician–Lower Silurian, Middle Devonian, Lower Carboniferous, and Upper Permian. The shale of the Lower Cambrian and Upper Ordovician Wufeng and Lower Silurian Longmaxi formations is rich in organic matter. It is widely distributed, has a high organic matter content, and forms thick single layers. It is one of the formations with high potential for shale gas exploration in China. Therefore, this chapter will put emphasis on the introduction of these two formations.

22.1.1 Lower Cambrian The organic-rich shale in the Lower Cambrian is mainly distributed in the Tarim Basin and South China. The burial depth of the Cambrian source rock is >5000 m in the Tarim Basin, which leads to difficulties in the shale gas exploration and production (small scale). However, the Middle–Lower Cambrian organic-rich shale is one of the best source rocks. It covers a large area and has a high organic matter abundance and large resource volume. The organic matter-rich shale in the Lower Cambrian in South China is widespread and buried at moderate depth. It is one of the most important target layers in shale gas exploration. This section will focus on the characteristics of organic-rich shale in the Lower Cambrian in South China. Organic matter-rich shale is abundant in the Lower Cambrian. It comprises dark shale, black carbonaceous shale, carbonaceous and siliceous shale, black nodal phosphorite, black silty shale, and stone coal. The Lower Cambrian shale is widespread in South China and is distributed in almost the whole Yangtze River Valley, with a large thickness of 20–300 m, covering an area of *58  104 km2. For more details about the distribution, please refer to Chap. 3.

22.1

Characteristics of Marine Shale in China

519

22.1.1.1 Geochemical Characteristics The TOC (total organic content) content of the marine shale of the Lower Cambrian in South China is high and mostly >2%. The Lower Cambrian series formed under the quick transgression and slow regression in the early stage. The early stage is a deep-sea shelf, while the late-stage regression led to shallow water depth in the Early Cambrian. Therefore, black shale with a high content of organic matter is mainly distributed in the lower part of the Lower Cambrian and the TOC content decreases upward (Fig. 22.1). The organic matter is dominantly sapropelic matter and lower plankton is an important hydrocarbon generation material. The source rock in the Lower Cambrian is overmature (Ro of 2.5–4.5%). The Cambrian around the paleo-uplift, for example, the Chuanzhong paleo-uplift in the Sichuan Basin and Huangling paleo-uplift in the middle Yangtze area, has a relatively low maturity (Ro of 2.0–2.5%). The analysis of hydrocarbon inclusions and the burial history of Cambrian in Dingshan at the southern margin of the Sichuan Basin shows that the Lower Cambrian source rock reached the oil generation threshold in the Early Ordovician, oil generation peak in the Late Silurian, high maturity stage in the Early Permian (wet gas and condensate oil stages), and overmature dry gas stage in the Early Triassic. In the meantime, the crude oil that had accumulated in the Dengying formation in the Sinian system cracked into dry gas caused by high temperatures (Fig. 22.2).

22.1.1.2 Shale Reservoir Characteristics The dark shale in the Lower Cambrian forms a reservoir with low–ultralow permeability. Micrometer–nanometer-sized pores of various pore types have been determined to be developed using argon ion polished specimens and SEM (scanning electron microscope). Well Jinye1 was the first exploration well for shale gas in the Cambrian in the Sichuan Basin, which showed a high production. The reservoir space includes organic matter pores, inorganic mineral pores, and microfractures. The inorganic mineral pores are mainly composed of pores in the interlayers of clay minerals, interparticle pores in brittle minerals, intraparticle dissolved pores, and intergranular pores in pyrite. The organic matter pores are generated in the later thermal evolution in the organic matter. The microfractures can be divided into structural, diagenetic, and dissolved microfractures. Based on the minerals the pores are associated with, these pores can be divided into three types, that is, pores in organic matter, brittle minerals, and

TOC(%)

(m) 140

The thermal evolution in the Sichuan Basin occurred relatively late in the early stage of the oil generation in the Late Silurian. It includes the large oil generation stage in the Late Permian, wet gas and condensate oil stage in the Late Triassic, and overmature dry gas stage in the Jurassic. The degree of thermal evolution has a trend from early (basin margin) to late (inner basin; Fig. 22.3).

0

2

TOC(%) 4

(m)

6

140

120

120

100

100

0

90m 80

1

1

q

n

80

60

40

60m 44m

60

40

20

20

0

0

Fig. 22.1 Vertical variation characteristics of organic carbon in the Lower Cambrian source rock

2

4

115m

6

8

10

520

Resource Potential and Exploration Progress of Shale Gas …

22 Z2

0

O1 O2

S3 D1

C1

C2 P1

T3 J1 J2 J3

K1

K2

E

Ro (%)

Legend

N

30

0.50-0.70 50 0.70-1.30

70

200

90 1.30-1.60 110

1.60-

130

400

170

150

190

210 600 230

250

800

640

480

320

160

0

t=0

Time(Ma)

Fig. 22.2 Hydrocarbon history of the Lower Paleozoic source rock in the Dingshan-1 well in the southeastern part, Sichuan Basin

Ma

550

C

Ro=0.5~0.7%

500

450

0

Ro=0.7~1.3%

400

S

350

D

300

C

250

P

Ro=1.3~2.0%

200

T3

150

J1~2

J1

100

K1

50

K2

Ro=2.0~4.0%

Fig. 22.3 Comparison of the thermal evolution in the Lower Cambrian source rock in the upper–middle Yangtze region

E

0

N~

22.1

Characteristics of Marine Shale in China

521

Table 22.2 Statistics for the reservoir space categories of the Qiongzhusi Formation in the southern Sichuan Basin Pore type

Main characteristics

Influencing factor

Pore scale and diameter

Contribution to the reservoir

Organic matter pores

The decrease in the volume and exhaust of gas of the organic matter after hydrocarbon generation results in pores forming honeycomb, line, bead or complex net structures

TOC, degree of thermal evolution

50– 200 nm

widespread

Porous interlayers of clay

Distributed in flaky clay minerals in slit or wedge shape

Related to sedimentation and diagenesis

50– 700 nm

widespread

Pores in brittle minerals

Interparticle pores

Grain-supported sedimentary structure. Pores have irregular shapes, form beads or dispersed

Related to sedimentation and diagenesis

0.2– 1.7 lm

Small distribution with bad connection

Intraparticle dissolved pores

The intraparticle isolated pores are formed by corrosion in minerals

Increase as the yield of organic acid

0.4– 2.8 lm

Many pores with bad connection

Intergranular pores in pyrite

Intergranular micropores in dispersed distribution

Related to the deposition of pyrite

100– 800 nm

Small distribution with bad connection

Photographs taken under the microscope (well Jinye 1)

(continued)

522

22

Resource Potential and Exploration Progress of Shale Gas …

Table 22.2 (continued) Pore type

Microfractures

Main characteristics

Influencing factor

Pore scale and diameter

Contribution to the reservoir

Structural fractures

Rock rupture created by tectonic stress. The strike is attributed to the direction of the stress

Tectonic

0.4– 2 lm

Many pores with good connection

Corrosion fractures

Fluid dissolved the solvent-sensitive composition in the process of passing the fracture. It shows a curved shape

Corrosion

0.2– 0.5 lm

Small distribution with good connection

Diagenesis fractures

Dewatering, cracking or recrystallization during diagenesis

Increase as the burial depth and thermal evolution advance

0– 0.2 lm

Small distribution with bad connection

interlayers of clay minerals. The pores in interlayers of clay minerals represent the main pore type (Table 22.2; Fig. 22.4). The porosity of the reservoir is 1.49–4.67%, with an average of 2.91%. The horizontal permeability determined using the pulsed method is 0.0002–1.5012  10−2 lm2, with an average of 0.2512  10−2 lm2.

22.1.1.3 Petrological and Mineralogical Characteristics The statistical analysis of 142 shale samples of the Lower Cambrian in the central–upper Yangtze area indicates a quartz content of 20.7–80% (average 49.59%), potassium feldspar content of 0–5.8% (average 1.44%), anorthosite content of 0–26.5% (average 9.24%), calcite content of 0– 19% (average 1.01%), dolomite and ferrodolomite content of 0–43% (average 1.09%), siderite content of 0–12% (average 0.37%), pyrite content of 0–10% (average 0.52%), and clay content of 15–71.8% (average 36.03%). The clay content of

Photographs taken under the microscope (well Jinye 1)

the Lower Cambrian shale is low, but that of brittle minerals is relatively high, similar to Barnett shale in the Fort Worth Basin, USA. The reservoir of Lower Cambrian is favorable for reservoir fracturing and reformation (Fig. 22.5).

22.1.2 Upper Ordovician–Lower Silurian Organic matter-rich shales, which developed in the Upper Ordovician Wufeng formation and Lower Silurian Longmaxi formation in South China, represent the main strata for commercial shale gas production in China (Fig. 22.6). In the Late Caledonian, affected by the collision and extrusion between the Cathaysian and Yangtze plates, a cratonic sag had developed in North Guizhou, South Sichuan, East Sichuan, and West Hubei. An occlusive–semiocclusive or non-compensatory anoxic environment formed and organic matter-rich shale was deposited in the Upper Ordovician

22.1

Characteristics of Marine Shale in China

0

20

40

523

60

80

100

3287.6 3291.215 3295.365 3297.27 3301.385 3304.865 3403.16 3407.755 3412.22 3415.89 3417.33 3523.01 3526.125 3530.115 3533.37 3537.63 3540.965 3544.905 3549.135 3552.69

Fig. 22.4 Porosity in the Jinye-1 well and Weiyuang area in the Sichuan Basin

Wufeng and Lower Silurian Longmaxi formations. This shale is mainly composed of siliceous or graptolite-bearing carbonaceous mudstone. The Wufeng shale is 4–10 m thick in the Middle and Upper Yangtze areas, and 20–30 m thick in the Lower Yangtze area. The Longmaxi shale is thicker in the Upper Yangtze area, with a maximum thickness of more than 300 m, while the thickness in the Middle and Lower Yangtze areas is less than 200 m. For more details, please refer to Chap. 3.

22.1.2.1 Organic Geochemical Characteristics The TOC values of the shale in the Wufeng and Longmaxi formations in the middle–upper Yangtze area vary between 0.5 and 4.0%, with a maximum of 8.6%. Vertically, the shale rich in organic matter is mainly at the bottom of the Wufeng and Longmaxi formation. The TOC content gradually decreases upward (Fig. 22.6). The organic-rich shale is primarily siliceous and carbonaceous in deepwater shelf facies in the TST (Transgressive system tract). The TOC content of the shale in well Jiaoye1 in the Jiaoshiba area in Fuling is >2%, with a maximum and average content of 5.89% and 3.5%, respectively. A successive accumulative thickness is 38 m. This shale in the Wufeng and Longmaxi formations represents the primary stratum for the current commercial shale gas production. The main type of organic matter in the shale in the Wufeng and Longmaxi formations is type I, with a small amount of type II1. The main source materials are plankton,

Fig. 22.5 Mineral composition of the Lower Cambrian shale in the middle–upper Yangtze region

100

0 1 20

80

1

60

40

40

60 Batnett

20

80

100

0 100

80

60

40

20

0

Fm.

8 0

Ro 4

Fm. 0

Longmaxi Fm. 4360

4340

4320

4300

4280

4260

Depth Lithology 0

TOC 8 0

Ro 4

Fm.

Ro 4

Fm. 0 300

GR

2400

2380

2360

2340

2320

2300

Depth Lithology 0

8 0

Ro 4

Fm. 0

Wufeng

8 0

Linxiang

TOC

Caogou

0

Wufeng

4400

4380

4360

4340

4320

4300

Depth Lithology

Wufeng

300

GR

Linxiang

0

TOC

Well Jiaoye 1

Fig. 22.6 Comparison of the organic geochemical index for the lower part of the Wufeng–Longmaxi formations, Sichuan Basin

300

GR

Longmaxi Fm.

Caogou

4040

0

Longmaxi Fm.

Wufeng

Longmaxi Fm.

4020

4000

3980

3960

3940

Depth Lithology

Well Nanye 1

Longmaxi Fm.

Wufeng

300

GR

Well Dingye 2HF 300

GR

2160

2140

2120

2100

2080

2060

2040

Depth Lithology

0

Well Peng 1 TOC 8 0

Ro 4

22

Linxiang

0

TOC

Well Renye1

524 Resource Potential and Exploration Progress of Shale Gas …

22.1

Characteristics of Marine Shale in China

Ma

400

525 350

D

Ro=0.5~0.7%

300

C

Ro=0.7~1.3%

250

P

200

T3

Ro=1.3~2.0%

J1~2

150

J3

100

K1

K2

50

0

E

N~Q

Ro=2.0~4.0%

Fig. 22.7 Comparison of the thermal evolution of the Lower Silurian Longmaxi formation in different areas, Sichuan Basin

bacteria, and algae. The Ro value of the shale in the bottom of the Wufeng and Longmaxi formations in the Upper Yangtze area is 2.0–3.0%, which indicates that it has entered the overmature evolution stage and dry gas is the main product. The Ro in the southwestern Sichuan Basin is 3.0– 3.5%, with a relatively high thermal evolution degree that can be attributed to the abnormal heat flow caused by a mantle plume in the Early Permian. The thermal evolution degree is relatively low in the middle Yangtze region, with a Ro value below 2.4%. The Ro value in the lower Yangtze region is 2.0–3.0%. The comparison of the thermal evolution history of the source rock of the Longmaxi formation in different areas in the Sichuan Basin shows that the Lower Silurian source rock entered the mature stage in the Permian, oil generation peak in the Triassic, wet gas condensation oil stage in the Middle Jurassic, and overmature stage in the Late Jurassic. The basin margin entered the mature stage earlier. For example, the Lower Silurian source rock in well Jianshen 1 reached the threshold of oil generation in the Early Permian, oil generation peak in the Late Permian, wet gas condensation oil stage in the Middle Triassic, and overmature dry gas stage in the Early Jurassic (Fig. 22.7). The source rock in the inner basin reached the overmature stage and was uplifted much later, which is advantageous for the preservation of shale gas.

22.1.2.2 Shale Reservoir Characteristics The reservoir space of the shale in the Wufeng and Longmaxi formations is similar to that of the Lower Cambrian, including organic pores, inorganic mineral pores, and microfractures. The inorganic pores primarily include interlayer pores in clay minerals, interparticle pores in brittle

minerals, intraparticle corrosion pores, and intercrystalline pores in pyrite. The porosity of the organic pores in the shale gradually decreases and the clay content increases upward in the Wufeng formation and the first member of Longmaxi formation (Fig. 22.8). The proportion of organic pores is the highest at the bottom of the Wufeng and Longmaxi formations. The proportions of different types of pores vary in the same layer in different areas. For example, the organic pores and interlayer pores in clay are the dominant types in the Jiaoshiba area in Fuling, accounting for up to 90% of the total porosity. The pores in brittle minerals account for less than 10% of the pores. The organic pores are the dominant pores in the Wufeng formation and sub-member 11 of the Longmaxi formation with high TOC and low clay contents, account for 50% of the total porosity, with a maximum of 76%. However, the pores in inorganic minerals in the Dingshan area occupy the largest proportion, with up to 60– 90% of the total porosity, while the organic pores account for less than 10–40%. The Wufeng formation and sub-member 11 of the Longmaxi formation have high TOC content and brittle mineral contents, which leads to more organic pores (22–55%) and pores in brittle minerals (30– 48%). Because the tectonic movement in South China is intensive, several detachment layers are present at the bottom of the Longmaxi formation in several locations outside the Sichuan Basin. These detachment layers exist in the research area indicating that they acted as slip layers during the Indo-China, Yanshan, and Himalayan movements (Fig. 22.9). They are important for two reasons: First, the

526

22

Resource Potential and Exploration Progress of Shale Gas …

2470.90

1972.87 1975.55

2491.94

1979.35 1982.75

2499.86

1986.15 1988.88

2508.81

1992.36 1995.51

2516.77

1997.99 2523.90

2003.94

m

2007.14

2530.28

2011.03 2014.29

2536.48

2016.86 2020.65

2542.77

2024.47 2026.81

2547.60

2030.66 2033.86

2553.53

2036.5 2041.45

2559.23

2044.45 2047.76

2566.96

2051.59 0%

20%

40%

60%

80%

100%

0%

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Fig. 22.8 Histogram of shale pore types in the Wufeng–Longmaxi formations. Left: well Jiaoye-2, Right: well Dingye-1

detachment layers and high-angle fractures created by multi-phase tectonic movements originated from net-like fractures at the bottom of the Longmaxi formation, which were advantageous for the preservation and reservoir stimulation of shale gas. Second, the fractures were destructive for the reservoir, releasing formation stress. In some areas with poor preservation conditions, fractures created by later tectonic movements are unfavorable for the preservation of shale gas. Therefore, they should be studied carefully. The statistics on the porosity of more than 500 samples from the first member of the Longmaxi formation in the Sichuan Basin and its periphery show that the porosity and permeability range from 0.15–8.61% and from 0.0047– 0.0116  10−3 lm2, respectively, with an average permeability of 0.0069  10−3 lm2. The samples have a low– medium porosity and low permeability. In the Wufeng formation and the first member of the Longmaxi formation, layers with relatively high porosity are distributed in the

Wufeng formation and at the bottom of the Longmaxi formation. The porosity is controlled by sedimentary microfacies and lithological variation. Meanwhile, the difference of porosity exists at the bottom of Longmaxi and similar intervals of Wufeng. The formation stress is relatively high in the Sichuan Basin. The shale has relatively good physical properties, with porosity greater than 4%, which results in a high shale gas flow rate after fracturing. In the normal pressure area outside of the basin, the porosity is *3.0% and the shale gas production is relatively low after fracturing. In some local areas, such as well Renye 1 in the southwestern Sichuan basin, the reservoir is tight and has poor physical properties (porosity of *0.73%). The gas tests during the drilling of the shale layer indicate a low value and the exploration failed. This indicates that the porosity correlates with the shale gas production. This influencing factor might be related to the preservation conditions, which still need to be further studied.

22.1

Characteristics of Marine Shale in China

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Fig. 22.9 Microfracture development characteristics of black shale in the Silurian Longmaxi formation in the Sichuan Basin and the peripheral area

22.1.2.3 Petrological and Mineralogical Characteristics The brittle mineral content in organic matter-rich shale in the Wufeng formation and Longmaxi formation is high (Fig. 22.10), with a silica content of 30–50%, feldspar content of 9–18%, pyrite content of 2–8%, and carbonate content of 6–15%. The content of plastic minerals is intermediate and the clay content is 27–39%. Overall, it is advantageous for fracturing and the support for the fracture to be open. The variation in the siliceous mineral content is the same as that of TOC. The brittle minerals are the most abundant in the good shale layer at the bottom of the Wufeng and Longmaxi formations, which indicates the biogenic origin of the siliceous minerals.

22.2

Resource Condition of Marine Shale Gas in China

The methods used for shale gas resource evaluation in China primarily include volumetric and analogical methods. Currently, few productive data are available for shale gas because the shale gas exploitation in China is in the initial stage. The experiment and test techniques regarding shale gas and the interpretation of geophysical data and geological evaluation are still problematic. Therefore, there is a lack of comparable data including calibrated data for the resource evaluation of mature shale gas, leading to differences in the understanding of the resources of marine shale gas in China.

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Fig. 22.10 Triangular diagram of the shale rock mineral components in the Upper Cambrian–Lower Silurian

Resource Potential and Exploration Progress of Shale Gas …

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AS HN LC NC PD RH SH TZ YH YZK ZY

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From 2009 to 2012, the Ministry of Land and Resources implemented resource potential investigation and evaluation, and optimization of the prolific zone for shale gas in China. The results of the evaluation of marine, continental, and transitional shale gas in 41 basins (areas) in China were reported in 2012 (Zhang et al. 2012). The geological reserves of shale gas in Chinese land territory were 134.42  1012 m3, with recoverable reserves of 25.08  1012 m3 (excluding Qinghai and Tibet). The geological reserves of marine shale gas were 91.84  1012 m3 (68% of the total reserves) and the recoverable reserves of marine shale gas were 12.97  1012 m3 (52% of the total reserves). The geological reserves of shale gas in the Cambrian were 39.33  1012 m3, with 4.95  1012 m3 recoverable reserves, and the reserves in the Silurian were 17.20  1012 m3, with recoverable reserves of 2.67  1012 m3. In 2011, the Chinese Academy of Engineering investigated the shale gas resources in China. Based on a questionnaire answered by experts from the Chinese petroleum industry and analogies with shale gas conditions in USA, the technologically recoverable shale gas reserves were predicted to be 9.2–11.8  1012 m3. The technologically recoverable reserves of marine shale gas were predicted to be 7.5  1012 m3, accounting for 75% of the total resources (Xie et al. 2014).

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22.3

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Exploration and Exploitation Status of Marine Shale Gas in China

Natural gas flow was obtained in shale since the 1960s during the exploration of conventional reservoirs in the Sichuan and Ordos basins. In the Sichuan Basin, the test of shale from the Lower Cambrian Qiongzhusi formation (well Wei 5) yielded a daily production of 2.46  104 m3 gas in 1966. The test in well Yang 63 in the Lower Silurian Longmaxi formation yielded a daily production of 3500 m3 gas after acidification. Chinese scholars (Luo 1986; Song 1990; Guan et al. 1995) started to pay attention to shale gas resources in the 1980– 1990s. Since 2000, the former Oil and Gas Resource Strategic Consulting Center of the Ministry of Land and Resources, China University of Geosciences (Beijing), Sinopec, PetroChina, and other units have carried out research on the geological conditions associated with China’s shale gas and have evaluated the resource potential, based on shale gas geological theory and technology applied in the USA, reexamination of previous data, and surveys of geological outcrops. In 2009, the former Ministry of Land and Resources launched the “Shale Gas Resource Potential and Favorable Area Optimization in Key Areas of China” project. After comparison and evaluation, it was proposed that

22.3

Exploration and Exploitation Status of Marine Shale Gas in China

China’s favorable area of marine shale gas is mainly distributed in the Sichuan Basin and southern China. The first shale gas resource survey well, that is, well Yuye 1, was implemented in Pengshui County, Chongqing. In 2009, major oil companies in China started the shale gas exploration. In 2011, PetroChina obtained a daily gas production of 15  104 m3 in the Wufeng and Longmaxi formations in well Ning 201-H1 in the Changning Block in the southern part of the Sichuan Basin, which represented a breakthrough in the commercial shale gas exploration in China (Dong et al. 2014, 2016). In 2012, Sinopec drilled well Jiaoye 1HF in the Wufeng and Longmaxi formations in the southeast of the Sichuan Basin and obtained a daily gas production of 20.3  104 m3. In 2013, Sinopec proved the first shale gas field in China, that is, the Fuling shale gas field (Wang 2015; Guo et al. 2016). By the end of 2017, the accumulated shale gas proved geological reserves in the Fuling shale gas field exceeded 600 billion m3. In addition, Sinopec made new discoveries in the Wufeng and Longmaxi formations in Weiyuan–Rongchang and Yongchuan and Dingshan in the Sichuan Basin. PetroChina found shale gas reserves that exceeded 1500  108 m3 in the Wufeng and Longmaxi formations in the Weiyuan, Changning, and Zhaotong areas in the southern Sichuan Basin. The China Geological Survey conducted shale gas surveys in non-petroleum exploration areas in South and North China and made discoveries in the Lower Cambrian and Silurian areas in Yichang. Energy companies, such as China Huaneng, China Huadian, and Shenhua, also actively participated in the shale gas exploration and made progress. By the end of 2016, a 24760 km 2D (two-dimensional) seismic survey, 4013 km2 3D seismic survey, and 1,161 wells had been completed in terms of the exploration and production of shale gas in China (China Ministry of Land and Resources 2016). Four commercial shale gas production zones were established in Fuling, Weiyuan, Changning, and Zhaotong in the Sichuan Basin. The shale gas reserves and production increased rapidly. By the end of 2017, China had proven shale gas reserves of *1  1012 m3. The shale gas production increased from 2500  104 m3 in 2012 to over 90  108 m3 at the end of 2017. China has become the third country in the world realizing the commercial development of shale gas. Based on exploration and development practice, Chinese scholars (Wang 2015; Guo 2014; Guo and Zhang 2014; Jin et al. 2016; He et al. 2016; Zou et al. 2015, 2016; Feng and Mu 2017) proposed the “dual enrichment” law for marine shale gas in complex tectonic zones and shale gas enrichment modes including the “structural sweet spot” and “continuous sweet spot”. Exploration and evaluation technology systems, such as the evaluation of selected areas and target optimization, are becoming more mature. Relevant development technologies, such as shale gas reservoir description, production capacity evaluation, and development parameter

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optimization, were established. Horizontal well optimized rapid drilling, pump plug cluster perforation and stage fracturing, simultaneous fracturing, and zipper fracturing are becoming more mature, technically allowing the shale gas production in the shallow sea (