Petroleum Geology of the South Caspian Basin 9780884153429, 0-88415-342-8

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Petroleum Geology of the

South Caspian Basin

ii

Contents

Petroleum Geology of the

South Caspian Basin Leonid A. Buryakovsky George V. Chilingar Fred Aminzadeh

Boston Oxford Johannesburg Melbourne New Delhi Singapore

Gulf Professional Publishing is an imprint of Butterworth–Heinemann. Copyright © 2001 by Butterworth–Heinemann A member of the Reed Elsevier group All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording, or otherwise, without the prior written permission of the publisher. Recognizing the importance of preserving what has been written, Butterworth–Heinemann prints its books on acid-free paper whenever possible. Butterworth–Heinemann supports the efforts of American Forests and the Global ReLeaf program in its campaign for the betterment of trees, forests, and our environment. Library of Congress Cataloging-in-Publication Data ISBN 0-88415-342-8 British Library Cataloguing-in-Publication Data A catalogue record for this book is available from the British Library. The publisher offers special discounts on bulk orders of this book. For information, please contact: Manager of Special Sales Butterworth–Heinemann 225 Wildwood Avenue Woburn, MA 01801-2041 Tel: 781-904-2500 Fax: 781-904-2620 For information on all Gulf Professional Publishing publications available, contact our World Wide Web home page at: http://www.gulfpp.com. 10 9 8 7 6 5 4 3 2 1 Printed in the United States of America

Contents

Dedication This book is dedicated to His Highness, the Amir of Kuwait, Sheikh Jaber Al Ahmed Al Sabah, for His outstanding support of the petroleum industry and personal concern He has demonstrated for the well being of His people.

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Special Acknowledgment We especially wish to acknowledge the outstanding help of academician John O. Robertson Jr., Ph.D., in preparation of the illustrations. The help extended by Michael V. Garfunkel, Essam Al-Ajeel, and Khaled Ben-Ameirah is also greatly appreciated.

CHAPTER 1 CH

Contribution No. 10, Rudolf W. Gunnerman Energy and Environment Laboratory, University of Southern California, Los Angeles, California

Contents

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Contents Foreword, x Preface, xii Nomenclature, xv Abbreviations, xix Structures of Azerbajan Part of the South Caspian Basin, xx CHAPTER 1

Geology of Azerbaijan and the South Caspian Basin .................................................. 111 General Overview, 1. Geologic Setting of Super-Deep Deposits, 5. Saatly Super Deep Well, SD-1, 9. CHAPTER 2

Mud Volcanoes ........................................................... 116 Yasamaly Valley, 18. Alyaty Ridge, 20. CHAPTER 3

Regional Distribution of Oil and Gas....................... 122 CHAPTER 4

Lithostratigraphic Framework.................................... 127 vii

CHAPTER 5

Onshore Oil and Gas Fields ...................................... 132 Region I: Apsheron Peninsula, 32. Region II: Pre-Caspian–Kuba Monocline, 43. Region III: Lower Kura Lowland, 44. Region IV: Yevlakh-Agdzhabedi Area, 44. CHAPTER 6

Offshore Oil and Gas Fields........................................ 52 Caspian Sea Overview, 52. Zone I: Western Portion of Apsheron–Pre-Balkhan Anticlinal Trend, 57. Zone II: South Apsheron Offshore Area, 91. Zone III: Baku Archipelago, 101. CHAPTER 7

General Regularities in Oil and Gas Distribution .......................................................... 113 I. Azerbaijan Portion of the South Caspian Basin, 113. II. Turkmenistan Portion of the South Caspian Basin, 199. III. Regions Adjacent to the South Caspian Basin, 212. CHAPTER 8

Conclusions (Chapters 1–7) ...................................... 239 CHAPTER 9

Mathematical Models in Petroleum Geology .......... 243 Introduction, 243. Mathematical Simulation of Geologic Systems, 244. CHAPTER 10

Mathematical Models in Oil and Gas Exploration and Production (Static Geologic Systems) .............. 248 Mapping of Structures within the Apsheron–Pre-Balkhan Anticline Trend, 248. Reservoir Characterization Using

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Log Data, 254. Modeling of Sedimentary Sequences Based on Well-Logging Data, 284. Entropy as Criterion of Heterogeneity of Rocks, 290. Anisotropy of Stratified Rocks, 297. Permeability of Reservoir Rocks, 302. Surface Activity of Rocks, 313. Models of Oil Composition and Properties, 324. CHAPTER 11

Mathematical Modeling of Geological Processes (Dynamic Geological Systems) ................................. 347 Methodology of Simulation of Dynamic Systems, 347. Mathematical Simulation of Sediment Compaction, 355. Numerical Simulation of Oil- and Gas-Bearing Rock Properties, 365. CHAPTER 12

Other Applications of Numerical Simulation Methodology ................................................................ 384 Basic Principles and Calculation Techniques, 384. Simulation of Reservoir-Rock Properties, 386. Simulation of Petrophysical Properties of Rocks, 390. Simulation of Water Invasion into Oil-Saturated Rocks, 398. Simulation of Pore-Fluid (Formation) Pressure, 400. Simulation of Hydrocarbon Resources and Evaluation of Oil and Gas Reserves, 403. CHAPTER 13

Conclusions (Chapters 8–13) .................................... 408 Bibliography ................................................................ 410 CHAPTER 1 VH

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Foreword If the end of cold war is the biggest news of the century in terms of world politics, the unleashing of the wealth in terms of untapped oil and gas reservoirs in the Caspian Sea region is probably the biggest economic news of the same century. Addressing the petroleum geology of South Caspian Basin at this crucial time of energy awareness shows unparalleled wisdom, experience, and maturity of the authors. The timing for such a useful book on a region that is considered to be the next Persian Gulf could not be more appropriate. The news of petroleum discoveries in the Caspian Sea region continue to pour in. Only a few months ago, the news broke about the possibility of discovering 50 billion barrel in the Kashagan offshore structure. If this is true, as all indications are, this latest discovery will put Kashagan structure second to only Saudi Arabia’s onshore Ghawar field, with remaining reserve of 70 billion barrels. Incidentally, Saudi offshore, Safaniya, the world’s currently known largest offshore deposit contains 19 billion barrels. The book provides one with a treasure of information on the most studied section of the Caspian Sea region. The book is written with a comprehensive approach that includes the development of scientific bases, simulation techniques, and mathematical models of both static and dynamic geological systems. This approach is necessary if one is interested in exploration, development, and production of a petroleum reservoir. The combination of science and engineering has been sought for a long time, and the book provides one with a fine example of how one should approach in developing oil and gas fields in the 21st century. As the world order is moving from the Modern to the Knowledge Era, the petroleum industry is creating a culture that requires combining cutting edge science with engineering into the core of decision making structure. This, in petroleum vocabulary, means that the petroleum industry must combine geological and geophysical skills with petroleum production engineering. This book collects this information from the anal of 150 years

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of exploration and production history of the Caspian Sea region and presents them in a format that is useful for both scientists and engineers. The book is helpful for determining oil and gas potential as well as optimum production strategies in the region. The book takes the reader through some of the most fundamental description of geological history in the region, and embarks into the application of advanced mathematical models and engineering techniques. The authors do this with impeccable dexterity and provides the reader with a powerful interdisciplinary tool for exploration, reserve evaluation, and production optimization. The authors take a bold approach to educating engineers on some of the essential aspects of geology and geophysics. I am not aware of another book that amalgamates geology, geophysics, and petroleum engineering with such a seamless approach. I recommend this book to every geologist, geophysicists, practicing engineer, graduate student, and academic who is engaged in petroleum studies. Rafiq Islam Killam Chair in Oil and Gas Dalhousie University Canada

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Preface The Caspian Sea is a highly promising oil- and gas-bearing province, because prolific oil and natural gas regions situated in the territories of Russia, Kazakhstan, Azerbaijan, and Turkmenistan extend to the Caspian Sea area (Figure 1-1). The Caspian Sea is the world’s largest salt lake—its length from the north to south is 1,174 km/730 mi., average width is 326 km/203 mi, and total area is 375,000 km 2/ 145,000 mi 2. Water depth in the middle of the sea ranges up to 788 m/2,584 ft and in the southern part, up to 1,025 m/3,361 ft. The Caspian Sea has no outlet, and although the surface level fluctuates, it averages about 25 m/82 ft below ocean level according to recent measurements. Geological studies in the Caspian Sea began in the second half of the 19th century. The South Caspian Basin, which comprises the South Caspian Sea, Eastern Azerbaijan, and Western Turkmenistan, with a high density of confirmed structures, was studied in greatest detail. Hydrocarbon accumulations have been discovered, explored and produced in areas with water depth up to 60 m/200 ft, and several oil and gas fields have been discovered in water depth up to 200 m/655 ft. Azerbaijan is one of the independent countries in western Asia, bounded on the south by Iran (Province of Iranian Azerbaijan), on the north by Russia, on the west by Georgia and Armenia, and on the east by the Caspian Sea. The country consists mainly of lowlands surrounded by the Kura River and its tributary, the Araks, which forms the border with Iranian Azerbaijan. The landscape ranges from semidesert to mountains of the Greater and Lesser Caucasus. Azerbaijan covers an area of about 86,600 km2 or 33,400 mi2. Azerbaijan is one of the oldest oil- and gas-producing provinces in the world. For example, the oldest oil-field, the Kirmaku, has been known from ancient times as a place of primitive production of oil

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and asphalt. The earliest date of Kirmaku field production is about 1834. The first deep oil well in Azerbaijan was drilled in the Bibieibat oilfield in 1848. Recoverable reserves of this unique oil- and gas-bearing province include about 1,700 MMtons/12 Bbbl of oil and 1 Tm3/35 Tft3 of natural gas. The main oil- and gas-bearing section in Azerbaijan is the so-called clastic Productive Series of Middle Pliocene age. It includes about 90% of all the identified hydrocarbon reserves of Azerbaijan and adjacent offshore area of the South Caspian Basin. During the last 20 years, a new type of reservoir rocks has been discovered in the territory of central and western Azerbaijan, mainly in the central portion of the Kura Depression. Commercial oil and gas reserves are present in the fractured Upper Cretaceous volcanic rocks. Extensive offshore development in Azerbaijan began in 1949. Since then, numerous oil and natural gas fields have produced about half their recoverable reserves. All fields are multi-bedded with as many as 30 producing zones in the Middle Pliocene sandstones and siltstones. Exploratory and production drilling is carried out from individual platforms and piers. Also, floating and semi-submersible drilling rigs are used for exploration. At present, exploration drilling in the Caspian Sea is carried out in water depth of 200 m/655 ft; the deepest well was drilled to a depth of 6,500 m/21,311 ft. Azerbaijan’s Apsheron Peninsula and adjacent offshore area is now being developed under multi-billion dollar contract with Western oil companies. Turkmenistan is located in Central Asia and is the southernmost of the CIS countries. The Turkmenistan Republic is bordered by the Caspian Sea to the west, Iran and Afghanistan to the south, Kazakhstan to the north, and Uzbekistan to the northeast and east. Its territory extends 1,100 km east-west and 650 km north-south and covers an area of approximately 488,000 km2 or 188,200 mi2. The climate of the country is dry and 80% of its territory is desert. Water resources are distributed by canal and irrigation systems. The petroliferous areas include the eastern portion of South Caspian Basin and the Amu-Darya oil- and gas-bearing provinces. The presence of seeps and mud volcanoes first attracted attention to the eastern part of South Caspian Basin at an early date. Oil was being produced from 3500 hand-dug wells and seeps on Cheleken Island by 1938. About 28 fields have been discovered to date in western Turkmenistan (onshore and offshore). More than 48 fields have

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been discovered since the beginning of petroleum exploration in the Amu-Darya area in 1929. After Russia, Turkmenistan is the second largest gas-producing republic. In 1990, the gas production was 3,100 Bft3. Oil production decreased 30% after 1980, but was stable (50 Mbbl/yr) during the last five years of 1980s. In Western Turkmenistan, the most promising area is probably the shallow offshore. With water depths of 50 m/164 ft or less, exploration and production techniques developed in the Gulf Coast area of U.S. could be applied here, i.e., using drilling barges and dredges in very shallow water and jack-up rigs in deeper water. Progress in the oil- and gas-producing industry is related closely to the improvement in exploration techniques and increase in discovery rates. Exploration and production of hydrocarbon resources must be based on reliable scientific information. During more than 150 years of oil and natural gas exploration and production in Azerbaijan, a great amount of geological, geophysical, petrophysical, geochemical, and engineering information has been gathered. This information will aid in estimating oil and gas reserves as well as improving field development technology. We used advanced mathematical methods to process the geological, geophysical, and engineering data, and our investigation included development of simulation techniques and construction of mathematical models of both static and dynamic geologic systems (geologic processes). Leonid A. Buryakovsky George V. Chilingar Fred Aminzadeh

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Nomenclature A Ada At B Ccarb Ccl Csh D d dw dact dnom dch dp,ave dp,Me F Fp,t F’ F’p,t G ∆G H Hmax Hr Ho h heff hsh I ∆Iγ ∆Inγ

area diffusion-adsorption factor absolute geological age “benzine” (gasoline) content carbonate cement content clay cement content shale cement content depth diameter wellbore diameter actual wellbore diameter nominal wellbore diameter pore-channel diameter average pore diameter median pore diameter formation resistivity factor formation resistivity factor at reservoir conditions resistivity index resistivity index at reservoir conditions geothermal gradient Gibbs free-energy difference entropy of information maximum entropy relative entropy zero hypothesis thickness effective (net) thickness shale thickness quantity of information relative GR factor relative NGR factor

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K filtration coefficient pressure-abnormality factor Ka k permeability permeability parallel to bedding k|| permeability perpendicular to bedding k⊥ modeling coefficient ki L ligroin content L length length of capillaries Lc M mathematical expectancy m number of parameters in the data matrix m cementation exponent N number of measurements, tests or observations n number of objects in the data matrix n saturation exponent probability pi p pressure external pressure, total overburden pressure pe pi internal pressure, pore-fluid pressure effective (grain-to-grain) pressure peff pp pore pressure pr reservoir pressure ∆p differential pressure cation-exchange capacity per 100 g of rock Q100 q volumetric flowrate liquid production rate qliq qoil oil production rate R resins plus asphaltenes content rate of sedimentation Rd R electric resistivity apparent resistivity Ra Ra(AO) apparent resistivity from lateral sonde of AO size Rcr oil-saturated reservoir rock cut-off (critical) resistivity Rg,r gas-saturated reservoir rock resistivity oil resistivity Roil Ro,r oil-saturated reservoir rock resistivity Rsh shale resistivity true resistivity Rt Rt,min minimum true resistivity

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Rw Ro Rm Rmf RIL r r rc So So/g So,r Sw Sw,r Scarb Ssort Ssh Sss sb sg sp shf T ∆t t tα U ∆USP V Vc Vs vλ vR α αSP β βc γ η ηp

water resistivity water-saturated reservoir rock resistivity drilling-mud resistivity mud-filtrate resistivity resistivity from Induction Log correlation coefficient radius radius of capillaries oil saturation oil/gas saturation residual oil saturation water saturation residual water saturation homogeneity of carbonates sorting factor sorting of shales sorting of sandstones specific surface area of pore space per unit of specific surface area of pore space per unit of specific surface area of pore space per unit of shape factor for pores temperature interval transit time time probability index @ α confidence level relative change in volume of sediments relative SP factor volume volume of capillaries seismic velocity variation of anisotropy variation of resistivity probability error or confidence level SP reduction factor modulus of elasticity irreversible compaction factor (compressibility density relative clay content in rock pore-pressure gradient

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bulk volume grain volume pore volume

factor)

ηsh ηr λ µ ν σ σ σR σr τ τw φ φ′ φeff φsh χsh ω Σω Σ

pore-pressure gradient in shales formation-pressure gradient in reservoir rocks anisotropy coefficient dynamic viscosity kinematic viscosity stress standard deviation, or mean square error standard deviation of resistivity standard deviation of correlation coefficient electrical tortuosity of pore channels thickness of pore-water film porosity “residual” porosity effective porosity shale porosity relative content of shales frequency or probability cumulative frequency or probability macroscopic cross-section of thermal neutron capture (absorption)

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Abbreviations AHFP bbl Bbbl Bcfg bpd bopd cfd cmd FSU GKZ GOC GOR GWC HC Mbpd Mcfd Mcmd MD MMcfd MMcmd MMt MSE Mtd OWC PTD SEM Tcf Tcfg tpd TD TOC TVD

abnormally high formation pressure barrels billion barrels of oil billion cubic feet of gas barrels per day barrels of oil per day cubic feet per day cubic meters per day Former Soviet Union State Committee on Reserves (in FSU) gas-oil contact gas/oil ratio gas-water contact hydrocarbons thousand barrels per day thousand cubic feet per day thousand cubic meters per day measured depth million cubic feet per day million cubic meters per day million tons mean square error thousand tons per day oil-water contact proposed total depth scanning electron microscope trillion cubic feet trillion cubic feet of gas tons per day total depth total organic carbon true vertical depth xix

Structures of Azerbaijan Part of the South Caspian Basin After declaring independence in 1991, many structures, oil and gas fields, and prospects in Azerbaijan were renamed. For reference, a list of old and new names of most oil and gas fields and prospects located in the Azerbaijan part of the South Caspian Basin is provided below. In this book, only new names are used. Old names:

New names:

26th Baku Commissars 28th of April 40th Anniversary of Azerbaijan Abramovich Aliyev Andreyev Bank Andriyevski Bank East Andriyevski Bank Artyom Island Arzu Asadov Bakhar Borisov Bank Bulla Island Bulla-moré Byandovan-moré Darvin Bank Duvanny Island

Azeri Gyuneshli Ashrafi Karabakh Guba Deniz Umid Gilavar Khazri Pirallaghi Adasi Arzu Zirva Bakhar Inam Khara Zyrya Bulla Deniz Byandovan Deniz Darvin Bank Zenbil

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Old names:

New names:

East Apsheron Galyaba Golovachev Bank Gryazevaya Sopka Gyandzhlik Gyurgyany-moré Kalmychkov Bank Kamen’ Ignatiya Kamen’ Persiyanina Kamni Dva Brata Kamni Grigorenko Karadag-moré Karagedov Bank Kaverochkin Khamamdag-moré Kornilov-Pavlov Bank Kumani Bank Kurinskiy Kamen’—1 Kurinskiy Kamen’—2 Kyurdakhany-moré Kyzylburun-moré Lenkoran’-moré Maiskaya Mekhdi Gusein-zadeh Midiya Nakhichevanskiy Nardaran-moré Neftechala-moré Neftyanyye Kamni Neftyanyye Kamni—2 North Apsheron Peschany Island Peschany-moré Pogorelaya Plita Promezhutochnaya Putkaradze Samedov

Shargi Absheron Galyaba Atashkyakh Palchygh Pilpilasi Gyandzhlik Gyurgyan Deniz Shirvan Deniz Dashli Aran Deniz Goshadash Khali Karadag Deniz Mugan Deniz Chyragh Khamamdag Deniz Sabail Chigil Deniz Kyurdashi Araz Deniz Kyurdakhany Deniz Kyzylburun Deniz Lenkoran Deniz Airapa Ufug Midiya Nakhchevani Nardaran Deniz Neftechala Deniz Neft Dashlary Oguz Shimali Absheron Gum Adasi Gum Deniz Yanan Tava Kyapaz Saba Seiyar

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Old names:

New names:

Samed Vurgun Sangachaly-Duvanny-Bulla Island Sangi Mugan’ Sevindzh Shakhovo-moré Shapirovskiy South Kurinskaya South Shirvanskaya Sovetabad-moré Topkhana Tsyurupa Bank Tyurkyany-moré Uzeir Gadzhibayev West Apsheron Yakubov Yalama Khudat Yashma-moré Yuzhnaya Yuzhnaya—2 Zhiloi Island Zorat-moré

Vurgun Sangachal-Duvanny Deniz-Khara Zyrya Sangi Mugan Sevindzh Shakh Deniz Danulduzu Talysh Deniz Lerik Deniz Shorabad Deniz Sumgait Deniz Agburun Deniz Tyurkyan Deniz Peik Garbi Absheron Khamdem Shollar Deniz Yashma Deniz Dzhanub Dzhanub—2 Chalov Adasi Dzhorat Deniz

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CHAPTER 1

Geology of Azerbaijan and the South Caspian Basin GENERAL OVERVIEW The territory of Azerbaijan (Figure 1-1) is part of the Alpine fold belt and consists of folded systems, embracing the eastern parts of the Greater and Lesser Caucasus Mountains, the Kura Intermontane Depression (Kura Lowland) separating them, and also the Middle and South Caspian basins (Figure 1-2). Thickness of the Earth’s crust here ranges from 38 to 55 km. The greater thickness occurs within the Greater Caucasus, the lesser in the Talysh foothills. In the submontane belt of the Lesser Caucasus crustal thickness reaches 40 to 45 km, and 50 km in the Kura Intermontane Depression. Peculiarities of the folded system of the Greater Caucasus include a flysch-filled trough at the southern slope of the Greater Caucasus with an extensive development of overlying structures. Where isolated, Early Jurassic, shaly copper-pyrite deposits occur. Within the Kura Intermontane Depression, Mesozoic-Early Paleogene and Late PaleogeneQuaternary structures are clearly distinguished. The first stage of Mesozoic volcanogenic-sedimentary rocks forms a single unit within the folded system of the Lesser Caucasus in the south and the Vandam zone in the north. Within the depression, a thick sequence of Late Paleogene-Quaternary deposits is widespread, unconformably overlying the lower structures. The Lesser Caucasus was a zone of volcanism during the Mesozoic, Paleogene, Miocene-Pliocene and Quaternary, and is characterized, in the central part, by an extensive ophiolitic belt—the eastern portion of the North Anatolia Belt.

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Petroleum Geology of the South Caspian Basin

Figure 1-1. Caspian Sea Region (Modified after National Geographic Society map, Washington, D.C., 1999).

Jurassic and Cretaceous deposits are widespread in Azerbaijan. Lower Jurassic deposits (thickness of 2,000 m and more) are widely distributed in the Greater Caucasus and are represented by slate and sometimes by sandstone, with intrusive sheets of diabase and gabbrodiabase. In its analogous terrigenous facies, the Lower Jurassic is more sparsely represented in the Lesser Caucasus and the Nakhichevan region. Apparently, within the Kura Depression, the Lower Jurassic deposits occur as equivalent, thin terrigenous facies. The lowermost Middle Jurassic strata of the Greater Caucasus are composed of argillaceous slates with rare partings of sandstone,

Geology of Azerbaijan and the South Caspian Basin

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Figure 1-2. Structural pattern of Azerbaijan (Modified after the Excursion Guide-Book for Azerbaijan SSR, Vol. II, 1984). A—Greater Caucasus Anticlinorium; B—Kura Intermontane Depression; C—Lesser Caucasus Anticlinorium; D—South Caspian Basin; I—Gobustan-Apsheron Trough; II—Lower Kura Trough; III—Geokchai-Saatly Anticlinal Trend; IV—Yevlakh-Agdzhabedy Trough; V—Iori-Adzhinour Trough. 1—Quaternary, 2—Miocene–Paleogene, 3—Mesozoic, and 4—consolidated crust.

whereas the uppermost section (2,500 to 4,000 m thick) is dominated by thick strata and beds of quartz sandstones with rare partings of shales. In the Lesser Caucasus, terrigenous rocks (thickness of 120 m) of the lowermost Middle Jurassic [the main part of the section (2,000– 3,000 m thick)] consists of lava sheets and diabasic volcanics. Quartz plagio-porphyrites with their volcaniclastic and sedimentary-volcanogenic sequences occur in the uppermost strata. In the Kura Depression these deposits are represented by similar facies. The Upper Jurassic deposits in the northern slope of the Greater Caucasus are composed of calcarenites and reef limestones (thickness

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Petroleum Geology of the South Caspian Basin

of 300 m), and in the southern slope by flysch-like variegated, silicified, and carbonaceous shales (thickness of 500 m). These deposits in the Lesser Caucasus and in the Kura Depression consist of reef limestone and volcanogenic-clastic intervals (500–1,500 m). Lower Cretaceous deposits of the Greater Caucasus consist of carbonaceous-terrigenous flysch (thickness of 500–2,000 m), whereas in the Lesser Caucasus and Kura Depression they are represented by tuffaceous-terrigenous and carbonaceous intervals. Upper Cretaceous deposits of the Greater Caucasus (thickness of 2,000 m) consist of terrigenous-carbonaceous flysch facies. Within the Lesser Caucasus their content is decreased and within the Kura Depression it greatly increased. The Paleogene, Neogene and Quaternary deposits are widespread within the Kura and Araks depressions, Kusary sloping plain, Gobustan area, Apsheron peninsula, Talysh foothills and in a number of residual and superimposed depressions of the Greater and Lesser Caucasus. These deposits of considerable thickness in depressions constitute the main reservoir rocks for oil and gas accumulations in Azerbaijan. Paleogene deposits in the depressions consist of green-gray, blocky shales with partings of sandstones and marls. The thickness of deposits is 300–400 m in the Pre-Caspian region, 1,700 m in the Apsheron peninsula, and 2,800 m in the Shemakha-Gobustan region. Within the Kura Depression, a thicker accumulation of more than 3,000 m is characteristic of the Paleogene deposits. Neogene deposits in regions adjacent to the Greater Caucasus consist of sandy shale in the lowermost strata and of more shallow, thick sandstones and coquina in the uppermost strata. Thickness ranges from 1,700 m (Pre-Caspian region) and 4,500 m (Apsheron peninsula) to 5,500 m (Gobustan area). Quaternary deposits consist of marine, continental, and volcanogenic facies. The thickest accumulation is observed within the Lower Kura subdepression (more than 1,500 m), where, in the lowermost strata, they are represented by shallow marine deposits, whereas the uppermost strata consist of alluvial and delluvial deposits. The above Phanerozoic deposits are submerged within Middle and South Caspian basins located to the east and the southeast of the Azerbaijan land area. Within the South Caspian Basin these deposits are buried at great depth, and thickness of the Paleogene-Quaternary interval increases. According to geophysical data in the South Caspian

Geology of Azerbaijan and the South Caspian Basin

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Basin adjacent to the Lower Kura subdepression, thickness of the Paleogene-Quaternary interval reaches 20 km. The modern structure of Azerbaijan and the South Caspian Basin originated during the last stage of Alpine folding. This explains why structures are parallel to ancient structural elements that predate the latest movement. Currently, this is a region of active folding, diapirism, fracturing, seismicity, mud volcanism, geysers, and thermal springs. The presence of Middle Pliocene terrigenous strata 2,500–3,500 m thick (the Productive Series) with oil and gas fields, and the widespread distribution of mud volcanism in the south-eastern Caucasus and in the offshore area of the South Caspian Basin, are distinctive features of Azerbaijan geology.

GEOLOGICAL SETTING OF SUPER-DEEP DEPOSITS The deepest deposits occur within the Kura Intermontane Depression, which is located between mountainous uplifts of Greater and Lesser Caucasus mega-anticlinoria. Structurally, it is a megasynclinorium that originated during the orogenic stage of Caucasus development. By its abyssal structure, the Kura Depression is divided into Upper, Middle, and Lower Kura troughs or subdepressions which demonstrate different mobility. The Middle Kura Trough with an extent of 300 km embraces the area from Tbilisi, Georgia, to the meridian of Kyurdamir, Azerbaijan. A wide, buried uplift extends toward Vandam from the region of Talysh foothills to the north. The Lower Kura Trough extends from the western Caspian abyssal fracture, located along the eastern slope of Talysh-Vandam uplift, to the western shore of the Caspian Sea. These geological features are separated by faults of the northwest extension (Figure 1-2). The surface of the Middle Kura intermontane area is named the MilMugan steppe and is composed of the Quaternary alluvial-deluvial deposits 800-m thick. The first indication of abyssal structure was revealed as a gravity maximum by a survey conducted in 1929–1931. The first investigator, V. V. Fedynskiy, named this gravity maximum as Talysh-Vandam. Detailed investigations of Talysh-Vandam gravity maximum were conducted by geologists and geophysicists of Azerbaijan who noted that the Saatly uplift region in latitudinal section is a block of shallow (about 8 km) “basalt” rocks with a velocity discontinuity of 6.7–6.8 km/sec. Different tectonic regimes caused a change in

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Petroleum Geology of the South Caspian Basin

folding characteristics of the Middle Kura Trough. During CaledonianHercynic stages the trough was a part of the Transcaucasus anticline (the Median Masiff). Within this trough, the uplift, erosion, and formation of separate basement fault blocks predominate. The main structural elements of the Middle Kura subdepression originated during the earliest Alpine stage. These are the Geokchai-Saatly (or KyurdamirSaatly) uplift, Iori-Adzhinour, and Yevlakh-Agdzhabedy troughs (Figure 1-2). During the Liassic time, the region of the modern Kura Depression was occupied by a shallow sea where terrigenous sediments accumulated. During Middle and Late Jurassic, a 5,000-m volcanogenic sequence accumulated as a result of intensive volcanic activity. Carbonate reefs grew in the Late Jurassic–Early Cretaceous time. A second stage of volcanic activity occurred during the Late Cretaceous time when volcanogenic sequence accumulated in separate parts of the Talysh-Vandam gravity maximum. The end of Late Cretaceous is marked by the accumulation of Campanian-Maastrichtian carbonate sediments. Sedimentation occurred in the Iori-Adzhinour, YevlakhAgdzhabedy, and Lower Kura troughs. The beginning of Oligocene-Miocene orogenesis altered the pre-existing geotectonic regime in the Kura Depression, and was dominated by warping with molasse accumulation. The Geokchai-Saatly zone of the buried uplifts is characterized by an elevated basement surface in the eastern part of Middle Kura Trough. The Saatly-Kyurdamir and Mil-Khaldan subzones (blocks) occur within the Geokchai-Saatly zone. The Saatly-Kyurdamir subzone includes Karadzhaly, Sor-Sor, Dzharly, and Saatly local uplifts, whereas the Mil-Khaldan subzone experienced Muradkhanly, Zardob, and Mil uplifts. It is hard to investigate Saatly-Kyurdamir buried uplift because there are no natural outcrops, and Cenozoic molasse deposits, overlapping Mesozoic sedimentary-volcanogenic strata, are very thick. Drilling on various parts of the uplift, however, has produced new data on Mesozoic magmatism. It was ascertained that the Mesozoic stage of uplift involved volcanogenic-sedimentary deposition with a volcanogenicplutonic association. Seismic, gravity and magnetic investigations of the Earth’s crust along profile, which crosses the uplift in a latitudinal direction, show that a velocity model of the crust based on reflected waves is rather informative. Seismic observations were conducted by vertical seismic sounding by reflected waves. Observations were conducted only along

Geology of Azerbaijan and the South Caspian Basin

7

the sublatitudinal profile that crosses the uplift area. As a result, a more detailed velocity model was obtained (Figure 1-3). According to these data, a high-velocity layer [V > (6.7–6.8) km/sec] is expected at a depth of 9 km. It became evident that the Saatly-Kyurdamir gravity maximum is expressed as a nose of the most ancient (Pre-Baikal) complex (Figure 1-4). The nose is overlapped by a magmatic sequence of basic and intermediate composition, mainly of Mesozoic age. Its roots penetrate deep into the mantle to the west where the Zardob magnetic maximum is present. These investigations show the development of Mesozoic magmatites as thick, highly-magnetic strata. To confirm these data, it was decided

Figure 1-3. Seismic density model along the line of deep seismic sounding (Modified after the Excursion Guide-Book for Azerbaijan SSR, Vol. II, 1984). (a) Observed and calculated plots of gravity field for section; (b) Seismic density model; Curves: 1—observed, 2—calculated, 3—Cenozoic sequence, 4—Mesozoic sequence, 5—sequence G (velocity analogous to that in “granitic” layer), 6—sequence B (velocity analogous to that in “basalt” layer), divided into two sub-sequences: B u and B l, 7—sequence B1 (supposed peridotite content), 8—boundary of velocity (density), 9—unconformities, 10—deep wells.

8

Petroleum Geology of the South Caspian Basin

Figure 1-4. Geologic and geophysical model of Saatly-Kyurdamir anticlinal trend (Modified after the Excursion Guide-Book for Azerbaijan SSR, Vol. II, 1984). 1—Cenozoic sequence-terrigenous deposits; 2—Mesozoic sequence: a. terrigenous-carbonate deposits, b. extrusive formations of basic and intermediate composition; 3—Baikal sequence, metamorphozed primary terrigenous formations; 4—Pre-Baikal sequence, gneiss and marl; 5—the oldest interval, gneiss and amphibolite; 6—intrusive formations of basic and intermediate composition; 7—undivided extrusive-intrusive interval; 8—low density rocks, serpentinites; 9—rocks of intermediate composition between crust and mantle; 10—position of upper mantle top; 11—zones of large faults; 12— deep wells.

to drill a super-deep well. It was expected that on reaching a depth of 9 km, the super-deep well would penetrate a volcanogenic section. Disturbed deposits, which are the source of the regional TalyshVandam gravity maximum, are expected lower. The authors suppose that as a whole, these are primarily sedimentary, metamorphosed, and consolidated deposits of the Upper Archean-Lower Proterozoic age.

Geology of Azerbaijan and the South Caspian Basin

9

It is possible that between the Mesozoic magmatic strata and the PreBaikal basement, there may occur somewhat thin intermediate deposits, which cannot be identified by common techniques.

SAATLY SUPER DEEP WELL SD-1 The Saatly Super Deep well SD-1, with a proposed depth of 15,000 m/49,212 ft, was located within the Middle Kura Intermontane Depression (Kura Lowland), where the Kura and Araks rivers converge and the Mil and Mugan steppes join (Figure 1-5). It is a region of warm semi-desert and dry steppes with an arid climate. The average annual temperature is +10°C. Annual precipitation does not exceed 200–300 mm. From December 1971 to August 1974, a preliminary well was drilled to 6,240 m/20,472 ft. The well penetrated Cenozoic molasse, Mesozoic Carboniferous deposits, and from 3,550 m/11,647 ft to bottom of the well, volcanogenic strata. The Saatly Super Deep well was designed in accordance with a “Study of the Earth’s mineral resources and super-deep drilling” conducted by the State Committee on Science and Engineering. The main goal of this program was to study the Earth’s crust in the Mediterranean Alpine geosynclinal belt, including the following investigations: 1. A detailed study of solid, fluid and gaseous phases of the Earth’s crust and their changes with depth. 2. The study of the geologic nature of seismic boundaries and the establishment of the reasons for crustal foliation by geophysical parameters. 3. The study of peculiarities of endogenic geologic processes manifested in deep parts of the Earth’s crust, including the process of ore generation. During the first stage of the investigations, while drilling the Saatly well to 8,000 m/26,247 ft, the main goal was to penetrate the sedimentary and volcanogenic section at a site of minimum thickness, according to geophysical study conducted in the area of Saatly local uplift. This was done (a) to study its composition, structure, occurrence, and oil content; (b) to study the conditions of generation and distribution of ores in the lower part of sedimentary-volcanogenic strata; (c) to penetrate granitic rocks, to study their interrelation with

10

Petroleum Geology of the South Caspian Basin

Figure 1-5. Location of Saatly Super Deep Well SD-1. Distances: Baku to Saatly: 180 km (112 mi); Baku to Alyat: 72 km (45 mi); Alyat to KaziMagomed: 46 km (28 mi); Kazi-Magomed to Ali-Bairamly: 13 km (8 mi); AliBairamly to Sabirabad: 38 km (24 mi); Sabirabad to Saatly: 12 km (7.5 mi).

sedimentary-volcanogenic formations; and (d) to develop and improve the drilling technology and methods of geological and geophysical investigations at great depth. In this section the following stratigraphic units were penetrated (Figure 1-6): Post-Pliocene (Quaternary) deposits (0–860 m) are represented by the irregular alternation of gray, thick-bedded clay; gray, unconsolidated siltstone; medium-grained and coarse-grained sandstone with grit inclusions; thin-bedded intervals with grit inclusions; and thinbedded intervals of continental origin. Apsheronian Stage (860–1,930 m) is represented lithologically by alternation of sandy, silty and clayey rocks in the upper portion of

Geology of Azerbaijan and the South Caspian Basin

11

Figure 1-6. Stratigraphic section (from cores and logs) of Saatly Super Deep Well SD-1 (Modified after the Excursion Guide-Book for Azerbaijan SSR, Vol. I, 1984). Aleurites = siltstones.

the section and with gray clay separated by silty, sandy and limy interlayers in the lower portion. Akchagylian Stage (1,930–2,250 m) is composed of gray silty clay with rare and thin partings of polymictic siltstone. Middle Pliocene (2,250–2,780 m) is represented by brown-gray silty clay alternating with polymictic sandstone.

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Petroleum Geology of the South Caspian Basin

Sarmatian Stage (2,780–2,830 m) is represented by alternation of thinbedded sandy argillaceous rocks and carboniferous rocks, overlying Mesozoic carbonate. Cretaceous—Late Jurassic (2,830–3,529 m) is represented by the alternation of thick (200 m), fractured, pelitomorphic, siliceous metamorphosed limestone and volcanogenic intervals (5 and 54 m, respectively). Jurassic (3,529–8,230 m) is represented by thick volcanogenic strata. The main attention was paid to the composition, structure, physical properties, and geochemical attributes of volcanogenic rocks. Core samples from volcanogenic strata, studied petrographically in detail, give an idea of structure, composition, facies, and rock deformation of volcanogenic strata. Volcanic facies on the SD-1 log are represented by two groups: (a) volcanic and (b) volcaniclastic. Volcanic facies are represented by a large number of genetic types, among which the leading ones are lava flows and lava breccias. Among rocks of the volcaniclastic facies, lavaclastites and hyaloclastites are widespread. Pyroclastic rocks (tuffs, tuff breccias), which belong to the same group of facies, are characterized by a variety of fragments, color, structure, and size. Volcanogenicsedimentary facies in the section of Jurassic volcanogenic strata are represented by thin tuffs, tuffites, tufogene-sedimentary rocks (tuff sandstones, tuff siltstones). Intrusive units are represented only by nonabyssal (hypabyssal) facies, i.e., sills and dikes. In these strata, volcanogenic facies predominate over volcanic ones. The great thickness of volcanogenic strata testifies that the penetrated section is confined to the center of volcanic activity, in the region where a continuous supply of volcanic matter masks sedimentation. According to petrographic data, volcanogenic strata changed from basalt to rhyolite. Most rocks belong to the porphyritic facies, and only a small group (dikes and sills) consists of aphyric basalt. In porphyritic rocks, plagioclase and magnetite are the main minerals. They are joined by dark-colored minerals, i.e., pyroxene, amphibole, and olivine. The contents of plagioclase, monoclinic pyroxene, amphibole, and magnetite in the main petrographic groups of rocks have been studied. Porphyritic basalts and andesite-basalts are very similar to each other in the content of all rock-forming minerals. Plagioclase is present in both and its content is approximately equal to that of bytownite-

Geology of Azerbaijan and the South Caspian Basin

13

anorthite. Clinopyroxenes are represented by subcalcic ferrous augites, characteristic of geosynclinal sequences of normal alkalinity. It is supposed that hyperalkalinity, sometimes noted in these rocks, is allogenic. The presence of amphiboles in hornblende-andesite and zeolitic metasomatites shows the volcanic origin of replaced rocks. The data obtained from chemical analyses prove the association of volcanics with basalts, andesite-basalts, andesites, andesite-dacites, dacites and rhyodacites. According to silica and alkaline oxide ratios (Na2O/K2O), basalts, andesite-basalts, andesites, and dacites belong to the limestone-alkaline gradation. Basalts and andesite-basalts are characterized by a high content of aluminia and low content of silica. In general, the composition of basic rocks of volcanogenic strata corresponds to that of the high-aluminiferous basalts of the andesitebasalt series. Acid and intermediate rocks are characterized by a low alkali content. Na2O predominates over K2O. High content of Na2O both in the basic and acidic volcanics is due to autometamorphism. Low content of TiO 2 and low content of Fe 2O 3 +FeO point to the geosynclinal nature of basalts. Analyzed rocks, on the whole, are characterized by the low content of SiO2, Fe2O3+FeO, MgO, TiO2, and K2O, and high content of Al2O3 and Na2O. Volcanogenic rocks can be differentiated on the basis of certain structural features. Rocks of the upper and middle parts of volcanogenic strata are of geosynclinal andesite-basaltic type, analogous to the Middle Jurassic (Bathonian) sequence, occurring within the Lesser Caucasus. Rocks of the lower part of the section cannot be determined beforehand because their lower boundary was not penetrated. As acidic volcanics predominate in the section, the rocks can be identified as sodic rhyolites. It is possible that at deeper horizons the volcanics of basic composition are present; then, the sequence can be identified as basalt-andesite-rhyolitic, analogous to the Lower and Middle Jurassic sequence of the Lesser Caucasus. All the rocks of volcanogenic strata are metamorphosed. Secondary minerals replace volcanic glass and primary minerals, and also infill cavities and fractures. Metamorphic minerals form varied mineral associations, among which are clay minerals, chlorite, calcite, chalcedony, quartz, albite, zeolite (laumonite), hematite, leucoxene, sphene, prehnite, epidote, pumpellyite, and sulphides. Acidic rocks, which compose the lower part of the strata, are silicified and calcitized.

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Petroleum Geology of the South Caspian Basin

In the lower part of the section some secondary minerals as quartz, chalcedony, sericite, and epidote are added to chlorite and calcite. With increase in depth, the low-temperature zeolites are replaced by more high-temperature epidote and then by prehnite-pumpellyite (greenschist stage of metamorphism). A low-temperature calcite-chlorite is also developed. A geochemical trend of main chalco-lithophylic elements in volcanics coincides with that in calcic-alkaline extrusive series of island arcs. Geochemical regularities in distribution of rare elements in rocks of volcanogenic strata correspond to those in volcanics, originated in zones of island arcs. In the SD-1 well section, the degree of helium preservation in volcanics is lower than in terrigenous deposits of the sedimentary sequence. Geochemical analyses of gases dissolved in interstitial solutions and/or adsorbed in the rocks, showed that the main components of gases emanating from volcanic rocks are carbonic-acid, nitric-carbonicacid, and hydrocarbons. The main hydrocarbon gas is methane. According to the results of gravity and magnetic surveys, the region of the Talysh-Vandam gravity maximum is structurally heterogeneous. Different areas of maxima (anomalies of the second order) are of different origin in the Earth’s crust. In the subsurface structure of the Saatly-Kyurdamir maximum, the projection of Pre-Alpine basement is interpreted as the complex of Upper Archean and Lower Achean sequences with allochtonous features. In the Alpine complex overlapping basement, products of Mesozoic magmatism of basic and intermediate composition are developed. During the second stage of drilling (below 8,000 m), it is expected that the SD-1 well will penetrate magmatic rocks of Mesozoic or older age; below 10,000 m, the older basement metamorphic rocks are expected. Saatly SD-1 well is one of the first wells which will penetrate rocks of great depth and answer many questions. Scientific and practical findings from the first stage of drilling the SD-1 well are the following: 1. The Earth’s crust section 8-km thick has been penetrated. This section is a standard not only for Saatly-Kyurdamir buried uplift, where commercial oil is produced from the volcanogenic strata, but also for the whole Alpine zone of the southern part of the Transcaucasus, where deposits of the most important commercial minerals are located.

Geology of Azerbaijan and the South Caspian Basin

15

2. The volcanogenic section penetrated by the well is 5,000-m thick, which contradicts the existing opinion that the sedimentaryvolcanogenic section overlying the Saatly local uplift is thin. 3. Microfauna (radiolaria) present at a depth of 6,560 m in siliceous tuff siltstones point to the deep accumulation of volcanogenic material of Jurassic age. This changes the existing opinion on the tectonic-magmatic evolution of the region reflecting the geosynclinal regime of the Transcaucasus Median Masiff development. 4. The results of petrochemical and geochemical study of the volcanics and the distribution of rare elements in the deposits show that they have been derived from calcic-alkali magma of the same source formed in island arc zones. 5. According to the prognosis, within the Kura Depre ssion the temperature must rise by 2–2.5°C per hundred meters of depth. This prognosis was not confirmed. At a depth of 8 km, the temperature reaches only 140°C. Such a low temperature at great depth is caused by low heat flow from the interior of the Earth’s crust due to tectonic-magmatic evolution of the region.

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Petroleum Geology of the South Caspian Basin

CHAPTER 2

Mud Volcanoes Mud volcanism and magmatic volcanism are two varieties of tectonic activity. As distinct from magmatic volcanism, mud volcanism originates and is manifested in sedimentary cover of the Earth’s crust. The tectonic nature of mud volcanism is associated with prolonged and steady development of subsiding zones, which are filled mainly with thick series of sandy-clayey rocks enriched with liquid and gas. Volcanism in general and mud volcanism, in particular, are closely associated with plicative, disjunctive and injective dislocations. Areas of volcanic activity are responsible for the transfer of huge masses of not only fluids but also breccia-plastic rocks. Thus, mud volcanism is an indicator of, and powerful factor for, transfer, dispersion, and concentration of rocks, liquids and gases, including oil and natural gas. Eastern Azerbaijan and Western Turkmenistan with adjacent submerged areas of the Caspian Sea are classic regions of mud volcanoes of different morphological types which eject solid, liquid and gaseous products at the surface. Roots of mud volcanoes reach to depths of 10–15 km and more (Mesozoic) in the Apsheron Peninsula, in the Gobustan area, Kura lowland, offshore areas of Apsheron and Baku archipelagoes and Apsheron Threshold, which are important oil- and gas-producing regions. The total area of mud volcanism in Eastern Azerbaijan is 16,000 km2, including more than 200 mud volcanoes (Figure 2-1). Scientists believe that there are 150 underwater mud volcanoes in the Southern Caspian Sea and 9 mud-volcanic islands. It is ascertained that mud volcanoes are confined to the most deformed portions of late geosynclinal trend (i.e., to molasse troughs), to the periphery of folded systems (i.e., to foredeeps), periclinal troughs of active geosynclinal folded regions, where thickness of sedimentary fill exceeds 10 km. The following factors are prerequisites for generation of mud volcanoes: anticlinal structure, dislocations with breaks of continuity, plastic clays, buried formation water, accumulation of hydrocarbon gases and abnormally-high formation pressure. 16

Mud Volcanoes

17

Figure 2-1. Locations of mud volcanoes in the eastern Azerbaijan (Modified after the Excursion Guide-Book for Azerbaijan SSR, Vol. I, 1984). a— Anticlines, b—mud volcanoes, c—areas with mud cones, d—boundaries between regions. The main structural areas: I—Pre-Caspian monocline, II—Shemakha-Gobustan area, III—Lower Kura Depression, IV—Apsheron Peninsula, V—Baku Archipelago.

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Petroleum Geology of the South Caspian Basin

Mud-volcano gases consist of saturated and unsaturated hydrocarbons (99% of which is CH4), a small amount of heavy hydrocarbons, CO2, N2, and other inert components (helium, argon). The chemical composition of gases varies between different regions. Isotopic analyses show that these gases originated mainly in sedimentary strata. Salinity and trace elements (I, B, Br) indicate that water from mud volcanoes is similar to the formation water of oil and gas fields. Alkaline water of sodium bicarbonate type predominates. Oligocene-Miocene and Pliocene deposits are dominated by fragmental products of mud volcanoes eruptions. About 90 minerals and more than 30 trace elements are present in mud-volcanic breccia. These include: boron, mercury, manganese, barium, strontium, rubidium, and copper. Volcanic mud is used widely for medicinal purposes including treatment of arthrithis and rheumatism.

YASAMALY VALLEY The offshore portion of the Dzheirankechmes Depression in the Central Gobustan area is located south of Baku Trough. It was filled with sediments of the Productive Series, and Akchagylian and Apsheronian deposits. A number of narrow and wide anticlinal trends are revealed within this depression. Anticlines are faulted; the faults are associated with wide zones of breccia, to which centers of mud volcanoes are confined. Mud volcanoes are widely distributed within the Dzheirankechmes Depression, where they reach large size: Lokbatan, Akhtarma, Kushkhana, Kyzyltepe, Shongar, Sarynja, Gyulbakht, Pilpilya, Otmanbozdag, Greater Kyanizadag, Tourogai, etc. The Lokbatan-Otmanbozdag group of volcanoes (Figure 2-2) is located in the northwestern portion of the Dzheirankechmes Depression, whereas Greater Kyanizadag and Tourogai are situated in the southwestern part of this depression, south of the Dzheirankechmes River. There are two anticlinal uplifts: dome-shaped Tourogai and brachyform Kyanizadag, which are composed of deposits of Productive Series in the crestal areas. These anticlines are faulted, and mud volcanoes are confined to faults. Lokbatan Mud Volcano is situated within the southern part of Yasamaly Valley and coincides with the Lokbatan oil field (Figure 2-3). Here, Pleistocene terraces are widespread, as well as limestones

Mud Volcanoes

19

Figure 2-2. Distribution of mud volcanoes in the Lokbatan-Karadag area.

of the Apsheronian Stage (Late Pliocene) and Middle Pliocene sandstones and shales. The mud volcano is located on the anticlinal arch and is a dome-shaped uplift (80 m) with two culminations on the top, with crater in-between. Mud volcanic breccia is 150-m thick and occupies an area of 425 hectares. Lokbatan is one of the largest and most active mud volcanoes in the world. It holds a record for the number of eruptions: since 1828, there have been 18. The last one occurred in 1980. The most intensive eruptions of this volcano occurred in 1887, 1935, 1954, 1972, and 1977. During the eruption of October 1977, the volcano spewed 30 MMm3 of natural gas and more than 150,000 m3 of mud-volcanic breccia. Solid ejecta include oil-saturated terrigenous and carbonate rocks of the Paleogene-Miocene and Late Cretaceous age. Volcanic activity has not greatly influenced reservoir pressure and oil production. For 50 years, more than 27 MMt of oil and 2 Bm3 of natural gas have been produced from Lokbatan field. Thus, volcanic roots are very deep.

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Petroleum Geology of the South Caspian Basin

Figure 2-3. Lokbatan Mud Volcano (Modified after the Excursion Guide-Book for Azerbaijan SSR, Vol. I, 1984). 1—Fault, 2—mud-volcanic breccia, 3—gas, 4—oil.

ALYATY RIDGE Alyaty Ridge, which is situated near the Pirsagat River, is the eastern continuation of the large Adzhichai-Alyaty anticlinal trend. This trend corresponds to the deep-seated thrust which separates the ShemakhaGobustan synclinorium of the Greater Caucasus and Lower Kura Depression. The Alyaty anticlinorium is asymmetric: its northwestern slope dips

Mud Volcanoes

21

toward the Dzheirankechmes River, whereas its southwestern slope is overturned in some places. Within Alyaty Ridge, there are more than 12 mud volcanoes. Their roots reach Cretaceous deposits and point to the oil and gas occurrence at deeper intervals. Dashgil Mud Volcano is located 2–2.5 km north of Alyaty railway station, which is situated 60 km southwest of Baku. The volcanic cone is a flat uplift elongated in east-west direction. Tectonically, it is confined to latitudinal faults extending along the western periclinal axis of the Dashgil structure. Dashgil is one of the active mud volcanoes in eastern Azerbaijan. It has erupted in 1882, 1902, 1908, 1926, and 1958. The area of volcanic breccia extends over 470 hectares, with an average thickness of 55 m. The volume of breccia spewed by the volcano is about 260 MMm3. Presently there are 50 active vents around the crater, intensively erupting mud, gas and water with an oil film. The height of the vent cones ranges from 0.5 to 2.5 m. The diameter of the crater is more than 200 m. At its southern part, there are outcrops of charred argillaceous rocks of the eruption of 1958. Among solid ejecta of the volcano are oil-saturated Miocene carbonate rocks and sandstones of the Middle Pliocene age. Gegerchin (Kirdag) Mud Volcano is located 5.6 km northwest of Alyaty railway station. With the Dashgil volcano, it forms an arched trend in a north-south direction. Vents spew mud, gas and water with an oil film. Among solid ejecta are fragments of limestones, marls and sandstones saturated with oil. Koturdag Mud Volcano is located 4 km southwest of Alyaty railway station, forming an isolated uplift. In the west it is separated from the Airantekyan uplift by a depression in which the oil-saturated Middle Pliocene sands were deposited. Koturdag mud volcano, which erupted in 1966 and 1969, is confined to the crestal part of the Koturdag uplift. Airantekyan Mud Volcano is located 10 km northeast of Atbulak railway station and morphologically is one of the Alyaty trend uplifts. The last eruptions occurred in 1964 and 1969, when temperature in the crater reached 800–1,000°C. In the crater area there are 70 mud vents, which spewed mud, gas and water with an oil film. The area of volcanic breccia extends over 805 hectares.

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Petroleum Geology of the South Caspian Basin

CHAPTER 3

Regional Distribution of Oil and Gas Azerbaijan is one of the oldest oil- and gas-producing provinces not only in the former Soviet Union but in the world. Oil and gas have been produced commercially for more than 150 years. Occurrences in Azerbaijan have been studied by numerous scientists, petroleum geologists, geophysicists and engineers: Gubkin (1937), Mirchink (1939), Abramovich (1948), Potapov (1954), Khain (1954), Krems (1954), Akhmedov (1957), Putkaradze (1958), Melik-Pashayev (1959), Samedov (1959), Babazadeh (1960), Ovnatanov (1962), Alikhanov (1964), Samedov and Buryakovsky (1966), Bagir-zadeh and Buryakovsky (1974), Yusufzadeh (1979), Ali-zadeh et al. (1985), and Buryakovsky (1993b, 1993c, 1993d). The oil and gas areas and their potential are shown in Figure 3-1, whereas play distribution is presented in Figure 3-2. The Apsheron Oil and Gas Region includes the Apsheron Peninsula and adjacent offshore area up to the Kyapaz Field. Middle Pliocene deposits (the so-called Productive Series) consist of wellsorted quartz sands and sandstones, which have good porosity and permeability, and are separated by impermeable shales. Although the Productive Series remains the main play, there is definite interest in clastic and carbonate reservoirs of the Cretaceous age. Several fields have already been discovered in the Productive Series within the northern part of the Baku Archipelago Oil and Gas Region. Further prospects occur in the Lower Productive Series and Oligocene and Miocene sandstones. Exploration efforts, however, have been disappointing in the central part of the region. But both central

22

Figure 3-1. Regional distribution of oil and gas in Azerbaijan and the South Caspian Basin (Modified after Aliyev et al., 1985). Regions: 1—with significant, proved, initial potential resources; 2—highly favorable (offshore); categories of favorability: 3—first, 4—second, 5—third; 6—areas favorable for oil and gas; 7—areas possibly favorable; 8—areas with unclarified prospects; 9—areas with no prospects. Oil- and gas-bearing areas: I—Apsheron, II—Baku Archipelago, III—Lower Kura, IV—Shemakha-Gobustan, V—Yevlakh-Agdzhabedy, VI—Gyandzha, VII—Kura-Iori interfluve, VIII—PreCaspian-Kuba, IX—deep-water parts of the South Caspian Basin; possibly favorable areas: X—Adzhinour, XI— Dzhalilabad; areas with uncertain potential: XII— Dzharly-Saatly, XIII—Mil-Mugan, XIV—Alazan-Agrichai, XV—Araks, XVI— Nakhichevan.

Regional Distribution of Oil and Gas 23

Figure 3-2. Oil and gas plays in Azerbaijan (Modified after Aliyev et al., 1985). 1—Productive Series (Middle Pliocene); 2—Paleogene-Miocene clastic reservoirs; 3—Cretaceous clastic-carbonate reservoirs; 4—Upper Cretaceous carbonate reservoirs; 5—Lower Cretaceous clastic-carbonate reservoirs; 6—areas with undetermined potential; 7—areas with no prospects.

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Petroleum Geology of the South Caspian Basin

Regional Distribution of Oil and Gas

25

and southern parts still have good reservoirs with seals and structures that remain to be tested. Also, active mud volcanoes occur here. The Lower Kura Depression is classified as having a first-order category of prospective oil and gas fields; however, many fields here have been already depleted. The potential for new oil and gas accumulations lies in parts of the Productive Series at great depth. On the northeast border of the Yevlakh-Agdzhabedi Depression, oil accumulations have been discovered in the Upper Cretaceous volcanic rocks and in the Eocene deposits in Muradkhanly and Zardob fields. This has been the basis for the interest in the Upper Cretaceous clastics-carbonates section, although there is still great interest in Eocene deposits. The Kura-Iori Interfluve became a first-category potential region after discovery of Tarsdallyar field in 1983. The primary play here is the Upper Cretaceous and Eocene clastics-carbonates section. In the Pre-Caspian-Kuba Oil and Gas Region, the main targets are the Siazan Monocline and adjacent Talabi-Kainardzha anticlinal trend. On the Siazan Monocline, commercial oil accumulations have been found in the reservoirs of Late Cretaceous through Miocene age. The OligoceneMiocene deposits are being tested in the Talabi-Kainardzha zone. In the Shemakha-Gobustan Oil and Gas Region, there is a great interest in southern and central Gobustan. In southern Gobustan, commercial oil and gas accumulations have been found in the OligoceneMiocene (Maikop Stage and Chokrak Formation) and in the Middle Pliocene (the Productive Series) rocks. Prospects here are buried Paleogene-Miocene structures of the Dzheirankechmes Depression. Another play is the Upper Cretaceous carbonate section of central and southern Gobustan. In the Gyandzha Oil and Gas Region, small oil accumulations have been discovered in Paleogene-Miocene rocks. This region is assessed as having poor potential. In the deep-water part of the South Caspian Basin, seismic survey and deep drilling have disclosed several favorable structures (from the Productive Series). In the Adzhinour Region, geological surveys have disclosed strongly deformed local highs in Pliocene-Quaternary deposits. The PaleogeneMiocene and Cretaceous deposits offer good possibilities here. Geophysical surveys, however, have not been encouraging for deep intervals.

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Petroleum Geology of the South Caspian Basin

The Dzhalilabad Area has a thick Paleogene-Neogene section, which consists of volcanic and clastic deposits. Strong oil and gas shows have been found in several parts of the Tumarkhanly-Germelin trend, where the Maikop and Chokrak formations are prospective. Areas with unknown oil and gas prospects are (1) the AlazanAgrichai and Araks downwraps, (2) the Dzharly-Saatly and Mil-Mugan zones of buried Mesozoic volcanic deposits, and (3) the Nakhichevan depression. Regional geophysical surveys and appraisal drilling are recommended for these areas.

CHAPTER 4

Lithostratigraphic Framework Past environmental conditions and the lithology within the geosynclinal regions are responsible for physical and chemical properties of sedimentary rocks. Post-depositional alteration (diagenetic and epigenetic) of sediments is dependent upon a great number of factors. Discovery of commercial oil and gas accumulations, and reserve evaluation, require the investigation of both reservoir and caprock properties. This is especially important for young sedimentary basins, which are characterized by thick, rapidly accumulated sand, silt, and shale sequences. A vivid example is the South Caspian Basin, which is distinguished by a diverse and unique set of characteristics: 1. An exceptionally high rate of sediment accumulation of up to 1.3 km/MMy. 2. Thick sedimentary cover (up to 25 km) including up to 10 km of Quaternary-Pliocene deposits. 3. Siliciclastic (sand-silt-shale) type of sediments. 4. Abnormally high formation pressures averaging up to 1.8 times greater than normal. 5. Low heat flow and formation temperature: at a depth of about 6 km, the temperature is approximately 105–110°C. 6. An inverted hydrochemical profile: with depth, calcium chloride and magnesium chloride waters change to sodium bicarbonate waters, i.e., water salinity decreases with depth. 7. Widespread mud volcanism. The main oil- and gas-bearing formation within eastern Azerbaijan and the South Caspian Basin is the Middle Pliocene Productive Series. The rocks of this formation, where oil and gas accumulations occur, have been the most thoroughly studied. Thickness of the Productive Series increases toward the central part of the South Caspian Basin

27

28

Petroleum Geology of the South Caspian Basin

in the southerly and southeasterly direction, from an average of 1,500 m in the Apsheron Peninsula to 3,150 m within the Apsheron Archipelago, to 4,150 m in the South Apsheron Offshore Zone, and to 4,400 m within the Baku Archipelago. Sedimentary rocks of Pliocene age (Pontian Stage, Productive Series, Akchagylian and Apsheronian stages) have been extensively studied. Pontian sediments (Lower Pliocene) consist of thinly-bedded, deepwater, gray and dark-gray, unconsolidated, limy shales; sands are rare. Characteristic fossils are Paracypria loezyi Lal., Leptocythere praebacuana Liv., Loxoconcha alata Schn., Loxoconcha eichwaldi Liv., and other Ostracoda, and embryonic Pelecypoda. The lithology of the Productive Series (Middle Pliocene) has been studied from outcrop samples, and cores and logs from deep wells. These deposits are devoid of fauna and, as a consequence, their stratigraphic position is determined by faunal characteristics of the underlying Pontian Stage and overlying Akchagylian Stage. Subdivision of the Productive Series is generally based on lithological changes resulting from cyclic deposition. The Upper Pliocene, which includes Akchagylian and Apsheronian sections, conformably overlies the Middle Pliocene Productive Series. The Akchagylian Stage, 50–70-m thick, consists of gray to green-gray, laminated shales with thin interbeds of fine-grained sands and volcanic ash. The 700-m thick Apsheronian Stage is subdivided into three sections. The top of the upper section consists of coquina and detrital limestones, whereas the base consists of alternating fine-grained and dense sandstones, shales and detrital limestones. The middle section is represented by dark-gray sandy shales with thin interbeds of finegrained sands and coquina. The lower section consists of dense sandy shales with thin sand interbeds. Quaternary old Caspian Sea deposits are represented by the Baku Stage, which is composed of dark-gray clays with thin interbeds of red sands. Thickness reaches 600 m. Recent sediments include coquinaooze formations, and local, coarse-grained sands. The Productive Series is divided into lower and upper divisions, and into several suites according to lithological composition, depending on their sand/shale ratio. The set of rocks includes sand, sandstone, siltstone, loam, shale, and chlidolites (unsorted sediments1 ) (Figure 4-1). 1

Chlidolites or unsorted sediments consist of equal amount (i.e., 1/3 each) of sand grains, feldspar grains, and various rock fragments.

Lithostratigraphic Framework

Figure 4-1. Stratigraphic section of the Productive Series.

29

30

Petroleum Geology of the South Caspian Basin

The lower division consists of (from bottom upward) the following suites: 1. 2. 3. 4. 5.

Kala (KaS) Podkirmaku (PK) Kirmaku (KS) Nadkirmaku Sandy (NKP) Nadkirmaku Shaly (NKG)

The upper division consists of the following suites: 1. 2. 3. 4.

“Pereryv” (“first break in deposition”) Balakhany Sabunchi Surakhany

The lithological characteristics of the enumerated suites and units are presented below.

Lower Division The Kala Suite, in the Apsheron Peninsula and Apsheron Archipelago, consists of sandstones, siltstones, shales, chlidolites, and sandy loams, primarily of gray color. Thicker layers of sandstones and siltstones are identified at the base of the upper portion of the suite. In the Baku Archipelago, the Kala Suite primarily consists of shale with interbeds of sandstones and siltstones. The Podkirmaku Suite, in the Apsheron Peninsula and Apsheron Archipelago, consists mainly of sands, sandstones, siltstones, and unsorted sediments with some shales. In the Baku Archipelago, sandstones also predominate in the PK suite, alternating with shales, argillaceous siltstones and sandstones. The Kirmaku Suite, in the Apsheron Peninsula and Apsheron Archipelago, consists predominantly of shales, with lesser amount of sandstones and siltstones. In the Baku Archipelago, the KS suite consists of gray shales with interbeds of fine-grained sandstones, with their content increasing toward the base of the suite, as well as toward the southeast, in the direction of subsidence. The Nadkirmaku Sandy Suite, within the Apsheron Peninsula and Apsheron Archipelago, is distinguished from the underlying KS suite by an increase in the content of sandysilty deposits. In the Baku Archipelago and Lower Kura region this suite is named Unit VIII. The Nadkirmaku Shaly Suite consists

Lithostratigraphic Framework

31

primarily of shales, loams, and sandy loams, with some thin sandstone and siltstone beds in the lower portion.

Upper Division The “Pereryv” Suite is composed predominantly of unsorted rocks, with rare sandstone and siltstone interbeds. To the south (Baku Archipelago, where it is named Unit VII), the suite consists primarily of shale. In the basal portion it is represented by loamy sands, and in the middle portion, by chlidolites. The Balakhany Suite is made up of sandstones, siltstones, shales, chlidolites, loams, and loamy sands. In the Apsheron and Baku archipelagoes, silty sandstones predominate at the base of the suite. The Sabunchi Suite consists of siltstones, poorly sorted sandstones, and shales. Sandy intervals IV, III, and II are present in the southern portion of the Apsheron Archipelago, whereas in the Baku Archipelago, units IV and III consist of siltstones, with their content increasing in Unit III and alternating with shales. The Surakhany Suite is made up of silty shales, argillaceous siltstones, sandstones, unsorted rocks, and rare gypsum interbeds.

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Petroleum Geology of the South Caspian Basin

CHAPTER 5

Onshore Oil and Gas Fields Four major oil- and gas-bearing regions (Figure 5-1) exist onshore in Azerbaijan: I. II. III. IV.

Apsheron Peninsula Pre-Caspian–Kuba Monocline Lower Kura Lowland Yevlakh-Agdzhabedi Area

REGION I: APSHERON PENINSULA Oil- and gas-bearing zones in the Apsheron Peninsula are mainly of Middle Pliocene (Productive Series), Upper Pliocene (Apsheronian Stage), and Miocene (Diatom Suite, Chokrak Formation) ages. The main oil- and gas-bearing and productive interval here is the Productive Series, which is subdivided into two divisions. The Upper Productive Series (i.e., the upper division) includes the following suites (from top to bottom): Surakhany, Sabunchi, Balakhany, and “Pereryv” (the first break in deposition). The Lower Productive Series (i.e., the lower division) includes the following suites (from top to bottom): Nadkirmaku Glinistaya (Shaly)—NKG; Nadkirmaku Peschanaya (Sandy) —NKP; Kirmaku—KS; Podkirmaku—PK; and Kala—KaS. Oil and gas fields of the Apsheron Peninsula and Apsheron Archipelago are multi-bedded (up to 40 oil-bearing units). Most of the oil reserves occur in fields of the central part of the peninsula: BalakhanySabunchi-Ramany, Surakhany, Karachukhur, Zykh and Gum Deniz (Table 5-1). Toward the east and southeast (Buzovny-Mashtagi, Kala, Zyrya, and other oil fields) and toward the northwest and west (Binagady, Chakhnaglyar, Sulutepe, and other oil fields) of the central part of the peninsula, oil saturation increases in the Lower Productive

32

Onshore Oil and Gas Fields

33

Figure 5-1. Oil and gas regional distribution, and fields and prospects of Azerbaijan and the South Caspian Basin (Modified after the Excursion Guide-Book for Azerbaijan SSR, Vol. I, 1984). 1—Boundaries between oil- and gas-bearing regions, 2—boundaries between oil- and gas-bearing areas, 3—oil fields, 4—gas and gas-condensate fields; Oil- and gas-bearing areas: 5—high oil and gas content, 6—moderate oil and gas content, 7—potential structure, 8—structure with low potential. Oil- and gas-bearing regions and areas (areas are shown in circlets): I—Apsheron-Gobustan region (areas: 1—Apsheron, 2—Shemakha-Gobustan); II—Pre-Caspian–Kuba region; III—Kura region (areas: 3—Lower Kura, 4—Kyurdamir, 5—Gyandzha, 6—Adzhinour, 7—Kura-Iori interfluve, 8—Alazan-Agrichai, 9—Dzhalilabad, 10—Baku Archipelago); IV—Araks area. Fields: 1—Balakhany-Sabunchi-Ramany, 2—Surakhany, 3—Karachukhur-Zykh, 4—Gum Deniz, 5—Gousany, 6—Kala, 7—Buzovny-Mashtagi, 8—Darvin Bank, 9—Pirallaghi Adasi, 10—Gyurgyan Deniz, 11—Chalov Adasi, 12—Azi Aslanov, 13—Palchygh Pilpilasi–Neft Dashlary, 14—Dzhanub, 15—Bakhar, 16—Binagady-Chakhnaglyar, 17— Sulutepe, 18—Yasamaly Valley, 19—Bibieibat, 20—Puta-Lokbatan, 21—KyorgyozKyzyltepe, 22—Karadag, 23—Shongar, 24—Umbaki, 25—Duvanny, 26—Dashgil, 27— Chondagar-Zorat, 28—Siazan-Nardaran, 29—Saadan, 30—Amirkhanly, 31—Eastern Zagly, 32—Zagly-Tengialty, 33—Kyurovdag, 34—Karabagly, 35—Khillin, 36—Neftechala, 37—Kyursangya, 38—Mishovdag, 39—Kalmas, 40—Pirsagat, 41—Malyi Kharami, 42—Kalamadyn, 43—Muradkhanly, 44—Kazanbulag, 45—Adzhidere, 46—Naftalan, 47—Mirbashir, 48—Sangachal, 49—Duvanny Deniz, 50—Khara Zyrya, 51—Bulla Deniz, 52—Garasu.

Surakhany Sabunchi Balakhany “Pereryv” NKG NKP KS PK KaS Total

Suite

6.3 200.1 147.5 0.2 1.2 13.5 54.8 76.5 — 500.1

Million Tons %

1.3 40.2 29.5 — 0.2 2.7 10.8 15.3 — 100.3

BalakhanySabunchiRamany

5.8 60.0 28.2 — 1.9 5.0 7.4 28.6 0.4 137.3

Million Tons %

4.2 43.7 20.5 — 1.3 3.7 5.4 20.9 0.3 100.3

Surakhany

— 10.2 11.3 — 0.2 0.8 4.0 16.3 3.8 46.6

Million Tons

— 21.7 24.4 — 0.5 1.6 8.6 34.9 8.3 100.3

%

Karachukhur

— — 2.1 — — — 0.2 9.9 1.3 13.5

Million Tons

%

— — 17.7 — — — 1.5 71.2 9.6 100.3

Zykh

Table 5-1 Comparison of Oil Reserves in the Central Apsheron Peninsula Fields

— — 17.3 — — 0.6 7.3 21.2 4.4 50.8

Million Tons

%

— — 34.1 — — 1.2 14.4 41.7 8.6 100.3

Gum Deniz

34

Petroleum Geology of the South Caspian Basin

Onshore Oil and Gas Fields

35

Series and decreases in the Upper Productive Series. Oil accumulations in the Diatom Suite are present in the west and southwest of the peninsula (Binagady, Lokbatan, Kergyoz, and other fields). Different traps are present in the Productive Series of the Apsheron Peninsula: structural (anticlinal and faulted), stratigraphic, and combination traps. Terrigenous (siliciclastic) reservoir rocks consist of sand, sandstone, and siltstone separated by shale interbeds. Reservoir rocks are highly porous and permeable. The Baku Trough is a synclinal structure located between the Karachukhur-Zykh anticline to the east and Bibieibat uplift to the west. Rocks in the trough consist mainly of shale and sand alternating with limestone beds. The latter compose the upper part of the section forming a bench around the trough composed of Late Pliocene and Post-Pliocene deposits. Kirmaku Oil Field is located in the central part of the Apsheron Peninsula, 15 km north of Baku, and between two large oil-bearing regions: the Balakhany-Sabunchi-Ramany group of oil fields to the southeast and the Binagady-Chakhnaglyar-Sulutepe group of oil fields to the southwest. Three topographic features are distinguished in the area of Kirmaku Field: the Kirmaku Ridge, Binagady Height, and Bogboga Mud Volcano. The highest point is Kirmaku Mountain (104.7 m) located in the southern part of the Kirmaku Ridge. The surface of the mountain is covered with many tar pits and shallow wells, which produced oil in the past. Structurally, Kirmaku Field has an asymmetric, box-like shape (Figures 5-2 and 5-3). Dips are 40–50° on the eastern flank, and 60– 70° on the western flank; dips decrease to 25° toward the crest, and on the periphery of the structure they decrease to 10°. The axis of structure extends about 3 km, and the width of the structure is about 400 m. The core consists of Paleogene and Neogene rocks. The Kirmaku structure is made up of the Neogene rocks (Productive Series of Middle Pliocene and Pontian Stage of Lower Pliocene). The crest consists of Pontian shale surrounded by the Podkirmaku Suite of the Lower Productive Series. The structure consists mainly of the Kirmaku Suite deposits characterized by a frequent alternation of shale, silt and sand. Recent and old Caspian Sea deposits rest unconformably on older Neogene rocks exposed by erosion.

36

Petroleum Geology of the South Caspian Basin

Figure 5-2. Geologic map of Kirmaku Oil Field (Modified after Alibekov et al., 1964). 1—Lower Balakhany Suite, 2—“Pereryv” Suite, 3—NKG Suite, 4—NKP Suite, 5—KS Suite, 6—PK Suite, 7—Pontian Stage.

Many geologists have studied the field structure. As a rule, however, they used rock samples only from outcrops. Additional detailed study, including exploratory drilling, was needed for field development. In the 1950s, 62 exploratory wells were drilled in three phases within the field area (Figures 5-2 and 5-3). Most of the wells were cored, and a total of 1,039 core samples were recovered and analyzed. The major productive interval, the Kirmaku Suite (KS), is represented by alternating shale, very fine- to fine-grained, argillaceous sand, and silt of brown and gray color. Total thickness of the suite ranges from 250 to 260 m. The KS interval is the most consistent in thickness and lithology over the whole section of the Productive Series. Quantitatively, sand and silt content prevail over that of shale. The KS section consists of 74% sand, sandstone and silt, and of 26% shale and sandy-silty shale. Thickness of sand and shale beds varies between

Onshore Oil and Gas Fields

37

Figure 5-3. Structural map and cross-section of Kirmaku Oil Field (Modified after Alibekov et al., 1964). (a) Structural map on the top of Pontian Stage: 1—well, 2—contour line on top of Pontian, 3—outcrops of Pontian rocks; (b) cross-section.

38

Petroleum Geology of the South Caspian Basin

1–2 mm to 10–20 cm. Among sandy-shaly alternations one can observe thicker interbeds of sand and shale up to 3–4 m. The number and thickness of sandy-silty beds are higher in the lower portion of the section. Average porosity of reservoir rocks is 26%, and the carbonate cement content is 8–16%. The underlying Podkirmaku Suite (PK) is the second oil-bearing formation penetrated by boreholes both in the crestal area of the structure and on its flanks. The PK Suite is the thickest (about 40 m) in the southern plunged portion of the structure. Toward the crest, thickness decreases significantly. The PK section is made up of medium- to coarse-grained quartz sand with large quartz grains and unevenly shaped pebbles. Sand is gray and light-gray in color, whereas pebbles are black. The upper part of the PK section contains mediumand fine-grained sand with some thin shale interbeds. In the lower and middle parts, grain size increases and shale interbeds disappear. Within the PK section, particularly in the lower part, one can observe interbeds of very dense and hard calcareous sandstone. Thickness of this sandstone ranges from 10–20 cm to 50 cm. Average porosity of the reservoir rocks is 26–28%; carbonate cement content is 12–15%. Kirmaku Oil Field has long been known as the place of oldest production of oil and asphalt. The precise date of earliest Kirmaku Oil Field production is unknown, but accounts date back as early as 1834. Initially, oil was produced from shallow pits in outcrops using bailers. Later, shallow wells with timber-lined walls were dug. These wells were situated, mainly, on the eastern and southern slopes of Kirmaku Mountain, and to a considerably lower extent, on the western slope. Depending on the location within the area and on the depth of productive formation, well depth varied greatly. Average depth was 50–60 m; however, some were up to 190 m deep. Some wells were very shallow: no more than 10–20 m deep. In the past, Kirmaku Field oil and gas wells were produced at maximum rates with rapid reservoir depletion. In some cases, flow per well reached 11–13 tpd (80–90 bpd). Production rate, however, could be sustained only for 1–2 months, and then declined to 1.0–1.5 tpd. Such practice, at that time, was believed to be normal, and most wells typically produced for several months and sometimes even for years. As production rate declined, wells were deepened to the next productive bed.

Onshore Oil and Gas Fields

39

Peak monthly oil production reached 4,500–5,000 tons before 1914 and World War I. The total number of wells (in and out of operation) reached 1,500. About 50 of them (the most productive) were operated until 1926. Digging of new wells was stopped in 1913, and was prohibited from then on. Maximum potential production rate was 3–5 m3/ day and was based on well tests. The longest oil column encountered during well testing was 60–70 m at a depth interval of 100–120 m. In other wells, the length of oil column was smaller and, in some cases, wells were dry. As a rule, the wells produced no water. Water first appeared in 1914–1917 at the northern part of the eastern flank. Oil was characterized by the following properties: density = 0.958– 0.988 g/cm3, Engler viscosity at 45°C = 10–16. A lighter oil with density of 0.903 g/cm3 and Engler viscosity of 6.84 was produced in Well 41 from a depth of 90–101 m. At present, Kirmaku Oil Field is virtually depleted of moveable oil and should be considered as a deposit of bituminous sands. Field development by routine well drilling probably will be quite ineffective. The use of one of the enhanced oil recovery methods (e.g., heat stimulation or injection of solvents) probably will not be effective, because the oil-saturated rocks are penetrated by many wells which will be very hard and expensive to seal. Field development by mining appears to be a reasonable one. However, considering that the area has been produced for a long period of time, the advantage of this method should be verified by digging at least one experimental, sloped tunnel (with a drilling chamber) at the base of productive formation, for drilling updip boreholes. Pilot horizontal wells (164, 72, and 187-m long) were drilled at the base of the southern slope of Kirmaku Mountain in 1956. The wells were drilled using water as a drilling fluid, and completed without casing. This project demonstrated a real possibility of producing oil from such wells. At the maximum penetration into productive formation (2.0 m), one of the flowing wells has been producing at approximately 5 m3/day of total liquids including 40–60 kg of oil per day. Initial production was 10–11 m3/day of total liquids and 80–110 kg of oil per day. Using geological, analytical, and field data, one can conclude that drilling horizontal wells from the ground level is the most reasonable technique for secondary development of bituminous sands of Kirmaku

40

Petroleum Geology of the South Caspian Basin

Oil Field. The advantage of this technique is due to: (1) absence of thick overburden, (2) absence of large volumes of liquids, (3) possibility for development of bituminous sands, and (4) presence of highlydeveloped infrastructure. Bibieibat Oil Field occurs on a brachianticlinal uplift striking NNW-SSE. The first oil well was drilled here in 1848. The oil field was developed in the early 1870s. The entire Productive Series section is oil bearing. Pliocene-Quaternary deposits are present in this area. The deposits form an asymmetric fold with steep western (up to 50°) and gentle eastern (15–27°) flanks. The anticline is broken by numerous transverse faults and its crest was penetrated by a mud volcano (Figure 5-4). Deposits of Apsheronian Stage (Late Pliocene) and Pleistocene occur in the uplifts adjacent to the Baku Trough to the north, northwest and west. These deposits extend as a wide ridge in a north-south direction and infill the syncline separating Bibieibat and Shubany uplifts. Farther away, these deposits crop out along the eastern slope of Yasamaly Valley and plunge toward the Caspian Sea. Yasamaly Valley is a monoclinal valley where beds on the right and left margins dip in the same direction. The rocks are of Late and Middle Pliocene age, and constitute the eastern flank of the AtashkyahShabandag diapiric fold to the west of the valley. The road from Volchy Vorota (Wolf Gate) to the Eibat railway station crosses deposits of Apsheronian Stage (Late Pliocene). Overlying Akchagylian deposits are “disguised” under recent valley sediments. Farther, one can observe outcrops of the Upper Productive Series, consisting of alternating shale, sand and sandstone. The Yasamaly Valley Productive Series deposits in the eastern flank contain oil fields discovered in 1938 and wedge out toward the fold crest due to its diapiric structure. Atashkyah structure is confined to the ridge of the same name. The structure is eroded, strikes north-south, and Oligocene-Miocene and Lower Pliocene deposits crop out in the core; they are bordered by the Middle Pliocene deposits. The western flank of structure dips steeply (45–65°), whereas the eastern flank may be vertical or even overturned. The brachyanticline is complicated by two major longitudinal faults of overthrust character. Oil occurs in the Productive Series. Shabandag Oil Field is also located in Yasamaly Valley. The field was discovered in 1945. It is confined to an ENE flank of Shabandag

Onshore Oil and Gas Fields

41

Figure 5-4. Structural map (a) and cross-section (b) of Bibieibat Oil Field. Stratigraphy: N 2prd—Productive Series, N2ak—Akchagylian Stage, N 2ap— Apsheronian Stage.

brachyanticline, filled with Middle and Upper Pliocene deposits. The core of uplift, which is dislocated, has diapiric structure. The SW flank is steep (50–70°), but dips more gently away from the axis of structure (Figure 5-5). Oil occurs in the Lower Productive Series. On the eastern flank of the Shabandag uplift, Diatom Suite deposits are also oil bearing. The offshore portion of Dzheirankechmes Depression of the Central Gobustan is located southwest of the Baku Trough. It is filled with

42

Petroleum Geology of the South Caspian Basin

Figure 5-5. Geologic cross-section of Shabandag Oil Field. Stratigraphy: K—Cretaceous, P3—Oligocene, N11—Lower Miocene, N21—Lower Pliocene, N22—Middle Pliocene, N23—Upper Pliocene.

sediments of the Productive Series of Akchagylian and Apsheronian age. A number of narrow and wide anticlinal trends occur within this depression. Anticlines are faulted and wide zones of tectonic breccia are associated with fault zones, with mud volcanoes occurring at their centers. One of them is Lokbatan Mud Volcano, which is situated 15 km southwest of Baku. Lokbatan Oil Field is located in the area of Lokbatan mud volcano. This field was discovered in 1932, when Well 62 blew out from Unit II of the Upper Productive Series (flow exceeded 1 Mtd or 7.3 Mbd). An oil gusher (up to 20 Mcmd or 706 Mcfd) blew out from Unit 4a in 1933, in Well 45 drilled in mud volcanic breccia 1,500 m east of the volcanic vent. The entire section of the Productive Series is oil bearing. There are 16 oil- and gas-saturated intervals. The field is an asymmetric brachianticline trending latitudinally. The eastern flank is steep (about 55°), whereas the northern one is gentle (30–40°). The Productive Series rocks crop out at the crest of anticline, and are more argillaceous in comparison with those of the Bibieibat and Shubany fields. The argillaceous Oligocene-Miocene section is penetrated at the northern flank in Well 616. The anticline is complicated by a longitudinal fault (amplitude = 500 m), to which the Lokbatan mud volcano is confined (Figure 2-3); the southern flank is elevated. The fault becomes a thrust fault to the east (Figure 5-6).

Onshore Oil and Gas Fields

43

Figure 5-6. Structural map (a) and cross-section (b) of Lokbatan Oil Field.

Shemakha-Gobustan Area. In this area oil and gas occurs only in Cretaceous, Paleogene, Miocene, and Pliocene deposits. Here, Umbaki Oil Field is being produced; oil pools are confined to Maikop Suite and Chokrak Formation. Also, Duvanny Gas Field is under production.

REGION II: PRE-CASPIAN–KUBA MONOCLINE The Pre-Caspian–Kuba Monocline is situated along the northeastern slope of the southeastern termination of the Greater Caucasus meganticlinorium (Figure 5-1). Here, the Siazan Monocline is oil and gas bearing. It is located on the northeastern overturned slope of Tengiz-Beshbarmak

44

Petroleum Geology of the South Caspian Basin

anticlinorium, complicated by the large Siazan fault. Most of the oil and gas occurs in the Upper Cretaceous, Paleogene and Lower Miocene deposits (Chandagar-Zorat, Siazan-Nardaran, Saodan, Amirkhanly, Zagly-Zeiva fields).

REGION III: LOWER KURA LOWLAND Region III includes Pirsagat-Khamamdag, Kalamadyn-Byandovan, and Kyurovdag-Neftechala anticlines, extending southeast into the Caspian Sea (see Figure 5-1). These anticlinal uplifts are complicated by faults and mud volcanoes. Mainly, the Productive Series and some deposits of Akchagylian and Apsheronian stages are oil bearing. Oil and gas reservoirs are multi-bedded and most are confined to the Upper Productive Series. Kyurdamir, Karabagly, Neftechala, Pirsagat, Kyursangya, Kalmas, and other oil fields are being produced now. Many uplifts are expressed as topographic highs caused by mud volcanoes.

REGION IV: YEVLAKH-AGDZHABEDI AREA Region IV embraces lower portions of the Kura and Araks rivers and is situated along the axis of Saatly-Kyurdamir uplift (Figure 5-1). In this area, several local uplifts were found by geophysical exploration and drilling. The rocks in this region comprise Pre-Upper Jurassic and Lower Senonian intrusives of basic composition, Upper Jurassic— Lower Cretaceous carbonates (reef limestones), Upper Senonian carbonate rocks, and terrigenous rocks of Paleogene-Quaternary age. Commercial oil and gas accumulations are confined to the fractured Upper Cretaceous igneous rocks and to the Eocene and Chokrak deposits (Muradkhanly Oil Field). The region is prospective for discovery of new oil and gas fields. Muradkhanly Oil Field. Different types of reservoir rocks have been identified during the last 20 years in the territory of Central and Western Azerbaijan (Figures 3-1 and 3-2). The most interesting reservoir rocks are found at the Muradkhanly Oil Field in the center of the Kura Depression (Figure 5-7). Commercial oil reserves are associated with the fractured Upper Cretaceous volcanic rocks. Productivity of terrigenous, carbonate, and pyroclastic rocks of Eocene age is lower than the Upper Cretaceous. Small commercial oil reserves have also been discovered in the Middle Miocene terrigenous-carbonate rocks of the Chokrak age.

Onshore Oil and Gas Fields

45

Figure 5-7. Structural map on the top of volcanic rocks of Muradkhanly Oil Field. 1—Faults, 2—contour lines on top of volcanic rocks, 3—initial OWC.

Fractured volcanic rocks play an important role in creating reservoirs and traps for hydrocarbon accumulation. Reserve estimation in such traps requires sophisticated methods of studying reservoir rock properties, such as density of fractures, specific surface area, width of fractures, irreducible fluid saturation, pore space structure, porosity and permeability (Kondrushkin and Buryakovsky, 1987, Abasov et al., 1997). Logs from the Muradkhanly Oil Field show that an anticline is present above the volcanic rocks at a minimum depth of 3,000 m. Within the 4,200 m contour line, the overall field size is 15 × 11 km. The dips vary from 10 to 20°. The structure has two faults and, hence, is divided into three separate blocks (Figures 5-7 and 5-8). Oil reserves are concentrated in the crestal area (the first block) and at the western flank of the structure (the second block). The Upper Cretaceous section includes undisturbed volcanic rocks: pyroxene-andesite; biotite-, hornblende-, and pyroxene-trachyandesite;

46

Petroleum Geology of the South Caspian Basin

Figure 5-8. West-east cross-section of Muradkhanly Oil Field. 1—Volcanic rocks, 2—clay/shale, 3—alternation of sand, silt and shale, 4—marl, 5—top of the volcanic rocks, 6—boundaries between Chokrak and Eocene deposits, 7—OWC in the volcanic reservoir, 8—oil reservoir, 9—zone of absence of reservoir rocks in Eocene deposits. Stratigraphy: K2—Upper Cretaceous, P2— Eocene, P3—Oligocene, N1—Miocene, N2—Pliocene, Q—Quaternary.

porphyry and amygdaloidal basalts; and products of alteration due to weathering of volcanic rocks with admixture of clastic material (tuffsandstones, tuff-breccia, and tuff-gritstone). Penetrated thickness of sedimentary and volcanic rocks ranges from 3 to 1,952 m (Figure 5-9). Strata correlation in some sections is very difficult. Reservoirs have been formed in the weathered volcanic rocks of the upper portion of the Upper Cretaceous section. Oil traps here were formed by transgressive overlapping by Maikop shales in the shallowest part, and by Eocene terrigenous-carbonate rocks on the western flank. Porosity and permeability were measured at a depth of 450 to 500 m from the top of volcanic rocks. Deeper intervals, i.e., from 1,000 to 2,000 m (Wells 3 and 6), are dry or showed insignificant flow of water. The most productive zone is the upper section of volcanic rocks, 25–30-m thick. Here, one can observe uniform and extensive secondary rock alterations and strong oil flow in most of the wells. The oil-saturated intervals are distributed from the top of volcanic

Figure 5-9. Log correlation in volcanic rocks of Muradkhanly Oil Field. 1—Perforations, 2—slotted strainer, 3—open hole, 4—formation test, 5—core recovery.

Onshore Oil and Gas Fields 47

48

Petroleum Geology of the South Caspian Basin

rocks to a depth of 10–50 m in some wells, and to a depth of 100 m and deeper in others. As shown in Figure 5-8, the bottom of oil accumulation is located at different depths in different volcanic rocks. This means that there is no continuous and flat oil-water contact; instead, it has a wave-shaped form. The real oil-reservoir boundaries intersect the contour lines on the top of volcanic rocks, and oil is present in the secondary porosity of these rocks. The reservoirs are characterized by non-uniform oil content, both in lateral and vertical directions. Consequently, production rates vary within wide limits, i.e., the initial oil production rate varies from 1 to 30 tpd (7 to 220 bpd) in 48% of wells, from 30 to 100 tpd (220 to 750 bpd) in 35% of wells, and more than 100 tpd (750 bpd) in 17% of wells. The maximum initial water production in most wells (58%) is 10 m3/day. The initial reservoir pressure and temperature are 55 MPa and 125°C, respectively. The initial reservoir pressure is higher than the bubble-point pressure by 40 MPa and higher than the normal hydrostatic pressure by 20 MPa. Gas content in oil is 30 m3/ton and the average oil density is 0.880 g/cm3 under standard conditions. The oil is paraffinic, with low sulfur content. The porosity of volcanic rocks is of fracture-vuggy and intergranular type. Large intergranular pores, vugs and fractures are present in the core samples (Figure 5-10). Large pores are 1 mm (average) in diameter, whereas vugs have diameters of 2 cm (average). Microfractures, which contain mainly calcite and argillaceous cement, have widths of 0.1 mm and wider. Oil is present in large intergranular pores, vugs, and fractures. During drilling, lost circulation (up to 100 m3/day) and high oil flows (up to 500 tpd) in several wells suggest that there are long and wide fractures in the volcanic rocks. Petrographic studies show that reservoir properties depend on the degree of weathering of volcanic rocks. The formation of large pores and vugs is due to the plagioclase dissolution. Sometimes, when plagioclase and other minerals are dissolved, microcaverns are formed. Microfractures have been studied in 4 × 5-cm thin-sections. Microfracture porosity ranges from 0.04 to 0.004%, fracture permeability varies from 0.16 to 6.90 mD, and average density of fractures is 0.30 cm/cm2. Scanning Electron Microscope (SEM) micrographs show that the volcanic rock texture depends on the original properties of the unweathered rocks and subsequent weathering and alteration (Figure 5-11). Alteration

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Figure 5-10. Oil-saturated core sample from the volcanic rocks of Muradkhanly Oil Field. Well No. 66, depth interval of 2,956–2,962 m (9,698–9,718 ft); andesite.

Figure 5-11. SEM microphotograph of the volcanic rock sample from Muradkhanly Oil Field. Well No. 6, depth interval of 3,027–3,031 m (9,931–9,944 ft); magnification = ×100.

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Petroleum Geology of the South Caspian Basin

of ash resulted in the formation of montmorillonite, chlorite and biotite during diagenesis and catagenesis. Matrix secondary pores range in size from 1 to 200 µm. These pores are often connected by irregularly curved fractures, 10–600 µm long and 0.5–10 µm wide. Mercury injection studies show that the volcanic rock matrix within the unproductive and/or low-productive sections contains up to 60– 75% of small pores with radii less than 0.1 µm, i.e., subcapillary pores which are not involved in fluid migration. Diameters of pore channels important for fluid movement are within the range of 0.25 to 6.3 µm. A power-law correlation between the pore channel diameter and matrix (intergranular) permeability is as follows: k = 0.0525dch2.85

where: k is permeability in mD, and dch is pore channel diameter in µm. The porosity of volcanic rocks studied in core samples by the saturation method varies within a wide range (0.6 to 28%) and the average value is 13%. The intergranular permeability is low; it varies from 0 to 10 mD, with an average value of 1 mD. The unusual combination of high porosity and very low permeability is due to the complex and non-uniform structure of the porous space. Finely porous rocks have complex pore structure and curved channels. The 0.1-µm subcapillary pores are not involved in fluid migration. The secondary matrix porosity includes pores (0.25 µm to 1 mm in size) and vugs (larger than 1 mm in size). Commonly, these pores and vugs are partly filled with kaolinite, illite, montmorillonite, ferro-oxides, and zeolites, some dispersed and highly swelling. Clay-mineral content (mainly authigenic clay minerals) in rocks is variable and can reach 40% or more. The petrophysical study shows that if the content of highly dispersed clay is more than 40%, then the water saturation of rocks is almost 70% and even higher. Under these conditions, rocks are not considered to be productive. Oil is present both in the rock matrix (pores and vugs) and in the micro- and macro-fractures. The intergranular matrix permeability is very low, and the oil saturation of reservoir rocks is distributed unevenly. Oil is mainly produced from zones which have hydrodynamic connections with the fracture systems. For quantitative evaluation of volcanic reservoirs, core samples from in-perimeter wells with oil production and out-perimeter wells without fluid flow were analyzed.

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The two statistical distributions of porosity were compared, and the average porosity values were determined. The secondary porosity (φ1) (vugs and fractures) can be determined using the following formula: φ1 = (φ2 – φ3) / (1 – φ3)

where φ2 is the porosity within the productive zones in the insideperimeter wells, and φ3 is the porosity within the unproductive (dry) zones in the outside-perimeter wells. The average secondary porosity is 1.8%. Depth intervals with high porosity (the secondary pores, vugs, and fractures) were determined using log data (electrical, radioactive, sonic, and caliper) and well test data. Thickness of these intervals can be considered as the effective (oil-bearing) reservoir thickness (net pay). These intervals have been identified using porosity determined from log data. Two porosity cutoffs were identified: (1) the lower limit: for impermeable, unproductive rocks, porosity is less than 7–8%; and (2) the upper limit: for rocks with content of highly-dispersed clay minerals higher than 40%. The upper limit identifies water-bearing intervals, with the total porosity exceeding 20%. Electrical logs were used to estimate the intergranular porosity and initial oil saturation. Based on the log analysis, the oil saturation in fractures is about 100%, whereas, the oil saturation in the matrix is about 50%. Weighted average oil saturation of the whole formation (including the secondary pores, vugs, and fractures) is about 90%. Gyandzha Area. Oil production in the Gyandzha area (including Kazanbulag, Adzhidere, Naftalan, and Mirbashir oil fields) is low and is confined to the Foraminiferal interval (Eocene) and Maikop Suite (Oligocene-Miocene).

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CHAPTER 6

Offshore Oil and Gas Fields CASPIAN SEA REGION The Caspian Sea is a highly promising oil- and gas-bearing region because oil and gas provinces situated on the territory of Russia, Azerbaijan, Turkmenistan, and Kazakhstan expand to the Caspian Sea area (Figure 6-1). The Caspian Sea is the world’s largest salt lake. Its length from north to south is 1,174 km, average width is 326 km, and total area is 375,000 km2. Water depth in the middle of the Caspian Sea ranges up to 788 m and in the southern part, up to 1,025 m. It has no outlet, and although the surface level of water fluctuates, it averages about 25 m below sea level according to recent measurements. Total area of the FSU portion of the Caspian Sea is 322,000 km2, including the shelf zone. To a depth of 200 m, the area is 240,000 km2. The general overview of hydrocarbon potential of the Caspian Sea area shows that in such a vast area almost no portion is without prospects for discovering oil and gas. About 150 prospective structures have been discovered; however, some 350 structures may be present. More than 45% of the total offshore area has water depth less than 50 m, and about 10% has water depth ranging from 50 to 100 m. About two-thirds of the Caspian Sea has water depth less than 200 m. The basin is a part of the eastern portion of the Pre-Tethys Sea which began to develop during the Early Paleogene time with AlpineHimalayan orogenic movements. The area of Caspian Sea includes three major geotectonic elements: Pre-Caspian region of the Russian Platform to the north; Scythian-Turanian Epi-Hercynian Platform in the middle portion of the sea; and Alpine geosynclinal zone to the south. Three distinct sub-basins (Northern, Middle and Southern) are related to these major structural elements.

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53

Figure 6-1. Caspian Sea area.

The South Caspian Basin, with its high number of confirmed structures, is the most studied. The middle and northern basins have not been studied as well (Figure 6-2). Hydrocarbon accumulations have been discovered, explored and produced in areas with water depth up to 60 m, and five oil and gas fields have been discovered in water depth up to 200 m. Hydrocarbon potential from 33 oil and gas fields is estimated at 10 Bt. Thirty-one of the fields are in the South Caspian Basin: 23 in Azerbaijan and eight in Turkmenistan. Two are in Kazakhstan in the north.

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Figure 6-2. Oil and gas possibilities of the Caspian Sea area. 1—Highly favorable areas, 2—areas favorable for oil and gas discovery, 3—discovered local structures, 4—oil and gas fields, 5—southern limit of areal extent of salt domes, 6—boundary between Pre-Paleozoic Russian Platform and Epihercynian Scynthian-Turanian Platform, 7—southern limit of Epihercynian Scynthian-Turanian Platform, 8—Alpine mountain system.

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At present, Caspian Sea exploration is carried out in offshore areas of Azerbaijan, Turkmenistan, Kazakhstan, and Russia. The main goal of deep exploration drilling in Azerbaijan and Turkmenistan portions of the Caspian Sea (Apsheron and Baku archipelagoes, western portion of Apsheron–Pre-Balkhan anticlinal trend, and eastern portion of Apsheron–Pre-Balkhan anticlinal trend) is to discover new oil and gas fields, and to deliniate those already discovered in the Middle Pliocene deposits (Productive Series in Azerbaijan and Red-Bed Series in Turkmenistan). In Kazakhstan and Russian parts of the Caspian Sea, it is advisable to study the oil and gas potential in Mesozoic deposits. At present, geological and geophysical investigation revealed more than forty anticlinal structures within the western part of South Caspian Basin. Most are prospects for oil and gas. Darvin Bank, Pirallaghi Adasi, Gyurgyan Deniz, Chalov Adasi, Dzhanub Bank, Palchygh Pilpilasi, Neft Dashlary, Gyuneshli, Azeri, Gum Deniz, Bakhar, Sangachal–Duvanny Deniz–Khara Zyrya, Bulla Deniz, and other oil and gas fields are on production. Among them, Neft Dashlary, Bakhar, Sangachal–Duvanny Deniz–Khara Zyrya, and Bulla Deniz are the largest fields. Exploration continues on more than 10 structures. Intensive offshore development in Azerbaijan began in 1949. Since then, 23 fields have produced 12 MMt of oil and condensate, and 11 Bm3 of gas, about half of their recoverable reserves. All fields are multi-bedded with 3 to 30 producing zones in the Middle Pliocene sandstones and siltstones. More than 3,000 wells have been drilled from over 1,000 platforms. In the Caspian Sea, exploratory drilling is carried out from individual platforms. Until recently, platforms were built for 40 m water depths; at present, platforms can be installed in water depth of 110 m and more. Floating rigs are used for exploration. At present, 8 such rigs are in operation. Five of them are self-lifting and can operate in 70-m water depth and drill to a depth of 6,500 m. Also, three semisubmersible drilling rigs are operating on the Gyuneshli and Chyragh structures in 165 m of water. At present, exploration drilling in the Caspian Sea is in water depth of 200 m, with the deepest well drilled to a depth of 6,500 m. The South Caspian Basin is characterized by deep water on the west and shallow water on the east. It is separated from the Middle Caspian Basin by the Caucasus-Kopet-Dagh fault. The Apsheron–Pre-Balkhan anticlinal trend extends NW-SE between Apsheron and Cheleken

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peninsulas and forms a narrow topographic high on the seafloor. All major fields in the area are located on this regional anticlinal trend (Figure 6-3). There are three offshore oil- and gas-bearing zones in the Azerbaijan portion of the South Caspian Basin: I. Western portion of Apsheron–Pre-Balkhan Anticlinal Trend II. South Apsheron Offshore Zone III. Baku Archipelago

Figure 6-3. Location of structures on the Apsheron Threshold (Modified after Bagir-zadeh et al., 1974). A—Oil and gas fields; B—prospects: 1—Goshadash, 2—Apsheron Bank, 3—Agburun Deniz, 4—Gilavar, 5—East Gilavar, 6—Danulduzu, 7—Ashrafi, 8—Karabakh, 9—Mardakyan Deniz, 10—Darvin Bank, 11—Pirallaghi Adasi (Northern Fold), 12—Pirallaghi Adasi (Southern Fold), 13— Gyurgyan Deniz, 14—Dzhanub, 15—Khali, 16—Chalov Adasi, 17—Azi Aslanov, 18—Palchygh Pilpilasi, 19—Neft Dashlary, 20—Gyuneshli, 21—Chyragh, 22— Ushakov, 23—Azeri, 24—Kyapaz, 25—Shakh Deniz, 26—Gum Deniz, 27–Bakhar, 28–Livanov-West, 29–Livanov-Center, 30–Livanov-East, 31—Barinov, 32—Gubkin (Western, Central, Eastern), 33—Zhdanov (Western, Eastern, Pre-Cheleken Dome), 34—LAM, 35–Cheleken.

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Two more zones are in the Turkmenistan portion of the South Caspian Basin: IV. Eastern portion of Apsheron–Pre-Balkhan Anticlinal Trend V. Chikishlyar-Okarem Zone The Deep Water Zone is located between these two portions of the South Caspian Basin.

ZONE I: WESTERN PORTION OF APSHERON– PRE-BALKHAN ANTICLINAL TREND (APSHERON ARCHIPELAGO AND THRESHOLD) The main oil- and gas-bearing rocks of the Apsheron–Pre-Balkhan anticlinal trend (the Apsheron Threshold) are of Middle Pliocene age (Productive Series). About 90% of all the identified hydrocarbon reserves of the South Caspian Sea are located here. According to folding intensity and the occurrence of oil and gas fields, the Apsheron Threshold is subdivided into two areas: western, i.e., Apsheron Archipelago, and eastern, i.e., Turkmenian Shelf (Figures 6-2 and 6-3). A conventional line between them can be drawn along the far eastern pericline of deeply buried Kyapaz structure. The region of the Apsheron Archipelago deserves special attention as the location of large oil and gas fields: Darvin Bank, Pirallaghi Adasi, Gyurgyan Deniz, Dzhanub Bank, Chalov Adasi, Palchygh Pilpilasi, Neft Dashlary, Gyuneshli, Chyragh, Azeri and a number of prospects. The Pirallaghi Adasi Field has been producing for about a century, whereas the Gyuneshli, Chyragh, and Azeri fields were discovered only recently. Within the Apsheron Archipelago, three anticlinal trends have been recognized (system of the East Apsheron anticlinorium), including the following structures (from northwest to southeast) (Figure 6-3): 1. Goshadash, Agburun Deniz, Apsheron Bank, Gilavar, Danulduzu, and Ashrafi. 2. Darvin Bank, Pirallaghi Adasi, Gyurgyan Deniz and Dzhanub. 3. Khali, Chalov Adasi, Azi Aslanov, Palchygh Pilpilasi, Neft Dashlary, Oguz, Gyuneshli, Chyragh, and Azeri. All these anticlinal structures have been considerably eroded, and the deposits of the Upper Productive Series have been subjected to

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erosion. The larger longitudinal thrust faults, both in amount of displacement and in extent, are located along the axis of the structures. Transverse faults, although of small amplitude, played an important role in the distribution of oil accumulations. Quaternary and Neogene (Pliocene and Miocene) deposits constitute the stratigraphic column of the Apsheron Archipelago. The Productive Series of the Middle Pliocene consists of interbedded sandstones, siltstones and shales up to 3,000 m in thickness. It is subdivided on the basis of the predominance of sandy or shaly sediments into the Kala (KaS), Podkirmaku (PK), Kirmaku (KS), Nadkirmaku Sandy (NKP), and Nadkirmaku Shaly (NKG) suites in the Lower Productive Series; “Pereryv”, Balakhany, Sabunchi, and Surakhany suites in the Upper Productive Series. Table 6-1 shows a comparison of the thicknesses of individual suites at some offshore areas. The oil potential of the Apsheron Archipelago structures is associated mainly with the Lower Productive Series, where the Podkirmaku and Kirmaku suites are the most productive in the area. The thickness of Podkirmaku Suite decreases in the northern fields (Darvin Bank and Pirallaghi Adasi) as a result of wedging-out of the basal strata, whereas for the Kirmaku Suite there is a decrease in oil-saturated thickness (net pay) toward the southeast as the clay content increases. The Kala Suite is oil-saturated everywhere throughout its area of distribution; its absence in the Darvin Bank and Pirallaghi Adasi areas is explained by the fact that during the time of deposition of the Kala Suite sediments, there were areas of erosion and removal of terrigenous material. To the south, the thickness and oil saturation of the Kala Suite significantly increase. The Nadkirmaku Sandy Suite and also the basal parts of the Nadkirmaku Shaly Suite are oil-bearing mainly in the structures of the southeastern part of archipelago. The Upper Productive Series deposits are present only at the Neft Dashlary, Gyuneshli, Chyragh and Azeri oil fields, and at the Dzhanub gas and gas-condensate field, where the conditions were favorable for their preservation. In the remaining structures of archipelago, the rocks of Upper Productive Series have been significantly eroded and do not contain commercial accumulations of hydrocarbons. Among the enumerated fields, Neft Dashlary is a pioneer in the development of offshore oil and gas fields. Exploration for the Neft Dashlary area and subsequent development marked the beginning of exploration and development on other structures situated farther

Surakhany Sabunchi Balakhany “Pereryv” NKG NKP KS PK KaS

Suite

— — 400 100 175 140 255 180 —

Pirallaghi Adasi

600 391 605 175 125 148 269 148 260

Gurgyany Deniz

1,090 1,390 1,655 1,159 1,112 1,155 1,222 1,110 1,355

Dzhanub

400 355 400 110 130 136 276 108 270

Chalov Adasi

260 350 370 100 110 130 250 100 320

Neft Dashlary

Average Thickness in Meters

1,350 1,423 1,702 1,105 1,135 1,146 1,250 1,148 1,250

Zyrya

1,200 1,440 1,806 1,120 1,120 11,64 1,262 1,120 1,228

Gum Deniz

Table 6-1 Comparison of Thicknesses of Different Suites in the Offshore Areas of Apsheron Archipelago

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Petroleum Geology of the South Caspian Basin

offshore. Consequently, a special attention is devoted to the history of exploration and development of this oil field.

Neft Dashlary Oil Field Location and History Neft Dashlary Oil Field is situated in the western part of the Apsheron Threshold (see Figure 6-3), which is a connecting link between the southeastern end of the Greater Caucasus and the PreBalkhan zone of Western Turkmenistan uplifts. The Apsheron Threshold is the northern bounding tectonic element of the South Caspian Basin, one of the most explored and promising zones of the Caspian Sea. Neft Dashlary Oil Field is the easternmost structure exposed above the water surface along the submerged ridge of the Apsheron Threshold, and is situated 55 km southeast of Pirallaghy Adasi and 110 km east of Baku (Figure 6-4). Communication with the shore is accomplished using helicopters and boats. The field is produced from the piers and individual platforms. The piers extend in rows of parallel lines/ branches to the individual platforms. Total length of the piers is more than 200 km. Neft Dashlary Field is situated in open water with depths of 15–25 m. The seafloor is composed of sandy-shaly rocks, with some dense sandstones. Detrital deposits consist of sand and shells. Bottom relief

Figure 6-4. Location of the offshore Neft Dashlary Oil Field.

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reflects bedrock structure and lithology. Boulders of well-cemented sandstones of the Productive Series are exposed above the water surface. They are spread over an area of more than 12 km2; the length of the boulder exposure is about 6–7 km, whereas its width is 2–3 km. Some boulders emerge 2–3 m above water level, whereas others are seen only in rough waters. These exposures extend from northwest to southeast, flanking the crest of a big anticlinal structure. Sandstone boulders continuously bleed oil and gas to the sea surface. This manifestation is so intense that in calm weather an oil film covers the water surface, and the escaping gas creates a “boiling” appearance. Wind and waves carry oil to sandstone outcrops, the surfaces of which are covered by an oil film. Because of the oil coating on these exposed rocks, this area is called Neft Dashlary or Oil Stones. The main climatic features of the region is the prevailing strong wind from the north with an intensity of 5 to 9 points by Beaufort wind scale (Sheriff, 1984). Calm weather is not prevalent more than 30–35 days per year. Maximum wave height is 11–16 m, whereas the wave intensity during 75–80 days per year exceeds 5 points by the Douglas sea-state scale (Sheriff, 1984). The earliest published geological report on Neft Dashlary Oil Field was written by the noted academician G. V. Abikh (1863), who described the area as “a small archipelago of underwater stones and boulders.” He also discussed hydrocarbon gases and oil seeps. G. Sögren (1892) and N. A. Lebedev (1902) also provided descriptions of tectonics and stratigraphy of the Neft Dashlary area. Later, the geological structure of the area was considered by S. A. Kovalevskiy (1926), S. M. Apresov (1933) and M. F. Mirchink (1939). In 1945– 1949, the Azerbaijan Oil Survey of the Academy of Sciences of the USSR under the leadership of A. K. Aliyev investigated the Neft Dashlary area. A preliminary geological map of the area was compiled along with a plan for exploration of the region. In August 1949, exploration began in the Neft Dashlary area. The first well, which was drilled in November 1949, flowed oil at 100 tpd (7,300 bpd) from the Productive Series through a 5 mm choke at a wellhead pressure of 7 MPa. The rate of exploration drilling increased; it was ascertained that the whole sequence of the Productive Series contained commercial oil and gas accumulations. The first well was rigged up in a short period of time on the largest outcrop projecting above sea level. A small house with a radio station,

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providing contact with the shore, was built for the drilling crew on piles sunk into the seafloor. The crew was led by toolpusher M. P. Kaverochkin. Drilling was carried out under very difficult conditions, with severe storms and strong winds. The second well in the Neft Dashlary area was constructed on a platform of “MOS” type designed by A. A. Mezhlumov, S. A. Orudzhev and Yu. A. Safarov in 1949. A young toolpusher, K. A. Abasov, was charged with drilling this well. To allow access to greater water depths, seven old ships were moved onto the inhospitable and dangerous “Black Rocks,” placed in a semicircle, and sunk in shallow water. They formed an artificial island which was called “The Island of Seven Ships.” Mechanical workshops, storehouse and an office were built on the ships’ decks, whereas cabins were used for crew housing and canteen. It was decided to connect the rock outcrops with each other to form an artificial island in the open sea. For the first time in the USSR, tens of meters of piers spread from this island far into the open sea. They were constructed by B. A. Roginskiy, A. Asan-Nuri, N. S. Timofeyev and other specialists. The subsequent long-term offshore field development (pier method) under extreme hydrometeorological conditions proved to be successful in water depths of 10-40 m. On February 18, 1951, the first oil tanker left the open-water moorage of a new town built in the open sea (Samedov, 1959). Today, this first attempt at Caspian offshore oilfield production has developed into a complex of hydrotechnical installations spreading over 200 km. All necessary conditions for work and recreation have been provided for offshore oilmen. There, one can see a residential development, Palace of Culture, shops, hospital, cinema, etc. An autonomous power station, also erected offshore, provides the power supply for field facilities and the town. At present, “The Island of Seven Ships” has been transformed into a five-story apartment hotel with swimming pool, compressor station, etc. (Yusufzadeh, 1979). Geology Since the beginning of exploration, more than 1,000 exploratory, producing and injection wells have been drilled in the Neft Dashlary oilfield area. The oil production was first obtained from the southwestern flank and then from the southeastern flank of anticline. Geology of the field is now known in detail.

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The stratigraphic sequence in the anticlinal structure of Neft Dashlary Field was studied from Koun (Eocene) to Apsheronian (Upper Pliocene) deposits. Outcrops of the Productive Series rocks, bordering a narrow band of Akchagylian and Apsheronian stages (Upper Pliocene), were present at the core of the structure. Tectonically, the field is a large brachyanticline, trending northwest to southeast (Figure 6-5a). The structure extends northwest-ward to a saddle separating this structure from Palchygh Pilpilasi Oil Field. The Neft Dashlary structure is asymmetrical: the southwestern flank dips 35–40°, whereas the northeastern flank dips 45–50° (Figure 6-5b). The structure is cut by transverse and longitudinal faults which cross the entire Productive Series. A large longitudinal fault extends along the northeastern flank of the structure; the southwestern flank thrusts over the northeastern one. Mud volcanism occurs along this fault. The structure is cut by a series of transverse faults. Most of these faults offset the main longitudinal fault and cut the entire Productive Series. Fault planes, with dips ranging from 60 to 90°, trend mainly in southeastern direction. Bed displacement is maximum over the crest and dies out toward the flank of anticline. Neft Dashlary Field is divided into five fault blocks according to oil and gas saturation and trap conditions (Figure 6-5a): I. II. III. IV. V.

Northwestern part of the field Central part of southwestern flank Central part of northeastern flank Southeastern plunge of southwestern flank Southeastern plunge of northeastern flank

Oil- and gas-producing zones of Neft Dashlary Field include the Productive Series, which in turn is divided into the following suites and units (upwards): Kala Suite, which is subdivided into units KaS1, KaS2, KaS3, and KaS4; Podkirmaku Suite, which is subdivided into units PK 1, PK 2, and PK 3 ; Kirmaku Suite, which is subdivided into units KS1 and KS2; Nadkirmaku Peschanaya (Sandy) Suite— NKP; Nadkirmaku Glinistaya (Shaly) Suite—NKG; “Pereryv” Suite; Balakhany Suite, which is subdivided into units V, VI, VII, VIII, IX and X; Sabunchi Suite, which is subdivided into units II, III and IV; and Surakhany Suite (units I and I′) (Figure 6-6a and 6-6b). (text continued on page 67)

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Figure 6-5. Structural map and cross-section of Neft Dashlary Oil Field. (a) Structural map on the top of PK Suite: 1—Diatom and Maikop (OligoceneLower Miocene) crumpled rocks, 2—dislocation with a break in continuity, 3—oil accumulation, 4—well; (b) geologic cross-section: 1—oil, 2—gas, 3—dislocation with a break of continuity, 4—Diatom and Maikop (OligoceneLower Miocene) crumpled rocks, 5—Koun (Middle Eocene) crumpled rocks.

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Figure 6-6a. Typical logs (Resistivity and SP) of the Productive Series in Neft Dashlary Oil Field: NW portion of field, NE wing (block I) and SW wing (block Ia).

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Petroleum Geology of the South Caspian Basin

Figure 6-6b. Typical logs (Resistivity and SP) of the Productive Series in Neft Dashlary Oil Field: SE portion of field, SW wing (blocks II and IV) and NE wing (blocks III and V).

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(text continued from page 63)

Field Development From the very beginning of development of Neft Dashlary Field, different methods of waterflooding of productive intervals were used in order to maintain reservoir pressures. The main productive intervals in Neft Dashlary Field are the following: Kala, Podkirmaku, Kirmaku, Nadkirmaku Sandy, “Pereryv,” and Balakhany suites. About 30 oil- and gas-saturated intervals have been identified. In the second fault block (main block), according to log and the well-test data, three separate sandy-silty productive units, divided by thick shale interbeds, are identified in the Kala Suite. Among them units KaS1 and KaS2 are characterized by high oil saturation and oil output. Unit KaS2 has a large gas cap, and Unit KaS3 is gas bearing. The main productive interval of the field is the Podkirmaku Suite. The first wells which penetrated this oil-bearing sequence had high initial flow rates. The entire Podkirmaku Suite is saturated with oil. The suite is divided into two main productive formations, PK1 and PK2, which are separated by shale layer 2–5 m thick. Average thicknesses of PK1 and PK2 are 40 and 45 m, respectively. At the trap crest, thickness of the shale layer between PK1 and PK 2 decreases and sometimes shale disappears. Thickness of the shale layer increases away from the crest toward the flanks. Reservoirs of the Podkirmaku Suite are characterized by water drive; gas caps are lacking. Figure 6-7a shows the distribution of producing and injection wells, whereas Figure 6-7b shows the production history of Unit PK1 in the second fault block. Figure 6-8a is a map of OWC migration due to waterflood front advance during the Unit PK1 production, whereas Figure 6-8b is a map of water encroachment rate in the same unit expressed as water-cut (%). Only the Lower Kirmaku Suite is oil-saturated (79–80 m from the bottom). The oil-saturated section includes two separate productive units, KS1 and KS2; the upper KS1 is less productive. In the third, fourth, and fifth fault blocks, oil saturation is confined (besides the above described productive units) to the Nadkirmaku Sandy and “Pereryv” suites and to the Upper Productive Series. Nadkirmaku Sandy Suite is distinguished by the high oil content

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Petroleum Geology of the South Caspian Basin

Figure 6-7. Distribution of producing and injection wells in Neft Dashlary Oil Field (a) and production history of Unit PK1 (b). 1—Producing wells, 2— injection wells, 3—1961 OWC, 4—initial OWC; Pav-average reservoir pressure, atm; Qw-water-injection rate, m3/day; N-number of producing wells; Qo-oil production, t/day; Qo′-oil production under natural depletion drive, t/day.

throughout the entire thickness. The “Pereryv” Suite consists of four to five individual beds separated by thin shale interbeds. These beds are unevenly saturated. Units X, VI, V, IV, III, I and I’ are oil bearing within the same beds as the “Pereryv” Suite. Units IX, VIII and VII have the most widespread distribution of oil saturation. In spite of the shallow depth (100 to 500 m), these units are characterized by high oil output.

Offshore Oil and Gas Fields

69

Figure 6-8. Annual (1953–1961) migration of oil-water contact (a) and corresponding water-cut (b) at Neft Dashlary Oil Field (Modified after Samedov and Buryakovsky, 1966).

The oil in these productive intervals is saturated with hydrocarbon gases; in addition, free-gas accumulations also occur here. The hydrocarbon gas of Neft Dashlary Field is largely methane. Wellhead gas contains admixed CO2. The composition of gas (vol-%) is presented in Table 6-2. On an average, natural gas of Neft Dashlary Field contains 68.1 to 96.7% methane, 0.64 to 5.14% ethane, 0.13 to 1.58% propane, 0.06 to 1.58% butane, and 0.13 to 2.54% heavier hydrocarbons.

NKP KS PK1 PK2upper PK2lower KaS1 KaS2 KaS3 KaS4

Suite/Unit

89.7 81.8 81.3 82.4 88.0 91.3 94.3 87.4 92.9

Methane

3.24 1.25 2.20 2.50 2.80 2.18 1.16 2.76 2.14

Ethane

1.26 0.86 0.91 0.91 0.71 0.63 0.87 0.82 0.67

Propane

1.11 0.21 0.75 0.86 0.39 0.53 1.16 0.50 0.43

Butane

Gas Composition (vol %)

1.16 0.35 0.85 1.37 0.65 1.01 1.16 1.76 1.04

C5

+

6.4 16.0 14.0 12.0 7.6 4.3 1.4 6.6 2.8

CO2

Table 6-2 Composition of Gas from the Neft Dashlary Oil Field

0.6832 0.7283 0.7366 0.7217 0.6616 0.6424 0.6227 0.6884 0.6269

(to Air)

Gravity

Specific

47.4 12.6 30.3 53.3 25.3 39.4 46.4 70.4 40.0

Bulk Volume)

C5+ (g/m3 of

Content of

70

Petroleum Geology of the South Caspian Basin

Offshore Oil and Gas Fields

71

The CO2 content by volume is 1 to 23%. Specific gravity of gas with respect to air ranges from 0.5814 to 0.8846. The gas is dry, although several analyses show a content of heavy hydrocarbons up to 100 g/m3. Gas saturation increases with an increase in clay content and with a decrease in sand content of reservoir rocks. A decrease in thickness of sand beds is accompanied by a change in grain size: the content of grain fraction less than 0.01 mm in size increases. For example, the Podkirmaku Suite contains an average of 65–70% sands, with about 20% content of fractions less than 0.01 mm in size. The initial gas/oil ratio (GOR) was 35–40 m3/m3. The Kirmaku Suite is characterized by a high content of shale beds and very thin sandyshaly interbeds. Individual beds may be as thin as 1 cm. Sand layers constitute no more than 45–50% of the entire suite; moreover, fractions less than 0.01 mm in size constitute 25% of sands. The initial GOR of the Kirmaku Suite was almost twice that of the Podkirmaku Suite, reaching 70–75 m3/m3. At the beginning of production, accumulations in both formations had the same reservoir pressure. Lithologic features of the Podkirmaku Suite (predominance of sandstones in the section, excellent sorting, coarser grain size, and high permeability) were not conducive to the accumulation of free gas; the latter is due to the great mobility of gas moving into the Kirmaku Suite above, which consists of thin sandy-shaly interbeds with a high specific surface area. A characteristic feature of the Kala Suite is the change of oil in KaS2 to gas on the far southeastern, down-dip part of the anticline (the fourth fault block). From the crest to the southeastern plunge, grain size decreases and the shale content of the reservoir increases. This is shown clearly in the KaS2 interval where, as a result, gas has accumulated with only a small oil fringe extending along the southeastern plunge of structure. The boundary of gas-saturated reservoir intersects the structural contour lines of the stratum from higher levels to lower. A similar change from oil to gas is observed in the other units of the southeastern plunge area; however, in these cases the gas is concentrated close to the crest of structure and forms a gas cap. The relationship between the oil and gas variations during field production depends on differing physical and geological conditions (energy state, drainage mechanism, etc.). In a single-phase reservoir, oil is either completely saturated by gas or it is undersaturated. The degree of undersaturation is determined by the ratio of gas to liquid hydrocarbons at a pressure below reservoir pressure. The degree of

72

Petroleum Geology of the South Caspian Basin

undersaturation of reservoir oil is the difference between the reservoir pressure and bubble-point pressure. At the beginning of production of Neft Dashlary Field, the degree of undersaturation of oil ranged from 0.6 to 3.0 MPa; gas was dissolved in oil and separated from it only in the borehole above the perforated interval. High pressure, existing when gas-saturated oil reservoirs were penetrated, permitted all the gas except methane, CO2, and a portion of ethane to be retained in solution in the oil. With a drop in pressure as a result of production, other hydrocarbons begin to appear in the gas phase. Gas is enriched in ethane, propane, butane, and heavier hydrocarbons. As a consequence, the specific gravity of the gas increases, depending on the duration of production and the rate of reservoir pressure drop. In the crestal area, pressure drops faster and the oil here is less compressed; therefore, the methane content increases from the crestal area towards the flanks of the structure, in the same direction of decrease in specific gravity of the gas. The Podkirmaku reservoir is a good example of this behavior (Table 6-3). Long before the beginning of production, the oil in crestal portions of the structure lost gas, mostly methane, in larger quantities than did the oil present on the flanks. As a result of redistribution of oil and gas within the reservoir, the difference between the gas/oil ratio in various parts of the accumulation should disappear with time. Losses

Table 6-3 Methane Content in Gas and Specific Gravity of Gas with Respect to Air vs. Depth in Neft Dashlary Oil Field Well No.

Perforated Interval, m

Methane Content, %

Specific Gravity of Gas

34 62 77 18 73 59 17 55

1,536–5421, 1,690–6951, 1,845–8511, 1,918–9211, 1,909–9131, 1,965–9671, 1,960–9681, 1,244–1,276

68.1 68.7 77.7 77.4 85.8 80.7 88.8 94.3

0.8838 0.8763 0.7781 0.7742 0.6425 0.7573 0.6678 0.5972

Offshore Oil and Gas Fields

73

of methane at the crestal area and its transfer along the bedding from the margin to the crest take place simultaneously. Ultimately, this leads to some decrease in the methane content and to an increase in the specific gravity of the gas in crestal portions of the accumulation. Upon the successful development of Neft Dashlary Field, drilling of exploratory wells was carried out in areas adjacent to the field.

Palchygh Pilpilasi Oil Field Location and History Palchygh Pilpilasi (meaning “Mud Volcano” in Azery language) Oil Field is located in the Caspian Sea east of Baku and southeast of Pirallaghi Adasi (see Figure 6-3). The main base for exploration and development is at Neft Dashlary Field, 4 km southeast. Seismic surveys conducted during 1953–1957 outlined the structure between Chalov Adasi and Neft Dashlary and discovered another anticline Palchygh Pilpilasi (Samedov et al., 1960). Later, in 1963– 1965, one more uplift, named Azi Aslanov, was discovered between Chalov Adasi and Palchygh Pilpilasi structures. By 1953, commercial oil saturation was established in nine units on both flanks of the Neft Dashlary anticline. The initial flow rates were high, over 50 tpd (365 bpd). Because Palchygh Pilpilasi area lies on the northwestern extension of the Neft Dashlary Oil Field and includes the same Middle Pliocene formations, it was suggested that the same units may be productive there. During the first few years of exploration (1952–1955), the objective was to penetrate the entire Productive Series and to study its lithology, stratigraphy, structure and petroleum potential. The first well (22) was spudded on August 10, 1952, over the most elevated area of the southwestern flank. This well (TD = 1,003 m), along with platform, was destroyed by a severe storm on December 11, 1952. By 1956, eight wells were completed. The crestal Well 20 tested oil with gas from Kala Suite and 0.5 to 1 tpd (3.6 to 7.3 bpd) of heavy oil (density = 0.945 g/cm3) from Podkirmaku Suite. Commercial flows from the exploratory wells spaced over 4 km were considered as indications of the high potential of the structure. An appraisal drilling program for the Palchygh Pilpilasi area was prepared by F. I. Samedov and A. M. Polaudin and approved on June 30, 1956. The program envisioned the drilling of 20 wells with

74

Petroleum Geology of the South Caspian Basin

proposed depth ranging from 1,000 to 1,900 m along seven profiles extended across the strike of the structure and encompassing both of its flanks. The spacing of profiles was 800 to 1,000 m. The appraisal drilling program was supposed to take two years (including the construction of offshore platforms). Some wells were proposed to be deviated and drilled from the existing platforms or platforms under construction at that time. The drilling program for 1956 included 12,000 meters with the remainder to be drilled in 1957. To study the KaS accumulation discovered in the northwestern area of the Neft Dashlary Oil Field, the drilling of four wells was proposed. Actually, five wells were drilled in 1956, with two wells yielding commercial oil production (18 and 45 tpd or 131 and 328 bpd). Four wells out of those drilled in 1957 flowed oil (15 to 22 tpd or 109 to 160 bpd), whereas one well flowed gas from Unit KaS4. Four of these wells, along with the other two which were not completed, have been destroyed by the hurricane on November 21, 1957. The hurricane severely affected the exploration and development program: no wells were drilled in 1958, and only one, in 1959. Nevertheless, the initial drilling program with some adjustments, was completed by 1958. As a result, oil accumulations have been discovered in KaS and PK suites and substantial amount of knowledge was gained about the geology and petroleum potential of the region. The most intensive drilling was conducted in 1960-1961. During that period, 12 wells were drilled that delineated discovered oil accumulations. Five of the wells tested oil (10 to 50 tpd or 73 to 365 bpd), four were water wet, one was plugged and abandoned, and two wells remained uncompleted. No wells were drilled in 1963. One well was drilled each year in 1964 and 1965, three in 1966, two in 1967 and five in 1968. A total of 46 exploratory and appraisal wells were drilled by 1969. Thirty-five of these wells were cored. The average profile spacing was 1,000 m, whereas the well spacing was 300 m. The profile spacing corresponded to the drilling program, whereas the well spacing was smaller due to drilling of some infill wells required by the complexity of the structure and lithology. Geology During the initial exploration period, it was believed that Palchygh Pilpilasi Oil Field was a northwestern plunge of the large Neft Dashlary

Offshore Oil and Gas Fields

75

structure. Exploration from 1952 to 1955 allowed structural maps to be revised, showing an independent brachianticlinal uplift of Palchygh Pilpilasi. It is separated from the Neft Dashlary structure by a small saddle (Figure 6-9). The stratigraphic section of the Palchygh Pilpilasi has been studied exclusively by deep drilling. Sediments of Pliocene age (Productive

Figure 6-9. Structural map on top of the Kala Suite of Palchygh Pilpilasi Oil Field (a) and geologic cross-section (b). 1—OWC, 2—contour lines on top of the Kala Suite, 3—fault.

76

Petroleum Geology of the South Caspian Basin

Series and Pontian Stage) have been encountered and studied. Pontian sediments are represented by deep-water facies, which are gray to dark gray in color, unconsolidated, and contain thin limey shale beds. Sandy varieties are rare. Characteristic fossils include Paracypria loezyi Lal., Leptocythere praebacuana Liv., Loxoconcha alata Schn., Loxoconcha eichwaldi Liv., and other ostracods, pelecypod embryos, and others. The Productive Series deposits, where the oil accumulations occur, have been thoroughly studied. Largely, deposits of the upper and lower divisions of the Productive Series have been encountered. The base of the upper division occurs as deep as 260 m rising from zero, where rocks of the lower division crop out on the seafloor, to 500 m on the plunge of the structure. Rocks of the Kirmaku and Nadkirmaku Sandy (NKP) and Nadkirmaku Shaly (NKG) suites occur along the crest of the structure. Total thickness of the Lower Productive Series is 900 m on the average and ranges from 700 to 1,200 m. The section is represented by the following formations, from the bottom up: The Kala Suite rests directly on Pontian sediments and is composed largely of interbedded sands, sandstones, shales, and siltstones, with rare admixtures of gravel. The total thickness of the sand-shale members of the Kala Suite is about 300 m. Shale predominates over sand and constitutes 60% of the total thickness. In the area of Palchygh Pilpilasi Field, the Kala Suite is subdivided into four sandy units, with thickness ranging from 20 to 30 m, separated by thick shale partings (Figure 6-10). The sandy unit is represented by gray to light-gray medium-grained quartz sand and sandstone with some fine-grained clayey varieties. Impermeable partings are gray to light-gray sandy shales. Sands of the Kala Suite are characterized by variation in grain size. The average grain-size distribution is as follows: >0.25 mm—6.9%; 0.25 to 0.1 mm—27.5%; 0.1 to 0.01 mm—37.2%; 0.25 mm—1%; 0.25 to 0.1 mm—24.8%; 0.1 to 0.01 mm—45.7%; and 0.25 mm

12.7 13.7 11.5 19.4 10.9 11.5

Suite/Unit

KS PK KaS1 KaS2 KaS3 KaS4 13.8 24.7 13.5 28.3 22.2 26.6

0.25–0.1 mm

53.5 47.3 55.7 36.6 40.5 36.4

0.1–0.01 mm

Grain-size Distribution, %

30.0 24.3 29.3 25.7 26.4 25.5

0.25 mm

10.1 10.4 13.5 12.8 14.7 13.5 11.0 18.7 12.4 12.1

Unit or Suite

V VI VII VIII IX X “Pereryv” NKP KS PK 21.0 10.3 46.3 38.5 54.8 39.6 38.5 22.1 19.7 40.0

0.25–0.1 mm

53.6 59.6 16.3 42.6 26.9 42.6 32.5 46.0 57.5 45.8

0.1–0.01 mm

Grain-size Distribution, %

24.4 21.7 33.9 16.1 13.6 14.3 18.0 23.2 20.4 12.1

0.25 mm

10.0 10.5 10.7 14.8 13.0 10.6 12.3 13.7 19.8 15.4 17.9

Unit or Suite

V VIupper VImiddle VII VIII IX Xupper Xlower “Pereryv” NKP PK 12.0 17.4 28.4 28.4 30.0 19.9 35.5 35.2 45.1 22.3 32.3

0.25–0.1 mm

68.1 59.7 51.8 49.8 49.2 59.8 45.8 47.0 32.3 52.8 36.8

0.1–0.01 mm

Grain-size Distribution, %

29.9 22.4 19.1 17.0 17.8 19.7 16.4 14.1 12.8 19.5 13.0

0.25 mm—6.9%; fraction 0.25 to 0.1 (text continued on page 138)

General Regularities in Oil and Gas Distribution

135

Figure 7-11. Variation of porosity (a, b) and permeability (c, d) with depth for the northwestern slope of the South Caspian Basin. (Modified after Buryakovsky et al., 1991b.) a, c—Sandstones; b, d—siltstones. Oil and gas fields and prospects: 1—Dzhanub, 2—Zyrya, 3—Surakhany, 4—Karachukhur, 5—Zykh, 6—Gum Deniz, 7—Gousany, 8—Bibieibat, 9—Patamdar, 10— Karadag, 11—Padar, 12—Kyurovdag, 13—Karabagly, 14—Kalmas.

IVb V

IVa

I II III

Class

Uncompacted sorted sand Shaly-silty sand Sandy loam, Siltstone Chlidolite, Loam Sandy-silty shale Dense sandstone and siltstone

Type

15–23

Medium 23–32 32–40 —

20

5–10

0.25 mm

0.3 0.4 0.3 2.2 1.3 1.8 0.4 0.7 0.6 0.7 1.5 0.7 2.1

Unit or Suite

II III III–IV IV IVa IVb IVc IVd IVe Average Sabunchi V V–VI VI 4.3 9.6 5.4 21.5 23.1 22.2 5.1 4.7 6.8 9.5 21.9 13.0 29.4 53.7 53.8 64.8 52.2 50.9 55.2 53.8 61.5 57.9 55.7 50.4 60.6 51.3

0.25–0.1 0.1–0.01 mm mm

41.7 36.2 29.5 24.1 24.7 20.8 40.8 33.1 34.7 34.1 26.2 25.7 17.2

0.25 mm—7.0%; fraction 0.25 to 0.1 mm—34.8%; fraction 0.1 to 0.01 mm—35.7%; and fraction 6,000 20–60 37.5

20–65 39.0

10–60 38.0

30–60 42.0

20–40 35.0

35–65 43.5

Illite

10–25 15.5

0–30 15.5

0–20 12.5

5–20 14.0

0–15 13.0

15–20 17.5

Kaolinite

0–10 4.0

0–15 5.0

0–10 5.5

5–15 7.0

0–10 7.0

5–10 6.5

Chlorite

Clay-Mineral Composition, %

0–25 7.0

0–15 1.5

0–30 4.0

0–5 1.0

Traces

Traces

MixedLayered

0–16 10

0–18 12

2–21 14

8–24 17

15–28 20

22–33 28

Porosity, %

0.6–0.8 0.7

0.8–1.5 1

1.5–3 2

3–8 6

8–35 22

35–250 142

Permeability, 10–7 mD

Table 7-10 Clay-Mineral Composition and Variation with Depth of Porosity, Permeability, and Pore Size in the Apsheron Archipelago Fields (average values are shown in the denominator)

—

0.5–1.5 0.8

0.7–2.0 1.3

1.0–2.5 1.6

1.3–3.1 2.1

1.7–3.9 2.7

Pore Size, µm

General Regularities in Oil and Gas Distribution 143

Figure 7-13. Contents of clay minerals in the Productive Series of Baku Archipelago. a—Montmorillonite, 2—illite, c— kaolinite, d—chlorite, and e—mixed-layer minerals.

144

Petroleum Geology of the South Caspian Basin

General Regularities in Oil and Gas Distribution

145

Table 7-11 Clay-Mineral Composition of Argillaceous Rocks in the Azerbaijan and the South Caspian Fields (Average Values are Shown in the Denominator) Clay-Mineral Composition, %

Field

MixedKaolinite Chlorite layered

Montmorillonite

Illite

Bibieibat

tr.–30 17

40–65 53

10–30 26

tr.–5 3

tr.–5 1

Palchygh Pilpilasi

10–35 24

45–60 51

20

tr.–5 3.8

tr.

40

40

15–20 17.5

tr.

tr.–5 2.5

Bakhar

10–55 27.7

30–55 46.1

15–25 20.4

tr.–10 4.2

tr.–5 0.8

Duvanny-Khara Zyrya

5–60 41

5–60 39

tr.–20 13

tr.–15 6

tr.–5 1

Bulla Deniz

5–70 39

5–70 37

tr.–35 16

tr.–10 4

tr.–10 4

Alyat Deniz

45–50 47

25

15

5

5–10 8

Khamamdag Deniz

30–75 49

10–45 28

10–15 12.5

tr.–10 5

tr.

Kyurovdag & Karabagly

40–75 53

10–35 23

tr.–20 12

tr.–15 10

—

Gyuneshli

Series are characterized by the highest content of smectite (31 and 35%, respectively), whereas in the Balakhany Suite, smectite content decreases to 21.1%. The NKG and KaS suites of the Lower Productive Series have the highest smectite content (30%). Figure 7-14 shows the smectite and illite contents in rocks of the (1) Apsheron Archipelago (Oguz, Palchygh Pilpilasi, Dzhanub-2, and Gyuneshli offshore areas), (2) South Apsheron Offshore Zone (Bakhar Field), (3) Baku Archipelago (Sangachal—Duvanny Deniz—Khara

146

Petroleum Geology of the South Caspian Basin

Figure 7-14. Montmorillonite (1) and illite (2) contents in argillaceous fraction (6,000

15–19 17 21–23 22 15–25 20

sequences from shallow to great depths, in formations as old as Cambrian (Dickinson, 1953; Foster and Whalen, 1966; Fertl, 1976; Fertl and Chilingarian, 1977; Dobrynin and Serebryakov, 1978; Magara, 1982; Buryakovsky et al., 1986; Aleksandrov, 1987; Dobrynin and Serebryakov, 1989). The ability to locate and evaluate overpressured formations is critical in drilling and completion operations, and in developing exploratory and reservoir engineering concepts. Although improved during the last decade, the overpressure prediction methods are still far from being perfect. This has been identified as one of the challenges of geoscience technologies. For predicting formation pressure, the paragraphs below describe the geophysical and drilling data-processing procedures used. Overpressure can be calculated from resistivity logs. This method involves first separating the shales from the sands, and then correcting the shale resistivity for formation temperature. The temperature correction is based on an empirical relationship derived for the region or area under study. Once the temperature correction is applied, a normal

153

General Regularities in Oil and Gas Distribution

Table 7-15 Pore-pressure Gradient in Shales, and Geothermal Gradient in the Fields of Azerbaijan and the South Caspian Basin

Field

Bibieibat Palchygh Pilpilasi Gyuneshli Bakhar Duvanny-Khara Zyrya Bulla Deniz Alyat Deniz Khamamdag Deniz Kyurovdag and Karabagly

Pore-pressure Gradient, MPa/m

Geothermal Gradient, °C/km

0.0125 0.0135 0.0146 0.0166 0.0171 0.0182 0.0178 0.0176 0.0176

28.5 26.0 24.0 28.0 16.0 16.0 16.0 16.0 16.0

compaction trend is established for the well. The overpressured zones are delineated by the deviation from the normal trend of pore pressure gradient. The same method can be applied for determining overpressure from sonic logs. If wells exhibit different and distinct pressure gradient patterns, each well represents a separate pressure compartment. Layering and variations in the overpressure are sometimes caused when pressure builds up along the shale zones and bleeds off into the associated permeable sands and sandstones. Excellent prediction criteria and sensitivity analysis of formation pressure in sealed layers were proposed by Khilyuk et al. (1994). Pore pressure and fracturing pressure can be computed using sonic velocity and empirical relationships among sonic velocity, rock density, and Poisson’s ratio. A typical methodology is as follows: (1) the stacking velocity information from seismic data is calibrated using well velocities; (2) a normal pressure gradient curve is calculated for the sonic velocity curves; (3) pore pressure is computed from the seismic velocity data using the normal-trend curve; thus, pore pressure distribution in a section is established; and (4) the fracture-pressure gradient is then computed from the pore-pressure gradient, the interval velocities and the empirical relationships among velocity, density and Poisson’s ratio.

h sh, m

50 40 30 20

Depth, m

2,000 3,000 4,000 5,500 12 18 15 13

φsh, %

0.0122 0.0125 0.0120 0.0110

ηsh, MPa/m

0.0116 0.0108 0.0100 0.0098

ηres, MPa/m

Apsheron Archipelago

250 235 185 150

h sh, m

15 12 10 18

φsh, %

0.0137 0.0146 0.0149 0.0148

ηsh, MPa/m

0.0124 0.0119 0.0116 0.0116

ηres, MPa/m

South Apsheron Offshore Zone

900 725 460 350

h sh, m

21 18 16 13

φsh, %

0.0167 0.0179 0.0187 0.0193

ηsh, MPa/m

0.0135 0.0137 0.0140 0.0142

ηre, MPa/m

Baku Archipelago and Lower Kura Depression

Table 7-16 φsh), (3) Pore-pressure Variation with Depth of (1) Average Thickness of Shale (hsh), (2) Shale Porosity (φ ηsh), and (4) Pore-pressure gradient in the Reservoir Rocks (η ηres) in Apsheron Gradient in Shales (η Archipelago, South Apsheron Offshore Zone, Baku Archipelago, and Lower Kura Depression

154

Petroleum Geology of the South Caspian Basin

General Regularities in Oil and Gas Distribution

155

Overpressure can be estimated using drilling and well-logging data. To predict pressure from the drilling and log data, fuzzy logic has been used by Aminzadeh et al. (1994). This method was first applied to data from the South Caspian Basin. Drilling parameters such as the bit weight, rate of penetration, and the changes in the rate of penetration were used for this purpose. The information obtained from pressure prediction is used to choose the required drilling mud density. Also, lithology can be predicted from the pressure data (Aminzadeh et al., 1994; Dunan, 1996; Lee, 2000). Many factors contribute to the magnitude of abnormal formation pressure. These include: (1) mechanical (compactional) deformation of rocks with a change in porosity; (2) mass transfer fluxes; (3) temperature changes; (4) diagenetic transformations; (5) chemistry of intertstitial solutions; (6) lithology and mineralogy; (7) sand/shale ratio; and (8) distribution of porosities and permeabilities of associated sands and shales. The abnormally-high pressures in the argillaceous sequences may substantially affect the geological processes at depth. They evidently have played an important role in folding, clay diapirism, mud volcanism, and earthquakes. The models of these phenomena are described by Coulomb’s law and by rheological models of various theoretical bodies. According to Coulomb’s law, resistance to shearing in shales is the first power function of normal compressive stress. As abnormal pore pressure in shales increases, the intergranular stress (effective stress) decreases, down to very low values under certain conditions. Resistance to shearing, determined by friction, decreases correspondingly. This leads to an intergranular sliding and facilitates to a considerable extent the development of shearing. In such instances, plastic argillaceous sequences become quite mobile at a high shale pore pressure and are displaced. Depending on the geological environment and duration, this process may lead to the development of folds, diapirs, mud volcanoes, or earthquakes. In the South Caspian Basin and onshore Azerbaijan, such geologic setup is quite typical of thick Paleogene to Miocene argillaceous sequences with extremely high, quasigeostatic values of AHFP, with shale pore pressure gradients of 0.020–0.023 MPa/m (Buryakovsky et al., 1986c, 1995). Development of abnormal pore pressures in shales of the South Caspian Basin and onshore Azerbaijan has been experimentally demonstrated by elastic compression of hermetically sealed cores of Cenozoic

156

Petroleum Geology of the South Caspian Basin

shales. Figure 7-17 shows that the pore pressure in the core rises with increasing external confining pressure and then decreases as the confining pressure decreases, but always remaining higher than in the case of increasing load, evidently as a result of residual (irreversible) deformation of the rock (see Rieke and Chilingarian, 1974). Of special interest are the young sedimentary basins, which are characterized by the presence of thick, rapidly accumulated sand/shale sequences. A vivid example is the South Caspian Basin, which is distinguished by a diverse and rather unique association of the following parameters: (1) an exceptionally high rate of sedimentation (up to 1.3 km/my); (2) a very thick (up to 25 km) sedimentary column; sediments of Quaternary—Pliocene age account for up to 10 km (sandsilt-shale); (3) argillaceous rocks make up 50 to 95% of the section and play a key role in determining the mineralogic, lithologic, geochemical, and thermobaric characteristics of the basin; (4) abnormally high pore pressure in shales (average factor of abnormality1 up to Ka = 1.8); (5) low heat flow and low formation temperature (at depths around 6 km, the temperature is approximately 105–110°C); (6) an inverted character of the hydrochemical profile (the chemistry of water changes with depth from calcium chloride and magnesium chloride to sodium bicarbonate type, i.e., freshening of water with depth); and (7) wide development of mud volcanism. The abnormally high formation (pore) pressure (AHFP) in reservoirs is known to be caused by several diverse factors. It appears, however, that the most probable mechanism of AHFP development in regions with thick sedimentary rocks (sand/shale sequence) is a rapid sedimentation and gravitational compaction. This leads to significant underconsolidation (undercompaction) of rocks and to a development of AHFP. Abnormal pressures in reservoir rocks are often caused by the influx of water from overpressured shales. Pressures in sandstones and shales approach each other only in moderately thick beds. The regionally developed reservoirs have a better pressure distribution than that in shales; consequently, their pore pressure usually is lower than that in the enclosing shales (Figure 7-18). In the South Caspian Basin, the drilled Pliocene terrigenous section is 6.5 km thick, with unevenly distributed AHFP, both vertically and 1

Abnormality factor Ka = pa/pn, where pa is abnormally high formation pressure and pn is the normal hydrostatic pressure.

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157

Figure 7-17. Experimentally determined relationship between the pore pressure p p in an argillaceous rock core and the external (confining) pressure σ. Arrows show increasing and decreasing confining pressure.

Figure 7-18. Pore-pressure gradient as a function of relative clay content χsh (Modified after Buryakovsky et al., 1995). 1–3—argillaceous rocks from three regions in Azerbaijan; 4–6—reservoir rocks (sandstones and siltstones) saturated with: 4—water, 5—oil, 6—gas.

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laterally. Presence and magnitude of AHFP are determined by studying the lithofacies of the oil- and gas-bearing rocks, structure of the uplifts, sand/shale thickness ratio, influx of water from shales into sands, integrity of caprocks, distribution of faults and fractured zones, etc. An important regional feature is a very high porosity of argillaceous rocks, much higher than those at similar depths in other areas of the world (Buryakovsky et al., 1982a; Dzhevanshir et al., 1986). As shown in Figure 7-19, porosity of Pliocene shales in the South Caspian Basin

Figure 7-19. Relationship between porosity φsh and depth H (in m) for argillaceous rocks (Modified after Buryakovsky et al., 1995). 1—Devonian (Weller, 1959); 2—Mesozoic (Proshlyakov and Dobrynin, 1961); 3—OligoceneMiocene (Vassoyevich, 1960); 4–6—Middle Pliocene (Durmishyan et al., 1973); 4—Apsheron Archipelago, 5—South Apsheron Offshore Zone, 6—Baku Archipelago and Lower Kura Depression.

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at depths of 4.0–5.5 km is several times higher than in the consolidated shales present in other regions at the same depth. Such a difference is the effect of geological age, relative contents of clay and sand, temperature, and other factors. The abnormally high porosity of shales is primarily the effect of the slower rate of compaction compared to the subsidence rate, due to the slow pore water removal from the compacting argillaceous rocks during rapid sedimentation. This process was crucial in development of AHFP in the South Caspian Basin. It should be noted that AHFP in argillaceous sequences is often attributed to the montmorillonite dehydration as it is altered to illite (hydromica). Field data, however, shows (see Figures 7-13 and 7-14) that a practically unaltered montmorillonite is present in the Baku Archipelago deposits at depths down to 6 km, i.e., throughout the entire drilled section. This indicates a subordinate role of montmorillonite dehydration in the total process of AHFP development in the South Caspian Basin and onshore Azerbaijan. Montmorillonite and illite-montmorillonite minerals may be transformed to illite during diagenesis1 and catagenesis2 , as described for almost all major sedimentation basins throughout the world. These changes in clay minerals during catagenesis are most probable (not simply possible, as in diagenesis), due to increase in temperature and pressure as the sediments are buried. Consequently, during late catagenesis, the clay-mineral assemblage consists of two components (illite and chlorite), no matter what the initial composition. On the other hand, virtually unaltered montmorillonite has been observed at great depths and in large amounts by Kheirov (1979). He explained that the almost unaltered montmorillonite found at a depth of 6,026 m in the Pliocene beds of the Baku Archipelago is due to specific sedimentation conditions, the composition of the initial material, and the abnormally low temperatures, i.e., these sediments lie in the early diagenetic zone. In some cases, absence of potassium ion could explain the absence of montmorillonite-to-illite transformation. Of great importance is the study of regularities in the distribution of clay minerals over the entire section, the identification of basic 1,2

Diagenesis—includes all physical, chemical, and biochemical processes which occur in the sediments after sedimentation and through lithification at near-surface temperature and pressure. Catagenesis—comprises all physical and chemical processes which occur in sedimentary rocks at high temperatures after lithification and up to metamorphism.

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factors influencing the transformation of montmorillonite to illite, and the prediction of catagenetic changes at greater depths not yet reached by boreholes. The results, however, do not always allow one to determine the origin of clay minerals, i.e., whether they are primary or secondary. For example, Milleau (1968, see Buryakovsky et al., 1989b) noted that the montmorillonite formed at the final stage of illite degradation does not differ from the primary montmorillonite, as evidenced by the X-ray analysis. Photomicrographs of fresh broken surfaces of argillaceous rocks of the Productive Series of the Baku Archipelago (depths of 1,400–5,200 m) were taken with scanning electron microscope (Buryakovsky et al., 1986c, 1988). The surfaces were examined in sections cut parallel, perpendicular, or oblique to the bedding. The mineral compositions of these rocks are on the whole the same throughout this depth range. The main clay minerals are illite and montmorillonite, with small amounts of kaolinite and chlorite. The rocks have a honeycomb-like texture, which is clearly seen in oblique sections. The SEM results indicate that there are both “forward” and “reverse” clay-mineral transformations, which occur simultaneously as the rocks are buried. The cores from the depths of 1,400–1,800 m show only very slight changes in the clay minerals, although one can identify damaged sublayers (twisting) at the edges, as well as secondary pores and cracking in some illite grains. There are also microcavities formed by diagenetic processes. Cores from depths greater than 4,000 m show greater evidence of transformation. Illite and montmorillonite predominate, with the montmorillonite being of both primary and secondary origin. The secondary montmorillonite occurs in the interstices between the illite grains, at their edges and in cracks. The primary montmorillonite is disrupted or twisted at the edges and the secondary pores are present. These Pliocene beds show degradation not only of the primary montmorillonite but also of the illite, which changes to montmorillonite. These transformations are probably largely responsible for the retention of the same illite to montmorillonite ratio at depth. Transformation of clay minerals during catagenesis is a complex process, proceeding over a long period of geologic time under the influence of interrelated and interdependent factors. It is extremely difficult to determine the effect of various factors, i.e., to give a quantitative estimate of the magnitude of influence of each one. The solution to this problem probably lies in future investigations. The

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effect of thermobaric and hydrochemical factors on the post-sedimentary (diagenetic and catagenetic) alteration of these Pliocene clays should be studied using the data on chemical analyses of formation waters (e.g., the availability of potassium ion), formation temperatures, and pore pressures determined from logs. Effect of Pressure and Temperature The abnormally low temperatures may be responsible for the absence of clear-cut clay-mineral transformation. Khitarov and Pugin (1966) and Magara (1982) have indicated that temperature is a major factor influencing montmorillonite degradation. Also of interest is the effect of illite degradation on the geothermal gradient. Inasmuch as hydration of clays is an exothermic reaction, there may be elevated gradients at depth ranges where the illite is transformed to montmorillonite, all other conditions being equal. In the areas of the South Caspian Basin and onshore Azerbaijan, the average geothermal gradient is approximately 16°C/km, and the temperature at a depth of about 6 km does not exceed 110°C. A characteristic feature is that the geothermal gradient becomes lower at a depth of approximately 4 km (Table 7-14). The increased geothermal gradient at a depth of approximately 4 km may be related to illite-to-montmorillonite transformation, which releases heat. At a depth of approximately 4 km, the transformation rate exceeds some limit, which causes hydration to predominate over dehydration. One should, therefore, consider the effects of temperature on diagenetic and catagenetic processes. An increase in temperature may accelerate the process of montmorillonite catagenetic transformation into non-swelling minerals (illite and chlorite). Consequently, if true, sections with high geothermal gradient should be characterized by a small montmorillonite content. On the other hand, inasmuch as a temperature decrease retards the process of montmorillonite transformation, sections with a low geothermal gradient should be characterized by a high montmorillonite content. Figure 7-20a shows the dependence of montmorillonite content on the geothermal gradient in shales of the South Caspian Basin. The highest montmorillonite contents are found in the shales of the Baku Archipelago and Lower Kura Region, which are characterized by a low geothermal gradient (16°C/km). The Apsheron Peninsula and the

Figure 7-20. Relationship between the montmorillonite content and geothermal gradient (a) and pore-pressure gradient (b) (Modified after Buryakovsky et al., 1995).

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adjacent offshore areas, which have a higher geothermal gradient (24.0–28.5°C/km), are characterized by lower montmorillonite contents. Low temperature apparently does not favor the transformation of montmorillonite to illite; this reduces the montmorillonite transformation rate. Under otherwise equal conditions, the transformation increases with depth, which means that some additional factors must be influencing the transformation. One of these factors, discussed by Serebryakov et al. (1995), is the lack of potassium ion in interstitial water. Inasmuch as the transformation of montmorillonite into illite proceeds with the removal of interstitial water, conditions at which desorbed water leaves the pore space without hindrance will be favorable for the development of this process. Factors opposing the withdrawal of fluids from the interlayer space of clays, therefore, may lead to slowing down or cessation of transformation of montmorillonite into illite or chlorite. The writers believe that such a factor is the abnormally high pore pressure, which occurs virtually throughout the section of the area under study. The hydrostatic pressure gradients in the pores of shales at 1,000–6,000 m are based on more than 2,000 determinations and range from 0.012 to 0.024 MPa/m, with a mean of 0.018 MPa/m (see Figure 7-16 and Table 7-14). The dependence of the montmorillonite content on the pore pressure gradient in shales is shown in Figure 7-20b. There is a close correlation between these two parameters. In regions of the Baku Archipelago and Lower Kura Depression, characterized by intense development of AHFP (pore pressure gradients in shales of 0.018–0.019 MPa/m), the montmorillonite content in shales reaches an average of 53%. In regions with moderate development of AHFP (Apsheron Archipelago and the South Apsheron Offshore Zone), the montmorillonite content decreases to 17%. These authors found no adequate discussion in relevant literature on the role of pore pressure in shales on clay-mineral diagenesis and catagenesis. It can be shown theoretically that rising pressures reduce the dehydration rates. The production of illite in shales involves an increase in the free water volume as a result of the release of bound water, which is denser than free water. A factor opposing this increase in volume (such as high pore pressure in shales) will reduce the dehydration rate. This agrees well with the conditions which exist in the above-described sections. On the other hand, AHFP can lead to transformation of illite to secondary montmorillonite by the absorption of water. At AHFP,

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smaller grain size of the clay minerals favors transformation of illite, as shown by the relationship between the pore size and depth (Table 7-10 and Figure 7-21; pore sizes were determined from SEM data). The writers propose the following scheme for the relationship between clay-mineral transformation and the thermobaric conditions: In a basin where the subsidence rate is equal to the rate of accumulation of sediments, the depth at which catagenetic transformation (desorption of water) begins remains more or less the same and is largely determined by the geothermal gradient. Inasmuch as the desorbed (interlayer) water is added to the interstitial water, abnormally high pore pressures may develop if the water cannot escape. Under some conditions, the rising pore pressure in shales may reduce the montmorillonite dehydration rate and release of water. The result will be similar to that arising from a low geothermal gradient, i.e., reduction in the rate of illite formation. Under favorable conditions, the illite may be hydrated, which is accompanied by a release of heat and their transformation to secondary montmorillonite. The relative rates of dehydration (illite formation) and the illite hydration (formation of secondary montmorillonite) may determine the pore pressure. The sedimentation rate and the sediment sources do not remain constant with time. Thus, different zones may differ in the dehydration rate because of changes in the sedimentation rate or type of sedimentary material. Transitions from a zone with normal pressures and normal dehydration rate to an AHFP zone may indicate either the effect of diagenetic and catagenetic processes or a lag in development of these processes. The montmorillonite content may remain the same or even increase with depth. This, however, does not mean that the process of dehydration of montmorillonite to illite is replaced by the illite hydration, although this is possible. Instead, it could mean that dehydration process in the AHFP zones is slow; therefore, these zones may be characterized by higher (or equal) montmorillonite contents than those in the younger zones with normal shale pore pressure. Effect of Hydrochemical Environment The hydrochemical environment in a basin of sedimentation has significant influence on the intensity of post-sedimentary transformations. Thus, it is important to ascertain the nature of the hydrochemical regime observed in the Cenozoic complex of the South Caspian Basin,

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Figure 7-21. Pore size distribution of argillaceous rocks from the Productive Series of Baku Archipelago. ω is relative frequency (Modified after Buryakovsky et al., 1986c). a—Duvanny Deniz, well 529, depth interval of 1,415–1,420 m/ 4,642–4,659 ft and 1,450–1,455 m/4,757–4,774 ft; b—same but depth intervals are 1,700–1,705 m/5,577–5,594 ft and 1,785–1,790 m/5,856–5,873 ft; c—same field but Well 275 and depth interval of 3,323–3,328 m/10,902– 10,919 ft; d—Sangachal, Well 534, depth interval of 4,295–4,303 m/14,091– 14,117 ft; e—Bulla Deniz, Well 537, depth interval of 4,993–5,000 m/16,381– 16,404 ft; f—same field but Well 15 and depth interval of 5,128–5,132 m/ 16,824–16,837 ft.

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namely: whether it is a consequence of diagenetic and catagenetic processes in shales and the transformation of clay minerals, or it is formed predominantly as a result of the action of other factors (e.g., compaction; see Rieke and Chilingarian, 1974). In this connection, the problem presenting the greatest interest is the origin of inverted hydrochemical profile in the section of the South Caspian Basin, i.e., with depth, calcium chloride waters are replaced by less saline sodium bicarbonate waters. The writers obtained numerous data from the laboratory analyses and field observations, indicating a decrease in the mineralization of pore waters in sands with depth. Replacement of calcium chloride water by alkaline sodium bicarbonate water is more characteristic for the AHFP zones in the South Caspian Basin areas (Buryakovsky, 1974a). Analogous data on the decrease of formation water salinity with increasing pressure were also noted in the Gulf of Mexico (Fertl, 1976). The appearance of hydrochemical inversion in the stratigraphic section of the South Caspian Basin may be explained by the genetic relationship between the hydrochemical regime and the development of abnormally-high pore pressures in shales. The water of primarily sodium bicarbonate type characterize the most pronounced AHFP zones in the Baku Archipelago and Lower Kura Depression. Chemistry of pore waters are determined largely by the compaction processes in argillaceous rocks and squeezing out of pore water (Chilingarian et al., 1994). The hydrochemical environment influences the diagenetic and catagenetic transformation (of clay minerals) processes. Figure 7-22 shows the dependence of montmorillonite content on the total salinity of formation water for the calcium chloride and sodium bicarbonate types of pore waters in sands, which are characteristic for the South Caspian Basin. As shown, a direct relationship exists for the sodium bicarbonate type of water, i.e., with increasing water salinity, the conditions for preservation of montmorillonite are improved and its content in the clays increases. Increase in the total salinity of water is caused by an increase in the content of carbonate and bicarbonate salts of alkali-earth metals. Sodium bicarbonate type waters are present in the Baku Archipelago and the Lower Kura Depression, as well as in the rocks from the Lower Productive Series of Apsheron Peninsula and adjacent offshore area, i.e., sections in which the argillaceous rocks are characterized by higher montmorillonite

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Figure 7-22. Relationship between the montmorillonite content and formation water salinity (Modified after Buryakovsky et al., 1995). 1—Sodium bicarbonate water, 2—calcium chloride water.

content. There is an inverse relationship between the montmorillonite content and the presence of calcium chloride type of waters. The chloride content [in particular sylvite (KCl)] increases with increasing water salinity. Thus, the alkaline medium is favorable for the formation and preservation of montmorillonite. This was also confirmed by the results of computer geochemical simulation (Buryakovsky et al., 1990c). The RAMIN program was utilized, which is similar to the geochemical model proposed by Kharaka and Barnes (1973). The RAMIN program makes it possible to simulate the equilibrium distribution of the majority of elements present in the pore solutions at temperatures up to 350°C on the basis of data on the chemical composition of formation water, temperature, pH and Eh. For determination of the

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possibility of dissolution or precipitation of one or another mineral, calculation of ∆G values of the Gibbs free-energy difference is included in the program. The results of the chemical analyses of formation water in Wells 96 and 521 of the Unit VII of the Sangachal–Duvanny Deniz–Khara Zyrya Field served as initial data for the computer-based simulation (Table 7-17). Average depth and formation temperature are as follows: Well 96: –3,091 m, +80°C; Well 521: –4,320 m, +97°C. The pH value used averaged 7.0–7.5. Table 7-18 gives the results of determination of the Gibbs freeenergy difference, ∆G, for various clay minerals. As shown, within the pH interval of 6 to 8, in most cases ∆G values for minerals of the montmorillonite and kaolinite groups exceed zero. This indicates a possibility that they are of authigenic origin. The values of ∆G for illite are always less than zero, which indicates the possibility of its precipitation from solution. Thus, the geochemical environment at great depths in the South Caspian Basin deposits is not only conducive to the preservation of allothigenic montmorillonite, but possibly allows the transformation of illite into secondary montmorillonite. Secondary Montmorillonite According to the data cited above, a rather close relation exists between the various clay mineral contents and the thermobaric and

Table 7-17 Chemical Analyses of Formation Water from Wells 96 and 521, Unit VII, Sangachal–Duvanny Deniz–Khara Zyrya Field

Components

Cl– 2–

SO4 HCO3– CO32– RCOO–

Concentration, mg/liter

Components

Concentration, mg/liter

709.0 211.2

Ca2+ Mg2+

195.2 36.0

Na++K+ Al3+

618.7 60

Σ

mV

Mean Ada,

16.8 11.2 6.6 2.6 39.4 5.6 4.6 — 100

28.0 26.6 35.1 31.5 38.5 38.8 55.8 — 33.9

— — 13.3 24.2

Frequency (in %) of Ada Intervals (in mV)

Lower Kura Depression (N* = 196)

Table 10-20 Distribution of Ada Parameter in the Rocks of Baku Archipelago and Lower Kura Depression

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Figure 10-16. Dependence of surface activity parameters on the mineral composition of rocks (Modified after Buryakovsky et al., 1986a). a—Bakhar Field, b—Sangachal—Duvanny Deniz—Khara Zyrya Field.

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(text continued from page 315)

reservoir rocks. The montmorillonite content of the clay cement of reservoir rocks of the Lower Kura Depression is almost twice higher than in the reservoir rocks of the Baku Archipelago and South Apsheron Offshore Zone. This explains why the surface activity of reservoir rocks of the Lower Kura Depression is higher than that in the offshore areas. The Ada is practically the same when the montmorillonite content in clays is the same. Thus, the above mentioned difference in the Ada for different rocks is due to different clay content. It is well known that the surface activity of montmorillonite clay is higher in comparison with other clay minerals.

Relationships Between Reservoir-rock Properties and Surface Activity Figures 10-17 and 10-18 show correlations between the reservoirrock properties and surface activity in the form of average (orthogonal) regression lines in one graph for two regions: (1) Baku Archipelago and South Apsheron Offshore Zone and (2) the Lower Kura Depression. The correlation coefficient (r) is presented in all cases. The correlation coefficients and criteria of their significance (three times the standard deviation sr) are presented in Table 10-21. From 32 correlations studied, only one differs slightly from zero at a significance level α = 0.05 (when α = 0.01, this correlation is significant). This correlation is the dependence of permeability on the clay content of the rocks of Lower Kura Depression. All other correlations are reliable enough and have a high statistical stability, i.e., they are controlled by geological factors. Comparison of data for both regions shows that correlations obtained for Baku Archipelago and the South Apsheron Offshore Zone are more stable in general. The relationships between the (1) weighted and relative clay content and surface activity parameters (Q100 and Ada); (2) Q100 and Ada; and (3) porosity (φ) and Ada are the most reliable correlations in the offshore areas. Such correlations validate the determination of porosity and clay content using SP logs. The correlations among reservoir-rock properties are good and depend on the similarity in lithology. In the Lower Kura Depression, correlations between the clay content and porosity, on one hand, and surface activity parameters, on the other

Figure 10-17. Correlations between reservoir-rock properties and surface activity parameters of rocks of the Productive Series (Modified after Buryakovsky et al., 1986a). 1—Baku Archipelago and South Apsheron Offshore Zone, 2—Lower Kura Depression. Cs = Csh = clay/shale content; Cc = carbonate content.

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Figure 10-18. Interrelationship among the reservoir-rock properties, surface activity parameters, and relative clay content of the Productive Series rocks (Modified after Buryakovsky et al., 1986a). 1—Baku Archipelago and South Apsheron Offshore Zone, 2—Lower Kura Depression. η = see p. 315.

(and also between Q100 and Ada) are quite reliable. In general, however, these correlations are less reliable than in the offshore fields. Among other correlations, relationship between porosity and permeability (controlled by a considerable effect of carbonate cement on both parameters) is the most reliable. This is due to wide carbonate cement content range (up to 44%) in comparison with the rocks of the Baku Archipelago and South Apsheron Offshore Zone (up to 26%). Figures 10-17 and 10-18 show that for the Lower Kura Depression, with the exception of permeability vs. clay content and porosity, all other correlations have a higher position on the figures with respect to the abscissa. This means that, for example, at the same clay content

287 167 273 165 282 162 162 246 163 247 161 243 157 150 199 157

φ–Ccarb k–Ccarb φ–Csh k–Csh φ–η k–η k–φ Q100–Csh Ada–Csh Q100–η Ada–η Q100–φ Ada–φ Q100–k Ada–k Q100–Ada

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

|r |

0.192 0.390 0.473 0.442 0.574 0.555 0.530 0.610 0.718 0.626 0.715 0.433 0.631 0.360 0.576 0.670

N = number of tests r= absolute value of coefficient of correlation σr = standard deviation φ = porosity k = permeability

Definitions of variables:

N

Type of Correlation

Eq. No.

0.057 0.060 0.047 0.063 0.040 0.054 0.057 0.040 0.038 0.039 0.039 0.052 0.048 0.071 0.067 0.044

σr

524 254 430 198 532 237 252 284 199 341 252 284 203 151 139 169

N

0.490 0.510 0.228 0.131 0.541 0.570 0.715 0.522 0.256 0.400 0.397 0.381 0.418 0.351 0.468 0.408

|r |

0.033 0.016 0.046 0.062 0.031 0.044 0.031 0.043 0.066 0.045 0.053 0.051 0.058 0.071 0.066 0.064

σr

Lower Kura Depression

Csh = shale/clay cement content Ccarb = carbonate cement content η = relative clay content Q100 = cation-exchange capacity Ada = diffusion-adsorption parameter

0.171 0.180 0.141 0.189 0.120 0.162 0.171 0.120 0.114 0.117 0.115 0.156 0.144 0.213 0.201 0.132

3σr

Baku Archipelago and South Apsheron Offshore Zone

Table 10-21 Coefficients of Correlation between Various Variables and Their Accuracy

0.099 0.140 0.133 0.186 0.093 0.132 0.093 0.129 0.198 0.135 0.159 0.151 0.174 0.213 0.198 0.192

3σr

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the reservoir-rock properties (porosity φ and permeability k) and diffusion-adsorption factor (Ada) in the Lower Kura Depression have higher values than for the offshore areas. The curves of φ, k and Ada vs. Q100 exhibit the same behavior (see Figure 10-15). The relationships between the surface activity parameters of rocks and their porosity and clay content (Q100 and Ada vs. φ, Csh and η curves) and their relationships between each other (Q100 vs. Ada, and φ vs. Csh and η) are very useful. The average regression lines were approximated by analytical equations. Sixteen correlations between various variables (reservoirrock properties and surface activity parameters) are presented in Table 10-22. These include: permeability vs. porosity, weighted and relative clay content, cation-exchange capacity and diffusion-adsorption parameter. Included is also the effect of carbonate cement content on reservoirrock properties. These equations can be generalized as the following single model: Fi(y) = ai + bi f(xi) + ciψ(xi)

(62)

Empirical coefficients a, b, and c for two regions studied are presented in Table 10-23.

Table 10-22 Correlations Between Surface Activity Parameters and Reservoir-Rock Properties Eq. No.

Equation

Eq. No.

Equation

1 2 3 4 5 6 7 8

φ = a3 – b3Ccarb + c3Ccarb2 lgk = a4 – b4Ccarb φ = a1 – b1lgCsh lgk = a2 – b2Csh φ = a6 – b6η lgk = a7 – b7η lgk = a5 + b5φ Q100 = a8 + b8Csh

19 10 11 12 13 14 15 16

Ada = a9 + b9√Csh Q100 = a14 – b14η + c14η2 Ada = –a15 + b15η lgQ100 = a10 – b10φ Ada = a11 – b11φ Q100 = a12 – b12lgk Ada = a13 – b13lgk Ada = –a16 + b16√Q100

See Table 10-21 for definitions of variables

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Petroleum Geology of the South Caspian Basin Table 10-23 Empirical Coefficients of General Equation of Correlation Baku Archipelago and South Apsheron Offshore Zone

Lower Kura Depression

i

a

b

c

a

b

c

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

30.0 3.48 36.6 3.30 0.30 4.00 2.70 0 21.1 0 15.8 1.91 68.6 14.2 29.7 18.7

1.632 0.194 15.8 0.113 0.300 6.67 0.242 0.480 9.4 5.1 78.8 0.061 2.86 4.37 10.3 13.3

0.0237 — — — — — — — — 51.1 — — — — — —

31.5 3.0 52.6 3.78 0.35 4.2 3.01 0 17.5 0 8.1 1.96 80.0 18.0 42.4 20.7

1.355 0.171 23.8 0.108 0.35 6.75 0.202 0.48 10.0 6.5 81.1 0.045 2.50 6.17 11.6 14.7

0.0185 — — — — — — — — 57.0 — — — — — —

Conclusions can be summarized as follows: 1. Based on a large volume of experimental data, correlations among surface activity parameters, reservoir-rock properties, and grain size and mineralogy of terrigenous rocks of the Productive Series of the Azerbaijan part of South Caspian Basin have been established. Also, the diffusion-adsorption parameter and cationexchange capacity for different rock types have been determined. 2. Correlation equations obtained may serve as petrophysical models while interpreting SP logs, and also planning and carrying out waterflooding operations.

MODELS OF OIL COMPOSITION AND PROPERTIES Crude oil is a complex natural system consisting of various components with a considerable predominance of different hydrocarbon

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groups. Data on hydrocarbon-group composition of oil are of great importance for understanding its origin and preparing genetic classifications.

Hydrocarbon Group Composition and Main Properties of Crude Oil Composition of crude oil is determined by dividing it into fractions according to the molecular weight, followed by estimation of hydrocarbongroup composition of each fraction. Division of crude oil into fractions can be made according to their boiling point ranges. Fractional composition shows relative contents in percent by weight (wt %) of different oil fractions boiling within definite boiling-point ranges. The following main fractions are distinguished in Russia and other CIS countries: “benzine” with boiling point range of 40 to 200°C, “ligroin” with boiling point range of 200 to 350°C, and “residual oil” with boiling point range of 350 to 500°C. “Benzine” fractions of the Azerbaijan oils constitute 40% of distillate at 100°C. (See p. 177.) Entropy, as a measure of heterogeneity of crude oil composition, differs in fractions having different boiling-point ranges (Buryakovsky, 1968). If relative entropy of oil as a heterogeneous system of lightboiling fractions (from 65 to 150°C) is 0.6–0.7, it increases to 0.8 in fractions with boiling-point range of 150 to 225°C. For high-boiling fractions (from 225 to 350°C), the relative entropy reaches a maximum value of 1. Entropy evaluation, as a measure of complexity of an oil composition, has a certain advantage over the other classifications of oils, because it allows one to assign a numerical value to the oil heterogeneity. The values range from 0 to 1, with 0 characterizing vertexes of the mixture triangle, and 1 characterizing the center of the triangle (see Figure 10-9). In order to evaluate the geochemical history, in addition to the fractional oil composition, hydrocarbon-group composition of different fractions is also used (content of paraffinic, naphthenic, and aromatic groups of hydrocarbons). The hydrocarbon-group composition of crude oil can be clearly presented on a mixture triangle (Gibbs’ triangle). Based on more than 100 samples of oils from the Apsheron Archipelago fields, hydrocarbon-group composition of light fractions of crude oil (gasoline and ligroin) is plotted on a triangular diagram in Figure 10-19.

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Figure 10-19. Hydrocarbon-group composition of light fractions of oils from Neft Dashlary Field (Modified after Buryakovsky and Dzhevanshir, 1992). • = “benzine” (gasoline); x = “ligroin.”

According to the experimental data, Figure 10-20 shows the dependence of content of various hydrocarbon groups on boiling point for crude oils of the Apsheron Archipelago. The results obtained by Dobryanskiy (1948) and Kartsev (1950) for “world” oils (weighted average data for many oil fields) are given for a comparison. With increasing boiling point, the aromatic hydrocarbons content increases, whereas the content of paraffinic hydrocarbons decreases. Besides hydrocarbon components, different non-hydrocarbon components are present in the crude oil. Asphaltenes and resins constitute the major portion of non-hydrocarbon components. Crude oil density and contents of asphaltenes and resins, gasoline, and ligroin of the crude oil from Neft Dashlary oilfield in the Apsheron

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Figure 10-20. Hydrocarbon-group composition of crude oils. 1—Average “world” crude oil according to A. A. Kartsev; 2—average “world” crude oil according to A. F. Dobryanskiy; 3—oil from Neft Dashlary Field; 4—oil from Palchygh Pilpilasi Field (Modified after Buryakovsky and Dzhevanshir, 1992).

Archipelago (Buryakovsky, 1974a) are presented as histograms in Figure 10-21. In the northwestern part of the Apsheron Archipelago (Darvin Bank, Pirallaghi Adasi, and Gyurgyany Deniz fields), average crude oil parameters [with evaluation of their variation within two-sigma limits (95% of confidence)], based on 1,642 analyses, can be presented as follows: γ = 0.9137 ± 0.0240 g/cm3 R = 37.2 ± 15.1% B = 1.54 ± 1.20% L = 7.4 ± 1.3%

γave = 0.9137 ± 0.0006 g/cm3 Rave = 37.2 ± 0.37% Bave = 1.54 ± 0.03% Lave = 7.4 ± 0.03%

where γ is density, R is the content of asphaltenes and resins, B is the “benzine” (gasoline) content, and L is the content of ligroin.

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Figure 10-21. Histograms of crude oil density (a), content of resins (b), and “benzine” (gasoline) content (c) in the crude oils of Neft Dashlary Field (Modified after Buryakovsky and Dzhevanshir, 1992). 1—Balakhany Suite, 2— “Pereryv” Suite, 3—NKP, 4—KS, 5—PK, 6—KaS.

Based on 820 analyses, in the southeastern part of the Apsheron Archipelago (Chalov Adasi, Palchygh Pilpilasi, and Neft Dashlary oilfields) these crude oil parameters are equal to: γ = 0.8800 ± 0.0380 g/cm3 R = 22.7 ± 11.8% B = 7.4 ± 7.5% L = 9.6 ± 8.0%

γave = 0.8800 ± 0.0013 g/cm3 Rave = 22.7 ± 0.41% Bave = 7.4 ± 0.26% Lave = 9.6 ± 0.28%

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The crude oil of the northwestern part of the Apsheron Archipelago contains more asphaltenes and resins and less low-boiling fractions; hence, its density is higher than that of the oil from the southeastern part of archipelago. Using both numerical characteristics and histograms or as frequency distributions (relatived frequencies), one can solve different geological and geochemical problems. For example, Figure 10-21 shows the distribution of oil densities, content of asphaltenes and resins, and gasoline content in different suites of the Neft Dashlary Field. With increase in burial depth, density of crude oil and content of asphaltenes and resins increase, whereas the gasoline content decreases. These trends, however, are not present in the Upper Productive Series. The increase in density of oil in the Upper Productive Series is related to the oxidation of oil by near-surface agents, which increases the content of asphaltenes and resins and decreases the gasoline content.

Relationship between Composition and Properties of Crude Oils There are correlations between the crude oil parameters and its composition and among the various parameters and content of trace elements. These variables can be studied by correlation and regression analyses. The correlation analysis shows the presence, strength, and sign of the relationship between the correlated parameters, whereas the regression analysis enables one to establish the type of relationship or to develop models. For example, correlation matrices for different crude oils from offshore oilfields of the Apsheron Archipelago were obtained from correlation analysis. Several types of correlation matrices with a different number of analyses and, therefore, with different reliable values of the correlation coefficient, were calculated. Table 1024 is a generalized matrix of correlation coefficients for the fields of the Apsheron Archipelago. Instead of numerical values of correlation coefficients in this table, only the signs of coefficients with reliable values are presented. Due to different interrelationships, estimation of a certain number of parameters of a given crude oil may be sufficient to estimate values of other parameters. The simplest, and at the same time one of the main properties of crude oil, is its density, which is closely dependent

Density Coking ability Acidity Viscosity Content of resins and asphaltenes Trace elements: V Fe Ni Cr Ti Co

Parameters

+ + +

Coking Ability Acidity

+ + + +

Viscosity

+ + +

Content of Resins and Asphaltenes

+ +

+

+

+

Ni Cr

+ +

+

Fe

+ + +

V

+

+ +

+ +

Ti Co

+

+

+

+ +

Mo

Trace Elements

+

+

Be Sr

Table 10-24 Signs of Correlation Coefficients between Crude Oil Parameters (Generalized Matrix)

+

Sn

+

+ + +

V/Ni

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Mathematical Models in Oil and Gas Exploration and Production

331

on the fractional composition and the content of asphaltenes and resins in the crude oil. Interrelationship among the major crude oil parameters is of great interest from the point of view of petroleum geochemistry, and equations derived by regression analysis can serve as mathematical models of the crude oils. Crude oils of some fields of the Apsheron oil- and gas-bearing region and adjacent offshore areas of the Caspian Sea were thoroughly studied. These oils are of high-quality, naphthenic-paraffinic type. Their densities range from 0.81 to 0.93 g/ cm3 and depend on the contents of heavy resins and asphaltenes, and light gasoline and ligroin. The influence of these components of crude oil on density can be studied by means of correlation for four parameters: (1) γ = oil density in g/cm3, (2) R = content of resins and asphaltenes in wt %, (3) B = content of gasoline in wt %, and (4) L = content of ligroin in wt %. Based on 820 analyses, the correlation between the oil density and content of resins plus asphaltenes was tabulated (Table 10-25) as an example. Empirical equation of relationship between the density and content of resins plus asphaltenes in crude oil in the form of regression R on γ is as follows: γ = 0.826 + 0.00237R

(63)

or in the form of regression γ on R: R = 212(γ – 0.778)

(64)

The coefficient of correlation between the R and γ is 0.710. It is not always convenient to have two different regression equations (Equations 63 and 64). Thus, it is desirable to have a single equation, for example, an equation of orthogonal regression as suggested by Nalimov (1960), Smirnov and Dunin-Barkovskiy (1965), Griffiths (1971), Buryakovsky et al. (1974c), Rodionov et al. (1987), and Buryakovsky and Agamaliyev (1990a). To calculate the orthogonal regression, it is necessary to give the probability of belonging of the experimental data to the ellipse of correlation, i.e., Q(χ). If the probability Q(χ) is given, then one can calculate the ellipse parameter χ by using the following formula: χ = (–2ln[1 – Q(χ)])1/2

(65)

0.82 0.83 0.84 0.85 0.86 0.87 0.88 0.89 0.90 0.91 0.92 0.93 0.94

0.815-0.825 0.825-0.835 0.835-0.845 0.845-0.855 0.855-0.865 0.865-0.875 0.875-0.885 0.885-0.895 0.895-0.905 0.905-0.915 0.915-0.925 0.925-0.935 0.935-0.945 NR 9 59

13 10 20 16 14 13 13

12.5

7.5

2 3 1 3

10–15

5–10

162

113 120 135 124 132 132 113 112 111

17.5

15–20

341

114 118 111 147 130 195 139 117

22.5

20–25

112 111 156 163 143 110 114 111 111 191

27.5

25–30

13 13 16 18 18 13 11 32

32.5

30–35

12 17 14 11 11 18

13

37.5

35–40

Content of Resins Plus Asphaltenes (wt %)

Nγ = number of crude oil density determinations. NR = number of determinations of resins plus asphaltenes content.

Average γave

Range ∆γ

Density (g/cm3)

4

2 1 1

42.5

40–45

Table 10-25 Correlation between the Crude Oil Density and Content of Resins Plus Asphaltenes

4

1 1 2

47.5

45–50

112 119 135 166 153 194 227 177 192 136 118 118 113 820

Nγ

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333

Thus, when Q(χ) = 0.98, the ellipse parameter is χ = 2.8. The higher the probability Q(χ), the greater is the ellipse parameter χ. Having available data on the values of χ, Rave, γave, δR, δγ, and ZRγ, one can estimate parameters of the orthogonal regression equation. This equation represents the main axis of the correlation ellipse, where coordinates of the ends in a normalized scale are calculated by the following formulae: aR = χ [(1 + ZRγ )/2] δR and aγ = χ [(1 + ZRγ)/2] δγ

(66)

For Q(χ) = 0.98 and χ = 2.8, calculation according to Equations 66 yields: aR = 15.22 and aγ = 0.0516

In a natural scale, the corresponding coordinates can be written as follows: R1,2 = Rave ± aR, i.e., R1 = 22.75% + 15.22% = 37.97% and R2 = 22.75% – 15.22% = 7.53%; and γ1,2 = γave ± aγ, i.e., γ1 = 0.9316 g/cm3 and γ2 = 0.8284 g/cm3. The equation of the main axis of the correlation ellipse at a given probability Q(χ) (the equation of orthogonal regression) may be obtained as an equation of a line passing through two points with coordinates (R1, γ1) and (R2, γ2). The corresponding points are (37.98, 0.9316) and (7.53, 0.8284). For these points, the equation of orthogonal regression can be written in the following form: R = 295(γ – 0.805) or γ = 0.0034R + 0.805

(67)

Both Equations 67 are equivalent. Conjugated equations of regression (Equations 67 and 64) represent the conjugated axes of the correlation ellipse. From Equations 67 it follows that the crude oil having density of 0.805 g/cm3 does not contain resins and asphaltenes. It is noteworthy that the value of 0.802 g/cm3 corresponds approximately to the density of ligroin obtained by refining crude oil from fields of the Apsheron oil- and gas-bearing region. If the content of resins and asphaltenes varies from 57 to 87%, the density reaches 1.0–1.1 g/cm3, i.e., crude oil changes into asphalt. Besides coefficients of correlation, the eccentricity e of the correlation ellipse may be used as a measure of tightness of correlation links:

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e = c/a

(68)

where c is half the distance between the foci, and a is half the length of the main axis of the ellipse. To calculate the distance between the foci, one should estimate the coordinates of the ellipse foci according to the following formulae (in normalized scale): fR = χZ1/2δR and fγ = χZ1/2δγ

(69)

Substituting values of parameters for variables, one obtains fR = 13.8 and fγ = 0.0468. In a normalized scale, CR = fR and Cγ = fγ. Therefore, e = 13.8/15.22 = 0.905. The ellipse eccentricity e does not depend on the probability Q(χ). The value of this probability defines only the number of data points belonging to the ellipse of correlation. One can compute the number of data points beyond the limits of the correlation ellipse according to the following formula: Nbeyond = N[1 – Q(χ)]. In the given case, Nbeyond = 16 with Ntotal = 820. Conjugated and orthogonal lines of regression, the equations of which were given earlier, are presented in Figure 10-22a. Lines of equal probability of the pairs γ and R are drawn in accordance with the correlation table (see Table 10-25). As shown, the form and the tightness of the contour lines along the main axis may also show a sufficiently close relation between density and content of resins and asphaltenes in crude oil. Variations in parameters are equal to: vR = 26.0% and vγ = 2.2% for R and γ, respectively. This shows that the content of resins and asphaltenes varies more than density, the stability of which is dependent on the stability of major crude oil components. The crude oil density is greatly affected by the content of lowboiling components. With increasing content of gasoline and ligroin, the density of oil decreases. Based on 792 analyses of crude oil, equations for the relationship between the oil density, γ, and gasoline (“benzine”), B, content were calculated as follows: γ = 0.9063 – 0.00380B

(70)

B = 143.7 – 155γ

(71)

The equations of the line of orthogonal regression (the main axis of the correlation ellipse) can be presented as follows:

Figure 10-22. Orthogonal and conjugated regression lines for relationships in oils from Neft Dashlary Field. a—Oil density (g/cm3) versus the content of resins (R, %); b—oil density versus “benzine” (gasoline) content (B, %). 1— Regression of γ on R and B, 2—regression of R or B on γ, 3—equal-frequency curve, 4—ellipse of correlation, 5— major axis of the ellipse (line of orthogonal regression), 6—minor axis of the ellipse.

Mathematical Models in Oil and Gas Exploration and Production 335

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Petroleum Geology of the South Caspian Basin

γ = 0.915 – 0.0500B or B = 200(0.915 – γ)

(72)

The correlation coefficient of 0.760 indicates a sufficiently close, reverse, linear relation between γ and B. At γ = 0.915 g/cm3, crude oil no longer contains gasoline fraction. The coefficient of variation for distribution of gasoline content is 51.4%, whereas for density it is 2.2%. Lines of equal probability form concentrically situated ovals stretched along the main axis (Figure 10-22b). The eccentricity of the ellipse is 0.94. Calculated values of all coefficients of correlation for paired correlations are presented in Table 10-26. Having available data on all paired correlations, one can derive an equation of multiple regression containing all three main parameters. The equation of multiple regression is a linear function: γ = γo + aR + bB + cL

(73)

where a, b, and c are numerical coefficients, and γo is the density of crude oil when R = B = L = 0. The multiple regression equations for various oilfields in the Azerbaijan portion of the South Caspian Basin are as follows: 1. Darvin Bank, Pirallaghi Adasi and Gyurgyany Deniz Fields: γ = 0.9805 + 0.00009R – 0.00910B – 0.00796L

Table 10-26 Coefficients of Correlation of Paired Relationships between Crude Oil Parameters Relationship Between

γ and γ and γ and B and L and L and γ and R,

R B L R R B B, L

Correlation Coefficient

+0.71 –0.76 –0.47 –0.60 –0.12 +0.64 0.83

Mathematical Models in Oil and Gas Exploration and Production

337

2. Chalov Adasi Field: γ = 0.9190 + 0.00046R – 0.00481B – 0.00208L

3. Palchygh Pilpilasi Field: γ = 0.9258 + 0.00017R – 0.00131B – 0.00139L

4. Neft Dashlary Field: γ = 0.8640 + 0.00210R – 0.00230B – 0.00140L

The general equation relating γ, R, B, and L is as follows: γ = 0.864 + 0.0021R – 0.0023B – 0.0014L

(74)

As shown in Table 10-26, the coefficient of multiple correlation, is higher than any paired coefficient of correlation. Thus, the equation of multiple correlation (Equation 74), which takes in consideration the influence of every parameter, describes the experimental relationships more reliably than the paired equations of regression. In deriving this regression, some parameters were fixed at average levels. To expedite the calculations, a nomograph (Figure 10-23) was constructed according to the Equation 74. For example, at the given values of R = 23%, B = 7.2%, and L = 7.0%, γ = 0.882 g/cm3. Inasmuch as the dependence of density on variations in ligroin content in the crude oil is weak, the term in the equation of multiple relationship (Equation 74) corresponding to the influence of ligroin on density may be replaced by a constant value. In this case the equation is written in the following way: γ = 0.8707 + 0.0013R – 0.0027B

(75)

The coefficient of multiple correlation is 0.830. Graphically this relationship is presented in Figure 10-24. As shown, the dependence of crude oil density on content of resins, asphaltenes, and gasoline (ligroin influence is excluded) is clearly expressed graphically and can be used in calculations.

Figure 10-23. Nomograph of relationships among oil density and contents of resins, “benzine” (gasoline) and ligroin.

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339

Figure 10-24. Interrelationship among the oil density and contents of resins and “benzine” (gasoline).

Dobryanskiy (1948), Bagir-zadeh et al. (1974c), and Leontaritis and Mansoory (1988) have shown that the content of paraffins in the crude oil increases with decreasing density. High-paraffin crude oil contains many light fractions (boiling point up to 150°C) and very small amounts of asphaltenes and resins. On the other hand, the paraffin content in the crude oil which is close in consistency to asphalt is practically equal to zero. Experimental data exists (Gadzhi-Kasumov, 1971; Dzhevanshir et al., 1994) on the content of resins and paraffins in the crude oils of

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Petroleum Geology of the South Caspian Basin

Apsheron oil- and gas-bearing region and the adjacent offshore areas of the Caspian Sea (Table 10-27). The data presented in Table 10-27 and Figure 10-25 show the relationship between the content of paraffins (P) and content of resins (R) in the crude oils. An empirical equation of this relationship is as follows: P = 30/(R – 4)

(76)

Crude Oil Viscosity Relationship between the viscosity and density of crude oil (changing simultaneously with increasing temperature) is considered next. Crude oils from the same fields of Azerbaijan have been investigated. Depth of burial of productive reservoirs varies from 500 to 3,500 m, while the reservoir temperature ranges from 30 to 90°C. Due to the influence of various factors, density of crude oils varies from 0.83 to 0.93 g/cm3. Dynamic viscosity µ and kinematic viscosity ν are related as follows: ν = µ/γ

(77)

where γ is the density of liquid. Table 10-28 shows the dependence of crude oil viscosity on density at five different temperatures: 10, 20, 30, 40, and 50°C. This table is based on 580 analyses. Figure 10-26 shows the dependence of viscosity on temperature. Logarithmic scale was used for viscosity, transforming asymmetric empiric distribution into symmetric one, close to the normal law. This figure shows that viscosity and temperature are related by logarithmic or power law. Interrelationship among kinematic viscosity, density, and temperature is presented in Figure 10-27. This interrelationship is best described by an exponential function: ν = νoexp(–bT)

(78)

where T is the oil temperature in °C, νo is the kinematic oil viscosity in centistokes at T = 0°C, which is equal to: (text continued on page 344)

341

Mathematical Models in Oil and Gas Exploration and Production Table 10-27 Contents of Resins and Paraffins in the Crude Oils from Apsheron Oil- and Gas-Bearing Region Content, wt % Field

Binagady Balakhany-Sabunchi-Ramany Surakhany “ “ Karachukhur “ “ “ Gum Deniz “ Kala Gousany Lokbatan Karadag “ Sangachal-Duvanny Deniz Darvin Bank Pirallaghi Adasi Chalov Adasi Palchygh Pilpilasi Neft Dashlary “ “ “ “ “ “ “ “ “ “ “

Suite or Unit

NKP PK Sabunchi PK KaS Balakhany NKG PK KaS VIII IX KaS KaS NKP VII VIII VII PK PK KaS KaS Sabunchi Balakhany “Pereryv” NKP KS-1 KS-2 PK-1 PK-2 PK-3 KaS-1 KaS-2 KaS-3

Resins

Paraffins

35.0 32.0 16.5 25.6 24.0 17.0 17.0 18.6 21.4 15.8 15.2 36.8 19.8 22.5 16.0 13.0 25.3 45.0 34.0 36.0 37.0 29.3 24.6 21.6 17.7 28.2 22.6 22.4 23.8 23.6 24.7 16.5 24.7

0.20 0.15 2.48 2.07 3.71 16.0 4.95 4.95 4.95 18.6 16.5 2.92 6.33 13.7 19.3 17.5 15.8 0.03 0.13 0.12 0.66 1.72 1.08 0.79 2.50 0.41 0.69 0.58 0.56 0.89 0.64 0.49 0.38

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Petroleum Geology of the South Caspian Basin

Figure 10-25. Relationship between the content of resins and content of paraffins. Table 10-28 Kinematic Viscosity of Crude Oils as Related to Density and Temperature Temperature, °C Average Density, g/cm3

10

20

30

40

50

0.82 0.83 0.84 0.85 0.86 0.87 0.88 0.89 0.90 0.91 0.92 0.93 0.94

5.6 5.6 11.2 14.0 20.5 22.4 39.2 53.0 86.4 118 — — —

4.2 5.6 9.9 12.9 13.7 20.3 23.2 32.6 50.3 94.5 133 356 —

2.8 4.5 5.6 7.9 9.4 12.4 18.3 21.9 30.9 50.5 89.2 178 178

2.8 3.9 5.4 5.8 6.5 10.5 11.7 14.4 22.7 30.2 53.7 111 178

1.4 2.5 4.3 5.2 5.6 7.6 10.3 11.0 15.1 24.1 33.6 55.8 89.2

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Figure 10-26. Statistical distribution (a) and cumulative probability (b) of oil viscosity at five different temperatures (Modified after Buryakovsky and Dzhevanshir, 1992).

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Petroleum Geology of the South Caspian Basin

Figure 10-27. Interrelationship among the kinematic viscosity (ν), oil density (γ) and temperature (Modified after Buryakovsky and Dzhevanshir, 1992).

(text continued from page 340)

νo = aexp(cγ)

(79)

where γ is the crude oil density in g/cm3 and a and c are empirical numerical coefficients, a being the crude oil viscosity when T = 0 and γ = 0. The numerical coefficient b in Equation 78 also depends on the crude oil density according to the following equation:

Mathematical Models in Oil and Gas Exploration and Production b = mγ – n

345

(80)

where m and n are numerical coefficients that can be estimated from the experimental data. Substituting Equations 79 and 80 into Equation 78, one obtains: ν = aexp(cγ – mγT + nT)

(81)

or, after taking logarithms, one can obtain the equation in the following form: lgν = ao + a1γ – a2γT + a3T

(82)

Coefficients ai of Equation 82 are calculated from the data presented in the correlation tables and Figures 10-26 and 10-27. Substituting numerical values of coefficients ai into Equation 82, one obtains: lgν = 16.6γ – 0.100γT + 0.072T – 12.8

(83)

In SI units Equation 83 becomes: lgν = 0.0166γ – 0.0001γT + 0.072T – 12.8

(84)

where γ is in kg/m3, T is in °C, and ν is in m2/sec. Dynamic viscosity, on the other hand, is equal to: µ = aγexp(cγ - mγT + nT)

(85)

Substituting Equation 67 into Equation 81, one obtains an expression relating the kinematic crude oil viscosity to the content of asphaltenes plus resins: ν = a′exp(c′R – m′RT + n′T)

(86)

where a′, c′, m′, and n′ are empirical coefficients. After taking logarithms of Equation 86, one obtains: lgγ = 0.6 + 0.0565R – 0.00034RT – 0.083T

(87)

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Petroleum Geology of the South Caspian Basin

Discussion of Results and Conclusions 1. Empirical equations of interrelationships among composition, parameters of the crude oil, and temperature were derived using the experimental data. These equations are not only of practical value but also of theoretical interest. Equations 83 and 87 provide theoretical correlations among the crude oil parameters and may be used in calculations involving temperature, density, and contents of asphaltenes plus resins and low-boiling fractions. 2. From the practical point of view, extrapolation of graphical or analytical models beyond the limits of the experimental data is interesting. For example, extrapolation of graphs in Figure 1027 or using Equation 83 for temperatures above 50°C enables one to predict the viscosity of crude oils of different densities at temperatures up to 100–120°C (at depths of 5,500–6,000 m). Deposits located in the more bathypelagic parts of the Apsheron– Pre-Balkhan Threshold occur at such depths. These deposits are most likely to contain gas-condensate fluids due to the low viscosity of fluids at reservoir temperatures. 3. In the near-surface rocks (with an average annual temperature of +14.5°C) crude oil is degraded into an asphalt-like material with a density of 1.0–1.1 g/cm3. Similar deposits of bituminous sands are known to occur at outcrops of oil reservoirs in different parts of the world.

CHAPTER 11

Mathematical Modeling of Geological Processes (Dynamic Geological Systems) METHODOLOGY OF SIMULATION OF DYNAMIC SYSTEMS Objects of geological study, i.e., geologic systems, with subsequent technologic impact (e.g., secondary and tertiary recovery) on them, are dynamic systems. They change either in “geologic” or “technologic” time scale. Thus, to develop adequate dynamic models of geologic and technologic processes, it is necessary to introduce time factor. The rather conflicting methodological approaches, such as systemstructural and genetic-historical, are merged in the modeling of the dynamic geologic systems. Merger of the structural and historical approaches in one model treats a geological system as a natural phenomenon which, on one hand, is relatively stable at a certain time stage, and on the other hand, is evolving during a sufficiently extended interval of the geologic time. The necessity to take geologic time into account meets with significant difficulties. This often causes an unwillingness to construct the geologic models when they should reflect the dynamics of geologic phenomena and processes. One of the reasons for this difficulty is the use of absolute and relative geologic time. The difference between them is substantial: the 347

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Petroleum Geology of the South Caspian Basin

absolute time has the beginning common for the entire Earth, which is not an attribute of the relative time scale based on paleontology and stratigraphy. Another reason is the lack of reproducibility of the geologic time in physical and chemical experiments, and practical impossibility to eliminate this obstacle using the similarity method and the dimensional analysis. The time factor is of a special importance for the problems of forecasting. Such problems indeed call for the creation and application of the mathematical models. The successful forecast may depend on the retrospective historical evaluation of the geologic system under study. Two methods in constructing such models may be offered: analytical and statistical. The better approach in modeling such systems is a combination of the mathematical analysis (i.e., differential equations) with the statistical-probabilistic expression of the numerical values for the parameters, causing the change in a dynamic geologic systems. This approach allows to describe in the deterministic way main features in the dynamics of the geologic systems. At the same time, it includes the statistical-probabilistic nature of various geologic parameters which cause the evolution of the systems. The implementation of analytical solution is accomplished using the statistical sampling technique (Monte Carlo method).

Analytical Approach Two important issues must be addressed before constructing analytical models. 1. The important properties of the system under study, as well as those of the surrounding lithosphere, should be defined. These properties should be described by strictly defined quantitative constraints. 2. The limitations assumed in describing these properties should be clearly delineated and should reflect the substance of a particular geologic system. It is natural to choose as the main parameters those properties of the system and of the surrounding rocks that would stimulate or restrain the course of the geologic processes. If a process can be characterized by a single parameter, for instance, the hydrocarbon reserves, this parameter should be used as the main one.

Mathematical Modeling of Geological Processes

349

In the following discussion, the writers use as synonyms the properties of the geologic system and their respective parameters. They may have a dual nature, i.e., they may be either deterministic or stochastic, depending on the formalization approach at each stage of the modeling of a geologic system. Two major assumptions should be made while developing the differential equations of geologic processes. 1. The rate of change in the geologic system, or the speed of the geologic process, is proportional to the state of the system. 2. Influence of various natural factors is proportional to the product of the number (or quantitative estimates) of the events accelerating the process by the number (or quantitative estimates) of the events retarding the process. The first assumption leads to differential equations similar to: dx/dt = ε(t)f(x)

(88)

where x is a variable (quantitatively measured natural factor) describing the evolution of geologic system; ε(t) is a coefficient of proportionality (generally time-dependent); and f(x) is a function of the variable x. In the case of a multi-phase process, a system of Equations 88-type is written jointly. The second assumption puts together a system of differential equations that takes into account the effects of interrelationships among variables: dx1/dt = ε1(t)f1(x1) + γ12(t)f1(x1)f2(x2)

(89)

dx2/dt = ε2(t)f2(x2) + γ21(t)f1(x1)f2(x2)

where x1 and x2 are variables (natural factors) accelerating and retarding the process, respectively; γ12(t) and γ21(t) are interdependency quotients of these variables (or natural factors), which are generally time-dependent. In some particular cases, the factors ε and γ may not be timedependent, i.e., they are constant. In those cases, Equation 88 forms the so-called model of “proportional effects,” or an “organism growth model.”

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Various functions of the affecting parameters can be used in Equations 88 and 89. This creates the necessary diversity in analytical descriptions of the dynamics of the geologic systems. For example, when f(x) = x, the process in Equation 88 is described by the exponential curve; when f(x) = x(a – x), where a = constant, process is described by the logistical curve (S-like or Gompertz curve), etc. The signs of ε and γ quotients in Equations 89 may vary. If the first equation has positive ε1 and negative γ12, then the two sign combinations are possible for the ε2 and γ21 in the second equation. In the case of negative ε2 and positive γ21, the processes of construction and destruction are antagonistic. In the case of positive ε2 and negative γ21, the processes merge into a single process controlled by the same natural factors, and the prevalence of the constructive component over the destructive one depends on the relation between these factors. Depending on the signs of ε and γ, the geologic processes can be stable or unstable in time. The former case is characterized by a point (center) or a convergent spiral on the phase plane in the coordinates (x1, x2). The latter case is characterized by a saddle or a divergent spiral. These models (Equations 88 and 89) are widely used in ecology (Kemeny and Snell, 1972; Volterra, 1976) and can be applied to geology, economics, social domain, etc. Using analytical models (Equations 88 and 89), one can study the evolution of a dynamic system in time. Based on the structure of the lithospheric space-time continuum, it is possible to equate the evolution of the geologic systems in depth to their evolution in the reversed time. In this sense, the geologic forecast is actually a reversed forecast, or “retrocast,” because it is directed backwards (in time) and is directed onwards in depth (in space). Taking into account the specifics of geologic time-space continuum, the analytical models (Equations 88 and 89) forecast the behavior and structure of a geologic system at depths not yet studied through geologic techniques, provided the normal stratigraphic succession of consecutive time intervals.

Statistical Approach The statistical approach, based on the empirical data, is simpler than the analytical one and still sufficiently justified from the viewpoint of lithosphere evolution. It is based on the inference of interconnections

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351

through generalization, analysis, and comparison of the structuralfunctional features of geologic systems at certain discrete moments of the geologic time. Approximation of the discrete (discontinuous) data by a continuous function obtains an empirical equation for a parameter (or a set of parameters) of the geologic object under study as a function of time. As an example, the equation expressing relationship between shale (clay) porosity (and density) and geologic age and taking into account burial depth and lithology, can be presented here (Buryakovsky et al., 1982a, 1990b). The relationship between porosity of shales (clays) and depth of burial was studied by numerous investigators (e.g., Rieke and Chilingarian, 1974). As shown on Figure 11-1, this relationship varies from one area to another. This is because porosity of argillaceous sediments is a complex function of numerous natural factors, often superimposed on each other. These factors include: 11. 12. 13. 14. 15. 16. 17. 18. 19. 10.

geologic age effective stress (total overburden stress minus the pore pressure) lithology mineralogy tectonic stresses speed of deposition of sediments thicknesses of sedimentary formations shape and sorting of grains amount and type of cementing material chemistry of interstitial fluids

This multitude of variables complicates the quantitative evaluation of the influence of individual factors on the porosity of argillaceous sediments. One method of solving this important problem is by establishing dependence of porosity of argillaceous sediments on the most important natural factors, the influence of which considerably overshadows (or incorporates) the influence of other factors. It is also necessary to remember that these predominant factors may have good correlation with each other. Buryakovsky et al. (1982a) studied dependence of shale (clay) porosity on geologic age, depth, and lithology of siliciclastics. They utilized data obtained by Dobrynin (1959, 1970), Vassoevich and

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Figure 11-1. Relationship between porosity and depth of burial for shales and argillaceous sediments. 1—Proshlyakov (1960); 2—Meade (1966); 3—Athy (1930); 4—Hosoi (1963); 5—Hedberg (1936); 6—Dickinson (1953); 7—Magara (1968); 8—Weller (1959); 9—Ham (1966); 10—Foster and Whalen (1966) (Modified after Rieke and Chilingarian, 1974, fig. 17, p. 42).

Bronovitskiy (1962), Weller (1959), Proshlyakov (1974), and Durmishyan (1973) for the shales from different regions. The following formula by Dobrynin (1970), for example, enables quantitative evaluation of the role played by various factors in forming porosity of shale (clay):

Mathematical Modeling of Geological Processes φ = φoexp(–0.014βcD)

353

(90)

where φo is the initial porosity of shale (clay); φ is the porosity of shale (clay) at a depth D (in m); and βc is coefficient of irreversible compaction (MPa–1). Using this formula, the writers plotted a family of straight lines on semilogarithmic paper (Figure 11-2). The actual compaction curves of argillaceous rocks are superimposed on this figure. Inasmuch as the coefficient of irreversible compaction βc (in 10–3, MPa–1) for each one of the straight lines (Equation 90) is known, it is possible to determine graphically its average value for actual curves: Weller (1959) = 58.5; Proshlyakov (1974) and Dobrynin (1970) = 42.8; Vassoyevich and Bronovitskiy (1962) = 33.6; Apsheron Peninsula and Apsheron Archipelago = 42.1; southwestern part of Apsheron Peninsula and northern part of Baku Archipelago = 27.1; and southern part of Baku Archipelago = 19.3. As shown in Equation 90, with the exception of depth, the effects of all other variables are included in the coefficient of irreversible compaction βc. Correlation of this coefficient with geologic age and lithology becomes apparent upon comparison of curves of different geologic age obtained by Weller (1959), Vassoyevich and Bronovitskiy (1962), Dobrynin (1970), Proshlyakov (1974), and Durmishyan (1973) with curves corresponding to deposits of the same geologic age in Azerbaijan, obtained for areas having different lithologies (Figure 11-2). Experimental data obtained by Terzaghi (1961), Dobrynin (1970), Rieke and Chilingarian (1974) and others, indicate that coefficient βc depends on the duration of sample loading. As far as lithology is concerned, extensive investigations by Durmishyan (1973), Rieke and Chilingarian (1974), Fertl (1976), Buryakovsky (1985a), Dzhevanshir et al. (1986) and others, showed that in the areas where argillaceous sediments experience rapid deposition, upward squeezing out of compaction fluids is impeded. This increases the pore fluid pressure, sometimes approaching geostatic, giving rise to the regional, abnormally high formation pressure. With increasing thickness of clay deposits and decreasing number of interstratified porous and permeable rocks (sands), the clay remains more porous (undercompacted) because of greater difficulty of fluid expulsion from clays. Although many other factors influence compaction, geologic age and lithology (ratio of shales to the total thickness of deposits) affect the

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Figure 11-2. Relationship between porosity and depth of burial for various shales. 1—Weller (1959); Aralsor super-deep well SG-1 (USSR); 3—Vassoyevich and Bronovitskiy (1962); 4—Apsheron Peninsula and Archipelago (Azerbaijan); 5–southwestern part of Apsheron and northern part of Baku Archipelago (Azerbaijan); 6—southern part of Baku Archipelago and Lower Kura Depression (Azerbaijan); 7—family of calculated porosity/depth curves (Modified after Buryakovsky et al., 1982a).

complex diagenetic processes occurring in a subsiding basin sediments, with a distinct geothermal gradient. The coefficient of irreversible compaction, βc, is related to the geologic age and lithology as follows: βc = (26.61 logAt – 8.42) • 10–3

(91)

βc = (14.0 – 166.6 logχ) • 10–3

(92)

Mathematical Modeling of Geological Processes

355

where At is the geologic age in millions of years, and χ is a ratio of thickness of clays to the total thickness of siliciclastics. On combining Equations 90, 91 and 92, an equation relating porosity to geologic age, lithology and depth is obtained: φ = φoexp[–0.014(13.3logAt – 83.25logχ + 2.79) • 10–3D]

(93)

where φo is the initial porosity of argillaceous sediments, and D is the depth in meters. A nomograph, presented in Figure 11-3, enables rapid solution of Equation 93. This nomograph was used to test the results obtained by (a) Hedberg (1926) for the Tertiary clays of Venezuela, (b) Stetyukha (1964) for the Tertiary clays of the northeastern part of Pre-Caucasus, and (c) Durmishyan (1973) for the Kala Suite of Apsheron Peninsula and Archipelago. Comparison of data obtained from Figure 11-3 (nomograph) and actual field data is presented in Figure 11-4. The absolute error does not exceed 3%. Relative error gradually increases with increasing absolute value of porosity and, on the average, varies from 5 to 30%. The difference between the calculated values and actual field data is probably because calculated values do not take into consideration all the factors which influence porosity. Nevertheless, Equation 93 gives satisfactory, practically usable results.

MATHEMATICAL SIMULATION OF SEDIMENT COMPACTION Post-sedimentational changes (during the diagenetic and epigenetic stages) of sediments depend on a great number of natural processes (including compaction) which result in the transformation of sediments into rocks. The diagenetic stage of rock transformations includes all physical, chemical and biochemical processes modifying sediments between deposition and lithification at low temperatures and pressures characteristic of surface and near-surface environments. In general, diagenesis is divisible into pre-, syn-, and post-cementation or lithification processes. Diagenesis takes an intermediate position between syngenesis and epigenesis, the former grading into diagenesis by syndiagenesis, and the latter grading into metamorphism. Under unusual conditions, however, diagenesis as defined here may grade directly into

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Petroleum Geology of the South Caspian Basin

Figure 11-3. Nomograph for determination of porosity at a particular depth of burial using geologic age and lithology (ratio of thickness of shales/total thickness of terrigenous complex) as controlling factors. R = χ (Eq. 93).

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357

Figure 11-4. Comparison of actual porosity and that obtained from nomograph (Modified after Buryakovsky et al., 1990b). a (left)—Venezuela; b—PreCaucasus; c (right)—Apsheron Peninsula and Archipelago. 1—Actual porosity, 2—calculated porosity.

metamorphism (see epigenesis). Because reef limestones, and other limestones which are constructed in-situ by organic frame-builders, are largely lithified to a degree, the definition must be expanded for this particular group of limestones to include the interactions between sediments and the fluids contained within them below the temperature and pressure levels of metamorphism sensu stricto, and in a similar sense between fluids and framework, infilled detritus framework, and combinations thereof. The catagenesis (or epigenesis) stage includes all processes at low temperature and pressure that affect sedimentary rocks after diagenesis and up to metamorphism. Epigenesis has been subdivided into juxtaand apo-epigenesis (Wolf, 1963b, 1965c, in: Chilingar et al., 1979, pp. 393, 395). It is possible that under unusual conditions syngenesis and diagenesis grade directly into metamorphism. For example, unconsolidated sediments may be exposed to volcanic high temperatures and metasomatic

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material and undergo metamorphism before diagenesis. Also, sediments partly undergoing cementation may be metamorphosed by shallow intrusions causing an increase of temperature and possibly pressure before epigenesis could occur. As a result of compaction of sediments, a decrease in thickness and in porosity and an increase in the density of sedimentary rocks take place. The most characteristic indicators of the process of sediment compaction are curves of the dependence of rock porosity on the depth of burial. Figure 11-5 shows such curves for sandstones, siltstones, carbonate rocks, and clays (shales), based on data of many experimental investigations: Athy (1930), Hedberg (1926, 1936), Dickinson (1953), Weller (1959), Foster and Whalen (1966), Ham (1966), Meade (1966), Magara (1968), Proshlyakov (1974), Rieke and Chilingarian (1974), Buryakovsky (1985a), and Aleksandrov et al. (1987). Studying the process of compaction of sediments and their transformation into rocks at the present-day scientific and technical level, it is necessary to develop a mathematical description of this process and to construct a mathematical model capable of describing the compaction process. One should be able to reconstruct the history of the formation of the original sediments and to predict their properties in regions and at depths that are not sufficiently studied by direct geological and geophysical methods.

Previous Investigations The problem of mathematical description of the process of sediment compaction is considered to be rather complicated due to both a great number of parameters affecting the consolidation of sediments and to the lack of quantitative information about the behavior of these parameters at different stages of consolidation of sediments and sedimentary rocks. In most cases, a researcher is forced (1) to work with data on the already-formed formation and (2) to rely on the available data on the dependence of degree of consolidation on the depth of burial (e.g., see Figure 11-5). Another source of information is experimental investigation of rocks at conditions simulating reservoir conditions, i.e., at high pressures and temperatures, corresponding to the depth of burial of formation being studied. Nevertheless, a combination of this data plus information obtained by geophysical and geochemical investigations of the upper

Mathematical Modeling of Geological Processes

359

Figure 11-5. Relationship between porosity and depth of burial for various types of sediments and rocks (Modified after Buryakovsky et al., 1990b). (a) Sandstones, and (b) siltstones (after Buryakovsky, 1985); deposits of the northwestern boundary of the South Caspian Dpression: 1—Dzhanub, 2—Zyrya, 3—Surakhany, 4—Karachukhur, 5—Zykh, 6—Gum Deniz, 7—Gousany, 8— Bukhta Il’icha, 9—Patamdar, 10—Karadag, 11—Padar, 12—Kyurovdag, 13— Karabagly, 14—Kalmas. (c) Carbonates (after Aleksandrov et al., 1987); Regions: 1—Scythian Plate, Upper Cretaceous limestones; 2—Western Kuban Trough, Upper Devonian limestones; 4–8—Southern Florida, Cenozoic and Mesozoic carbonates: 4—average, 5—Eocene, 6—Paleocene, 7—limestone, 8—dolomite, 9–10—deepwater carbonate mud, 11–12—chalk. (d) Argillaceous sediments and rocks (after Rieke and Chilingarian, 1974): 1—Proshlyakov; 2—Meade; 3—Athy; 4—Hosoi; 5—Hedberg; 6—Dickinson; 7—Magara; 8— Weller; 9—Ham; 10—Foster and Whalen.

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layers of the lithosphere enables one to start solving the problem of a mathematical simulation of the consolidation process of sedimentary rocks. Many attempts were made to construct a mathematical model. Some of them dealt with such properties of sediments and compacting rocks as elasticity, plasticity, viscoelasticity, thixotropy, etc., that are rather variable depending on the type of sediment. Various differential equations were analytically derived, which enabled one to describe the processes of rock changes in a space-time continuum of upper layers of lithosphere. For example, R. Berner (1971, see Chilingarian and Rieke, 1976, p. 59) suggested a differential equation to evaluate the rate of sediment compaction (as a change in porosity) as follows: dφ/dt = (Rd /γma)[1/(1 – φ)](dφ/dD)t

(94)

where φ is the porosity (fraction); D is the depth of burial; Rd is the rate of sedimentation (weight of a sediment per unit of area per year); γma is the density of solid phase (matrix) of formation; and t is the duration of compaction. The (dφ/dD) term can be determined from depth-versus-porosity curves (e.g., see Figure 11-5). On the basis of a joint solution of the Darcy and material balance equations, Buryakovsky and Dzhevanshir (1976a) obtained the following model of clay compaction: φ = φo - [4(1 – φo)KDt]/h2

(95)

where K is the filtration coefficient; D is the depth; h is the thickness of a compacting clay layer; and t is the duration of compaction. This model is helpful in determining the sealing properties of the clay caprocks in different regions of Azerbaijan (i.e., the central and southwestern portions of Apsheron Peninsula; the northern and southern portions of Baku Archipelago; and the Lower Kura Depression). In order to compare Pliocene formations with the more ancient ones, the sealing properties of caprocks of Mesozoic age in the West Siberian lowland and rocks of Devonian age in the Volga-Urals oil and gas province were evaluated. As mentioned above, the application of differential and other analytical equations is not the only mathematical method to account for time when simulating geological systems. An empirical approach is simpler and sufficiently reliable when used for the history of the development

Mathematical Modeling of Geological Processes

361

of the upper part of lithosphere. It is based on a comparison between consolidation curves (Figure 11-5) of rocks of different ages and on the approximation of discrete age data by a continuous function. Equation 93 may be given as an example of dependence of shale porosity on the geologic age, taking into account the depth of burial and lithology of rocks studied. Many equations were obtained on the basis of experimental investigations of rocks at high pressures and temperatures (Dobrynin, 1970; Pavlova, 1975). One of the limitations in using these models for regional lithological studies is that they are all able to consider only elastic deformation of sediments and rocks occurring as a result of the compaction process under the pressure of overburden (thickness of the overlying sediments). Using such models, it is impossible to take into account irreversible deformations resulting from other processes of diagenesis and catagenesis. Additionally, a geologic time factor is not present in these models, i.e., the models cannot be related as dynamic models, which does not correspond to the systems approach to the problem of prediction of properties of rocks.

Compaction of Terrigenous (Siliciclastic) Rocks The rate of compaction of terrigenous sediments depends on the lithology, rate of sedimentation, and tectonic regime of the sedimentation basin. Compaction of sandy-silty and clayey sediments takes place at different rates and differs from compaction of carbonate and evaporite deposits. One of the most important properties determining the degree of compaction of sediments is the ease of release (expulsion) of interstitial waters: sand gives up pore waters easier than clay. The presence of thick strata of water-saturated clays in a sedimentary section retards the compaction. A rapid rate of sedimentation also retards the compaction process. Conversely, intensive tectonic activity may result in rapid lithification. Generally, the rate of sedimentation is determined by the rate of tectonic movements and depends on the interrelationships among the rate of influx of sedimentary material, washout of sediments, and the rate of subsidence of the basin floor [or uplift of the onshore area (mainland)]. Geosynclines are characterized by a rate of sedimentation of approximately 100–200 meters per million years, whereas platforms have a rate of 20–30 meters per million years. Taking into account a

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simultaneous process of consolidation of sediments, the rate of their accumulation in subsiding areas (depressed zones) may be ten times higher. An attempt was made by Buryakovsky et al. (1982a) to describe systematically the process of sediment compaction. The curves showing changes in the porosity with depth may be described by the socalled “organism-growth model,” equivalent to the “model of proportional effects.” The difference between the “model of organism growth” and the “model of proportional effects” is as follows: the former is based on the equality of the rate of change of parameter y of some process to the value of this parameter reached at a certain moment of time t, i.e., dy/dt = cy,

(96)

which leads to an exponential dependence of the parameter y on time t: y = yoect

(97)

where c is the factor of proportionality. The second model is derived from the equality of absolute change of the parameter y to the value of this parameter reached at a certain moment of time, i.e., dy/dc = cy

(98)

resulting in an exponential dependence of the parameter y on the factor of proportionality c: y = yoe c

(99)

If the process is affected by the sum of different factors, then the equation becomes:  n  y = yo exp ∑ ci   i =1 

(100)

This model can be transformed into a multiplicative model: n

y = yo ∏ X i i =1

(101)

Mathematical Modeling of Geological Processes

363

n

where Xi = exp(ci ), and ∏ Xi is a generalized measure of the change i =1 in parameter y. Based on the principle of equality of the degree of evolution of the compaction process to the obtained value of some parameter characterizing this process, the writers obtained a number of models: (a) Model of the degree of sediment compaction (compaction model of K. Terzaghi, 1961): Ut = 1 – ht/ho = 1 – {[hminexp(chhmint)]/[hmin – ho(1 – exp(chhmint))]}

(102)

where ho, ht, and hmin are thicknesses of the layer before compaction, at time t, and for the completely compacted rock (lowest, minimum value), respectively; ch is the factor of proportionality. (b) Model of density change: γt = [γoγmaxexp(cγγmaxt)]/[γmax – γo(1 – exp(cγγmaxt))]

(103)

where γo, γt, and γmax are rock densities before compaction, at time t, and the highest value for the completely compacted rock, respectively; cγ is the factor of proportionality. (c) Model of porosity change: φt = [φoexp(–cφt)]/[1 – φo(1 – exp(–cφt))]

(104)

where φo, and φt are porosities before and during the process of compaction of sediments and rocks; and cφ is the factor of proportionality. Models based on Equation 101 were widely used in predicting reservoir rock properties and physical properties of terrigenous rocks at different geological and physical conditions of the South Caspian Basin, Daghestan Plain, and the Middle Caspian Basin at depths of 6–9 km. Many examples are given by Buryakovsky et al. (1982a, 1990b).

Compaction of Carbonate Rocks There are a number of major differences between the compaction of terrigenous and carbonate rocks, with the early lithification of carbonates. Most researchers (Proshlyakov, 1974; Pavlova, 1975; Bagrintseva, 1977; Chilingarian et al., 1979; and Chilingarian et al., 1995) consider the changes in the carbonate rock properties, including those due to burial, to be caused by different physicochemical processes

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occurring in the pore space of sediments and rocks. In this case, influence of gravitational compaction plays a secondary role. Other researchers (Dobrynin, 1970; Bezborodova, 1977; and Aleksandrov, 1987) consider the geostatic load to be the main factor affecting the compaction of carbonates, i.e., the effective pressure, which is equal to the difference between the total overburden load and the pore (reservoir) pressure. According to these authors, secondary processes change sediments and rocks only locally, distorting general regularities of their compaction with depth. This is particularly true in the case of compaction of chalks. The problem lies in the retention and development of secondary porosity, e.g., solution porosity (vugs, etc.) and porosity created by dolomitization. The initial porosity of carbonates often approaches that of sandstones in that their structure consists of aggregates of oolites, grains, and crystals, whereas the sandstones are granular. Carbonates also have a more heterogeneous pore structure. The initial (primary) porosity of carbonates depends on their genetic type to a great extent: it is the largest in biogenetic, biomorphic and clastic (detrital) varieties, whereas it is considerably lower in cloddy and the chemogenic ones (excluding chemogenic oolitic limestones). According to the data of Aksenov et al. (1986), values of maximum porosity of carbonate rocks considering structural-genetic types are: biogenetic rocks—24% and seldom 26%; biogenetic-detrital—24% and seldom 34%; clottedcloddy—13% and seldom 17%; crystalline-granular—4% and seldom 6%; pelitomorphic—2% and seldom 6%; and oolitic and pisolitic— 24% and seldom 34%. As in the case of terrigenous rocks, carbonate rocks which had higher initial porosities, underwent the most intensive epigenetic changes. It should be noted that lithification of carbonate rocks takes place much faster than that of sandstones and siltstones. This results in an earlier completion of the process of mechanical compaction. More than 30 different processes, which are controlled both by local and regional factors, occur during the diagenesis and catagenesis (Larsen and Chilingar, 1983). Lithification of carbonate sediments is of biochemical, physicochemical, and mechanical nature. To some degree these processes occur simultaneously and change both composition and pore geometry of sediments. With time, their rates are reduced. An essential difference between mechanical and biochemical-physicochemical processes is that the former acts in one direction with results

Mathematical Modeling of Geological Processes

365

being irreversible. Biochemical and physicochemical processes, on the other hand, can take place in different directions; thus, increase and decrease in secondary porosity of carbonate rocks can occur periodically depending on the environmental conditions. For example, diagenetic dolomitization may give rise to 13% porosity, which can be later destroyed by cementation or enhanced by dissolution. Inasmuch as the mechanical processes are unidirectional and usually irreversible, possibly they play a major role in changing the original (primary) porosity of carbonate rocks. Thus, there is similarity with compaction of terrigenous rocks. The process of compaction in carbonates is quite different depending on the structural-genetic type of carbonate. Degree of consolidation, dissolution and cementation under the influence of geostatic pressure are all important. Increase of geostatic load as a result of subsidence of sediments leads to the solution of crystals under pressure, i.e., differential solution takes place in more strained parts of grains with a subsequent deposition of material on the surfaces having lower potential energy. In addition, grains (and crystals) may get flatter parallel to the surface of stratification. These processes decrease the initial porosity both in carbonate and terrigenous rocks.

NUMERICAL SIMULATION OF OIL- AND GAS-BEARING ROCK PROPERTIES Methodology of Numerical Simulation The modeling of physical properties of rocks for predicting these properties in the unexplored areas, in general, and at great depth, in particular, indeed is important (Krumbein and Graybill, 1969; Harbaugh and Bonhem-Carter, 1974; Griffiths, 1981; Merriam, 1981; Magara, 1982; Buryakovsky et al., 1982a, 1990b, 1991b; Buryakovsky, 1992). The main factor of post-sedimentational changes of any deposit is the compaction under the pressure of overlying strata, resulting in the continuous decrease of the initial porosity of sediments and rocks with depth. Figure 11-5 shows the dependence of porosity of terrigenous and carbonate sediments and rocks on the depth of burial as obtained by different investigators. As shown in Figure 11-5, curves for all rocks of various composition may be described by an exponent; this

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indicates similarity in the process of consolidation of sediments of various origins. All this suggests a single concept for the solution of the problem of mathematical simulation of the processes of compaction and lithification of sedimentary rocks (Buryakovsky, 1993a). In general, the problem of simulation of the process of sedimentary rock compaction for prediction of the physical properties of rocks may be solved by using three assumptions and their implication: 1. The process of post-sedimentational changes and consolidation of sediments is affected by many natural factors. 2. The effect of each factor is unique and differs from those of other factors. 3. The final result is the sum of individual influences of all natural factors on sediments during their transformation into rocks. Thus, assumptions (1) and (2) indicate that individual influences of any factor on the overall result of consolidation are small and are inversely proportional to the number of factors. Assumption (2) indicates that the influence of each factor is not equal to that of others. The above discussion allows one to reach the following conclusions: (1) Small influences of each i-th factor resulting in a relative change in the volume of consolidating sediments (U) can be represented as dUi /Ui , whereas the cumulative influences of all the factors can be repre-sented by ∫dUi /Ui. This expression is somewhat analogous to Hooke’s law: dUi /Ui = –βσ where β = modulus of elasticity and σ = acting stress. If βσ is understood not only as the effect of static load, but also as the influence of any i-th factor, one would obtain: U

∫

n

dUi / Ui = ∑ ci i =1

Uo

(105)

where ci is the influence of i-th factor. Hence, one can derive the following equations:  n  U = Uo exp ∑ ci   i =1 

(106)

and n

U = Uo ∏ xi i =1

(107)

Mathematical Modeling of Geological Processes

367

n

where xi = exp(ci), and ∏ xi is a generalized measure of a change in i =1 parameter U. (2) Differences in the physicogeological nature of factors require that those affecting rock consolidation be presented in the form of relative dimesionless values that also correspond to a formal type of individual influence dUi /Ui. The influence of the i-th factor (dUi /Ui ~ ci) is evaluated (a) from the results of direct laboratory measurements on cores (reproduction of Hooke’s law), (b) by using analogies when direct physical simulation is impossible, or (c) by actual field observations and measurements. Based on the above conclusions, a multi-variable model was proposed for evaluation of the degree of compaction and diagenetic changes of sediments after their deposition in the sedimentary basin. The general form of this model is: n

U t = Uo ∏ xi i =1

(108)

where Uo is the degree of the initial compaction of sediments and Ut is the degree of compaction at a given depth and at a certain geologic time t; and xi is the modeling coefficient. In selecting the modeling coefficients, one must consider: (1) conditions of accumulation of terrigenous and carbonate sediments, (2) their post-sedimentary changes (diagenesis and catagenesis or epigenesis), and (3) the structural evolution of the region. One should recognize the role of different factors, such as: external (pressure, temperature, etc.) and internal (lithology, mineralogic composition, cementation, etc.). The characteristic features of coefficients xi is their independence, which is a necessary condition for the model (Equation 108). Numerical values of coefficients xi corresponding to the factors ci are given in Table 11-1. Their evaluation is carried out according to the initial data of experimental and field studies (Dobrynin, 1970; Pavlova, 1975; Bagrintseva, 1977) using concept of the fuzzy sets theory (Buryakovsky and Kuzmina-Gerasimova, 1982b). Modeling coefficients take into account the influence of major geological (natural) factors on compaction and other diagenetic changes of rocks (Buryakovsky et al., 1981, 1982a, 1990b). These factors are as follows: (1) geologic age (in million years—my), (2) number of

Absolute geological age, 0 At , my Dynamic deformation, N, 0.73 tectonic-strat. unit Depth of burial, D, km 0 Formation temperature, T, °C 0 Rate of sedimentation, Rd, m/my 20 Content of quartz in sandstones, 100 Q, wt % Content of smectites in clays, 0 M, wt % Cementation index, C, wt % 0 Sorting of sandstones, Sss 1 Sorting of shales, Ssh — Homogeneity of carbonates, Scr 0

Factor

0

100 1.00 1.2 40 50 80 10 6 3 9 2

0.85 0.6 20 30 90 5 3 2 10 1

0.2

50

0.1 0.4 0.5 0.6 0.7

9 4 8 3

15

1.8 60 80 70

1.17

150

12 5 7 4

20

2.4 80 100 60

1.37

200

15 6 6 5

25

3.0 100 200 50

1.60

250

18 7 5 6

30

3.6 120 300 40

1.88

300

21 8 4 7

35

4.2 140 500 30

2.20

350

Scales of Absolute Values of Factors

0.3

Normalized Scale, TI

Table 11-1 Numerical Values of Factors Determining the Degree of Compaction

24 9 3 8

40

4.8 160 800 20

2.58

400

0.8

27 10 2 9

45

5.4 180 1000 10

3.01

450

0.9

30 — 1 10

50

6.0 200 2000 0

3.53

500

1.0

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tectonic (orogenic) cycles (in dimensionless tectonic—stratigraphic units), (3) depth of burial (in kilometers), (4) temperature (in °C), (5) rate of sedimentation (in meters per million years), (6) content of quartz in sandstones (in wt %), (7) content of smectites (montmorillonite) in shales (in wt %), (8) degree of cementation (content of CaCO3 in wt %), (9) sorting coefficient of Trask, and (10) degree of homogeneity of carbonate rocks (dimensionless). Ranges in the absolute values of natural factors are shown in Table 11-1. Scales of absolute values of natural factors are presented in this table. Model (Equation 108) requires a normalized form of natural factors. Normalization equations for natural factors are shown in Table 11-2. These equations, which relate the absolute and the normalized scales, were obtained from data in Table 11-1. The number of natural factors used in Equation 108 varies depending on the type of rocks. The degree of influence of a particular factor is also different for each type of rocks. There are three types of natural factors with a different degree of influence on rocks: strong, moderate, and weak.

Table 11-2 Equations of Normalization Factor

Absolute geological age, At , my Dynamic deformation, N, tectonic-stratigraphic units Depth of burial, D, kilometers Formation temperature, T, oC Rate of sedimentation, Rd , m/my Content of quartz in sandstones, Q, wt % Content of smectites in clays, M, wt % Cementation index, C, wt % Sorting coefficient of sandstones, Sss Sorting coefficient of shales, Ssh Homogeneity of carbonates, Scr

Equation of Normalization

TA = 0.002At TN = 0.2 + 1.46logN TD = 0.167D Tt = 0.005T TR = 0.5(logRd – 1.3) TQ = 1 – 0.01Q TM = 0.02M TC = 0.033C Tss = 0.1(Sss – 1) Tsh = 0.1(11 – Ssh) Tcr = 0.1Scr

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The “strong” factors affecting the compaction of sandstones are geologic age and depth of burial. The factors of “moderate” influence are: the number of tectonic cycles (epochs), quartz content, and degree of cementation (CaCO3 content). The “weak” factors are: rate of sedimentation, sorting coefficient of Trask, and temperature. Thus, eight natural factors affect compaction of sandstones. Five natural factors affect the compaction of carbonate rocks. The “strong” factors are: geologic age, the number of tectonic cycles, depth of burial, and temperature. The “moderate” factors are the degree of heterogeneity and degree of cementation. For shales, there are eight natural factors. The “strong” factors are: geological age, depth of burial, and rate of sedimentation. The “moderate” factors are: the number of tectonic cycles, content of smectites (montmorillonite), and degree of cementation. The “weak” factors are: the sorting coefficient and temperature. Modeling coefficients are calculated using the following equation: xi = exp(–ajTi )

(109)

where aj is the coefficient of influence of normalized value Ti of any natural factor on the various rock properties xi (Table 11-3). Coefficients aj were obtained by examining numerous experimental data (Buryakovsky et al., 1982a; Chilingar, Bissell, and Wolf, 1979). Using modeling coefficients, one can calculate the Z factor: n

Z = Ut / U o = ∏ x i

(110)

i =1

The Z factor characterizes the relative degree of compaction and other diagenetic changes of sediments, i.e., the relative degree of rock Table 11-3 Coefficient aj Degree of Influence of Natural Factors Rock Type

Strong

Moderate

Weak

Reservoir Rocks Caprocks

0.968 2.996

0.714 1.833

0.511 1.309

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371

consolidation. This factor is used for calculation of rock properties using the following equations (Buryakovsky, 1993a): Porosity

φ = φo Z 1

(111) 4

Permeability

k = ko(Z1)

Density

γ = γma(1 – φoZ1)

112) (113)

where φo and ko are, respectively, the initial values of porosity and permeability before compaction of sediments; γma is the density of matrix of consolidated rocks, and Z1 is equal to: n n    Z1 = ∏ xi / 1 – φ o 1 – ∏ xi   = Z / [1 – φ o (1 – Z )]     i =1 i =1

(114)

Z1 is the relative change in porosity: φ/φo.

Calculation Technique The technique of numerical simulation of the rock properties is computerized (Buryakovsky and Kuzmina-Gerasimova, 1982a, 1983; Buryakovsky, 1993a). The Monte Carlo method was used in calculations using probable database intervals as an input. Thus, one can obtain statistical characteristics and histograms of rock properties. The algorithm of solution is presented in Figure 11-6. The main blocks shown in the flowchart in Figure 11-6 are as follows: Block 1: Input of initial information. Block 2: Selection of rock type, using the following keys: KE = 1 for sandstones, KE = 2 for carbonate rocks, KE = 3 for shales. Block 3: Input of minimum CA(i ) and maximum CB(i ) absolute values of numerical quantities of natural factors for each type of rocks. All factors are shown in Table 11-1 in the form of absolute scales. In addition, this block provides for an input of probable intervals of initial porosity and permeability values, and probable matrix density intervals for each rock type. Block 4: Calculation of normalized T values of natural factors in the limit of [0; 1], in the form of minimum T(2i – 1) and maximum T(2i) values, according to the equations of normalization in Table 11-2. Block 5: Calculation of the modeling coefficients xi in the limit of [0; 1] in the form of minimum C1(i) and maximum C3(i) values for

Figure 11-6. Procedure for the reservoir-rock property simulation.

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“strong,” “moderate,” and “weak” factors using Equation 109 and Table 11-3. Block 6: Calculation of average values of the modeling coefficients using equation C2(i) = [C1(i) + C3(i)]/2. Block 7: Creation of the file of random numbers by standard subroutine. Block 8: Simulation of parameters xi, φo, ko, γma by Monte Carlo method in the form of triangle distribution of random values. Block 9: Simulation of relative degree Z of rock compaction according to Equation 110. Block 10: Calculation of value Z1 using Equation 114. Block 11: Porosity simulation according to Equation 111. Block 12: Permeability simulation of sandstones according to Equation 112. Block 13: Density simulation according to the Equation 113. Block 14: Printing out of statistical characteristics of distributions of rock properties: average value, standard deviation, variance, minimum and maximum values, and also the data to plot histograms and cumulative curves either in absolute frequencies or in relative frequencies. The above described block-diagram was used to create a program in BASIC for numerical simulation of petrophysical parameters of rocks (see Buryakovsky, 1993a).

Examples of Numerical Simulation As examples of numerical simulation of petrophysical properties of rocks, the following formations were used: (a) Mesozoic terrigenous and carbonate reservoir rocks and shales in the East Pre-Caucasus oiland gas-bearing province and in the adjacent offshore areas of the Middle Caspian Basin, and (b) Neogenic sandstones in the Apsheron oil- and gas-bearing region and in the adjacent offshore areas of the South Caspian Basin. The method and software for numerical simulation of petrophysical properties of rocks can be applied to any geologic and stratigraphic attributes independent of the age and post-sedimentary changes of the rocks. A. The Numerical Simulation of Reservoir A. Properties of Mesozoic Sandstones Model Input. Geological age: 140–190 my; dynamic deformation: 1.8–2.2 tectonic-stratigraphic units (dimensionless); depth of burial:

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2.0–2.5 km; formation temperature: 85-95°C; rate of sedimentation: 100–200 m/my; quartz content: 60-80%; degree of cementation: 12– 18%; Trask sorting coefficient: 3–4; initial porosity before compaction: 0.35–0.45; initial permeability before compaction: 1,000–2,000 mD; and density of rock matrix: 2.6–2.7 g/cm3. Model Output: 1. Simulation of porosity Statistical Distribution Range in Porosity, Fraction Minimum

Maximum

Frequency

Relative Frequency

0.118 0.130 0.142 0.154 0.167 0.179

0.130 0.142 0.154 0.167 0.179 0.191

34 106 109 43 6 2

0.113 0.354 0.363 0.143 0.020 0.007

Cumulative Relative Frequency

0.113 0.467 0.830 0.973 0.993 1.000

Porosity distribution: mean = 0.144; minimum = 0.118; maximum = 0.191; standard deviation = 0.0117; and variance = 8.13%. 2. Simulation of permeability Statistical Distribution Range in Permeability, mD Minimum

Maximum

Frequency

Relative Frequency

11.422 18.402 25.382 32.362 39.342 46.322

18.402 25.382 32.362 39.342 46.322 53.302

25 138 105 27 3 2

0.083 0.460 0.350 0.090 0.010 0.007

Cumulative Relative Frequency

0.083 0.543 0.893 0.983 0.993 1.000

Permeability distribution: mean = 25.39 mD; minimum = 11.42 mD; maximum = 53.30 mD; standard deviation = 5.84 mD; and variance = 22.99%.

Mathematical Modeling of Geological Processes

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3. Simulation of density Statistical Distribution Range in Bulk Density, g/cm3 Minimum

Maximum

Frequency

Relative Frequency

2.166 2.200 2.233 2.267 2.301 2.334

2.200 2.233 2.267 2.301 2.334 2.368

11 39 88 100 48 14

0.037 0.130 0.293 0.333 0.160 0.047

Cumulative Relative Frequency

0.037 0.167 0.460 0.793 0.953 1.000

Bulk density distribution: mean = 2.270 g/cm3; minimum = 2.166 g/cm3; maximum = 2.368 g/cm3; standard deviation = 0.0378 g/cm3; and variance = 1.67%. B. The Numerical Simulation of the Mesozoic Carbonate Rock Properties Model Input. Geological age: 140–190 my; dynamic deformation: 1.8–2.2 tectonic-stratigraphic units; depth of burial: 2.0–2.5 km; formation temperature: 85–95°C; homogeneity of rocks: 0.7–0.9; initial porosity before compaction: 0.35–0.45; and density of rock matrix: 2.67–2.75 g/cm3. Model Output 1. Simulation of porosity Statistical Distribution Range in Porosity, Fraction Minimum

Maximum

Frequency

Relative Frequency

0.109 0.119 0.128 0.137 0.147 0.156

0.119 0.128 0.137 0.146 0.156 0.165

27 89 85 63 28 8

0.090 0.297 0.283 0.210 0.093 0.027

Cumulative Relative Frequency

0.090 0.387 0.670 0.880 0.973 1.000

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Petroleum Geology of the South Caspian Basin

Porosity distribution: mean = 0.132; minimum = 0.109; maximum = 0.165; standard deviation = 0.01092; and variance = 8.25%. 2. Simulation of density Statistical Distribution Range in Bulk Density, g/cm3 Minimum

Maximum

Frequency

Relative Frequency

2.296 2.322 2.348 2.375 2.401 2.427

2.322 2.348 2.375 2.401 2.427 2.453

9 27 79 85 65 35

0.030 0.090 0.263 0.283 0.217 0.117

Cumulative Relative Frequency

0.030 0.120 0.383 0.667 0.883 1.000

Density distribution: mean = 2.385 g/cm3; minimum = 2.296 g/cm3; maximum = 2.453 g/cm3; standard deviation = 0.0326 g/cm3; and variance = 1.37%. C. The Numerical Simulation of the Mesozoic Shale Properties Model Input. Geological age: 140–190 my; dynamic deformation: 1.8–2.2 tectonic-stratigraphic units; depth of burial: 2.0–2.5 km; formation temperature: 85–95°C; rate of sedimentation: 100–200 m/ my; content of smectites: 30–40%; degree of cementation: 10–12%; Trask sorting coefficient: 3–4; initial porosity before compaction: 0.45– 0.55; and density of rock matrix: 2.6–2.7 g/cm3. Model Output 1. Simulation of porosity Statistical Distribution Range in Porosity, Fraction Minimum

Maximum

Frequency

Relative Frequency

0.097 0.118

0.118 0.138

21 70

0.070 0.233

Cumulative Relative Frequency

0.070 0.303

Mathematical Modeling of Geological Processes

0.130 0.159 0.180 0.201

0.159 0.180 0.201 0.222

102 74 27 6

0.340 0.247 0.090 0.020

377

0.643 0.890 0.980 1.000

Porosity distribution: mean = 0.151; minimum = 0.097; maximum = 0.222; standard deviation = 0.0226; and variance = 14.97%. 2. Simulation of density Statistical Distribution Range in Bulk Density, g/cm3 Minimum

Maximum

Frequency

Relative Frequency

2.082 2.139 2.195 2.252 2.309 2.365

2.139 2.195 2.252 2.309 2.365 2.422

11 43 103 95 36 12

0.037 0.143 0.343 0.317 0.120 0.040

Cumulative Relative Frequency

0.037 0.180 0.523 0.840 0.960 1.000

Density distribution: mean = 2.251 g/cm3; minimum = 2.082 g/cm3; maximum = 2.422 g/cm3; standard deviation = 0.06197 g/cm3; and variance = 2.75%. D. The Numerical Simulation of Reservoir Properties of D. Neogene Sandstones Model Input. Geological age: 10–12 my; dynamic deformation: 1.1–1.2 tectonic-stratigraphic units; depth of burial: 2.0–2.5 km; formation temperature: 85–95°C; rate of sedimentation: 500-800 m/ my; quartz content: 60-80%; degree of cementation: 10–15%; Trask sorting coefficient: 3–4; initial porosity before compaction: 0.35–0.45; initial permeability before compaction: 2,000–3,000 mD; and density of rock matrix: 2.6–2.7 g/cm3.

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Petroleum Geology of the South Caspian Basin

Model Output 1. Simulation of porosity Statistical Distribution Range in Porosity, Fraction Minimum

Maximum

Frequency

Relative Frequency

0.225 0.243 0.261 0.278 0.296 0.313

0.243 0.261 0.278 0.296 0.313 0.331

30 87 113 57 11 2

0.100 0.290 0.377 0.190 0.037 0.007

Cumulative Relative Frequency

0.100 0.390 0.767 0.957 0.993 1.000

Porosity distribution: mean = 0.266; minimum = 0.225; maximum = 0.331; standard deviation = 0.0176; and variance = 6.61%. 2. Simulation of permeability Statistical Distribution Range in Permeability, mD Minimum

299.21 372.45 446.28 519.81 593.35 666.88

Maximum

372.45 446.28 519.81 593.35 666.88 740.42

Frequency

Relative Frequency

Cumulative Relative Frequency

10 72 116 75 23 4

0.033 0.240 0.387 0.250 0.077 0.013

0.033 0.273 0.660 0.910 0.987 1.000

Permeability distribution: mean = 492.30 mD; minimum = 299.21 mD; maximum = 740.42 mD; standard deviation = 72.00 mD; and variance = 14.62%.

Mathematical Modeling of Geological Processes

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3. Simulation of density Statistical Distribution Range in Bulk Density, g/cm3 Minimum

Maximum

Frequency

Relative Frequency

1.792 1.839 1.886 1.933 1.980 2.027

1.839 1.886 1.933 1.980 2.027 2.074

3 35 88 92 62 20

0.010 0.117 0.293 0.307 0.207 0.067

Cumulative Relative Frequency

0.010 0.127 0.420 0.727 0.933 1.000

Density distribution: mean = 1.946 g/cm3; minimum = 1.792 g/cm3; maximum = 2.074 g/cm3; standard deviation = 0.0509 g/cm3; and variance = 2.62%.

Discussion of Results and Conclusions The results of the numerical simulation show that the modeling coefficients xi represent adequately the influence of many geological factors on the petrophysical properties of rocks (Figure 11-7). Thus, the results of numerical simulation show that there is a significant difference between the reservoir properties of Mesozoic and Neogene rocks (Figures 11-8 and 11-9). Geological time is the main factor determining the degree of rock compaction: porosity of Mesozoic sandstone is about two times lower than that of Neogene sandstone (Figure 11-8a). Permeability of Mesozoic sandstone is twenty times lower than that of Neogene sandstone (Figure 11-8c), as indicated by tabulated data of example 1 versus example 4. These results are in agreement with the data cited by many researchers (e.g., Magara, 1982; Larsen and Chilingar, 1983). Comparison of the results obtained by simulation of the clastic reservoir rock properties (sandstones) with those of the carbonate rocks shows that carbonate rocks become compacted and consolidated faster than sandstones. This is obvious from the results of examples 1 and 2 (Figures 11-8 and 11-9). These results are in agreement with

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Petroleum Geology of the South Caspian Basin

Figure 11-7. Results of numerical simulation of Mesozoic reservoir-rock properties (Modified after Buryakovsky, 1993a). a—Porosity, b—permeability, c—density. 1—Average curve, 2—confidence limits.

those obtained by many investigators (e.g., Chilingar et al., 1979; Larsen and Chilingar, 1983). The results of numerical simulation presented in examples 1 and 3 (Figures 11-8 and 11-9) indicate that clays become compacted and consolidated faster than sands. Extensive data on compaction of clays and sands were provided by Chilingarian and Rieke (1972); Rieke and Chilingarian (1974); Magara (1982); and Larsen and Chilingar (1983). The results of the numerical simulation indicate that statistical distributions of porosity and density obey the normal law (Figure 118a,b), whereas the distribution of permeability obey the log-normal law (Figures 11-8c). These results are in agreement with those of Harbaugh and Bonham-Carter (1974) and Buryakovsky et al. (1982a). A multi-variable model of lithification (compaction and other diagenetic changes) of both terrigenous and carbonate sediments into rocks was constructed. This model is an integral part of models for

Mathematical Modeling of Geological Processes

381

Figure 11-8. Statistical distribution of petrophysical properties of rocks (Modified after Buryakovsky, 1993a). a—Porosity, b—density, c—permeability. Mesozoic rocks: 1—sandstone, 2—carbonates, 3—shale; Cenozoic rocks: 4—sandstone. ω—frequency.

the properties of oil- and gas-bearing rocks, such as porosity, permeability and bulk density. The relationships between absolute and normalized values of geologic factors were established on the basis of experimental and field data. The models for the evaluation of both reservoir rock and caprock properties were proposed.

Figure 11-9. Cumulative probability curves for petrophysical properties of rocks (Modified after Buryakovsky, 1993a). a—Porosity, b—density. Mesozoic rocks: 1—sandstone, 2—carbonates, 3—shale; Cenozoic rocks: 4—sandstone.

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383

Software was developed for calculation of rock properties. The proposed models and computer program allow one to obtain both the reservoir rock and caprock properties at reservoir temperature and pressure. The proposed method of numerical simulation of oiland gas-bearing rock properties was verified by numerous examples provided.

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CHAPTER 12

Other Applications of Numerical Simulation Methodology BASIC PRINCIPLES AND CALCULATION TECHNIQUES With increasing depth of exploration, one of the major problems is the estimation of influence of natural factors (overburden and effective pressures, reservoir pressure, formation temperature, lithology, pore space geometry, etc.) on the petrophysical properties of sedimentary rocks. Mathematical models of the processes which describe the influence of pressure, temperature, and structural and lithological factors on petrophysical properties of sedimentary rocks can be presented using two approaches: deterministic (analytical) and probabilistic (statistical). Both of these approaches are mutually dependent and their combination enables the generalization of studied processes. Statistical methods can be used only when sufficient data exists. The data is obtained either at the stage of completion of exploration or during subsequent development of a deposit. Obtaining the representative data can be very expensive. Therefore, a new procedure should be developed for prediction of rock properties when data are sparse. Such studies are especially appropriate for the exploration and development of offshore oil and gas field of the offshore areas of Azerbaijan and Turkmenistan. In the Caspian Sea, the productive formations (1) occur at great depths; (2) are widespread with abnormally high pore pressures; and (3) the problems of drilling, coring and logging do not allow acquisition of reliable data for the evaluation of reservoir rock and caprock properties, especially at the early stage of exploration. Data collection first involves determination of petrophysical properties of rocks if cores are available. Secondly, one must determine the

384

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385

limiting values (cut-offs) of any parameter used for identification of beds (a typical problem of the pattern recognition theory). Both of these present problems in the simulation of rock properties. The main principles used in simulation are as follows: 1. The most complete quantitative characteristics of geologic and petrophysical parameters are delineated by their statistical distributions. 2. The distributions of geologic and petrophysical parameters are simulated on the basis of their mathematical descriptions (models), which may be probabilistic as well as deterministic. 3. In the case of scarcity of data, the artificial distributions of model input data are formed by means of their interval-probable presentation, and the Monte Carlo technique is used for plotting such distributions. 4. For the purposes of prediction of petrophysical properties of rocks, simulation of statistical distributions is required on the basis of models with variable input data depending upon changes in the regional geologic environments. 5. For the purposes of identification of formations, simulation of more than one statistical distribution and the determination of the cut-off points for the simulated parameters (which allows strata classification) are required. The characteristic feature of construction of artificial distributions for solving geologic modeling problems is that the decision about the influence of various natural factors upon the parameter under study is often made only at the intervals of their variation, which indicates the presence of fuzzy data (Zadeh, 1980). In such a case, the intervalprobable determination of the input data and the subsequent calculation results provide consideration of the indeterminate form of the basic factors. Figure 12-1 shows a functional block-diagram of parameter imitation on the basis of which the simulation algorithm was developed. Notations in the diagram are as follows: LP—Leading Procedure (Prediction or Identification); MD 1, ..., MD N—Mathematical Descriptions (Models) of parameters; PBDF—Procedure of Basic Data Formation; PORV—Procedure for Obtaining the Random Variables; PFU, PFN, PFT—Procedures for Formation of random variables with Uniform, Normal or Triangular distributions; PSP—Procedure for Statistical Processing; PObD, PPD, POD—Procedures for Obtaining, Processing, and Output of Data; CP—Control Procedure for selection of the type

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Petroleum Geology of the South Caspian Basin

Figure 12-1. Block-diagram of simulation of petrophysical properties (notations in the block-diagram are discussed in the text).

of problem. If a prediction problem is to be solved, the control is transferred to the procedure of formation of basic data with the aim of changing the influence of input factors while preserving the model type. If an identification problem is to be solved, the control is transferred to the choice of the required models (mathematical descriptions).

SIMULATION OF RESERVOIR-ROCK PROPERTIES To solve the problems of numerical simulation of reservoir rock and caprock properties, mathematical models of various parameters of rocks (and the basic geologic data of different accuracy and reliability)

Other Applications of Numerical Simulation Methodology

387

were used. The theory, methods and computer technique have been described above. The most important reservoir rock and caprock properties are porosity, permeability, oil or gas saturation, and density. The models of porosity φ, permeability k, and formation bulk density γ were used as mathematical descriptions of the rock properties (see Equations 111, 112, 113 and 114). Initial oil or gas saturation was evaluated from the following equation: So/g = 1 – ak–b

(115)

where the empirical coefficients a and b have the following (average) values for the region under study: a = 0.80 and b = 0.225. In determining the baseline for coefficients xi , conditions of rock occurrence in the areas of the northern, northwestern and northeastern flanks of the South Caspian Basin were assumed. In this region the oil- and gas-bearing formations belong to the Productive Series (in Azerbaijan) or to the Red-Bed Series (in Turkmenistan) of the Middle Pliocene age (10–12 million years). The region under study was subjected to the action of one Alpine Orogeny (Khain, 1954; Potapov, 1964). The intensity of subsidence of the sedimentary basin floor during the Middle Pliocene time decreased with depth, and increased in the direction from the Apsheron Peninsula to the Apsheron and Baku archipelagos and from the Cheleken Peninsula to the Turkmenian shelf, i.e., southward. The mineralogical composition of sediments is mainly quartz (40 to 80%); Trask sorting coefficient of grains is 2–4; degree of cementing is moderate (CaCO3 content in sandstones is 8–12%). Properties of reservoir rocks and caprocks of oil- and gas-bearing formations and aquifers at the formation pressure and temperature were determined at depths of up to 6,500 m (at this depth formation temperature is 105 to 110°C). The parameters under study were estimated up to a depth of 9,000 m (Figures 12-2 and 12-3). These figures show that as stratigraphic (to the bottom of the Middle Pliocene interval) and hypsometric (along the same bed) depths increase, the absolute and effective porosity decrease from 19–20 to 14–15% and from 14–15 to 9–10%, respectively. The corresponding permeability of sandstones and siltstones (text continued on page 390)

Figure 12-2. Results of simulation of reservoir-rock properties in the South Caspian Basin (Modified after Buryakovsky et al., 1990b). a—Porosity, b—permeability, c—density. 1—Average curve, 2—confidence limits, 3–4—core data, 5— statistical distribution of actual (measured) permeability.

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Figure 12-3. Results of simulation of petrophysical properties of rocks (variation with depth) (Modified after Buryakovsky et al., 1990b). a—Reservoir rocks from Apsheron region: 1—porosity, 2—permeability, and 3—density. b—Shales from three regions of the South Caspian Basin: 4, 5, 6—porosity, and 7, 8, 9—density.

Other Applications of Numerical Simulation Methodology 389

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Petroleum Geology of the South Caspian Basin

(text continued from page 387)

decreases from 130–150 to 40–60 mD. At a depth of 9,000 m, porosity varies from 7 to 10%, whereas permeability changes from 2 to 11 mD. Tables 12-1 and 12-2 show the predicted values of reservoir-rock properties of the Productive Series of the offshore fields in the Apsheron and Baku archipelagoes, respectively.

SIMULATION OF PETROPHYSICAL PROPERTIES OF ROCKS Mathematical Model of Electrical Resistivity of Sedimentary Rocks For a homogenous, isotropic medium with resistivity R, changes of overburden pressure dpe, changes of pore (reservoir) pressure dpi , and changes of temperature dT, will result in the changes of electrical resistivity of rocks as follows: dR = (∂R/∂pe)dpe + (∂R/∂pi)dpi + (∂R/∂T)dT

(116)

Table 12-1 Predicted Reservoir-Rock Properties of Different Suites of the Productive Series in Offshore Areas

Suite

Depth, m

Porosity, %

Oil/gas Saturation, %

Effective Porosity, %

Permeability, mD

Surakhany Sabunchi Balakhany “Pereryv” NKG NKP KS PK KaS

200–1,500 200–2,000 200–2,500 200–2,500 300–2,500 300–2,500 400–1,500 500–2,000 700–2,200

23 23 23 23 21 23 23 23 22

77 77 76 76 71 77 73 77 74

18 18 18 18 15 18 17 18 16

302 283 287 287 117 280 139 298 174

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Other Applications of Numerical Simulation Methodology Table 12-2 Predicted Reservoir-Rock Properties of Some Offshore Fields in the Apsheron and Baku Archipelagoes

Field

Depth, m

Khamamdag Deniz Garasu Deniz Sangi Mugan Aran Deniz Dashly

3,200–4,100 3,900–4,500 3,900–4,500 3,700–4,300 4,800–5,300

Oil/gas Effective Porosity, Saturation, Porosity, Permeability, % % % mD

20 19 19 19 17

73 71 71 72 69

15 14 14 14 12

164 107 107 109 172

or dR/R = (1/R)(∂R/∂pe)dpe + (1/R)(∂R/∂pi)dpi + (1/R)(∂R/∂T)dT

(117)

Assuming that pe, pi and T are independent of R, the following approximate solution was obtained (Dobrynin, 1970): R(pe, pi, T)/R ≈ [R(pe)/R] • [R(pi)/R] • [R(T)/R]

(118)

If one assumes that only pe, pi , or T influence the resistivity R at one time, the influence of the next parameter begins when the action of the previous one ends. In such a case, a mathematical model can be constructed where the influence of each one of the parameters is expressed by a certain coefficient. Each one of these coefficients is related to resistivity R, with the influence of certain parameters on the original resistivity R 0 . The overall effect of these parameters on resistivity is a product of influences of individual parameters. Each one of these coefficients is greater than 1 when the parameter influence increases the resistivity and is smaller than 1 if reverse is true. If other factors, such as lithologic or structural, are involved, this model is broadened, and coefficients can be derived. The overall effect can be presented as a product series: L

m

n

R / R0 = ∏ ki = ∏ α i / ∏ β i i =1

i =1

i =1

(119)

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Petroleum Geology of the South Caspian Basin

where L = m + n, α > 1, and β > 1. This is a general statistical model describing all parameters influencing resistivity of sedimentary rocks. The proposed statistical model reflects the nature of various phenomena if the following conditions are met: 1. All proposed coefficients ki take into account the total influence of thermodynamic and lithologic factors on R in the natural setting. These coefficients are obtained empirically by testing rock samples using equipment capable of simulating natural conditions. 2. Numerous experiments confirmed the influence of different thermodynamic and lithologic factors on resistivity of rocks. 3. Results obtained using the preceding model are in agreement with those obtained from well-logging. The Rn/R0 ratio obtained from the statistical model (Dzhafarov and Buryakovsky, 1979) closely agree with ratios obtained from well-logging. 4. The statistical model is a generalization of the deterministic model and is a result of logical extension for any number of factors. Calculations are carried out by simulation of coefficients ki using the Monte Carlo techniques in intervals given on the basis of experimental and field data. In studying the resistivity changes with depth, experimental functions of R versus p e, pi, and T are transformed depending upon the depth only. Then the resistivity values are simulated by Equation 119 for successive points at different depth taking into account coefficients ki. The distributions of coefficients can be uniform, triangular, normal, lognormal, etc. An example of such resistivity calculation for water-saturated sandstones of the Apsheron oil and gas reservoirs is presented in Figure 12-4. The experimental results are in good agreement with those obtained from theoretical model. The same statistical model can be constructed using a wider systems approach (Middleton, 1962). If one assumes that at moment ti resistivity is Ri and at moment ti-1 it is Ri-1, and that their difference is proportional to original resistivity, then: Ri – Ri–1 = ki(Ri–1)

where ki is the independent coefficient of proportionality.

(120)

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On the basis of previous assumptions it follows that: Ri = R0(k + 1)

(121)

As n → ∞ one obtains: n

Rn = R0 ∏ ( k + 1)

(122)

i =1

that is, we have a multiplication model. As a rule, such models lead to lognormal distribution (Middleton, 1962). There is a lognormal distribution of resistivity, which occurs in nature. If one assumes that R0 is the original resistivity of formation with a given distribution g(R) (R0 is constant for given conditions), and ki are coefficients determining this resistivity (these coefficients could be either greater than 1 or less than 1; coefficients ki are independent of each other and their individual effects do not depend on the previous resistivity of rock), then after n changes resistivity of a given rock will be equal to: Rn = R0 • k1 • k2 • ... • kn

(123)

This statistical model is a function of time: the resistivity Rn is a function of time tn. In certain geological scenarios, however, time and space coordinates become mutually interchangeable. The predicted value of Rn, therefore, can be interpreted also as a function of space, at a particular depth. In this statistical model, Rn is analogous to R(pe, pi, T) where pe is the effective (grain-to-grain) pressure, pi is the reservoir (pore) pressure, and T is the formation temperature. This model can be used for predicting resistivity at a given depth, under certain lithologic and thermobaric conditions. At different depths, the resistivity R(pe, pi, T) varies identically to the resistivity R0. The coefficients ki, which include the influence of lithology and saturating fluids on resistivity, are as follows (Figure 12-5): (1) packing; (2) compressibility of fluids saturating the pore space; (3) compressibility of the cementing material (argillaceous, argillaceouscalcareous or calcareous); (4) influence of the relative content and

394

Petroleum Geology of the South Caspian Basin

Figure 12-4. Results of simulation of the effect of temperature, pressure, rock texture and lithology on the electrical resistivity of water-saturated sandstones (Modified after Buryakovsky et al., 1990b). Type of pore cement: a—carbonate, b—clay-carbonate, c—clay.

types of clays in sandstones on the surface electrical conductivity; (5) thickness of the double electrical layer; (6) geometry of the pore space; and (7) temperature. The coefficients ki were used for determining corrections (Table 12-3) (for the effective pressure pe and formation temperature T ) for the true resistivity R t and formation resistivity factor (F ) of water-saturated core samples measured under atmospheric conditions.

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Figure 12-5. Fuzzy relations Fi for model of sedimentary-rock resistivity considering the following effects. Effect of differential pressure: 1—effect on matrix; 2—electrolyte; 3–5—cement: 3—clay, 4—clay-carbonate, 5—carbonate; 6—clay content; 7—double-electrical layer; 8—pore-space geometry. Effect of temperature: 9–11—effect on rock skeleton and cement: 9—clay, 10—claycarbonate, 11—carbonate; 12—electrolyte.

Other Mathematical Models of Petrophysical Properties of Rocks Two important problems of petroleum geology (modeling of petrophysical properties of oil- and gas-bearing formations) have been solved: (a) identification of reservoir beds and (b) identification of productive formations. Any of the parameters listed below may be used as a cut-off (identifying) parameters:

396

Petroleum Geology of the South Caspian Basin

Table 12-3 Corrections to the (1) Resistivity and (2) Formation Resistivity Factor for Effective Pressure and Temperature In Situ Depth, m

Correction in Rt for peff

Correction in Rt for peff and T

Correction in F for peff and T

Clay Cement

2,000–3,000 3,000–4,000 4,000–5,000 5,000–6,000

1.78 1.88 2.06 2.05

0.66 0.62 0.58 0.52

1.61 1.74 1.78 1.75

Clay-Carbonate Cement

2,000–3,000 3,000–4,000 4,000–5,000 5,000–6,000

1.45 1.52 1.51 1.45

0.61 0.57 0.52 0.47

1.48 1.69 1.61 1.58

Carbonate Cement

2,000–3,000 3,000–4,000 4,000–5,000 5,000–6,000

1. 2. 3. 4.

1.23 1.25 1.25 1.22

0.57 0.52 0.48 0.43

1.32 1.43 1.38 1.33

true resistivity, Rt interval transit time, ∆t macroscopic cross-section of thermal neutron absorption, ∑ formation bulk density, γ

Information about the types of fluid saturating the rocks is provided by resistivity. Although various models of petrophysical properties of rocks are used, the most commonly used are the following relationships: Rt = Rwτφ–mSw–n

(124)

Rt,a = Rt /[ksh(Rt/Rsh – 1) + 1]

(125)

∆t = φ∆tf + (1 – φ)∆tma

(126)

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∑ = φ∑w + φ (1 – ∑w )∑o + (1 – φ)∑ma

(127)

γ = φγf + (1 – φ)γma

(128)

where Rt, Rt,a, ∆t, ∑, and γ are the true resistivity of isotropic (Rt) and heterogeneous (Rt,a) rocks, interval transit time in rocks, macroscopic cross-section of thermal neutron capture (absorption), and formation bulk density, respectively. Subscripts f, w, o, and ma denote the fluid, water, and oil filling the pore space, and the rock matrix, respectively; Rw and Rsh are the resistivities of formation water and shale; ksh is volume content of clay in an laminated shaly reservoir rock; τ is the electrical tortuosity of pore channels; and m and n are the empirical coefficients (m = 1.6 and n = 2.0 for the rocks of region under study; average values). Heuristic formulas were used for determining the cut-off (separating) values of parameters. To distinguished the water- and oil-saturated beds using their resistivity, the following criteria for determining the cutoff values of Rt,cr were used: Rt,cr = [(DoRw – DwRo) + (DwDo(Ro – Rw)2 – (Do – Dw)lnDo/Dw)]1/2/(Do – Dw)

(129)

Rt,cr = 1/2(Rw,max + Ro,min)

(130)

Rt,cr = (Rw,md • Ro,md )1/2

(131)

where Rw, Ro, Rw,md, and Ro,md are average and median values, whereas Dw and Do are standard deviations of resistivity in water- and oilsaturated layers. The calculations show that the cut-off values of petrophysical parameters depend considerably upon the geometry of the pore space, the degree of cementation, the clay content in reservoir rocks, and the salinity of formation water. For example, with the increase in clay content in the reservoir rocks and transition from isotropic to anisotropic layers, the cut-off value of resistivity of the oil- and gas-bearing formations decreases from 10–15 to 4–8 ohm • m. Thus, the use of static (for identification) as well as dynamic (for forecast) stochastic models in geologic studies allows solution of a number of important practical problems when data are scarce by using artificial distributions of various geologic and petrophysical parameters.

398

Petroleum Geology of the South Caspian Basin

SIMULATION OF WATER INVASION INTO OIL-SATURATED ROCKS The simulation of dynamic geotechnological systems on using the methodology described above, gave rise to two groups of mathematical models of changes in the petrophysical properties of reservoir rocks during oil displacement by water (Buryakovsky, 1985a; Buryakovsky and Chilingarian, 1991c): 1. Model of water invasion into the oil reservoir during the water drive. In the course of oil displacement by water, water saturation Sw of the reservoir increases from the value equal to the residual water saturation (Sw,1 = Sw,r) to the value of the pore volume minus the residual oil saturation [Sw,2 = (1 – So,r)]. A dynamic model [Sw = f(t)] with a Sw range between Sw,r and (1 – So,r) can be constructed. One can use Equation 88 at f(x) = x(1 – x), where x = Sw. With the initial and final conditions taken into account, the solution of Equation 88 can be presented as follows: Sw = [(1 – So,r)Sw,rexp((1 – So,r)εt)]/[(1 – So,r) – Sw,r + Sw,rexp((1 – So,r) εt)]

(132)

where t is the duration of oil displacement by water. The change of water saturation versus time is shown on Figure 126 (curve 1). 2. Models of variation in the petrophysical properties of reservoirs during waterflooding. The electrical resistivity Rt of an homogeneous oil-bearing bed changes according to the following equation: Rt = Rt,0{[(1 – So,r) – Sw,r + Sw,rexp((1 – So,r)εt*)]/[(1 – So,r) × Sw,rexp((1 – So,r)εt*)]}n

(133)

where Rt is the electrical resistivity of the reservoir rock at any Sw; Rt,0 is the electrical resistivity when Sw = Sw,r; and t* is the dimensionless time (t* = t/tmax). Other petrophysical parameters can be represented in a similar way. As Figure 12-6 demonstrates, the change in water saturation from 0.2 to 0.8 causes:

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399

Figure 12-6. Results of simulation of petrophysical properties (variation with time). 1—Water saturation Sw. G /G 0 ratio for: 2—acoustic transit time ∆t; 3—anisotropic true resistivity Rt,a, 4—isotropic true resistivity Rt. G = petrophysical parameter, G0 = initial value of G.

a. A 13-fold decrease in the electrical resistivity Rt of a homogeneous oil-bearing reservoir (curve 4); b. Greater than 3-fold decrease in the electrical resistivity Rt,a of a heterogeneous reservoir (curve 3); and c. A 1.27-fold decrease in the acoustic interval transit time ∆t (curve 2) at a constant salinity of the reservoir water and geometry of the pore space. The above described dynamic models of certain petrophysical parameters of the oil-saturated reservoirs allow one to achieve two goals: 1. To follow closely the changes in these parameters occurring during oilfield development. 2. To apply the models for observation of the water invasion into the reservoir and of movement of the oil-water contact (based on well-log information).

400

Petroleum Geology of the South Caspian Basin

The specific feature of the models (Equations 132 and 133) is that they take into consideration the so-called “technological” duration of the process of reservoir development. The model (Equation 132), which describes the dynamics of water movement in oil-saturated reservoir in the process of its development, can be changed into a model of lateral migration of oil (if the water is replaced by the oil).

SIMULATION OF PORE-FLUID (FORMATION) PRESSURE The description of processes of pore-fluid pressure generation and destruction is obtained from Equations 89, where f1(x1) = p1 and f2(x2) = p2 are pore-fluid pressures in the process of their increase and decrease, respectively. This dynamic model satisfied the following conditions: 1. A current pore-fluid pressure at any moment of time is a result of dynamic equilibrium among the synchronous processes of generation/dissipation of these pressures in a given geologic object. 2. Natural factors affecting generation/dissipation of pore-fluid pressures are permanent. 3. The rate of change in pore-fluid pressure in a given geologic object is proportional to the current pore-fluid pressure. 4. Pore-fluid pressures increase/decrease so that a constant portion of the current pore-fluid pressure increases/decreases per unit of time (the given condition is not obligatory). 5. Factors of pressure drop act so that a portion of pressure decrease per unit of time is equal to the product of increasing portion of the pressure by its decreasing portion. Dynamic models can be described by a system of nonlinear differential first-order equations as follows: dp1/dt = ε1p1 – γ12p1p2

(134)

dp2/dt = –ε2p2 + γ21p1p2

where p 1 = p 1 (t) is the pore-fluid pressure during the period of its increase; p2 = p2(t) is the pore-fluid pressure during the period of its decrease; ε1 and ε2 are coefficients of pore-fluid pressure change during the periods of its increase and decrease, respectively; and γ12

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401

and γ21 are coefficients of interaction of natural factors determining either preservation or change of the pore-fluid pressure. The system of Equations 134 describe the theoretical processes of generation, stabilization, preservation, and dissipation of pore-fluid pressures. Due to the difficulty in simultaneous experimental determination of the coefficients of pressure change and coefficients of opposite influence of some natural factors, numerical simulation using the models is possible in a practical case only when the coefficients having opposite influence may be neglected. For γ12 = γ21 = 0, Equations 134 are reduced to two equations, one of which describes the abnormal pore pressures, and the other, a drop to normal hydrostatic pressure. At actual conditions, it is necessary also to take into account the self-retarding effect of the process, leading to the following equation: p1 = [pmaxpoexp(ε1pmaxt)]/[pmax – po(1 – exp(ε1pmaxt))]

(135)

where po is the initial value of the pore pressure (hydrostatic pressure of water at a depth where sedimentation began), pmax is the maximum possible pore pressure at given conditions, and t is time. The coefficient of proportionality calculated for the South Caspian Basin averages 0.02 (MPa per million years)–1. The change in pressure with depth is assumed to be analogous to the change in time and may be described by an equation similar to Equation 135. This assumption is probably true for the South Caspian Basin, taking into account a relatively young age of rocks, absence of noticeable faulting, one-phase formation of folded structure, normal bedding of sequential stratigraphic intervals, etc. Other factors can also influence the development of abnormal pore pressure, but in the South Caspian Basin they probably play a subordinate role (Buryakovsky et al., 1986c). Using Equation 135, it is possible to describe the dynamics of the pore-fluid pressure (Figure 12-7a) and to forecast the pore pressure in the reservoir rocks and caprocks at various depth (Figure 12-7b) for the various regions of the South Caspian petroleum province (Buryakovsky and Chilingarian, 1991c). Fertl (1976), Fertl and Chilingarian (1976), and Magara (1982) pointed that the abnormally-high pore pressures have different origin and can be caused by various natural factors superimposed upon each other. In the South Caspian Basin, for example, with accumulation of

402

Petroleum Geology of the South Caspian Basin

Figure 12-7. Results of pore-fluid pressure simulation. a—Variation in porefluid pressure with time; b—variation in pore-fluid pressure with depth, for three regions of the South Caspian Basin. ph = hydrostatic pressure, pmax = total overburden (geostatic) pressure.

thick sand-shale sequences (mainly shales), the most probable mechanism for abnormally-high pore pressure development is gravitational consolidation with upward filtration of fluids. Gravitational consolidation prevails over the upward flow of fluids at rapid rates of sedimentation. This leads to a considerable undercompaction of sediments (mainly shales) and development of abnormally high pore pressures. It has been shown (Buryakovsky et al., 1986c) that hydrostatic pressure gradients in shales at the depth interval of 1,000–6,000 m

Other Applications of Numerical Simulation Methodology

403

(over 2,000 determinations by well-logging) range from 0.012 to 0.024 MPa/m with an average value of 0.018 MPa/m (Figure 12-8).

SIMULATION OF HYDROCARBON RESOURCES AND EVALUATION OF OIL AND GAS RESERVES The model of determining hydrocarbon resources (a materialfunctional model of Equations 89 type, at f1(x1) = V1 and f2(x2) = V2, where V1 and V 2 are hydrocarbon volumes in increasing (V 1) and

Figure 12-8. Pore-fluid pressure in clays versus depth in the South Caspian Basin (Modified after Buryakovsky et al., 1986c). η = pore-fluid pressure gradient.

404

Petroleum Geology of the South Caspian Basin

decreasing (V2) accumulations) was described by Buryakovsky (1977b). At one-stage oil accumulation, the model is analogous to Equation 135: V1 = [BVoexp(ε1Bt)]/[B – Vo(1 – exp(ε1Bt)]

(136)

where B is the volume of reservoir containing a hydrocarbon accumulation. This model allows to forecast the extent of the oil-gas accumulation and to evaluate the hydrocarbon resources locally or for a region as a whole (Figure 12-9). As a forecast target, reservoirs of the deep-water zone of the South Caspian Basin have been used. They were studied by seismic surveys only (Buryakovsky, 1983). Using Equation 136, a model of hydrocarbon reserves evaluation in individual traps was obtained. This model is a derivative of Equation 136 and is formally similar to the Equation 108, where xi are reservoir parameters for hydrocarbon reserves estimation using the volumetric method. The volumetric method used in the evaluation of hydrocarbon reserves appears to increase the reliability of estimated reserves.

Figure 12-9. Results of simulation of hydrocarbon accumulation in traps. B = pore volume of the reservoir, V = volume of trapped hydrocarbons.

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405

The formula used in calculating crude oil volume in-situ is as follows: V = AheffφSo

(137)

where V is the volume of oil accumulation, A is the reservoir area, heff is the thickness of oil-bearing formation (net pay), φ is the porosity, and So is the oil saturation. Equation 137 can be simplified if φSo is replaced by the “effective oil saturated porosity” φeff : V = Aheffφeff

(138)

It should be noted that some offshore structures in the South Caspian Basin are studied only by a sparse grid of seismic lines, and offshore areas adjacent to the oil and gas fields were not studied during exploration. In view of this problem, it was decided to use mathematical methods. An algorithm and computer program using Double Fourier Series for uneven spacing of the initial data were developed. Examples of structural mapping on top of the Lower Productive Series along the northern slope of South Caspian Basin are presented in Figures 10-1 and 10-2. Effective oil and gas saturated thickness of a reservoir (net pay) was determined through the identification of layers using a cluster-analysis technique, i.e., by means of recognition without preliminary training. For this purpose, sections studied using well logs were utilized. Each section was divided into groups of layers with definite reservoir-rock properties. These groups were identified by means of comparison with the well-testing results. As a measure of reliability in division into groups of beds, the Correlation Coefficient (see Equation 5) and generalized Euclidian Distance (see Equation 6) were used. An example of identification of beds is shown in Figure 10-7. In the algorithm, each bed has a thickness equal to the average thickness of all beds in the section. A more complex algorithm allows simulation of sections taking into account distribution of bed thicknesses based on lithology. The φSo (see Equation 137) of reservoir rocks was evaluated by simulating processes of compaction and other diagenetic changes of sediments, as described above. Examples of simulation of reservoir-

406

Petroleum Geology of the South Caspian Basin

Figure 12-10. Statistical distributions of calculated values of petrophysical properties and water saturation (Sw). a—Porosity (fraction), b—permeability, c—water saturation (fraction). Formations: 1—Balakhany Suite; 2—“Pereryv” Suite; 3—NKP Suite; 4—PK Suite.

Other Applications of Numerical Simulation Methodology

407

rock properties are presented in Tables 12-1 and 12-2 (or in Figure 12-10). Hydrocarbon volumes were calculated using the Monte Carlo technique (see Equations 137 or 138) at the interval-probable setting of reservoir parameters. As discussed by Abasov et al. (1984), such method of reserves evaluation is more preferable than evaluation using the average parameters. This allows one to obtain not an average value of reserves but their distribution. Consequently, reliable intervals of real values of reserves (with the reliability coefficient fixed in advance) can be obtained.

408

Petroleum Geology of the South Caspian Basin

CHAPTER 13

Conclusions (Chapters 9 to 12)

The above-described approach to modeling of the geologic systems allows one to solve theoretical as well as some applied problems. The theoretical problems include: 1. 2. 3. 4.

Compaction and other diagenetic alterations of sediments. Formation and evolution of the geofluidal (pore-fluid) pressures. Formation of hydrocarbon resources. Problems of regional sedimentation and the role of endogenic and exogenic factors in the processes of tectogenesis, folding, mud volcanism, and earthquake forecast.

The applied problems include: 1. Estimation of hydrocarbon reserves in various traps. 2. Prediction of petrophysical properties of rocks and pore-fluid pressures at depths not yet studied by geologic and geophysical techniques. 3. Estimation of the degree of water invasion into the reservoir during its development. In the studied region of the South Caspian Basin, on the other hand, the described approach allowed to solve the following practical problems: 1. Evaluation and prediction of the petrophysical properties of reservoir rocks and caprocks. Bulk density, porosity, permeability, residual water saturation, electric resistivity, etc. are used as input parameters at reservoir conditions in situ. 2. Evaluation and prediction of the pore-fluid pressures in reservoir rocks and caprocks; estimation of the sealing properties of caprocks. 3. Evaluation and prediction of the volume of hydrocarbon accumulation, and estimation of oil and gas reserves in various traps.

408

Conclusions

409

The systems approach to geology is both a sophisticated philosophy and a scientific method for investigation of very complicated geologic systems. As applied to petroleum geology, it includes the methodological base and technology of mathematical simulation used for modeling geologic systems, the systems which have been previously investigated and estimated by using experimental data and/or field studies. Because geologic systems develop in time, it is very important to simulate them as dynamic systems. The necessity of considering the geologic time factor does not eliminate the possibility of developing, along with the dynamic models, also of the static and structural models. It is imperative, however, to remember that geology is a historic discipline, and the relative lack of success in its mathematization is associated to a significant degree with difficulties in considering the time factor.

428

Petroleum Geology of the South Caspian Basin

CHAPTER 29

Author Index Abasov, M. T., 119, 407, 410, 411, 422 Abikh, G. V., 61 Abramovich, M. V., 120 Agamaliev, R. A., 221, 320, 321, 331, 412, 415 Akhmedov, A. G., 202, 410 Akhmedov, A. M., 202, 410 Akhmedov, G. A., 22, 410 Akhundov, A. R., 410 Aksenov, A. A. , 221, 410 Aleksandrov, B. L. , 152, 358, 359, 364, 410 Alibekov, B. I. , 411 Aliev, R. A., 155, 411 Alikhanov, E. N., 22, 36, 37, 201, 210, 411 Aliyarov, R. Yu., 140, 155, 402, 403, 414, 415 Aliyev, A. K., 61 Aliyev, A. I., 23, 24, 208, 411 Aliyev, A.D., 411 Ali-Zadeh, A. A., 411 Amanniyazov, K. N., 223, 411 Aminzadeh, F., 153, 155, 411, 418, 420, 421 Apresov, S. M., 61 Arkharova, I. M., 320, 321, 415 Arps, J. J., 411 Asan-Nuri, A., 62 Ashirmamedov, M. A., 411 Ashumov, G. G., 178, 179, 180, 411 Athy, L. F., 358, 411 Avchan, G. M., 411 Babajev, F. R., 22, 114, 185, 339, 412 Babazadeh, B. K., 22, 120, 412 Bagir-zadeh, F. M., 22, 56, 114, 185, 339, 412 Bagrintseva, K. I., 363, 367, 412 Bairamalibeili, N. I., 331, 413 Barnes, H.,, 167, 421 Baturin, V. P., 412 Belyakova, G. M., 412 Berner, R., 360 Bezborodova, I. V., 223, 364, 412 Bissell, H. J., 357, 363, 370, 380, 417 Bonham-Carter, G., 198, 380, 420

Bredehoeft, J. D., 199, 412 Brod, I. O., 120, 412 Buryakovsky, L. A., 22, 56, 69, 83, 114, 119, 129, 140, 155, 157, 158, 162, 167, 185, 186, 189, 198, 202, 250, 252, 263, 266, 284, 297, 303, 326, 327, 328, 343, 331, 339, 351–352, 353, 354, 357, 359, 362, 365, 370, 389, 394, 401, 407, 410, 412–416, 425, 426 Carman, P. C., 416, 417 Chapman, R. E., 419 Chetverikova, O. P., 220, 417 Chilingar, G. V., 153, 155, 157, 158, 162, 163, 167, 189, 198, 237, 303, 357, 363, 364, 370, 380, 416, 417, 420, 421, 422, 426 Chilingarian, G. V., 152, 156, 166, 171, 189, 353, 358, 359, 360, 363, 380, 392, 398, 401, 416, 417, 419, 401, 419, 425 Clarke, J. W., 212, 217, 221, 223, 225, 226, 227, 230, 418 Dadashev, R. M., 83, 413 Danchenko, K. V., 210, 418 Davis, J. C., 244, 365, 420 Dickinson, G., 152, 352, 358, 418 Dikenshtein, G. Kh., 234, 418 Dobryanskiy, A. F., 179, 180, 339, 418 Dobrynin, V. M., 152, 326, 351, 352, 353, 361, 364, 367, 418 Donaldson, E. C., 363, 417 Doveton, J. H., 244, 365, 420 Dunan, J. P., 155, 418 Dunin-Barkovskiy, I. V., 256, 257, 331, 426 Durmishyan, A. G., 352, 353, 355, 418 Dzhafarov, I. S., 119, 250, 252, 263, 266, 284, 297, 354, 357, 359, 362, 365, 370, 389, 394, 407, 410, 412, 413, 414, 415, 418, 419 Dzhafarova, N. M., 410, 419

428

Author Index Dzhalilov, D. G., 186, 425 Dzhevanshir, R. D., 140, 155, 157, 158, 162, 167,198, 250, 252, 266, 326, 327, 328, 343, 351, 354, 357, 359, 362, 365, 370, 389, 392, 394, 410, 411, 412, 414, 415, 416, 419, 422 Efendiev, G. M., 155, 411 Engelhardt, W. V., 419 Fedynskiy, V. V., 5 Fertl, W. H., 152, 353, 401, 419 Foster, J. B., 152, 352, 358, 419 Fyodorov, S. F., 185, 419 Gadzhi-Kasumov, A. S., 339, 419 Gadzhiyev, B. A., 419 Geodekyan, A. A., 235 Godin, Yu. N., 419 Gordon, Z. S., 223, 419 Grachevskiy, M. M., 208, 420 Graybill, K. A., 198, 243, 365, 422 Griffiths, J. C., 198, 331, 365, 420 Gubkin, I. M., 22, 120, 420 Gurevich, A. E., 153, 237, 420, 421 Gussow, W. C., 185, 420 Gyul’, K. K., 420 Ham, H. H., 352, 358, 420 Harbaugh, J. W., 198, 244, 365, 380, 420 Hedberg, H. D., 352, 355, 358, 420 Hosoi, H., 352, 420 Hotz, R. F., 419 Ismailova, Kh. G., 257 Johns, P. J., 309 Kahn, J. S, 243, 292, 424 Kalinko, M. K., 420 Karimov, K., 418 Kartsev, A. A., 179, 180, 326, 421 Kasumov, S. M., 413 Katz, S. A., 153, 163, 421, 426 Kauffman, M. E., 244, 422 Kaverochkin, M. P., 62 Kazi, A., 166, 417 Kemeny, J. G., 350, 421 Kevorkov, F. M., 202, 410 Khain, V. Ye., 22, 120, 387, 421 Khanin, A. A., 421 Kharaka, J. K., 167, 421 Kheirov, M. B., 140, 159, 415, 421 Khilyuk, L., 153, 421 Khitarov, N. I., 161, 421 Khodzhakuliyev, Ya. A., 221, 421 Kingston, J., 220, 221, 223, 224, 421 Klemme, H. D., 256, 257, 331, 426

429

Kleschev, K., 418 Kolmogorov, A. N., 270 Kondrushkin, Yu. M., 410, 421 Kotyakhov, F. I., 422 Kovalevskiy, S. A., 61 Kozeny, J., 422 Kravchik, M. S., 237, 422 Krems, A. Ya., 22, 120, 422 Krumbein, W. C., 198, 243, 244, 365, 422 Kukhmazov, M. S., 129, 413 Kuliev, R. D., 415 Kuliyev, G. G., 422 Kuzmina-Gerasimova, V. L., 244, 367, 371, 414 Langnes, G. L., 422 Larsen, G., 364, 422 Law, B. E., 422 Lebedev, L. I., 422 Lebedev, N. A., 61 Lee, S., 155, 422 Leibenzon, L. S, 422 Leontaritis, K. J., 339, 423 Listengarten, B. M., 331, 411, 413 Livshits, M. G., 223, 423 Madera, E. R., 414 Magara, K., 152, 161, 352, 379, 401, 423 Main, R., 417 Maksimov, S. P., 185, 210, 211, 212, 213, 220, 225, 226, 423 Maltsev, N. G., 224, 423 Mamedov, B. M., 224, 423, 426 Mamedov, M. M., 426 Mamedzadeh, R. N., 411 Mansoory, G. G., 339, 423 Matveyenko, A. A., 411 Mazzullo, S. J., 417 McCammon, R. B., 244, 422 Meade, R. H., 352, 358, 423 Mekhtiev, Sh. F., 208, 423 Mekhtiev, U. Sh., 410 Melik-Pashayev, V. S., 22, 423 Merriam, D. F., 244, 365, 420, 424 Meyerhoff, A. A., 201, 205, 210, 212, 424 Mezhlumov, A. A., 62 Middleton, G. M., 393, 424 Miller, R. L., 243, 292, 424 Mirchink, M. F., 22, 61, 120, 300, 424 Monicard, R. P., 306, 424 Muskat, M., 309 Nalimov, V. V., 331, 424 Narimanov, A. A., 252, 424

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Petroleum Geology of the South Caspian Basin

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Subject Index A Abnormally-high formation pressure, 149, 150, 155, 401, 402, 403 Age, Albian, 223, 224 Alpine, 208 Aptian, 203 Callovian-Oxfordian, 223 Cambrian, 152 Carboniferous, 9, 217, 336 Cenomanian, 203, 223, 224 Cenozoic, 8, 195, 203, 208, 231, 359, 382, 140, 155, 164, 195 Cretaceous, 2, 4, 21, 22, 25,44,45, 46, 201, 219, 220, 221, 223, 224, 225, 226, 227, 230, 231, 237, 359 Cretaceous-Late Jurassic, 12 Devonian, 158, 359 Eocene, 25, 63, 220, 224, 359 Holocene, 220 Jurassic, 1, 2,3, 12, 44, 201, 203, 214, 217, 219, 221, 222, 223, 224, 226, 227, 230, 231, 236, 237, 238 Mesozoic, 6, 7, 8, 9, 16, 26, 55, 158, 201, 203, 208, 220, 231, 359, 360, 375–377, 379, 380, 382 Miocene, 32, 57, 147, 155, 203, 205, 206, 210 Neocomian, 203, 223 Neogene, 4, 35, 58, 201, 205, 206, 210, 220, 224, 237, 240, 373, 377, 379 Oligocene, 147, 205, 220 Oligocene-Miocene, 18, 42 Oxfordian, 223 Paleogene, 4, 25, 35, 155, 203, 220, 224, 237, 240, 359 Paleozoic, 195, 217, 231 Permian, 217, 236, 237, 238

Permo-Triassic, 236 Pleistocene, 18, 40 Pliocene, 18, 19, 21, 22, 25, 28, 32, 35, 40, 55, 113, 126, 127, 140–141, 156, 158, 159, 161, 170, 172, 196, 251, 284, 202, 203, 204– 205, 206, 208, 210, 224, 387 Middle, 11 post, 10 Quaternary, 4, 5, 28, 58, 107, 196, 201, 205, 220, 224 Triassic, 212, 217, 238 Turonian, 203, 224 Upper Archean-Lower Proterozoic , 8 Anisotropy, coefficients, 258–300 Anisotropy, permeability, 298, 301 stratified rocks, 297–302 Anticlinal trend, Adzhichai-Alyaty, 20 Apsheron-pre-Balkhan, 55–91, 113, 199, 210 Badkhiz-Karabil, 231 Fatmai-Gum Adasi, 91 Geokchai-Saatly, 3 Kalamadyn-Byandovan, 44 Khali-Azeri, 185 Kilyazi-Krasnovodsk, 116 Kyurovdag-Neftechala, 44 Pirsagat-Khamamdag, 44 Saatly-Kyurdamir, 8 Talabi-Kainardzha zone, 25 Utalgi-Kyanizadag, 101 Anticline (also see structure), 18 Anticlinorium, Greater Caucasus, 3 Lesser Caucasus, 3 Tengiz-Beshbarmak, 43–44 Arch, Dauletabad, 225 Kara Bogaz, 231, 232 Kara-Kum, 217, 232

431

432

Petroleum Geology of the South Caspian Basin

Archipelago, Apsheron, 16, 28, 30, 31, 32, 34, 55, 57–91, 114, 115, 116, 117, 119, 120, 134, 140–142, 147, 149, 154, 158, 163, 172, 173, 175, 176, 178–180, 182, 185–191, 239, 240, 295, 325, 326–327, 328, 329, 353, 355, 357, 360, 387, 390 Baku, 16, 17, 28, 30, 31, 55, 56, 101–112, 115, 116, 117, 140–141, 142, 144, 146, 148, 149, 150, 158, 159, 160, 161, 163, 165, 166, 172, 175, 200, 239, 240, 319, 320, 321, 322, 324, 353, 360, 387, 390 Kimmerian, 201 Artyom Island (Pirallaghi Adasi), 118

B Baku, City of, 10, 42, 60 Basin, Amu-Darya, 212–231 source rocks, 220–221 statigraphy, 217–220 structure, 212, 215 Azov-Kuban, 232 back-arc, 201 Kura, 232 Middle Caspian, 4, 55 Murgab, 218 North Stavropol, 233 South Caspian, 1, 3, 4, 5, 25, 27, 55, 199–242 South Mangyshlak, 231–238, 237, 238 subsidence rate, 164 Tedzhen-Murgab, 217 Terek-Kuma, 232 Uchyacan, 232 Ustyurt, 233 Western Siberian, 210 Beaufort wind scale, 61 Belt, North Anatolia, 1 ophiolitic, 1 “Benzine” fractions, 325 Boltzmann’s constant, 290 Brachyanticline, 62, 227 Bakhar, 94 Bulla Deniz, 109–110 Lokbatan, 42 Palchygh Pilpilasi, 79 Shabandag, 41, 146, 241

C Caprock, 158, 203, 208, 224, 241, 360, 387, 401 Cape, Sangachal, 102 Caspian Sea, general description, 52 Catagenesis, 243, 357 Catagenetic transformation, 161, 164, 166, 170 Cation-exchange capacity, 319 CDP surveys, 248, 251, 254 Clay, dehydration rate, 163–164 minerals, 140–146 transformation, 197, 240–241 water, bound, 163 desorbed, 164 free, 163 interstitial, 164 Cluster-analysis technique, 264 Coefficient of correlation, 265, 319, 322, 324, 331–337, 405 analysis, 329 elipse eccentricity, 333–336 Compaction, carbonate rocks, 363–365 mathematical simulation, 355–361 siliciclastic rocks, 361–363 Compressibility factor, 353, 354 Coulomb’s law, 155 Crust, collision zone, 217 earth, 1, 6, 9, 14, 15 oceanic, 201

D Darcy equation, 303 Deep water, South Caspian Basin, 404 zone, 57 Dendroid diagram, 285 Density, simulation, 375, 376 Depression, Araks, 4 Beshkent, 214, 217, 220 Dzheirankechmes, 18, 25, 41 intermontane, Kura, 1, 3 Kazakh, 234 Kura, 3, 4, 5, 6, 9, 16, 25, 44 Lower Kura, 17, 20, 148, 149, 150, 154, 158, 161, 163, 166, 319, 320, 321, 322, 324, 360 Murgab, 214, 217 Nakhichevan, 26 North Ustyurt, 234

Subject Index Yevlakh-Agdzhabedi, 25 Zaunguz, 212, 214, 217 Diagenesis, 159, 161, 166, 170, 243, 355 Diagnostic coefficient, 263, 271, 272–273, 274 Diapirism, 5 Diapirs, 208 Diffusion-adsorption factor, 314 Dome, Cheleken, 252, 253, 254 pre-Cheleken, 199, 206 Double Fourier Series, 405 Douglas Sea-State Scale, 61 Downwarp, Alazan-Agrichai, 26 Araks, 26 Dzhalilabad area, 28

E Entropy, chaotic state, 290 heterogeneity of rocks, 290–297 maximum, 293 of information, 291, 292 relative, 292–293, 295, 296 Epigenesis (see Catagenesis), 355, 357–358 Equations of normalization, 369 Euclidian distance, 405

F Fault, Caucasus-Kopet-Dagh, 55 fluid migration along, 206 Siazan, 44 Foldbelt, Alpine, 1, 5, 6 Kopet-Dagh, 201 North Anatolia, 1 Foredeep, 16 Kopet-Dagh, 212, 214, 217, 230, 232 Formation, Albian-Cenomanian, 221 Amu-Darya, 221 Aptian-Albian marine shales, 221 Bukhara carbonates, 221 Dogger sandstones, 300 Gaurdak, 219 Khodozhaipak, 221 Olenek, 236 Shatlyk, 223, 225, 226, 227 Formation pressure, sensitivity analysis, 153 Fuzzy set, 395

433

G Gas field, Dauletabad, 212, 223, 224, 225, 226, 227 Donmez, 212, 223, 224, 225, 226, 227 Dzhanub, 182, 186, 193, 195, 365 Gas, carbon dioxide (CO2), 71, 72, 187 composition, 187 condensate, 186 ethane, 187 methane, 187 generation, 14 natural, 70, 72 properties, 185–191 specific gravity, 188 Geologic time, relative, 347–348, 349 absolute, 347–348 Geosycline, 16 Mediterranean Alpine, 9 Gibbs’ composition triangle, 325, 326 Gibbs’ free energy difference, 168, 169 Gradient, formation-pressure, 153, 154 geothermal, 153, 154 pore-pressure, 153, 154, 157 Gravity, 9 Saatly-Kyurdamir gravity maximum, 7, 14 Talysh-Vandam gravity maximum, 8, 14

H Hagen-Poiseuille equation, 303 Heterogeneity, 290–297 Heuristic formulas, 397 Hooke’s law, 367 Hydrocarbon inversion, 166, 189 Hydrochemical effect, 164–168 Hypothesis testing, 256 zero, 266

I Island arc, 14 Seven Ships, 62 Isoseisms, Apsheron, 114

J Jurassic Salt, 213, 214

434

Petroleum Geology of the South Caspian Basin

K Kolmogorov-Smirnov criteria, 266, 270 Kozeny-Carman equation, 304–305, 306, 308 Kulbach informativity measure, 266, 271, 272–273 Kura Lowland (also see: Depression, Kura), 1, 16, 23, 24 Kusary sloping plain, 4

L Leptocythere praebacuana Liv., 28, 76 Ligroin fraction, 177, 180 Lithofacies, 204 Apsheron, 127 Gobustan, 117 Lithology, 126, 198, 206 Lithostratigraphy, 27–31 Loxoconcha alata Schn., 28, 76 Loxoconcha eichwaldi Liv., 28, 76

M Markov’s modeling procedure, 285, 288 Mathematical, 249 Double Fourier Series, 249, 252 models, 243 regional structural pattern, 249 simulation, 243, 244–247 simulation, principles, 247 Matrices, transition frequencies, 289 Mean Standard Error (MSE), 258 Median Masiff, Trans-Caucasus anticlinal, 6, 15 Microcavities, 160 Microfauna (radiolarians), 15 Migration, fluids, along faults, 206 Model, analytical, 348–350 cluster-analysis technique, 405 density change, 363 deterministic (analytical), 384 dynamic, 400 dynamic, stochastic, 397, 399 dynamic, time, 347–348 evaluation of oil reserves, 403–407 lognormal, 393 numeric simulation, examples, 373–379 numerical simulation, methodology, 384–407

oil composition, 324 properties, 325–329 molecular weight, 325 “organism growth,” 349, 362 petrophysical, 395–397 pore-fluid, 400–403 porosity change, 363 probabilistic (statistical), 384–385 proportional effects, 349 reservoir rock property, 372 simulation of rock properties, 386–390 statistical, 348, 350–355 Terzaghi compaction theory, 363 water invasion, 398–400 Modeling coefficient, 367 Modulus of elasticity, 366 Monocline, Siazan, 25 Monte Carlo technique, 348, 371, 407 Mountain system, Alpine, 54 Mountains, Kirmaku, 35, 39 Elburz, 201 Greater Caucasus, 1, 2, 3, 4, 5, 20, 23, 24, 117, 147, 235, 239, 240 Lesser Caucasus, 1, 3, 4, 5, 13, 23, 24, 117, 147, 239, 240 Talysh, 117, 147 Ural, 360 Mud volcanism, (see: volcanic, mud) Multi-Dimensional Statistical method, 263–271

N Nose, Donmez, 225, 226

O Offshore Zone, Apsheron, 115, 117, 119, 140–141, 142, 149, 158, 163, 166, 205 South Apsheron, 319, 320, 321, 322, 324 Oil and gas field, Adzhidere, 51 Agburun Deniz, 56, 57 Aktas, 237 Alan, 229 Alyat Deniz, 145, 146, 153, 391 Amirkhanly, 44 Apsheron Bank, 56, 57 Aran Deniz, 146 Arystan, 234 Asar, 237

Subject Index Ashrafi, 56, 57 Atashkyah , 124, 174 Azeri, 55, 56, 57, 120, 174 Azi Aslanov, 56, 57 Bagaja, 216 Bakhar, 55, 56, 94–101, 118, 142, 145, 153, 174, 255, 263, 266, 271, 298, 300 Balakhany, 32, 34, 35, 124, 125, 147, 172, 173, 174, 175, 341 Barinov, 56, 248, 252 Beurdeshik, 216, 223 Bibieibat, 40, 41, 42, 121, 124, 135, 145, 172, 173, 174, 257, 258, 260 Binagady, 32, 35, 122, 124, 126, 127, 153, 174, 341 Bota, 229 Bukhta Il’icha, 359 Bulla Deniz, 55, 101, 102, 103, 106, 108, 110–112, 142, 145, 146, 153, 165, 169, 171, 285, 286 Buzovny, 32, 125, 173, 174 Chakhnaglyar, 32, 35, 122, 126, 173, 174 Chalov Adasi, 55, 56, 57, 59, 73, 82, 83, 120, 125, 173, 181, 185, 186, 187, 191, 194, 296, 328, 337, 341 Chandagar-Zorat, 44 Cheleken, 56, 199, 200, 210 Chyragh, 56, 57, 174, 175 Darvaza, 212 Darvin Bank, 55, 56, 57, 58, 82, 120, 123, 125, 173, 174, 180, 182, 185, 186, 191, 194, 327, 336, 341 Denguizkul Khauzak, 215, 229 Duvanny Deniz, 43, 101, 102, 103, 104, 105–106, 122, 124, 127, 142, 145, 153, 165, 168, 172, 174, 341 Dzhanub Bank, 55, 56, 57, 58, 59, 82–91, 120, 136, 142, 249 Dzhanub-2, 145, 249, 250 Dzhanub-3, 250 East Gilavar, 56 Garasu Deniz, 146, 391 Gezdek, 122, 127 Gilavar, 56, 57 Goshadash, 56, 57 Gousany, 127, 135, 296, 341, 359 Griaznyi Vulkan, 212 Gubkin Bank, 56, 201, 206, 207 Gugurtly, 223

435

Gum Deniz, 33, 55, 56, 59, 135, 295, 296, 341, 359 Gyuneshli, 56, 57, 58, 120, 134, 138, 142, 145, 153, 172, 174, 175, 186, 191, 248, 249, 250, 251 Gyurgyany Deniz, 55, 56, 57, 59, 82, 120, 123, 125, 180, 182, 185, 191, 194, 296, 327, 336 Inchkhe-more, 233 Iolotan, 231 Kala, 32, 121, 124, 126, 172, 173, 174, 341 Kalmas, 44, 125, 135, 359 Kandym, 229 Kansu, 237 Karabagly, 44, 142, 145, 146, 153, 359 Karabakh, 56 Karabil, 215, 223 Karachukhur, 32, 34, 121, 124, 125, 135, 173, 296, 341, 359 Karadag, 125, 127, 135, 341, 359 Kazanbulag, 51 Kergez, 35, 127 Khali, 56, 57, 195 Khamamdag Deniz, 145, 146, 153, 391 Khara Zyrya, 101, 102, 103, 106, 142, 145, 153, 168, 172, 174 Kirmaku, 35, 36, 37, 38–40 Kokdumalak, 227, 229, 230 Korganov, 56 Kotur-Tepe, 199, 200, 210, 211 Kuba, 25 Kuruk, 216 Kushkhana, 127, 172, 174, 175 Kyapaz, 22, 56 Kyurdakhanly, 56 Kyurdamir, 44 Kyurovdag, 121, 125, 142, 145, 146, 153, 359 Kyursangya, 44 Kyzyltepe, 127 LAM (Laboratory of Air-born Methods for exploration) Bank, 56, 201, 206, 207, 212, 252, 253, 254 Livanov Bank, 201, 206 Livanov- East, 56, 252, 253 Livanov-Center, 56 Livanov-West, 56 Lokbatan, 18, 35, 42, 43, 124, 172, 174, 175, 257, 258, 259, 341 Makarov Bank, 92

436

Petroleum Geology of the South Caspian Basin

Oil and gas field (continued) Mardakyan Deniz, 56 Mashtagi, 32, 125, 173, 174 Mirbashir, 51 Mishovdag, 121, 125 Muradkhanly, 25, 44, 45, 46, 47, 147 Naftalan, 51 Naip, 223 Nardaran Deniz, 56 Neft Dashlary, 55, 56, 57, 58, 59, 60–73, 74, 75, 120, 125, 126, 134, 138, 172, 173, 174, 175, 179, 180, 181, 182, 183, 185, 186, 187, 191, 192, 194, 195, 248, 249, 250, 296, 309, 309, 311, 312, 326, 327, 328, 329, 337, 341, 391 Neftechala, 44, 127 Oguz, 57, 142, 145, 249 Ozek-Suat, 233 Padar, 359 Palchygh Pilpilasi, 55, 56, 57, 62, 73–82, 120, 134, 142, 145, 153, 173, 179, 185, 186, 191, 193, 194, 296, 327, 328, 337, 341 Patamdar, 135, 359 Pirallaghi Adasi, 120, 123, 125, 127, 173, 174, 180, 181, 182, 185, 186, 194, 327, 336, 341 northern fold, 55, 56, 57, 58, 82 southern fold, 56, 57, 58, 59 Pirsagat, 44, 124 pre-Cheleken Dome, 206 Puta, 124, 172, 174, 175 Rakushechnoye-more, 233 Ramany, 32, 34, 35, 124, 125, 172, 173, 174, 175, 341 Sabunchi, 32, 34, 35, 124, 125, 147, 172, 173, 174, 175, 341 Sakar, 223 Samantepe, 216, 229 Sandykachi, 215 Sangachal, 101, 102, 103, 142, 145, 165, 168, 172, 174, 341 Sangi Mugan, 146, 391 Saodan, 44 Setalantepe, 212 Shabandag, 40–41, 42, 122, 126, 174 Shakh Deniz, 56 Shakhpahty, 237, 238 Shatlyk, 223, 227, 228

Shorabad Deniz, 56 Shubany, 42 Shurtan, 216, 229 Siazan-Nardaran, 44 Starogroznenskoye, 233 Sulutepe, 32, 35, 126, 173, 174 Surakhany, 32, 34, 121, 124, 125, 135, 147, 172, 173, 175, 341, 359 Tarsdallyar, 25 Tasbulat, 237 Tenge, 237 Turkyany, 295, 296 Udchaji, 215 Umbaki, 43 Urtabulak, 229 Ushakov, 56 Uzen, 231, 233, 234, 236, 237 Yasamaly Valley, 122, 126, 174 Yashlar, 215, 231 Yashma Deniz, 56 Yuzhno-Zhetybay, 237 Zagly-Zeyva, 44 Zardob, 25 Zevardy, 229 Zhdanov Bank, 201, 206, 207, 252, 253 Zhetybay, 231, 233, 237 Zykh, 32, 34, 124, 125, 135, 359 Zyrya, 32, 59, 359 region, Adzhinour, 25 Apsheron Peninsula, 2, 32–43 Baku Archipelago, 22 Bukhara, 229 Charjou, 227, 229 Gyandzha, 25, 51 Kura-Iori Interfluve, 25 Monocline, pre-Caspian-Kuba, 43–44 Monocline, Siazan, 43 Paleogene-Miocene, 24 Sangachal-Duvanny Deniz-Khara Zyrya, 55 Shemakha-Gobustan, 25, 42 Talabi-Kainardzha, 25 Yevlakh-Agdzhabedi, 44–51 fractured volcanic, 45, 46, 47, 48, 49, 50, 51 petrographic studies, 48 porosity, 48 resistivity logs, 47 Oil, accumulations, 191–195 “benzene content,” 182

Subject Index boiling point, 175, 176, 177, 179 classification, 176–180 coking ability, 330 composition, 175–185, 176, 177–179, 184 composition vs. properties, 329–340 deep accumulations, 195–198 density, 176, 178, 180–185, 195, 326–329, 329–331, 338, 339, 340, 342, 344–346 dynamic viscosity, 340, 345–346 dissolved gas, 186 entropy, 325 fraction yield, 176 fractional composition, 175 gas saturation, 182 gasoline content, 335, 338, 339 GOR, 186 kinematic viscosity, 340, 342, 343, 344–346 maturity value, 221 migration, 195 potential, 210 properties, 175–185 resin content, 335, 338, 339, 342 viscosity, 340–345 Orogenesis, Oligocene-Miocene, 6 Orogeny, Alpine-Himalayan, 201, 224, 387 Hercynian, 217 Hercynic stage, 6 Himalayan, 52 Neo-Alpine, 201 Ostracods, 28, 76 Overpressured formations (see Reservoir, pressure, abnormally high)

P Pair-Variable empirical probabilities, 278–281 Paleogeographic curve, Apsheron, 116 Paleo-Tethys, 201 Paracypria loezyi Lal., 28, 76 Pelecypod embryos, 76 Pelecypods, 28 Peninsula, Apsheron, 4, 16, 17, 22, 28, 30, 32, 34, 35, 55–56, 91, 108, 109, 115, 116, 117, 119, 120, 134, 140–141, 142, 147, 161, 166, 172, 173, 175, 176, 178–180, 182, 185–191, 199, 200, 239,

437

240, 252, 253, 254, 300, 331–337, 353, 355, 357, 360, 387 Cheleken, 55–56, 199, 200, 204, 205, 210, 387 subsidence, 116, 117 Permeability, 50, 76, 102, 134, 302–308 Petrophysical parameters, 266, 268–269, 270, 287 Photomicrographs, 148, 160, 169, 172 Plain, Daghestan, 363 Plate, Scythian, Cretaceous limestones, 359 Platform, Russian, 52, 54, 116, 147, 239 Scythian-Turanian Epi-Hercynian, 52, 54 Poisson’s ratio, 153–155 Pore pressure, computation, 153 Porosity, mercury injection, 50, 51 secondary, 51 Pressure, abnormality factor, 156 Pre-Tethys Sea, 52 Probability curves, 382

R RAMIN program, 167 Rate of sedimentation, 361, 362 Reefs, 223, 230 Region, Apsheron, 117, 295, 340, 373, 389, 392 Gobustan, 4, 16–18, 20, 25, 41 Groznyy, 309 Karachukur-Zykh, 295 Karadag, 118 Lower Kura, 30, 117, 140–141, 142, 146 Nakhichevan, 2 Sangachal, 104 Talysh, 23, 24 Uzen, 236 Reservoir, caprock, 146, 241 carbonate content, 307 characterization, 113 classification, rock type, 133, 136 clay content, 307 effect of faults, 120 electrtical properties, 390–395, 397 flow rate, 303 formation resistivity factor, 153 formation resistivity index, 309, 311, 312 gas gravity, 72 gas/oil ratio, 72 lithology, 319

438

Petroleum Geology of the South Caspian Basin

Reservoir (continued) logging, 255–263 migration, 242 permeability, 76, 102, 134, 302–308 calculation, 308–313 log calculation, 308 petrophysical properties, 303 porosity, 102, 134 carbonates, 223 pressure, abnormally high (AHFP), 149, 150–152, 155–164, 166, 196, 237, 241, 242, 402 confining, 156 gradient, 149, 150, 152, 154, 163 pore, 161–164 relative clay content, 321–323 reserves, 243 residual water saturation, 308 residual water saturation vs. permeability, 310 resistivity, 255–263 cut-off points, 256–263, 274–275 index vs. permeability, 310 rock characteristics, 137 properties, 319–324 property distribution, 132–140 seals (see also caprock), 208 source rocks, 205–206, 220–221 specific surface area, 306 surface activity, 319, 323 temperature, 148, 150–164 tortuosity, 304 traps, 120–126, 205, 208, 221, 224, 241 water invasion, models, 398–400 waterflooding, 104, 105 Rheological models, 155 Ridge, Alyaty, 20, 21 Apsheron-preBalkhan, 206 Karpinskiy, 232, 233 Kirmaku, 35 Rift system, 217, 218 Aral-Murgab, 218 River, Araks, 9, 10, 44 Dzheirankechmes, 18, 21 Kura, 9, 10, 44, 117 paleo-Kura, 239 paleo-Ural, 239 paleo-Volga, 239 Pirsagat, 20 Ural, 117 Volga, 117, 360

Rocks, andesite-basalt, 12, 13 argillaceous, 140–148 carbonate, 4, 6, 21 Cenozoic molasses, 9 core data, 116, 140, 160, 284 deformation, 156 diabase, 2, 3 gabbro-diabase, 2 flysch, 1, 4 modeling, petrophysical, 381 ophiolitic, 1 particle size histogram, 171 permeability, 141 pore size vs. depth, 148–149 pore water, chemistry, 166, 168 pore-size distribution, 165 porosity, 198 porosity vs. depth, 158, 352, 354, 356, 357, 359, 360 porphyritic basalts, 12 quartz sandstones, 3 reef , 3, 4, 6, 212 sand/shale sequences, 156 sandstone, 2 silt fraction, 141 slate, 2 terrigenous, 3, 35 tuffaceous-terrigenous, 4 volcanic, 6, 12, 13, 26 clastic, 4 Mesozoic, 1 metamorphosed, 13–14

S Saatly, town of, 10 Sand-silt ratio, 284 Scanning electron microscope (SEM), 140, 148, 160, 169, 170, 172 Sea, shoreline, North Caspian, 117 Sediments, alluvial, 4 -deluvial, 5 argillaceous, 2, 140–148 breccia, 18 -plastic, 16 chlidolites, 28 clay, 140–146, 147 distribution, 147 transformation, 142, 159, 160, 161–164, 168

Subject Index coefficient of irreversible compaction, 353, 354–355 compaction, 171, 355, 358–365 carbonate, 363–365 terrigenous, 361, 362 deltaic, 4, 119, 203 depositional pattern, 118–119 diatoms, 62 distribution of clays, 131 of heavy minerals, 129–133 foraminiferal interval, 51 geochemical, 14, 15 geometry of, 148 grain-size, 197 hydrochemical effect, 164–168 Kimmeridgian-Tithonian, 221, 226, 227, 231 macrofossils, 284 microfossils, 284 molasse, 6 troughs, 16 numerical simulation, 365–371 rapid deposition, 206 regression models, 198 salinity vs. clay content, 167 sedimentation rate, 164 Tertiary, 221, 224, 355 Trask sorting coefficient, 370, 387 Seeps, 91 gas, 61 offshore, 60 oil, 199 Seismic sounding, 7 density model, 7 Sequences, Lower Archean, 14 Upper Archean, 14 Shelf, Turkmenian, 57, 204, 205, 251–254, 387 Siberian, western lowlands, 360 South Offshore Zone, Apsheron, 140–141, 142 Specific surface area, 303–308 Stage, Akchagylian, 11, 18, 28, 40, 41, 44, 107, 113, 204, 210, 284 Albian, 220 Apsheronian , 10, 18, 19, 28, 32, 40, 44, 106, 107, 204, 284 Aptian, 220 Baku, 28 Barremian, 220 Berriasian, 219, 220

439

Calovian, 217, 219 Cenomanian, 220 Chokrak, 25, 26, 32, 43, 44, 147 Conasian, 220 Diatom, 32, 41 Hauterivian, 220 Kimmeridgian, 204, 217, 219 Koun, 63, 64 Liassic, 6, 300 Maastrichtian, 220 Maykop Series, 25, 26, 43, 51, 205 Pontian, 28, 35, 37, 76, 113, 134, 284 pre-Baikal, 8, 9 Productive Series, 5, 18, 22, 24, 25, 27, 28, 29–30, 32, 35, 40, 41, 42, 44, 57, 58, 76, 78, 84, 88, 91, 92–93, 106, 107, 108, 110, 112, 113, 115, 116, 117, 118, 119, 126, 134, 138–140, 140, 142, 143, 144, 150, 160, 165, 172–175, 182, 185, 188–191, 203, 205, 239, 240, 241, 249, 250, 254, 255, 263, 271, 284, 300, 307, 309, 311, 320, 321, 324, 329, 387, 390, 405 core data, 239 lithology, 28, 30, 113 petrography, 129 stratigraphy, 29, 113, 116 Red Bed Series, 55, 203, 204, 206, 207, 210, 211, 219, 220, 239, 252, 253, 387 Sarmatian, 12, 205 Senonian, 44 Tithonian, 217, 219, 221, 224, 226, 227, 231 Turonian, 220 Valanginian, 30, 219, 220 Step, Badkhyz-Karabil, 214, 217 Bukhara, 212, 214, 217 Charjou, 212, 214, 217 Shakhpahty, 231 Uzen, 231 Zhetybay, 231 Steppe, Mil-Mugan, 5, 9 Stratigraphic section, Saatly, 11 Stratigraphy, regional, 203–205 Structure, Aligul, 210 Apsheron Bank, 195 Atashkyah, 40 Azeri, 248

440

Petroleum Geology of the South Caspian Basin

Structure (continued) Azi Aslanov, 79 Bakhar, 91, 94 Barinov, 252 Boya-Dag, 199 Bulla Deniz, 106, 109, 110 Chalov Adasi, 79, 83, 88 Chyragh, 248, 250, 251 Dagadzhik, 210 Dashgil, 21 Duvanny Deniz, 102 Dzhanub, 83, 88 Dzhanub-2, 251 Gum Adasi, 91, 92, 94 Gum Deniz, 91 Gyurgyan Deniz, 83 Kara-Tepe, 199 Khali, 79, 195 Khara Zyrya, 107, 110 Kum-Dag, 199 Kyapaz, 57 Kyzyl-Kum, 199 Makarov Bank, 92 Mardakyany Deniz, 195 Neft Dashlary, 79, 83, 252 Palchygh Pilpilasi, 79, 83 pre-Caspian monocline, 17 Shakh Deniz, 91, 94 Ushakov, 251 Zapadno Cheleken, 210 Subsidence, Apsheron Peninsula, 116, 117 Subzone (block), Mil-Khaldan, 6 Saatly-Kyurdamir, 6 Suite, Balakhany, 31, 32, 34, 58, 59, 62, 67, 78–79, 83, 84, 8, 90, 92–93, 94, 115, 117, 134, 137, 138, 139, 181, 183, 186, 255, 298, 300, 302, 328, 341, 390, 406 Kala (KaS), 30, 32, 34, 58, 59, 62, 67, 71, 73, 74, 75, 76, 79, 81, 82, 84, 87, 91, 93, 115, 117, 120, 125, 126, 127, 134, 138, 145, 150, 173, 181, 183, 185, 186, 187, 190, 192, 193, 194, 295, 296, 328, 341, 355, 390 Kirmaku (KS), 30, 32, 34, 35–36, 38, 58, 59, 62, 67, 71, 76, 78, 79, 81, 83, 84, 87, 90, 93, 115, 117, 120, 121, 122, 123, 124, 125, 126, 127, 138, 139, 173, 174,

175, 181, 183, 186, 190, 191, 192, 194, 255, 260, 328, 390 Nadkirmaku Clayey (Shaly) (NKG), 30–31, 32, 34, 62, 115, 117, 124, 125, 138, 139, 173, 174, 181, 182, 183, 190, 255, 288, 390 Nadkirmaku Sandy (NKP), 62, 58, 59, 67, 76, 78, 83, 84, 87, 90, 93, 94, 101, 102, 107, 109, 115, 117, 124, 125, 126, 127, 134, 138, 139, 145, 150, 173, 174, 186, 190, 192, 193, 194 Pereryv, 31, 32, 34, 58, 59, 62, 67, 68, 78, 84, 86, 90, 93, 94, 101, 102, 107, 109, 115, 117, 119, 134, 138, 139, 150, 174, 181, 183, 190, 192, 249, 250, 255, 263, 271, 328, 341, 390, 406 Podkirmaku (PK), 30, 32, 34, 35, 38, 58, 59, 62, 67, 71, 72, 74, 78, 79, 82, 84, 85–86, 87, 88, 90, 93, 94, 95, 101, 115, 117, 120, 121, 122, 123, 124, 125, 126, 138, 150, 173, 181, 182, 183, 185, 186, 187, 190, 191, 192, 193, 194, 260, 328, 341, 390, 406 Sabunchi, 31, 32, 34, 58, 59, 62, 84, 92, 115, 117, 137, 138, 140, 142, 341, 390 Surakhany, 31, 32, 34, 58, 59, 62, 84, 115, 117, 138, 140, 142, 390 Surface activity, 319–324 Survey, CDP, 248, 251, 254 gravity anomaly, 251 Synclinorium, Kichikdag-Umid, 110 Shemakha-Gobustan, 20

T Talysh foothills, 1, 4 region, 23, 24 Technology, simulation, flowchart, 246 Tectonic escape, 201 Temperature, geothermal gradient, 148, 149, 152, 161–164, 196, 205, 354 Tethys Sea, 201 Theory of information, 290–293 Thermobaric conditions, 164 Thermographic studies, 140 Thickness of pore-water film, 309, 313

Subject Index Threshold, Apsheron, 16, 56, 57–91, 134, 200, 210–212, 249 Traps, anticlinal faulted, 120, 128 nonfaulted, 120, 128 classification, 120 distribution, 120 lithologic, 120, 128 stratigraphic, 120, 128 Trend, Apsheron—pre-Balkhan, 248, 248–251, 251–254 Tumarkhanly-Germelin, 26 Trough, Baku, 18, 35, 40, 41 Dzheirankechmes, 101 Gobustan-Apsheron, 3 Iori-Adzhinour, 3, 6 Kelkor, 206 Kura, 3, 6 Lower Kura, 101 Middle Kura, 147 South Mangyshlak, 234, 236 Western Kuban, 359 Yevlakh-Agdzhabedy, 3, 6 molasse, 16 periclinal, 16

U Undercompaction, 241 Uplift (see also high), Airantekyan, 21 Alyaty, 21 Azi Aslanov, 73 Bibieibat, 35, 40 Chyragh, 251 Duvanny Deniz, 102 Dzharly, 6 Geokchai-Saatly, 6 Gubkin, 252, 253, 254 Gyuneshli, 251 Karachukhur-Zykh, 35 Karadzhaly, 6 Karakum, 212, 217, 219, 220 Kilyazi-Kransnovodsk Zone, 147 Koturdag, 21 Kyanizadag, 18 Kyurdamir-Saatly, 6, 14, 44 Livanov-East, 252, 253 Malay, 214–217 Mary-Serakh, 214, 217, 220 Mil, 6 Muradkhanly, 6

Saatly, 5, 6, 15 Sangachal, 102, 104 Shabandag, 41 Shubany, 40 Sor-Sor, 6 Tourogai, 18 Zardob, 6 Zhdanov, 254

V Viscosity, crude oil, 340 oil, Engler, 38 kinematic, 340, 342–346 Volcanic, breccia, 19, 21 chemical analyses, 13 magmatic, 16 Volcanoes, mud, 5, 16–21, 62, 208 Airantekyan, 21 Akhtarma, 18 Bogboga, 35 cones, 17 Dashgil, 21 definition, 16 gases, 18 Gegerchin (Kirdag), 21 Greater Kyanizadag, 18 Gyulbakht, 18 Koturdag, 21 Kushkhana, 18 Kyzyltepe, 18 Lokbatan, 18-20, 42 Lokbatan-Otmanbozdag group, 18–19 Makarov Bank, 95 Otmanbozdag, 18 Pilpilya, 18 region of, 16–17 Sarynja, 18 Shongar, 18 Tourogai, 18 trace elements, 18 Turkmenistan region, 199 Volchy Vorota (Wolf Gate), 40

W Waterflooding, 398

441

442

Petroleum Geology of the South Caspian Basin

Water, chemical composition, 189 formation, properties, 188–191 Productive Series, 189 salinity, 189–191, 192–194 saturation, 308, 310 Well logs, Resistivity logs, calculation of pressure, 152 sonic, 153 Well, super deep, Saatly, SD-1, 9–15

X X-ray diffractometer, 140, 142, 160

Y Yasamaly Valley, 18, 19, 40

Z Zardob magnetic maximum, 7 Zone, Alpine, 14 geosynclinal, 52 Chikislyar-Okarem, 199 Dzharly-Saatly, 26 island arc, 15 Mil-Mugan, 26 Transcaucasus, 14 Vandam, 1