Carbonate Reservoir Rocks

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Carbonate Reservoir Rocks

Ksenia I. Bagrintseva

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Cover design by Kris Hackerott

Library of Congr ess Cataloging-in-Publication Data:

ISBN 978-1-119-08357-3

Printed in the United States of America

10 9 8 7 6 5 4 3 2 1

This book is dedicated to the Academician George V. Chilingar (Chilingarian), one of the foremost experts of carbonate rocks in the World. His studies on

carbonate reservoir rocks were indeed i nvaluable. He was the first American Petroleum Geologist elected to the Russian Academy of Sciences, and an oil field

in Iran was named after him: “Chilingar”.

vii

Contents

Introduction xi

Acknowledgements xv

1 Carbonate Reservoir Rock Properties and Previous Studies 11.1 Brief Review of the Previous Studies 11.2 Major Terminology 4

2 Major Sedimentational Environments of Carbonate Rocks in

Sedimentary Basins 132.1 Types of Carbonate Buildups 132.2 Open Shelf Edges 152.3 Genetic Types of Limestones and Dolomites 202.4 Effect of Post-Depositional Processes on the Void Space Formation 25

3 Conditions of Void Space Formation in Carbonate Rocks of

Various Compositions and Genesis 293.1 Carbonate Rock Solubility and the Effect of Certain Factors on

the Calcite and Dolomite Solubility Relationships 293.2 Pore Space Formation in Carbonate Rocks of Various Genesis 333.3 Formation of Fracture Capacity Space and Fluid Filtering in

Fractured Rocks 37

4 Reservoir Rock Study Techniques 434.1 Major Evaluation Parameters and Laboratory Techniques of Their

Determination 434.1.1 Porosity 434.1.2 Residual Water Saturation 44

4.2 Method By Bagrintseva: The New Technique of Fracturing and Vugularity Evaluating through the Capillary Saturation of the Carbonate Rocks with Luminophore 47

4.3 Determination of Fracture Openness 524.4 Method By Bagrintseva-Preobrazhenskaya: The Evaluation

Technique of Rock Hydrophobization By Wetting Contact Angle 54

viii Contents

4.5 Method By Shershukov: New Methodological Approach to the Theoretical Permeability Calculation from Mercury Injection Porometry 60

5 Natural Oil and Gas Reservoirs in Carbonate Formations of the

Pre-Caspian Province 715.1 Brief Review of Geology and Major Oil and Gas Accumulation

Zones in the Pre-Caspian Province 715.2 Karachaganak Oil-Gas-Condensate Field 77

5.2.1 Field Geology and Lithology of the Productive Sequence 775.2.2 Major Reservoir Rock Types 775.2.3 Specifics of the Void Space Structure 815.2.4 Carbonate Deposits Fracturing 925.2.5 Correlations of the Major Parameters 935.2.6 Reservoir Rock Types 96

5.3 Zhanazhol Oil-Gas-Condensate Field 995.3.1 Field Geology and Lithology of the Productive Sequence 995.3.2 Major Reservoir Rock Types 1095.3.3 Specifics of the Void Space Structure 1115.3.4 Carbonate Deposits Fracturing 1185.3.5 Correlation of the Major Parameters 1205.3.6 Reservoir Rock Types 1265.3.7 Major Conclusions 129

5.4 Tengiz Oil Field 1295.4.1 Field Geology and Lithology of the Productive Sequence 1295.4.2 Major Reservoir Rocks Types 1325.4.3 Specifics of the Void Space Structure 1385.4.4 Carbonate Deposits Fracturing 1425.4.5 Correlations of the Major Parameters 1485.4.6 Reservoir Rock Types 1515.4.7 Major Conclusions 153

5.5 Korolevskoye Oil Field 1535.5.1 Field Geology and Lithology of the Productive Sequence 1535.5.2 Major Reservoir Rock Types 1565.5.3 Specifics of the Void Space Structure 1595.5.4 Carbonate Deposits Fracturing 1605.5.5 Correlation of the Major Parameters 1655.5.6 Reservoir Rock Types 165

5.6 Astrakhan’ Gas-Condensate Field 1675.6.1 Field Geology and Lithology of the Productive Sequence 1675.6.2 Major Rock Types 1685.6.3 Specifics of the Void Space Structure 1705.6.4 Carbonate Deposits Fracturing 1745.6.5 Reservoir Rock Types 179

Contents ix

6 Natural Oil and Gas Reservoirs in the Timan-Pechora Province 1816.1 North Khosedayu Oilfield 181

6.1.1 Production Deposits Lithology 1816.1.2 Limestone Vugularity and Fracturing 1896.1.3 Reservoir Rock Types 1906.1.4 Specifics of the Carbonate Rocks’ Pore Space Structure 1936.1.5 Main Conclusions 206

7 Types and Properties of the Riphaean Carbonate Reservoir Rocks 2097.1 Yurubchenskoe Gas and Oil Field 209

7.1.1 Lithology of the Riphaean Productive Sequence 2097.1.2 Void Space Morphology of the Riphaean Carbonates 2127.1.3 Vugularity of the Riphaean 2167.1.4 Pore Space Structure 2187.1.5 Fracturing of the Riphaean Carbonate Rocks 2207.1.6 Riphaean Carbonate Rocks Filtering-Capacity Reservoir

Properties 2237.1.7 Main Conclusions 230

8 Theoretical Fundamentals of the Reservoir Rock Evaluation and

Forecast 2318.1 Void Space Structure of Various Genesis Carbonate Deposits 2318.2 Residual Fluid Saturation in the Carbonate Reservoir Rocks 2378.3 Evaluation-Genetic Classification of the Carbonate Reservoir

Rocks By Bagrintseva 2498.3.1 Distinctive Features of the Pore-Type Carbonate Reservoir

Rocks. 2528.3.2 Distinctive Features of the Fracture Type and Complex-Type

Carbonate Reservoir Rocks. 2538.4 Distribution Models of Different-Type Reservoir Rocks 253

9 Major Factors Determining the Formation and Preservation of

High-Capacity Carbonate Reservoir Rocks 2599.1 Conditions for the Formation of High-Capacity Reservoir Rocks 2599.2 Evaluation of the Fracturing Role in the Development of the

Complex-Type Reservoir Rocks 2639.3 Correlations between Major Reservoir Rock Evaluation Parameters 2689.4 Criteria of the Reservoir Rock Forecast

and Evaluation 276

Conclusions 285

Attachments 287

References and Bibliography 319

Index 329

xi

Introduction

Any improvement of the mineral resource base is only possible if the nature of the emergence, evolution, parameter estimation of high grade reservoir rocks at great depths is known and a theory of their forecast is developed. Over 60 percent of world oil production is currently associated with the carbonate reservoir rocks. The exploration, appraisal and development of these fields are significantly complicated by a number of factors. These factors include the structural complexity of the carbonate complexes, variability of the reservoir rock types and properties within a particular deposit, many unknowns in the evaluation of fracturing and its spatial variability, and the preserva-

tion of the reservoir rock qualities with depth.The main objective of the present-day studies is discovering patterns in the reservoir

rock property changes of carbonate deposits of different genesis, composition and age. A short list of the unsolved issues includes: the role of facies environment in the car-bonate formation; the major geologic factors affecting the formation of high-capacity reservoir rocks and preservation of their properties; recommendations as to the use of the new techniques in studies of the structural parameters; and establishing a correla-tion between the major evaluation parameters.

A poorly developed knowledge domain is still the evaluation of the role of frac-tures in the capacity and hydrocarbon filtering of the different-type carbonate reservoir rocks. The author devoted a great deal of attention to the development of methodolo-gies and techniques, which improve the reliability of evaluating the vugginess, fractur-ing, and void (pore, fracture, cavity and vug) space structure.

The author perfected an earlier developed new methodology in studies of the void space structure (Bagrintseva’s method, 1982). This methodology is based on carbonate rock saturation with luminophore and on special techniques in processing of photo-graphs made under UV light. The luminophore technique was combined with the ras-ter electron microscopy and its variation, the studies under the cathode luminescence regime. This combination enabled a more detailed study of the reservoir void space, the nonuniformity in the open fracture evolution, their morphology, length and variability of openness. Over recent years these techniques have found wide application.

The book devotes special attention to describing techniques for improving reliabil-ity in the identification and evaluation of the reservoir rocks with complex void space structure. These new techniques proposed and meticulously developed by the author enable the evaluation of the void space structure, the reservoir rock type, the identifica-tion of vugs, cavities and fractures, their morphology, interconnectivity, openness and

xii Introduction

the differentiation of fractures in terms of their importance to the fluid filtering. The book includes a number of photographs obtained with the UV-light source after the rocks were saturated with luminophore. These illustrations show significant variability and diversity of the fractures in carbonate rocks of different composition and genesis.

Among the poorly developed but important issues is the study of the carbonate rock surface properties. New methodological studies conducted by the author and her assis-tant (K.I. Bagrintseva and T.S. Preobrazhenskaya) came up with the wettability study technique based on the wettability contact angle. The technique opened a possibility of identifying the nonuniform wetting of porous and fractured carbonates as well as the differentiated and integral characteristics of certain core samples, which allowed for the rock wettability identification within certain intervals.

The empiric correlation between the wetting contact angle and the type of the rock-saturating fluid was established. This correlation allows to identify the rock productiv-ity, the boundaries of intervals with different hydrocarbon composition in the carbonate sequence, and to fine-tune the oil-water and gas-oil contacts’ location.

Some other issues were theoretically substantiated. They include the patterns in the spatial positions of different type reservoir rocks within sequences and the forecast and identification criteria of the reservoir rock types and properties within multi-facies intervals. The 45-year-long carbonate reservoir studies allowed the author to solve a number of theoretical issues, to develop the Evaluation-Genetic Classification, and to suggest the new methodological studies for better understanding the fluid filtering mechanisms through complex porous-fractured media. Fundamentally new data were obtained, which show the importance of the interconnection between the filtering-conducting elements. These studies were conducted by I.V.Shershukov and enabled the merger of singular indications into a system. Dr. Shershukov authored the Chapter devoted to the processing of porometric curves.

The studies of particular oil fields were directed toward identifying the effect of lithogenetic and structural specifics, composition and stratigraphic age of deposits on the lithophysical properties, and toward establishing the role played by the pore space geometry on rock capacity and permeability. For this purpose, beside the defining parameters, a number of structural parameters were also determined: the range and share fraction of the rock pore radiuses, the average radius of the entire pore popula-tion, the average radius of the filtering-controlling pores, and the threshold value for a system of interconnected fractures. The determination of the structural parameters enabled the analysis of the correlation between the structural parameters and reser-voir rock properties, and the derivation of empirical correlations. Special attention was devoted to fractures, which play a major role in the filtering processes.

In a lengthy reservoir formation process, the nature and direction of the effect on the soluble carbonate rocks continually changes, the structural features of the void space change in space and time, numerous reservoir rock types emerge, which are different in their complexity and have substantially different major parameters.

The author believes that currently used carbonate rock reservoir terminology is highly confusing and ambiguous, including the understanding of the reservoir rock types, the residual water saturation, and the terms of vugularity sand fractureness. So the author developed her own approach and pays special attention to properly naming different type reservoir rocks, reflecting their genesis, properties and roles.

Introduction xiii

The book includes three major sections. The first one deals with the carbonate rock sedimentational environments and void space formation in carbonate rocks of differ-ent genesis. The books shows that the specific formation conditions of complex void space in carbonates of different lithofacies composition predetermine the direction and intensity of postdepositional alterations.

The second section presents the new techniques, methods developed by the author for evaluation parameters, void space structure, and especially fracturing studies. New methodologies are described allowing for taking into account the connectivity of the conducting elements in the estimation of theoretical permeability of the fractured-porous media. A brief description of the reservoir rock types and properties in the Paleozoic carbonates of the largest oil and gas fields on the East-European Platform and in the Siberian Riphaean is provided. The integrated comprehensive studies of the lithophysical properties of productive deposits were used to summarize the actual data about the value, nature of changes of the capacity/porosity, permeability, and void struc-ture carbonate rock parameters. The data shows the variability of properties in the well sections of a number of large fields in the Pre-Caspian Depression and Timan-Pechora Province. The principal correlations between the evaluation parameters are included, the correlations typical for individual fields (Tengiz, Karachaganak, Korolevskoye and others) are checked, and the spatial reservoir rock variability in the natural reservoirs of the Pre-Caspian and Timan-Pechora provinces is established.

The reservoir rock description of the North Khosedayu field is based on the data obtained by Dr. P.V. Shershukov. Geology and properties of the Yurubchenskoe gas-oil field Riphaean reservoir rocks are briefly described.

The third section is theoretical. It deals with the main pattern in carbonate reser-voir rock changes. It emphasizes the role of the major factors facilitating the formation of favorable void space and the preservation of high-capacity reservoir rocks at great depths. It shows the similarity of the parameters’ correlations and similar trends in their changes. The Evaluatiion-Genetic Classification is developed for carbonate reservoir rocks of different types and classes.

Based on the theoretical considerations, the author proposed the Conceptual Scheme reflecting the sedimentation environment role in the reservoir rock types and proper-ties evolution. This scheme allows for the reservoir rock potential forecasting.

xv

Acknowledgements

The author acknowledges the contribution to the experimental and theoretical studies by Dr. G.E. Belozerova, N.V. Lysak, T.S. Preobrazhenskaya, T.G. Kuts, N.N. Potapova, V.B. Rabutovsky, E.N. Gadalina, E.V. Ovcharenko, R.S. Sautkin, without whose help and participation the book would not have materialized.

Special thanks to Grigoriy I. Shershukov for his software development, which allowed computer processing of luminophore capillary saturation photo images.

The author appreciates the assistance in the English language book preparation by Dr. I.V. Shershukov and G.I. Shershukov.

1Carbonate Reservoir Rock Properties and Previous Studies

1.1 Brief Review of the Previous Studies

Carbonate studies become ever more important in view of large oil and gas discoveries in carbonate reservoirs at various depths. Commercial accumulations are found in rocks from the Mesozoic to the Cambrian. The oil and gas discoveries in carbonates at depths over 5,000 m confirmed the potential of deeply-buried carbonate sequences. At the same time they illuminated the difficulties as the reservoir rocks with a complex void space structure and intense fracturing are developed at great depths. In the appraisal process, significant variability of reservoir properties in the productive intervals and difficulties in the reservoir rock type determination were identified. These are the problems in the hydrocarbon reserves evaluation.

Numerous writers contributed to the studies of the carbonate reservoir rocks. Among them are the Russian language publications by A.I. Konyukhov (1976), E.M. Smekhov (1974, 1985), F.I. Kotyakhov (1977), K.I. Bagrintseva (1965, 1977, 1982, 1986, 1988, 1996), Ya.N. Perkova (1966, 1982, 1985), L.P. Gmid (1968, 1970, 1985), Yu.I. Maryenko (1978, 1986), G.E. Belozerova (1979, 1986), V.N. Kirkinskaya (1981), B.K. Proshlyakov (1981, 1987), V.G. Kuznetsov (1981), A.N. Dmitrievsky (1982, 1986, 1992), T.T. Klubova (1984), as well as the English language publications by G. Archi (1952), D. Agoulier (1978), A.E. Levorsen (1959, 1970), T. Sander (1967), G.V. Chilingar, G. Bissel and F. Fairbridge (1970, 1992), J.L. Wilson (1980), T. Golf-Racht (1986) and many others.

2 Carbonate Reservoir Rocks

Usually in the studies of complex reservoirs so common in carbonate sequences two major factors are only briefly considered. These factors are: first, the fracturing allow-ing the fluids to filter/flow; second, the secondary voidness emerging mostly due to the dissolution and leaching processes. The vugularity increases the useful reservoir capac-ity and correspondingly increases the recoverable hydrocarbon reserves. Long-term postdepositional alterations equally affected limestones and dolomites and provided for a wide range of reservoir types. A complex structure of pores in the carbonates is associated with the elevated rock solubility as the effect of numerous multidirectional factors such as the chemical composition and rate of filtering of underground waters, temperature, pressure, etc.

The effect of lithology on the carbonate fracturing is being studied in-depth. Experimental studies of the association between the fracture formation and rock physi-cal properties showed that rock plasticity is controlled by structure, porosity, content of the insoluble residue, and the extent of silicification, recrystallization and calcitization. The crystalline (especially microgranular) limestones display the lowest plasticity. The highest plasticity factors are attributed to biomorphic rock varieties. The correlation between plastic properties, porosity and pore channel sizes was established. The recrys-tallization processes unevenly affect the plasticity coefficient: under recrystallization, with the formation of a new crystalline structure, the rock plasticity increases. In the carbonates of a non-uniform structure the rock plasticity declines after recrystalliza-tion. The plasticity of unevenly dolomitic limestones behaves similarly. Increase in the rock clay content causes the plasticity changes. That is particularly obvious in the rocks of the chemo-biogenic genesis.

Comprehensive studies of the carbonates’ elastic deformations by N.N.Pavlova, 1975, showed the effect of composition and void type on the rock deformation pro-cesses, changes in their strength and the appearance of additional void spaces.

The decompaction effect is especially important: the forces similar to tectonic forces completely neutralize the rock compaction caused by the action of effective stress. Obviously under natural conditions the effect of the tectonic stress on the void space formation is much more complex than in the experiments. It is important that the for-mation of voids in the natural environment is much higher, affected by dissolution and leaching. These processes are differently manifested in porous-permeable and compact, low capacity rocks; they are most active in the fractured rocks. Many writers indicated a positive effect of the dissolution and leaching processes on the vugularity development in carbonate rocks including at great depths (B.K. Proshlyakov, 1975; E.M. Smekhov, 1968; K.I. Bagrintseva, 1980, 1986). They, however, did not analyze why the vugs occurred in some areas and not in others. It is important that the complex reservoir rock types develop under the effect of the combination of reviewed factors.

Numerous studies deal with the fracture openness, changing their capacities from a bed to a core sample, identification of open multidirectional fractures at depth. The the-oretical studies of the nature and extent of the fractured rock deformations were con-ducted by Yu.P. Zheltov (1966), V.M. Dobrynin (1979), V.N. Maydebor (1971, 1980), and the experimental studies by D.V. Kutovaya (1962), I.A. Burlakov and G.I. Strukov (1978).

V.N. Maydebor (1971, 1980) rejected a probability of significant deformations in the fractured reservoir rocks of the oil beds. He believed that the microfracture

Carbonate Reservoir Rock Properties and Previous Studies 3

compressibility factor is commensurate with the matrix pore compression factor in the areas adjacent to the micro-fractures. E.M. Smekhov (1982) believed that the fracture permeability declines less intensely or remains constant with the increase in the rock depth. E.S. Romm (1985) noted that at depth the fracture openness of productive frac-tured reservoir rocks are similar for different fracture systems and average 20–30 μm. As K.I. Bagrintseva et al. (1986) showed, average fracture openness of 10 μm in the Karachaganak field provided fracture permeability of 5 to 182 mD in low-capacity beds.

Based on rock deformation theory, V.M. Dobrynin (1970, 1990) estimated the effect of structural parameters (vugularity and fractureness) on the rock compressibility. He found that the vug geometry and size and their deviation from the regular spherical shape are very important in the estimation of the compressibility factor. Substantial deviations of the natural vug form from the most stable spherical geometry must result in an increased compressibility of the secondary voids. However, if microfractures are present, the secondary void’s compressibility factor can even decline under the increased stress due to a partial closing of the micro-fractures. Obviously, natural vug’s geometry is significantly different from the theoretical spherical voids. For this reason the compression process of the fractured-vugular rocks has a more complex nature. The growth of the perfectly-shaped secondary crystals shows that the vugs preserve their openness for a long time.

The existence of continuous open fractures in the fractured rocks is unlikely under the natural environment even in the conditions of the rock’s complex state of stress. The total microfracture closing in the natural reservoir must be countered by protrusions, inclusions of the rock fragments and other surface irregularities. These irregularities in the fracture surfaces substantially decrease their useful capacity but provide for the preservation of the openness and the existence of available void space.

There is no consensus currently on the fracture capacity estimation issue (A.A. Trofimuk, 1961; E.M. Smekhov, 1968, 1970; M.X. Bulach, 1972; K.I. Bagrintseva, 1977, 1997, 1998; V.M. Dobrynin, 1983, 1990). This is a controversial issue but the discovery of a number of large fields in the fractured rocks allows saying that the capacity of the fractures proper is substantial.

The author cannot agree with those writers who separate the capacity of the fractures proper from the expansion cavities along these fractures and the porous zones which develop over them. It is impossible to separate these voids either in the natural reser-voir conditions or in laboratory core studies. And many writers (e.g. D.S. Sokolov; K.I. Bagrintseva) believe that should not even be attempted.

Photographs of the carbonate core samples saturated with a luminophore show a complex structure of different type voids. They demonstrate impossibility on a num-ber of occasions to estimate the fraction of pores, vugs, and fractures/fracture cavi-ties in the total rock capacity. It is difficult to imagine the formation process of the opened tectonic fractures whose openness would be preserved without change dur-ing long periods of fluid filterings in them, especially in highly soluble carbonates (K.I. Bagrintseva, 1982, 1998). Even with a great number of the latest generation open fractures in a tight interbed, the secondary voids form in the productive bed because of the leaching and removal of the soluble portion of the carbonates. It is unrealis-tic to try to separate these beds and selectively evaluate them without establishing three important criteria:first, ensure that on the whole the productive bed includes

4 Carbonate Reservoir Rocks

morphologically different types of voids; second, identify which types (fractures, pores or vugs) are dominant for the fluid filtering; and third, determine from which type of voids the fluids would be produced during development (V.D. Victorin, N.A. Lykov, 1980).

In studying complex media, it is important to identify the dominant fracture ori-entation and their communicability. Using the ray-path method, I.P. Dzeban (1980) conducted a detailed study of the fractures and vugs effect on the elastic wave propaga-tion velocity. He conducted a broad experimental study of the fractured-vuggy rocks’ acoustic properties and suggested the theoretical substantiation of the processes.

What is important is that the Dzeban’s produced data about the fracturing (and espe-cially microfracturing) effect on the elastic wave propagation velocity are different in principle from the results derived from the time-average equation. This proves that the equation is applicable only for the purely pore-type reservoir rocks.

I.P. Dzeban (1981) found a correlation between the P-wave and S-wave propagation velocities and the vugular capacity for limestones with intense vug development. His conclusions are:

(1) The P-wave propagation velocities calculated for the porous-vugular reservoir rocks are overestimated compared to those found from the time-average equation; and as the vug capacity increases, these velocities are significantly higher.

(2) The P-wave propagation velocities calculated for the porous-fractured reservoir rocks are underestimated compared to those found from the time-average equation.

Dr. Dzeban proposed to use this pattern for the identification of the pore-fracture type and fracture-pore type reservoir rocks based on the underestimation of porosity value derived from NGK (GGK) compared with the porosity value as determined from the time-average equation. Comparing the elastic wave propagation velocities in the porous and vugular-porous media derived in the experiments, Dzeban concluded that the wave propagation velocity in the vugular rocks is much higher. His explanation is in the unequal compressibility of the pores and vugs.

The conceptual issues of the identification and evaluation of complex types carbon-ate reservoir rocks using logging were published in monographs of R. Derbant (1972), V.M. Dobrynin (1983), V.N. Dakhnov (1960, 1980), B.Yu. Wendelstein (1986), B.A. Alexandrov (1979), S.S. Interberd and G.A. Shnurman (1984), V.I. Ilyinsky and A.Yu. Limberger (1981), B.Yu. Wendelstein and M.G. Latysheva (1986), G.M. Zoloyeva, N.V. Farmanova and N.V. Tsareva (1977), and V.F. Kozyar (1986). Most writers indicate the ambiguity of log data in the reservoir rocks with a complex void space structure and propose to use the combination of log techniques.

1.2 Major Terminology

Special note for the English language readers (compiled by the translator and the author):While preparing this book, we have paid special attention to the consistency of the English language translation between this book and a previously published one in the English language, namely:

Carbonate Reservoir Rock Properties and Previous Studies 5

“Atlas of Carbonate Reservoir Rocks of the Oil and Gas Fields of the East European and Siberian Platforms.” / Edited by K.I. Bagrintseva. – by K.I. Bagrintseva, A.N. Dmitrievsky, and R.A. Bochko. – Moscow, Russia, 246 pp.: ill.

The Atlas provides rich illustrations and data of carefully selected core samples of dif-ferent type reservoir rocks from the major carbonate oil fields, representing most for-mer Soviet Union locations. The Atlas and this book by Bagrintseva are complementary.

Dr. Ivan Shershukov has made a proof-check of the translation and terms and com-piled the below English language / terms explanations, hoping that they might ini-tially facilitate your reading. Further and more detailed explanations are done by Prof. Bagrintseva in respective chapters of this book.

Here are several notes on the major terms, as used by the author.

The correct term, as

used by Bagrintseva

in the Atlas and down

this book:

Meaning (explanation of the

usage):

Alternative or similar existing

names (“conflicting” terms):

Pore A small void. Capillary forces

act in such small voids,

either “holding” fluid

(under wettable conditions)

or pushing it out (e.g.:

water under hydrophobic

conditions). So there is

some residual water satura-

tion in pores.

Some writers use the name “pore”

in a wide sense, naming this way

fractures and vugs. See more

below about “porosity” and

“capacity” terms.

Porosity A percentage showing volume

of all pores developed in the

rock matrix. It is evaluated

for pore-type and vug-pore

type reservoir rocks.

Bagrintseva does not use this term

in regards to fractures and vugs/

cavities in complex-type reser-

voir rocks, where permeability is

provided by fracture elements.

Micro-pores, or sub-

capillary pores

So called pores with a radius

less than 0.1 μm. So they

are completely containing

residual water.

Bagrintseva uses the cutoff value

of 0.1 μm, considering the

thickness of water film, which is

bonded to the wettable surface.

See her chapter about residual

water saturation.

Fracture capacity A percentage showing volume

of all fractures and fracture

cavities developed in the

rock matrix.

Fracture “porosity”. Bagrintseva

does not use the term “porosity”

in regard to all complex-type

reservoir rocks, where tight rock

matrix does not provide perme-

ability, and permeability is due

to fracture system.

6 Carbonate Reservoir Rocks

Vug capacity A percentage showing volume

of all vugs developed in the

rock matrix.

Vug “porosity”. Vugs’ capacity does

add value to the porosity in vug-

pore type reservoir rocks. But

in vug-fracture type reservoir

rocks, the term porosity would

mislead the scientist because

pore matrix is non-permeable

and contains residual water;

vugs and fractures do not hold

and contain residual water.

Vug A large void (isometric or

elongated). Capillary

forces do not act in such

large voids. So there is no

residual water saturation

in vugs and all vug space is

effective for oil and gas.

“Pore” would be the wrong term.

“Cavity” is one of the types of

vugs. The book uses the term

“vug” more often than the term

“cavity”; and sometimes it is not

possible to distinguish between

them. Still, it would be correct

to leave the term “cavity” for the

elongated voids, developed along

fractures, while the term “vug”

comprises more isomentric void,

and sometimes might include

cavities as well.

Cavity or fracture

cavity

A large elongated void. The

widening of fracture open-

ness leads to creation of

cavity along fracture. So

cavity is an elongated vug.

All space of the cavity is the

effective volume for oil and

gas, since capillary forces

do not act in fractures and

cavities.

Vug – it is a more widely used

term. See the explanation above.

Void There are different types of

voids in the rock: pores,

vugs, fractures, and frac-

ture cavities. Sometimes

it is hard or impossible

to distinguish between

fractures and fracture cavi-

ties, or between vugs and

cavities.

Space. Empty volume.

Carbonate Reservoir Rock Properties and Previous Studies 7

Porous, vuggy,

fractured

These are general usage

words, describing rock

properties. They do not

describe the pore function

in the rock, nor the vug

function, nor the fracture

function in terms of reser-

voir type.

Bagrintseva insists on not-using

these terms in regards to the

names of reservoir rock types.

The reason is that many rocks

might have some small amount

of pores and fractures, which

are not sufficient for creat-

ing permeable pore matrix, or

permeable fracture system, and

so are not sufficient for creating

a reservoir rock type. Hence,

using such words is only good

for general rock description but

not for naming the reservoir

type.

Pore-type A special usage term, describ-

ing reservoir rock type.

Pore system provides

sufficient permeability

and porosity. Lower cutoff

values of such parameters

are established by the book

author.

“Porous type” would be a wrong

term since pores are sometimes

not enough or too small to pro-

vide for sufficient reservoir rock

permeability.

Pore channels control-

ling to permeability

Pores that serve as main

channels and provide the

main permeability, as

derived from the calculated

poromentric curves.

Filtering pores or filtrating pores

Fracture-pore type One of the pore-types. The

pore matrix is poor, but

still sufficient for creat-

ing enough permeability

through pore channels.

Effective porosity is low:

so effective capacity of frac-

tures is a valuable add-on.

Bagrintseva points out that the last

word in the name of reservoir

rock type names the element

in charge for reservoir rock

permeability. It would be wrong

to name such type as “pore-

fracture” type.

Pore-fracture type One of the fracture-types. The

fracture system provides for

the permeability. Separated

pore zones communicate

through fractures. Pore

zones act as an add-on into

the fracture capacity.

Would be wrong to name it

“fracture-pore” type.

8 Carbonate Reservoir Rocks

Fracture-type One of the fracture-types. The

fracture system provides

both for the permeability

and the capacity. Tight

matrix is comprised from

small sub-capillary pores

filled with residual water or

has no pores at all.

Vug-fracture type One of the fracture-types.

The fracture system

provides the permeability.

The capacity is created by

isolated isometric vugs

and fracture cavities.

Newly-formed vugs and

cavities are associated with

fractures and located along

fractures.

“Cavity-fracture” type would also

be a right term. Still, it is hard

to distinguish between vugs

and cavities. Following original

Bagrintseva’s text, we always

use “vug-fracture” term and

sometimes compliment it with

“fracture cavity” term.

Genesis. Genetic. Bagrintseva points out that,

like with a human being

gene, a geologist may iden-

tify initial primary features,

which pre-determine the

direction and extent of post

depositional changes on

the pore space and rock

structure. Please refer to

Bagrintseva’s Classification

for more details.

Origin.

Inherited vugularity. Vugs (and cavities) which

develop in good porous

matrix, where initial pore

system provides good pore

permeability.

Newly-formed

vugularity. Newly-

formed vugs.

Elongated cavities (and

sometimes isometric vugs),

which develop in bad

non-porous matrix, where

initial pore system does

not provides permeability.

Fracture system created

paths for fluid filtering,

then leaching of fractures

and some form component

lead to this type vugularity.

Newly-formed cavities. It would be

okay to use this term too. Read

more above about vug and cav-

ity terms.

Carbonate Reservoir Rock Properties and Previous Studies 9

Reservoirs or reservoir

rocks.

This term refers to the rocks,

which may contain oil and

gas.

Reservoir or Natural

reservoir.

This term refers to a field,

massif or bedded.

Bagrintseva uses this term

when presenting the major

field’s spatial models, where

different reservoir rock

types are shown.

Trap. Oilfield.

Oil and gas reservoir rocks are rocks capable of holding liquid and gaseous hydro-carbons and releasing them in the process of field development. The criteria of a rock being an oil and gas reservoir rock are the values of permeability and capacity caused by porosity, fracturing and vugularity. The value of the useful (effective) capacity for oil and gas depends on the value of the residual water saturation. The lower limits of per-meability and effective capacity determine commercial evaluation of the beds, which depends on the fluid composition and reservoir rock type. The fraction (or share) of the pores, vugs, fractures participation in the process of filtering and in the total reservoir capacity determines the reservoir rock type: pore-type, fracture type or complex type (fracture-pore type, vug-fracture type, vug-pore type).

Reservoir properties of carbonate rocks are determined by the primary sedimenta-tion environment and the intensity and direction of the postdepositional alterations affecting the development of pores, vugs, fractures and large leaching cavities. Specific features of the carbonate rocks (early lithification, selective solubility and leaching, propensity for the fracture formation) result in the diversity of void morphology and genesis. This is manifested by a wide range of oil and gas reservoir rock types. Most significant hydrocarbon reserves are associated with the vug-pore type and pore-type reservoir rocks.

Permeability is a property of rocks to transmit liquid and gaseous fluids. Permeability is a measure of medium’s filtering conductivity and represents one of the most important reservoir rock parameters determining the possibility to extract oil and gas from the rocks. Its value substantially depends on the pore channel size and sinuosity and on rock’s fractureness.

Porosity is the capacity of rocks to hold fluids, due to the action of capillary forces. The total capacity of the reservoir rocks is formed by three types of voids: pores, vugs and fractures (with fracture cavities). They differ in their genesis, morphology, conditions of hydrocarbon accumulation within them and filtering through them. Three kinds of rock porosity are distinguished: total, open and effective porosity. Total porosity is the volume of communicating and isolated pores. Open porosity is the volume of communicating pores filled up by the fluids at the rock saturation under vacuum; the open porosity is lower than total porosity by the amount of isolated pores. Effective porosity is the volume occupied by the movable fluids; the effective porosity is lower than open porosity by the amount of residual fluids. Porosity value

10 Carbonate Reservoir Rocks

is measured as the ratio of pore volume to the rock sample volume, and is placed in the % or as a fraction of 1.

Fracturing of rocks significantly increases their filtering properties. The capacity of the fractures proper is 0.5 to 1%, but in the carbonates it significantly increases to 1.5 to 2.5% and even 5.5% as a result of leaching and dissolution of the fracture cavities. In describing the reservoir rocks, it is incorrect to apply the term “fracture porosity” because the carbonate rock matrix has low porosity and the cavities (vugs) are effective. It is more correct to use the term “fracture capacity”.

Vugularity is the secondary voidness formed in the soluble carbonate rocks. Two types of vugularity are identified in relation to their genesis and significance for the hydrocarbon reserves: the inherited and the newly-formed vugularity. The inherited vugularity is developing within the porous-permeable rock varieties with the originally favorable pore structure; the newly-formed vugularity is typical of the originally com-pact low-capacity rocks.

The newly-formed vugularity significantly increases the reserves’ volume in low-porosity rocks at the expense of increasing effective vug capacity and widening fracture cavities, i.e., the development of the secondary voidness.

Residual water-oil-gas-condensate-saturation is the unrecoverable part of the flu-ids. The residual fluids occupy micropores and lower the amount of the reservoir useful capacity. The amount and distribution nature of the residual (irreducible, buried) water depends on the structural complexity of the porous medium, the value of the per-unit volume surface (specific surface) and on the surface properties of the rock (the extent of hydrophilicity and hydrophobicity). The residual water saturation in the pores of vari-ous lithologies ranges between 5% and 70%. Its content in sandy-silty rocks increases with increasing clay content.

The beds’ fill with fluids and the fluid displacement from the beds depend on:

• Structural patterns of the rock void space (the size, geometry, commu-nicability of various kinds of voids predetermine the filtering regime of liquids and gases);

• The extent of the capillary forces;• The nature of residual fluid distribution.

A significant distinction between the pores and vugs is in that in the pore channels the capillary forces dominate the gravity forces; in the vugs the gravity forces dominate the capillary forces. In fractures both capillary and gravity forces act simultaneously. The manifestation of certain forces controls the values of effective porosity, permeabil-ity and the residual water preservation.

Reservoir properties of rocks are important quantitative parameters for the reserves evaluation in oil and gas fields, for estimation of the water resources and the selection of a field production regime.

Surface properties of the carbonate rocks: wettability is among the most important parameters, which determine the distribution of oil and gas in the natural reservoir, the relative permeability for different phases and the possibility of their extraction from the beds.

Carbonate Reservoir Rock Properties and Previous Studies 11

Substantial difference in wettability was established for the rocks of the productive horizons and those beyond the productive portion of the natural reservoir. The latter are not in contact with the hydrocarbon components and usually preserve their original hydrophilic properties. The productive oil and gas-saturated rocks, depending on the void space type and fluid composition, are to some extent hydrophobic.

It was empirically found that the commonly applied separation into hydrophilic (the wetting contact angle θ less than 90o) and hydrophobic (the wetting contact angle θ greater than 90o) cannot be accepted for the rocks containing dry or wet hydrocarbon gases or oil of various composition. The experiments showed unequal pore space inter-nal surface hydrophobization extent in the oil-gas-condensate-saturated rocks.

Rock surface properties significantly change as a result of interactions between the rock material and liquid and gaseous hydrocarbons. That is why three rather than two zones should be identified within the commonly accepted wettability range: a typically hydrophilic zone with no indications of hydrocarbon mobility and interactions with them (the wetting contact angle θ in this case is 10 to 30o, rarely 50o); the intermediate where due to stirring and mixing of gas or gas-condensate (i.e., dry or wet hydrocarbon gas) and their action on the internal rock surface the hydrophobization is relatively low (the wetting contact angle increases and ranges between 76 and 110o); and the typically hydrophobic, with the wetting contact angle (changed due to the presence of oil in the rocks) of 105–150o.

Since the oil, condensate and gas distribution is non-uniform, it causes an uneven extent of rock pore space hydrophobization and requires a great number of measure-ments to determine the real contact angle. The medium value of the wetting contact angle is most informative. It reaches 80 to 105o in the rocks affected by gaseous hydro-carbons (gas or gas-condensate) and 105o and greater in the rocks containing liquid hydrocarbons (oil of various compositions).