Carbonate Reservoir Rocks

By Ksenia I. Bagrintseva

Most of the world’s energy still comes from fossil fuels, and there are still many strides being made in the efficiency and cost effectiveness of extracting these important and increasingly more elusive natural resources.  This is only possible if the nature of the emergence, evolution, and 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 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 preservation of the reservoir rock qualities with depth.

The main objective of most 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 carbonate 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 correlation between the major evaluation parameters.  

The focus of this volume is to show the scientific and engineering community a revolutionary process.  The author perfected an earlier developed 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 photographs made under UV light. The luminophore technique was combined with the raster 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.

Useful for the veteran engineer or scientist and the student alike, this book is a must-have for any geologist, engineer, or student working in the field of upstream petroleum engineering.

• Language: English
• Publisher: Wiley
• Release date: Jul 29, 2015
• ISBN: 9781119083986

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Chapter 1

Carbonate 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.

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 allowing the fluids to filter/flow; second, the secondary voidness emerging mostly due to the dissolution and leaching processes. The vugularity increases the useful reservoir capacity 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 physical 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 recrystallization 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 recrystallization. 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 processes, 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 formation 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 theoretical studies of the nature and extent of the fractured rock deformations were conducted 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 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 fractured 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 reservoir 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 number of occasions to estimate the fraction of pores, vugs, and fractures/fracture cavities 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 during 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 unrealistic 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 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 orientation 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 propagation 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 especially 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 carbonate 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:

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 different type reservoir rocks from the major carbonate oil fields, representing most former 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 compiled the below English language / terms explanations, hoping that they might initially 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.

Oil and gas reservoir rocks are rocks capable of holding liquid and gaseous hydrocarbons 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 permeability 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 sedimentation 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 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 compact 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 fluids. 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 various 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, communicability 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, permeability 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.

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 internal 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