Fracture and Vuggy Porosity

SPE Society of Petroleum Engineer'S of AIME SPE 10332 Fracture and Vuggy Porosity by Koenraad Johan Weber, * Shellinternationale Petroleum Maatschappy and Margot Bakker, Kon/Shell Exploration & Production Laboratories 'Member SPE-AIME «(!Copyright 1981, Society of Petroleum Engineers of AIME This paper was presented at the 56th Annual Fall Technical Conference and Exhibition of the Society of Petroleum Engineers of AIME, held in San Antonio, Texas, October 5-7,1981. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central Expressway, Dallas, Texas 75206. ABSTRACT The discovery of hydrocarbons in fractured rock always brings up the controversial subject of fracture porosity. Evidence of brecciation, leaching and infilling often complicate the issue. The high recovery efficiency of oil from fractures combined with the frequent absence of appreciable matrix porosity, in many cases enhance the economic importance of the estimated figures. Sometimes one can base ones predictions on local production experience from similar fields, but more often one has to rely on the limited information from production tests, cores, logs and occ<Jsionally neilrby outcrops. At an early stage this approach can only lead to the location of the most fractured or vuggy zones and a very rough estirnnte of the associated porosities. To reduce the uncertainty one can make use of a statistical approach based on a classification of fractured reservoir types with corresponding porosity ranges collected from literature. An atten~t has been made to gather a comprehensive worldwide data suite large enough to establish reI iable porosity ranges for a series of reservoir types. A simple practical classification into seven types of fractured and leached reservoirs has been adopted based on tectonic style and leaching pnJCC'sses. Any figures quoted in literature were critically examined and only used when there was clear evidence that they were based on thorough fracture/vug spacing and fracture/vug width and size studies or on reliable material balance calculations. This reduced the data set to a fraction of its original size b~t the resulting table is thought to stand up to scrutiny. INTRODUCTION Several years ago the authors recognized the need for a I;UlllPLefLt!U; overview of the subj ec t of fracture porosity. An increasing number of hydrocarbon accumulations were being found in fractured reservoirs every time bringing up the question of fracture porosity. Also for fields which had produced for many years, the effective fracture porosity often remained in doubt. rhe introduction of more sophisticated petrophysical and reservoir methods provides more insight in the fracture porosity distribution and occasionally leads to realistic fracture void volumes. Usually, however, that is only possible with the aid of a good geological understanding of the reservoir. It WaS decided to carry out a literature review including any article of which the title indicated a relationship with fracture or vuggy porosity. A total of some five hundred articles were studied and in addition data were gathered from Shell fields. The first conclusion from this study was that it is remarkable how few reliable fracture or vuggy porosity figures are quoted in literature. To augment the scarce data, the authors were able to arrive at reasonable estimates in filling in the missing parameters from other similar occurrences. Although there is considerable variation between any pair of cases studied, a simple class- ification has been introduced to group the data in a small number of groups of genetically related types, viz.: 1. Monoclines and lowdip anticlines 2. Strongly folded anticlines 3. Fracture porosity enhanced by leaching 4. Karst aquifers, surface to shallow 5. Deeply burried brecciated karst, collapse breccias 6. Fractured chert 7. Fractured tuffs, igneous rocks 2 FRACTURE AND VUGGY POROSITY SPE 10332 Matrix type vugs not directly connected with a continuous fracture system have been excluded because their contribution to the reservoir porosity can usually be determined quite well with logs and cores. Basically, this paper is a literature study and the emphasis is on providing references covering the entire subject of fracture porosity together with a realistic assessment of porosity ranges for the various types. GENESIS OF FRAr.'l'TJRF. AND KARSTIC POROSITY This paper deals with porosity formed by the following processes. I. Non-tectonic processes 2. Regional extensive strain, overpressuring of pore fluids, decompaction by erosion, karstic leaching, collapse brecciation because of cave collapse or the solution of underlying evaporates, shrinkage cracks and basement erosion. Tectonic processes related to folding and faulting It is not the aim of the paper to describe these processes in depth but instead an annotated lite~ature survey is presented. A useful paper discussing the classification of natural fracture systems has been written by Nelson (1979). He emphasizes the need to unravel the superimposed components of different and warns against the inclusion of surface related cracks resulting from release of load in quarries and road cuts. Stearns and Friedman (1972) describe the various common fracture systems and demonstrate the influence of rock ductility/lithology and the bedding thickness on the fracture density. Currie and Nwachukwu (1974) demonstrate that incipient fracture porosity at depth can develop gradually into a network of open fractures under conditions of continued uplift and erosional unloading. The mechanics of the development of faulting and fracturing are treated by Price (1966). The development of folds is discussed in some detai 1 by Laubscher (1977) while the important bedding plane slip occurring in folded anticlines is described by Chapple and Spang (1974). With respect to karst development, there is a vast literature dealing with the formation of cave systems. Bogli (1976) proposes theories on karst development in which he puts the emphasis on the aggressive mixture of water with different composition which is formed in the phreatic zone and the effect of the CO 2 in the air in the caves of the vadose zone. The lithologic controls on the development of solution porosity in carbonate rocks are well documented by Rauch and White (1970). Deike (1969) shows how the cave systems in a karst are often related to preexisting joints or fracture systems. An interesting re- construction of the development of a largely collapsed karst development associated with uplift and faulting and subsequently covered by a marine erosion, was made by Poty (1980). There is clear evidence that the larger caves in a karst tend to collapse with deeper burial. An actual case causing an earthquake in Libya has been described by Campbell (1968). Collapse caused by the dissolution of evaporites underneath carbonates and other rocks is discussed by Herrmann (1968). In the oil field area of the North Sea similar phenomena have been recognized by Lohmann (1972). Finally, we have the possibility of the creation of fracture pore space by fracturing of the rock as a result of very high pore fluid pressures. This process is often mentioned but little evidence is us'ually presented to substantiate this theory. Recently, however, Lapre and Pulga (1978) writing on the Emilio heavy oil accumulation in the Adriatic, give fairly conclusive proof of the intrusion of the heavy immature crude into the rock during a tensional phase of the comprehensive folding of the formation. An unusual phenomenon associated with this process is the occurrence of horizontal oil- filled fractures. DETERMINATION OF FRACTURE AND VUGGY POROSITY The classic method of estimating fracture porosity is to examine cores, count the number of natural fractures and measure their width. These methods are only realistic if one has a good handle on the fracture systems involved and the influence of bed thickness and lithology. Outcrop studies are usually needed to provide this insight although great care has to be taken to recognise surface related decompaction fissures from these tectonic fractures. Studies of this type have been carried out in Iran (fig. 1), Turkey, and the U.S.A .• Sangree (1969) who performed detailed studies of this kind in Iran, wrote a paper on these methods. In Russia, much attention has been paid to the careful analysis of fracture porosity on the basis of core studies, e.g. Smekhov (1969). The bulk of the figures quoted in this paper have been derived in this fashion. In the course of such studies several factors have been recognised as essential in order to arrive at a realistic estimate of fracture porosity; viz. : 1. Recognition of the various fracture systems, their relative age in relation to burial depth and oil migration. In many cases the older fractures are cemented up by calcite and anhydrite and only the younger system is partly open. Elimination of non-natural fractures. SFE 10332 K.J. WEBER AND M. BAKKER 2. 3. 4. Analysis of the influence of structural shape (see Harris et aI, 1969), bedding thickness stratigraphy (marly or shaly intercalations' promote bedding plane slippage), lithology/ duc tili ty. Careful analysis of average open fracture width for each fracture system. Thin sections are oIten used to study the micro fractures. Fracture widths of 0.01-0. I mm are common for small joints. Extension fractures of I to 25 feet in length can have open width of 0.1- I mm with an average in the order of 0.2 mm. Major extension fractures may be from 0.2 to 2 mm wide, usually with at least partial infilling. Infilling of fracture pore space by various minerals and bitumen. can often help in unraveling the age relationships of cements in multiple fracture systems. Karst features often fill up with surface derived sediments, ores or guano. Usually it is necessary to use a rock mechanical/ statistical approach to arrive at a realistic fracture density distribution. A good example of this technique is presented by Kiraly (1969). An excellent analysis of the relationship of bedding thickness and fracture spacing is given by Bock (1971). An example of a complete analysis of cores and outcrops is the estimate of the fracture porosity distribution of the Gach Saran field in Iran (fig. 2). The fracture system was derived from observing various outcrops of similar anticlines in the Zagros mountains foothills (fig. I) while the fracture widths were derived from cores. Next in importance in determining realistic fracture and vuggy porosities is the material balance method. Basically this method will work very well if there is no effective matrix and if one can observe the fluid interfaces accurately. In aquifers in karstic formations, this method can be quite (~ffective. A problem is the sometimes irregular distribution of porosity in the vertical sense. In karst systems, near the surface there are often one or more levels of cave development which contain the bulk of the cavernous porosity. In collapsed karsts the porosity is usually more evenly distributed. An excellent example of a reliable material balance calculation of near surface karst porosity could be made on the basis of the account of the accidental flooding of the West Driefontein mine in South Africa (Cousens and Garrett, 1969). All the water from a dolomite karst zone overlying the gold- bearing formation drained into the mine via a fissure. In this area, the karst zone is subdivided into separate compartments by vertical igneous dykes. Thus the bulk volume of the drained karst could be accurately established as well as the volume of water ~hich had to be pumped up. The karst porosity IS about 1% of the total drained bulk volume. However, most of the caves and larger cavities are restricted to the upper half of the interval and a porosity of some 2% for the main karstic zone is very likely. Besides the more basic material balance calculations, there exists a range of more sophisticated reservoir engineering methods to determine fracture and connected vuggy porosity. The basic thoughts were presented by Warren and Root (1963) and in ideal circum- stances these methods work quite well. There are however, several complicating factors. Firstly the pressure build-up curves associated with double porosity reservoirs are similar to those observed for a stratified reservoir. Secondly, there is often too little time to obtain a truly representative build-up curve. Other complicating factors are baffles to horizontal flow in the reservoir, skin effects, heterogeneous distribution of the fracture porosity, and variations in aquifer size and permeability. The basic problem is the assessment of the retarded matrix influx relative to the supposedly instantaneous fracture porosity influx. Long shut-in periods are very helpful in solving this problem and both in Masjid-i-Suleiman (Gibson 1948) and in Amposta Marino fields such periods provided the key to a realistic estimate of the fracture porosity. Mavor et al. (1979) discuss the analysis of one well pressure build-up curves of the type used for the Amposta Marino field. The basic principle is the recognition of two parallel, semi- log straight lines in the build-up graphs. Unfortunately the first line is usually obscured and we have to take recourse to more complicated methods. A type-curve approach is described by Bourdet and Gringarten (1980). Accepting the fact that the theoretically ideal dual porosity pressure build-up curve will usuailly be obscured by well storage, skin, and other disturbing factors, they derived type curves based on the behaviour of heterogeneous models which can be compared to measured build-up curves. From this analysis, it is possible to estimate the ratio of the fissure storativity to the total storativity and the interporosity flow coefficient, which depends on the shape. the size and the permeability of the matrix blocks. The numerous petrophysical methods to detect fractures and to measure fracture and vuggy pore space are excluded from this paper because they are the subject of several papers to be presented at the SPE annual conference of 1981. 4 FRACTURE AND VUGGY POROSITY SPE 10332 This porosity development is characterized by low density regional fracture systems with very small open width (0.01-0.1 rnm) often formed by de- loading during uplift. Locally the fracture density may increase near major fault zones (fig. 3) or as a result of warping or differential compaction. Fracture porosity is usually very low with a range of 0.01 to 0.1% of rock bulk volume. However, the fracture permeability is often crucial in obtaining economic well productivities. Many very large oil fields fall in this category, such as the large anticlinal structures in Iran, Iraq and southern Russia. For this reason much effort has been given to the analysis of the fracture systems and the related fracture I width. Outcrop and core studies, together with reser~oir engineering calculations and some logging exper1ments have gradually given a fairly good ov~rview of the type of fracturing providing the major fracture porosity. The individual beds are jointed in a mainly orthogonal extensional pattern related to the anticlinal axis direction. Fracture density is controlled by degree of bending, bedding thickness, and bed ductility. The degree of bedding plane slippage along shaly or marly intercalations is also important with respect to fracture spacing and fold shape. Huch bedding plane slippage often lea~s to box fold type structures (Laubscher, 1977). On the anticlinal noses and flanks some ~hear fractures are formed but their contribution to fracture porosity is minimal. Strong bending produces through going fractures across series of beds, and partly depending on the compe~ence of the core of the structure, keystone fault1ng can develop parallel to the crest of the structllres. These major fractures and faults can provide excellent vertical and lateral conununication over large distances (fig. J). In the Agha Jari fi~ld, wells 7! miles apart undergo mutual pressure adjustments to within a few psi (Drununond, 1964). Fracture width ranges from values of the order of 0.1 nun for the joints restricted to a single bed to 0.2 - 0.5 nun for the larger fractures intersecting several beds. Partial or complete infilling of the fractures by calcite or anhydrite is conunon but in many cases a partially cemented fracture may well retain a larger void volume than an uncemented one. Major faults are often associated with brecciated zones and sometimes even tectonic caves. In these fault breccias internal fracture porosities of some 5 per cent have been observed in iran. Along the crest of sinusoidal anticlines and along the hinges of box fold type anticlines, fracture porosities of up to 0.4 per cent are possible. The limbs of the anticlines show a quick increase of the fracture spacing downwards away from the crest or the hinge zones. Therefore, the overall fracture porosity over a vertical interval of 1000 feet or more is unlikely to be larger than 0.2 per cent. FRACTURE POROSITY ENHANCED BY LEACHING, TABLE 3 Many fields in this category have undergone some near surface leaching and therefore corne close to the brecciated karst group. However, the quoted examples probably never reached the stage where they could be called cavernous except perhaps the upper zone in Kirkuk. The bulk of the extra fracture porosity relative to the foregoing group is formed by the enlargement of the fracture width by leaching to up to O.S cm. In some cases, preferential leaching of certain fossils can also increase the apparent fracture porosity by creating vuggy zones connected to open fractures or by causing brecciation. The well-known Mara and La Paz fields in Venezuela were long thought to have a fracture porosity of about 1 per cent. However, subsequent studies showed that much of this porosity was actually situated in the intensively fractured basement rocks which consist of granodiorites mica schists, gneisses, and metamorphic quart;ites (Dikkers, 1964). The fracture porosity range for this group is from 0.2 to about I per cent. Values of about 0.5 per cent appear to be rather common. KARST AQUIFER, SURFACE TO SHALLOW, TABLE 4 Although cave systems sometimes appear to be very widespread and voluminous, the material balance calculations in karst aquifers indicate that the actual void volume is only of the order of at most 3 per cent. Moreover, figures of 3 per cent are probably only possible for the relatively sm~ll vertical intervals of major cave development (f1g. 4). For larger bodies of karst and vertical intervals of more than 300 feet values of about ) per cent are more realistic. Early deep erosion and collapse may already cause pore space reduction and infilling by surface sediments. The range of the total porosity in caves and associated vugs and fissures is from 0.2 to 3 per cent. DEEPLY Not too many reliable figures could be found for this category although it is of increasing importance. In the Mediterranean several such oil fields have been found such as Amposta Marino (fig. 5) Castellon B5 and Nilde. In the North Sea the Zechstein interval in Auk and Argyll should probably be classed in this group. In the U.S., there is the large number of Ellenburger fields. It can be expected that in China many oil fields are of this type. SPE 10332 K.J. WEBER AND M. BAKKER [n Auk and Argyll, it is difficult to separate the contribution from the fractured Zechstein from that of the Rotliegendes reservoir and no reliable figures are as yet available. From the data from the other fields a range of 0.5 to about 2 per cent appears likely. There is frequently some evidence of matrix contribution even though the matrix porosity may be very low. It is probable that the actual maximum fracture and cavernous porosity is of the order of 1.5 per cent. FRACTURED CHERT, TABLE 6 The fractured chert of the Monterey formation in California is famous for its extraordinarily large fracture porosities. The main reason for this phenomenon is the occurrence of the chert in thin beds separated by much more ductile intercalations of shale, mudstone and dolomite. The softer rock keeps the brecciated chert together and fracture widths of several millimeters combined with fracture spacings of about 5 cm can be observed. Draping over a fault scarp as in the Santa Maria field enhances the fracturing and maximum fracture porosities of some 8 per cent are possible. Few reliable data could be found for formations in this category although there are several important and also oil fields of this t yp e. Ii u b be r t eta I. (I 955) des c rib e 0 i 1 fi e 1 d s in serpentine rock in Southeast-central Texas. The oil is situated in fractures ranging from hairlines to nearly 4 em width and which may be nminly caused by the diagenetica11y alteration of the rock. The occurrence of oil in the basement of the Mara and La Paz fields has already been mentioned above. In the U.S.S.R., Bortnitskaya et a1. (1974) describe oil fields in igneous rock in the Dni.eper-Donets basin. Cooling joints and intersected ves iCllles in the b,lsal t can form fracture porosi ty of up to 6 per cent. For chis heterogeneous group it is difficult to estimate a likely range but values from 2 to 8 per cent have been observed. The fracture and vuggy porosity data presented in this paper may not be very accurate individually but the similarity between the figures in a given group and the rather limited ranges give some confidence in the overall picture. It is concluded that the tables can be used to slot in new cases provided sufficient geological information is available. Although the mcidern logging and reservoir engineering methods are an important step forward, it is indispensable to prepare a realistic geological model before deciding on a fracture porosity figure. Care was taken to include a representative series of references in this paper in order that others interested in the subject can continue this type of work. The authors do not doubt that there is much more published data while oil companies and universities probably have much additional information relative to the subject. Thus it is worthwhile to periodically review the available data to increase the understanding of fracture porosity development and consequentially to improve the art of estimating and measuring this elusive parameter. ACKNOWLEDGEMENT The authors wish to thank the Shell International Petroleum Company and the Koninklijke/8hell Exploratie en Produktie Laboratorium for permission to publish this paper. REFERENCES 1. Al-Nagib, F.M., AI-Debouni, R.M., AI- Irhayim, T.A. and Morris, D.M.: "Water drive performance of the fractured Kirkuk field of Northern Iraq", 8PE-paper 3437 (1971). 2. 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Weidenbach, F.: "Uber einige Wasserbohrungen im Jura", Jber. u. Mi t t. oberrh. geal. Ver., N.F. 36, pp. 54-73 (1954). Zotl, J.: "Karsthydrogeologie", Springer Verlag, Wien, New York, 291 pp. (1974). 8. Fracture and Vuggy Porosity SPE 10332 'L\1l1,E I t·lonoc 1 ines and low-dip anticlines : 0.0) 0.1% TABLE 3 Fracture porosity enhanced by leaching : 0.2 - 1.0% I t on Country Lithology Fract. Method Ref porosity Location Country Lithology Fract. Method Ref Alsace- France Limestone 0.01-0.02 cores 23 & Vuggy Eschau near porosity field fault U Lacq France Limestone 0.4-0.5 49 ~- Scharz- Germany Sandstone O. I in 18 Res. N. outcroF field and Dolo- eng. & wald subsur- & cores mite calc. 57 face Ain Zalah Iraq Limestone 0.4 13 Texas U.S.A. Sandstone a.0.025 29 cores w. cores field and Dolo- Spraberry Siltstone b.0.15 cores 19 mite field K. 'kuk Iraq Limestone Upper Mat. "Utah U.S.A. Sandstone 0.02-0.1 37 I cores [ie ld and Dolo- Zone bal. Altamont Siltstone mite 3.0· and Blue- bell fields Lower Zone Dukhan Qatar Limestone 0.02-0.04 cores 13 0.9 field D :t U.S.S.R. Limestone 0.2-0.33 Various U.S. S. R. Limestone Usually 53 cores 32 cores U. Jur Dolomite field in Dolomite 0.06-0. I f)eld~ Ukraine. Stavropol. N, and lndon- Marly 0.36-0.39 Mat. 59 Kuibishev Wasian esia Limestone bal. regions fields W. Irian Corbii Mad Roumania Limestone 0.9 10 cores ITABLE 2 field La Paz and Venez- Limestone 0.5 Mat. 16 Strongly folded anticlines : 0.1 - 0.3% Mara fields uela bal.& Location Country Lithology Fract. Method Ref cores porosity Roosevelt U.S.A. Limestone 0.55 cores 48 Diyarbakir Turkey Limestone 0.01-0.4 Outer. Shell Pool. Utah Dolomite oil field and Dalo- 0.1 & data Marl avo cores West Edmond U.S.A. Limestone 0.08-0.56 mite I cores 35 Gach Saran Iran Limestone 0.17crest Outer. Shell Hunton Pool Oklahoma field and Dolo- 0.03flank & cores data mite • Agha Jari Iran Limestone 0.22 Mat. 25 The upper zone contains zones with very large vugs field and some bal. which contribute to the production as if they form sandstone part of the fracture system. This zone could also Haft Kel Iran Limestone 0.21 Mat. 25 be grouped with the karst cases. field and Dolo- bal. mite Ma;h_d ·1 Iran Limestone 0.2 Mat. 17 8 Suleiman and Dolo- bal. 24 field Well Pakistan Siltstone 0.11-0.21 cores 51 Nuryal··] sandstone Potwar region Limestone 0.05-0.75 nni pnp,'- U.S.S.R. Sandstone Up to 0.3 cores 5 -'" Danets Siltstone Basin D tan U.S.S.R. Limestone 0.16-0.35 cores 32 U. Cret. and fields Dolomite Ural-Volga U.S.S.R. Limestone 0.25-0.3 Mat. 56 region & shales bal. Stavrc~)ol U.S.S.R. Limestone 0.1-0.3 cores 22 region marls S.W. Lacey U.S.A. Silicious 0.17 R'es. 40 field, Limestone eng. Oklahoma calc. Salt Flat- U.S.A. Limestone 0.2 Log 43 Tenney Anal. Creek field, Texas SPE ~0332 K.J. Weber and M. Bakker 9. TABLE l~ TABLE 6 , Fractured Chert : 5 - 8% L Country Lithology Fract. Method Ref L it i Country Lithology Frac t. Method Ref & Vuggy porosity porosity S ,t Ha .a U. S.A. Chert 6 cores 42 V, I France Chalky 0.9-\ .8 cores 20 district Honterey & 47 Limestone & logs California Formation Ba :c -D- , France Limestone up to 3 cores IS Shales Meuse Hat. bal. Grands France Dolomite 1 Mat. 63 Causses Marly bal. TABLE 7 Hassif Limestone Central Fractured tuffs, igneous rocks : 2 - 8% 'f ~b ic,l Yugos- Limestone 1. 1-1 .6 Mat. 39 River lavia bal. ~[on Country Lithology Fract. Method Ref Springs porosity Cetina " " 0.2 Mat. 39 S 1 md Germany Keratophyr 2.3-8 cores 27 aquifer bal. aquifer tuff Zrmanja II II 0.3 Mat. 39 S it 11 Germany basalt 0.3-5, II 55 River bal. aquifer avo 3 Aquifer l)niepl~r- U.S.S.R. diabase up to 6 " 5 G 1-& 8: Rud" II II 0.3 Mat. 39 Donets basalts Aqu ifer bal. Basin porphyres l'I Id U.K. " up to outcrop 21 andesites Hi Us 2-3 & cores - Ebinger Alb Germany " 1.5-3.0 Mat. 55 Reutlinger Schwabi- " 0.5-2.0 bal. 58 Alb scher Ostalb Jura " 1.8 62 West South Dolomite ±2 in Mat. II Driefontein Africa main bal. mine karst zone, ±I for total interv. 11<') Ik U.S.A. Limestone 0.5 Hat. 60 Qutl.drangle bal. Kentucky TABLE 5 Deeply burried brecciated karst, collapse br~ccias : 0.5 - 2.0% Location Country Lithology Fract. rMethod Ref & Large size Vuggy porosity Mcditcr- Spain Limestone 0,6-1.5 Res. Shell ranean. eng. datal Amposta calc.& M<lrino Fld. cores Castel10n " " 1.6 as Shell BS Field above data Martin U,S.A. Dolomite 1.8 cores 2 field West Ellenburger Tex<ls Pegasus " " 2.8 cores 8 Field & logs Ellenburger Fullerton " Limestone 0.33-1.04 cores 30 Field & Ellenburger Dolomite avo 0.6 Lower flank with conjugate shear fractures " Axial fractures predominate in hinge zones Fig. 1 - Sketch of anticlinal Asmari formation outcrop in the Zagros range foothills, Iran. N ZONE OF MAJOR OF MAJOR KEYSTONE FAULTING 3-6 PER KM 2000 FTSS 4000 FTSS 6000 FTSS 8000 FTSS FRACTURES' 0000 FTSS DOWN FLANK o 2 4km ' ' Fig. 2 - Distribution of fracture porosity in Gachsaran field, Iran. A 1 l2 9 'r' -, . ;< EOCENE -725 m f # ·-IH-Al-lf¥ +"""_-=-· ··· - J -750m 5 2000 FTSS 4000 FTSS 6000 FTSS 8000 FTSS tOOOO FTSS -775m +-11+1 =-<-= I~ +-f _f_ -800m +->~ ~~- - :-=:-_~__4_- o 200 400m .' ' ' Fig. 3 - East-West cross-section fracture profile of Eschau field, France. (After Ghez and Junot, 1972). . oil- filled fractures. DETERMINATION OF FRACTURE AND VUGGY POROSITY The classic method of estimating fracture porosity is to examine cores, count the number of natural fractures. Careful analysis of average open fracture width for each fracture system. Thin sections are oIten used to study the micro fractures. Fracture widths of 0.01-0. I mm are. 7. Fractured tuffs, igneous rocks 2 FRACTURE AND VUGGY POROSITY SPE 10332 Matrix type vugs not directly connected with a continuous fracture system have been excluded because