Hydrocarbon migration in the Zagros Basin, offshore Iran, for understanding the fluid flow in the Oligocene–Miocene carbonate reservoirs

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Russian Geology and Geophysics 54 (2013) 64–81 www.elsevier.com/locate/rgg

Hydrocarbon migration in the Zagros Basin, offshore Iran, for understanding the fluid flow in the Oligocene–Miocene carbonate reservoirs Z. Shariatinia a,*, M. Haghighi b, S. Feiznia c, A.H. Alizai d, G. Levresse e a

b

Department of Geosciences, University of Tehran, Tehran 141556455, Iran Australian School of Petroleum, University of Adelaide, Adelaide, SA 5005 Australia c College of Natural Resources, University of Tehran, Tehran, Iran d Geological Survey of Pakistan St. 17/2, Gulistan-e-Jauhar, Karachi, Pakistan e CGEO-UNAM, Campus Juriquilla, Querétaro 76230, México Received 24 September 2011; accepted 16 February 2012

Abstract Kuh-e Mond Field is a conventional heavy oil resource in the Zagros foreland Basin, Iran, produced from the fractured carbonates partially filled by dolomite, calcite, and anhydrite cement. Vitrinite reflectance data from carbonate reservoir suggest low-maturation levels corresponding to paleotemperatures as low as 50 °C. The observed maturation level (<0.5% Rmax) does not exceed values for simple burial maturation based on the estimated burial history. Oil inclusions within fracture-filled calcite and dolomite cement indicate the key role of these fractures in oil migration. The fluid inclusion temperature profiles constructed from the available data revealed the occurrence of petroleum in dolomite, calcite, and anhydrite and characterize the distinct variations in the homogenization temperatures (Th). Fluid inclusions in syntectonic calcite veins homogenize between 22 °C and 90 °C, showing a salinity decrease from 22 to 18 eq. wt.% NaCl. Fluid inclusions in anhydrite homogenize at <50 °C, showing that the pore fluids became warmer and more saline during burial. The Th range in the calcite-dolomite cement depicts a change in water composition; therefore, we infer these cements precipitated from petroleum-derived fluids. The microthermometry data on the petroleum fluid inclusions suggest that the reservoir was filled with heavy black oils and high-salinity waters and indicate that undersaturated oil was present in a hydrostatically pressured reservoir. The Th data do not support vertical migration of hot fluids througout the section, but extensive lateral fluid migration, most likely, drove tectonically dewatering in the south or west of the pool. © 2013, V.S. Sobolev IGM, Siberian Branch of the RAS. Published by Elsevier B.V. All rights reserved. Keywords: heavy oil; petroleum inclusions; PVTX simulation; phase diagram; Kuh-e Mond Field, Iran

Introduction The Kuh-e Mond Oilfield is a conventional heavy oil resource which was hosted by the carbonates ramp facies of Asmari Formation (32–18 Ma) deposited in the Zagros foreland basin (Alavi, 2004). The reservoir characteristics of Asmari Formation improved by development of fractures and faults in different tectonic episodes. The present distribution of petroleum belonging to Cenozoic reflects subtle tectonism and the connectivity of carbonate strata, through faults. The

* Corresponding author. E-mail address: [email protected] (Z. Shariatinia)

reservoir is highly heterogeneous fracturing character that makes it challenging for the production and development. Hypothetically lateral oil migration in a porous medium through effective permeability introduced by fracture system is a response to pressure-induced hydrofracturing from the source rocks. This decrease towards flanks and thus accumulated in the stratigraphic traps (Stöcklin, 1968). To constrain this, we need to look into the evolution of chemistry of hydrocarbon fluids in the Zagros Basin (Aplin et al., 1999; Bordenave, 2008). The original characteristics of this hydrocarbon fluids produced from Oligocene–Miocene reservoir are not easily identifiable because they have been overprinted by post accumulation processes like partitioning the petroleum fluids in petroleum systems (Bennett and Larter, 1997; Larter et al., 2000; Taylor et al., 1997). A geochemical protocol

1068-7971/$ - see front matter D 201 3, V.S. So bolev IGM, Siberian Branch of the RAS. Published by Elsevier B.V. All rights reserved. http://dx.doi.org/10.1016/j.rgg.2012.12.006 +

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Fig. 1. Geographic location of the Kuh-e Mond heavy oil field. KZ, Kazerun Fault Zone.

employed earlier by Aplin et al. (1999) to identify the paleotemperatures insights into thermal regime. By doing this, timing and chemistry of oil charge and both the distribution and physical properties can be constrained. This can be done by modeling a fluid flow model for this petroleum-prospective region. Here in this study oil inclusions are commonly taken as a proxy for maximum burial temperatures and display trend for increasing temperature downward which conform to the present geothermal gradient. Oil inclusions have also fuelled academic debate about whether diagenesis, especially cementation, continues after emplacement of oil into reservoir. We describe the petroleum fluid inclusions (HC) homogenization temperatures and its evolution from base to top of the Asmari Formation to investigate the different phases of the oil migration and flow dynamics of the oilfield. Geological and tectonic settings Zagros Basin is a prolific petroleum basin (Lakpour et al., 2008) in southwest Iran. Kuh-e Mond Oilfield marks the western tip of Fars Arch and is located in the southwest of Zagros Basin (Fig. 1). This is a large anticline, i.e., 90 km long and 16 km wide, with a vertical closure of approximately 2500 m. The lithology and microfacies identification of Asmari Formation (Figs. 2–4), reveals that the formation was deposited in the tropical ramp systems placed at the platform margin of the Zagros foreland basin during Early Oligocene to Late Miocene time (Aqrawi, 1998; Beydoun, 1998; James and Wynd, 1965; Kashfi, 1992; Motiei, 1993, 1995; Ricou, 1974; Sepehr and Cosgrove, 2004; Stöcklin, 1968). The petrography of Asmari Formation, Kuh-e Mond Oilfield represents that it has precipitated within intertidal to subtidal facies; in the spectrum of the subenvironment include

lagoonal, shoal and low-energy environment below the normal wave base. Fracturing in Asmari Formation is related to tectonic events evolution during the formation of Neo-Tethys basin that continued to present Zagros foreland basin. By the Late Cretaceous, the basin converged due to the subduction of Arabia plate beneath the Iranian plate (Berberian, 1995; Berberian and King, 1981; Beydoun, 1998; Stoneley, 1981). This continued collision remain active till the late Miocene, exerted buckling and neutral-surface forces on the sediment package in the form of the combination of flexural slip and neutral-surface mechanism that led to the shortening of the Zagros folded thrust belt. This shortening of Zagros thrust belt is also been confirmed by magnetic fabric data. The layer-parallel shortening during early to middle triggered detachment folding in the Kuh-e Mond area which have developed in front of the Kazerun Fault (Al Laboun, 1986; Al-Husseini, 2000, 2008; Alavi, 2004; Alsharhan and Nairn, 1997; Aubourg et al., 2010; Baker et al., 1993; Berberian, 1995; Berbrian and King, 1981; Colman-Sadd, 1978; Falcon, 1967, 1969, 1974; Kent, 1958, 1979; Murris, 1980; Nemati and Pezeshk, 2005; Ricou, 1974; Sepehr, 2001; Talbot and Alavi, 1996). This tectonic event produced large connected fractures, which are important for ensuring effective porosity and permeability as well as the draining and accumulation of the petroleum fluids in the reservoir (e.g., Bordenave, 2008; Bordenave and Burwood, 1990; Bordenave and Herge, 2005; Chilingarian et al., 1992; Colman-Sadd, 1978; Downey et al., 2001; Ge and Garven, 1992; Hansom and Lee, 2005; Lee and Williams, 2000; Nemati and Pezeshk, 2005; Sattarzadeh et al., 2000; Taberner et al., 2003; Vaziri-Moghaddam et al., 2010). Absence of source-rocks in Kuh-e Mond could be explained by thermal maturity level of shale formations in the area (Fig. 5). A diagram for the Lower Paleozoic source show the

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Fig. 2. Data from each studied borehole core of Asmari Formation which combined in a datasheet for interpretation. These datasheets contain gamma-ray, density and sedimentological logs and poroperm values. The graphic well logs indicate that in reservoir intervals which are dolomitized, the intercrystalline porosity is dominated. Based on the integration of sedimentological criteria and well-log signatures, the carbonates in the Kuh-e Mond Oilfield are subdivided into four depositional sequences. 1, limestone; 2, anhydritic dolomitic limestone; 3, anhydritic limestone; 4, dolomitic limestone; 5, limestone; 6, anhydrite; 7, marl; 8, dolomite; 9, limy dolomite; 10, anhydritic limy dolomite; 11, silty dolomite; 12, silty limy dolomite.

expulsion rate in the syncline north of Kuh-e Mond, most of the expulsion occurred prior to the trap formation. Figure 5 explains the oil expulsion modeled for the Kuh-e Mond anticline and include three possible Early Paleozoic source

rocks. Thermal results for these shaly formations show that these do not include the probable source rock facies in the area (Bordenave and Hegre, 2005). A source-rock of the Early Paleozoic would have been already over mature at the time

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Fig. 3. Field-scale facies model reconstructed for the Upper carbonates system in the Kuh-e Mond Oilfield. Twelve facies types are recognized in this environment that juxtaposed along the peritidal to off-shoal settings. Within the shallower part of this carbonate ramp, five main facies belts can be distinguished. The whole depositional realm was clearly above the fair weather wave base. Also shown is the schematic depositional facies model, based on the cores and thin sections, together with the idealized sequences for this environment. Peritidal and lagoon facies in which extensive dolomitization, anhydrite cementation and nodule formation occur. 1, limestone; 2, dolostone; 3, dolomitestone; 4, limy dolostone; 5, shale; 6, anhydrite/gypsum; 7, argillaceous limestone; 8, planctonic foraminifera; 9, Lepidocyclina; 10, Rotalids; 11, echinoids; 12, Discocyclina.

of Asmari Formation were deposited. While Cretaceous organic-rich layers would have been still been immature at the time of Asmari Formation deposition. The results show that the origin of the hydrocarbons in Kuh-e Mond is probably

more complex. This conclusion also confirmed by Mamariani et al., (2000) that consented oil might have migrated via lateral migration from the Jurassic Hanifa-Tuwaiq Mountain sourcerocks well developed in the Arabo-Persian Gulf.

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Fig. 4. Photomicrographs of six important facies types characteristic of their depositional environment. a, F12: Ooid bioclast grainstone/packstone; b, F11: ooid bioclast packstone/wackstone; c, F9: peloid/bioclast packstone/wackstone; d, F8: peloid milioid packstone/wackstone; e, F10: peloid/intraclast packstone/wackstone; f, F2: nodular mudstone.

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Fig. 5. Computed of the expelled amount of hydrocarbons in the most external part of Zagros, in the Mond–Khurmuj area sections. The two lower sections represent the oil expulsion rates at two times steps at present day off in the Zagros basin history. Three possible sources have been taken into consideration (Early Paleozoic, Cretaceous Kazhumi and Pabdeh-Gurpi of Middle Eocene). Early Paleozoic source rocks did no longer expel any oil after formation of Asmari traps, and they released most of the oil during late Jurassic time (adapted from Rudkiewicz et al., 2007).

Methodology and samples The study is based on six core wells drilled in the Asmari Formation, Kuh-e Mond Oilfield, Zagros Basin of Iran. The detailed work includes studuing drilled cores, thin sections, core logs, and core plugs as well as petrophysical analyses and fluid inclusions data collection. Thus, the study is aimed mainly at examining the subsurface data across the Iranian Zagros offshore Kuh-e Mond Oilfield. Core and thin-section analysis is used for the identification of petrophysical and the textural features that lead to identify facies types and their related diagenetic alteration, with special consideration to investigate the porosity evolution. Petrology Forty selected samples for different stratigraphic intervals of the Asmari Formation used for this petrology study. The locations of these samples are marked on the Fig. 1. All thin sections were inspected under an Olympus® BX-50 petrographical optical microscope and checked with a UV source for hydrocarbon-bearing fluid inclusions. Thin-sections were stained using the Dickson method (1966). Carbonate growth zones were studied using a Citl® cold cathode (CL) stage on an Olympus BX-50 microscope. The acceleration voltage of the electron beam was 15 kV with a probe current of 500 µA. Fluid inclusion studies Twenty thick sections were observed using an Olympus BX-50 epifluorescence microscope equipped with a UV-light source (Mercury lamp, λ = 365 nm), a U-MNU2 excitation

filter (straight band, 360–370 nm), and an LP400 longpass emission filter (>400 nm), allowing the recognition of fluorescent petroleum-bearing fluid inclusions Microthermometric data were acquired using a Linkam THMSG-600 stage attached to an Olympus® BX-50 petrographic microscope equipped with ultra-long working distance objectives at the 40× Laboratory from 100×. The stage was calibrated using natural North Sea petroleum-bearing fluid inclusions as well as pure C7 and C15 synthetic fluid inclusions at low temperature. Low temperature measurements present an accuracy of ±0.1 ºC. Salinities were calculated from melting temperature measurements using the equation of Bodnar (1993). Diagenetic controls on the reservoir quality Lithology Asmari Formation is compared with modern and ancient analogues that are well documented in the available literature to evaluate the depositional facies of the formation and it capacity to act as reservoir. This involves grain size, type (ooids, peloids, shells and other diagnostic allochems), textures, lithology and sedimentary structures that are restricted to Kuh-e Mond Oilfield reservoir (Fig. 3 and 5). Five facies assemblages identified on the basis of above finding and are supratidal, intertidal, lagoon, shoal and off-shoal environments (Fig. 3). Facies labeled in Fig. 3 from F1–F8 has been deposited in the supratidal, intertidal and restricted lagoon systems belong to Upper and Middle parts of Asmari Formation and Facies F9–F14 (Fig. 3), are interpreted as open lagoon, shoal and offshoal deposits.

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Fig. 6. (a) Photomicrographs of thin sections in lower part of the Asmari Formation shows fossil calcite cavity-fill for dolomitised packstone with fine to medium dolomite crystals are partially fabric retentive. Th values of the analyzed fluid inclusions in the fringing calcite ranging from 39 to 53 °C. The aqueous inclusions found in the sparry calcite revealed Th values between 68 and 99 °C. (b) Fossil cavities cemented with granular mosaic calcite. (c) Another fossil cavity calcite filled partially with equant sparry calcite. (d) Transmitted light photomicrograph showing very coarse calcite spars and isopachous rind equant calcite mosaics surrounded constituents. The displayed equant calcite had monophase aqueous inclusion indicating precipitation at lower temperatures. the sparry calcite cement revealed Th values between 45 °C and 75 °C, and the Th values observed from aqueous inclusions in the recrystallized very coarse sparry calcite (c, d) 88 °C. (e and f) Photomicrographs in skeletal wackstone with porosity 14.2% and represent the all major porosity types in the Asmari Formation.

In Facies F1 to F3 (Fig. 3), primary anhydrite occurs in the form of nodular fabric (chicken wire) or as massive and layered anhydrite. Secondary types could describe the enterolithic anhydrite, dense anhydrite and anhydritic dolomud-

stone. Primary anhydrite is a nodular chickenwire texture and has found in the middle and upper parts of the Asmari (Figs. 2, 4, and 6a). Enterolithic and nodules textures are more common observed in Asmari Formation in the different facies include

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mudstones, wackestones to packstones and grainstones. Secondary diagenetic anhydrite is more common than the primary anhydrite, and occurs both as nodules and vug/fracture-fills. Warren and Kendall (1985) and Warren (2006) proposed evaporative sabkhas of the Trucial Coast as a modern analogue for these facies. Ehrenberg et al. (2007) suggested anhydrite in the Asmari Formation formed in evaporite basin rather than as a later diagenetic product. Facies F3 and F4 (Fig. 3), represent the dolomite lithology with mudstone texture, are massive and homogeneous. Facies F3 can be distinguished from F4 by its anhydrite (rhombs) and gypsum bladed crystals. These facies are associated with F1 and F2 (Fig. 3). It has no evidence of subaerial exposure and was deposited in a restricted shelf lagoon. Modern analogues for these facies are peritidal environments (particularly from intertidal ponds) (Flügel, 2004; Tucker and Wright, 1990). Facies F5 (Fig. 3) characterized with finely or moderately crinkled horizontal lamination consists of alternating calcilutitic laminae and bioclastic laminations are typical features of the intertidal environments described from modern tidal flat systems e.g. Persian Gulf or Shark Bay (Aguilera-Franco and Hernández-Romano, 2004; Hardie, 1986; Hernández-Romano, 1999; Flügel, 2004; Lasemi, 1995; Shinn, 1983; Steinhauff and Walker, 1996). Fenestral dolomudstones (Facies F6; Fig. 3) consists of fine grained microcrystalline limestone and facies type is interpreted as an intertidal deposit. Bioclasts are lacking and the fenestrate structures are well developed. Fenestrate structures are typical products of shrinkage and expansion, gas bubbles, and air escape during flooding, or may even result from burrowing activity of worms or insects. Shinn (1983) considered similar facies representative of a tidal flat environment, where trapped air between irregularly-shaped deposits leads to the development of birdseyes. Facies F7 (Fig. 3) consists of peloid/intraclast grain-dominated textures, with grain grading and commonly massive structure. The grains are poor to medium sorted and are

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composed of dominantly packstone, but ranging from wackestone to grainstone. In some samples, the predominant nonskeletal carbonate grains are intraclasts. The facies intercalates with open lagoonal facies is indication of deposition in the intertidal shelf lagoon. In F8 and F9 (Fig. 3) facies, peloids are common. Components of this facies include benthic imperforate foraminifera (Dendritina and miliolids). This facies was deposited in a restricted shelf lagoon. The restricted condition is suggested by the rare to absent normal marine biota (Flügel, 2004). Facies 10 (Fig. 3) is a poorly sorted bioclast wackestone to packstone (limestone or dolomite). Skeletal grains include benthic foraminifera (miliolids, rotaliids), echinoid, corallinacean and bivalve fragments indicated sedimentation took place in an open shelf lagoon. Coarse bioclast grainstone (F12; Fig. 3) with coarse bioclast wackestones to grainstones described as shoal environment. Porosity and permeability values Main effective connected porosity types for the Asmari Formation is dominated by two groups comprises interparticle porosity and vuggy porosity. Distribution of the pore network is heterogeneous and is dependent on fractures, vugs and channels contribution (Fig. 6e and f). Measured porosity in the Asmari dolomicrites is generally low (5% mD), but well test results present higher effective porosities in excess of 25% and average permeabilities in excess of 100 mD (Fig. 7). This high permeability is associated with vuggy and intraparticle porosities observed with fractured dolomitised facies that confirmed analyzing dolomitized samples SEM photos (Fig. 8b). More than 60% of existing porosity in the studied interval is diagenetic (secondary) in origin. Intraparticle (IP), Mouldic (MO) and intercrystalline (IX) pores are the most frequent types of porosity (Fig. 6e, f). The average porosity varies between 2.66 up to 5.92% in the Upper Asmari intervals which

Fig. 7. (a) The percentage of all major porosity types in the Asmari Formation. (b) Graph shows the relative abundance of the geological mechanisms considerably improved the porosity in the whole Asmari Formation. The dissolution has allotted to be the highest rate on the graph.

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Fig. 8. (a) Porosity with the dolomitization percentages in the rock. (b) The SEM photo that shows cube faces of dolomite crystals and new opening between the crystals resulted from dolomitization of the rock matrix in retentive type. The largest dolomite crystal sizes are as large as 130 µm.

Fig. 9. Diagenetic sequence for the Asmari Formation carbonates. Diagenetic settings and their relative timing are based on petrographic and geochemical relationships.

is dolomitised with higher rates (Fig. 7). Therefore there is a scattered porosity–permeability values in the rocks. The poroperm values increases toward the intercrystalline (IX) areas in dolomitised zones.

This interpreted reservoir quality has been dependent to the fractures allowed dissolution process precede more intensively chemical alteration of allochems and unstable components and connecting the isolated porosities (Fig. 6a, b, f).

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Table 1. Petrographic characteristics of the main diagenetic phases within the Asmari Formation Phase

Texture

Crystal shape

Crystal size, µm Color

Other features

C1

Isopachous rim

Bladed-prismatic

<20–30

Non

Surround ooids and peloids

C2

Syntaxial overgrowth

vary

Non

Inclusion-free surround crinoids

C3

Blocky

Equant

<100–200

Dull red

Non-ferroan, vug and fracture-fill

C4

Drusy fabric

Equant

>200

Dull red

Fracture-fill

A1

Chicken-wire and nodular

Non

Primary deposit and occurs in mudstone and wackestoun facies

A2

Nodular and replacement

Lath shaped

Up to 1 mm

D1

Microdolomite

Planar-e

6–12

Non

Non-ferroan, co-exists with primary anhydrite in intertidal facies

D2

Micromedium crystalline matrix

Planar-s

20–60

Non to dull red

Occurs mostly in grainstone facies

D3

Saddle-like dolomites

Undulose extinction

200–300

Dull red

Inclusion-rich cores and inclusion-free rims

D4

Zoned dolomites

Planar-e to planar-s

80–250

Dull to bgight red

Inclusion-rich cores

Secondary replacement and vug-filling deposit

Note. C1–C4, Calcite; A1, A2, anhydrite; D1–D4, dolomite.

Primary porosities including intergranular porosity, fossil cavity (intragranular porosity) and intercrystalline are most common types. Though, these primary porosity types are usually modified even at shallow depth during burial either meteoric realm (Fig. 6c). Petrographic observations have shown that dissolution is the most important factor in porosity (Fig. 6b). This process has been recognized as a key factor in generating reservoir quality in all Asmari Formation (Al-Aasm and Lu, 1994; Durocher and Al-Aasm, 1997). The results of pore types counting indicated that there are eight dominant pore types in these reservoir units. The relative abundance of these pore types is presented in Fig. 7. The most common pore types (mouldic and solution enlarged, up to 60%) in the reservoir rocks were produced by dissolution of the unstable components. Earlier studies reported that mouldic pores increased the porosity but had little effect on the permeability (Fig. 9); however, the association of these pore types with interparticle (shoal complex facies) and touching vugs (e.g., fractures) has increased the poroperm values. This study shows that the best reservoirs are found in grainstone/packstone textures with a high mouldic and interparticle porosity and in dolomitic grainstone/packstone sediments Near-surface leaching processes are associated mostly with the limestone intervals (open-marine grainy facies), because early dolomitized sediments were more stable in meteoric conditions than limestone. The fabric-selective dissolution during meteoric diagenesis created solution pores (Fig. 9). Diagenetic parageneses Calcite Cementation Calcite cementation was of limited significance in the studied thin sections. Four types of mainly nonferroan calcite cements were observed, from early to late stage (Table 1 and Fig. 9): (1) bladed, prismatic isopachous rim calcite (C1; Figs. 6d and 9); (2) syntaxial overgrowth rim calcite (C2; Fig. 6e); (3) equant calcite (C3, Fig. 6b); and (4) blocky

calcite cement (C4). Based on their morphologies the first two generations of cement (C1 and C2) are interpreted to have formed during early diagenesis in a marine phreatic environment, while the latter types of calcite cements formed during shallow to deeper burial stages. Bladed, prismatic isopachous rim cement (C1) surrounds ooids and peloids in the grainstone facies. In this facies, syntaxial, inclusion-free overgrowth cements (C2) occur on crinoid fragments. Some of these calcite cements are partially replaced by dolomite and secondary anhydrite. C3 and C4 calcite cements are abundant and occur mostly as equant, drusy fabric occluding vugs and fractures (Table 1 and Fig. 9). Dolomitization The early stage of diagenesis is characterized by cementing the mouldic pores, the vugs (Fig. 6e) and the fractures (Fig. 6f), grainstone facies by poikilotopic and intergranular cements and equant sparry/fossil cavity-fills (Fig. 6b and d) and dolomitization which stronger influenced the upper Asmari Formation. Furthermore, changing the rock fabrics during diagenesis modified the porosity quantities in the carbonate rocks are strongly tied to water rock chemical interactions (Machel, 2005; Moore, 2001). Dolomitization is particularly influenced the middle and upper parts of Asmari Formation. Dolomites were in the different two forms; fabric-retentive, fabric-selective or partially fabric-destructive. These two different forms of dolomite neomorphism are dolomite retentive crystals which is the product of matrix dissolution and secondary precipitation. The importance of diagenetic dolomitization on reservoir heterogeneity and its impact on poroperm evolution is widely understood (Machel, 2004, 2005). Dolomitic intervals of the reservoir rocks are more permeable than the limestone and anhydrite successions (Figs. 8 and 9). The SEM photo in Fig. 8b shows the intercrystalline spaces in dolomite crystals (Fig. 8b). The source of magnesium in the pore waters of the sedimentary basins could be from the brines originated vicinity

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of Gachsaran formation evaporites (Bahadori et al., 2011; Kent, 1979; Sepehr, 2001; Taberner et al., 2003). Fine-grained dolomite, formed at an early stage, may be dissolved at depth and recrystallized as coarser-dolomite (Warren, 2000). Anhydrite The anhydrite zone covers the upper carbonate reservoir intervals. However, anhydrite is present in different forms of diagenetic textures. The degree of diagenetic dolomitization and the abundance of anhydrite cement both increases upwards in the Asmari Formation, when conditions became less open-marine. It is the main occluding parameter in reservoirs, thus more important from a petrophysical perspective (Lucia et al., 2004). Anhydrite itself is rarely porous its presence increases the formation matrix density by 10 relative percent and clogs the porosity. Thus reserves have been underestimated by about 10 percent. Anhydrite in the studied reservoir occurred as Enterolithic which could consider as Facies F1 and F2 (Fig. 3), anhydrite and dolomites. Generally this microfacies consist of anhydrite/gypsum either as a nodular fabric (chicken wire) or as massive and layered anhydrite (Warren, 2006; Warren and Kendall, 1985) (Fig. 3). Replacive nodular and poikilotopic anhydrite had only a minor influence on porosity and permeabilities values (Figs. 2 and 6a). Even in some cases, anhydrite fabrics enhanced reservoir quality.

Microthermometry A fluid inclusion study was carried out on samples from the lower, middle and upper part of the Asmari Formation. Fluid inclusion microthermometric results are presented in Figs. 10, 11 and Table 2. The wafers used for the fluid inclusion work were obtained for every single paragenetic generation found, dolomite (coarse sparry calcites, vein filling), calcite (sparry, vein filling, fossil cavity), and anhydrite (Fig. 6a minerals paragenesis). Moreover, special care was taken in selecting defect-free crystals, with no visible evidences of deformation. All the selected samples fluid inclusions assemblages is conformed by primary fluid inclusions,

either isolated or along growth zones, as well as pseudosecondary and secondary fluid inclusions trapped along fracture planes and cleavages. Forty samples were analyzed in the lower part. The mineralogy is dominated by coarse-crystalline dolomite, veinfilling dolomite and late vein-filling calcite. Secondary fluid inclusions are not focused much in this study. Isopachous equant/fringe calcite cement Under the optical microscope, calcite crystals contain mostly primary oil and aqueous inclusions appear within the equant and fringe cements that are intercalated with hydrocarbons primary inclusion within the same cement. Primary oil inclusions sizes commonly range from 5 to 15 of microns in dimension. They are two-phase, with a liquid phase composed of a translucent, yellow fluid (Fig. 12). Under UV excitation, organic liquids in inclusions fluoresces vivid light blue to white. Some present under water portion in the liquid HC phase. Primary oil inclusion (n = 11) range from 28 to 58 °C. Aqueous Primary inclusions sizes commonly range from 5s to 10s of microns in dimension. They are two-phase, and translucent. Aqueous inclusions (n = 5) in the same crystal growth have homogenization temperature ranging from 38.8 °C to 53.3 °C (Fig. 11). The early equant calcite cement (C1) have precipitated at temperatures above 35 °C in the presence of waters of moderately high salinity (~22 wt.%). Calcite fossil cavity cement Under the optical microscope, calcite crystals contain mostly primary oil and aqueous inclusions appear within granular mould fill cements that are intercalated with hydrocarbons primary inclusion. Primary oil inclusions are abundant in number and their size is about 5–15 µm diameter. The primary oil inclusions are dominantly two-phase inclusions, with a liquid phase composed of a translucent, colorless to brown fluid, and a gas phase. The most common form of fluid inclusions have negative crystal shapes but some irregularlyshaped varieties also occur. Angular, fragmental particles of solid, probably solid bitumen were sporadically recorded in some inclusions, an indication that they were trapped as solids

Fig. 10. Homogenization temperatures (Th in °C) versus estimated salinities (eq. wt.% NaCl) of fluid inclusions trapped in dolomite, calcite and anhydrite cements. 1, dolomite; 2, calcite.

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Fig. 11. Distribution of homogenization temperatures (Th in °C) of aqueous inclusions trapped in dolomite, calcite and anhydrite cements. 1, calcite; 2, anhydrite; 3, dolomite.

and not derived from the liquid subsequent to entrapment. Under long-wavelength ultraviolet light (UV) excitation, organic liquids in inclusions fluoresces vivid light blue to white. Some present under water portion in the liquid HC phase. Primary oil inclusions (n = 17) found with Th ranging from 40 to 73 °C in calcites with yellow color under UV (Fig. 12) with a defined mode at 64 °C. Secondary oil inclusions observed are of large diameter (10–15 µm) depicts a two-phase liquid phase composed of yellow fluid. The most common form of secondary oil inclusions found is of irregular-shape. They are commonly ranging from 10 to 15 microns in dimension. Under UV secondary oil inclusions are fluorescent in blue to yellow with lower intensity than primary. There seems to be no obvious distribution pattern to the fluorescence colors. The secondary oil inclusions (n = 20) with yellow Fluorescence color obtained Th between 44.7 and 64.9 °C with a well-defined Gaussian maximum distribution at about 53.6 °C. The second group with blue color under UV (n = 23) homogenized at 39.2 to 78 °C temperatures. Homogenization temperatures of this group have a defined mode at 48 °C (Table 2). Primary aqueous inclusions sizes commonly vary from 5 to 20 of microns in dimension. All these inclusions are two-phase. No traps or daughter solids are observed. The most common form of fluid inclusions has negative crystal shapes but some irregularly-shape varieties also found. Primary aqueous inclusions (n = 94) had Th values of 52.3 to 125.2 °C with a defined mode at 86.4 °C and a well-defined Gaussian maximum distribution at about 103.2 °C. The ice melting temperature was in a range from –6 °C to –15 °C, with a

moderately high salinity calculated around 19 eq. wt.% NaCl (Fig. 10). Coarse-crystalline dolomite rim cement Primary petroleum inclusions placed at the outer rims of the dolomite (Fig. 12). They are two phase and large vapor bubbles are present which upon heating homogenize to the liquid phase. They are also different in size and sometime contain gas that is mobile at room temperature. Their sizes commonly range from 10s to 100s of microns in dimension. Many of these inclusions are two-phase, with a liquid phase composed of a translucent, blue to yellow fluid, and a gas phase (Fig. 12). Under UV excitation, organic liquids in inclusions fluoresces vivid light blue to white. Some of them present under water portion in the liquid HC phase. Presence of the brown spots of the oil at the boundaries of cements placed in the fracture, are the impregnation of cements after oil migration. Primary oil inclusion (n = 20) range from 32 to 67.7 °C (Table 2). Primary aqueous inclusions (n = 14) in the rims of coarse matrix dolomites (dolospars) that line up across cavities and fractures, had Th values between 71 and 116 °C, as well as 86 and 117 °C with a well-defined Gaussian maximum distribution at about 90.5 °C (Table 2). The corresponding salinities are 19.3 to 20.5 eq. wt.% NaCl and 18.8 to 20.1 eq. wt.% NaCl. The secondary aqueous fluid inclusions had irregular shapes and larger than primary inclusions. They (n = 11) showed Th values between 41 and 64 °C with a well-defined Gaussian maximum distribution at about 58 °C and estimated water compositions of 19.1 eq. wt.% NaCl.

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Table 2. Fluid inclusions data measured from dolomite and anhydrite minerals. Anhydrite layers are from Asmari Formation Host

Inclusion content and type

Th ranges, °C

µ = Σxi⋅n/N °C

n

Salinity (eq. wt.% NaCl)

Equant calcite

Primary oil

28–58,

52

11

–

Primary aqueous

38.8–53.3

43

5

19.1–20, mean 19.8

Primary oil

40–73

64

17

–

Calcite fossil cavity

Dolomite rim cement

Sparry calcite vein

Dolomite vein/fracture fill

Anhydrite lath

Late calcite vein fill

Anhydrite vein fill

Secondary oil

40–70

51

21

–

Secondary oil (yellow fluorescence)

44.7–64.9

53.6

20

–

Secondary oil (blue UV color)

39.2–78

48

23

–

Primary aqueous

52.3–68.7–76.9–88–98–125.2

103.2

94

19 6.4–18, mean 14

Secondary aqueous

45–73

47

20

Primary oil

32–67.7

57.5

20

Primary aqueous

71–116; 86–117

90.5

14

19.3–20.5 18.8–20.5, mean 19.5 19.1

Secondary aqueous

41–64

58

11

Primary oil

32.3–67.7

57.2

40

Secondary oil

20–28–53

32

10

Primary aqueous

38–44–45–53–75–83

62.9

25

18.1–20.0, mean 20.5

Primary aqueous (coarser calcite crystals)

69–91

77

25

17.2–17.8

Primary oil

67.7–124.1

106

29

Secondary oil

65–104

85

20

Primary aqueous

87.6–104.6

94

100

17.7–19.3, mean 18.6

Secondary aqueous

102–125

119

36

19.8–21.3, mean 20.4

Primary aqueous

47–59–70

53

30

17.3

Primary oil

16–20–46

32

29

Primary oil <75 °C

50–58

54

10

Primary oil >75 °C

110–130

125

9

Secondary oil

48–112

66

60

Primary aqueous

52–76–83

69.5

12

Primary aqueous

50.0–68.8

61

24

17.7–18.4 mean 18

Primary aqueous

106–109

107

3

18.9 17.2–17.8 mean 17.6

Secondary aqueous

70–90

77

14

Primary oil

41–50

43

6

Secondary oil

39–45

39

5

Primary aqueous

45–55

50

3

18–20 mean 19

17

Note. µ, Gaussian maximum distribution; n, frequency of inclusions.

Sparry calcite vein cement Primary oil inclusion found in calcite vein filling cements, though the inclusions contents have not homogenized. Secondary oil inclusions occur in both smaller and coarser crystal sizes of sparry calcite vein cemented the veins/fractures, are commonly ranging in sizes from 10 to 25 microns in dimension. These inclusions are two-phase, with a brown liquid phase under UV and lower intensity than primary ones. Homogenization temperatures of primary oil inclusions hosted by coarser crystals show a broad histogram of homogenization temperature (n = 40) ranging from 32 to 68 °C. Homogeniza-

tion temperatures of this group have a defined mode at 57.8 °C (Table 2). The homogenization temperatures of secondary oil inclusions (n = 10) hosted by smaller crystals are at 20 to 53 °C with a defined mode of 32 °C (Table 2). The data obtained from primary aqueous fluid inclusions (n = 25) in sparry calcite indicate Th between 44.2 to 74.7 °C with a well-defined Gaussian maximum distribution at about 62.9 °C. Primary aqueous inclusions were found in fracture-fill coarser sparry calcite (n = 25) have Th values between 69 and 91 °C with a well-defined Gaussian maximum distribution at about 77, estimated salinities 17.2 to 17.8 wt.% NaCl. Most of the primary oil homogenized between 51 and 56 °C, except

Z. Shariatinia et al. / Russian Geology and Geophysics 54 (2013) 64–81

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Fig. 12. Photomicrographs showing aqueous and oil inclusions in doubly polished wafers: (a) view under incident UV showing examples of primary yellow fluorescent oil inclusions in vein-filling calcite cement (width of view: 300 µm); (b) transmitted light view of primary 2-phase aqueous inclusions in calcite filling a fossil cavity, the oil is orange brown (width of view: 150 µm); transmitted light view of primary 2-phase aqueous inclusions in vein-filling calcite (width of view: 150 µm); (c) view under incident UV showing examples of primary yellow fluorescent oil inclusions in vein-filling calcite (width of view: 150 µm); (d) transmitted light view of a primary 2-phase inclusion in a calcite (width of view: 150 µm).

for two inclusions with Th values of 110 and 130 °C (Table 2). Primary aqueous inclusions had considerably higher temperatures comparing secondary oil inclusions (32 to 68 °C). Coarser sparry calcite precipitated in the vein/fractures cements following the early equant calcite cement. In this cement, the Th of primary aqueous inclusions (n = 80) were measured between 44.6 to 82.7 °C, 52.3 to 76.9, 80.4 to 98.1 °C and 106.6 to 109 °C with a well-defined Gaussian maximum distribution at about 60.9, 64.8, 86 and 107.5 °C, respectively. Fig. 10 displays a cross plot of the Th values versus estimated salinities of the various diagenetic phases measured from the carbonate-evaporite samples in the Asmari Formation. Dolomite vein-filling In the dolomitized veins, the primary oil inclusions are associated with the highest Th values (102 to 125 °C) that homogenized at relatively high temperatures 68 to 124 °C, compared to other oil inclusions in other phases.

Secondary oil inclusions (n = 20) found associated with primary aqueous inclusions homogenized at temperatures between 65 and 104 °C (Table 2 and Fig. 11). Primary aqueous inclusions (n = 100) have Th values ranging from 88 to 105 °C and 104 to 124 °C and 116 °C respectively corresponding to the and salinities between 17.7 and 19.3 eq. wt.% NaCl. The dolomites revealed the highest Th (mostly above 80 °C) (Fig. 10). Thus, they are believed to have precipitated at the highest temperatures compared to all other measured phases. Anhydrite laths Primary petroleum inclusions were found in anhydrite laths. In the anhydrite phase, petroleum inclusions largely homogenized to hydrocarbon liquid at temperatures below 50 °C. Petrographic relationships suggest that anhydrite formed after dolomite. Aqueous inclusions were observed in the anhydrite veins, while the recorded primary oil (n = 29) homogenization temperatures range from 16 to 46 °C with a defined mode at 32 ºC (Fig. 11).

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The anhydrite may have formed at lower temperatures than the dolomite and cooling between the emplacements of the two minerals may have occurred and based on aqueous inclusions are believed to have precipitated at temperatures above 50 °C (Fig. 10). Late calcite vein-filling In calcite vein fills, appear within the last grow zone (Fig. 10) and show yellow color under UV light. All these inclusions are two-phase. Most of the primary oil homogenization temperatures were between 51 and 56 °C except for two inclusions with Th values of 110 and 130 °C (Table 2) which make them different than the previous sparry calcite. Secondary oil inclusions size commonly range from 15 to 20 microns in dimension. These inclusions are two-phase, one with a liquid phase composed of coffee to brown fluid and others more common fluid inclusions are irregular-shape. Under UV secondary oil inclusions are fluorescent in blue with lower intensity than primary. There seems to be no obvious distribution pattern to the fluorescence colors. Secondary oil inclusions showed signs of leakage, such as anomalously high ratios of gas to liquid. Their Th values vary between 48 to 112 °C with a well-defined Gaussian maximum distribution at about 66 °C. The Th values are higher than those found in the later anhydrite vein cements, illustrating the relative cooling (Table 2). Primary aqueous inclusions (n = 24) have Th values from 50 to 69 °C with a well-defined Gaussian maximum distribution at about 60.6 °C and salinities range from 17.7 to 18.4 eq. wt.% NaCl (Fig. 10). Most of the calcites (except the fossil cavity-fill spars) show similar salinities to those of the dolomites (i.e., 19–22 wt.%). Aqueous inclusions Th’s results ranging from 46 to 73 °C for coarser crystals indicated precipitation at temperatures continued largely above 45 °C in the presence of waters of variable salinities (about 6 to 18 wt.%), and to at least 75 °C. Most of the calcites (except the dolomite and calcite spars fossil cavity fill) show similar salinities to those of the dolomites (i.e., 19–22 wt.%) which are believed to have precipitated at temperatures above 50 °C. The vein-filling sparry calcite cement found in the Asmari Formation show relatively less saline water compositions (17–18 wt.%). Anhydrite vein cement Primary oil inclusions are two-phase, with a liquid phase composed of a translucent fluid, and a gas phase. Under UV excitation, organic liquids in inclusions fluoresces vivid light blue. Sizes commonly range from 10 to 40 µm and have negative crystal shapes. They (n = 6) homogenized at 41 to 50 °C. Secondary petroleum inclusions have sizes larger than 20 µm and some contain large gas bubbles this is evidence of stretching or leaking by diagenetic dissolution. Secondary petroleum inclusions (n = 5) in anhydrite crystals yielded with Th values between 39 and 45 °C. Homogenization temperatures of this group have a defined mode at 39 ºC. Primary aqueous inclusions have negative crystal shapes and their sizes are larger than 15 µm. Primary aqueous

inclusions (n = 3) had Th of 45–55 °C and salinity values of 17 eq. wt.% NaCl (Fig. 11).

Discussions and interpretation of fluid inclusion data The youngest primary early equant calcite cement have precipitated at temperatures above 35 °C in the presence of waters of moderately high salinity (~22 wt%). This was followed by the coarser sparry calcite cement fracture/vein fillings, precipitation occurred at temperatures largely above 55 °C continuing to at least 85 °C. This based on the primary aqueous inclusions in the presence of waters with moderately to high salinities (about 19–22 wt%). More saline equant calcite precipitated at temperatures above 35 °C. Consequently, the equant calcite probably formed at lower temperatures than the coarse vein filling calcite cements, which predate petroleum emplacement. Most of the primary oil homogenized range between 51 and 56 °C. The dolospars revealed precipitation temperatures (representing the outer dolomite rims) exceeding 65 °C continuing to at least 125 °C. The dolomite phase (cement-rims on dolospars) postdate calcite vein cements with highest temperatures fits with the highest calcite temperatures (65 to 85 °C) in whole reservoir, while the corresponding high salinity (19 wt.%). Furthermore, oil was present during calcite precipitation in the fracture/vein. Whilst, Th values of oil inclusions (51 and 56 °C) are higher in sparry calcite for anhydrite laths, suggests relative cooling (Table 2). The measured Th values of oil inclusions (about 22–47 °C) are much lower than those of aqueous inclusions in the vein-filling calcite, indicating significant undersaturation with gas. They also suggest that pressures may have been above hydrostatic (Munz, 2001). There is an increasing trend of Th (beginning at 35 °C) during precipitation of the various calcite cement phases. This range from early equant (>35 °C and <45 °C) toward the fossil cavities (>45 °C). The granular calcite mosaic crystals and parry vein filling phase had Th about 80 to 98 °C (>70 °C); though their water salinity did not change remarkably (about 18 to 22 wt.%). The Th evolution from equant toward vein fill calcite may suggest that it corresponds to early and shallow burial cementation with an influx of water that is of different composition during burial with less salinity during cooling. While, primary aqueous inclusions with salinity of 20.5 eq. wt.% NaCl for anhydrite laths demonstrate Th values considerably lower than values were reported from primary aqueous inclusions in the calcite cements (Fig. 11). The occurrence of the monophase inclusion may suggest that anhydrite formed at lower temperatures supports a phase of cooling between the two minerals. However, except from the inclusions found in the calcite cements at the base of the Asmari Formation, the Upper Asmari vein-filling dolomite displays highest Th values; indicating dolomite precipitation temperatures > 85 °C, that continued to at least 105 °C (maximum 125 °C with estimated water salinities of 19.8 to 21.3 eq. wt.% NaCl ~5 times more saline than seawater) (Fig. 10). The recorded range of salinities may invoke a transition from marine to higher salinity waters,

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probably of petroleum derived origin (largely above 80 °C, continuing to at least 95 °C). Oil was present during calcite (27 and 65 °C) / dolomite (68 and 104 °C) / anhydrites (47 to 46 °C) precipitation in the fractures/veins (Table 2). The decreasing tendency in oil inclusions thermal profile (Fig. 11) observed toward anhydrite, which illustrate the relative cooling. The oil inclusions data show the onset of carbonate cementation occurred at temperatures above 45 °C and that cementation was progressive through burial diagenesis. The cementation event is thought to be concurrent with early petroleum generation and migration, because saline waters found trapped in some oil inclusions. Oil inclusions homogenized to liquid at temperatures above 50 °C, indicating significant undersaturated oil with gas in general. Dominating this lower homogenization temperature of petroleum inclusions relative to coexisting aqueous inclusions implies that the oil was undersaturated with gas at the time of inclusion formation. This probably reflects the result of a compositional change to more gas-rich fluid caused by mixing of early reservoired undersaturated oil that later migrated with more mature petroleum. Also, we suggest migrating an undersaturated oil columns in their early histories prior to formation of gas caps and then increasingly mature, higher GOR petroleum followed from a source rocks; likely the vicinity of Kuh-e Mond Oilfield. The composition of the petroleum migrated to Asmari Formation unchanged and the segregation of light components occurred partially. Also, this implies that the amount of migrated gas-rich fluid was insufficient to adjust the original composition of reservoired oils to the composition of more volatile oils or wet gas. Alternatively, high primary homogenization temperatures of 124 °C from oil inclusions for dolostones of Asmari formation, implies to less undersaturated oil compared to the oil inclusions that had lower Th values.

Conclusions This study integrated geochemical data with the depositional and tectonic background of Zagros basin. The importance of estimating the origin and nature of the reservoir fluids is due to their indulgent in extensive dolomitization and appearing anhydrite nodules in the Asmari Formation. The sedimentary textures of carbonates favor and fit well with a model that dolomitizing fluids originated from the highly concentrated brines. Anhydrite texture represent that it had been deposited primarily near-shore, peritidal setting, associated with dolomitization. We attempted fluid inclusions as a geochemical protocol for carbonate reservoirs; which is an approach tested earlier by Aplin et al. (1999) and Tseng and Pottorf (2002). This employed to the petroleum fluids palaeotemperature investigations for modeling the fluid flow of the area in the Kuh-e Mond project. Oil inclusions occur within both fracture–fills cements, dolospars and annealed fractures, indicating that diagenesis

79

continued after and during oil emplacement. And fractures were obviously involved in oil migration. The occurrence of oil phase with saline waters inside fluid inclusions in calcite demonstrates that during calcite precipitation oil was migrating from the source rocks by the late Oligocene to mid-Miocene. Analyzing the aqueous fluid inclusions hosted in the calcite equant sparry/fossil cavity-fills had measured low temperatures of precipitation (<45 °C) and the estimated salinity is 19 wt.%. In dolostones homogenization temperature range between 52 to 125 °C and salinity 6.5 to 20 eq. wt.% NaCl. The lowest Th obtained for vein anhydrite suggests that it may have formed at shallower depths during cooling of the brines and is consistent with uplifting history of the basin. Both fluid inclusion and maturation modeling data indicate late Oligocene to mid-Miocene petroleum t migration into the reservoir at temperatures lower than 50 °C. This indicates that the oil was undersaturated with gas low GOR present in a hydrostatic pressured reservoir during the early Tertiary (Taberner et al. 2003). The Th data suggesting undersaturated oil columns during early histories and then gas-rich fluids migrated in later phase. These were insufficient to adjust the original composition of reservoir oils compared with more volatile oils or wet gas. The decreasing trend of Th temperatures upward Asmari Formation is consistent with the uplift events during Late Miocene time. Later that caused removing about 1300 meters of the crest of Kuh-e Mond anticline. Also the fluid inclusion temperatures are consistent with the vitrinite reflectance-derived temperatures in the pre-Tertiary section, as vitrinite reflectance increases with depth (Table 2). Acknowledgements The authors thank the geochemistry lab staffs in the Department of Geology and Petroleum Geology in University of Aberdeen for technical assistance in carrying out the geochemical analyses. Petroleum samples were provided by National Oil Company of Iran Ltd. Funding for this collaboration project was provided by a grant to the Professor John Parnell.

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