Linking diagenesis to sequence stratigraphy and its impact on reservoir quality of the

Asmari Formation in Naft Sefid field, Dezful Embayment (SW Iran)

B. Soltani*1, H. Rahimpour-Bonab2, A. Rahmani3, E. Sefidari4

1. Research Institute of Petroleum Industry (RIPI), Tehran, Iran

2. School of Geology, College of Science, University of Tehran, Tehran, Iran

3. National Iranian Oil Company (NIOC), Tehran, Iran

4. Research Institute of Applied Sciences (ACECR), Shahid Beheshti University, Tehran, Iran

Abstract

The present study has investigated relationship between diagenesis and sequence stratigraphy along with

their effects on reservoir quality of the sedimentary microfacies. Detailed Microscopy observations of thin

sections from core/cutting-bearing wells led to identification of fourteen microfacies, which are classified into

three sub-environments of Inner ramp (tidal flat, lagoon), Middle ramp and Outer ramp. Inner ramp

microfacies mostly observed in upper and middle parts of the Asmari Formation, while middle to outer ramp

microfacies largely developed in middle part. The most important diagenetic processes controlling reservoir

quality of the Asmari formation include neomorphism, compaction, cementation, dolomitization, dissolution

and fracturing. Transgressive system tract (TST) microfacies in middle to outer ramp have been subjected to

neomorphism, compaction, dissolution (moldic porosity) cementation and partly dolomitization. Based on

petrophysical data with considering diagenetic imprints, seven reservoir zones are proposed for the Asmari

Fromation. Highstand system tract (HST) microfacies of inner ramp dominating the most part of reservoir

zone 1 have been subjected to dolomitization, fracturing, minor compaction, and have better reservoir quality

than the TST microfacies. Finally, correlation of the identified reservoirs zones has been investigated in the

framework of third order stratigraphic sequences.

Keywords: Diagenesis, reservoir quality, sequence stratigraphy, Asmari Formation, Naft Sefid field, Dezful

Embayment

* Corresponding author: bsoltani@alumni.ut.ac.ir

1. Introduction

The Oligo-Miocene carbonate successions of the Asmari Formation and its time-equivalents in

the Persian Gulf considered as one of the most well-known petroleum systems of the Middle-

East, especially in Iran and Iraq, which more than 90% of the recoverable hydrocarbons of Iran

and Iraq (e.g. James and Wynd, 1965; Murris, 1980; Berberian and King, 1981; Motiei, 1993;

Jassim and Goff, 2006). Overall, the Zagros basin contains about two-thirds of proven oil

reserves and one-third of gas reserves in the world (e.g. Beydoun et al., 1992). The Asmari

Formation (well-known as fractured carbonate unit) is the most prolific reservoir in at least 63

fields in Dezful Embayment including several supergiant and giant reservoirs such as Ahwaz,

Marun, Gachsaran, Aghajari, Naft Sefid, SW Iran (Motiei,1993; Alavi, 2004). The most prolific

reserves of the Arabian Platform and Zagros Basin hydrocarbon provinces (almost 400 billion

barrels of oil-in-place and 7% of oil reserves in the world) produced from the Early Miocene

Asmari carbonates and the Albian-Cenomanian Sarvak limestones (Bordenave, 2002;

Rahimpour-Bonab et al., 2012).

Lithologically, the Asmari Formation mainly consists of limestones and dolomites, and some

intervals of marl, shale, sandstone and evaporites can be seen in some parts of it; for example,

Kalhur anhydrite in Lorestan and Izeh zones, and Ahwaz sandstone in southwest Dezful

Embayment (Motiei,1993). In its type section (Tang-e Gel-e Torsh), it is composed of

limestones, dolomitic limestones, and argillaceous limestones with the thickness of 314 m.

However, its thickness varies from 100 to more than 500 m in the Dezful Embayment (Beydoun

et al., 1992; Motiei, 1993).

More recent studies have been conducted on the biostratigraphy and lithological characteristics

(e.g. James and Wynd, 1965; Adams and Bourgeois, 1967; Kalantari, 1986; Seyrafian et al.,

1996; Rahmani et al., 2009; Amirshahkarami et al., 2010; Rahmani et al., 2012), facies analysis

and depositional environment and sequence stratigraphy (Nadjafi et al., 2004; Vaziri-

Moghaddam et al., 2006; Amirshahkarami et al., 2007; Kavoosi and Sherkati, 2012), and isotope

stratigraphy of the Asmari Formation (Ehrenberg et al., 2007; van Buchem et al., 2010).

However, the relationship between the diagenesis and reservoir quality of this formation in a

sequence stratigraphic context are still remained as a relatively unknown issue.

The quality and heterogeneity of carbonate reservoirs are dominantly associated with various

controlling parameters including sedimentary environments, diagenetic agents, tectonic features,

burial history of the basin, and timing of hydrocarbon migration (Choquette and James, 1987;

Wang and Al-Aasm, 2002; Wierzbicki et al., 2006; Morad et al., 2012). Diagenetic key

parameters such as cementation, dissolution and dolomitization have the most controls on

heterogeneous distribution and evolution of reservoir quality of carbonate reservoirs (Wang and

Al-Aasm, 2002; Morad et al., 2012). The integration of diagenesis and sequence stratigraphy can

be applied as a useful tool for predicting sedimentary facies, temporal and spatial distribution of

porosity and permeability in carbonate reservoirs (Moore, 2001; Tucker and Booler, 2002; Caron

et al., 2005; Morad et al., 2012). This method can also justify the cause of compartmentalization

of the mixed carbonate-evaporite reservoirs.

Accordingly, this study aims to (1) determine the main microfacies and their affecting diagenetic

processes and (2) reservoir zonation of the Asmari Formation based on the linking diagenesis to

reservoir quality in the sequence stratigraphic framework.

2. Geological setting and stratigraphy

From the Middle Eocene to Early Miocene, the Arabian Plate has affected the southern Asian

Plate border resulted in the Zagros belt orogeny. The Zagros Basin, as a second largest basin in

the Middle East, extends from Turkey, north-eastern Syria and north-eastern Iraq through north-

western Iran and fallows into south-eastern Iran. The Zagros orogens of Iran are divided into

three principle tectonic units (Stocklin, 1968; De Jong, 1982) namely the Zagros fold-thrust

zone, the imbricated zone and the Urumieh–Dokhtar magmatic zone (Alavi, 2004) (Fig. 1). The

Zagros fold thrust belt is divided into several zones including Lurestan, Izeh, Dezful

Embayment, Fars, High Zagros (Fig. 2), each of them have different tectonic context and

sedimentary history (Berberian and King 1981; Motiei 1993). Generally, the Zagros zones

including Dezful Embayment are considered as northeastern part of the Arabian Plate. These

structures formed as a result of the Arabian-Eurasia collision during the Late Miocene to

Pliocene orogenic stages (Stocklin, 1968). The Dezful Embayment was isolated from Lurestan

and Fars provinces by the Kazerun fault (Falcon1974; Motiei 1993). It considered as a part of the

Zagros fold-thrust belt, in which the Asmari Formation was best developed. Studied intervals of

the Asmari Formation in this research are located in the Naft Sefid oil/gas field, Dezful

Embayment (Fig. 1).

From the Late Cretaceous-Eocene, Dezful Embayment considered part of a NW-SE trending

basin, which was possibly a remnant of the Late Cretaceous fore-deep basin. The basin was filled

with carbonate sediments during the Oligocene and siliciclastic deposits (Ahwaz sandstones) in

the southwestern part of the Dezful Embayment as well (Horbury et al., 2004).

Figure 1 (a) Major tectono-sedimentary subdivisions of the Iran (after Falcon, 1974), (b) Location of the Naft Sefid

field in Dezful Embayment.

The influence of the silisiclastic input has been decreased towards the northern and central parts

of the Dezful area so that there was deeper water basin (more subsidence rate) towards the

northern parts of the Dezful Embayment, and then, the remaining basinal parts filled with the

evaporitic deposits (i.e. Basal Anhydrite and Kalhur Member/ Middle Anhydrite) (Fig. 2).

Convergence of the plates led to closing of the Neo-Tethys, and therefore, deposition of the thick

evaporitic successions of Gachsaran Formation.

The base of the Asmari Formation is diachronous so that its base, towards the coastal Fars area,

is mainly Rupelian in age; but in the Dezful Embayment, its age varies from Rupelian to

Chattian (Motiei, 1993) (Fig. 2). The top of the Amari Formation is mostly Burdigalian in age,

but, toward the coastal and interior Fars, it has Chattian age. For instance, although the

Oligocene deposits of the Asmari Formation have been reported from some outcrops (e.g., Tang-

e-Gurgudan outcrop), and many oil-fields (e.g., Ahvaz, Ab-Teymur, Rag-e-Sefid) in SW Iran,

they have not been deposited in northern oil-fields of Dezful Embayment (such as Naft Sefid and

Haftkel) (e.g. van Buchem et al., 2010). In other words, in the latter fields, deposition of the

Asmari succession began in chattian stage overlaying the Pabdeh Formation with the basal

anhydrite layer, and overlaid by the Gachsaran evaporitic cap rock.

Figure 2 Stratigraphic column of the Oligo-Miocene rock units in the Dezful Embayment, Izeh Zone and High

Zagros, Zagros basin (modified from van Buchem et al., 2010)

3. Materials and methods

Geological data from two exploratory wells (NS-A, NS-B) in the Naft Sefid Field were used

for this study. A total of 1620 standard thin sections from core and cutting samples were

investigated for petrographic purpose. Microfacies analysis and depositional setting of the

samples were done based on Dunham (1962) and Flügel (2004, 2010) classifications.

The reservoir rock types of Lucia classification (1995) were determined through the integration

of depositional facies, diagenetic imprints and petrophysical data. Then, the main controlling

factors affecting the reservoir quality (i.e. depositional textures and diagenetic imprints) were

determined in framework of the depositional sequences. Finally, the proposed reservoir zones of

the Asmari Formation in the studied wells were correlated in the sequence stratigraphic

framework.

4. Facies analysis

Detailed petrographic analysis of the cores, cutting and thin sections allowed the identification

of fourteen (one non-carbonate/ anhydrite and thirteen carbonate) microfacies. Distribution of

microfacies along with their interpreted depositional characteristics indicates a gradual change

from inner ramp to outer ramp sub-environments of a homoclinal carbonate ramp (Soltani et al.,

2013). The major identified microfacies are shown in Figures 3 and 4. In the studied intervals,

the inner ramp facies (dolomitized mudstone (MF2) and echinoid wackestone (MF5)) are the

main constituents of the Asmari Formation while sandy wackestone (MF4) and faverina

packstone (MF12) microfacies have the least frequency.

5. Diagenesis

The diagenesis usually decreases porosity through filling of the available pore spaces by various

forms of cementation and mineral growth; however, it can cause increasing porosity by leaching

of the grain matrix (dissolution) and produce secondary pore spaces; dolomitization processes

can also led to increase, create, reduce, redistribute and preserve porosity (Alsharhan, 1995;

House, 2007). Distribution of the diagenetic parameters as a function of their stratigraphic

position, depositional environment and sedimentary texture determines the ultimate nature of the

rock fabrics, and therefore, their reservoir quality.

Figure 3 The main inner ramp microfacies types of the Asmari Formation in the studied wells; (MF1): Anhydrite,

(MF2): Anhydrite bearing mudstone, (MF3): Dolomudstone, (MF4): Sandy wackestone, (MF5): Echinoid

wackestone, (MF6): Benthic foraminifera wacke to packstone. (MF7): Peloidal packstone, (MF8): Benthic

foraminifera packstone-grainstone, (MF9): Ooid grainstone, (MF10): Coral boundstone.

Figure 4 The main middle to outer ramp microfacies types of the Asmari Formation; (MF11): Algal wacke to

packstone, (MF12): Faverina packstone, (MF13): Bioclastic packstone, (MF14): planktonic foraminifera wacke to

mudstone

Neomorphism, micritization, compaction, cementation, dolomitization, dissolution and fracturing

are the main diagenetic processes, which modified the primary reservoir quality of the Asmari

Formation in the studied wells of Naft Sefid field. Neomorphism was frequently occurred as

transformation of high-Mg calcite into equant calcite spar and recrystallization of the mud-

dominated fabrics. This process has less importance and uncertain role on reservoir quality in the

studied successions.

Micritization, as a common marine diagenetic process, is observed as thin micritic envelopes

around carbonate allochems in most grain-supported facies (e.g., MF7 to MF9) (Fig. 3). This

syn-depositional process caused the more mineralogical stability of the grains against the

compaction and cementation, which prevented porosity loss during burial diagenesis.

Dolomitization is another process widely occurred in the upper part of the Asmari Formation,

which led to create/ increase in porosity/ permeability. This process is the key parameter

controlling reservoir quality, which possibly occurred during reflux of saline brines originated

from Gachsaran Formation (cf. Ehrenberg et al., 2007).

Dissolution is one other diagenetic process, which affected the porosity and permeability. This

process caused the creation of moldic porosity in the upper part of the succession (Fig. 5 C).

Dissolution is observed as preferential leaching of compositionally unstable components such as

aragonitic allochems of Borelis melo curdica and gastropods, which subjected to undersaturated

meteoric pore fluids.

Cementation by anhydrite and calcite is another destructive post-depositional process, which

observed in different types such as fracture-filling, poikilotopic, pore-filling and drusy/ blocky

forms (Fig 5 E-H). Both physical and chemical compactions, which resulted in reducing porosity

and permeability of the facies, are observed in the studied thin sections. Physical compaction led

to the reorientation of grains in some mud-supported microfacies (Fig. 5-D). Chemical

compaction developed as stylolite within both grain and mud dominated facies (Fig. 5-D).

Fractures observed in various scales in the studied wells. They are mostly associated with

compacted and stylolite bearing mud-dominated microfacies, i.e. mudstones and wackstones.

Fracturing is best developed in dolomitized microfacies (Fig. 5-A). In many samples, fractures

are filled with anhydrite and calcite cements. Fracturing appears to be the last diagenetic event in

the Asmari succession, in which fractures have cut the stylolites, unless in rare samples filled

with anhydrite cement (Fig. 5-F).

Figure 5 Main diagenetic processes affecting the reservoir quality of the Asmari Formation in the studied wells; (A)

dolomitization, (B) fracturing, (C) dissolution (moldic porosity), (D) mechanical compaction and stylolite, (E)

Poikilotopic anhydrite cement, (F) fracture-filling anhydrite cement, (G) drusy calcite cement infilling bivalve

bioclast, and (H) blocky calcite cement within bioclast.

6. Reservoir quality and zonation

The reservoir quality of carbonate facies is mainly controlled by the combination of primary

(texture, fabric, grain size, mineralogical composition) and secondary (diagenetic) properties

(Ahr, 2008; Lucia, 1995; 2007). In this section, according to petrophysical classification of Lucia

(1995), the relationship between porosity and permeability are shown by different rock fabric

classes (Fig. 6). Various depositional facies of the Asmari Formation influenced by different

diagenetic processes resulted in different amounts of porosity and permeability (Fig. 6).

Accordingly, in this research, reservoir zones are determined with considering the depositional

characteristics and the most effective diagenetic imprints (dolomitization, anhydrite cementation,

dissolution and fracturing) controlling reservoir quality of the studied wells (Fig. 6 and Table 1).

Figure 6 Poro-perm cross-plot of the Asmari Formation in the studied wells (triangles: well-A, and circles: Well-B)

representing high reservoir quality of lagoon and outer ramp microfacies resulted from dolomitization (pink-dashed

circle), fracturing and dissolution (brown-dashed oval range). Lower quality in these rock fabrics is due to

cementation (mainly anhydrite) and compaction (red-dashed oval range).

In the studied wells, porosity resulting from the dissolution of allochems and permeability from

dolomitization and fracturing caused enhancing reservoir quality of the Asmari Formation.

Compaction and cementation (calcite/ anhydrite) led to decrease in the reservoir quality. Given

that the microscopy observations and porosity-permeability cross plot, dolomudstone (MF3),

echinoid wackestone (MF5) and peloidal packstone (MF7) represent better reservoir quality in

the Asmari interval (Fig. 8), which widely influenced by dolomitization (development crystalline

porosity) and fracturing (increase in permeability).

Despite of low values of matrix porosity (less than 10%), in some oil fields of Dezful

Embayment (e.g. Gachsaran oil field), up to 80,000 barrels of oil per day are produced from the

fractured dolomitized limestone (McQuillan, 1985). The more occurrence and intensity of

fracturing in dolomitized microfacies than the limestones is thought to higher fragility of

dolomite (Ahr, 2008). In addition, the dolomites have higher resistance to compaction (Moore,

2001), and therefore, undergo less reservoir quality loss with depth than limestones (Amthor et

al. 1994). Fractures in the Asmari sequences are partially filled with anhydrite cements; however,

in cases they have not been filled and increased permeability. The main destructive processes are

cementation (anhydrite/ calcite) and compaction, which have significantly decreased porosity

and permeability of the Asmari reservoir in the studied wells (Fig. 8).

Based on depositinal microfacies, rock fabrics and their petrophysical characteristics, and

considering diagenetic impacts, seven reservoir zones have been determined for the Asmari

Formation in the wells NS-A and NS-B of the Naft Sefid Field (Table 1 and Fig. 8). As given in

table 1, the Zone 1 represents the best reservoir quality in the studied wells. Also, the values of

porosity and permeability decrease from Zone 1 to Zone 7 in well NS-B.

Table 1 Determined reservoir zones based on the average values of porosity and permeability in the wells NS-A and

NS-B.

7. Linking between diagenesis and sequence stratigraphy

Sequence stratigraphic investigations led to the determination of three third-order sequences

(Fig. 8); the two first sequences (the equivalent of sequences 4 and 5 introduced by van Buchem

et al., 2010) are Aquitanian in age (Early Miocene), which their deposition started with lowstand

subaqueous anhydrites (i.e. Basal Anhydrite and Middle Anhydrite/ Kalhur Member). The third

sequence (the equivalent of sequence 6 by van Buchem et al., 2010) has Burdigalian age (Middle

Miocene) and represents the last stage of the Neo-Tethys closure marked by shallow water

evaporitic condition (deposition of Gachsaran Formation) (Fig. 8).

Due to the lack of petrophysical and core data in the middle-lower part of the Asmari Formation

in well NS-A, only two reservoir zones in the uppermost part of the Asmari succession (sequence

6 with Burdigalian age) are discussed as following.

Reservoir Zone 1 (RZ-1): This zone is about 58 m thick in the studied wells and corresponds

with the upper part of the Asmari Formation (HST of sequence 6), the upper boundary of which

is overlaid by member 1 of the Gachsaran Formation (Fig. 8). Dolomite and limestone constitute

the main body of this zone. According to the rock fabric classification of Lucia (1995), reservoir

zone 1 lies mainly in the class 3 with permeability range of less than 20 microns (Fig. 7a). The

average values of porosity and permeability in this zone are 9.9 % and 0.65 md, respectively.

This reservoir zone shows the best reservoir quality in which lagoonal to tidal flat microfacies

(dolomitized mudstone and echinoid wackestones) of the inner ramp are dominant. The major

part of the reservoir quality of this zone is associated with the post-depositional processes of

extensive dolomitization, fracturing and dissolution (Figs. 7a, 8 and 9).

Figure 7 Poro-perm values of the upper sequence (sequence 6) of Asmari Formation in the studied wells (squares:

well-A, and circles: Well-B); (a) Reservoir Zone 1, and (b) Reservoir Zone 2

Reservoir Zone 2 (RZ-2): This zone is mainly composed of limestone and dolomite, which

belong to the TST of sequence 6. The average thickness of this zone in the studied interval is

about 51 m. The major components of this zone are related to inner ramp microfacies (lagoon to

outer ramp). This zone has a lower reservoir quality than zone 1 (Table 1); the porosity and

permeability mean values are 7.4 % and 0.16 md, respectively. This resulted from the destructive

impacts of compaction (stylolitization) and anhydrite cementation, as well as limited

dolomitization (Figs. 7b, 8 and 9). Based on the Lucia’s classification (1995), this zone falls into

the classes 1 and 2 (dolomitized packstones to grainstones) with a permeability range of 20 to

500 microns (Fig. 7b).

Figure 8 Sedimentological characteristics and generalized reservoir zones (RZ1-RZ7) of the Asmari Formation

within sequence-stratigraphic framework; the upper part of Asmari succession equals to RZ1-2 shows the best

reservoir quality in the correlated studied wells.

Figure 9 A conceptual sequence stratigraphic model representing the distribution of diagenetic imprints in upper

part of the Asmari Formation (Schematic figure modified after Bosence and Wilson, 2003).

8. Conclusion

The Asmari Formation in the Naft Sefid field has variable thickness of about 200 to 400 meters,

which deposited in a carbonate homoclinal ramp. The most sedimentary thickness of Asmari

Formation in this field is associated with the inner ramp and somewhat the middle-outer ramp

microfacies. Seven reservoir zones were determined for the Asmari Formation based on the

depositional characteristics, diagenetic imprints and petrophysical rock fabrics. The major part of

the reservoir quality observed in zone 1 and 2 (i.e. inner ramp microfacies). High-stand system

tract (HST) was found the best reservoir quality in comparison to transgressive system tract

(TST), which resulted from the constructive impacts of dolomitization, fracturing and dissolution

processes. Inner ramp microfacies in the high-stand system tract were mainly affected by total

dolomitization, fracturing, and selective (moldic) dissolution. Middle-outer ramp microfacies of

the transgressive system tract (TST) were influenced by compaction, dissolution, cementation

and partial dolomitization.

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