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: [email protected]
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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