Hydrocarbon Vertical Continuity Evaluation in the ......4 Geophysics Department, Exploration Directorate, National Iranian Oil Company (NIOC), Tehran, Iran . Abstract: A collection

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Hydrocarbon Vertical Continuity Evaluation in the Cretaceous Reservoirs

of Azadegan Oilfield, Southwest of Iran: Implications for Reservoir

Geochemistry

Bahram Alizadeh1,2,*

, Mehrab Rashidi1,3

, Alireza Zarasvandi1,2

, Seyed Rasoul Seyedali1,2

, Mohammad

Hasan Aliee4

1 Department of Geology, Faculty of Earth Sciences, Shahid Chamran University of Ahvaz, Ahvaz, Iran

2 Petroleum Geology and Geochemistry Research Center (PGGRC), Shahid Chamran University of Ahvaz,

Ahvaz, Iran

3 Geochemistry Department, Exploration Directorate, National Iranian Oil Company (NIOC), Tehran, Iran

4 Geophysics Department, Exploration Directorate, National Iranian Oil Company (NIOC), Tehran, Iran

Abstract: A collection of data obtained from analytical methods in geochemistry along with the reservoir

engineering and geologic data were used to investigate the reservoir continuity in the Cretaceous

Fahliyan, Gadavan, Kazhdumi and Sarvak reservoirs of the super-giant Azadegan oilfield, SW Iran. The

geochemical data indicate that the oil samples, with medium to high level of thermal maturity, have been

generated from the anoxic marine marl/carbonate source rock(s). The Sargelu (Jurassic) and Garau

(Cretaceous) formations are introduced as the main source rocks for the studied oils. The dendrogram

obtained from the cluster analysis of high-resolution gas chromatography data introduces two main oil

groups including Fahliyan reservoir, and Kazhdumi along with Sarvak/Gadvan reservoirs. This is

confirmed by C7 Halpern star diagram, indicating that, the light oil fraction from Fahliyan reservoir is

distinct from the others. Also, different pressure gradient of the Fahliyan Formation (over-pressured)

relative to other reservoirs (normally-pressured) show the presence of compartments. The relation

between toluene/n-heptane and n-heptane/methylcyclohexane represents the compartmentalization due to

maturation/evaporative fractionation for Fahliyan and water washing for other studied reservoirs. Also,

the impermeable upper part of the Fahliyan Formation and thin interbedded shaly layers in the

Kazhdumi, Sarvak and Gadvan formations have controlled reservoir compartmentalization.

Key words: reservoir continuity, geochemistry, pressure gradient, oil-oil correlation, Azadegan oilfield,

Abadan Plain

E-mail: [email protected]

1 Introduction

In order to best evaluate the oil and gas continuity and detection of the compartments in the reservoirs,

geochemistry of petroleum and reservoirs have been integrated successfully (Kaufman et al., 1990; Paez et al.,

2010; Smalley and England, 1994). Reservoir compartmentalization discusses the fluid flow barriers between

two reservoirs/layers, such as low-permeability rocks or tar mats (Smalley and England, 1992). Recognizing the

structure of the reservoir and its pressure regime as well as the prediction of fluids behavior with different

compositions in separated compartments are of great importance. To reduce the risk of exploration and

development activities of the field, increasing the knowledge about geological setting of the area and reservoir

characteristics is vital (Smalley and Hale, 1996).

A wide range of analytical methods including reservoir continuity analysis (RCA), geochemical oil-oil

correlation (Hwang and Baskin, 1994; Kaufman et al., 1990; Lindberg et al., 1990; Slentz, 1981), C7 light

hydrocarbon compounds analysis (Ahanjan et al., 2016; Kaufman et al., 1990; Márquez et al., 2016), high-

resolution gas chromatography (HRGC) (Kaufman et al., 1990) and pressure-volume-temperature (PVT)

analysis of reservoir (Paez et al., 2010) combined with geological and geophysical connectivity data

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10.1111/1755-6724.13822.

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interpretation (Hovadic and Larue, 2010) are frequently used to identify the uncertainty of the reservoir

continuity.

The Azadegan field, located in SW Iran, has been introduced as the largest undeveloped oilfield of the world

(Fig. 1) (Du et al., 2015; Liu et al., 2013; Motiei, 2011). The Cretaceous Sarvak, Kazhdumi, Gadvan and

Fahliyan formations (Fig. 2) are considered to be the main reservoirs in the field (Alizadeh et al., 2012, 2016;

Bordenave and Hegre, 2010; Du et al., 2016). Geological and geophysical properties of these reservoirs have

been studied by many researchers (Abdollahie Fard et al., 2006; Abeed et al., 2011; Alizadeh et al., 2012, 2016;

Bordenave and Hegre, 2010; Du et al., 2016; Kobraei et al., 2017), but their continuity as an influencing factor

for the field development has not been investigated yet. Therefore, it is important to elucidate the oil variation

and distribution across the reservoirs and also their compartmentalization caused by either faults or facies

changes. Therefore, the main objective of this research is to assess the reservoirs continuity utilizing

combination of petroleum/reservoir geochemistry with geologic and engineering data. The oil genetic families

and the impact of physical processes (e.g. alteration and biodegradation) on the reservoirs have been

investigated geochemically. Also, the geologic and engineering data were used to delineate the reservoirs filling

scenario, continuity and compartmentalization. The present study illustrates the integrated application of

geochemistry, geology and engineering in reservoir compartmentalization, which in turn controls the oil

accumulation and helps to prepare a road map for the field development.

Fig. 1. Location map of the studied area and the well B in Azadegan oilfield of Abadan Plain (SW Iran) demonstrating the

main tectonic boundaries (Modified from Abdollahie Fard et al., 2006; Bordenave and Hegre, 2010; Zeinalzadeh et al.,

2015; Sherkati et al., 2004).

2 Regional Geology

The Zagros fold-and-thrust belt (ZFTB) is situated along the NE margin of the Arabian Plate and is currently

active compressional belt. The Abadan Plain, as a part of Mesopotamian Foredeep Basin, is located in the

southwest of ZFTB and north of Persian Gulf (Fig. 1) (Alavi, 2004; Beydoun, 1991; Murris, 1980; Sharland,

2001). The Mesopotamian Basin, comprising the pre-Neogene N-S trending folds which are introduced as

Arabian/Pan African trend structures, was not affected by the main phase of the Zagros tectonic movement.

Therefore, structural horsts and tilted fault blocks which are described as reactivated basement structures have


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formed the giant structures and controlled the compaction of sediments in the Arabian plate (Berberian and

King, 1981; Stöcklin, 1968). The Azadegan basement paleo-high, as one of the main horst blocks in

Mesopotamian basin, includes the Azadegan and some of the other giant oilfields (Abdollahie Fard et al., 2006;

Alizadeh et al., 2012, 2016; Du et al., 2016). The collision of Arabian plate with Eurasia continent block in the

late Cretaceous reactivated fault systems, salt domes and N-S structures in Iran, Iraq and Kuwait. The result of

this event has influenced sedimentary sequences of Mesopotamian basin (Abdollahie Fard et al., 2006; Abeed et

al., 2011; Alizadeh et al., 2012, 2016; Beydoun, 1991; Du et al., 2016; Murris, 1980; Sharland, 2001). From the

late Cretaceous to middle Miocene, marine carbonates and shales along with some evaporates were affected by

the onset of Zagros tectonic movement and Infra-Cambrian basement tectonics (Abdollahie Fard et al., 2006;

Bordenave and Hegre, 2010; Du et al., 2016). The main phase of the Zagros orogeny occurred in the late

Miocene and Pliocene, led to reactivation of the fault systems, expansion of Mesopotamian basin and

deposition of the coarse-grained clastic sediments which are sourced from the Zagros Mountains (Abdollahie

Fard et al., 2006; Du et al., 2016; Murris, 1980).

The N-S trending Azadegan oilfield was discovered in 1999 by National Iranian Oil Company (NIOC) and

consists of two parts, corresponding to Cambrian salt tectonic activity. The trend of this field is followed by the

Burgan, Zubair and Nahr Umr structures in Arabian plate (Abdollahie Fard et al., 2006; Abeed et al., 2011;

Alizadeh et al., 2012, 2016; Aqrawi and Badics, 2015; Du et al., 2016; Sharland, 2001). The significant tectonic

movements in Cretaceous conduced to precipitate the platform-type facies of the main carbonate reservoirs (e.g.

Fahliyan and Sarvak) in the Azadegan oilfield. Also, the discontinuous input of clastic sediments prograded

from the Zubair and Burgan deltas (located in the west and southwest of the area) led to the deposition of the

Gadvan and Kazhdumi sandstone reservoirs.

The carbonate Fahliyan (Neocomian) and Sarvak (Cenomanian-Turonian) formations considered to be the

main reservoirs in the field, containing the light (33 API degree) and heavy (20 API degree) oils, respectively.

On the other hand, the sandstone layer of Gadvan (Barremian-Hauterivian) and Kazhdumi (Albian) formations

are the secondary producible reservoirs in the field with the light oil (32 and 30 API degree). The Sarvak

Formation consists of shallow ramp/low-gradient shelf facies. The sandy members in the Kazhdumi and Gadvan

formations illustrate bird-foot delta to prodelta system in a marginal ramp setting (Du et al., 2016). These

successions are represented by Azadegan and Kushk in the Abadan Plain, respectively. The Fahliyan Formation

is mainly composed of shoal facies in the south, and shallow to open marine argillaceous limestones in the north

of the field (Shakeri and Parham, 2013). This formation has been divided into lower and upper parts. The upper

part is composed of an alternation of shales and limestones, while the lower part mostly consists of shallow

marine carbonates interbedded with shales and acts as a reservoir (Soleimani et al., 2017). It also laterally

changes to basinal mudstones of the Garau Formation (James and Wynd, 1965).

Geochemical studies have introduced the Sargelu (Middle-Upper Jurassic) and Garau (Lower Cretaceous)

formations as the main source rocks in Abadan Plain (Abdollahie Fard et al., 2006; Alizadeh et al., 2012, 2016;

Bordenave and Hegre, 2010; Du et al., 2016; Kobraei et al., 2017; Zeinalzadeh et al., 2015). Correspondingly,

Middle-Upper Jurassic bituminous limestones and shales are reported as the main source rocks in the

Mesopotamian basin of Iraq (Abeed et al., 2011; Pitman et al., 2004). Despite the presence of shale layers in the

Gadvan Formation, a fair hydrocarbon generation potential is revealed by the low total organic carbon (TOC)

contents (Kobraei et al., 2017). The efficient seal rocks for the Cretaceous reservoirs are generally the

interbedded/overlaid shaly and argillaceous sediments.

3 Methodology

The drill stem test (DST) oil samples from each reservoirs of the exploration well B in the Azadegan oilfield,

including lower part of Fahliyan, lower sandstone part of Gadvan, sandstone layer in Kazhdumi and thick

limestone of Sarvak (Fig. 2) were collected. Asphaltene fractions from these samples were precipitated by

adding an excess amount of n-hexane. The maltenes (deasphalted oils) were separated into three fractions

including aliphatic/aromatic hydrocarbons and polar compounds using liquid chromatography on a micro

column, filled with alumina:silica gel (2:1, v:v). Prior to chromatography, the column was stored in an oven at

200 ˚C for 12 hr. The aliphatic fractions were eluted with 5 mL of n-pentane. The column then poured by a

mixture of n-pentane and dichloromethane (40:60, v:v 5mL) for separation of the aromatic hydrocarbons.

Finally, the polar compounds were eluted with 5 mL of methanol.


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Fig. 2. Simplified stratigraphic chart with petroleum system elements in the Abadan Plain of Iran and equivalents in Iraq and

Kuwait (after James and Wynd, 1965; Bordenave and Burwood, 1995; Sharland et al., 2001; Alavi, 2004; Sepehr and

Cosgrove, 2004; Du et al., 2016; Baniasad et al., 2017; Soleimani et al., 2017).

In order to evaluate the oil composition and identify different compartments within the reservoirs, a collection

of data obtained from the standard analytical methods such as bulk composition analysis, gas chromatography

(GC), HRGC, gas chromatography-mass spectrometry (GC-MS) and bulk isotope analysis along with pressure

data of the reservoirs were used and integrated with the bulk properties of the oils such as API gravity, sulfur

content and Ni/V ratio (Table 1).

Table 1 Nickel/Vanadium, sulfur content, API gravity and pressure data of the studied oil samples in the Well B of

Azadegan oilfield.

Reservoir Ni (ppm) V (ppm) Ni/V Sulfur (%) API Pressure (psi)

B-Sv 14.00 74.00 0.19 5.60 20 4500

B-Kz 39.00 85.00 0.46 2.50 30 5800

B-Gd 21.00 30.00 0.70 2.10 32 6150

B-Fh 14.00 10.00 1.40 1.60 33 9150

Sv = Sarvak; Gd = Gadvan; Kz = Kazhdumi; Fh = Fahliyan; Ni = Nickel; V = Vanadium.

GC analyses of aliphatic hydrocarbons were done using a Fissions Instruments GC 8000 series equipped with

a split/splitless injector and flame ionization detector (FID) as well as a Zebron ZB-1 HT Inferno fused silica

column (30 m × 0.25 mm i.d. film thickness 0.25 μm, Phenomenex®). GC-MS analyses were performed on


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aliphatic and aromatic fractions using a quadrupole mass spectrometer Trace MS (Thermoquest) linked to a

Mega Series HRGC 5160 gas chromatograph (Carlo Erba, IT) equipped with a 30 m × 0.25 mm i.d. film

thickness 0.25 μm Zebron ZB-5 fused silica capillary column (Phenomenex®). The mass spectrometer was also

operated in order to identify very low concentrations of hydrocarbon compounds in the range of C26 to C35.

Analyses of low molecular weight hydrocarbons in the range of C5 to C9 (Fig. 3) were performed with a

Fissions Instruments GC 8000 series, too. The light hydrocarbons derived from gas-chromatography of the

whole-oils were used to evaluate the content, distribution and behavior of the oil samples, which are helpful for

appraisal of vertical continuity in the reservoirs (Beeunas et al., 1999; Kaufman et al., 1990; Smalley and

England, 1994; Smalley and Hale, 1996).

Fig. 3. The nC5 to nC9 high-resolution gas chromatogram of the Sarvak oil sample in well B.

Sulfur contents were measured by Leco S200 sulfur analyzer instrument. ICP-MS system was used for

computing the Ni and V elements. On the other hand, API gravity of the oil samples was determined by

applying ASTM D-4052 standard method.

Analysis of the bulk stable carbon isotope was performed on the whole oils using a Flash HT 2000 Elemental

Analyzer (Thermo Scientific) equipped with combustion and pyrolysis furnaces and coupled with a Delta V

Advantage IRMS (Thermo Scientific) ion source, which was capable of performing GC analysis.


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The chromatograms were normalized by calculating the peak height ratios of GC. The small peaks located

between the normal alkanes in the range of C9 to C13 (Fig. 4), were selected and used for classification of the

oils into the distinct groups based on cluster analysis (Kaufman et al., 1990).

Fig. 4. Illustrative high-resolution gas chromatographic signatures (Kaufman et al., 1990) for the selected oil samples from

the studied reservoirs, showing the 21 peak ratios selected for compartmentalization studies and used for classification of the

oils into the distinct groups based on cluster analysis (Sv = Sarvak; Kz = Kazhdumi; Gd = Gadvan; Fh = Fahliyan).

4 Results and discussion 4.1 Bulk composition of oils


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The n-alkane profiles of oil samples from each reservoir are dominated by low molecular weight (<nC22)

components (Fig. 5), suggesting a significant contribution of organic matter from planktonic materials to higher

plants (Hunt, 1996). The samples predominate C12 to C36 n-alkanes, with a maximum frequency at nC13 or nC14.

The values of pristane/phytane (<1), Pr/nC17 (0.22-0.42), Ph/nC18 (0.42-0.42) and carbon preference index (CPI,

around 1) indicate that the oils have been generated from anoxic marine marls/carbonates, containing a mixture

Fig. 5. The GC pattern of n-alkanes for the studied oil samples.

of type II and II-S kerogen with terrestrial organic matter input during their deposition (Fig. 6a) (Connan et al.,

1986; Connan and Cassou, 1980; Peters et al., 2005; Tissot and Welte, 1984; Volkman and Maxwell, 1986). The

distribution and relative abundance of the gasoline range hydrocarbons are easily changed by physical processes

including biodegradation and water washing (Hunt, 1996; Tissot and Welte, 1984). All the samples, with the

exception of Fahliyan oil, have slightly altered in various degrees which are demonstrated by GC patterns of n-

alkanes. Furthermore, low values of Pr/nC17 and Ph/nC18 (<1) (Table 2) is an indication of high thermal


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maturity. The Fahliyan, Gadvan and Kazhdumi oil samples are recognized by moderate to high level of thermal

maturity, while the Sarvak oil has less thermal maturity. There is a reverse relationship between sulfur content

and thermal maturity. The sulfur contents ranges from 1.6% in Faliyan oil to 5.6% in Sarvak oil, supported by

their level of thermal maturity (Fig. 6b). Also, based on the result of Tissot and Welte’s (1984) ternary diagram,

the all samples are classified as paraffinic oils (Fig. 6c).

Fig. 6. (a) The cross-plot of pristane/nC17 versus phytane/nC18 indicate that the oils have generated from anoxic marine

marls/carbonates with type II and II-S kerogen and moderate to high level of thermal maturity, (b) plot of the sulfur content

versus Ts/Tm showing the enhancement of the sulfur content from Fahliyan to Sravak reservoir oils supported by their level

of thermal maturity and (c) the Tissot and Welte’s (1984) ternary diagram, classifying the all samples as paraffinic oils.

Table 2 Bulk composition and gas chromatography data of the studied oil samples.

Reservoir Pr/Ph Pr/n-C17 Ph/n-C18 CPI %Saturate %Aromatic %Polar

B-Sv 0.63 0.18 0.37 1.00 74.00 30.00 23.00

B-Kz 0.54 0.19 0.39 0.95 40.00 21.00 39.00

B-Gd 0.60 0.22 0.41 0.99 49.00 31.00 20.00

B-Fh 0.67 0.42 0.42 1.00 52.00 32.00 16.00

Pr = pristane; Ph = phytane; Pr/nC17 = pristane/n-heptadecane; Ph/nC18 = phytane/n-octadecane; CPI = carbon preference index (2 [C23 + C25 + C27 +

C29]/[C22 + 2 (nC24 + C26 + C28) + C30]); Polar = resin + asphaltene.

The ratios obtained from GC and GC-MS data were used to construct the star diagrams which is applied to

show geochemical differences between the oil samples. Good correlation between the star diagrams is due to the

compositional similarity among the samples, indicating their common genetic family originated from the same

source rock(s) (Fig. 7) (Hwang and Baskin, 1994). This is supported by Tissot and Welte’s (1984) ternary

diagram, classifying all samples as paraffinic oils (Fig. 6c). The oil samples contain high contents of nickel and

vanadium, confirming the marine depositional setting of the crude oils (Peters et al., 2005).


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Fig. 7. The star diagram based on the GC parameters (a) and the different biomarker ratios (b), demonstrating the same

genetic oil family for the studied oils.

4.2 Biomarkers and isotopic description

Biomarkers of the oil samples were determined in order to investigate the thermal maturity, depositional

environment and the age of corresponding source rock(s). Different biomarker indicators were used to identify

depositional environment of the source rock(s) (Fig.8), including C22/C21 tricyclic terpane, C24/C23 tricyclic

terpane, C35/C34 hopane, gammacerane/C31 homohopane, C27 diasterne/(diasterane + regular sterane) (Peters et

al., 2005). The ratios indicate marine marl-carbonate source rock(s) deposited under anoxic environments with

some input of the higher plants (Clark and Philp, 1989; Connan et al., 1986; Connan and Cassou, 1980; Peters

and Moldowan, 1993; Peters et al., 2005; ten Haven et al., 1988; Zumberge, 1984). The low salinity condition as

well as restricted stratification in depositional environment of the source rock(s) are represented by the low

gammacerane parameter for the studied oils (Tulipani et al., 2015).


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Fig. 8. The relationship between the facies dependent biomarker ratios including (a) C35/C34 Hopane versus C29/C30 Hopane,

(b) Ts/(Ts+Tm) versus C27 Dia/(Dia+Reg) Steranes, (c) ternary diagram of C27, C28 and C29 steranes, (d)

dibenzothiophene/phenanthrene against pristane/phytane, (e) Gammacerane/C31 Homohopane versus C29/C30 Hopane and (f)

plot of aromatic against saturate carbon isotope data (Sofer, 1984), indicating the oil samples have been generated from the

marine marl-carbonate source rock(s) deposited under anoxic and low salinity environments.

The concentrations of C27, C28 and C29 regular steranes were used to characterize depositional setting of the

corresponding source rock(s) (Fig. 8c). All the oil samples show identical sterane profiles with higher relative

abundance of C27 and C29 steranes, dominated in the marine organisms and the terrestrial plants, respectively

(Volkman and Maxwell, 1986).

Plotting dibenzothiophene/phenanthrene versus pristane/phytane indicates less carbonate content in

depositional settings of the source rock(s) related to Fahliyan and Gadvan oil samples (Fig. 8d). The crude oils

originated from the carbonate source rocks are generally richer in sulfur compounds. Furthermore,

dibenzothiophene parameter is an indicator of the sulfur content. However, the thermal maturity must be

considered while evaluating this parameter (Peters et al., 2005). Based on the plot of

dibenzothiophene/phenanthrene versus pristane/phytane, the Sarvak oil sample shows stronger marine carbonate

signature and consequently the higher relative abundance of the sulfur.

Thermal maturity of the oil samples was evaluated using biomarker isomerization ratios (Fig. 9). The values

of Ts/(Ts+Tm) (<0.3) and C31-hopane 22S/(22S+22R) (0.54-0.68) (Table 3) show medium to high level of


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thermal maturity. However, the Fahliyan and Gadvan oil samples have higher thermal maturity relative to

Kazdumi and Sarvak oils (Seifert and Moldowan, 1986; Peters et al., 2005). This is also demonstrated by the

ratios of C29 sterane 20S/(20S+20R) (0.39-0.50), C29 Sterane ββ/(ββ+αα) (0.55-0.57) and C27 Dia/(Dia+Reg)

steranes (0.08-0.21) steranes as well as Ts/Ts+Tm (0.15-0.28). Furthermore, the high values of

methylphenanthrene index (0.67-0.75, equivalent to 0.75-0.80% vitrinite reflectance) along with the other

triaromatic steroid ratios including C26/C28 TAS (0.14-0.27) and C27/C28 TAS (0.9-1.1) confirm moderate to high

level of thermal maturity (Table 3).

Fig. 9. Maturity related saturate and aromatic biomarker plots including (a) Ts/(Ts+Tm) versus C29 Sterane 20S/(20S+20R),

(b) C29 Sterane 20S/(20S+20R) versus C29 Sterane ββ/(ββ+αα) and (c) C26/C28 Triaromatic Steroids versus C27/C28

Triaromatic Steroids, showing medium to high level of thermal maturity increasing by depth from Sarvak to Fahliyan

reservoirs.

Table 3 Calculated biomarker ratios related to maturity of the oil samples.

Resevoir Ts/

(Ts+Tm)

C31 hopane 22S/

(22S+22R)

C29 Sterane ββ/

(ββ+αα)

C29 Sterane 20S/

(20S+20R) C26/C28 TAS C27/C28 TAS Rc MPI-1

B-Sv 0.15 0.59 0.55 0.39 0.27 1.08 0.77 0.67

B-Kz 0.18 0.55 0.55 0.45 0.21 1.1 0.82 0.75

B-Gd 0.20 0.54 0.55 0.46 0.15 1 0.73 0.75

B-Fh 0.28 0.68 0.57 0.50 0.14 0.9 0.76 0.69

Ts/(Ts+Tm) = 18α(H)-trisnorhopane/[18α(H)-trisnorhopane + 17α(H)-trisnorhopane]; C26/C28 TAS = C26/C28 triaromatic steroids; C27/C28 TAS =

C27/C28 triaromatic stroids; Rc = 0.6 MPI-1 + 0.4 (for 0.65 to 1.35% Ro); MPI-1 = methylphenanthrene index-1 ([1.5 * (2-methylphenanthrene + 3-

methylphenanthrene)]/[phenanthrene + 1-methylphenanthrene + 9- methylphenanthrene]).

Two factors were used to verify that the Sargelu (Jurassic)/Garau (Cretaceous) formations are the main source

rocks for the oil samples. The C28/C29 regular sterane ratio as a geologic age indicator, decreases by time

(Grantham and Wakefield, 1988). This ratio for the studied oil samples ranges from 0.55 to 0.64, specifying the

Jurassic-Lower Cretaceous marine carbonate source rock(s) (Grantham and Wakefield, 1988). This is in

accordance with the stable carbon isotope ratio, varying from -28.1‰ to -28.8‰ (Table 4) (Baniasad et al.,

2017; Bordenave and Hegre, 2010; Chung et al., 1992).

Table 4 Different facies and age related biomarker ratios along with the bulk stable carbon isotope data for the

studied oil samples in the Azadegan oilfield.


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Facies related biomarkers

Age

related

biomarker Whole-

oil

stable

C13

isotope Reservoir G/C31

Hop

C22

Tri/

C21

Tri

C24

Tri/

C23

Tri

C35/C34

Hopane

C29/C30

Hopane

Homo-

hopane

Index

%C27

Sterane

%C28

Sterane

%C29

Sterane

C27

Dia/(Dia+Reg)

Steranes

C27/C29

Steranes

C28/C29

Steranes

B-Sv 0.20 0.72 0.29 1.3 1.65 0.1 41 16 43 0.08 0.74 0.62 -28.8

B- Kz 0.28 0.81 0.36 1.1 1.42 0.1 41 18 41 0.18 0.82 0.64 -28.3

B- Gd 0.16 0.79 0.37 1.03 1.30 0.11 39 19 42 0.21 0.79 0.55 -28.1

B- Fh 0.15 0.71 0.42 1 1.39 0.1 39 20 41 0.19 0.77 0.57 -28.4

G/C31 Hop = gammacerane/C31 homohopane; C22 Tri/C21 Tri = C22 tricyclic terpane/C21 tricyclic terpane; C24 Tri/C23 Tri = C24 tricyclic terpane/C23

tricyclic terpane; C35/C34 Hopane = C35 hopane/C34 Hopane ; C29/C30 Hopane= C2917α-norhopane/C3017α-hopane; Homo Hopane Index = C35/(C31-

C35) homohopanes; C27 Dia/(Dia+Reg) Steranes = C27 diasterne/(diasterane + regular sterane); C27/C29 Steranes = C27/C29 ααα-20R steranes; C28/C29

Steranes = C28/C29 ααα-20R steranes.

Plot of aromatic against saturate carbon isotope data (Fig. 8f) (Sofer, 1984) demonstrates the marine

carbonate source rock(s) for the samples. Although the oil samples show a slight depletion (<2‰) in both

saturate and aromatic carbon isotopes due to thermal maturity variations, they have a common genetic family

(Clayton, 1991; Galimov, 2006; Peters et al., 2005).

4.3 Low-molecular weight hydrocarbons

The star diagram (Fig. 10a) and multivariate statistical cluster analysis (Fig. 10b) were used to evaluate the

high-resolution gas chromatography (HRGC) data of the whole oils (Kaufman et al., 1990). Despite the

similarities between geochemical and isotopic properties of the oil samples, the dendrogram obtained from the

cluster analysis of HRGC offers two main different oil groups. The first group includes only the Fahliyan

reservoir, but the second group is divided into two subgroups including Kazhdumi and Gadvan/Sarvak

reservoirs.

Fig. 10. The star diagram (a) and the cluster diagram (dendrogram) (b) of 21 selected HRGC peak ratios for the studied

reservoir oils, showing two main oil groups including Fahliyan reservoir and Kazhdumi along with Sarvak/Gadvan

reservoirs.

In order to confirm different compartments within the reservoirs, the C7 light hydrocarbon parameters were

investigated. The plot of toluene/nC7 versus nC7/MCH suggests common source rock(s) with type II kerogen for

the oil samples (Thompson, 1979, 1983, 1987, 1988, 2006). Based on the relationship between the values of

heptane and isoheptane (Fig. 11a), the source rock has deposited in a marine carbonate environment (Peters et

al., 2005; Thompson, 1983, 1987, 1988). This is proved by the very low values of toluene/nC7 and higher values

of nC7/MCH (Table 5) (Peters et al., 2005). The cross-plot of toluene/n-heptane versus n-

heptane/methylcyclohexane indicates that the evaporative fractionation/maturation and water washing have

influenced the compartmentalization in the Fahliyan and the shallower reservoirs (i.e. Kazhdumi, Gadvan and

Sarvak), respectively (Fig. 11b) (Thompson, 1979, 1983, 1987, 1988, 2006). Plotting the ratios of

toluene/ethylbenzene versus dimethylbenzene confirms the maturity trend of the oils (Fig. 11c). On the other

hand, the relation between heptane and isoheptane values indicate that all four oil samples are thermally matured


13

(Fig. 11a). These oils are supposed to be originated from the deeper parts of the basin, where the source rock(s)

passed the oil window (Lis et al., 2008). The gas chromatograph pattern as well as biodegradation, sulfur

content and maturity level of the Fahliyan reservoir oil are different from the other oil signatures. These

evidences confirm the existence of two main compartments in the reservoirs.

Fig. 11. The C7 light hydrocarbon plots for the studied oil samples include, (a) Heptane versus Isoheptane ratios, indicating a

common source rock for the oils (After Thompson, 1983, 1987, 1988; Peters et al., 2005), (b) Toluene/n-Heptane versus n-

Heptane/methylcyclohexane, showing the effect of evaporative fractionation, biodegradation, maturation and water washing

on the different reservoir oils (After Lafargue, and Thiez, 1996; Thompson, 1983, 1987, 1988; Peters et al., 2005), and (c)

Toluene/Ethylbenzene against Dimethylbenzene, representing transpicuous trend of thermal maturity for the oil samples

(After Lis et al., 2008).

Table 5 The main ratios obtained from light hydrocarbon analysis, used for calculating the C7 Halpern correlation

start diagrams.

Resrevoir C1 C2 C3 C4 C5 TR1 TR2 TR3 TR4

B-Sv 0.03 0.61 0.11 0.02 0.22 22.24 69.17 28.28 18.37

B-Kz 0.03 0.58 0.15 0.04 0.21 21.07 71.25 24.03 18.28

B-Gd 0.02 0.61 0.13 0.02 0.22 19.81 71.05 29.10 19.63

B-Fh 0.06 0.52 0.20 0.05 0.16 20.78 46.87 16.93 13.43

Resrevoir TR5 TR7 TR8 P2 P3 Heptane

value

Isoheptane

value nC7/MCH Toluene/nC7

B-Sv 46.66 3.74 3.18 2374547 745852 46.11 2.91 2.89 0.32

B-Kz 42.31 2.71 3.88 6561487 1692134 50.36 3.76 3.21 0.30

B-Gd 48.73 3.78 3.39 4693079 1384326 47.12 3.03 3.29 0.28

B-Fh 30.36 2.43 3.63 7648971 2105223 45.03 3.17 2.38 0.44

C1 = 2,2-dimethylpentane/P3; C2 = 2,3-dimethylpentane/P3; C3 = 2,4-dimethylpentabe/P3; C4 = 3,3-dimethylpentane/P3; C5 = 3-ethylpentane; TR1

= toluene/X; TR2 = nC7/X; TR3 = 3-methylhexane/X; TR4 = 2-methylhexane/X; TR5 = P2/X; TR7 = 1-trans-2-dimethylcyclopentane/X3; TR8 =


14

P2/P3; X = 1,1-dimethylcyclopene; P2 = 2-methylhexane + 3-methylhexane; P3 = 2,2-dimethylpentane + 2,3-dimethylpentane + 2,4-dimethylpentane

+ 3,3-dimethylpentane + 3-ethylpentane; MCH = methylcyclohexane.

The main peak ratios obtained from light hydrocarbons were used to compute the C1 to C5 parameters in

Halpern C7 star diagram (Halpern, 1995). This diagram displays the dissimilarities between the plotted light

fractions of the oils (Fig. 12a). This represents that the light oil fraction from Fahliyan reservoir is different from

the other studied reservoirs. Halpern (1995) explained that the low TR1 value is in relation with the low value in

toluene compound and indicates the long migration path. TR1 and TR2 ratios can be affected by water washing

or low level of biodegradation. Therefore, the oil samples with the high values of these ratios (Fig. 12b) have

originated from the source rock(s) in adjacent reservoirs.

Fig. 12. The oil correlation based on the C1-C5 (a) and TR1-TR8 (b) star diagrams for the studied reservoir oils, indicating

the light oil fraction from Fahliyan reservoir being different from the other reservoirs (After Halpern, 1995).

4.4 Engineering framework

Pressure data measured by wireline testers (e.g. MDT and RFT) are required to investigate the reservoir

compartmentalization. The cross plot of pressure data versus depth provide valuable information for detecting

different reservoir compartments in vertical scale. The reservoirs in this study have different pressure gradients

(Fig. 13). These step-like pressure variations confirm different compartments in the reservoirs. In the over-

pressured oil reservoirs, the subsurface pore-fluid pressure is greater than hydrostatic pressure. The pressure-

depth plot for the studied reservoirs demonstrates the overpressure regime in Fahliyan reservoir, represented by

a pressure step between this reservoir and the others. Although the Fahliyan reservoir is significantly over-

pressured, the shallower Gadvan, Kazhdumi and Sarvak reservoirs follow a normal pressure trend. This suggests

the presence of two main vertically-separated compartments, confirming the results obtained from the cluster

diagram and C7 light hydrocarbon analyses. The overpressure regime in Fahliyan reservoir is due to compaction

of the shaly layers in the Upper part of the reservoir, acted as a barrier for fluid flow.


15

Fig. 13. Pressure gradient of the hydrocarbons in the studied reservoirs, showing an overpressure regime in Fahliyan

reservoir.

5 Conclusions

The reservoir continuity of Fahliyan, Gdavan, Khazdumi and Sarvak Cretaceous reservoirs in the Azadegan

oilfield was investigated. For this purpose, a set of reservoir engineering, geologic, and geochemical data

obtained from GC, high-resolution GC, GC-MS, C7 light hydrocarbon and bulk isotope analyses were used.

Based on the results of geochemical analyses, the oil samples have medium to high level of thermal maturity,

increasing by depth from Sarvak to Fahliyan reservoir oils. This is in accordance with the sulfur contents,

ranging from 1.6 to 5.6% in Fahliyan and Sarvak oils, respectively. Various biomarker indicators along with the

GC parameters indicate that the oil samples have generated from the anoxic marine marl/carbonate source

rock(s), containing a mixture of type II/ II-S kerogen. Plot of saturate versus aromatic carbon isotope data, the

high contents of nickel and vanadium as well as the relationship between heptane and isoheptane values confirm

the marine carbonate source rock(s) for all the oil samples.

The C28/C29 sterane ratios and the stable carbon isotope values specify the Sargelu (Jurassic) and Garau

(Cretaceous) formations as the main source rocks for the oils. The high values of TR1 and TR2 ratios, calculated

from the C7 light hydrocarbon analysis, indicate that the oil samples have originated from the source rock(s) in

the adjacent reservoirs.

The good correlation between the GC-star diagrams for the oil samples indicate that they have a common

genetic family, derived from the same source rock(s). This is supported by the Tissot and Welte’s (1984) ternary

diagram, classifying all the samples as paraffinic oils. However, the dendrogram obtained from the cluster

analysis of high-resolution GC data represents two main oil groups. The first group includes only Fahliyan

reservoir, while the second group is divided into two subgroups Kazhdumi and Gadvan/Sarvak reservoirs. Based

on C7 Halpern star diagram, the light oil fraction from Fahliyan reservoir is different from the others. Also, the

changes in the pressure by depth for the studied reservoirs show that the Fahliyan Formation follow an

overpressure trend, while the shallower Gadvan, Kazhdumi and Sarvak reservoirs are normally pressured. These

evidences also suggest different compartments in the studied reservoirs, consistent with the results of the cluster

and the C7 light hydrocarbon analyses.

Due to similar composition of the studied oils, it can be concluded that the oil composition has not played an

important role in reservoir compartmentalization. On the other hand, the cross-plot of toluene/n-heptane versus

n-heptane/methylcyclohexane indicate that the maturation/evaporative fractionation and water washing have

influenced the compartmentalization in the Fahliyan and the shallower reservoirs (i.e. Kazhdumi, Gadvan and


16

Sarvak formations), respectively. Furthermore, the impermeable Upper part of the Fahliyan Formation and the

thin interbedded shaly layers in the other studied formations can be introduced as the controlling factors for the

compartmentalization in studied reservoirs.

Acknowledgments

The authors would like to appreciate National Iranian Oil Company-Exploration Directorate (NIOC-EXP) for

its financial support and the permission to publish this manuscript. We are also, thankful for the valuable

support of the Petroleum Geology and Geochemistry Research Center (PGGRC) of Shahid Chamran University

of Ahvaz.

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About the first author

Bahram Alizadeh was born in 1961. He is Proffesor of Petorleum Geology in Shahid Chamran University (SCU) of Ahvaz

and Director of Petroleum Geology and Geochemistry Research Center (PGGRC) of SCU. His main published research

articles are in the fields of organic/petroleum geochemistry, source rock evaluation, and petroleum system modeling.

Email: [email protected]; cell-phone: +98-916-606-3840.


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