The impact of micro-to macro-scale geological attributes on Archie's exponents, an example from Permian–Triassic carbonate reservoirs of the central Persian Gulf

Marine and Petroleum Geology 102 (2019) 775–785

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Research paper

The impact of micro-to macro-scale geological attributes on Archie's exponents, an example from Permian–Triassic carbonate reservoirs of the central Persian Gulf

T

Maziyar Nazemi, Vahid Tavakoli∗, Masoud Sharifi-Yazdi, Hossain Rahimpour-Bonab, Mehdi Hosseini School of Geology, College of Science, University of Tehran, Tehran, Iran

A R T I C LE I N FO

A B S T R A C T

Keywords: Archie's exponents Rock type Sequence stratigraphy Lucia plot Depositional features Diagenetic processes

Enormous and inherent heterogeneity of carbonate reservoirs causes problems in the estimation of their geological and petrophysical attributes. The major part of this heterogeneity is due to the various pore types and structures of these reservoirs. Water saturation is economically one of the most important characteristics of any producing reservoir. Archie introduced practical exponents, which are fundamental parameters for saturation calculation. In this research, the effect of geological factors controlling Archie's exponents including depositional and diagenetic characteristics in a sequence stratigraphic framework in Permian–Triassic carbonates of Persian Gulf Basin was carried out. Rock typing approach has been used for assigning reservoir characteristics to geological parameters. Five digenetic facies that were determined according to petrographic studies, wire line logs, SEM and conventional core analysis as well as mercury injection tests, were grouped into four rock types using Lucia diagram. Archie's exponents were calculated for different rock types. Results showed that porosity value and pore type have an important effect on the exponents. This effect could be traced vertically in macro-scale using sequence stratigraphic concept. Grainstone facies with high m values are located in early HST and late TST. Tight grainstone or mud-dominated facies with low m values are located in early TST and late HST.

1. Introduction In petroleum exploration and reservoir evaluation, accurate determination of petrophysical parameters such as porosity, permeability, and water saturation is essential. These parameters are mainly controlled by reservoir geology (depositional conditions and diagenetic processes). Considerable researches have been accomplished in carbonate reservoirs, however, there are still major complications in identifying the properties of these reservoirs (Mazzullo and Chilingarian, 1992; Shedid and Almehadiab, 2002; Asgari and Sobhi, 2006; Chenjei et al., 2015; Hosseini et al., 2018; Nazemi et al., 2018). Unlike homogenous characteristics of siliciclastic reservoirs (uniform in nature), distribution of petrophysical parameters is largely complex in carbonate reservoirs (Lucia, 2007; Bust et al., 2009). The key point is understanding the relationship between geological properties and reservoir characteristics (Chilingarian et al., 1992; Jodry, 1992; Wardlaw, 1996; Serag et al., 2010; Hamada et al., 2013). Water saturation (Sw) assessment is one of the most substantial tasks in formation evaluation. In order to diminish uncertainty of financial forecasting in development of ∗

hydrocarbon reservoirs, accurate calculation of Sw and thus hydrocarbon in place is necessary (Rezaee et al., 2007; Soleymanzadeh et al., 2018). Accurate values of Archie's parameters (a, m, n) mainly control the accurate calculation of water saturation and also play a significant role in formation evaluation (Rezaee et al., 2007). Assuming constant values for these coefficients, Formation Resistivity Factor (FRF) as well as Sw calculations will have considerable errors (Hosseini-nia and Rezaee, 2002; Rezaee et al., 2007). Archie's parameters vary widespread in heterogeneous and complicated lithologies (particularly in carbonate rocks). The occurrence of diverse diagenetic processes such as dolomitization and dissolution and presence of fractures and microporosity in carbonate rocks result in various pore types; accordingly, these contribute to a complex pore structure (Ramakrishnan et al., 2001; Ara et al., 2001). Given the variation and complexity, it is not reasonable to use fixed values of a, m and n to calculate water saturation in various types of rock. Otherwise, calculated water saturation would be either overestimated or underestimated in reservoirs (Mao et al., 1995; Rezaee et al., 2007; Shi et al., 2008; Qin et al., 2016). Hence, variable values of m and a are more appropriate to describe the

Corresponding author. E-mail address: [email protected] (V. Tavakoli).

https://doi.org/10.1016/j.marpetgeo.2019.01.040 Received 11 July 2018; Received in revised form 24 January 2019; Accepted 29 January 2019 Available online 30 January 2019 0264-8172/ © 2019 Elsevier Ltd. All rights reserved.

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to the Najd Rift system, which occurred about 570–530 million years ago with a general trend from northwest to southeast, along with the Zagros Mountains (Fig. 1b) (Alsharhan and Nairn, 1997; Al-Husseini, 2000; Sharland et al., 2001). The tectonic framework of the region consists of a massive crater that includes the outcropped pinnacle in the west and the sedimentation on the margin of the platform in the east and northeast. The main bed rock had a great influence on the sedimentary environment and, consequently, the stratigraphy of sedimentary rocks that were later deposited on it (Al-Husseini, 2000; Ziegler, 2001). Other tectonic movements such as uplift occurred during Middle-Late Cretaceous and, eventually, Zagros orogeny has had fewer effects on the formation of the Persian Gulf and its central part (Insalaco et al., 2006; Tavakoli et al., 2011). Upper Permian–Triassic succession in the central Persian Gulf consists of Dalan (Late Permian) and Kangan (Early–Middle Triassic) formations (equivalent to Khuff Formation in Arabian nomenclature) (Fig. 1a). Kangan and upper Dalan formations host the main amount of hydrocarbon in the studied area. Upper Dalan member (with about 230 m thickness) consists of K4 and K3 reservoir units from bottom to top, respectively. It overlies the Faraghan Formation with an erosional disconformity (Rahimpour-Bonab et al., 2009; Tavakoli, 2016; Abdolmaleki and Tavakoli, 2016) (Fig. 1a). K4 is the major gas reservoir with lime, dolomite and slight amounts of anhydrite lithology. This unit is distinguished from the overlying member (K3) by two anhydrite layers. Dolomitic limestone and dolomite are the main lithologies in the K3 unit (Mehrabi et al., 2016). The Kangan Formation encompasses K2 and K1 reservoir units. The unconformity between K2 and K3 succession is known as Permian–Triassic boundary in the central Persian Gulf (Kashfi, 1992; Rahimpour-Bonab et al., 2009; Tavakoli, 2015; Tavakoli and Jamalian, 2018). The Kangan Formation (with about 193 m thickness) is composed principally of lime, dolomite and anhydrite interlayers. Dashtak Formation with shale and anhydrite lithology is the cap rock of this reservoir (Aali et al., 2006; RahimpourBonab, 2007). K2 and K4 are more significant reservoir intervals than other intervals in the studied succession due to the early dolomitization and dissolution, both of them enhanced reservoir quality (Aali et al., 2006; Ehrenberg, 2006; Moradpour et al., 2008; Rahimpour-Bonab et al., 2009). Evaporation due to dry climate (Insalaco et al., 2006) and saturated brine formation caused extensive dolomitization (Tavakoli

cementation exponent and tortuosity factor specification and to calculate water saturation in most of the reservoirs (Rasmus, 1983; Tabibi and Emadi, 2003; Xiao et al., 2013). In general, the fixed value of m can be estimated by using cross-plot of porosity against FRF that can be achieved by core resistivity measurements (Borai, 1987; Deborah, 2002; Liu et al., 2011). Archie's exponents and their effect on water saturation calculations and reservoir evaluation have been studied by numerous researchers (e.g. Rasmus, 1983; Focke and Munn, 1987; Tabibi and Emadi, 2003; Rezaee et al., 2007; Salazar et al., 2008; Mahmood et al., 2008; Xiao et al., 2013; Wang et al., 2014; Nabawy, 2015; Qin et al., 2016; Glover, 2017; Soleymanzadeh et al., 2018; Nazemi et al., 2018). They have emphasized the role of depositional facies and diagenetic modifications to identify true Archie's exponents. Sequence stratigraphy also establishes a basic model to embody spatial and temporal distribution of petrophysical attributes. Indeed, depositional sequences have a good relationship with depositional and diagenetic attributes (Enayati-Bidgoli and Rahimpour-Bonab, 2016) so that could establish a link between Archie's parameters distribution in different sequence positions. The purpose of this study is the investigation of geological factors controlling Archie's exponents including depositional and diagenetic properties in a sequence stratigraphic framework in Permian–Triassic carbonates of Persian Gulf Basin. Rock typing approach has been used for assigning reservoir characteristics to geological parameters. This approach assists to overcome heterogeneity within the reservoir that complicate prediction of petrophysical properties. 2. Geological setting and stratigraphy Persian Gulf sediments have been accumulated since Paleozoic (Fig. 1a). Detrital sediments deposited from the middle Paleozoic in the southwest of Iran, but in the late Paleozoic carbonates precipitated in the basin, which has continued until the Late Cretaceous, the time for the beginning of the Alpine orogeny (Kashfi, 1992). The main and old structures of the Arabian Plate were under the influence of two tectonic phases: 1) the first tectonic phase was related to the Amar Collision, which occurred about 636–626 million years ago, along the northernsouthern stretch of the Bariik Amar area and 2) The next event is related

Fig. 1. Stratigraphy of Dalan and Kangan formations (a) (Nazemi et al., 2018). Geographical location of the central Persian Gulf Basin (studied area) (b). The main hydrocarbon fields, Arabian plate, and main Zagros trust belt are obvious (b) (modified from Insalaco et al., 2006). 776

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Fig. 2. Thin-section photomicrograph of various diagenetic facies in the studied interval. (a) MDST facies with low reservoir properties (b) MDST facies with birdseye porosity (c) WKST- PKST facies with low porosity and permeability (d) CEG facies with pervasive anhydrite cement (low porosity and permeability) (e) IPG facies with high porosity and permeability (f) MOG facies with moldic porosity and low permeability (g) MOG facies with recrystallized dolomites (high porosity and permeability).

of 1302 thin sections, SEM (Scanning Electronic Microscopy) analysis by VEGA TESCAN, wire line log data in about 326 m, 400 core porosity and permeability data, 29 mercury injection pressure tests, 58 core plugs and 9 whole core samples (to obtain more accuracy) for FRF parameters in about 300 m core, which were chosen from a single well with K1 and K2 (Triassic), K3 and K4 (Permian) units. For petrographical observations and recognizing calcite from dolomite, one-third of each thin section stained with Alizarin Red-S (Dickson, 1965). To indicate the presence of porosity, half of the samples were impregnated

et al., 2011). Dissolution also enhanced reservoir quality at low sealevel situations at the upper K4 and lower K2 units (Tavakoli et al., 2018).

3. Materials and methods This research is based on a dataset from the pay zones of the Permian–Triassic gas reservoirs in one of the gas fields in the central Persian Gulf. In order to achieve determined goals, our dataset consists 777

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Fig. 3. Porosity vs. permeability cross plot (adopted from Lucia, 1995) for diverse rock types of the studied formation.

petrographic studies, four microfacies were recognized that include mudstone, wackestone, packstone, and grainstone. These facies could be grouped into three facies belts (peritidal, lagoon and shoal). In terms of depositional setting, the upper Dalan–Kangan succession was deposited in a homoclinal ramp on the Arabian Platform (Insalaco et al., 2006; Esrafili-Dizaji and Rahimpour-Bonab, 2009; Jafarian et al., 2017). Generally, grain-dominated facies belonging to shoal facies belt improved reservoir attributes. Conversely, mud-dominated facies have high matrix content and resulted in a reduction of porosity and permeability. Diagenetic features in the studied succession contain cementation (anhydrite cements), dissolution (moldic porosities), dolomitization and compaction (both physical and chemical) (TaluAbu-Ghabin, 1989; Alsharhan, 2006; Insalaco et al., 2006; Rahimpour-bonab et al., 2010; Tavakoli et al., 2011; Abdolmaleki et al., 2016). Marine diagenetic conditions resulted in marine calcite cementation and evaporite sediment deposition in hypersaline conditions (Insalaco et al., 2006). The hypersaline diagenetic regime led to the development of dolomitization (seepage-reflux) that improved pore-throats (Esrafili-Dizaji and Rahimpour-Bonab, 2009; Rahimpour-bonab et al., 2010). Carbonate intervals influenced by subaerial conditions has endured moldic dissolution. Dissolution mainly occurred in shoal facies and then had a positive influence on the porosity. Anhydrite cementation process occurred in shallow burial conditions continued to burial diagenetic environment (Rahimpour-Bonab et al., 2009). Other burial events in the studied interval are compaction and cementation which had a negative effect on reservoir evolution (Tavakoli et al., 2011). Compaction (physical and chemical) plays a reservoir barrier role in this formation (Khalifa, 2005; Ehrenberg, 2006; Rahimpour-Bonab et al., 2009, 2010). Cementation process by occluding pore spaces and pore-throats performed pervasive negative effect on the reservoir quality in the studied succession. Petrophysical characteristics in Dalan and Kangan carbonate formations are under the control of sedimentary and diagenetic processes, which need to be considered in defining diagenetic facies. By integration of depositional facies and diagenetic modifications, diagenetic facies would be defined. Here, samples were classified into five diagenetic facies which include mudstone (MDST), wackestone-packstone (WKST-PKST), cemented grainstone (CEG), interparticle grainstone (IPG), and moldic grainstone (MOG) (Fig. 2). These facies in addition to the depositional description defined based on diagenetic modifications and pore types present at facies.

by blue-dyed epoxy. Petrographic studies used for facies description (Dunham, 1962), diagnostic allochems, grain size, and mineral composition, as well as fabrics and diagenesis features. SEM technique was utilized to determine and analyze the cement types and pore characterization of several samples. Determination of percentage of each pore type were carried out by comparison charts in thin sections. By means of Boyle's and Darcy's laws, total porosity and permeability values have been measured through samples, which were cleaned with Soxhlet extraction method. High-pressure mercury intrusion tests were accomplished up to a maximum pressure of 60000 psi to achieve pore-throat size distribution, pore-throat sorting, and distribution. Wire line log data were used to improve comprehensive interpretation through integrating both geological (facies analysis, diagenetic and sequence stratigraphic interpretations) and petrophysical data. To obtain FRF of the core plugs samples at ambient conditions, samples were saturated by brine. Measurement of electrical resistivity under ambient conditions was carried out on sequential days till stabilized resistivity value for each sample was observed. In meantime, samples were judged to ensure that they have attained ionic equilibrium with synthetic formation brine. The following relationship indicates the calculated FRF at ambient conditions:

FRF =

Ro Rw

Where Ro is the resistivity of the core plug with 100% saturation (Ω.m) and Rw is the formation brine resistivity (Ω.m). A log-log graph of FRF versus porosity was made for samples and the best line fit determined using the least square method. The porosity exponent “m” considered as the gradient of the fitted line in accordance with Archie's formula:

FRF =

a Øm

In the Archie equation, Ø considered as porosity (fraction), FRF is Formation Resistivity Factor, m as porosity exponent or cementation exponent and a assumed as intercept with the Y-axis (a = 1 when the line is fitted through (1, 1)). 4. Results 4.1. Geological framework

4.2. Depositional sequences Facies analysis includes the study of depositional features such as components (skeletal and non-skeletal), sedimentary textures, lithology and composition in microscopic and macroscopic scales. Based on

Sequence stratigraphy establishes a chronostratigraphic framework to the distribution of reservoir characterization. Based on T-R method, 778

Marine and Petroleum Geology 102 (2019) 775–785 Intercrystalline-Microporosity Interparticle-Moldic-Intercrystalline Moldic-Interparticle Moldic-Intercrystalline Compaction-Anhydrite cementation Marine cementation-Dissolution-Anhydrite cementation Dissolution-Marin cementation Dissolution-Neomorphism-Marin cementation

4.3. Reservoir rock typing Rock typing is an approach to find out analogs in heterogenetic reservoirs which contains both geological parameters and petrophysical features (Ebanks, 1987; Porras and Campos, 2001). Lucia classification emphasizes particle size, pore type and geometry of pores (Lucia, 1995, 1999, 2007). This classification is based on the carbonate rocks fabrics, which is divided into three groups formed under the influence of the same diagenetic and depositional sedimentary characteristics. According to the integration of petrophysical (porosity and permeability) and geological features, this category includes 1) grainstone and dolomite with particle/crystal size larger than 100 μm 2) packstone and dolomite with particle/crystal size between 100 and 20 μm 3) wackestone and mudstone and dolomite with particles size less than 20 μm. Petrophysical characteristics in Dalan and Kangan carbonate formations are under the control of sedimentary and diagenetic processes, which is why the diagenetic facies have already been introduced. These diagenetic facies were plotted on the Lucia diagram (Fig. 3). Based on the integration of petrophysical (porosity, permeability, m (cementation exponent), and pore type) and geological processes, 4 rock types were determined through diagenetic facies frequency on this diagram. The porosity and FRF values were depicted against each other for each rock type. For each rock type, petrophysical attributes including m, a (tortuosity factor), Archie equations, PTS (pore-throat-sorting in 16, 50 and 86 percent of mercury saturation), permeability, porosity, FRF and R2 (correlation of determination) values as well as geological features (sedimentary and diagenetic properties) are demonstrated in Table 1. Also, the plotted graphs of FRF versus porosity, PTSD and pressure against saturation are displayed for each rock type, similarly (Figs. 4 and 5).

0.07 0.12 0.14 0.19

5. Discussion Geological features such as fabric, size, mineralogy, lithology, and diagenesis are the main factors control the Archie parameters. The change of these features cause drastic heterogeneity in the horizontal and vertical dimensions of carbonate rocks and also cause difficulties in the calculation of petrophysical characteristics such as cementation and tortuosity exponents. Basically, these problems arise from the complicated structure of pore space and the presence of various pore types in carbonate rocks. The most effective procedure to overcome the heterogeneity of the reservoir is to apply a method involving comprehensive integrating of petrophysical and geological features (sedimentary and diagenesis) to achieve higher accuracy results in obtaining Archie coefficients. In this study, Lucia diagram approach for determination of distinct rock types was conducted.

16.99 11.32 9.54 3.98 1.83 2.1 2.26 2.43

0.86 0.47 0.57 0.62

F = 16.99Ø−1.83 F = 11.32Ø−2.10 F = 9.54Ø−2.26 F = 3.98Ø−2.43

176.33 86.3 74.68 57.48

69.56 1.84 11.41 2.93

1.27 6.82 0.4 5.81

MDST-CEG IPG MOG MOG

Pore Type Diagenetic Features Sedimentary Features K PTSD PHI FRF Equations a m

R2

vertical distribution of facies and wireline logs (GR and RHOB), the upper Dalan-Kangan formations are composed of four third-order sequences (KS1, KS2, UDS1 and UDS2) that is correlatable with other studies (Insalaco et al., 2006; Maurer et al., 2009; Koehrer et al., 2010; Aleali et al., 2013; Abdolmaleki et al., 2016; Tavakoli, 2017). Sequence boundaries were recognized by anhydrite layers as the shallowest facies as well as increased RHOB which were developed in sea level fall. These sequence boundaries do not represent erosional evidence and were considered as SBІ (Catuneanu, 2006) in this succession. The maximum flooding surfaces (MFS) highlighted by open marine facies and GR also was elevated in this succession. The end-Permian regression in the region have been confirmed before (Rahimpour-Bonab et al., 2009; Tavakoli, 2015; Tavakoli et al., 2018).

5.1. Rock type 1 This rock type is mainly composed of MDST, WKST-PKST and CEG facies. The remarkable diagenetic attributes of MDST and WKST-PKST facies are compaction (mechanical and chemical) and dolomitization

1 2 3 4

Rock type

Table 1 Rock types and petrophysical attributes associated with sedimentary and diagenetic features of the studied succession.

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Fig. 4. FRF versus porosity plots for rock type 1 (a) and rock type 2 (d). PC plots for rock type 1(b) and rock type 2 (e). PTSD plots for rock type 1 (c) and rock type 2 (f).

the mercury entering in the permeable network is at its highest level compared to other rock types, except rock type 3. The pore-throat size distribution diagram exhibits a high expansion and tendency towards smaller radius. Consequently, the heterogeneity of pores is high and the connections between pores tend to be weak, which causes to increase tortuosity exponent. Moreover, the lower porosity and smaller pore types highly influence cementation exponent (Kazemzadeh et al., 2007; Nazemi et al., 2018). The low cementation exponent in this rock type is affected by low porosity, which is due to compaction and cementation processes. Compaction and cementation are two diagenetic features which have negative effect on the fluid flow through rocks (Moore, 2001; Lucia, 2007). Since this class is mainly composed of MDST and WKST-PKST facies, they are less affected by diagenetic fluids and have less heterogeneity. Therefore, depicted porosity and FRF values against each other represent a slight dispersion and high correlation of determination (see Fig. 7).

(Fig. 6a and b). The compaction process has caused the deposited particles being degraded and greatly reduce porosity. Due to the dolomitization process, microcrystalline dolomites are formed which containing low porosity and also a low connection between the porethroats. However, due to the process of neomorphism, the size of dolomite crystals has increased. Microporous dolomudstone facies contain microporosity which increases the total porosity of the samples. CEG facies are heavily cemented in this category (Fig. 6c). Anhydrite cement has been barricaded in a way that clogs the pores and pore-throats, pervasively. Fracturing occasionally enhance permeability in this facies. A review of petrophysical characteristics also exhibits that this type rock has low porosity and permeability. Low porosity and lack of pore-throat connection in this facies have increased the FRF values compare to other groups. This feature has a great impact on the tortuosity factor, which is controlled by the relationship of pore space in the facies. According to the mercury injection capillary pressure data, one of the main characteristics of this rock type is very high dispersion of the pore-throat size and pores. Despite the low slope of the injection curves and the presence of the flat part at the middle, the pressure of 780

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Fig. 5. FRF versus porosity plots for rock type 3 (a) and rock type 4 (d). PC plots for rock type 3 (b) and rock type 4 (e). PTSD plots for rock type 3 (c) and rock type 4 (f).

increase in sorting and the decrease in the pore-throat radius distribution in this rock type can be inferred. The values of m or cementation factor increases because of the higher porosity and somewhat permeability in this rock type. The attendance of pore spaces and diagenetic factors, such as cementation, have augmented the heterogeneity of the rock type and reduced FRF values. The FRF versus phi plot represents the large dispersion of samples compared to the previous rock types, which is due to the diagenesis effects.

5.2. Rock type 2 IPG facies has the greatest frequency and MOG facies are less frequent than most of the facies forming this class. Most of the grainstone facies in this rock type have intergranular and somewhat moldic porosity, and also have a relatively high permeability. Isopachous marine cementation in the grainstone facies has prevented compaction and maintains porosity and initial permeability (Fig. 6d) (Moradpour et al., 2008; Tavakoli et al., 2011). Anhydrite cementation has been restricted in this group. Petrophysically, this rock type has higher porosity and relatively greater permeability than previous ones. With increasing porosity and permeability, the value of a decreases, indicating the connection of the pore-throats. MICP studies represented that compared to the introduced rock types (1), the curves of this category are characterized by a much lower pressure at the mercury entering point and in contrast higher saturation levels at similar pressures. These features indicate greater connectivity, larger grain size, more sorting and generally higher quality pore-throat network than other rock types. The middle part of the mercury injection curves in the rock type 2 shows a slight slope. By examining the pore-throat size distribution curve, the

5.3. Rock type 3 The MOG facies has the greatest frequency in this rock type. The most considerable diagenetic process in this class is moldic dissolution, which has increased the porosity of the facies by dissolving the allochems (Fig. 6e). Intergranular is less frequent than moldic porosity, which only occurs in grainstone facies. The primary framework is preserved by isopachous marine cementation in some cases, leading to primary intergranular porosity (IPG facies) preservation into the depth of burial. The cementation and compaction processes have had little effect in these facies. From a petrophysical point of view, this rock type 781

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Fig. 6. SEM photomicrograph. (a) MDST facies (b) WKST-PKST facies (c) CEG facies (d) IP facies (e) MOG facies.

of dolomite in the form of euhedral and permeable crystals. Cementation and compaction are negligible in this facies and have no effect on its reservoir properties. In fact, low rate of cementation due to the effect of meteoric diagenesis, did not occlude pore spaces and porethroats. As well, low degree of compaction due to the grain-dominated nature, did not play negative role in decreasing primary porosity and also permeability. Petrophysically, this rock type has the highest porosity and somewhat good permeability. Increase in porosity and permeability leads to a proper connection between the pores, which results in a decrement of the tortuosity factor of the facies so that it has the lowest value. Generally, in this group, the mercury-injection curves illustrate lower pressure at the entrance point of mercury into the porous network and at different points of saturation, compared with other rock types. These features represent a higher porous network quality, greater continuity, larger radius of pore-throats and better sorting. According to the examination of the pore-throat size distribution diagram, increasing the sorting and decreasing the pore-throat radius distribution in the facies of this category are inferred. The maximum porosity in this facies has increased the cementation coefficient and, the permeability values have been effective in increasing the cementation factor. By increasing the amount of empty space in the facies of this class, the values of FRF are reduced. Different diagenesis processes such as selective dissolution, neomorphism, and fracture have led to an increase in

has higher porosity compared to previous one, albeit its permeability does not look too much. The mercury injection curves of rock type 3 indicate a higher pressure than other rock types at the entrance point of mercury into the porous network. In other parts of the capillary pressure-saturation curves, the gradient reflects a pore-throat connection with low conjunction, radius, and poor sorting. Based on the porethroat size distribution curve, the pore-throat radius more than 1 μm is rare in this class and pore-throats are more likely to have a lower radius. In comparison with the other rock types, the pore-throat radius is smaller. Increasing porosity diminish the tortuosity factor and also has a positive effect on the values of m or cementation factor, which is affected by high porosity in this class. As the heterogeneity increases in this type of rock, like the previous rock type, FRF values are reduced, and the samples in the FRF plot show a large dispersion over phi, which is due to porosity increase as the result of diagenetic interactions.

5.4. Rock type 4 The major facies forming this rock type is MOG and then IPG facies. Like the previous rock type, they contain moldic dissolution, but the intensity of this diagenetic process has significantly increased porosity compared to the previous one. The factor of permeability enhancement in this facies comprises processes such as fracturing and neomorphism 782

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Fig. 7. A sedimentological log of the studied succession. In this log, factors controlling Archie's parameters (diagenetic facies, pore type, cementation) along with petrophysical attributes in a sequence stratigraphic framework are observed. BP: interparticle, MOL: moldic, BC: intercrystalline.

and m diminution values and in other hand increasing tortuosity factor (rock type 1 is more abundant in middle TST). In early HST and late TST, the mold pore spaces remain empty and, by creating the MOG facies, increase porosity, permeability, and consequently, m values are obvious (rock types 3 and 4 are more frequent in early HST and late TST). In early TST, porosity, permeability and m increase as a result of sea level fall and the moldic pores are observed (rock type 4 is more abundant in early TST). The KS2 sequence is mainly composed of MDST and less frequent CEG facies. In this sequence, the anhydrite interlayers are frequent and

heterogeneity in the facies of the rock type. As the result, plotting FRF against phi witnesses a large dispersion among the samples. 5.5. Sequence interpretation In the KS1 sequence near the sequence boundary, moldic dissolution along with evaporite deposits developed and influenced by sea level fall (Esrafili-Dizaji and Rahimpour-Bonab, 2009; Tavakoli et al., 2011). These pores were plugged in middle TST with pore-filling anhydrite cement (CEG facies). In this facies, we observe porosity, permeability, 783

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5. Based on the sequence position of different rock types, in general, high-energy grain dominated facies (IP, MOG) in the rock types 3 and 4 are located in late TST and early HST stages. On the contrary, the mud dominated low-energy facies (MDST, WKST-PKST), in the rock type 1 is located in late HST and early TST. The diagenetic processes, such as anhydrite cementation, which blocked the pore spaces and put CEG facies in the rock type 1 class. 6. With the integration of Archie parameters, porosity–permeability and geology features in the context of the sequence stratigraphy, the heterogeneity and uncertainties in the reservoir can be reduced to a large extent.

their presence has led to the development of anhydrite cements in pore spaces in the shoal grainstone facies and reduced the porosity, permeability and m values (rock type 1 is more visible). The only part of the pore spaces that is immune to cementation is the IPG, which is located in early HST (rock type 2 is more abundant in early HST). Open fractures in this sequence cause increased permeability in tight facies (Abdolmaleki et al., 2016). The UDS1 has influenced by sea level fall (late HST) and shallow intertidal and lagoon facies (MDST, WKST-PKST) have developed. This class of facies has porosity, permeability, and m with low values (rock type 1 is more frequent in late HST). In early HST and TST, the porosity, permeability, and m increase due to the expansion of the shoal facies (IPG and MOG) (rock types 3 and 4 are more abundant in early HST and TST). The reason for the increase in permeability is the presence of connected moldic pores in the base of this sequence. The UDS2 is largely formed of MOG facies with less IPG frequency. In the late HST, due to the presence of shallow lagoon facies (MDST), porosity and permeability values, as well as m, is decreased (rock type 1 has a high frequency in late HST). However, in early HST and late TST, initially, the pervasive presence of interparticle and moldic porosity in the grainstone facies resulted in a significant increase in porosity, permeability, and m (rock types 4 and 3 are more abundant in early HST and late TST). The low abundance of anhydrite deposits in this sequence prevents the expansion of anhydrite cements in pore spaces, therefore it has no effect on reservoir properties. Some of the muddominated facies has high porosity and permeability due to the recrystallization process (Tavakoli et al., 2011). Kazemzadeh et al. (2007) stated in their research that cementation exponent in the Archie equation is firmly dependent on pore type. They concluded that by classification of carbonate rocks into the textureporosity types, the acquired R2 from FRF versus porosity is significantly increased. Nabawy (2015) concluded in his study that the major variation of both a and m was due to their dependence on several factors, such as porosity, permeability, and formation factor. He stated that the m is often dependent on the pore volume and elongation pore fabric, while the a is dependent on the porosity, lithology, and permeability. Nazemi et al. (2018) calculated Archie's exponents for seven determined rock types in the central Persian Gulf. Their research clarified that pore typing has a great impact on classifying Archie's exponents. This study confirms the results of these researches while integrates the effects of facies type and diagenetic processes on the exponents.

Acknowledgments The first author would like to thank his parents and his fiancé (Sh. Lund. Shahedi), who gave him so much morale to write this paper and they have always supported him. The authors also would like to thank Prof. Rezaee, associate editor of Marine and Petroleum Geology and one anonymous reviewer which improved the first version. References Aali, J., Rahimpour-Bonab, H., Kamali, M.R., 2006. Geochemistry and origin of the world's largest gas field from the Persian Gulf, Iran. J. Petrol. Sci. Eng. 50, 161–175. Abdolmaleki, J., Tavakoli, V., Asadi-Eskandar, A., 2016. Sedimentological and diagenetic controls on reservoir properties in the permian–triassic successions of western Persian Gulf, southern Iran. J. Petrol. Sci. Eng. 141, 90–113. Abdolmaleki, J., Tavakoli, V., 2016. Anachronistic facies in the early Triassic successions of the Persian Gulf and its palaeoenvironmental reconstruction. Palaeogeogr. Palaeoclimatol. Palaeoecol. 446, 213–224. Aleali, M., Rahimpour- Bonab, H., Mousavi- Harami, R., Jahani, D., 2013. Environmental and sequence stratigraphic implications of anhydrite textures: a case from the Lower Triassic of the Central Persian Gulf. Asian Earth Sci. 75, 110–125. Al-Husseini, M l, 2000. Origin of the Arabian plate structures: amar collision and Najd Rift. GeoArabia 5 (4), 527–542. Alsharhan, A.S., Nairn, A.E.M., 1997. Sedimentary Basins and Petroleum Geology of the Middle East, vol. 20. Elsevier, Azar, pp. 1376 AP - Technology & Engineering – (878pp). Alsharhan, A.S., 2006. Sedimentological character and hydrocarbon parameters of the middle permian to early triassic Khuff Formation, United Arab Emirates. GeoArabia 11, 121–158. Ara, T.S., et al., 2001. In-depth investigation of the validity of the Archie Equation in carbonate rocks. In: SPE Production and Operations Symposium, Oklahoma, 24–27 March. Paper No. SPE 67204. Asgari, A.A., Sobhi, G.A., 2006. A fully integrated approach for the development of rock type characterization. In: Middle East Giant Carbonate Reservoir. Journal of Geophysics and Engineering, pp. 260–270. Borai, A.M., 1987. A new correlation for the cementation factor in low-porosity carbonates. SPE Form. Eval. 2, 495–499. Bust, V.K., Oletu, J.U., Worthington, P.F., 2009. In: The Challenges for Carbonate Petrophysics in Petroleum Resource Estimation: International Petroleum Technology Conference Doha, IPTC 13772. Catuneanu, O., 2006. Principles of Sequence Stratigraphy. Elsevier, Amsterdam, pp. 375. Chenjei, W., Changbing, T., Jie, Z., Kaiping, C., Dong, D., Benbiao, S., Yanpeng, H., 2015. Heterogeneity characteristics of carbonate reservoirs: a case study using wholecore data. In: Society Petroleum Engineering, SPE 175670. Chilingarian, G.V., Torbazadeh, J., Metghalchi, M., Rieke, H.H., Mazzullo, S.J., 1992. Interrelationships Among Surface Area, Permeability, Porosity, Pore Size and Residual Water Saturation, Carbonate Reservoir Characterization: a Geologic Engineering Analysis Part 1, vol. 30. Elsevier Publ. Co., Amsterdam, pp. 379–397. Deborah, A.R., 2002. Trends in cementation exponents for carbonate pore systems. Petrophysics 43, 434–446. Dickson, J.A.D., 1965. A modified staining technique for carbonate in thin section. Sediment. Petrol. 36, 491–505. Dunham, R.J., 1962. Classification of carbonate rocks according to their depositional texture classification of carbonate rocks. Am. Assoc. Pet. Geol. Mem. 1, 108–121. Ebanks, W.J., 1987. Flow unit concept-integrated approach to reservoir description for engineering projects. Am. Assoc. Pet. Geol. Meet. Abstr. 1, 521–522. Ehrenberg, S.N., 2006. Porosity destruction in carbonate platforms. J. Petrol. Geol. 29, 41–52. Enayati-Bidgoli, A.H., Rahimpour-Bonab, H., 2016. A geological based reservoir zonation scheme in a sequence stratigraphic framework: a case study from the Permo–Triassic gas reservoirs, Offshore Iran. J. Mar. Petrol. Geol. 73, 36–58. Esrafili-Dizaji, B., Rahimpour-Bonab, H., 2009. Effects of depositional and diagenetic characteristics on carbonate reservoir quality: a case study from the South Pars gas field in the Persian Gulf. Petrol. Geosci. 15, 325–344. Focke, J.W., Munn, D., 1987. Cementation exponents in middle eastern carbonate reservoirs. SPE Form. Eval. 2, 155–167. Glover, P.W.J., 2017. A new theoretical interpretation of Archie's saturation exponent.

6. Conclusions The following conclusions were obtained through application and consideration of facies studies, diagenesis, reservoir properties (porosity, permeability), Archie exponents and MICP assessments. 1. Five diagenetic facies including MDST, PKST-WKST, CEG, IP, and MOG were identified. 2. With the using of facies information and their stacking pattern, 4 third-order sequences were recognized which are compatible with other studies in the Arabian plate. 3. According to the integration of the diagenetic facies, the petrophysical parameters (porosity, permeability) and Archie exponents, four rock types were distinguished in the framework of the Lucia diagram. 4. Since Archie's exponents are more pore space controlled, their changes depend on the porosity variation rather than permeability changes. So that the values demonstrate a direct relationship with the increase of porosity and some degree of permeability, and there is an inverse relationship between the values of a or the tortuosity factor. In addition, by using the MICP data to investigate the distribution of the pore-throat radius, it was concluded that in highporosity facies, permeability enhancement can also be effective on Archie exponents. 784

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