Investigation of factors influencing geological heterogeneity in tight gas carbonates, Permian reservoir of the Persian Gulf

Journal of Petroleum Science and Engineering 183 (2019) 106341

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Investigation of factors influencing geological heterogeneity in tight gas carbonates, Permian reservoir of the Persian Gulf

T

Marzieh Honarvar Nazari, Vahid Tavakoli∗, Hossain Rahimpour-Bonab, Masoud Sharifi-Yazdi School of Geology, College of Science, University of Tehran, Tehran, Iran

ARTICLE INFO

ABSTRACT

Keywords: Tight carbonate reservoir Mercury injection Rock typing Diagenesis Persian Gulf FZI* (FZI-Star)

Understanding the spatial distribution of petrophysical properties in carbonate reservoirs is complicated due to their heterogeneity and sensitivity to diagenesis along with important facies variations. The reservoir evaluation in tight carbonates is even more complicated. The Permian Dalan Formation in the central part of Persian Gulf is generally considered as conventional carbonate reservoir. However, in this study, a part of K3 unit of this formation is introduced as a tight carbonate reservoir. To identify the factors influencing the quality of this unit, the sedimentary facies, depositional environments, diagenetic processes, and pore-type distribution were studied in details on 402 thin sections. Porosity and permeability of K3 are mainly controlled by dolomitization, dissolution, compaction, and cementation. MICP-based (mercury injection capillary pressure) methods, FZI*(FZIstar), and rock fabric numbers were considered to recognize the factors controlling heterogeneity of this unit. The MICP-based methods of Winland, Pittman, and Rezaee were combined with 3 porosity cutoffs to detect the heterogeneities of tight carbonates. None of these methods provided a high degree of correlation between porosity and permeability of the samples. The results of rock fabric number showed that samples with similar reservoir quality are the product of different diagenetic processes. Results obtained in this study demonstrate that the FZI*(FZI-star) and rock fabric number classifications are the most suitable methods for differentiating the tight zone and non-reservoir/reservoir parts in carbonates of K3 unit.

1. Introduction The main purpose of reservoir characterization is to predict the spatial distribution of petrophysical characteristics such as porosity, permeability, and water saturation, which, in turn, control the amount of hydrocarbons in place (e.g. Lucia, 1999; Ahr, 2008), fluid flow (e.g. Mirzaei-Paiaman et al., 2018, 2019a; 2019b), and hydrocarbon recovery. These characteristics are quite variable in carbonate reservoirs, due to their complexity and heterogeneity compared to sandstones. Complex pore systems, high sensitivity to diagenesis, and significant facies changes differentiate carbonate from sandstone reservoirs (Choquette and Pray, 1970; Beard and Weyl, 1973; Pittman and Larese, 1991; Brown, 1997; Ehrenberg and Nadeau., 2005). Variations in petrophysical properties of carbonate reservoirs at various depths indicate significant changes in their depositional processes, diagenesis and burial history (Ehrenberg and Nadeau, 2005; Bjørlykke, 2014). Several studies showed that diagenesis is an important factor controlling porosity distribution in carbonate reservoirs (e.g. Moore and Wade, 2013). These changes are more significant in low permeability carbonates due to their small pore-throat sizes (Rashid et al., 2015, 2017; Wang et al.,

∗

2017; Hosseini et al., 2018; Zhang et al., 2018). Rock typing and hydraulic flow unit (HFU) determination are the most practical methods to characterize the heterogeneity and understand the controlling factors of reservoir properties. They are also used for special core analysis sample selection (Mirzaei-Paiaman and Saboorian-Jooybari, 2016). Different methods and techniques of rock typing are used based on the objectives of the study and available information (e.g. Amaefule et al., 1993). Bear (1972) defined HFU as the volumes of reservoir rocks which are similar in terms of geological and petrophysical properties. Gunter et al. (1997) described flow units as stratigraphically continuous zones with similar reservoir properties. Mirzaei-Paiaman and coworkers (2018, 2019a and 2019b) have presented two rock types definitions based on the petrophysical characteristics of the carbonate reservoirs. They showed that these two classes of rocks are not necessarily identical and in most cases are different. They defined a group of rocks with similar primary drainage capillary pressure curves as a petrophysical static rock type (PSRT). Knowledge of PSRTs is needed for water-saturation vs. height calculations in the initialization of the simulation model. Also, they have presented a petrophysical dynamic rock type or PDRT (equivalent to the HFU) as a group of rocks with

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

https://doi.org/10.1016/j.petrol.2019.106341 Received 9 March 2019; Received in revised form 27 July 2019; Accepted 3 August 2019 Available online 07 August 2019 0920-4105/ © 2019 Elsevier B.V. All rights reserved.

Journal of Petroleum Science and Engineering 183 (2019) 106341

M.H. Nazari, et al.

Fig. 1. Geological map of the Late Permian and the geographic position of the studied area (modified from Ziegler, 2001).

similar flow behavior. They defined PDRT based on the Kozeny-Carman equation and Darcy's law. Knowledge of HFUs of PDRTs is needed to identify more prolific intervals. Mirzaei-Paiaman and his co-workers (2018, 2019a and 2019b) definition of PDRT of HFU implies that only one index can be obtained to identify HFUs. Because Darcy's law (when Darcy's velocity is replaced by actual velocity) shows that rocks forming an HFU should have similar k/phi values. Mirzaei-Paiaman et al. derived this index and named it FZI* or FZI-Star. Rock typing could help

to identify the static and dynamic behavior of the reservoir (Gomes et al., 2008). These properties, in turn, are controlled by diagenetic processes that follow basic fabric, texture, and reactions between fluid and rock (Gomes et al., 2008; Nazemi et al., 2018, 2019). Currently, there are no specific criteria for the definition of tight gas carbonate reservoirs, and most of the studies have been conducted using the tight gas sandstones’ characteristics. In 1980, the Federal Energy Regulatory Commission defined tight gas sandstone reservoirs 2

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M.H. Nazari, et al.

Fig. 2. Stratigraphic column of the studied member in the Persian Gulf Basin. K3 is the main focus of this study (modified from Tavakoli et al., 2011).

with less than 0.1 mD permeability cutoff. Holditch (2006) defined tight gas sandstone reservoirs with low permeability, which is insignificant for natural hydrocarbon production. According to Zou et al. (2012), tight gas sandstone reservoirs have a porosity of 3–12%, a permeability of less than or equal to 0.1 mD, and a saturation of 40–70%. The Dalan Formation, as the prime conventional carbonate gas reservoir in the Persian Gulf, is the subject of this study (Fig. 1). Although this carbonate formation with the age of Late Permian has been a focus of many studies (e.g. Rahimpour-Bonab et al., 2010; Tavakoli et al., 2011; Abdolmaleki et al., 2016; Mehrabi et al., 2016; Tavakoli and Jamalian, 2018, 2019), its upper part (K3 unit) has never considered as a significant productive unit. It is due to the dominance of mud-dominated facies and destructive diagenesis leading low reservoir quality. This study represents the heterogeneity and controlling factors in rock typing of this low-quality gas carbonate reservoir. Here, we used PSRT and both core-scale and reservoir-scale HFU techniques to find the best method for recognizing heterogeneity in tight carbonates. The study represents reservoir properties along with the effective factors influencing the main characteristics of this unit. Although a small amount of hydrocarbon has been recovered from this unit to date, the K3 would be the main source of gas production from the giant gas reservoirs of the Persian Gulf in the coming years. The results of this study also shed light on the role of facies distribution and diagenetic processes in controlling reservoir quality and its effect on the rock typing of the K3 gas unit.

2. Materials and methods A total of 402 thin sections prepared from 120 m of one well core samples for determination of sedimentary facies, diagenetic processes, depositional environments, and pore types. Core plugs taken at intervals of 0.3 m and one thin section prepared from each plug. The Dunham method (1962) has been used to identify sedimentary facies. Calcite and dolomite mineralogy of thin sections differentiated by alizarin red-S staining (Dickson, 1965). Blue-dyed epoxy impregnation was used to determine the pore types. Porosity types in samples were named after Choquette and Pray (1970). Boyle's law was used to determine the porosity and Darcy's law resolving the air permeability of the core plugs. Different methods were proposed to characterize the heterogeneity and determine the rock types. Rock typing has been performed based on Lucia's methodology (1995), FZI* (FZI-star) (Mirzaei-Paiaman et al., 2018, 2019b), and empirical PSRT indices (e.g. Mirzaei-Paiaman et al., 2015, 2018, 2019a and 2019b; Pittman, 1992; Winland (Kolodzie, 1980); Rezaee et al., 2006). Coefficient of determination (R2) was used to evaluate the relationship between porosity and permeability, which should be close to 1 for a good correlation. 3. Geological setting and stratigraphy The Arabian Plate during the Early Precambrian to Cambrian was part of the Gondwana supercontinent (Alsharhan and Kendall, 1986). The plate moved southward in Ordovician, and then migrated northward (Alsharhan and Nairn, 1997). Two types of structural elements including the Amar Collision (620–640 million years ago) and Najd Rift 3

Journal of Petroleum Science and Engineering 183 (2019) 106341

0.034 0.034

4. Results

0.06 5.37

5.37

0.06

0.029 0.12 5.52 7.16

6.7

0.05

0.034 0.2 8.47 4.54

3.45

0.04

0.031 0.15 2.22 5.99

4.25

0.04

0.03 0.15 7.01 7.64

5.52

0.05

Average K (mD) in tight K3 Average K3 FZI* (μm) Average K (mD) in tight K3 Average K3 K (mD) Average ϕ (%) in tight K3 Average K3 ϕ (%)

System (530–570 million years ago) controlled this prolific basin (AlHusseini, 2000; Sharland et al., 2001). These considerable events resulted in the establishment of the Qatar-Fars Arch as a plaeohigh that affected the tectonic pattern of this region. The Arch subdivided the basin into two parts and played a major role in the distribution of the hydrocarbon reservoirs in the Persian Gulf (Alsharhan and Nairn, 1997; Sharland et al., 2001). In the Silurian, organic shales of the Sarchahan Formation were deposited as the source rock of the region's largest hydrocarbon reservoirs (Konert et al., 2001; Bordenave, 2008). Sedimentation of the Dalan carbonates, equivalent to Lower Khuff Formation (Khalifa, 1992) in Oman, Bahrain, Saudi Arabia, and Kuwait, Chia Zairi in Iraq and Bih and Hagil in United Arab Emirates, began in the warm and dry climatic conditions of the Middle Permian (Insalaco et al., 2006). The climatic conditions changed from the ice-house to the greenhouse during this time, likely to be similar to today's dry Persian Gulf climate (Al-Jallal, 1995; Alsharhan and Kendall, 2003). The siliciclastics of the Middle–Late Permian Faraghan Formation were covered by the Dalan evaporite/carbonate formation, which forms the main reservoir of the Persian Gulf Basin (Tavakoli and Jamalian, 2018). The Dalan Formation is divided into three members from bottom to the top, including the lower Dalan, Nar, and upper Dalan, respectively (Fig. 2). The upper Dalan unit is subdivided into K4 and K3 units. The K3 gas unit is composed of lime/dolomite and anhydrite. The Dalan and Kangan formations are separated by a discontinuity surface in the Early Triassic (Rahimpour-Bonab et al., 2009; Esrafili-Dizaji and Rahimpour-Bonab, 2013; Tavakoli, 2015; Tavakoli et al., 2018).

Peritidal Dolomite

Sedimentary environments and facies distribution of the Dalan carbonates at the central part of the Persian Gulf have been the subject of extensive studies (e.g. Alsharhan, 1993; Al-Jallal, 1994; Alsharhan and Nairn, 1997; Sharland et al., 2001; Rahimpour-Bonab et al., 2009; Enayati-Bidgoli and Rahimpour-Bonab, 2016; Abdolmaleki et al., 2016; Abdolmaleki and Tavakoli, 2016; Tavakoli, 2016, 2017; Jafarian et al., 2017; Tavakoli and Jamalian, 2018, 2019). According to the petrographic examinations of thin sections, four sedimentary environments including peritidal, lagoon, leeward shoal, and proximal open marine have been identified. The following section documents a brief description of sedimentary environments and their facies in the K3 unit (Table 1). 4.1.1. Peritidal The tidal facies and surrounding areas, including supratidal, intertidal, and shallow subtidal, are called peritidal (Folk, 1973; Wright, 1984; Flügel, 2010). The mud-dominated and boundstone facies indicate low energy and shallow depth of the sedimentary environment. Mudstone, dolo-mudstone (Fig. 3a), skeletal wackestone (Fig. 3b) and stromatolite boundstone (Fig. 3c) are included in this environment. Fenestral porosity (Fig. 3d) is seen in some samples, but its overall effect on reservoir properties is negligible. The presence of stromatolite boundstone facies is attributed to the tidal environment (Flügel, 2010). 4.1.2. Lagoon The facies of this environment include peloid/skeletal wackestone, mudstone, dolo-mudstone, and peloid skeletal packstone. The presence of a small number of anhydrite nodules in the grain-dominated facies (packstone) shows relatively slight evaporation in the sedimentary environment (Fig. 3e). The presence of dolomites in the mud-dominated (mudstone and wackestone) facies reflects the effect of early diagenesis on these facies (Tavakoli et al., 2011; Sharifi-Yazdi et al., 2019).

Boundstone

Leeward shoal Grainstone

Packstone

Proximal open marine/ Lagoon Leeward shoal/Lagoon

Limestone/ Dolomite Limestone/ Dolomite Limestone Wackestone

Lagoon/Proximal open marine/Peritidal Dolomite

Mudstone/Dolo mudstone/Fossiliferous mudstone/ Bioturbated fossiliferous mudstone/Fossiliferous dolo mudstone Skeletal wackestone/Bioturbated Skeletal wackestone/Peloid Skeletal wackestone/Bioturbated Skeletal wackestone Peloid skeletal packstone/Skeletal packstone/Intraclast peloid packstone Peloid skeletal grainstone/Skeletal grainstone/Ooid skeletal grainstone/Intraclast peloid grainstone/Intraclast skeletal grainstone Stromatolite boundstone Mudstone

Environments Main lithology Facies

4.1. Facies and depositional environments

Texture

Table 1 Specifications of facies and sedimentary environments in studied unit. Facies, main lithology and environments are arranged based on their abundance in the studied interval. K: permeability, ϕ: porosity.

M.H. Nazari, et al.

4

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Fig. 3. The main facies of K3 unit in Dalan Formation: dolo-mudstone (a), skeletal wackestone (b), stromatolite boundstone (c), fenestral porosity (d), peloid skeletal packstone with anhydrite nodules and cements (e), skeletal grainstone (f). All images are in polarized light. Arrows show the bioclasts.

4.1.3. Leeward shoal This environment consists of peloid/ooid skeletal grainstone and skeletal packstone facies. A relatively high energy environment for these facies can be deduced from various evidence including abundant bioclasts and grain-dominated nature of the samples. Presence of micrite in some cases, without any indication for the very shallow environment (such as evaporites), indicates that these facies were deposited in leeward shoal setting. The existence of interparticle and intraparticle porosities have increased the reservoir quality of this unit (Fig. 3f).

wackestone and mudstone. The presence of bioturbation indicates the perturbation in the surrounding environments. 4.2. Diagenesis Facies distribution and diagenetic history are two important factors in controlling reservoirs’ properties. Also, various rock types are defined based on the integration of the diagenesis and facies characteristics in the framework of porosity and permeability (Tavakoli, 2018). In carbonate reservoirs, diagenesis is the most important factor influencing porosity and permeability distribution (e.g. Lucia, 2007; Ahr, 2008; Moore and Wade, 2013). The strong relationship between sedimentary environments and diagenesis in the Dalan Formation reported earlier (e.g. Rahimpour-Bonab et al., 2010; Tavakoli et al., 2011; Asadi-

4.1.4. Proximal open marine The distance of the facies from brine source, evaporation, and high energy of waves has led to the formation of limy facies such as skeletal 5

Journal of Petroleum Science and Engineering 183 (2019) 106341

M.H. Nazari, et al.

Fig. 4. Anhydrite cements (a), blocky calcite cements (b), signs of compaction (c), dolomitization (d). All photos are in polarized light. Arrows show the mentioned properties.

dissolution. The result of this process is seen as moldic pores in petrographic studies. Dissolution has mainly occurred during meteoric diagenesis but continued until the burial environment (Abdolmaleki et al., 2016). When this porosity type is associated with other diagenetic processes, such as dolomitization or fracture, the quality of the reservoir was greatly increased (Rafiei et al., 2016). 4.2.3. Dolomitization Early dolomitization is one of the main carbonate diagenetic processes, which often occurs in the vicinity of marine environments when sediments exposed to a high-density brine source (Warren, 2006). Due to the presence of Mg2+, dolomite has a higher density than the calcite, and so this dolomitization increases the reservoir quality (Saller, 2004). Dolomitization remains as the predominant diagenetic process in the mud-dominated (mudstone/wackestone) and boundstone facies of this carbonate unit. Dolomitization has enhanced the overall reservoir quality (Fig. 4d) of both mud- and grain-dominated textures (Tavakoli and Jamalian, 2019). In the Dalan Formation, stromatolites occur in peritidal environments and are dolomitized when the brines available.

Fig. 5. Porosity and permeability cross-plot in the K3 unit with dolomite percentage in the samples. Most of the samples have low permeability.

Eskandar et al., 2013; Abdolmaleki et al., 2016). The prominent diagenetic processes controlling reservoir quality of K3 unit are investigated below.

4.3. Range of poroperm The porosity in the K3 unit of the Dalan Formation, as shown in Fig. 5, varies between 32% and 0.08%. Almost half of the data has a permeability of less than 0.1 mD. In the lack of accepted porosity and permeability cutoffs for the definition of tight gas carbonate reservoirs, we propose three cutoffs here. The first is based on the works of Zou et al. (2012) and the two others based on the porosity frequency distribution in the studied reservoir, as described below.

4.2.1. Cementation Anhydrite and blocky calcite are the most frequent types of cement in this unit. Anhydrite cements (Fig. 4a) were produced by the early diagenetic processes while blocky calcite cements (Fig. 4b) were formed in meteoric and shallow to deep environments (Tavakoli and Jamalian, 2018). These types of cement generally occlude a large intergranular porosity. In many samples, these cements have prevented further compaction through binding the allochems and creating a solid framework (Fig. 4c). In some cases, blocky calcite and anhydrite cements were also precipitated inside the pores. In the case of complete pores filling, the reservoir quality was lost.

4.3.1. Cutoff Ⅰ Samples with porosity range from 3 to 12% and permeability of less than or equal to 0.1 mD were considered as the tight parts of the K3 unit, as suggested by Zou et al. (2012) for tight gas sandstones. 4.3.2. Cutoff Ⅱ Samples with a permeability of less than or equal to 0.1 mD have

4.2.2. Dissolution Another factor affecting the reservoir quality of the K3 unit is 6

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M.H. Nazari, et al.

Fig. 6. Normal probability plot of FZI* values (a), plot of 0.0314 √k versus √ ϕ on a log-log plot for core-scale HFUs base on FZI* method (b), the position of tight samples in the previous plot (c), the percent of tight samples in various HFUs in K3 unit (d).

Rezaee et al. (2006) methods to evaluate the heterogeneity based on sample pore-throat size distribution. The goal is to identify any useful method and so we used the equations for both sandstone and carbonate samples. Here, the application of these methods is to compare tight samples with conventional carbonate reservoirs. In these three methods, the pore throat radii are divided into six classes including 0.2–0.5, 0.5–1, 1–2, 2–5, 5–15, and 15–20 μm.

been selected. Then, major changes in porosity frequency of these samples detected by porosity frequency distribution diagram. In this method, the porosity ranges of 2–5% and 5–8% had different frequencies. It is worth mentioning that the maximum porosity of the samples with less than 0.1 mD permeability is about 8%. Each rock typing method was applied in these two porosity groups. 4.3.3. Cutoff Ⅲ The porosity frequency distribution of all K3 samples was evaluated. The porosity ranges from 2 to 8% and 8–32% had two different frequencies. Then, the samples with a permeability of less than or equal to 0.1 mD selected for further studies. As with cutoff II, each rock typing method separately applied in these two groups. All samples with less than 0.1 mD permeability and any porosity value (from 2 to 32%) were also considered as one group to evaluate all low permeability samples without any subdivision.

4.4.1. Winland plot Using the MICP data in sandstone and carbonate samples from the Weyburn (Canada) and Spindle (United States) oil fields as well as Hidalgo (United States) gas field, Winland found that the pore-throat sizes in 35% of the mercury saturation are best correlated with porosity and permeability (Kolodzie, 1980). Winland's equation (Kolodzie, 1980) is as follows:

Log (R35) = 0.732 + 0.565 Log (K air )

0.864 Log ( )

(1)

where R35 is pore-throat radius in 35% saturation in MICP test (μm), Kair is air permeability (mD), and ϕ is porosity (%). The R35 of all samples calculated by Winland method was less than 0.5 μm. For the purpose of distributing the samples in more homogenized groups, the Winland method excluded from further considerations.

4.4. Empirical static rock typing indices There are three empirically-derived methods to determine the PSRT in the reservoirs. All of these methods have been developed based on the mercury injection capillary pressure (MICP) test data. These methods have been collected and reviewed by Mirzaei-Paiaman and his co-worker (2019a). The distribution and size of the pores can be measured using the MICP curve technique provided by Purcell (1949). In this study, we used Winland (Kolodzie, 1980), Pittman (1992), and

4.4.2. Pittman Using 202 sandstone samples from the USA and with further study of Winland's method (Kolodzie, 1980), Pittman (1992) obtained the 7

8

7.24

10.14

5.41

7

8

9

6.26

4

5.06

5.21

3

6

4.09

2

5.39

5.93

1

5

Average ϕ (%)

HFU

58.05

7.27

1.31

0.18

0.15

0.11

0.07

0.04

0.04

Average K (mD)

0.9

0.26

0.12

0.06

0.05

0.04

0.04

0.03

0.02

Average FZI* (μm)

Skeletal grainstone/Peloid skeletal grainstone/Ooid skeletal grainstone Bioturbated skeletal wackestone/Skeletal wackestone Peloid skeletal packstone/Skeletal packstone Stromatolite boundstone Bioturbated mudstone/Fossiliferous mudstone/Dolo mudstone Peloid skeletal grainstone/Ooid skeletal grainstone Bioturbated skeletal wackestone/Fenestral skeletal wackestone Skeletal packstone Mudstone/Bioturbated mudstone/Fossiliferous mudstone Peloid skeletal grainstone/Ooid skeletal grainstone/Intraclast skeletal grainstone Skeletal wackestone/Bioturbated skeletal wackestone Peloid skeletal packstone/Intraclast skeletal packstone Peloid skeletal grainstone/Ooid skeletal grainstone Peloid skeletal wackestone Mudstone/Dolo mudstone Peloid skeletal packstone Mudstone Peloid skeletal grainstone Skeletal wackestone Peloid skeletal packstone/Bioturbated skeletal packstone Peloid skeletal grainstone/Skeletal grainstone/Ooid skeletal grainstone Mudstone/Fossiliferous mudstone/Dolo mudstone Skeletal wackestone/Peloid skeletal wackestone Peloid skeletal packstone

L/D L L/D L L L D D L D/L L D L

L L L D L D L D/L D/L L

L/D L/D

Peloid skeletal grainstone/Skeletal grainstone/Intraclast skeletal grainstone/Ooid skeletal grainstone Peloid skeletal packstone Mudstone/Dolo mudstone Peloid skeletal grainstone/Intraclast skeletal grainstone/Skeletal grainstone Skeletal wackestone Peloid skeletal packstone

L

L/D L

D/L D L

Dolo mudstone/Mudstone Skeletal wackestone/Bioturbated skeletal wackestone

D D/L

D/L

D/L

Skeletal wackestone Peloid skeletal packstone Dolo mudstone/Mudstone/Fossiliferous mudstone

D/L

Facies Skeletal grainstone/Peloid skeletal grainstone/Ooid skeletal grainstone/Skeletal intraclast grainstone Mudstone/Bioturbated mudstone/Fossiliferous mudstone

L

Lithology

Mold Inter

Inter/Intra/Mold Intercry/Mold Inter/Intra/Mold

Mold/Intercry Mold/Inter/Intra/ Vug Inter/Intra

Mold/Vug Mold/Inter/Intra

Mold/Intercry/Vug

Mold/Intra Mold/Intra Inter/Intra/Mold

Mold/Intra/Inter _ Mold _ Intra/Inter

Intra Mold/Intra

Mold

Mold Mold Mold/Intercry Intra/Mold/Inter

Intra/Inter/Mold

Mold _ Intercry Mold/Intercry

Intra/Inter/Mold

Mold/Intercry/Inter/ Intra Mold Mold/Inter/Intra _

Mold/Intra/Inter

Porosity type

Anhydrite & Blocky Cementation/ Compaction Compaction/Anhydrite Cementation Dolomitization Anhydrite & Blocky Cementation/ Compaction Compaction/Dolomitization Compaction

Dolomitization/Compaction Compaction/Blocky & Anhydrite Cementation Dolomitization Compaction/Dolomitization

Compaction/Anhydrite Cementation Compaction/Blocky & Anhydrite Cementation Compaction/Anhydrite Cementation Dolomitization Compaction/Anhydrite Cementation Dolomitization Compaction/Blocky & Anhydrite Cementation Dolomitization/Compaction Compaction/Anhydrite Cementation Compaction/Anhydrite & Blocky Cementation Dolomitization/Compaction

Blocky & Anhydrite Cementation/ Compaction Dolomitization Compaction/Blocky Cementation Dolomitization Anhydrite & Blocky Cementation/ Compaction Dolomitization/Compaction

Blocky & Anhydrite Cementation/ Compaction Compaction/Dolomitization Blocky Cementation/Compaction Dolomitization Dolomitization/Compaction

Compaction/Dolomitization Compaction Dolomitization/Compaction

Compaction/Blocky & Anhydrite Cementation Dolomitization/Compaction

Diagenesis process

Proximal open marine Lagoon

Lagoon Lagoon/Proximal open marine Leeward shoal

Leeward shoal

Lagoon/Peritidal/Proximal open marine Lagoon/Proximal open marine Lagoon/Leeward shoal/Proximal open marine Lagoon Lagoon/Proximal open marine

Lagoon/Proximal open marine Lagoon Leeward shoal

Lagoon/Proximal open marine Lagoon/Peritidal Lagoon Proximal open marine/Lagoon Leeward shoal

Lagoon/Peritidal/Proximal open marine Lagoon/Leeward shoal Leeward shoal

Lagoon Lagoon Lagoon Leeward shoal

Lagoon Lagoon/Leeward shoal Peritidal Peritidal/Lagoon/Proximal open marine Leeward shoal

Proximal open marine/Lagoon Lagoon Lagoon/Proximal open marine/ Peritidal Leeward shoal

Lagoon/Proximal open marine

Leeward shoal

Paleo Environments

Table 2 Petrographic results obtained from core-scale HFUs. Facies, lithology, pore types, diagenetic processes, etc. are arranged based on their abundance in the studied interval. K: Permeability, ϕ: Porosity, L: Limestone, D: Dolomite, Inter: Interparticle, Intra: intraparticle, Mold: Moldic, Fen: fenestral, Vug: Vuggy.

M.H. Nazari, et al.

Journal of Petroleum Science and Engineering 183 (2019) 106341

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M.H. Nazari, et al.

Fig. 7. Normalized cumulative FZI* against depth to distinguish reservoir-scale HFUs in K3 unit (a), cutoff Ⅰ (porosity, 3–12% and permeability less than or equal to 0.1mD) (b), cutoff Ⅱ (porosity, 2–5% and permeability less than or equal to 0.1mD) (c), cutoff Ⅱ (porosity, 5–8% and permeability less than or equal to 0.1mD) (d), cutoff Ⅲ (porosity, 2–8% and permeability less than or equal to 0.1mD) (e), cutoff Ⅲ (porosity, 8–32% and permeability less than or equal to 0.1mD) (f), cutoff Ⅲ (porosity, 2–32% and permeability less than or equal to 0.1mD) (g). Each percent represents the ratio of tight samples to all samples in the rock types.

best results of porosity-permeability and pore-throat size relationship in R25, which is presented by the equation below:

Log (K ) =

1.221 + 1.415 Log ( ) + 1.512 Log R25

The formula is as follows:

Log (K ) =

(2)

1.160 + 1.780 Log ( ) + 0.930 Log (R50)

(3)

R50 in this equation is the pore-throat radius in 50% mercury saturation in a mercury injection test, K is air permeability (mD), and ϕ is porosity (%). The R50 values obtained from equation (3) were less than 0.2 μm and so excluded from further processing.

In this equation, R25 is the pore throat radius in 25% mercury saturation in the MICP test, K is air permeability (mD), and ϕ is porosity (%). As with the Winland method, the R25 of all samples obtained from equation (2) was smaller than 0.5 μm.

4.5. Hydraulic flow units

4.4.3. Rezaee Rezaee et al. (2006) presented R50 as the most reliable size of the pore-throat radius for calculating permeability. They used 144 samples from several carbonate oil fields in the central and southwestern Iran.

There are various methods to define HFUs (Tiab and Donaldson, 2015; Tavakoli, 2018). Many studies have applied various petrophysical data to determine the HFUs, which FZI* is one of the most reliable indices. 9

5.98

6.43

3.12 4.67

6

7 8

3.24

3

5

6.11

2

6.65

5.57

1

4

Average ϕ (%)

Region

10

0.06 0.05

0.06

0.05

0.06

0.03

0.04

0.06

Average K (mD)

0.04 0.03

0.03

0.03

0.03

0.04

0.02

0.03

Average FZI* (μm)

Skeletal wackestone/Bioturbated skeletal wackestone Stromatolite boundstone Peloid skeletal grainstone/Skeletal grainstone Skeletal wackestone Dolo mudstone Skeletal grainstone/Peloid skeletal grainstone/Ooid skeletal grainstone Skeletal wackestone/Bioturbated skeletal wackestone Peloid skeletal packstone Bioturbated skeletal wackestone Fossiliferous mudstone

D D L D/L D L L L D L

Ooid skeletal grainstone Dolo mudstone Dolo mudstone

L D D

Mudstone Skeletal grainstone

Skeletal grainstone

L L/D L

Mudstone Skeletal wackestone/Fenestral skeletal wackestone

Facies

D L

Lithology

Inter/Mold/Vug _ Mold Mold

Mold _ Mold/Intra/Inter

Intercry Inter/Intra/Mold

Intra/Inter/Mold _ Intercry/Intra/ Mold _

_ Intra/Inter/Mold

Intra/Inter/Mold

_ Mold/Vug

Porosity type

Dolomitization Compaction/Blocky & Anhydrite Cementation Dolomitization/Compaction Dolomitization/Compaction Blocky & Anhydrite Cementation/ Compaction Compaction Compaction Compaction Compaction

Dolomitization/Compaction

Blocky & Anhydrite Cementation/ Compaction Dolomitization/Compaction Blocky & Anhydrite Cementation/ Compaction Blocky Cementation/Compaction Dolomitization/Compaction Dolomitization/Compaction

Dolomitization/Compaction Compaction

Diagenesis process

Proximal open marine Lagoon Lagoon/Proximal open marine Lagoon/Proximal open marine

Lagoon/Proximal open marine Peritidal Leeward shoal

Lagoon/Peritidal/Proximal open marine Peritidal Leeward shoal

Leeward shoal Lagoon Lagoon

Lagoon/Proximal open marine Leeward shoal

Peritidal/Lagoon Proximal open marine/Peritidal/ Lagoon Leeward shoal

Paleo Environments

Table 3 Petrographic results obtained from reservoir-scale FZI* rock typing using cutoff Ⅰ (porosity, 3–12% and permeability less than or equal to 0.1mD). Facies, lithology, pore types, diagenetic processes, etc. are arranged based on their abundance in the studied interval. K: Permeability, ϕ: Porosity, L: Limestone, D: Dolomite, Inter: Interparticle, Intra: intraparticle, Mold: Moldic, Fen: fenestral, Vug: Vuggy.

M.H. Nazari, et al.

Journal of Petroleum Science and Engineering 183 (2019) 106341

Average ϕ (%)

3.58

3.28 2.98

2.87

3.86

3.08

2.55

3.05

Region

1

2 3

4

5

6

11

7

8

0.03

0.03

0.03

0.04

0.03

0.02 0.04

0.04

Average K (mD)

0.03

0.03

0.03

0.03

0.03

0.03 0.04

0.03

Average FZI* (μm)

Dolo mudstone Peloid skeletal grainstone Skeletal wackestone Skeletal packstone Fossiliferous mudstone Intraclast peloid packstone Peloid skeletal grainstone Bioturbated skeletal wackestone

L L L L L D D L/D

L L

D L L L L D D D L D L L

Skeletal grainstone/Intraclast skeletal grainstone/Peloid skeletal grainstone Mudstone Skeletal wackestone/Intraclast skeletal wackestone Peloid skeletal packstone Mudstone/Bioturbated mudstone Peloid skeletal grainstone/Ooid skeletal grainstone Dolo mudstone Bioturbated dolo mudstone/Fossiliferous mudstone Bioturbated skeletal wackestone Skeletal wackestone/Peloid skeletal wackestone Dolo mudstone Skeletal grainstone Ooid skeletal grainstone/Peloid skeletal grainstone/Skeletal grainstone Skeletal wackestone/Peloid skeletal wackestone Peloid skeletal packstone

Facies

L/D

Lithology

_ _ Mold Inter/Intercry Intra _

_ Mold/Intra

Mold/Vug/Inter _

_ Intercry Mold _ Intra/Inter/Mold _ _ _ Mold _ Intra/Mold Mold/Intra/Inter

Intra/Inter/Mold

Porosity type

Blocky Cementation/Compaction Dolomitization/Compaction Dolomitization Dolomitization/Compaction Compaction/Dolomitization Dolomitization/Compaction Blocky & Anhydrite Cementation Blocky & Anhydrite Cementation/ Compaction Compaction Blocky & Anhydrite Cementation/ Compaction _ Blocky & Anhydrite Cementation/ Compaction Compaction Compaction Compaction _ Blocky & Anhydrite Cementation Compaction/Dolomitization

Blocky & Anhydrite Cementation/ Compaction Dolomitization/Compaction Compaction _

Diagenesis process

Table 4 Petrographic results obtained from reservoir-scale FZI* rock types using cutoff Ⅱ (Porosity, 2–5% and permeability, less than or equal to 0.1mD).

Lagoon Lagoon Proximal open marine Lagoon Leeward shoal Proximal open marine

Proximal open marine Leeward shoal

Proximal open marine Leeward shoal

Peritidal Peritidal/Lagoon Lagoon Proximal open marine Leeward shoal Lagoon Lagoon Lagoon Proximal open marine/Lagoon Peritidal Leeward shoal Leeward shoal

Leeward shoal

Paleo Environments

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Journal of Petroleum Science and Engineering 183 (2019) 106341

Journal of Petroleum Science and Engineering 183 (2019) 106341

Dolomitization/Compaction Blocky & Anhydrite Cementation/Compaction Compaction/Dolomitization Blocky & Anhydrite Cementation/Compaction Compaction/Dolomitization Dolomitization/Compaction Dolomitization/Compaction Dolomitization/Compaction Blocky & Anhydrite Cementation/Compaction Dolomitization Blocky & Anhydrite Cementation/Compaction Compaction _ Inter/Intra/Mold Vug/Mold Intra/Inter/Intercry/Mold _ _ _ Intercry Intra/Inter/Mold _ Mold/Intra/Inter Mold Mudstone/Dolo mudstone Skeletal grainstone Skeletal wackestone/Fenestral skeletal wackestone Skeletal grainstone Mudstone Mudstone/Bioturbated fossiliferous mudstone Skeletal wackestone Stromatolite boundstone Peloid skeletal grainstone Skeletal wackestone Skeletal grainstone Bioturbated skeletal wackestone

Peritidal Leeward shoal Proximal open marine/Peritidal Leeward shoal Lagoon Lagoon Peritidal/Proximal open marine Peritidal Leeward shoal Lagoon Leeward shoal Lagoon

4.5.1. FZI* or FZI-star The FZI* introduced by Mirzaei-Paiaman et al. (2015, 2018, 2019a, 2019b) for the first time and is calculated using porosity and permeability, as follows:

Log (FZI ) =

(4)

A geological rock type is a group of reservoir rock samples with similar geological, petrophysical, and reservoir properties (Tavakoli, 2018). The most important application of geological rock typing method is to investigate the effect of geological factors on petrophysical behavior. Various methods have been proposed for this purpose and the most applicable ones in the oil industry are investigated in this study. 4.6.1. Rock-fabric numbers (RFN) Lucia (2007) presented a relationship between grain size and sorting from mudstones to grainstones and defined the RFN as:

Log (k) = (9.7982

12.0838Log(RFN))

+ ((8.6711

8.2965 Log (RFN )) Log (

ip))

(5)

where RFN is rock-fabric numbers ranging between 0.5 and 4, ϕ ip is the interparticle porosity (fraction), and K is permeability (mD). The results of this method are presented in Table 9 and Fig. 8. 5. Discussion The porosity and permeability of the K3 unit were investigated to evaluate the heterogeneity of low permeability parts of this unit. Regarding the porosity range suitable for hydrocarbon storage, part of the K3 unit can be considered as a tight carbonate gas reservoir. Evaluating the heterogeneity helps better understanding the reservoir properties at different intervals. For this purpose, samples with less than 0.1 mD permeability and different ranges of porosities (12–3%, 2–5%, 5–8%, 2–8%, 8–32% and 2–32%) were investigated. Initially, we examined Winland (Kolodzie, 1980), Pittman (1992) and Rezaee et al. (2006) models derived from the MICP technique. In Winland model, all samples yield the R35 values of less than 0.5 μm. Similarly, the R25 and R50 resulted from equations (2) and (3) (using Pittman and Rezaee methods) yield values of less than 0.5 μm. Consequently, the classification of the samples based on empirical static rock typing indices in low permeability intervals has no satisfactory results. As a result, they are dismissed from further analyses. The FZI* method also used in this study, and both core-scale and reservoir-scale HFUs yielded satisfactory results. Core-scale HFUs were identified by a probability plot of FZI* values. A good separation of HFUs in the plot of 0.0314 k versus on a log-log plot (Fig. 6b)

0.03 0.03 6.48 6.18 6 8

0.5 Log ( )

4.6. Geological rock typing

0.05 0.06

0.03 6.488 5

0.061

0.03 6.478 4

0.064

0.02 6.02 2

0.03

0.03 0.05 6.03 1

1.50307 + 0.5 Log (k)

where K is permeability (mD), ϕ is the effective porosity (fraction), and FZI* is the flow zone indicator (μm). Probability plot (Fig. 6a) was used to identify core-scale HFUs (Mirzaei-Paiaman et al., 2015). The results illustrated using the plot of 0.0314 k versus on a log-log plot (Fig. 6b). More than 80% of the tight samples are located in HFUs 1, 2, and 3 (Fig. 6c and d), which indicate the ability of the method to classify the low permeability samples. The petrophysical and geological characteristics of the core-scale HFUs are summarized in Table 2. By plotting depth versus normalized cumulative FZI*, different flow zones were recognized (Fig. 7), from which one can identify reservoirscale HFUs. Following this procedure, vertical and horizontal sections illustrated baffle and reservoir-scale flow units, respectively (Fig. 7 and Tables 3–8). As can be seen, eight regions were recognized. On the basis of non-identical slopes, five HFUs were distinguished. Due to the identical slope, regions 1, 4, and 5 were placed in one HFU. These regions belong to the different depths and so their characteristics are reported separately in the tables.

D L L L D D D D L D L L

Diagenesis process Porosity type Facies Lithology Average FZI* (μm) Average K (mD) Average ϕ (%) Region

Table 5 Petrographic results obtained from reservoir-scale FZI* rock typing using cutoff Ⅱ (porosity, 5–8% and permeability less than or equal to 0.1mD).

Paleo Environments

M.H. Nazari, et al.

12

2.55

3.36

7

8

5.28

4

4.08

2.98

3

6

4.8

2

5.27

4.65

1

5

Average ϕ (%)

Region

13

0.03

0.03

0.04

0.05

0.05

0.04

0.03

0.05

Average K (mD)

0.03

0.03

0.03

0.03

0.03

0.04

0.03

0.03

Average FZI* (μm) L/D D L/D D L/D L L D D D D L L L/D D L L L L L L L D L L L

Lithology Skeletal grainstone/Peloid skeletal grainstone Peloid skeletal packstone Skeletal wackestone Mudstone/Dolo mudstone Mudstone/Bioturbated fossiliferous mudstone Skeletal grainstone Peloid skeletal grainstone/Ooid skeletal grainstone Dolo mudstone Bioturbated dolo mudstone/Fossiliferous mudstone Skeletal wackestone Stromatolite boundstone Peloid skeletal grainstone/Ooid skeletal grainstone Skeletal packstone Skeletal wackestone Dolo mudstone Skeletal grainstone/Peloid skeletal grainstone Skeletal wackestone Dolo mudstone Peloid skeletal packstone Peloid skeletal grainstone Skeletal wackestone Skeletal packstone Fossiliferous mudstone Bioturbated skeletal wackestone Peloid skeletal grainstone Intraclast peloid packstone

Facies Intra/Mold/Inter Mold Intercry/Mold Intercry _ Intra/Inter/Mold Intra/Inter/Mold _ _ Intercry Intercry Inter/Intra/Mold _ Mold _ Mold/Inter/Intra Mold _ Mold Mold/Intra _ _ Mold Mold Intra Intercry

Porosity type

Table 6 Petrographic results obtained from FZI* rock typing using cutoff Ⅲ (porosity, 2–8% and permeability less than or equal to 0.1mD).

Blocky & Anhydrite Cementation/Compaction Blocky & Anhydrite Cementation/Compaction Compaction Compaction Compaction Compaction/Dolomitization Blocky & Anhydrite Cementation Intercry/Inter

Blocky & Anhydrite Cementation/Compaction _ Compaction/Dolomitization Dolomitization/Compaction Compaction/Dolomitization Blocky Cementation/Compaction Blocky Cementation/Compaction Dolomitization/Compaction Dolomitization/Compaction Dolomitization/Compaction Dolomitization/Compaction Blocky & Anhydrite Cementation/Compaction Anhydrite & Blocky Cementation/Compaction Dolomitization/Compaction Dolomitization/Compaction Blocky & Anhydrite Cementation/Compaction Compaction

Diagenesis process

Leeward shoal Lagoon Peritidal/Lagoon Peritidal/Lagoon Proximal open marine/Lagoon Leeward shoal Leeward shoal Lagoon Lagoon Proximal open marine/Lagoon/Peritidal Peritidal Leeward shoal Leeward shoal Proximal open marine/Lagoon Peritidal Leeward shoal Proximal open marine Proximal open marine Leeward shoal Leeward shoal Lagoon Lagoon Lagoon Proximal open marine Leeward shoal Lagoon

Paleo Environments

M.H. Nazari, et al.

Journal of Petroleum Science and Engineering 183 (2019) 106341

Journal of Petroleum Science and Engineering 183 (2019) 106341

Leeward shoal

Lagoon/Proximal open marine Lagoon/Peritidal Lagoon Leeward shoal

Leeward shoal

shows the ability of FZI* index to understand the reservoir heterogeneity also in low permeability reservoirs. Permeabilities increase from HFU1 to HFU9. Although high-energy grain-dominated facies generally have high reservoir potential, some diagenetic processes including anhydrite and blocky calcite cementation and compaction are responsible for low reservoir quality. These tight grain-dominated facies accompanied by mud-dominated facies make up HFU1, HFU2, and HFU3. Relatively high porosity values are the result of the presence of moldic porosities, appear as separate pore spaces. Flow units such as HFU4, HFU5, and HFU6 contain grain-dominated facies with moldic porosities less affected by negative factors. Owing to slight recrystallization and therefore growing dolomite crystals, permeability has increased slightly in these HFUs. In HFU7, HFU8, and HFU9 the presence of moldic and interparticle pore types along with the scarcity of plugging agents prevail in grain-dominated facies. Accordingly, the highest values of porosity and permeability appear in these HFUs. On the other hands, extensive dolomitization has led to the enhancement of permeability in mud-dominated facies. For separation of reservoir/non-reservoir zones from tight intervals at reservoir-scale, normalized cumulative FZI* was plotted against depth. Subsequently, the entire interval was classified into eight regions (Fig. 7). According to the results obtained by this method, classes 6, 2, 4, 5, 1, 8, 7, and 3 have the highest percentage of low permeability samples in K3 unit, respectively. Diagenetic processes including cementation, compaction, and dissolution in grain-dominated facies and dolomitization and compaction in mud-dominated facies play a significant role in determining the final reservoir properties of these rock types. Dissolution of allochems in grainstone, packstone, and wackestone facies with limestone lithology have increased porosity. On the other hand, in some grainstone and packstone facies, isopachous and anhydrite cements prevented more compaction and porosity loss in the 3221–3230 m interval. Originally, mudstone facies have a very low reservoir quality, but due to the effect of dolomitization, both mudstone and grainstone facies have relatively high porosity in some cases and are placed in one rock type. As a result of the dolomitization in mudstone facies with dolomite lithology, the porosity increase in rock type 2. On the other hand, the cementation process occludes pore spaces and reduces both porosity and permeability. Dolomitization in mud-dominated and stromatolite boundstone facies plays a significant role in porosity creation in rock type 4, but compaction has reduced the permeability in this rock type. The over-dolomitization of these facies can destroy the quality of the reservoir. As seen in Fig. 7, the lowest sample ratios of tight to the total number of samples are visible in rock types 5, 1, 8, 7, and 3. The petrographical characteristics of these rock types in different cutoffs are shown in Tables 3–8. So, by comparing the two factors controlling reservoir quality, namely diagenesis and facies, and the results obtained from the FZI* calculations, the diagenesis is the main factor affecting this low permeability carbonate unit. Therefore, the FZI * method can be used to separate tight reservoirs from other reservoir/non-reservoir units in the carbonate intervals. RFN method was used to investigate the effect of allochems' size on the heterogeneity of carbonates of the K3 unit. Based on the performed analyses and calculations, classes 1, 2, and 3 have approximately the same porosities. The values of R2 between porosity and permeability in classes 1, 2, and 3 are all close to 1, indicating the well sorting and similar sizes of the allochems. Both mud-dominated and grain-dominated facies were located in the same class, which also show the effect of diagenesis. Cementation in grain-dominated limestone facies has led to the porosity destruction and occluding the pore throats. Consequently, they show similar reservoir properties with mud-dominated dolomitic facies. The degree of dolomitization in dolomitic muddominated facies justifies the location of these facies along with graindominated facies. The degree of heterogeneity in tight carbonate reservoirs due to the diagenetic processes, change the porosity and permeability distribution (Lucia, 1995; Makhloufi et al., 2013; Rashid et al., 2017). Finally, in this study, the FZI* and Lucia classifications are

L 0.02 11.3 6

0.07

10.15 5

0.07

0.03

D D D L 0.03 0.02 9.93 8.29 2 4

0.07 0.05

Skeletal grainstone/Peloid skeletal grainstone/Ooid skeletal grainstone

_ _ _ Intra/Inter/ Intercry Mold/Intra/Inter

Blocky & Anhydrite Cementation/ Compaction Compaction/Dolomitization Dolomitization/Compaction Dolomitization/Compaction Blocky & Anhydrite Cementation/ Compaction Blocky & Anhydrite Cementation/ Compaction Intra/Inter/Mold

Peloid skeletal grainstone/Skeletal grainstone/Intraclast skeletal grainstone Mudstone/Dolo mudstone Mudstone/Dolo mudstone/Bioturbated fossiliferous mudstone Skeletal wackestone Peloid skeletal grainstone/Skeletal grainstone L 0.02 12.46 1

0.08

Diagenesis process Porosity type Facies Lithology Average FZI* (μm) Average K (mD) Average ϕ (%) Region

Table 7 Petrographic results obtained from reservoir-scale FZI* rock typing using cutoff Ⅲ (porosity, 8–32% and permeability less than or equal to 0.1mD).

Paleo Environments

M.H. Nazari, et al.

14

Average ϕ (%)

6.21

5.73

2.98

5.71

6.19

5.79

2.55

3.36

Region

1

2

3

4

5

6

15

7

8

0.03

0.03

0.05

0.05

0.05

0.04

0.04

0.05

Average K (mD)

0.03

0.03

0.03

0.03

0.03

0.04

0.02

0.03

Average FZI* (μm)

Dolo mudstone Mudstone/Dolo mudstone/Bioturbated fossiliferous mudstone Skeletal wackestone Stromatolite boundstone Peloid skeletal grainstone/Skeletal grainstone Skeletal wackestone/Peloid skeletal wackestone Dolo mudstone Skeletal grainstone/Peloid skeletal grainstone/Ooid skeletal grainstone Skeletal wackestone/Bioturbated skeletal wackestone Skeletal packstone/Peloid skeletal packstone Mudstone Peloid skeletal grainstone/Ooid skeletal grainstone Skeletal wackestone Peloid skeletal packstone Fossiliferous mudstone/Bioturbated fossiliferous mudstone Bioturbated skeletal wackestone Intraclast peloid packstone Peloid skeletal grainstone

D D D D L L/D D L

L L L L L L/D D L

L L

Peloid skeletal grainstone/Ooid skeletal grainstone

Skeletal grainstone

Peloid skeletal grainstone/Skeletal grainstone/Intraclast skeletal grainstone Skeletal wackestone/Fenestral skeletal wackestone/Intraclast skeletal wackestone Peloid skeletal packstone Dolo mudstone/Mudstone Mudstone/Dolo mudstone

Facies

L

L

L D D

L/D

L

Lithology

Intra

Intercry/Inter

_ _ Mold Mold

_ Mold/Intra

Mold/Inter/Vug Mold/Inter

_ Mold/Intra/Inter

_ _ _ Intercry Intra/Inter/ Intercry Mold

Intra/Inter/ Intercry Intra/Inter/Mold

Mold _ _

Intercry/mold/Vug

Intra/Inter/Mold

Porosity type

Table 8 Petrographic results obtained from reservoir-scale FZI* rock type using cutoff Ⅲ (porosity, 2–32% and permeability less than or equal to 0.1mD).

Blocky & Anhydrite Cementation/ Compaction Blocky & Anhydrite Cementation/ Compaction

Dolomitization/Compaction Blocky & Anhydrite Cementation/ Compaction Compaction Blocky & Anhydrite Cementation/ Compaction _ Blocky & Anhydrite Cementation/ Compaction Anhydrite Cementation/Compaction Compaction Compaction/Dolomitization Compaction/Dolomitization

Blocky & Anhydrite Cementation/ Compaction Blocky & Anhydrite Cementation/ Compaction Dolomitization/Compaction Dolomitization/Compaction Dolomitization/Compaction Dolomitization/Compaction Blocky & Anhydrite Cementation/ Compaction Dolomitization/Compaction

_ Dolomitization/Compaction Compaction/Dolomitization

Blocky & Anhydrite Cementation/ Compaction Compaction/Dolomitization

Diagenesis process

Leeward shoal

Lagoon Lagoon Proximal open marine Lagoon/Proximal open marine Lagoon

Proximal open marine Leeward shoal

Proximal open marine Leeward shoal

Lagoon/Proximal open marine Peritidal Leeward shoal

Lagoon Lagoon/Peritidal Lagoon Peritidal Leeward shoal

Leeward shoal

Lagoon Lagoon/Peritidal Lagoon/Proximal open marine Leeward shoal

Peritidal

Leeward shoal

Paleo Environments

M.H. Nazari, et al.

Journal of Petroleum Science and Engineering 183 (2019) 106341

Journal of Petroleum Science and Engineering 183 (2019) 106341

M.H. Nazari, et al.

Table 9 Classification of the samples based on Lucia method. Average ϕ (frac)

Poroperm R2

Facies

Lithology

Pore type

Diagenetic processes

Class 1 0.06 0.05

0.05 0.05

0.86 0.82

Mudstone/Stromatolite boundstone/Skeletal wackestone Skeletal grainstone/Dolo mudstone/Bioturbated skeletal wackestone

D L/D

_ Inter/Intra/ Mold/Fen

Class 2 0.06

Dolomitization/Compaction Blocky & Anhydrite Cementation/Compaction/ Dolomitization

0.06

0.94

Mudstone/Skeletal grainstone/Skeletal wackestone/Dolo mudstone/Bioturbated skeletal wackestone

D/L

Inter/Intra/ Mold/Fen

0.06

0.07

0.94

L/D

Inter/Intra/Mold

Class 3 0.03

Skeletal grainstone/Peloid skeletal grainstone/Ooid skeletal grainstone/Mudstone/Fossiliferous mudstone/ Skeletal wackestone/Skeletal packstone

Dolomitization/Blocky & Anhydrite Cementation/ Compaction Blocky & Anhydrite Cementation/Compaction/ Dolomitization

0.07

0.95

Skeletal grainstone/Ooid skeletal grainstone/Mudstone/ Skeletal wackestone/Bioturbated fossiliferous mudstone

L/D

Inter/Intra/Mold

0.05

0.08

0.84

Peloid skeletal grainstone/mudstone/Skeletal wackestone/Mudstone/Dolo mudstone/Bioturbated fossiliferous mudstone

L/D

Inter/Intra/Mold

Average K (mD)

Compaction/Blocky & Anhydrite Cementation/ Dolomitization Compaction/Blocky & Anhydrite Cementation/ Dolomitization

dissolution, compaction, and cementation in mud-dominated and graindominated facies control the quality of the reservoir and so the fluid flow properties of the determined HFUs. Mud-dominated and graindominated facies have the same behavior in terms of reservoir quality in the RFN method. The results showed that dolomitization and cementation control such variations. The results of our study indicate that the most suitable methods for rock typing in tight parts of K3 carbonate reservoir unit are FZI* and RFN methods. Acknowledgments The authors would like to thank University of Tehran for financial support of this research. The paper greatly benefited from inspiring reviews of Dr. M. Foroutan from University of Tehran and two anonymous reviewers which we are grateful.

Fig. 8. Permeability versus porosity cross-plot for samples with permeability less than 0.1 mD and their position in Lucia classification. Frac: fraction.

recommended as the most practical methods in the study of the K3 tight gas carbonate unit's heterogeneity. Regarding all classifying cutoffs, diagenetic processes control reservoir and petrophysical properties as well as the heterogeneity of this carbonate unit.

Appendix A. Supplementary data Supplementary data to this article can be found online at https:// doi.org/10.1016/j.petrol.2019.106341. References

6. Conclusions

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In this study, some parts of the Upper Permian K3 carbonate unit are introduced as tight carbonate gas reservoirs regarding their porosity and permeability. For understanding the reservoir heterogeneity, the conventional methods of Pittman, Rezaee, and Winland applied to the data and the values of R25, R35, and R50 were less than 0.5 μm. Consequently, they had no satisfactory results in the study of the tight parts of the K3 unit of Dalan Formation. The FZI* method was successfully used to separate the tight from other parts of the studied unit at both core- and reservoir-scale. For identification of reservoir-scale HFUs we plotted depth (on Y-axis) versus normalized cumulative FZI* (NCFZI*) (on x-axis). Vertical and horizontal sections illustrate baffle and reservoir-scale flow units. By plotting depth versus NCFZI* we may observe several regions that straight lines could be passed through. The number of such lines does not reflect the actual number of reservoirscale HFUs, because some of these regions may be identical in fluid flow at reservoir scale. Here the number of lines with non-identical slopes represents the actual number of HFUs. So we have to compare slopes and bring two numbers 1) the total number of regions, 2) the number of reservoir-scale HFUs. These regions belong to the different depths. By studying thin sections, the diagenetic processes of dolomitization, 16

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