Unveiling the Diagenetic and Mineralogical Impact on the Carbonate Formation of the Indus Basin, Pakistan: Implications for Reservoir Characterization and Quality Assessment

Abstract

The Chiltan formation is a potential hydrocarbon-producing reservoir in the Indus Basin, Pakistan. However, its diagenetic alterations and heterogeneous behavior lead to significant challenges in accurately characterizing the reservoir and production performance. This manuscript aims to utilize six carbonate core samples of the Chiltan limestone to conduct an in-depth analysis of the diagenetic impacts on reservoir quality. The comprehensive formation evaluation was carried out through thin-section analysis, SEM-EDS, and FTIR investigation, as well as plug porosity and permeability measurements under varying stress conditions. In result, petrography revealed three microfacies of intraclastic packestone (MF1), bioclastic pelliodal packestone (MF2), and bioclastic ooidal grainstone (MF3), with distinct diagenetic features and micro-nano fossil assemblages. The MF1 microfacies consist of bioclasts, ooids, pellets, and induced calcite, while the MF2 microfacies contain micrite cemented peloids, algae, and gastropods. Although, the MF3 grainstone microfacies contains key features of bioclasts, milliods, bivalves, echinoderms, and branchiopods with intense micritization. Diagenesis has a significant impact on petrophysical properties, leading to increased reservoir heterogeneity. The specified depositional environment exposed the alteration of the Chiltan formation during distinct diagenetic phases in marine, meteoric, and burial settings. Marine diagenesis involves biogenic carbonates and micro-nano fossils, while meteoric diagenesis involves mineral dissolution, reprecipitation, secondary porosity, compaction, cementation, and stylolite formation. Pore morphology and mineralogy reveal a complex pore network within the formation, including a micro-nano pore structure, inter–intra particle, moldic, vuggy, and fenestral pores with variations in shape, connectivity, and distribution. Various carbonate mineral phases in the formation samples were analyzed, including the calcite matrix and dolomite crystals, while silica, calcite, and clay minerals were commonly observed cement types in the analysis. The core samples analyzed showed poor reservoir quality, with porosity values ranging from 2.02% to 5.31% and permeability values from 0.264 mD to 0.732 mD, with a standard deviation of 1.21. Stress sensitivity was determined using Klinkenberg-corrected permeability at increasing pore pressure conditions, which indicated around 22%–25% reduction in the measured gas permeability and 7% in Klinkenberg permeability due to increasing the net confining stress. In conclusion, the Chiltan formation possesses intricate reservoir heterogeneity and varied micropore structures caused by diagenesis and depositional settings. The formation exhibits nonuniform pore geometry and low petrophysical properties caused by the diverse depositional environment and various minerals and cement types that result in a low-quality reservoir. Stress sensitivity further decreases the permeability with varying stress levels, emphasizing the need of stress effects in reservoir management. The results of this study provide a solid foundation in reservoir characterization and quality assessment that has implications for predicting fluid flow behavior, providing insight into geological evolution and its impact on reservoir quality and leading to improving resource exploration and production strategies.

1. Introduction

The Middle Jurassic carbonates are extensively distributed worldwide and contain not only significant commercial hydrocarbon resources but also hold valuable water resources [1,2,3]. It is estimated that approximately 60% of the global oil reserves and 40% of its gas reserves are held in carbonate deposits, with around 400 identified oil and gas basins across onshore and offshore regions. The Middle East holding proved to have conventional reserves of about 70% of oil and 90% of gas reserves in carbonate formations [1,4]. Similarly, Pakistan has considerable potential in carbonate deposits in the Indus Basin and Baluchistan Basin [5]. However, carbonates are challenging in petroleum exploration and production due to their complex reservoir heterogeneity, diagenesis, and post-depositional environment factors [6,7]. Understanding these factors is crucial for assessing the reservoir potential. The reservoir quality of carbonates is influenced by the initial depositional features and subsequent diagenetic modifications [8,9]. The depositional environment influences the formation characteristics, and diagenesis affects the reservoir quality through post-depositional processes [10,11,12,13,14]. Numerous physiochemical and biological changes during rock development alter micropore structures, leading to complex reservoir heterogeneity [15,16]. The fundamental factors influencing the carbonate reservoir quality include mineralogy, rock textures, and depositional settings, all of which outline the digenetic alterations that occur. The main diagenetic processes that affect the carbonate reservoir quality include dolomitization, micritization, dissolution, compaction, cementation, and fracturing [17,18,19]. These processes alter the reservoir characteristics in response to periodic facies variations in marine carbonates due to changes in the depositional environment [20]. The shallow marine environment initially shapes the formation framework and supplies carbonate sediments during the deposition of biogenic carbonates, including calcareous algae, bivalves, and forums, with early cementation and micritization [4,21]. The meteoric environment infiltrates the carbonate sediments, causing mineral dissolution, reprecipitation, secondary porosity enhancement, and an altering mineralogical composition that result in modification of the pore structure. Burial diagenesis occurs due to sediment compaction, which leads to increasing the pressure and temperature and precipitation of cement minerals like calcite and silica [4,22]. Consequently, a comprehensive understanding of these diagenetic and depositional factors is essential for effectively characterizing and developing carbonate reservoirs for hydrocarbon exploration and production.

Variations in the petrophysical, pore morphology, and mineralogical parameters within carbonate reservoirs are heavily influenced by a combination of factors, including the depositional environment, diagenetic processes, overburden stress, and tectonic activities. These factors collectively transform carbonate rocks into highly heterogeneous and challenging materials for their analysis, measurement, and interpretation [23,24,25,26,27]. Furthermore, overburden stress plays a particularly significant role in shaping pore morphology, pore geometry, and the overall petrophysical properties of the reservoir. In carbonate formations, the impact of pore sensitivity becomes even more pronounced when compared to clastic sand stones. This heightened sensitivity is due to their complex lithofacies and diagenetic processes, which tend to affect the reservoir quality and recovery efficiency [28,29]. Stress sensitivity is often overlooked during reservoir characterization, leading to severe complexities in interpretation, estimation, modeling, and development. Measurements made under stress sensitivity are essential for accurately and effectively estimating reservoir parameters [30].

The Chiltan limestone is recognized as a prolific hydrocarbon-producing formation within the Indus Basin, ranging from the Late Triassic to Pleistocene ages and forming a marine carbonate sequence in the Mughal Kot area [31,32]. Since its initial discovery in 1959, the Chiltan formation has served as a gas-producing reservoir for various exploration and production companies. The formation comprises a wide range of carbonate units, varying from thin to thick-bedded, and includes irregular coarse-grained, bioclastic, and intraclastic limestones, all indicative of deposition in shallow to marginal marine environments. The presence of age diagnostic species of macro-nano fossils in this succession contributes significantly to severe diagenetic impacts on its reservoir potential [33,34]. The complexity of the reservoir is associated with its variable lithological composition, mineral content, pore space, conductivity, facies, and textures. These factors collectively pose challenges in recovery and increase exploration risks [35].

Bilal Wadood et al. conducted an outcrop study on Middle Jurassic carbonate deposits and observed that carbonates are modified during marine, meteoric, and burial phases. Further, extensive dissolution processes and interconnected fracture networks may have enhanced the reservoir potential of the studied strata [36]. Sajjad Ahmad et al. integrated outcrop and subsurface geochemical analysis through total organic carbon (TOC) and Rock-Eval pyrolysis for hydrocarbon source rock evaluation. They observed that Sembar and Chiltan formations have significant potential as hydrocarbon source rocks in the study region [37]. MA Khan et al. performed a study to analyze the diagenetic and depositional controls on reservoir quality of the Lower Goru formation. They concluded that the quality of the studied reservoirs is influenced by mineral authigenesis, including quartz overgrowth, carbonate cementation, and minor detrital clay. Moreover, the secondary porosity is attributed to the partial-to-complete dissolution of various clay and bioclasts components [38].

In the existing literature, several well logs and outcrop studies have been conducted in the area to investigate the reservoir potential of the carbonate formations that primarily focusing on sedimentological, paleontological, and geochemical analyses [4,39]. These studies did not identify the stratigraphic units’ heterogeneity type properly and still lacked in determining their reservoir complexities due to several diagenetic alterations and pore structural modifications in the carbonate formations. According to an outcrop study, the Chiltan formation poses intricate variations in lithology, deposition, and pore structural geometry due to diagenesis [36]. This indicates that the formation was developed under a variety of different depositional and diagenetic conditions and remains subjected to study. Consequently, a comprehensive reservoir characterization and analysis are necessary to understand the diagenetic impacts on reservoir quality and improve the recovery efficiency.

In this study, six carbonate core samples of the Chiltan formation have been utilized for the first time to conduct an integrated reservoir characterization for a quality assessment. The primary objective of this research is to examine the impacts of diagenesis, depositional environment, and overburden stress on the reservoir quality using various methods like thin-section petrography, mineralogy assessment, plug porosity, and gas permeability measurements under various overburden stress conditions. The study serves to address the key issues and challenges related to carbonate reservoir measurement and interpretation resulting from diagenesis. Ultimately, this research could lead to (i) lowering the risks associated with reservoir management and (ii) contributing to improving the productivity of indigenous resources.

Geological Settings of the Study Area

The Lower Indus Basin is divided into central and southern basins by the Sukkur Rift Zone. The research region is situated in the eastern portion of Jacobabad-Khairpur High in an NNE–SSW orientation. Geologically, the study area is comprised of normal faults associated with Horsts and Graben structures, including Pano Akil graben, Mari-Kandhkot High, and Khairpur-Jacobabad High, that represent the tectonic history of the region, as depicted in Figure 1. Strategically, the area is located for its hydrocarbon prospects, encompassing the Sargodha High to the north, the Indian Shield to the east, and the Indian Plate marginal zone to the west [40,41]. The diverse structural styles of the Southern Indus Basin have been influenced by various geological events. Three notable post-rifting events were identified, which included a Late Cretaceous uplift and inversion, a Late Paleocene right-lateral wrenching, and a Late Tertiary Holocene Khairpur High uplift [40,42,43]. Geographically, the area is primarily comprised of rocks from the Mesozoic age succession, with thick Jurassic sequences and a few outcrops of Triassic occurrences [40]. Despite the presence of shallow marine Eocene rocks, this region also exposes some of the oldest rocks, including those from the Triassic age (Wulgai formation) and Paleocene age (Dunghan limestone). The Dunghan limestone is deposited on the eastern side of the Jacobabad Khairpur High above the Cretaceous series and directly overlying the Middle Jurassic Chiltan formation, showing well-known unconformity at the K–T boundary formed during Collovian time throughout the Indus Basin [44,45]. Beyond the Cretaceous, the Paleocene Ranikot formation existed, and the sequence continued up to modern alluvium. According to data correlations and assumed thickness, earlier Cretaceous and Middle Jurassic Chiltan formations are also present. The effects of collisional tectonics are limited to the northern parts of Pakistan, with the Central Indus Basin largely unaffected. The surrounding regions underwent rifting during the Mesozoic succession, resulting in the formation of the Khairpur-Jacobabad High, as depicted in Figure 1. Interestingly, the carbonate platform environment remained stable despite tectonic activity that effectively produced subaqueous islands [46]. The hydrocarbon trapping mechanism of the region is intricately linked to its tectonic history, involving structural and stratigraphic elements like anticlines, fault trapes, lateral seals, pinch outs, and isolated reservoirs [47]. Chiltan limestone is regarded as the shelf carbonate sequence of the Middle Jurassic age, characterized by thick layers of oolitic beds, including reefal development in the upper section. The Early Cretaceous interval includes pelagic Parh limestone, Mughal Kot formation, and Pab sandstone, followed by Sembar shale, as well as Lower and Upper Goru sands in the lower part. Eocene rocks overly the Paleocene sequence, while Oligocene Nari formation sediments were deposited on top of the Eocene sequence. Additionally, Siwalik spreads over the Indo-Pakistan Plate with unconformable contact [48,49]. The Chiltan limestone and sands of Goru formations represent potential hydrocarbon resources in the region, with reservoirs ranging from shallow to deeper levels of the Jurassic and Cretaceous ages [49]. The intraformational and overlying shales act as seals, with anticline traps in the existing stratigraphic play. According to borehole data from exploration and production (E&P) companies, the stratigraphic column of the Southern Indus Basin spans from Triassic to modern alluvium, as depicted in Figure 2.

2. Materials and Methods

2.1. Materials and Preparation of the Core Samples

Long cylindrical reservoir cores from the Middle Jurassic age Chiltan limestone formation were collected from the subsurface core database Petcorelab, Hydrocarbon Development Institute of Pakistan, (HDIP) Islamabad, through the Directorate General Petroleum Concession, Pakistan. The selected core samples were prepared through various core slabbing and core plugging procedures to create core plugs of the desired size. After labeling and tagging the samples, several core preparation techniques were employed for a comprehensive laboratory-scale investigation. The six carbonate cylindrical core plugs, measuring 4.5 cm (1.77 inches) in length and 2.5 cm (0.984 inch) in diameter, were prepared. A standard procedure was followed to create six slides of 0.028 mm polished, blue dye-stained thin sections and six samples of 3 mm × 3 mm × 2 mm cubical chips with carbon coatings for the SEM-EDS analysis.

2.2. Characterization Methods

Six carbonate core samples of Chiltan formation were characterized through various analytical techniques. The experimental workflow chart with each specific procedure is illustrated in Figure 3. This figure provides a visual representation of the entire experimental processes of all the undertaken procedures.

2.3. Petrographic Analysis

The prepared thin sections were examined using a polarized light Olympus BX-51, Olympus America Inc. (Pittsford, NY, USA), microscope equipped with polarizing filters, a rotatable stage, and magnification range of 10× to 1000×, using zooming for detailed examination to capture the typical microphotographs of the obtained microfacies, and a digital sight DS-U3 Nikon camera (Nikon, Tokyo, Japan) was attached to the microscope and integrated with software for the image analysis. Dunham’s classification system was employed for the petrographic analysis of the thin sections.

2.4. Scanning Electron Microscope (SEM) and Energy Dispersive Spectroscopy (EDS) Analysis

Mineralogy, microstructure, and diagenetic interactions of the samples were examined through scanning electron microscopy (SEM) using a JEOL-JSM-6590LV, with field emission Japan Compact SEM imaging interface software, JSM-IT 700HR (JEOL Ltd., Tokyo, Japan) connected to a Bruker QUANTAX 200 system (Billerica, MA, USA) for Energy Dispersive X-ray microanalysis (EDS analysis). The microscope utilized a focused electron beam to scan the sample’s surface, which produced signals and characteristic X-rays through interactions for precise navigation and visualization. EDS detected the X-rays emitted by high-energy electrons from SEM, identifying and quantify the elemental composition of the samples by analyzing their energy.

2.5. FTIR Analysis

Fourier-Transform Infrared spectroscopy (FTIR) was conducted to confirm the carbonate mineralogy and identify any changes in the mineral composition. The analysis was performed using a portable infrared spectrometer, ALPHA, by Bruker, Optik GmbH in Ettlingen, Germany. The equipment contained an ATR (Attenuated Total Reflection) mode, which possessed an interchangeable sampling module for analysis. The IR spectra were obtained by compressing the sample powders on a diamond crystal, resulting in spectra obtained between 4000 cm⁻¹ and 500 cm⁻¹, and 24 scans with 2 cm⁻¹ resolution were averaged.

2.6. Petrophysical Measurements

The porosity measurements of selected core plugs were determined using core test helium expansion PHI-220 porosity. The core porosity was determined by comparing the measured core plug volume with the calculated grain volume using Boyle’s law method. This difference was used to calculate porosity when gas was compressed into rock samples’ pores using an experimental configuration. Additionally, gas permeability and stress sensitivity assessments were carried out using the GP-12-2631 Temco (Pomona, CA, USA) permeameter under both ambient and various net stress conditions, with calculations based on Darcy Equation (1) [50].

(1)$K_g=2{\mu }_g{Q}_b\frac{L}{A}\left(p_1^2-p_2^2\right)$

In this context, the core length is symbolized by L, the cross-sectional area is denoted by A, µ_g represents the gas viscosity, p₁ stands for the pressure across the core length (upstream pressure), and p₂ represents the downstream pressure. The flow rate Q_b is directly related to the gas permeability K_g.

2.7. Determination of Klinkenberg Permeability and Stress Sensitivity

Steady-state gas permeability tests were conducted on 06 carbonate core samples at varying mean pore pressures to analyze the influence of gas slippage in heterogeneous carbonates. Nitrogen gas was injected into the core samples at different inlet pressures of 0.225, 0.395, 0.535, 0.695, and 0.895 atm to determine the gas permeability using Equation (1) of Darcy law while keeping the pressure drop constant at 0.25 atm. The Klinkenberg permeability is expressed by Equation (2) [51].

(2)$K_g=k_{\infty }\left[1+\frac{b}{P_{av}}\right]$

Here, b represents the Klinkenberg constant, also known as the gas slippage factor, and k_∞ denotes the Klinkenberg or absolute permeability. The gas slippage factor b was determined using Equation (3) [52].

(3)$b=\frac{\left(4C\lambda P_{av}\right)}{rslip}$

where C is a constant to the order of 1, dependent on the pore throat geometry, and λ represents the free path length of gas molecules and is calculated using Equation (4) [53]:

(4)$\lambda =\frac{\mu }{P_{av}}\sqrt{RT\pi /2M}$

Here, R is the gas constant, M is the molar mass of gas, and T refers to the absolute temperature. The influence of the Klinkenberg constant on the pore throat structure was determined by the absolute permeability k_∞ and expressed by Equation (5) [54]:

(5)$k_{\mathrm{\infty }}={aK}_g+b$

In the pore throat relation between the Klinkenberg permeability k_∞ and measured permeability K_g, a represents the slope, and b represents the intercept. Stress sensitivity was also conducted to assess the impact of stress on the carbonate rock permeability and pore throat structure under various stress conditions. The net stress is described by Equation (6) [28]:

(6)${\sigma }^{\prime }={\sigma }_c-n_k{p}_p$

The coefficient n_k represents the stress coefficient, assumed as 1 for effective stress calculations without significant error. The coefficient value is typically greater than 1 for conventional rocks and less than 1 for rocks rich in clay content [55]. To analyze the combined effect of the net confining stress and slippage factor at different pore pressures on the slippage parameters, a model with Equation (7) was employed.

(7)$k_{\mathrm{\infty }}=K_a[1+b/Pm]{\left({\sigma }_c-n_k{p}_p\right)}^{-\gamma }$

Here, γ denotes the stress exponent, and k_∞ is the corrected or absolute Klingenberg permeability.

3. Results and Discussion

The primary objective of this research was to undertake a thorough and integrated analysis of the Chiltan carbonate reservoir, aiming to explore the influence of diagenesis, depositional settings, and overburden stress on its potential reservoir quality. The characterization of the reservoir involved thin-section petrography, SEM, EDS, plug porosity, and gas permeability, as well as stress sensitivity, all aimed at gaining a comprehensive understanding of the reservoir heterogeneity and its impact on the reservoir performance. The results of each analysis are detailed subsequently as follows.

3.1. Microfacies Analysis and Petrographic Description

Based on the spatial variability within and between microfacies from thin-section petrographic investigations, three distinct microfacies were identified and categorized as follows: intraclastic packestone (MF1), bioclastic pelliodal packestone (MF2), and bioclastic ooidal grainstone (MF3), all indicative of a shoal and lagoon environment.

MF1 is characterized by dark gray limestone displaying an intraclastic packestone texture. It consists of fine-grained to medium-sized particles embedded with calcite; micrite cement; and various bioclasts such as intraclasts, peloids, ooids, and pellets. Several diagenetic features of a shallow marine environment, including induced calcite fractures, and tectonic fractures, were observed in these microfacies. MF2 exhibits a light pale gray bioclastic pelliodal packestone composed of fine-to-medium-sized particles surrounded by a variety of micro-nano fossils, including pelliods, bioclasts, algae, and gastropods. Common diagenetic shifts associated with a shoal environment include cementation, micritization, and neomorphism, observed in these microfacies. MF3 is characterized by mild gray bioclastic grainstone containing euhedral to anhedral Ferron dolomite crystals. It features an accumulation of various micro-nano fossils, such as bioclasts, milliods, bivalves, echinoderms, and branchiopods. The digenetic features observed in these microfacies include intense micritization, cementation, and induced calcite fractures.

In petrography, the analysis revealed that the samples predominantly consist of limestone composition with some dolomite crystals, as seen in Figure 4. Thin-section analysis further unveiled that the examined core samples exhibit three distinct microfacies characterized by packestone and grainstone textures ranging in color from dark gray to light brownish. These microfacies contain various bioclasts and intraclasts with diverse allochems. Visual estimates indicate that calcite, micrite, spar cement matrix, and ferruginous clay content make up approximately 60%–65% of the microfacies in both packestones. In contrast, around 30%–35% of the relative average allochems consists of intraclasts, bioclasts (bivalves and gastropods), and pallets in MF1, as shown in Figure 4a,b. MF2, on the other hand, is predominantly composed of pelliods, bioclasts, algae, gastropods, and echinoderms, each with distinct ratios, as observed in Figure 4c,d. The analysis also revealed vuggy or solution and fracture porosity ranging from 2% to 5%, as depicted in Figure 4a,d. Additionally, the unusual presence of siliciclastic quartz, appearing as rounded fine-grained particles randomly arranged, is noted in Figure 4a,d. In the MF3 grainstone microfacies, visual estimates suggest that approximately 25%–30% is comprised of cement with some Ferron dolomite crystals, while 60%–65% consists of allochems, as observed in the microphotographs. Various undifferentiated bioclasts, miliolid, foraminifers, echinoids, peloids, intraclasts, and ooids were identified in the analysis, as displayed in Figure 4e,f. Additionally, minute traces of siliciclastic quartz were also observed in all three microfacies, as shown in Figure 4. The petrographic details of the observed microfacies are provided in Table 1.

The petrography and microfacies analyses of thin sections illuminated the key diagenetic features and microstructure present in the examined microfacies. The microfacies were categorized using Dunham classification to identify the grain size, cement type, and matrices. Semi-quantitative data regarding carbonate constituents in the percentages were calculated using visual estimation charts developed by Baccelle and Bosellini [56,57]. The examination revealed highly biomineralized by-products indicative of a shallow marine environment, including fossils fragments, carbonate sediments, and surrounding cement muds. The predominance of micrite cement suggests a relatively quiet depositional environment, while the bivalves and gastropods point to limited water conditions observed in both microfacies [58,59]. The presence of bioclasts such as bivalve shells and other skeletal fragments indicates a moderately saline shallow marine environment. Intraclasts, bioclasts, cement, and ooids, on the other hand, are indicative of high-tide conditions near the seashore [60]. Allochems were found to be micritized in the observed microfacies, with some partially micritized rims, particularly in the case of bivalves. This suggests the reworking of low grains in high-energy environments.

3.2. Diagenesis and Identified Features

Diagenesis begins early during the interaction of sediment with water, although many diagenetic processes occur after deposition. Diagenesis exerts a significant impact on petrophysical properties, leading to an increase in reservoir heterogeneity. This complexity results in a reduction in the porosity, permeability, and micropore structure, eventually affecting the reservoir quality [61,62]. Through petrography and SEM analyses, considerable diagenetic development was observed, characterized by stronger grain contacts and alteration of the primary sedimentary features. These features include well-sorted fine-grained sediments and diversified clay minerals, typically forming tight reservoirs with low porosity and low permeability [62,63]. This research identified several diagenetic processes that modify the configuration of carbonate rocks over time, including micritization, cementation, compaction, dissolution, and dolomitizations. Different diagenetic processes with identified features through bio-stratigraphy analysis are discussed below.

3.2.1. Micritization

Micritization was observed as an early diagenetic event that adversely affects the reservoir quality by altering the intrinsic characteristics of skeletal grains and microbial activity. The microscopic degradation of bioclasts was found to be highly significant in the examined samples, potentially creating a depositional micrite matrix, as depicted in Figure 5a. SEM imaging further confirmed that the micrite underwent recrystallization, leading to the formation of microcrystalline calcite, as shown in Figure 5b. The micritization of allochems primarily occurs in shallow waters due to the activity of algae-boring (endolithic) organisms, ultimately leading to the generation of peloids [58,64].

3.2.2. Dissolution

The dissolution or leaching of metastable bioclasts, due to the circulation of meteoric fluids, was frequently observed in the petrography and SEM analyses, as shown in Figure 5c,d. During dissolution, the micrite matrix disintegrates first, primarily during early marine and meteoric diagenesis, due to methane exaltation resulting from algal decomposition [65]. This type of dissolution is common in packestone microfacies found in lagoon environments. Later stages of dissolution involve the disintegration of dolomite grains, stylolitization, cementation, and enlargement of the fracture, as observed in Figure 5c,d. This dissolution follows the early diagenetic phase of burial diagenesis. Carbonate cement precipitates in the pores of allochems under strong shoal conditions. The retention of organic matter is limited by the constant refilling of pore spaces by oceanic water. Consequently, the disintegration of cement during early diagenesis cannot be attributed to the decomposing of organic materials [58].

3.2.3. Cementation

Calcite cementation was frequently observed in the analysis, along with a small amount of ferroan–dolomite cement, blocky cement, isopach fibrous, and drusy mosaic cement, as shown in Figure 5. The pore-filling calcite cement was found between the fossils, creating granular and drusy mosaic cement, as identified in Figure 5e,g. Dolomite cement crystals were also found with defined shapes ranging from euhedral to anhedral in packestone–grainstone microfacies. Isopachous fibrous cement is an initial stage cement that precipitated around the bioclasts and intraclasts, gradually encasing the fossils over time, as identified in Figure 5e,g. This cement type formed in a marine diagenetic environment with a high content of calcium carbonate and low clastic influx [9,66]. Blocky cement was frequently found in grainstone microfacies and precipitated in three distinct phases: intergranular, intraskeletal molds, and fractures, as observed in Figure 5e,f. The paragenetic sequence of cementation involves precipitation between allochems, grain dissolution, and fractures through fossils, indicating its recent development.

3.2.4. Compaction

Two types of compactions were observed in the examined samples. Mechanical compaction, caused by microscopic fractures in deep burial diagenesis, was evident, with fractures slashing through allochems and calcite filling in the open fractures, as observed in Figure 5f,g. Physical compaction resulted from grain contacts, breaking, and deformation induced by sediment overburden. The presence of stylolites and matrix-supported rocks serves as indicators of chemical compaction, as shown in Figure 5a,f. Mechanical compaction may result from overburden stress, while chemical changes are sensitive to factors such as temperature, pressure, and water volume in pore spaces [21].

3.2.5. Neomorphism

Several neomorphic processes were observed during the analysis, including the replacement and recrystallization of bioclasts and the microscopic matrix. Neomorphism became progressively evident in the partial-to-total recrystallization of skeletal components. Calcite with a high magnesium content accumulates in fossil bioclasts under meteoric-to-burial conditions and replaces the bioclasts with a crystalline form in a systematic manner, as observed in Figure 5c,g,h.

3.2.6. Dolomitization

Dolomite crystals were observed in the grainstone microfacies of the Chiltan formation. These dolomite crystals were found to be fine-to-medium-grained and displayed subhedral to rhombohedral shapes, indicating their sequential evolution under ambient fluid chemistry, as seen in Figure 5e,f. The dolomite crystals in this form were composed of ferroan material, as revealed by SEM and EDS analyses. Additionally, some ankerite crystals were found within the dolomite rhombs, suggesting that, when magnesium is replaced by iron, dolomite first becomes ferroan dolomite and then ankerite, as shown in Figure 5e. Mg ions are released from clays associated with carbonates to form ferroan dolomite during early-stage burial diagenesis, and over time, Fe ions gradually replace the Mg ions, as indicated by the EDS patterns.

3.3. Depositional Environment and Diagenetic History Reconstruction

The depositional environment of the Chiltan formation is classified on various identified facies and their depositional settings. The Chiltan formation is interpreted to have been deposited approximately 17 million years ago (Ma) [67]. The numerical ages are distributed, and the relative sea level interpreted the second-order rise cycle over the long term, characterized by composite transgressive tract systems. In the short term, it exhibits two episodes of third-order cycles of rising and falling sea levels, while the Haq curve comprises three episodes [68]. The absence of a single event in the Chiltan formation may be due to the local tectonic activity. The Chiltan formation exhibits a complex diagenetic history marked by several diagenetic settings and tectonic events that have taken place and altered the primary sedimentary structures and have shaped the formation’s evolution. This diagenetic history suggests the presence of both high-energy tidal shoal and low-energy wave lagoon inner shelf settings. The presence of ooids and peloids is indicative of wave-disturbed, shallow water, and high-energy conditions. Sand shoals/barriers and grainstone facies separate the open-marine from the restricted-marine environment, with several effects of early marine to meteoric diagenesis [69]. Conversely, the presence of dolomite crystals, neomorphism, and dissolution of biotic components suggests burial settings below the storm wave base depositional phase, as shown in Figure 6. According to the observed microfacies analysis, the Chiltan formation reveals a dynamic depositional history in a marine setting, with diverse sedimentary components and fossil assemblages, as depicted in Figure 6. The identification of reworked sediments, calm depositional conditions, and diagenetic process and periods provide valuable information about the formation depositional environment with its paragenetic sequence.

The order of the diagenetic processes was established to identify the paragenetic relationships during the diagenetic study. These processes include micritization, cementation, dissolution, compaction, fracturing, and vein filling occurring in distinct diagenetic environments like marine, meteoric, and burial, as identified in Figure 7. The early marine diagenetic settings encompass the micritization of allochems, matrix disintegration, and precipitation of isopachous fibrous cement, as observed during this phase. Micritization was caused by microboring organisms that partially destroy the grains at the sediment–water interface and form a micrite envelope. Isopachous calcite cement is an early marine cementation process, primarily restricted to the open sea environment, leading to the early lithification of grains and the preservation of porosity [39,70]. Meteoric diagenesis follows early marine diagenesis and is characterized by the dissolution of granular and drusy mosaic cement, resulting in the formation of vugs and molds, as identified in Figure 7. Meteoric diagenesis precedes burial diagenesis, characterized by marine cementation and dissolution. Consequently, the pore spaces associated with stylolites, dolomite, and fractures cannot be expanded or bridged [71]. Following the meteoric diagenesis, pore-filling cement and blocky cement were recognized as evidence of shallow burial settings identified from microfractures, displaced grains, neomorphism, and recrystallization. Deep burial diagenesis occurs at depths of hundreds of meters and involves various alterations like stylolitization, calcite vein filling, the formation of coarse-grained dolomite crystals, compaction, and neomorphism. The dolomites were formed by the release of Mg and Fe ions from clay during deep burial diagenesis associated with stylolites [39,72].

3.4. Mineralogical Analysis

The mineral constituents of Chiltan limestone were analyzed through SEM-EDS, FTIR, and thin sections. The observed mineralogy of the examined samples contains calcite, dolomite, and an intermix of clay and cementing materials as the dominant mineral components. Furthermore, the presence of aluminum (Al), silicon (Si), iron (Fe), sodium (Na), clay, and cementing materials was also observed. These minerals form the grain structure of carbonate rocks and are detected in SEM-EDS patterns, as shown in Figure 8a,c. Calcium intermixed with magnesium (Mg) in the presence of Fe and formed saddle Ferron dolomites. Meanwhile, the exposure of silicon (Si), aluminum (Al), sulfur (S), and sodium (Na) indicates the presence of clay minerals intermixed with siliciclastic influx, likely forming micrite, as shown in Figure 8a,c. The detailed mineral composition obtained from the EDS analysis, along with their weight percentages (%), are shown in Table 2. The pore morphology and mineralogy of the analyzed samples indicated a complex network of pore types within the formation, including micropore to macropore structures; inter–intra particles; and moldic, vuggy, and fenestral pores with variations in shape, connectivity, and distribution. Various carbonate mineral phases in the formation samples were analyzed, including calcite and dolomite, with calcite being the predominant mineral forming the rock matrix, while silica, calcite, and clay minerals were the most common cement types observed in the analysis. The mineral compositions were compared with spectral bands in the analysis to identify any changes in the mineral structures of the examined samples. The minerals within the specimen could be identified by the detected absorption spectra. The FTIR investigation showed that low-Mg calcite predominated in both samples, despite a small high-Mg calcite phase observed in the analysis, as shown in Figure 9. The carbonate phases were determined based on the peak wavenumbers of the absorption bands. A dolomite phase was identified with three absorption bands of spectrum peak wavenumbers in sample 2, while a huntite phase (Mg-rich content) was also observed with several bands in the spectrum. Furthermore, the absorption spectra of several tested minerals like quartz, feldspar, and kaolinite were also identified as non-carbonate clay species.

According to the findings from the FTIR analysis, Chiltan limestone exhibits a diverse range of carbonate phases. However, pure calcite (with low magnesium content, CaCO₃) is commonly found, characterized by peak wavenumbers at 850 cm⁻¹, 1050 cm⁻¹, 2500 cm⁻¹, and 3100 cm⁻¹, as observed in Figure 9. An increase in magnesium content results in a shift of the peak wavenumber positions from calcite to dolomite, while the peak wavenumbers for huntite and magnesite are greater than those for dolomite [73]. Varying the magnesium content gives rise to a range of high-Mg calcite (Ca_1–n Mg_n (CO₃)) bands observed in the analysis. In high-Mg calcite matrices, Ca₂⁺ ions are replaced by Mg₂⁺, leading to an increase in wavenumbers. This phenomenon has also been reported in binary and ternary carbonate solid solution systems [74,75,76]. Based on SEM, EDS, FTIR, and thin-section analyses, the most prevalent carbonate cements in Chiltan limestone include calcite, ferroan dolomites, micrite muds, and some clay minerals. These minerals impact the carbonate quality through mineral precipitation. Additionally, some terrigenous sediment, grain coatings, huntite minerals, and kaolinite clay were also identified, influencing the quality of the carbonate reservoir.

3.5. Petrophysical Measurements

For the petrophysical assessment, the density, porosity, and permeability of the core plugs from each microfacies were determined. The relatively average density of the core samples was 2.664 g/cc. The relationship between the bulk density and porosity was calculated to identify the degree of reservoir homogeneity. The observed relationship was linear and inverse with a weak correlation, as shown in Figure 10a. This suggests that the rock samples had variable mineralogical structures, grain shape, packing, and fabric, resulting in a nonuniform and heterogenous pore structure. The measured matrix porosity ranged from 0.52% to 6.4%, with an average of 3.4%, while the permeability values ranged from 0.18 to 1.69 mD, with an average of 0.449 mD. It was also observed from the porosity determination that wackestone microfacies had somewhat larger plug porosity values compared to grainstone. The estimated visual porosity during the microfacies analysis ranged from 2 to −5%, including intergranular, intracrystalline, and dissolution porosities distinguished by SEM analysis in Figure 8a–c. The plotted permeability and porosity data did not show a strong correlation and demonstrated a linear relationship with a weak coefficient due to the varied pore sizes and pore throat network, as shown in Figure 10b. This complexity of the pore structure significantly impacts the fluid flow properties and can be determined through rigorous porosity and permeability relationships. Few deviations in the cross-plotted data points were observed, indicating the presence of microcracks, as confirmed by thin-section and SEM analyses. The reduction in petrophysical properties was caused by micro-nano size pores and varying pore throat structures, thereby increasing the permeability variations and affecting the reservoir quality.

3.6. Klinkenberg-Corrected Permeability and Gas Slippage Factor

Tight permeability rocks are sensitive to stress and pore pressure, leading to gas molecules slippage at low pore pressures, resulting in an increase in the measured permeability. This slippage effect occurs due to the difference between the free path of the gas molecules and pore throat sizes [77,78]. To account for the gas slippage effects in low permeability cores at low pore pressures, the measured permeability is often corrected using the Klinkenberg permeability method in studies. Consequently, a practical method was established to calculate the Klinkenberg permeability and the gas slippage factor in the low-permeable Chiltan carbonate formation. Different empirical equations were utilized to determine the Klinkenberg-corrected permeability based on the observed pore throat geometries of the examined samples. Figure 11 illustrates the linear relationship between the permeability coefficients (K_g) and the reciprocal of the average pore pressure (1/Pav) under varying pore pressure conditions using Equation (1). The Klinkenberg permeability was determined by extrapolating the gas permeability line to zero. The obtained regression for the measured data was found to be satisfactory, with a coefficient of determination (R²) equal to 0.994. The gas permeabilities measured at various mean pore pressures and identified Klinkenberg permeability values of six carbonate core samples are provided in Table 3.

To calculate the gas slippage factor (b), a straight line was fitted to the permeability data obtained from the Klinkenberg tests using Equations (2) and (3). The outcomes that could be fitted to a straight line with a correlation coefficient greater than 0.79 for 30 data points were considered for the study. It was observed that there were variations and scattering in the data regarding the relationship between the gas permeability (K_g) and gas slip factor (b_k), as shown in Figure 12, and other relevant data are presented in Table 3. The variations in the slippage parameters and permeability may be attributed to the heterogeneity in the carbonate rocks and nonuniform pore sizes in the samples under study. Consequently, it is evident that the permeability results could not be reliably calculated using the available empirical correlations, as the carbonate rocks exhibited significant heterogeneity and a variety of pore geometries [28]. The slippage effect in a conventional reservoir core is negligible due to the larger pore radius, and the gas slip factor becomes close to zero. In contrast, a tight reservoir core possesses a very small pore radius and has significant effect on the gas flow [52,79].

Furthermore, it was observed that the gas slippage effect increases the permeability at reduced pore pressures. This indicates that gas molecules have longer free paths than the pore throat diameter and depend on effective pore sizes (r_slip). Consequently, the pore throat structure of the core samples has a significant impact on the Klinkenberg constant, which describes the difference between the measured gas permeability (K_g) and Klinkenberg permeability (k_∞). The calculated values of the effective pore size (r_slip) and gas slip factor (b_k) for the Klinkenberg permeability of the studied samples at different mean pore pressures were determined using Equations (2)–(4) and are provided in Table 3. The linear relationship between the (k_∞) and (K_g) at various mean pore pressures was also observed using Equation (5) and is illustrated in Figure 13. The corrected Klinkenberg permeability did not precisely match the average gas permeability at different mean pore pressures. This discrepancy could be attributed to the heterogeneity of the carbonate rock and varying pore throat geometries of different lithofacies caused by diagenesis. Sample #03 is the only one that closely approximated the experimental results, with an average gas permeability of 0.21 mD, which was somewhat close to the corrected Klinkenberg permeability of 0.11 mD, as mentioned in Table 3. Carbonates possess secondary porosity and fracture permeability due to their heterogeneity. Subsequently, laboratory measurements of the reservoir properties, such as a special core analysis (SCAL), are essential for understanding the reservoir performance.

3.7. Effect of Overburden Stress

Overburden stress can significantly reduce the permeability of low-permeable reservoirs, with a profound impact on the pore morphology, geometry, and petrophysical properties. Carbonate reservoirs are particularly sensitive due to their complex lithofacies and diagenetic processes, which typically affects the reservoir quality and recovery [30]. According to the experimental findings using Equations (6) and (7), the gas permeability exhibits an inverse relationship and decreases with an increase in the net stress, as illustrated in Figure 14. This suggests that an increase in the net stress leads to a decrease in pore pressure, resulting in increased permeability due to the gas slippage effect. This effect allows gas to flow more easily through the pores. Furthermore, it was observed that an increase in the net stress resulted in a decrease in the absolute permeability, as shown in Figure 15.

This implies that, at lower stress levels, an increase in the net stress leads to a decrease in permeability due to the gas slippage effect and becomes less pronounced at high pore pressures. The increased flow due to the slippage effect compensates for the reduction in slip-adjusted permeability, resulting in a larger decrease in permeabilities at higher net stresses and low pore pressures. The higher reduction in permeability at lower overburden stress was confirmed through microcracks, as identified in a few samples by the SEM and thin-section analyses shown in Figure 4 and Figure 8. These microcracks at the grain boundaries increase the permeability at lower-confining stress. The variations in effective stress and pore pressures are the primary cause of changes in the gas permeability. Therefore, it is essential to analyze the relationship between the net stresses and gas slippage to evaluate their impact on the reservoir pore radius [61]. Therefore, the slippage radius values calculated at different confining stresses using model Equation (7) are illustrated in Figure 16. The observed slippage radius decreases with the increasing net stress in steady-state and pulse decay measurements. This indicates that the compaction of the observed microcracks as identified through the SEM and thin section analyses causes a lower reduction in permeability for the net confining stress. It implies that a permeability below 1mD is more sensitive to the net overburden stress. The permeability drop in heterogeneous carbonates cannot be generalized for all types of low-permeable reservoirs. Therefore, the permeability of the examined samples demonstrated a continuous decline under the increased net confining stress, especially with a very low initial absolute permeability.

4. Reservoir Quality Assessment

An integrated study was conducted to assess the impacts of diagenesis and overburden stress on the reservoir quality of the Chiltan limestone reservoir. Several microfacies depositions with different diagenetic settings have primarily influenced the reservoir quality. Various diagenetic processes and depositional environments, such as marine, meteoric, and burial diagenesis, have significantly impacted the reservoir potential and provided the basis for static and dynamic reservoir conditions. These diagenetic events include dissolution, compaction, and dolomitization, affecting the reservoir quality. Depositional environments reduce the petrophysical properties due to early to late-stage cementation. Compaction resulting from overburden stress reduces the rock porosity through burial activities, degrading the reservoir quality after cementation. Observed microfractures, stylolites accumulation, and grain degradation may enhance the reservoir porosity at different stratigraphic stages, then by being overfilled by calcite cement during deep burial activities, as observed in the analyses. The petrophysical and petrographic evidence indicates a reduction in the intergranular porosity and even permeability. The observed dolomitization may reduce the reservoir quality, whereas dissolution may contribute to its improvement. The analyzed samples contained substantial marine organic compounds that precipitate with carbonate minerals and grains, as observed in the SEM and thin-section analyses, affecting the reservoir quality. Furthermore, rock lithification processes, such as aging, mineral compositional changes, and mineral cementation, have a significant impact on the grain textural qualities. Different carbonate minerals have diverse effects on the reservoir potential. The minerals’ authigenesis and rock diagenesis control the fluid flow movement in porous media [40,77,78,79]. Stress sensitivity indicates a reduction in the gas permeability with the increasing pore pressure, determining the gas slippage effects in the heterogeneous pore structure of the carbonate reservoir. This suggests a significant relationship between the overburden pressure, porosity, and permeability. The distribution of the porosity and permeability in tight or vuggy carbonates closely relates to the stress variations, as these properties depend on rock lithofacies and the pore architecture. The examined samples had low primary porosity and permeability values, resulting in denser carbonate rocks. The reduction in the petrophysical properties is due to the presence of intergranular, micro-nano-sized pores and pore throats among the observed microfacies, significantly affecting the reservoir potential [78]. The presence of clay and micrite mud also increases the permeability variations that affect the reservoir quality. Additionally, the overburden pressure and compaction cause the grain boundaries to come closer together, reducing their petrophysical properties and making them low-quality reservoirs. This study investigated the microscale variations in reservoir properties among the microfacies caused by diagenesis, revealing larger-scale depositional environments with unique geological histories. It provided insights into reservoir heterogeneity at the macroscopic level, highlighting the severity of the diagenetic processes influencing the quality of the reservoir. Furthermore, this study emphasizes the need for further geochemical or core flooding analyses in the future to improve the flow properties and optimize hydrocarbon recovery, highlighting the influence of diagenetic and mineralogical factors on the reservoir quality in the Chiltan formation.

5. Conclusions

A comprehensive and integrated approach was conducted on the diagenetic and mineralogical impacts on the reservoir quality assessment in the Chiltan formation, unveiling a compelling narrative of scientific exploration and discovery. The novelty of the research lies in the meticulous analysis of the intricate interplay of the diagenetic processes that significantly influenced the potential reservoir performance based on the following key findings.

• The identified microfacies primarily consist of shallow to deep marine carbonate deposits ranging from packestone to grainstone, containing various micro and nano fossil assemblages. The particle size is predominantly fine-grained to medium, with euhedral to anhedral dolomite crystals, calcite cement, bioclasts associated with the micrite matrix, and clay minerals. This complex microfacies composition reflects the dynamic geologic history and depositional settings, representing the challenges in reservoir management and production.

• Several diagenetic processes, including micritization, cementation, and neomorphism, have had a detrimental impact on the reservoir quality during different diagenetic phases, such as marine, meteoric, and burial diagenesis. Conversely, dissolution, chemical compaction, and fracturing have enhanced the secondary porosity and permeability, which, in turn, are subsequently reduced by induced calcite cementation and the intermix of clay minerals, as described in Figure 5. This interplay of diagenetic processes significantly increases the reservoir heterogeneity, which ultimately affects the reservoir performance.

• The porosity and permeability values of the analyzed core samples ranged from 2.02% to 5.31% and 0.264 mD to 0.732 mD, with a standard deviation of 1.21, reflecting the formation’s heterogeneity. The packestone facies exhibit fair reservoir potential, while the grainstone facies show poor quality, indicating the presence of a complex pore throat structure.

• SEM, EDS, and FTIR analyses revealed that the formation predominantly contains calcite, dolomite, and huntite minerals, which have a strong affinity with grains and clay minerals, leading to precipitation and an increase in the reservoir heterogeneity.

• Overburden stress sensitivity testing exposed a substantial drop in the measured gas permeability ranges up to 22%–25%, with various gas slippage effects at lower pore pressures. This indicates that rock compaction due to the net confining stress tends to decrease in the primary porosity and permeability with an increase in the burial depth. Consequently, this highlighted the challenges in maintaining an effective fluid flow, resulting in the poor quality of the reservoir.

• These findings highlight the complex interplay of diagenetic processes, mineralogy, and overburden stress in determining the reservoir quality. The incorporation of these outcomes unveils the diagenetic and mineralogical complexities and heterogeneity of the reservoir matrix, thereby enhancing the reservoir characterization accuracy and quality assessment. Further, this study suggests certain limitations like sample size, spatial variability, fluid flow mechanisms, and mechanical properties for future studies. They should employ extended data collection, advanced imaging techniques, integrated reservoir simulation, field-scale validation, and economic analysis for the better prediction and optimization of reservoir behavior and help in decision making for reservoir development planning. This holistic approach opens the window for more effective exploration and exploitation strategies for carbonate reservoirs, highlighting the value of a multidisciplinary perspective in this complex geological domain. This will significantly aid in the development of indigenous resources in the region and contribute to global advancements in the field.

Author Contributions

Conceptualization, Data Curation, and Investigation, F.H.M.; Project Administration and Supervision, A.H.T.; Resources and Validation, K.R.M.; Formal Analysis and Review, A.A.M. and K.R.M.; Writing—Original Draft, F.H.M.; Writing—Review and Editing, G.A. All authors have read and agreed to the published version of the manuscript.

Data Availability Statement

The data presented in this study are available in this article.

Acknowledgments

The authors would like to gratefully acknowledge the Mehran University of Engineering and Technology, Jamshoro, Pakistan, for the support and cooperation while conducting this research. The authors also acknowledge the HDIP, Islamabad and DGPC, Pakistan for providing public domain data source.

Conflicts of Interest

The authors declare no conflict of interest.

Footnotes

Disclaimer/Publisher’s Note: The statements, opinions and data contained in all publications are solely those of the individual author(s) and contributor(s) and not of MDPI and/or the editor(s). MDPI and/or the editor(s) disclaim responsibility for any injury to people or property resulting from any ideas, methods, instructions or products referred to in the content.

Figures and Tables

Figure 1. Tectonic history of the adjoining regions of the study area.

Figure 2. Stratigraphic column of the study area showing the petroleum play of different formations. * is the symbolic representation and indicates the interplay of respective formation potential as described in figure as source, seal and reservoir.

Figure 3. Schematic workflow of the Chiltan carbonate formation.

Figure 4. Thin-section microphotographs of the Chiltan formation displaying identified microfacies MF1 (a,b), MF2 (c,d), and MF3 (e,f). Pallets (PT), intraclasts (IT), gastropods (GT), bioclasts (BT), bivalves (BV), silicic clasts (SC), peloids (PL), echinoderms (EC), ooids (OD), foraminifera (FR), matrix (MT), stylolite disintegration (SD), vuggy porosity (VP), cement filled evaporate (FM), spar cement (SpC), fracture porosity (FP), micrite cement (Mic), branchiopods (BD), and neo morphed algae (ALG).

Figure 5. Showing thin-section microphotographs (a,c,e–h) and SEM microphotographs (b,d) of the Chiltan carbonate formation, indicating different diagenetic features. Cement micritization (MIC), dissolution of stylolite (DST), dissolution of bioclasts (DBT), dissolution of micrite cement (DM), intragranular pores (IGP), drusy cement (DC), fracture enlargement (FE), isopach fibrous cement (IF), angular mosaic cement (GM), dolomite crystals (DC), blocky cement (BC), spar cement (SC), calcite-filled fractures (CF), physical compaction (PC), low magnesium calcite (LC), replacement and recrystallization (RPC), grain dissolution (GD), fracture dissolution (FD), Ferron dolomite crystals (FE-DC), micrite envelope (MCE), and clay minerals (GM).

Figure 6. Schematic depositional phases and diagenetic environments proposed for the Chiltan limestone.

Figure 7. Sequential occurrences of diagenetic events and features with impacts on the reservoir quality.

Figure 8. SEM microphotographs (a–c) and EDS patterns of the studied Chiltan formation, indicating various minerals and diagenetic features. Dissolution pores (DP), intragranular pores (IGP), siliciclastic minerals (S-CM), intracrystalline pores (ICP), micrite (Mic), dolomite crystals (DC), and proton number of the elements (P. Number).

Figure 9. FTIR analysis of the Chiltan carbonate formation.

Figure 10. (a) Relationship between porosity and bulk density. (b) Relationship between permeability and porosity.

Figure 11. Measured gas permeability (Kg) versus reciprocal mean pore pressure (1/Pav) of sample #03.

Figure 12. Relationship between the gas slip factors versus measured gas permeability of the studied carbonate samples.

Figure 13. Relation between the corrected Klinkenberg permeability and gas permeability at different mean pore pressures.

Figure 14. Permeability (Kg) versus the net confining stress (NCS) relation.

Figure 15. Relationship between the absolute gas permeability and the net confining stress.

Figure 16. Slip radius as a function of the net confining stress.

Table 1

Petrographic illustration of the visual estimates for the observed microfacies of the Chiltan formation.

Microfacies	Carbonate Grains			Cement		Estimated Visual Porosity (Thin Section)	DominantPore Type	Diagenetic Features	Depositional Environment
Lithology	Bio-Clasts %	Intraclasts/Echinoderm %	Peloids/Ooids %	Calcite %	Micrite %
Intra-clastic Ooidal packestone	05%	20%	10%	35%	25%	Bad porosity up-to 5%	Primary porosity is limited. Secondary porosity is developed by stylolization.	Intra-Formational Clasts, Calcite veins, Neomorphism stylolization	Shoal
Bioclastic grainstone	25%	25%	15%	20%	13%	Bad porosity up-to 2%–3%	Primary porosity is limited. Secondary porosity developed due to grain dissolution.	Calcite vein, Cementation, Dissolution, Dolomitization	Lagoon
Pelliodal Packestone	15%	05%	15%	40%	20%	Bad porosity up-to 2%–5%	Primary porosity is limited. Secondary porosity developed due to grain dissolution.	Calcite vein, Cementation, Dissolution, Dolomitization	Lagoon

Table 2

Mineral composition of Chiltan limestone.

Element	Atomic No.	Mass Norm. %	Weight, %
Oxygen	8	50.90	71.46
Calcium	20	42.09	23.59
Iron	26	1.92	0.77
Aluminum	13	0.94	0.78
Silicon	14	2.86	2.29
Sulphur	16	0.43	0.30
Magnesium	12	0.57	0.53
Sodium	11	0.28	0.28

Table 3

Gas permeability data sheet and adjusted parameters at different mean pore pressures at the 500 psi stress condition.

Sample ID	Parameters	Mean Pore Pressure					Klinkenberg Permeability (mD)
		0.225	0.395	0.535	0.695	0.895
23-CHL-01	Gas Permeability (Kg), mD	0.693	0.558	0.491	0.45	0.426	0.343
	Slip radius (rslip), µm	1.5	1.39	1.49	1.59	1.59
	Gas slip factor (bk), psi	14.01	26.52	33.49	40.78	52.56
23-CHL-2A	Gas Permeability (Kg), mD	0.543	0.41	0.322	0.289	0.257	0.168
	Slip radius (rslip), µm	0.68	0.6	0.7	0.69	0.72
	Gas slip factor (bk), psi	30.64	60.94	71.14	94.32	115.06
23-CHL-03	Gas Permeability (Kg), mD	0.089	0.059	0.042	0.036	0.031	0.011
	Slip radius (rslip), µm	0.21	0.2	0.22	0.21	0.21
	Gas slip factor (bk), psi	175.2	184.6	218.72	236.7	246.3
23-CHL-4B	Gas Permeability (Kg), mD	0.712	0.502	0.408	0.341	0.273	0.153
	Slip radius (rslip), µm	0.41	0.38	0.38	0.4	0.48
	Gas slip factor (bk), psi	50.15	96.5	129.36	160.94	170.36
23-CHL-05	Gas Permeability (Kg), mD	0.381	0.251	0.173	0.149	0.112	0.027
	Slip radius (rslip), µm	0.12	0.1	0.19	0.11	0.12
	Gas slip factor (bk), psi	179.18	185.7	190.3	204.5	210.4
23-CHL-06	Gas Permeability (Kg), mD	0.283	0.186	0.132	0.112	0.095	0.032
	Slip radius (rslip), µm	0.19	0.18	0.21	0.2	0.19
	Gas slip factor (bk), psi	107.67	243.6	242.54	251.2	263.1

References

1. Xia, L.-W.; Cao, J.; Wang, M.; Mi, J.-L.; Wang, T.-T. A review of carbonates as hydrocarbon source rocks: Basic geochemistry and oil–gas generation. Pet. Sci.; 2019; 16, pp. 713-728. [DOI: https://dx.doi.org/10.1007/s12182-019-0343-5]

2. Medici, G.; Lorenzi, V.; Sbarbati, C.; Manetta, M.; Petitta, M.J.S. Structural classification, discharge statistics, and recession analysis from the springs of the Gran Sasso (Italy) carbonate aquifer; comparison with selected analogues worldwide. Sustainability; 2023; 15, 10125. [DOI: https://dx.doi.org/10.3390/su151310125]

3. Goldscheider, N.; Chen, Z.; Auler, A.S.; Bakalowicz, M.; Broda, S.; Drew, D.; Hartmann, J.; Jiang, G.; Moosdorf, N.; Stevanovic, Z.J.H.J. Global distribution of carbonate rocks and karst water resources. Hydrogeol. J.; 2020; 28, pp. 1661-1677. [DOI: https://dx.doi.org/10.1007/s10040-020-02139-5]

4. Amjad, M.R.; Ehsan, M.; Hussain, M.; Al-Ansari, N.; Rehman, A.; Naseer, Z.; Ejaz, M.N.; Baouche, R.; Elbeltagi, A. Carbonate Reservoir Quality Variations in Basins with a Variable Sediment Influx: A Case Study from the Balkassar Oil Field, Potwar, Pakistan. ACS Omega; 2023; 8, pp. 4127-4145. [DOI: https://dx.doi.org/10.1021/acsomega.2c06773] [PubMed: https://www.ncbi.nlm.nih.gov/pubmed/36743037]

5. Daud, F.; Khan, G.N.; Ibrahim, M. Remaining hydrocarbon potential in Pakistan a statistical review. Proceedings of the Society of Petroleum Engineers (SPE) Annual Technical Conference; Islamabad, Pakistan, 22–23 November 2011.

6. Durrani, M.Z.A.; Talib, M.; Ali, A.; Sarosh, B.; Naseem, N. Characterization and probabilistic estimation of tight carbonate reservoir properties using quantitative geophysical approach: A case study from a mature gas field in the Middle Indus Basin of Pakistan. J. Pet. Explor. Prod. Technol.; 2020; 10, pp. 2785-2804. [DOI: https://dx.doi.org/10.1007/s13202-020-00942-0]

7. Rashid, M.; Luo, M.; Ashraf, U.; Hussain, W.; Ali, N.; Rahman, N.; Hussain, S.; Aleksandrovich Martyushev, D.; Vo Thanh, H.; Anees, A. Reservoir Quality Prediction of Gas-Bearing Carbonate Sediments in the Qadirpur Field: Insights from Advanced Machine Learning Approaches of SOM and Cluster Analysis. Minerals; 2022; 13, 29. [DOI: https://dx.doi.org/10.3390/min13010029]

8. Cantrell, D.; Shah, R.; Ou, J.; Xu, C.; Phillips, C.; Li, X.; Hu, T. Depositional and diagenetic controls on reservoir quality: Example from the upper Cretaceous Mishrif Formation of Iraq. Mar. Pet. Geol.; 2020; 118, 104415. [DOI: https://dx.doi.org/10.1016/j.marpetgeo.2020.104415]

9. Hu, Y.; Guo, Y.; Qing, H.; Zhang, J. Diagenetic Control of Reservoir Performance and Its Implications for Reservoir Prediction in Jinci Sandstone of upper Carboniferous in the Middle East Ordos Basin. ACS Omega; 2022; 7, pp. 39697-39717. [DOI: https://dx.doi.org/10.1021/acsomega.2c03542]

10. Cipolla, C.L.; Lewis, R.E.; Maxwell, S.C.; Mack, M.G. Appraising unconventional resource plays: Separating reservoir quality from completion effectiveness. Proceedings of International Petroleum Technology Conference; OnePetro: Richardson, TX, USA, 2011.

11. Mahesar, A.A.; Shar, A.M.; Ali, M.; Tunio, A.H.; Uqailli, M.A.; Mohanty, U.S.; Akhondzadeh, H.; Iglauer, S.; Keshavarz, A. Morphological and petro physical estimation of eocene tight carbonate formation cracking by cryogenic liquid nitrogen; a case study of Lower Indus basin, Pakistan. J. Pet. Sci. Eng.; 2020; 192, 107318. [DOI: https://dx.doi.org/10.1016/j.petrol.2020.107318]

12. Purdy, E.G. Carbonate Diagenesis: An Environmental Survey; Istituto di Geologia e Paleontologia dell’Università di Roma: Rome, Italy, 1968; pp. 183-228.

13. Hewaidy, A.G.A.; Ayyad, H.M.; Abd El-Moghny, M.W.; Gameel, O.J.G.J. Sequence stratigraphy and biozonation of the Upper Eocene Anqabiya Formation, Gebel Anqabiya, Egypt. Geosci. J.; 2019; 23, pp. 357-375. [DOI: https://dx.doi.org/10.1007/s12303-018-0056-6]

14. El Husseiny, A.; Vanorio, T.J.G. Porosity-permeability relationship in dual-porosity carbonate analogs. Geophys. J.; 2017; 82, pp. MR65-MR74. [DOI: https://dx.doi.org/10.1190/geo2015-0649.1]

15. Worden, R.; Armitage, P.; Butcher, A.; Churchill, J.; Csoma, A.; Hollis, C.; Lander, R.; Omma, J. Petroleum reservoir quality prediction: Overview and contrasting approaches from sandstone and carbonate communities. Geol. Soc. Lond. Spec. Publ.; 2018; 435, pp. 1-31. [DOI: https://dx.doi.org/10.1144/SP435.21]

16. Haile, B.; Klausen, T.; Czarniecka, U.; Xi, K.; Jahren, J.; Hellevang, H. How are diagenesis and reservoir quality linked to depositional facies? A deltaic succession, Edgeøya, Svalbard. Mar. Pet. Geol.; 2018; 92, pp. 519-546. [DOI: https://dx.doi.org/10.1016/j.marpetgeo.2017.11.019]

17. Beigi, M.; Jafarian, A.; Javanbakht, M.; Wanas, H.; Mattern, F.; Tabatabaei, A. Facies analysis, diagenesis and sequence stratigraphy of the carbonate-evaporite succession of the Upper Jurassic Surmeh Formation: Impacts on reservoir quality (Salman Oil Field, Persian Gulf, Iran). J. Afr. Earth Sci.; 2017; 129, pp. 179-194. [DOI: https://dx.doi.org/10.1016/j.jafrearsci.2017.01.005]

18. Javanbakht, M.; Wanas, H.; Jafarian, A.; Shahsavan, N.; Sahraeyan, M. Carbonate diagenesis in the Barremian-Aptian Tirgan Formation (Kopet-Dagh Basin, NE Iran): Petrographic, geochemical and reservoir quality constraints. J. Afr. Earth Sci.; 2018; 144, pp. 122-135. [DOI: https://dx.doi.org/10.1016/j.jafrearsci.2018.04.016]

19. Feng, T.; Feng, Y.; Tang, J.; Cui, Y.; Wang, B.; Peng, F.; Qin, D.; Zhang, Y. Diagenesis Sequence and Hydrocarbon Accumulation Period of the Ordovician Reservoir in Well Tashen-6, Tahe Oilfield, Tarim Basin, NW China. ACS Omega; 2022; 7, pp. 29420-29432. [DOI: https://dx.doi.org/10.1021/acsomega.2c03737]

20. Strasser, A.; Pittet, B.; Hillgärtner, H.; Pasquier, J.-B. Depositional sequences in shallow carbonate-dominated sedimentary systems: Concepts for a high-resolution analysis. Sediment. Geol.; 1999; 128, pp. 201-221. [DOI: https://dx.doi.org/10.1016/S0037-0738(99)00070-6]

21. Ali, S.A.; Clark, W.J.; Moore, W.R.; Dribus, J.R. Diagenesis and reservoir quality. Oilfield Rev.; 2010; 22, pp. 14-27.

22. Ahmed, M.A.; Nasser, M.E.; Jawad, S.N.A. Diagenesis Processes Impact on Reservoir Quality in Carbonate Yamama Formation/Faihaa Oil Field. Iraqi J. Sci.; 2020; 61, pp. 92-102. [DOI: https://dx.doi.org/10.24996/ijs.2020.61.1.10]

23. Palabiran, M.; Sesilia, N.; Akbar, M. An analysis of rock typing methods in carbonate rocks for better carbonate reservoir characterization: A case study of Minahaki Carbonate Formation, Banggai Sula Basin, Central Sulawesi. Proceedings of the 41th Scientific Annual Meeting of Indonesian Association of Geophysicists (Pit Hagi) Lampung, (Aip Conference Proceedings); Lampung, Indonesia, 26–29 September 2016.

24. Sun, H.; Vega, S.; Tao, G. Analysis of heterogeneity and permeability anisotropy in carbonate rock samples using digital rock physics. J. Pet. Sci. Eng.; 2017; 156, pp. 419-429. [DOI: https://dx.doi.org/10.1016/j.petrol.2017.06.002]

25. Ahr, W.M. Geology of Carbonate Reservoirs: The Identification, Description and Characterization of Hydrocarbon Reservoirs in Carbonate Rocks; John Wiley & Sons: Hoboken, NJ, USA, 2011.

26. Ayyad, H.M.; El-Moghny, M.W.A.; Abuseda, H.; Samir, A.; Bazeen, Y.S. Sequence stratigraphy and reservoir characterization of the lower Eocene rocks (Thebes Formation) along the Tethyan Ocean’s southern margin: Biostratigraphy and petrophysical parameter applications. Int. J. Earth Sci.; 2023; 112, pp. 1091-1112. [DOI: https://dx.doi.org/10.1007/s00531-023-02291-9]

27. Boggs, S. Petrology of Sedimentary Rocks; Cambridge University Press: Cambridge, UK, 2009.

28. Abro, W.A.; Shar, A.M.; Lee, K.S.; Narejo, A.A. An integrated analysis of mineralogical and microstructural characteristics and petrophysical properties of carbonate rocks in the lower Indus Basin, Pakistan. Open Geosci.; 2019; 11, pp. 1151-1167. [DOI: https://dx.doi.org/10.1515/geo-2019-0088]

29. Shar, A.M.; Mahesar, A.A.; Chandio, A.D.; Memon, K.R. Impact of confining stress on permeability of tight gas sands: An experimental study. J. Pet. Explor. Prod. Technol.; 2017; 7, pp. 717-726. [DOI: https://dx.doi.org/10.1007/s13202-016-0296-9]

30. Shafiee, M.; Kantzas, A. Investigation on the effect of overburden pressure on vuggy carbonate oil reservoir core properties. Proceedings of the Canadian International Petroleum Conference; Calgary, AB, Canada, 16–18 June 2009.

31. Khalid, P.; Farid, A.; Naseer, M.T.; Yasin, Q.; Naseem, S. Seismic stratigraphy and attributes application for imaging a Lower Cretaceous deltaic system: Sukkur rift zone, Lower Indus Basin, Pakistan. Mar. Pet. Geol.; 2023; 149, 106030. [DOI: https://dx.doi.org/10.1016/j.marpetgeo.2022.106030]

32. Wadood, B.; Ahmad, S.; Khan, S. Sedimentary microfacies analysis and reservoir characterization of the middle jurassic carbonates: A case study from lower Indus Basin, Pakistan. Proceedings of the International Field Exploration and Development Conference 2018 8th; Springer: Singapore, 2018; pp. 1994-2000.

33. Shah, S. Geological Survey of Pakistan. Stratigr. Pak.; 2009; 22, pp. 245-273.

34. Ahmad, F.; Quasim, M.A.; Ahmad, A.H.M. Microfacies and diagenetic overprints in the limestones of Middle Jurassic Fort Member (Jaisalmer Formation), Western Rajasthan, India: Implications for the depositional environment, cyclicity, and reservoir quality. Geol. J.; 2021; 56, pp. 130-151. [DOI: https://dx.doi.org/10.1002/gj.3945]

35. Agar, S.M.; Geiger, S. Fundamental controls on fluid flow in carbonates: Current workflows to emerging technologies. Geol. Soc. Lond. Spec. Publ.; 2015; 406, pp. 1-59. [DOI: https://dx.doi.org/10.1144/SP406.18]

36. Wadood, B.; Khan, S.; Liu, Y.; Li, H.; Rahman, A. Investigating the impact of diagenesis on reservoir quality of the Jurassic shallow shelfal carbonate deposits: Kala Chitta Range, North Pakistan. Geol. J.; 2021; 56, pp. 1167-1186. [DOI: https://dx.doi.org/10.1002/gj.3968]

37. Ahmad, S.; Ahmad, F.; Ullah, A.; Eisa, M.; Ullah, F.; Kaif, K.; Khan, S. Integration of the outcrop and subsurface geochemical data: Implications for the hydrocarbon source rock evaluation in the Lower Indus Basin, Pakistan. J. Pet. Explor. Prod. Technol.; 2019; 9, pp. 937-951. [DOI: https://dx.doi.org/10.1007/s13202-018-0569-6]

38. Khan, M.A.; Khan, T.; Ali, A.; Bello, A.M.; Radwan, A.E. Role of depositional and diagenetic controls on reservoir quality of complex heterogenous tidal sandstone reservoirs: An example from the Lower Goru formation, Middle Indus Basin, Southwest Pakistan. Mar. Pet. Geol.; 2023; 154, 106337. [DOI: https://dx.doi.org/10.1016/j.marpetgeo.2023.106337]

39. Memon, F.H.; Tunio, A.H.; Mahesar, A.A.; Abbas, G. Integrated Study to Assess the Diagenetic Impacts on Petro-Physical Characteristics and Reservoir Quality of Sukkur Rift Zone. J. Xi’an Shiyou Univ.; 2023; 19, pp. 1858-1865.

40. Haris, M.; Ali, S.K.; Kazmi, S.U.; Ali, S.Z.; Zaheer, M.; Hussain, S.; Saad, K.; Islam, M.; Mehmood, T.; Humza, M. Surface and Subsurface Expressions of Jacobabad Khairpur Highs, Southern Indus Basin Using Well Data: An Approach For Well Prognosis. Int. J. Sci. Res. Publ.; 2022; 12, pp. 433-468. [DOI: https://dx.doi.org/10.29322/IJSRP.12.06.2022.p12654]

41. Qayyum, F.; Hanif, M.; Mujtaba, M.; Wahid, S.; Ali, F. Evaluation of source rocks using one dimensional maturity modeling in Lower Indus Basin, Pakistan. Arab. J. Geosci.; 2016; 9, pp. 252-274. [DOI: https://dx.doi.org/10.1007/s12517-015-2244-2]

42. Qureshi, M.A.; Ghazi, S.; Riaz, M.; Ahmad, S. Geo-seismic model for petroleum plays an assessment of the Zamzama area, Southern Indus Basin, Pakistan. J. Pet. Explor. Prod.; 2021; 11, pp. 33-44. [DOI: https://dx.doi.org/10.1007/s13202-020-01044-7]

43. Zia, A.; Awais, M.; Ishaq, M.; Hamid, S.; Akhtar, N.; Sheikh, L. Application of well log Analysis to assess the petrophysical parameters of the early eocene Sui Main Limestone (SML) in Kharnhak-1 well, Middle Indus Basin, Pakistan. Iran. J. Oil Gas Sci. Technol.; 2016; 5, pp. 1-20.

44. Siddiqui, N.K. Sui Main Limestone: Regional geology and the analysis of original pressures of a closed-system reservoir in central Pakistan. AAPG Bull.; 2004; 88, pp. 1007-1035. [DOI: https://dx.doi.org/10.1306/012004200150]

45. Khan, U.; Du, J.; Hussain, S.; Jiang, Z.; Ali, S.; Ali, I.; Khan, M.; Zhang, B. Three-dimensional Structural Modeling (3D SM) and Joint Geophysical Characterization (JGC) of Hydrocarbon Reservoir. Minerals; 2022; 12, 363. [DOI: https://dx.doi.org/10.3390/min12030363]

46. Iqbal, M.; Nazeer, A.; Ahmad, H.; Murtaza, G. Hydrocarbon exploration perspective in Middle jurassic-early cretaceous reservoirs in the Sulaiman Fold Belt, Pakistan. Proceedings of the PAPG/SPE Annual Technical Conference; Islamabad, Pakistan, 22–23 November 2011.

47. Wandrey, C.J.; Law, B.; Shah, H.A. Sembar Goru/Ghazij Composite Total Petroleum system, Indus and Sulaiman-Kirthar Geologic Provinces, Pakistan and India; US Department of the Interior, US Geological Survey: Reston, VA, USA, 2004.

48. Youssef, A.A.; Awotunde, A.A. Geosciences. Modelling fluid flow in karst reservoirs using Darcy Model with estimated permeability distribution. Comput. Geosci.; 2019; 133, 104311. [DOI: https://dx.doi.org/10.1016/j.cageo.2019.104311]

49. Gao, H.; Li, H.A. Pore structure characterization, permeability evaluation and enhanced gas recovery techniques of tight gas sandstones. J. Nat. Gas Sci. Eng.; 2016; 28, pp. 536-547. [DOI: https://dx.doi.org/10.1016/j.jngse.2015.12.018]

50. Mahesar, A.A.; Memon, K.R.; Tunio, A.H. Comparison of Klinkenberg-corrected gas and liquid permeability in Kirthar fold belt tight gas sands. Mehran Univ. Res. J. Eng. Technol.; 2017; 36, pp. 957-964. [DOI: https://dx.doi.org/10.22581/muet1982.1704.20]

51. Loeb, L.B. The Kinetic Theory of Gases; Courier Corporation: Washington, DC, USA, 2004.

52. Liu, G.; Bai, Y.; Fan, Z.; Gu, D. Determination of Klinkenberg permeability conditioned to pore-throat structures in tight formations. Energies; 2017; 10, 1575. [DOI: https://dx.doi.org/10.3390/en10101575]

53. Al-Wardy, W.; Zimmerman, R.W. Effective stress law for the permeability of clay-rich sandstones. J. Geophys. Res. Solid Earth; 2004; 109, pp. 1-10. [DOI: https://dx.doi.org/10.1029/2003JB002836]

54. Dunham, R.J. Classification of Carbonate Rocks according to Depositional Textures; Datapages, Inc.: Rockaway, NJ, USA, 1962.

55. Bacelle, L.; Bosellini, A. Diagrams for visual estimation of percentage composition in sedimentary rocks [Diagrammi per la stima visiva della composizione percentualle nelle rocce sedimentarie]. Ann. Univ. Ferrara NS Sez. IX Sci. Geol. Paleont.; 1965; 1, pp. 59-62.

56. Flügel, E.; Flügel, E. Fossils in thin section: It is not that difficult. Microfacies of Carbonate Rocks: Analysis, Interpretation and Application; Springer: Berlin/Heidelberg, Germany, 2004; pp. 399-574.

57. Cheema, A.H. Microfacies, Diagenesis and Depositional Environments of Samana Suk Formation (Middle Jurassic) Carbonates Exposed in South East Hazara and Samana Range. Ph.D. Thesis; University of the Punjab: Lahore, Pakistan, 2010.

58. Mohamed, A.A.I.; Belhaj, H.; Gomes, J.S.; Bera, A. Petrographic and diagenetic studies of thick transition zone of a middle-east carbonate reservoir. J. Pet. Gas Eng.; 2017; 8, pp. 1-10.

59. Zhao, H.; Liang, B.; Sun, W.; Hu, Z.; Sun, J.; Hao, J.; Liu, Q. Experimental Study on the Effects of Pore Pressure and Slippage on the Permeability of a Fracture Network during Depressurization of Shale Gas Reservoir Production. ACS Omega; 2022; 7, pp. 13644-13653. [DOI: https://dx.doi.org/10.1021/acsomega.1c07191] [PubMed: https://www.ncbi.nlm.nih.gov/pubmed/35559137]

60. Shar, A.M.; Mahesar, A.A.; Abbasi, G.R.; Narejo, A.A.; Hakro, A.A.A.D. Influence of diagenetic features on petrophysical properties of fine-grained rocks of Oligocene strata in the Lower Indus Basin, Pakistan. Open Geosci.; 2021; 13, pp. 517-531. [DOI: https://dx.doi.org/10.1515/geo-2020-0250]

61. Abuseda, H.; Kassab, M.A.; LaLa, A.M.; El Sayed, N.A. Integrated petrographical and petrophysical studies of some Eocene carbonate rocks, Southwest Sinai, Egypt. Egypt. J. Pet.; 2015; 24, pp. 213-230. [DOI: https://dx.doi.org/10.1016/j.ejpe.2015.05.006]

62. Caron, V. Petrogenesis of Pliocene Limestones in Southern Hawke’s Bay, New Zealand: A Contribution to Unravelling the Sequence Stratigraphy and Diagenetic Pathways of Cool-Water Shelf Carbonate Facies. Ph.D. Thesis; The University of Waikato: Hamilton, New Zealand, 2002.

63. Swei, G.; Tucker, M.E. Impact of diagenesis on reservoir quality in ramp carbonates: Gialo Formation (Middle Eocene), Sirt Basin, Libya. J. Pet. Geol.; 2012; 35, pp. 25-47. [DOI: https://dx.doi.org/10.1111/j.1747-5457.2012.00517.x]

64. Ehrenberg, S.; Eberli, G.; Keramati, M.; Moallemi, S. Porosity-permeability relationships in interlayered limestone-dolostone reservoirs. AAPG Bull.; 2006; 90, pp. 91-114. [DOI: https://dx.doi.org/10.1306/08100505087]

65. Ahmed, S.; Solangi, S.H.; Jadoon, M.S.K.; Nazeer, A. Tectonic evolution of structures in Southern Sindh Monocline, Indus Basin, Pakistan formed in multi-extensional tectonic episodes of Indian Plate. Geod. Geodyn.; 2018; 9, pp. 358-366. [DOI: https://dx.doi.org/10.1016/j.geog.2018.03.004]

66. Haq, B.U.; Hardenbol, J.; Vail, P.R. Chronology of fluctuating sea levels since the Triassic. Science; 1987; 235, pp. 1156-1167. [DOI: https://dx.doi.org/10.1126/science.235.4793.1156] [PubMed: https://www.ncbi.nlm.nih.gov/pubmed/17818978]

67. Flügel, E.; Munnecke, A. Microfacies of Carbonate Rocks: Analysis, Interpretation and Application; Springer: Berlin/Heidelberg, Germany, 2010; Volume 976.

68. Flügel, E. Microfacies Analysis of Limestones; Springer Science & Business Media: Berlin/Heidelberg, Germany, 2012.

69. Tavakoli, V.; Rahimpour-Bonab, H.; Esrafili-Dizaji, B. Diagenetic controlled reservoir quality of South Pars gas field, an integrated approach. Comptes Rendus Geosci.; 2011; 343, pp. 55-71. [DOI: https://dx.doi.org/10.1016/j.crte.2010.10.004]

70. Lee, Y.I.; Friedman, G.M. Deep-burial dolomitization in the Ordovician Ellenburger Group carbonates, west Texas and southeastern New Mexico. J. Sediment. Res.; 1987; 57, pp. 544-557.

71. Deelman, J. Magnesite and Huntite. Low–Temperature Formation of Dolomite and Magnesite. 2011; Available online: http://www.jcdeelman.demon.nl/dolomite/files/13_Chapter6.pdf (accessed on 12 March 2014).

72. Stanienda-Pilecki, K.J. The importance of Fourier-Transform Infrared Spectroscopy in the identification of carbonate phases differentiated in magnesium content. Spectroscopy; 2019; 34, pp. 32-42.

73. Sakai, S.; Yang, D.; Yasuda, T.; Akiyama, K.; Kuga, T.; Kano, A.; Shiraishi, F.; Amekawa, S.; Ohtsuka, S.; Nakaguchi, K. Pulsed terahertz radiation for sensitive quantification of carbonate minerals. ACS Omega; 2019; 4, pp. 2702-2707. [DOI: https://dx.doi.org/10.1021/acsomega.8b03311] [PubMed: https://www.ncbi.nlm.nih.gov/pubmed/31459506]

74. Abbas, G.; Tunio, A.H.; Memon, K.R.; Mahesar, A.A.; Memon, F.H.; Abbasi, G.R. Modification of cellulose ether with organic carbonate for enhanced thermal and rheological properties: Characterization and analysis. ACS Omega; 2023; 8, pp. 25453-25466. [DOI: https://dx.doi.org/10.1021/acsomega.3c02974]

75. Klinkenberg, L. The Permeability Porous Media to Liquids Gases; American Petroleum Institute Drilling and Production-Practice: Washington, DC, USA, 1941.

76. Zou, J.; Yue, X.; An, W.; Gu, J.; Wang, L. Applicability analysis of klinkenberg slip theory in the measurement of tight core permeability. Energies; 2019; 12, 2351. [DOI: https://dx.doi.org/10.3390/en12122351]

77. Memon, K.R.; Ali, M.; Awan, F.U.R.; Mahesar, A.A.; Abbasi, G.R.; Mohanty, U.S.; Akhondzadeh, H.; Tunio, A.H.; Iglauer, S.; Keshavarz, A. Influence of cryogenic liquid nitrogen cooling and thermal shocks on petro-physical and morphological characteristics of Eagle Ford shale. J. Nat. Gas Sci. Eng.; 2021; 96, 104313. [DOI: https://dx.doi.org/10.1016/j.jngse.2021.104313]

78. Memon, K.R.; Mahesar, A.A.; Ali, M.; Tunio, A.H.; Mohanty, U.S.; Akhondzadeh, H.; Awan, F.U.R.; Iglauer, S.; Keshavarz, A. Influence of cryogenic liquid nitrogen on petro-physical characteristics of mancos shale: An experimental investigation. Energy Fuels; 2020; 34, pp. 2160-2168. [DOI: https://dx.doi.org/10.1021/acs.energyfuels.9b03700]

79. Mahesar, A.A.; Ali, M.; Shar, A.M.; Memon, K.R.; Mohanty, U.S.; Akhondzadeh, H.; Tunio, A.H.; Iglauer, S.; Keshavarz, A. Effect of cryogenic liquid nitrogen on the morphological and petrophysical characteristics of tight gas sandstone rocks from kirthar fold belt, Indus Basin, Pakistan. Energy Fuels; 2020; 34, pp. 14548-14559. [DOI: https://dx.doi.org/10.1021/acs.energyfuels.0c02553]