Integrated Analysis of the Eocene Sakesar Formation: Depositional Environment, Microfacies, Geochemistry, and Reservoir Characteristics in the Potwar Basin, Pakistan

The current study aimed to evaluate the petroleum generation potential of the Sakesar Formation. This study interprets and presents a depositional environment model, microfacies, and geochemical and petrophysical data of the Eocene Sakesar Formation in the Potwar Basin, Pakistan. Twenty well-cutting samples from two wells and six fresh outcrop samples were thoroughly studied. Results of total organic carbon and Rock-Eval pyrolysis of Sakesar Formation sediments show fair to good TOC contents ranging from 1.2-1.67 wt%. S2 values of samples showed fair to good generation potential. Sediments appear mature, having primarily mixed Type II-III kerogen with good oil/ gas-generation potential. Three microfacies have been identified in the Sakesar Formation at the Tatral section: Bio-clastic wacke-packstone, Lockhartia-rich mud-wackestone, and benthic foraminiferal wackestone. The microfacies of the Sakesar Limestone depict the deposition of the Sakesar Limestone from the distal middle ramp to restricted inner ramp settings. Petrophysical well logs analysis of the Sakesar Formation showed an average porosity of ~9.12%; the lithology was identified as limestone, having an average water saturation of ~22.32% and an average hydrocarbon saturation of ~77.68%. Thus indicating average to good reservoir properties with very good hydrocarbon saturation. Sakesar Formation sediments characteristics interpretation showed that it can act as both source rock and reservoir rock in the Potwar Basin.


Introduction
One of Pakistan's productive oil and gas basins is the Potwar Basin in the Upper Indus Basin.Since the Attock Oil Company's first commercial hydrocarbon discovery at Khaur in 1914, the basin has been the focus of hydrocarbon exploration for more than a century (Asif et al., 2011;Du and Wang, 2013;Shah, 2022).This basin covers two-thirds of eastern Pakistan.Numerous scholars have provided details on hydrocarbon source rock (Kadri, 1995;Imtiaz et al., 2017;Liu et al., 2023;Shah and Abdullah, 2017).Hydrocarbon traps in the Potwar Basin are structurally controlled and also include stratigraphic traps (Ren et al., 2022;Shah, 2022;Xu et al., 2022a;Yasin et al., 2021;Yu et al., 2021).
The Potwar Basin's primary hydrocarbon reservoir and source rocks are the Early-Eocene and Paleocene sedimentary rocks (Kadri, 1995;Xi et al., 2023;Yang et al., 2024;Zhu et al., 2022).Major oil and gas discoveries in the Potwar Basin are from the Sakesar and Chorgali formations (He et al., 2021;Shah, 2009;Shah, 2023;Yin et al., 2023a;Yin et al., 2023b).The average thickness of the Sakesar and Chorgali formations in the area is (141.43-182.88m).A study by Fazeelat et al. (2010) has found that shallow marine sediments in the Potwar Basin are organic-rich, prompting the need to evaluate the Sakesar's Formations depositional environment, source, and reservoir rock characteristics in the Potwar Basin at Tatral and Balkassar oilfield.
The novel contribution of this research lies in its comprehensive approach: for the first time, well cutting samples, along with outcrop and well logs, have been thoroughly studied to assess source rock generation potential, thermal maturity, kerogen type identification, forms of kerogen assemblages, depositional environment, and petrophysical properties.This investigation aims to estimate the properties of reservoir rocks and their generation potential and will use Rider 1986 criteria to evaluate it (Table 1).Moreover, this research employs three different methods to assess and evaluate the two most critical properties of the petroleum system, namely, source and reservoir rock properties.Previous researchers have studied different formations and they have used different techniques.For example, Ali et al. (2015) studied Sakesar Formation reservoir properties at Fimkassar oilfield, Asif and Tahira (2007) studied the Tobra and Khewra formation's geochemical properties at Fimkassar oilfield, Khan et al. (2017) have studied microfacies of the Chorgali Formation at Khair-E-Murat range.This study is both necessary and unique due to the scarcity of information regarding the comprehensive interpretation of source and reservoir rocks in the Balkassar oilfield, including an understanding of the potential of proven source and reservoir rocks.The study area Balkassar and Tatral Section is located in Potwar Basin (Fig. 1).
The output of this study will establish the depositional environment, source generation potential, type of kerogen, thermal maturity of source rocks, forms of kerogen present and presence of possible hydrocarbons and the reservoir rocks in the subsurface of Balkassar oilfield.This research will have direct applicability to future hydrocarbon exploration by oil and gas companies.

Geological setting
The Potwar Basin is situated on the western side of the Indian Shield which is a part of the Upper Indus Basin, is where the Tatral Section and Balkassar oilfield are located (Kadri, 1995;Khan et al., 2022;Wei et al., 2023;Xiao et al., 2023;Zhang et al., 2021).The fore-deep of the Indus Basin, which consists of depressions, a platform and an outer and inner folded zone, are its main features (Kadri, 1995;Kazmi and Jan, 1997;Liang et al., 2024).The Indus Basin is host to almost all of Pakistan's main hydrocarbons resources (Kadri, 1995;Ren et al., 2023;Yin et al., 2023c;Yang et al., 2023).
The Kalachitta-Margalla hill ranges borders the Potwar Basin to the north, the Salt Range to the south, the Jhelum River to the east, and the Indus River to the west (Jia et al., 2023;Shah and Abdullah, 2016;Yin et al., 2023d;Yu et al., 2022).The basin is characterised by tight, complicated folds extending east to west that are disturbed by steep angle faults and turned southward.The northernmost part of the basin is more extensively deformed (Aadil et al., 2014;Kazmi and Abbasi, 2002;Kazmi and Jan 1997;Riaz, 2022;Shah, 2009;Shah, 2022).In the western portion, there are a number of broad, moderate east-west folds, however, the eastern portion's strike abruptly shifts toward the northeast, and the structures are composed of massive synclines and anticlines (Shah, 2022;Tie et al., 2023;Jia & Zhou, 2023;Zhou et al., 2023).

A brief overview of the source and reservoir rocks of Potwar Basin
Most of the potential source rocks in the Potwar Basin are of Palaeocene and Eocene age, and the majority of the oil discoveries are within faulted anticline traps ranging from the Cambrian to the Miocene (Table 2).The Sakesar, Wargal, Lockhart, Hangu, and Patala formations are recognized as the key source rocks in the Potwar Basin (Dai et al., 2023;Hasany and Saleem, 2012;Shah, 2022).Reservoir rocks in the basin include Paleogene shelf carbonates, Miocene alluvial sandstones, Jurassic and Permian continental sandstones, along with Cambrian alluvial and shoreface sandstones (Aadil et al., 2014;Kazmi and Abbasi, 2002).Notable reservoir rocks that have produced oil and gas in the Potwar Basin include the Jurassic Dutta, Cambrian Khewra, Jutana, Kussak, Tobra, Wargal, Amb, Margalla Limestone, Chorgali, Bhadrar, and Murree formations (Fazeelat et al., 2010;Ihsan et al., 2022;Kazmi and Jan, 1997).

Materials and Methods
A thorough geological field survey was carried at the type section of the Sakesar Formation (Tatral Section) was sampled at latitude 32°43'38.85"N,longitude 72°56'7.13"Efor sampling (Fig. 2).Assaad (2008) and Tucker (2003) standard field procedures were used for sampling.
Eight outcrop samples were extracted after digging to minimise the effects of weathering.For microfacies analysis, six representative rock samples were used.As samples must be collected from unweathered material in outcrops.Therefore, a fresh section of the outcrop should be exposed to obtain representative samples, this would require a trench to be cut through the exposed weathering zone using hand equipment, and sampling should be continuous and must evenly represent the entire interval being sampled.The exposed section to be sampled must be cleaned of all debris down to the lowest strata to be sampled.Once the exposed top layer was cleaned, a channel was excavated through the existing outcrop to expose fresh, unweathered material.This channel was extended down to the lowest strata to be sampled.Samples were then taken using a geological hammer, where harder, more resistant rock material was present.In order to support the analytical interpretation, field images of the diagnostic field characteristics were captured (Fig. 3).The Sakesar Formation, which has the lower confirmable contact with Nammal Formation in the study area, is made up of light to medium and dark grey to brown, cherty, fractured, and occasionally nodular limestone, the formation was approximately 70 m thick.The Scanning Electron Microscope (SEM) was used for the micritic sediments and high-resolution photomicrographs to interpret microfacies present in the Sakesar Limestone.Twenty well cutting samples were obtained from a well of the Balkassar oilfield in the Potwar Basin.The sediments were from Eocene sequence.The samples from well were obtained at intervals of 2-3 m interval.The details of the samples are provided in Table 3 and 4. Reservoir rock characteristics were established using various logs: density, neutron, gamma ray, resistivity and spontaneous potential logs.Criteria from Rider (1986) and Shah and Shah (2021) were used to qualitatively describe the reservoir properties.This study used a set of well logs from Well A to investigate the Chorgali Formation's reservoir potential.Shah (2022), Shah and Shah (2021) and Hartmann and Beaumont's (1999) methods were used in this study to evaluate reservoir rock characteristics.Additionally, the hydrocarbon saturation, porosity, water saturation, and formation water resistivity were all calculated.a helium environment that was heated to 600°C.Pyrolysis generated the free hydrocarbons (S1), the amount of hydrocarbons produced by thermal cracking (S2), and Tmax, which are the three most crucial parameters (Baker, 1979;Espitalié et al., 1985;Peters, 1986).The hydrogen index and production yield were two other significant factors that were determined.

Well Log Analysis
The well logs in the LAS file format (.CSV file format) were used on the interactive petrophysics software package to determine reservoir properties to estimate various important reservoir characteristics.
The procedure for obtaining various parameters from the well logs is described in the section below: The log track parameters that were directly read included:  5). 3. Self-Potential (SP) was directly determined from the log chart SP curve.4. The value of the Rmf/Rwe (equivalent water resistivity) ratio was measured (Fig. 6). 5.The equivalent water resistivity (Rwe) was calculated by dividing the corrected Rmf value by the Rmf/Rwe value ratio.
6.The equation for Rwe is as follows: R we = R mfeq /(R mfeq /R we ) Where R mfeq = equivalent mud filtrate resistivity 7. The equation in Figure 4 was used to convert R we to R w , and the correct R we value was determined using the Rwe value derived in step 5.
8. Archie's equation was used to estimate water saturation (S w ): 9. The following equation can be used to estimate the saturation of a hydrocarbon (Sw) at a particular temperature :

S H =1-Sw
After measuring the resistivity values of the mud filtrate, they were converted to equivalent mud filtrate resistivity values using the equation in Figure 4. To obtain the equivalent water resistivity, the equivalent mud filtrate resistivity values were used according to step 6.Subsequently, the equivalent water resistivity was converted to water resistivity, which was then used to determine water saturation using Archie's equation.
The log header's mud filtrate resistivity was determined at surface temperature.To determine the mud filtrate resistivity at formation temperature, it must be corrected to formation temperature for each value at a certain depth, and this correction was made using the equation presented in Figure 5.    (Schlumberger, 1977).

Microfacies analysis and depositional environment
The Sakesar Formation is comprised of light-medium grey to dark light grey, massive, nodular limestone and petrographically, it mainly comprises of wackestone depositional texture (Shah, 2009;Shah, 2023;Shah et al., 2023).

Bioclastic wackestone (Plate 1)
Limestone that makes up this microfacies is light grey, nodular, fractured, and medium to thick bedded (Fig 7).The microfacies is characterized mainly by bioclasts, the orthochem of the microfacies is micrite matrix mainly.The orthochem micrite matrix exhibits a state of calm and low energy conditions.

Depositional Environment
The bioclasts of various echinoids and algae scattered in microscopic environments are the primary allochems of this microfacies.This microfacies is consistent with an inner ramp depositional environment based on the faunal composition and depositional texture of the wackestone.

Lockhartia rich Mud wackestone (Plate 2)
It is made up of thickly bedded, cherty, nodular, light to dark grey limestone.The Lockhartia-dominant allochems of larger benthic foraminifera, followed by the Assilina species of larger benthic foraminifera, with echinoids and bioclasts of certain larger benthic foraminifera, are mostly what distinguish the microfacies.

Benthic foraminiferal wackestone (Plate 3)
This microfacies is composed of medium-to thick-bedded, light to pale grey nodular, and highly fractured limestone.The larger benthic foraminifera, rotalia species, and several echinoids comprise the majority of the allochems that characterize the plate 2 microfacies.Additionally, bioclasts of several larger and smaller benthic foraminifera are included in the allochems of this microfacies.

Depositional Environment
The micritic covering on the skeletal grains, according to Flugel et al. ( 2010), suggests deposition in the photic zone at a depth of less than 100 to 200 m.The predominance of larger benthic foraminifera, which are dispersed in micritic matrix, demonstrates very calm and low-energy conditions (Fig. 8).

TOC and Rock-Eval Pyrolysis
Commonly, organic richness is represented by TOC wt% (Peters, 1986;Peters and Cassa, 1994).According to Baker, (1979) and Espitalié et al. (1977), for clastic rocks to be considered a source rock, it should have a minimum TOC value of 1.0%.The Sakesar Formation sediments TOC contents ranges from 1.2-1.67wt%.These data indicates that the majority of the samples possessed fair to good potential as per TOC results however TOC itself is not an enough source to be relied on it only, as it is just a screening/initial method.Additionally, the samples with thermal maturity would have greater original TOC values than the TOC values at this time since TOC content declines with increasing thermal maturity (Li et al., 2023;Peters, 1986;Su et al., 2023;Wang et al., 2023;Xu et al., 2022b).
According to Peters and Cassa (1994), the S2 parameter, which is obtained during pyrolysis, is the most indicative measure for assessing the potential of hydrocarbons generation.According to Baker, (1979) and Espitalié et al. (1977), at least 5mg HC/g S2 is essential for good petroleum generation potential.Generally, the hydrocarbon (S2) yields ranged from 3.6-5.25 mg/g in Sakesar Formation.S2 vs TOC cross plot (Fig. 9) indicated fair to good petroleum generation potential.Using the migration index (S1/TOC), it is possible to differentiate between indigenous and migrated petroleum (Peters, 1986), the examined samples were indigenous, as indicated by the migration index, S1 vs TOC (Fig. 10).

Kerogen Type
HI is the hydrogen index (mgHC/g TOC) which is used to characterize the origin of organic matter (Baker, 1979).HI values for the Sakesar Formation ranged between 265-386 mg HC/g TOC.For kerogen classification, samples pyrolysis data were used HI vs Tmax plot.All examined sediments mostly have mixed type-II/III kerogen.The type of kerogen identified by S2 vs TOC plots was also in agreement with the HI vs Tmax plot (Fig. 11).

Thermal Maturity
In this study, three maturity indicators were utilized for thermal maturity including Tmax, vitrinite reflectance (%Ro), and the Production index.Vitrinite reflectance values ranging 0.6-1.3%Ro is mature, capable of generating oil (Brooks and Welte, 1984;Tissot, 1984;Waples, 1985).Tmax values varied widely, with values from 435 to 465 °C reflecting type III kerogen and values from 430 to 455 °C representing types I and II (Espitalié, 1977).
The observed vitrinite reflectance values for the Sakesar Formation ranged from 0.72 to 0.81%, with a Tmax of 438 to 443 °C, suggesting the peak of the oil generation window (Table 3) (Fig. 12).The Rock-Eval Tmax parameter is used to assess the maturity of kerogen in sedimentary rocks, which is crucial for hydrocarbon exploration, Tmax represents the temperature at which maximum hydrocarbon generation occurs from kerogen during pyrolysis, a laboratory simulation of natural thermal degradation, as kerogen matures under geological conditions, its ability to generate hydrocarbons increases, reflected in a higher Tmax value, therefore, a rising Tmax indicates more mature kerogen, helping geologists identify potential hydrocarbon source rocks and their evolutionary stage ranging from immature, through the optimal oil window, to overmature gas-producing stages (Baker, 1979;Welte, 1972;Waples, 1985).There are many factors that can influence the Tmax according to Espitalié et al. (1985) such as migrated hydrocarbons, a low pyrolysis response and oil-based mud.According to Mahdi et al. (2022) and Jarvie et al. (2001) samples have the highest Tmax values when the S2 >0.50-mg/g rock.The analysed sediments had S2 >1-mg/g rock (Table 3 and 4).The measured Tmax values of the samples ranged from 438 •C to 443 •C.According to Peters (1986) the results shows the presence of mature organic material.
The maturity of organic matter can be assessed by comparing the amount of hydrocarbons it has already generated (S1) with its total potential hydrocarbon yield.This comparison involves calculating the production index (PI), which is the sum of S1 and the remaining potential hydrocarbons (S2), as described by Collins (1975) andRomanchev (1979).For Type I and Type II kerogen PI value is more than 0.1, whereas the typical PI value range for Type III kerogen is between 0.1 and 0.2, the samples are considered immature if PI values are <0.15, the samples are considered mature if the PI values ranges between 0.15-0.4and the samples are considered over-mature if the values are >0.4 (Peters, 1986;Bacon et al., 2000).
The PI values for the sediments from the Sakesar Formation in this study ranged from 0.17 to 0.33, thus indicating a maturity level reaching the oil window (Fig. 13), which is in agreement with the Tmax and vitrinite reflectance data.

Reservoir potential
The reservoir parameters determined from the petrophysical analysis were used for quantitative interpretation of the reservoir.The estimated petrophysical characteristics of the Sakesar Formation are shown in Table 5.The average porosity was 9.12%, showing poor to moderate reservoir potential, whereas higher porosity is observed in the middle and top portion of the Formation (8028-8113ft) where as low porosity is observed at the higher depth of the formation.According to Rider's (1986) Shah and Shah (2021) criteria, the average water saturation was 22.32%, and the hydrocarbon saturation was 77.68%, indicating an average to good hydrocarbon potential (Table 1).

Organic richness and Rock-Eval pyrolysis
According to Bordenave (1993), sediments must contain a significant quantity of organic richness, typically exceeding 2% total organic carbon (TOC) by weight, for hydrocarbons to be produced when they attain thermal maturity.According to Peters and Cassa (1994), The Total Organic Carbon (TOC) is a fundamental geochemical marker that quantifies the weight percentage of organic materials present, as highlighted by Peters (1986) and Shah (2023).Analysis of the samples reveals that most exhibit fair to good TOC levels, with several displaying very good TOC contents.
To enhance our comprehension of the generative potential, it is essential to utilize Total Organic Carbon (TOC) data alongside other geochemical parameters, such as the S1 and S2 pyrolysis characteristics, as outlined by Peters and Cassa (1994) and Dembicki (2009).Consequently, to differentiate between non-indigenous and indigenous hydrocarbons, we employed both the S1 values and the TOC weight percentages.Analysis of the rock samples revealed that they consistently presented low S1 values and, conversely, high TOC levels, signifying the presence of native hydrocarbon sources.The majority of the examined sediments include mixed type-II/III kerogen.S2 vs TOC graphs and the HI vs Tmax plot both correctly identified the kind of kerogen (Fig. 11).As a result, the Sakesar Formation sediments have the potential to produce considerable amounts of hydrocarbons at the appropriate thermal maturities, as well as to contribute a significant amount to the oilfield's main petroleum system.

Microfacies analysis and depositional environment
Three microfacies have been identified based on the biogenic components, carbonate texture, and depositional fabric: Bioclastic wacke-packstone (Plate 1), Lockhartia rich Mud wackestone (Plate 2), and benthic foraminiferal wackestone (Plate 3).Assemblage of rotalia, echinoids, algae, and associated bioclasts, comprise the majority of the fauna in these microfacies.On the basis of these microfacies a depositional model has been constructed (Fig. 8).

Petrophysical analyses
Petrophysical analysis through wireline logs were conducted using spontaneous potential (SP) method.The upper and middle part of the Sakesar Formation from ~8028-8113 ft depth generally exhibits good porosity, the average porosity at most of the interpreted points is also in good potential range >10%.According to Amigun and Odole (2013) and Rider's (1986) criteria (Table 1), Sakesar Formation have good reservoir potential to produce hydrocarbons in Balkassar oilfield with moderate porosity and good hydrocarbon saturation.

Conclusions
The investigation of the Sakesar Formation sediments through microfacies analysis, geochemical analysis, and petrophysical analysis has yielded several key findings: Microfacies Analysis: Three distinct microfacies were identified based on biogenic components, carbonate texture, and depositional fabric in the Sakesar Formation at the Tatral section: Bioclastic wacke-packstone, Lockhartia-rich Mud-wackestone, and benthic foraminiferal wackestone.The microfacies of the Sakesar Limestone suggest that it was deposited in restricted inner ramp settings extending to the distal middle ramp.
Geochemical Analysis: Source rock analyses, including S2, HI (Hydrogen Index), and Tmax values, indicate that the Sakesar formations possess fair to good potential for hydrocarbon generation.The presence of mixed type II/III kerogen is suggested by the S2 and HI values.Plots of S2 vs. TOC (Total Organic Carbon) and HI vs. Tmax position the sediments within the early maturity window, implying that the Sakesar Formation may have generated oil and gas.

Petrophysical Analysis:
The Sakesar Formation exhibits average reservoir qualities but demonstrates good hydrocarbon saturation potential, indicating a promising capacity to produce hydrocarbons.
These findings collectively enhance our understanding of the Sakesar Formation's potential as a hydrocarbon source, underscoring the significance of integrated sedimentological, geochemical, and petrophysical analyses in evaluating petroleum systems.

Figure 2 .
Figure 2. Showing the exposed section of Sakesar Formation in Tatral Section, also displaying its conformable contact with Nammal Formations.

Figure 3 .
Figure 3. Litholog of the Sakesar Limestone at the study area.

Figure 5 .
Figure 5.According to temperature R mf and R we correction (Schlumberger, 1977).

Figure 8 .Figure 9 .
Figure 8. Depositional model of Sakesar Formation on the basis of samples analysed.

Table 3 .
Summary of analysed sediments of Sakesar Formations in Balkassar well 8.

Table 4 .
Geochemical results of the sediments of Balkassar well 8.

Table 5 .
Various well logs calculated parameters for different properties estimation.