Geochemical investigation and hydrocarbon generation–potential of the Chia Gara (Tithonian–Berriasian) source rocks at Hamrin and Kirkuk fields, Northwestern Zagros Basin, Iraq

This study investigates the geochemical characteristics and hydrocarbon generation potential of the Chia Gara Formation (Tithonian–Berriasian) in the Northwestern (NW) Zagros Basin, Iraq. A comprehensive analysis of forty–seven extract samples and seven crude oil samples was conducted to evaluate the formation’s petroleum potential. The total organic carbon (TOC) content of the analyzed samples ranged from 0.68% to 3.95%, indicating fair to excellent source rock quality. Rock–Eval parameters revealed thermal maturity, suggesting an environment favorable for both oil and gas generation. Integrated analysis of TOC/Rock–Eval data, stable carbon isotope data, and biomarker parameters confirmed the existence of kerogen Type–II and mixed–II/III constituents, along with carbonate–rich deposits. These findings suggest deposition within an algal–dominant anoxic-marine environment. Characterization of crude oils from these fields revealed paraffinic types, further supporting the interpretation of the Chia Gara interval as the primary source rock in the NW Zagros Basin. The oil–source correlation strengthens the evidence, consolidating the formation’s significance in the region’s petroleum system.


Introduction
The Zagros and Mesopotamian basins encompass a multitude of petroleum systems, spanning Paleozoic, Mesozoic, and Cenozoic rocks, solidifying Iraq's position as one of the world's most petroleum-rich nations [1,2].Iraq stands tall as a titan among the world's petroleum-rich nations, possessing an estimated 133 billion barrels of oil and over 110 trillion ft 3 of gas reserves [1,3].This extraordinary abundance strengthens its position as a major petroleum producer in the Middle East.Strategic positioning of major hydrocarbon fields within the Mesopotamian Foredeep (MFB) and Zagros basins (Figure 1A) further enhances its standing.The NW Zagros Basin (Figure 1A) represents the main exploration frontiers discovered by the North Oil Company (NOC).The Sargelu, Naokelekan/Najmah, Gotnia, and Chia Gara formations of the TMS AP7 from the bottom to the top respectively represent the main source rocks succession of this basin (Figure 1C), these formations might charge Upper-Cretaceous and Miocene age rock rock units including Shiranish Qamchuqa, Nahr Umr, Euphrates, Jeribe Dhiban reservoirs within Iraq, plus neighbor countries including Kuwait, and Iran [4,5].The oil-source correlation in the Zagros Basin region of northern Iraq continues to be an area of intense investigation, with ongoing research initiatives dedicated to unraveling the depositional environments of the hydrocarbon-generated rocks and the origin of the produced hydrocarbon in the investigation region.This study comprehensively assessed the geochemical characteristics, hydrocarbon potential, and oil-source correlations of the Chia Garainterval (Tithonian-Berriasian) in the NW Zagros Basin.Specific objectives included: a) Quantifying organic matter (OM) richness, b) determining kerogen types, c) assessing thermal maturity, d) hydrocarbon generation potential, and e) paleoenvironmental conditions during deposition.This was achieved through integrated analysis of geochemical data, including TOC content, Rock-Eval, carbon isotope (δ 13 C) analysis, gas chromatography (GC), and gas chromatography-mass spectrometry (GC-MS).Correlation of collected oils samples to elucidate their origin in the investigation region.By comparing the geochemical signs of crude oils and source rocks, researchers can identify potential source rocks and assess their generation potential.

Geological setting
Iraq is situated in a geologically active region, bordered by three major tectonic plates: the Arabian, Iranian, and Anatolian (Turkish) Plates.The Zagros Basin, an elongated fold region stretching from the Turkish margin in the north to the Iranian border in the east, is divided into the Inner and Outer 1300 (2024) 012037 IOP Publishing doi:10.1088/1755-1315/1300/1/0120373 Zagros sutures [6,7].These sutures represent zones of collision amongst the Arabian and Iranian plates.The ongoing collision of these plates has led to the creation of the Zagros Mountains, a prominent feature of the Iraqi landscape.The Inner Zagros include the Lurestan, Dezful, and Fars embayments (located in Iran), as well as Kirkuk (located in Iraq) [8,9].Paleocene Periods, the Neo Tethys, an ancient ocean, commenced its closure, marking the onset of the Arabian Plate's collision with both the Turkish and Iranian Plates.This significant collision event triggered extensive deformation and the formation of mountain ranges across the region [13].
During the Eocene Epoch, the Neo-Tethys Ocean underwent its conclusive closure, marking the culmination of the collision between the Arabian and Turkish-Iranian Plates.This significant event led to the emergence of the Zagros Mountains, recognized one of the greatest seismically active provinces worldwide in the present day [14].
The intervals from the Jurassic to the Cretaceous are characterized by a combination of carbonates, shaly carbonates, and shale rocks, as illustrated in Figure 2. Within these formations, the Chia Gara sediments exhibit a sequence of slender limestone and shale beds containing various species of ostracodes, ammonite faunas, radiolaria, and foraminifera [15].These sediments are underlain by the Gotnia (anhydrite) Formation and overlain by the Sarmord Formation.At the primary site, the Chia Gara Formation measures a thickness of 233 meters [16].The age assessment, relying on the presence of Calpionella alpina sp. and Celliptica sp., suggests a Tithonian-Berriasian age [7].

Sampling and geochemical analysis
An extensive geochemical analysis was undertaken to assess the oil generation potential of the Chia Gara interval, encompassing a comprehensive evaluation of 47 carefully selected rock samples and 7 oil samples.The samples strategically acquired are 24 from the Hamrin oilfield (H-1 well), 23 from the Kirkuk oilfield (K-109 well), and 7 from the Cretaceous-Tertiary reservoirs within the Kirkuk and Hamrin fields.This meticulous investigation provides valuable insights into the geological evolution of the region.All samples were subjected to a comprehensive geochemical analysis at StratoChem Laboratories in Cairo, Egypt.This analysis included TOC/Rock-Eval pyrolysis, δ 13 C analysis, GC, and GC-MS analyses.The results of the geochemical analysis will be used to assess the richness of organic matter, kerogen types, thermal maturation, and generation potential of the Chia Gara Formation.
Prior to geochemical analysis, both the core and cutting samples underwent a meticulous cleaning process utilizing distilled water.The objective was to eliminate any residual drilling fluid additives or potential contaminants from the samples.Following this cleaning step, the samples were pulverized to achieve a grain size of less than 200 mesh, preparing them for further analysis.This process is necessary to increase the surface area of the samples and facilitate their dissolution in hydrochloric acid (HCl).After pulverization, the samples were dissolved in HCl to remove carbonate minerals.Carbonate minerals are often present in sedimentary rocks and can interfere with the measurement of TOC.Once the carbonate minerals were removed, the samples were cleaned repetitively with purified water to remove the remaining HCl.Finally, cleaned samples were analyzed utilizing a LECOCS 200 combustion furnace to measure TOC content.TOC measurement involves determining the organic carbon existing in samples after undergoing a specific analysis process.This parameter holds significance as it serves as a crucial indicator for evaluating the potential of a formation to generate hydrocarbons.Rock-Eval 6 instrument was performed on 100 mg whole-rock samples following established procedures [17][18][19].Samples were heated in an inert environment up to 300 °C to liberate free hydrocarbons (S1), which were subsequently detected utilizing a flame ionization detector (FID).Following that, the samples were heated gradually from 300°C to 650°C at a rate of 25°C per minute to release non-volatile hydrocarbons (termed as S2) and CO2 (identified as S3).These components were detected using a flame ionization detector (FID) for hydrocarbons and a thermal conductivity detector (TCD) for CO2 (Table 1).The temperature at the maximum rate of hydrocarbon generation (Tmax) was also recorded.The S1, S2, and S3 yields were coupled with TOC in order to yield hydrogen index (HI; mg HCs/gr rock), oxygen index (OI; mg CO2/gr TOC), production index (PI; mg HCs/gr rock), and potential yield (PY; mg HCs/gr rock) (Figures 3 and 4).These indices, as illustrated in Figures 3 and 4, were subsequently utilized to estimate kerogen types, assess thermal maturity, and evaluate the potential for hydrocarbon generation.[17,[20][21][22].The saturated hydrocarbon fractions are fractionated consuming n-hexane, while dichloromethane is used for the aromatic and heteroatomic compounds (NSO).Both Delta-E isotope mass spectrometer and Sofer [23] have been used to determine stable isotopic-compositions (δ 13 C/ δ 12 C) hydrocarbon fractions.The fractionation of saturated hydrocarbons was carried out using n-hexane, a process that isolates these specific compounds.Additionally, aromatic and heteroatomic compounds (NSO) were separated by consuming dichloromethane (Table 2).The stable isotopic compositions (δ 13 C/δ 12 C) of the hydrocarbon fractions were obtained utilizing both a Delta-E isotope mass spectrometer and the methodology outlined by Sofer [23].These analytical techniques allow for a detailed examination of the carbon isotope ratios within the hydrocarbon fractions, providing valuable insights into the origin and characteristics of the OM present in the examined samples.The use of n-hexane and dichloromethane in the fractionation process enhances the specificity of the analysis, enabling a more nuanced understanding of the different components within the hydrocarbon mixture.Gas chromatography (GC) analyses were performed on an Agilent 7890-GC outfitted with a 30 m×0.32 mm silica column, with the heat of the furnace automated to rise between 70 °C and 360 °C at a rate of 5 °C per minute.This temperature program was designed to isolate a varied range of compounds, from volatile organics to heavy hydrocarbons.The Agilent 7890A-GC and 5975C-MS systems were used to determine the isotopic composition of stable carbon in the samples (Tables 3 and 4).This analytical approach offers detailed insights into the composition of saturated and aromatic hydrocarbons, thereby contributing to a further understanding of the generation potentiality of the examined geological formation.By delving into the molecular composition of OM, this methodology provides valuable information about the type and quantity of hydrocarbons present, shedding light on the formation's potential for resource development.

Results and interpretation
4.1.TOC and pyrolysis data The TOC and Rock-Eval measurement of 47 samples belonging to the Tithonian-Berriasian source rocks is presented in Table 1.The Hamrin and Kirkuk oilfields have fair to excellent generation potential for hydrocarbon, as evidenced by their TOC values, which range from 1.01 to 1.37 wt.% (averaging 1.18 wt.%) in the Hamrin oilfield and from 0.68 to 3.95 wt.% (averaging 1.78 wt.%) in the Kirkuk oilfield (Table 1).The observed positive correlation between TOC and the sum of the S1+S2 parameters (Figure 2A) suggests that the kerogen in these oilfields possesses the potential to generate significant quantities of hydrocarbons.This positive association reflects the direct relationship between the abundance of TOC and the potential yield of hydrocarbons (S1+S2).Higher TOC values correspond to greater availability of OM for hydrocarbon generation, as indicated by the corresponding increase in S1+S2 values.This correlation provides valuable insights into the hydrocarbon-generating capacity of the studied formation and highlights the potential of these oilfields to yield substantial quantities of hydrocarbons, making them attractive targets for exploration and development.The Tithonian-Berriasian interval likely played a significant role in the formation and accumulation of the hydrocarbons in the Hamrin and Kirkuk oilfields.These rocks are a valuable resource for the oil and gas industry in Iraq [24].Figure 2B shows that the analyzed samples from wells H-1 and K-109 have low S1 values compared to their higher TOC content.This indicates indigenous origin OM in these samples, meaning that it was generated within the source rock itself rather than being transported from another location.Indigenous OM is typically characterized by low S1 values relative to TOC because it is less mature and has not been subjected to the same degree of thermal and chemical alteration as transported OM.The presence of indigenous OM in the Tithonian-Berriasian interval of the Hamrin and Kirkuk oilfields is significant because it implies that these rocks have a high capability to generate hydrocarbons.Indigenous OM is generally more oil-prone than transported OM.HI and Tmax are two important parameters that are used to estimate kerogen types and maturity [25].The hydrogen Index (HI) quantifies the hydrogen content within the kerogen, whereas Tmax represents the temperature at which the highest generation percentage of hydrocarbon [26].Kerogen type delineates the composition of the Organic Matter (OM), while kerogen maturity signifies the extent to which the OM has been converted into hydrocarbons.The illustration HI and oxygen index (OI) in Figure 2C shows that the analyzed samples from the Tithonian-Berriasian formation of the Hamrin and Kirkuk oilfields contain mixed Types II, II/III, and III kerogens.This is evidenced by their HI values, which range beteen 200 and 350 mg/g, and their higher Tmax value, which range beteen 430 and 460°C.Type II kerogen is the most oil-prone kerogen type, while Type III kerogen is less oil-prone but can still generate oil, especially if it is highly mature.The fact that the investigated samples comprise Types-II, -II/III and-III kerogens suggests that they have a high oil generation potential.The Tmax data also confimed that the kerogen is in the oil window.The temperature of oil window is the range at which kerogen is actively generating oil.The fact that the Tmax values are all within the oil window suggests that the Tithonian-Berriasian formation are a viable target for oil exploration and production.The HI and Tmax data indicate that the Tithonian-Berriasian source rocks of the Hamrin and Kirkuk oilfields contain mixed Type-II/III and-III kerogen that is in the oil window.This suggests that investigated interval have a high potential to generate oil.The production index (PI) is a determine of the maturity of a source rock.It range from 0.02 to 1, with higher values indicating more mature source rocks.The data presented in Table 1 reveals that the majority of Tithonian-Berriasian samples obtained from the Hamrin and Kirkuk fields possess PI values surpassing 0.5, indicative of their maturity as source rocks.However, samples exhibit PI values below 0.5, signaling their status as immature source rocks.The prevalence of mature source rock samples within the Tithonian-Berriasian interval is a positive indicator for the prospective development of the Hamrin and Kirkuk oilfields.Mature source rocks are generally more conducive to the generation and accumulation of hydrocarbons compared to their immature counterparts.

Depositional environment
Table 2 presents the overall composition, encompassing saturates, aromatics, polarNSO, and asphaltenes, in addition to carbon isotopes and various geochemical measurements for nine rock extracts and seven oils from two fields in northern Iraq.The dataset was utilized to assess the paleodepositional conditions of OM, including the salinity, redox condition, and temperature of the depositional environment [27].The cross-plot of δ 13 CSAT versus δ 13 CARO has been established as a valuable tool for discerning the depositional conditions of geological formations and distinguishing oils originating from either marine or terrestrial sources [25].In this specific case, the dataset of δ 13 CSAT and δ 13 CARO values for the rock extracts ranges from -28.6 to -27.1‰ and -28.3 to -27.2‰, respectively (Table 2), which strongly suggests a marine-derived source (Figure 4A).These values fall squarely within the typical range for marine OM (-28 to -22‰) and are significantly lower than those for terrestrial OM (-27 to -20‰).This compelling evidence unequivocally indicates that the OM in the rock extracts was accumulated in a marine depositional condition.The data points for the rock extracts fall within the field for marine-derived oils, while those for terrestrial-derived oils typically plot in a separate, distinct field.Further corroboration for this conclusion is provided by a plot of Pr versus Ph.The Pr/Ph ratio is valuable geochemical data that provides valuable information regarding the depositional conditions and maturity of hydrocarbons.Generally, low Pr/Ph values (<1.0) indicate anoxic origin OM, whilset higher values (>1.0) are associated with terrestrial OM [28,29].In the case of the analyzed samples, the Pr/Ph ratios range between 0.35 and 0.99, which is consistent with reducing conditions and a significant contribution from marine OM [28,29].Furthermore, the crossplot of the carbon preference index (CPI) versus the Pr/Ph ratio for extract and crude oil samples (Figure 4B) reinforces the interpretation of an anoxic marine environment.The CPI, assessing the ratio of odd-numbered and even-numbered of n-alkanes, generally tends to be higher in marine OM compared to terrestrial OM.In this instance, the high CPI values observed for the analyzed samples strongly suggest a marine-origin OM.Taken together, the Pr/Ph ratios and CPI values provide compelling evidence that the OM within the samples underwent deposition in anoxic marine conditions.These results have important implications for understanding the potential for oil generation in the region.Anoxic conditions are generally favorable for the preservation of OM, which in turn increases the likelihood of oil generation.Therefore, the realization that the OM in this region originated in an anoxic marine condition suggests a high potential for the presence of exploitable hydrocarbon reservoirs.The biomarker data obtained from mz-191 and mz-217 are illustrated in Figure 5. Tricyclic terpanes, as detected by m/z 191 (Figure 5), are widely present in crude oils and bitumens, indicating their IOP Publishing doi:10.1088/1755-1315/1300/1/0120379 derivation from lacustrine and marine-origin source rock formations [30].The values of tricyclic terpanes including C19/C23, C22/C21, C24/C23, and C26/C25 (Table 3), provide insights into the environmental conditions.These values suggest a marine environment dominated by carbonate and with negligible amounts of argillaceous material.Furthermore, the C24/C26 ratio serves as a discriminative feature for characterizing the anoxic/marine depositional environment, particularly in distinguishing carbonate and shale [31].This biomarker information contributes to the overall understanding of the depositional circumstances prevalent during the deposition of OM in the Zagros Basin.The C24/C26 ratios (Tables 3) observed in the range of 2.43-4.58suggest that the sediment primarily comprises carbonatedominant source rocks deposited under reducing conditions.This biomarker insight provides valuable information about the depositional setting and environmental characteristics of the Zagros Basin during the studied period.The ratios of gammacerane/hopane (G/C30), steranes/hopanes, and C35/C34 are pivotal geochemical indicators that have an imporant role in the evaluation of source rocks and paleoenvironmental conditions of the Chia Gara Formation in the NW Zagros Basin.These ratios were determined through meticulous analyses, contributing to a further understanding of the generation potential in the region.The G/C30 ratio serves as a key marker for distinguishing between marine and lacustrine organic inputs in sedimentary environments [32].Calculated G/C30 ratios spanning between 0.05-0.21as presented in Table 3, suggest a predominance of marine-derived organic material in the Chia Gara Formation, indicative of carbonate-rich deposited in the marine depositional setting.The steranes/hopanes ratio provides insights into the organic input sources, with steranes associated primarily with higher plant OM and hopanes linked to microbial contributions [32].The ratio variation between 1.12 and 1.49 ( from both terrestrial and marine environments.This information aids in discerning the complex depositional history of the Chia Gara Formation.The C35/C34 ratio, a measure of the relative abundance of the stable carbon isotopes C35 and C34in source rock, provides valuable insights into its depositional environment [33].In this study, the C35/C34 ratios spanning from 1.09 to 1.49 as shown in Table 3, strongly support the interpretation of carbonate-dominated sediment deposited under reducing conditions (Table 2).These findings, along with other geochemical and sedimentological data, suggest that the Chia Gara Formation originated in an anoxic marine environment, a setting favorable for OM preservation and potential petroleum generation [34].The presence of low Pr/Ph ratios (Table 2) further suggests a sediment composition rich in carbonates and points towards anoxic or marine depositional conditions.The sterane biomarkers C27, C28, and C29 play a pivotal role in elucidating the origin of OM and the prevailing depositional conditions.C27 and C28 are predominantly present in marine origin organisms, while C29 is more abundant in higher plants.This distinct distribution pattern enables researchers to differentiate between marine and terrestrial sources of OM [35].In the given context, the ratio of C27-C29 steranes in the extracts and crude oil samples (Figure 6A) strongly suggests that the OM originated from an open marine depositional environment.This conclusion aligns with other geochemical and sedimentological data that also point to a marine setting for the examined intervals [36].The Trisnorneohopane (Ts) to trisnorhopane (Tm) ratio (Ts/Tm) is a valuable organic geochemical parameter that serves as an indicator of the relative proportions of terrestrial and marine origin OM in calcareous sediments.As the proportion of shale in calcareous facies increases, the Ts/Tm ratio systematically elevates, reaching a value of 0.5 as noted in previous studies [25].This phenomenon arises from the distinct distribution patterns of trisnorneohopane and trisnorhopane, two organic biomarker compounds [25].Also, The diasterane/sterane (Di/st) ratio stands as a critical organic geochemistry parameter, providing valuable information regarding the depositional cicumstaces and OM source of sediments.In the present study, the Di/st ratios of 0.96 for the extract samples (Table 4) provide compelling evidence for derivation from carbonate clay-poor sediments deposited in anoxic/marine environments.Diasteranes, unlike their sterane counterparts, are primarily associated with OM derived from algal-rich OM and other marine organisms.Therefore, a high Di/st ratio strongly indicates a significant contribution of marine OM to the sediment.In this case, the Di/st ratios of 0.96 suggest that marine OM.The ternary diagram (Figure 6A), indicates that the analyzed s are normal (paraffinic) type, and sourced from Chia Gara Formation [37].Based on API gravity values range between 28-38, the samples were classified as medium-light, while classification according to sulfur contents [38], was that the sulfur content of analyzed samples >1%, revealing sour oil types within Zagros Basin.The relationship between Pr/n-C17 and Ph/n-C18 (Table 2; Figure 6B) indicate Types II and mixed-II/III kerogens, and deposition of marine algae under reducing condition [39],.The Ts/(Ts+Tm) ratios decrease as the shale portion decreases (Table 4), low values suggest carbonate rocks [40].
A comprehensive evaluation was conducted using geochemical indicators, including Tmax and PI results, along with specific maturity indicator biomarker results (Tables 1-4).This multifaceted approach provides a thorough assessment of the maturity of the Chia Gara interval samples, offering insights into the oil generation potential of the examined formation.The analysis of Tmax and HI data (Table 1), reveals that the majority of samples examined from the Chia Gara interval as shown in Figure 4B exhibit signs of thermal maturity.This aligns with the assessment based on both Tmax and PI, signifying that the collected samples under investigation have reached a maturity level corresponding to that of the oil window except for some samples from the Ham.The only exception is for some samples from the Hamrin oilfield, which plots in the immature source rock zone consistent with the low pyrolysis Tmax values below 430 (Figure 3D).2).The C29 sterane (C29 ααS) and C32 hopane ratios, shown in Table 4, the cross plot between the C29 versus C32 isomerization ratios easily showed that the extract samples are extended from immature to peak mature of oil window (Figure 7B).The odd/even ratios of n-alkanes, including the carbon preference index (CPI), are applied to predict the thermal maturation of source rocks and hydrocarbons [41].CPI values below or approaching 1.0 suggest mature source rocks, whereas higher values are associated with relatively immature source rocks [41].The analyzed extracts show CPI values up to 1, reflecting greater thermal maturity for the examined samples.This is consistent with low Di/St.ratios, which indicate highly mature IOP Publishing doi:10.1088/1755-1315/1300/1/01203713 source rocks [28].The higher thermal maturation levels of the examined samples are also proved utilizing the Ts/Tm ratio (Table 3).The identification of a relatively elevated Ts index, along with a Ts/Tm ratio exceeding 1 (as outlined in Table 3), signifies a high level of maturity within the potential source rock.This maturity level aligns with the oil window, corresponding to %Ro values ranging between 0.55% and 0.80%.4.3.Oil/oil and oil/source rock correlations Organic biomarkers and stable carbon compositions of both aliphatic and aromatic fractions provide valuable information for deciphering the source of organic matter and the depositional environment, enabling geochemical correlations between oil samples and potential source rocks [23,30,42].This study focuses on the Chia Gara Formation in the Zagros Basin, applying biomarker and carbon isotope (δ 13 C) analysis to investigate the genetic relationship between oil samples and potential source rocks within this specific geological setting.By analyzing the distribution of specific organic biomarkers such as steranes, hopanes, and n-alkanes, alongside the carbon isotopic composition of the hydrocarbons, this study aims to identify the source organic matter and assess the genetic linkage between the oils and the Chia Gara source rocks.
There is a positive correlation between δ 13 CSAT and (δ 13 CARO) hydrocarbons indicates of the oil samples, suggesting that the oils are derived from marine sources, with the more mature oils (Figure 7A).This result is consistent with the CPI versus Pr/Ph cross plot (Figure 7B).Analysis of the isoprenoid ratios Pr/n-C17 and Ph/n-C18, commonly employed in deciphering redox conditions and organic matter inputs in depositional environments, reveals valuable insights into the origin of the studied oil samples.Notably, the cross-plot of these ratios (Figure 6B) suggests a strong correlation with Type II kerogen, characterized by a predominance of marine algae-derived organic matter accumulated under reducing environmental conditions.Pr/Ph ratio can serve as a reliable indicator of the redox conditions during deposition [43]: a Pr/Ph ratio greater than 1 indicates oxygen-rich (oxic) conditions, while a ratio below 1 suggests oxygen-depleted (anoxic) conditions.In the samples under analysis, the consistent Pr/Ph ratios below 1 consistently indicate a predominantly oxygen-depleted environment during the deposition of the source rock.This observation suggests that the organic material present in these samples accumulated in conditions lacking significant oxygen availability.Most of the analyzed samples exhibit a predominance of C27 steranes relative to C28 and C29 steranes, with C28 steranes demonstrating the lowest relative abundance of C29 and C27.A ternary diagram based on C27, C28, and C29 sterane ratios to differentiate between various depositional environments.As depicted in Figure 6A, the distribution of the steranes within the studied samples suggests a marine origin for the organic matter and indicates that the source rock most likely accumulated within an open marine environment [35].Analysis of C29 sterane diastereomers provides valuable insights into the thermal history of source rocks.The αββ/(ααα+αββ) and 20S/(20S+20R) ratios reveal moderate to high maturity (0.45-0.56) and moderate to advanced maturity (0.39-0.54), respectively.Notably, the 20S/(20S+20R) ratio aligns with a vitrinite reflectance of 0.8%, further supporting advanced source rock maturity.Therefore, analysis of C29 sterane ratios conclusively demonstrates the advanced thermal maturity of the source rocks, providing valuable information for understanding the geological history and oil generation potential of the area.

Conclusions
The investigation in this study focused on evaluating the source rock potetiality of the Chia Gara Formation.The key conclusions drawn from this research are as follows: • TOC values for the Chia Gara samples are up to 3.95 wt%, signifying a fair to excellent source rocks quality.• Rock-Eval Tmax values of up to 449 °C, and the production index (PI) was higher than 0.34, indicating that the Chia Gara Formation is within the oil window.• The stable carbon isotope and biomarker analysis revealed a marine depositional environment.• The biomarker parameters suggested carbonate sediments accumulated in an anoxic marine depositional condition.• The examined oils are classified as medium-light paraffinic oil, and the Chia Gara Formation is the main oil source that generates and expels these hydrocarbons.• The OM within the Chia Gara Formation is highly mature and of high quality, making it a promising source of rock for petroleum.• The marine depositional environment and anoxic conditions further enhance the petroleum potential of the formation.Subsequently, the Chia Gara Formation generates medium-light paraffinic oil.• The positive correlation between δ 13 CSAT and δ 13 CARO hydrocarbons indicates a marine source for the oils, consistent with biomarker analysis.• Isoprenoid ratios (Pr/n-C17 and Ph/n-C18), are indicative of marine algae-derived organic matter in an oxygen-depleted environment.• Analysis of C29 sterane reveals moderate to high maturity and moderate to advanced maturity.This is consistent with the advanced thermal maturity of the Chia Gara source rocks is indicative of their geological history and oil generation potential.

Figure 1 (
Figure 1 (A) Location maps illustrating the Zagros Basin and major structural divisions of Iraq, and (B) Location map of the Kirkuk and Hameen fields and investigated wells in Northern Iraq.

Figure 2
Figure 2 Stratigraphic chart showing the position and chronostratigraphic range of the Jurassic-Cretaceous formations in Iraq (modified after Harland et al., 1992).The formation of anticlinal structures in Iraq stems from successive stages of convergence involving the Turkish-Iranian and Arabian plates.Notably, the Hamrin and Kirkuk oilfields, regarded as the primary oilfields in the NW Zagros Basin, are situated within the low-folded zone, as depicted in Figure 1A.Notably, the Hamrin and Kirkuk oilfields, recognized as crucial oil reserves in the NW Zagros Basin, are situated within the low-folded zone, as illustrated in Figure 1A.Structurally, these fields are characterized by elongated, asymmetrical anticlines interspersed with narrow synclines and thrust faults (Figure 1B; McQuarrie 2004; Ameen 1992).The region under investigation sits at the convergence point of three significant tectonic plates: the Arabian Plate, the Turkish Plate, and the Iranian Plate.This unique positioning renders it an area of high tectonic activity, characterized by a prolonged history of subduction, collision events, and various other tectonic processes.The primary tectonic action within this area is marked by the subduction of north and northeastward-moving oceanic crust during the Late Tithonian beneath the Turkish and Iranian Plates.This subduction process played a pivotal role in generating a sequence of island arcs and marginal basins along the southern periphery of the Arabian Plate.During the Cretaceous-

Figure 3 A
Figure 3 A) A cross-plot of TOC versus S1+S2 to reveal generation potential of the examined samples, B) A cross-plot TOC versus S1 of the analyzed samples from H-1 and K-109 wells have low S1 compared with high TOC values, indicating indigenous origin OM, C) The HI vs OI diagram shows the presence of Types-III and-II kerogen and D) HI and Tmax plot show that the Tithonian-Berriasian interval of the Hamrin and Kirkuk oilfields contain mixed Types-II/III and-III kerogens that and in the oil window.

3rd 10 Figure 4
Figure4A) A cross-plot of stable carbon isotope (δ 13 C) ratios for saturated (δ 13 CSAT) and aromatics (δ 13 CARO) hydrocarbons indicates that the oils in northern Iraq originated from the Chia Gara source rock and contain mostly marine OM, B) A cross-plot of the CPI and the Pr/Ph ratio suggests that the OM in the samples has been preserved under marine conditions.

Figure 6 A
Figure 6 A) Terneray diagram of the Saturate, Aromatics, and NSO, B) Cross plot of Pr/n-C17 and Ph/n-C18 showing types-II and-mixed-II/III kerogens, and deposition of marine algae under reducing conditions.

Figure 7 A
Figure 7 A) Ternary diagram showing the paraffinic oil type in the study region and B) A plot of C32 versus Pr/n-C17.

Table 1 .
TOC/Rock-Eval data for the Kirkuk and Hamrin fields within the Zagros Basin

Table 2 .
Results of stable carbon isotope data and GC of the extract and oil samples in the NW Zagros Basin, northern Iraq.

Table 3 .
Geochemical data of both the extracts and oil samples within the Hamrin and Kirkuk fields, northern Zagros Basin, Iraq.

Table 3
) suggests a mixed organic source, indicating contributions

Table 4 .
A summary of biomarker characteristics from the Chia Gara extract and crude oil samples of the Hemreen and Kirkuk oilfields, Iraq.