Carbonate-rich Source Rock Research Articles

An integrated geochemical analysis, basin modeling, and palynofacies analysis for characterizing mixed organic-rich carbonate and shale rocks in Mesopotamian Basin, Iraq: Insights for multisource rocks evaluation

Shales and carbonate-rich sediments are crucial in characterizing the geological history of petroleum as source rocks. This emphasizes the global significance of carbonate source rocks, and it has sparked research interests and exploration of these strata as unconventional resources. This study presents inclusive organic geochemical characteristics, palynofacies analysis, and basin modeling of the carbonate source rocks in the Ajeel oilfield, Mesopotamian Basin, Iraq. This study used traditional and advanced geochemical techniques, as well as microscopic examination and basin modeling. A total of 109 core and cutting samples from the Middle Jurassic–lowermost Early Cretaceous succession were studied via geochemical and palynological methods to evaluate their thermal maturation, depositional conditions, and hydrocarbon (HC) generation potential by combining one-dimensional (1D) modeling of the burial/thermal history and the generation/expulsion timing in the Mesopotamian Basin, Iraq. The results of total organic carbon/Rock-Eval pyrolysis revealed that the Middle Jurassic–lowermost Early Cretaceous interval predominantly comprised carbonate-rich sediments with Type-II and mixed Type-II/III kerogen. Furthermore, the results showed that these potential source rocks were of fair to excellent quality (oil window) and were deposited mainly in an anoxic marine environment. Geochemical and palynological investigation suggested that the carbonate-rich source rocks were deposited mainly under a distal suboxic–anoxic condition and contained Type-II kerogen (oil prone), except for part of the Chia Gara Formation, which displayed distal dysoxic–oxic shelf depositional conditions. The 1D basin modeling results of the burial/thermal maturation history and the generation/expulsion timing showed that these sediments reached their peak generation potential (main oil window) during the Early Miocene, and this has continued until the present day. Subsequently, the Middle Jurassic–lowermost Early Cretaceous succession represents the main source of petroleum in the Mesopotamian Basin, Iraq.This work shows how an integrated palynofacies analysis, basin modeling, and geochemical study can be used for the precise assessment of multisource rock intervals of mixed organic-rich carbonate and shale rocks. These research findings will provide guidance for better resource exploitation in northern Iraq, which has higher source-rock quality in terms of organic richness and maturity than that in southern Iraq.

Origin and environmental implications of dibenzothiophenes in the Huanghekou East Sag and the Laizhouwan Northeast Sag, Bohai Bay Basin

A suite of nine oils from Huanghekou East Sag and Laizhouwan Northeast Sag, Bohai Bay Basin, China, were analysed to investigate the effect of the depositional environment on dibenzothiophenes. Five oils were high-sulfur oils (HSOs, sulfur content >1%) from Huanghekou East Sag while other four oils were low-sulfur oils (LSOs). The major organic matter inputs of all oils were algae, and specific algae might contribute to the high molecular weight alkanes and C29 steranes of HSOs. HSOs mainly originated from carbonate-rich source rocks in more saline environments while LSOs derived from clay-rich source rocks deposited in freshwater conditions, as supported by a series of biomarkers, including phytane, gammacerane, terpanes and their abundance ratios. Maturity parameters show that the samples are all in the low mature to mature stage. The methylated dibenzothiophenes are more abundant in HSOs than those in LSOs. The major sources of methylated dibenzothiophenes are algae and bacteria while the dibenzothiophene is more derived from terrigenous plants, according to the carbon isotope values of individual compounds. Abundant bacterially generated H2S as well as reducing depositional environment result in transformation from algae-originated organic matter to relatively large amount of dibenzothiophenes, further, carbonate-rich source rocks might inhibit the demethylation, leading to the more abundance of methylated dibenzothiophenes in HSOs. Parameters derived from dibenzothiophenes, such as the ratios: methyldibenzothiophenes/methylphenanthrenes, methyldibenzothiophenes/phenanthrenes, dimethyldibenzothiophenes/dimethylphenanthrenes, and dimethyldibenzothiophenes/phenanthrenes are most useful for indicating reducing depositional environments among HSOs and LSOs.

Thermal maturation, mineral catalysis, and gas generation kinetics of carbonate source rock

Source-rock evaluation must start by first characterizing thermal maturity. The concept of thermal maturation or thermal decomposition is a well-defined quantitative modelling of kinetic parameters to explain the generation and expulsion of liquid and gaseous hydrocarbons from sedimentary source rocks. However, unlike coal and shale source rocks, carbonate source rocks are emerging source rocks and no analyses of thermal maturation kinetics have been reported in the literature. Apparently, this study is one of the most recent and first laboratory study of thermal maturation kinetics of carbonate source rock. In this paper, we simulated this process by conducting controlled laboratory experiments under high temperature from 40 °C to 450 °C using advanced integrated analytical techniques. The dataset is modeled by the solid state kinetics of first order reactions. In addition, the poor knowledge of how catalytic minerals stimulate thermal maturation is investigated; a unique and significant contribution that sets this work apart from previous thermal maturation studies. The result from kinetic modelling showed that the distribution of activation energy in the range of 99–325 kJ/mol is bimodal, reflecting possible peak shift in the thermal decomposition process, reaction mechanism and maturation prediction. The model further suggests that the maturation process of carbonate-rich source rock is very likely to be different from that of clay-rich source rock. Elemental and mineralogical analyses of investigated sample revealed the presences of catalytic elements such as iron, gypsum, pyrite and kaolinite. The analysis of the generated gases constrained to only three gases showed that the volume content of carbon dioxide, methane and water are 2%, 46% and 52% respectively. The generation of carbon dioxide is constant whereas methane increases and water decreases respectively with thermal maturation. Although, the investigated sample has a high calcite content of 91.9%, the methane content of 46% gives a strong indication of high natural gas generative potential as contrasted with the 2% of carbon dioxide generated. The findings of this study can help to better understand the coupled mechanism controlling thermal maturation of carbonate source rock and also provide useful reference dataset for basin modelling of carbonate source rocks for field studies.

Integrated geochemical characterization and geological modeling of organic matter-rich limestones and oils from Ajeel Oilfield in Mesopotamian Basin, Northern Iraq

The current study focuses on the organic geochemical and basin modeling of organic matter-rich limestones and oil samples from the Ajeel Oilfield. The objective was to characterize the organic matter and its hydrocarbon-generating potential, and its relevance to future hydrocarbon exploration in the northwestern Mesopotamian Basin. The organic biomarker results of the extracted bitumen samples indicated that the Sargelu, Naokelekan, and Chia Gara limestones received abundant planktonic-bacterial organic matter input, with a limited terrestrial contribution. Lipid-rich organic matter that originates from phytoplankton and bacteria with low amounts of terrestrial organic matter suggest a high abundance of Type-II or mixed-II/III kerogen as the original organic matter at time of sedimentation.Bulk property and geochemical analyses of the recovered oil samples, with mediumAPI gravities between 31 and 33°, and relatively high sulfur concentrations of up to 3.95 wt%, suggest that examined oil samples were derived mainly from Type II-S kerogen at moderate maturity stages. Biomarker ratios and parameters, as well as carbon isotopes, further indicated that these oils were derived from marine carbonate-rich source rocks deposited under reducing environmental conditions. These biomarker fingerprints and carbon isotopes show a genetic link between the oil examined samples and the extracted rocks of the Sargelu, Naokelekan, and Chia Gara source rocks and represent a mix of these carbonate-rich source rocks. Therefore, these source rocks contained kerogen Type II-S with high sulfur, and generated commercial oil at relatively low thermal maturity of early to moderate stages, as demonstrated from maturity parameters such as Tmax and PI as well as several biomarker ratios.Burial/maturity models with kerogen Type–II–S kinetic parameter revealed that the Sargelu, Naokelekan, and Chia Gara intervals began to generate oil at slightly lower thermal maturity (maturity levels = 0.55–0.79 EASY%Ro). As a result, about 10%–50% of the organic-matter was converted to oil during the Late Paleocene. The basin models also suggested that the organic-rich units including Sargelu and Naokelekan source rocks reached higher maturity levels, with TR of 71%–79% in the Early Miocene (20 Ma) and continued to the present. Trapping large quantities of oil lead to the high pressures and expulsion of these oils. The high conversion ratios further suggested large oil volumes accumulated in the northwestern Mesopotamian Basin were mainly originated from the Middle-Late Jurassic Sargelu and Naokelekan source rocks.

Geochemical characteristics of crude oils and basin modelling of the probable source rocks in the Southern Mesopotamian Basin, South Iraq

Bulk property and geochemical analyses were performed on 15 crude oil samples collected from the Early Cretaceous clastic reservoirs in the oilfields of the southern Mesopotamian Basin, South Iraq. Specific gravities ranging between 25.4 and 31.6 API and relatively high sulfur concentrations of up to 1.97 wt % suggest that the samples were generated from kerogen Type II-S at relatively low maturity level. Biomarker ratios and parameters as well as carbon isotope ratios, indicate that the oils were derived from marine carbonate-rich source rocks deposited under reducing environmental conditions during the Jurassic to Early Cretaceous. Furthermore, biomarker maturity suggests two maturity subgroups for the samples based on their sulfur concentrations and specific gravity values. Sub-group (A) is characterized by oils generated from low-mature source rocks from the Late Jurassic-Early Cretaceous Sulaiy Formation; while the relatively high mature oils of sub-group (B) were generated from organic-rich intervals in the Jurassic Sargelu and Najmah formations. Basin model results revealed that these formations reached a peak oil-generation window at different times, expelling various quantities of oil. The basin model results further suggest that the organic-rich interval in the Sulaiy Formation began to expel little amounts of oil, corresponding to transformation ratio (TR) between 50 and 63% since the Late Miocene to present-day, while the organic-rich intervals in the Sargelu and Najmah formations were the earliest to expel significant amounts of oil, with relatively high TR values of 50–90% during the end of the Late Cretaceous to Early Eocene and continued to the present-day. These generated oils subsequently migrated to the shallow stratigraphic reservoir intervals through the vertical pathway of faults, and are currently extracted for use in the oil industry.

Organic geochemistry of oil seeps from the Abu-Jir Fault Zone in the Al-Anbar Governorate, western Iraq: Implications for early-mature sulfur -rich source rock

Organic geochemical methods were performed on four oil seep samples collected from the Abu-Jir Fault Zone (AJFZ) in the Al-Anbar Governorate, western Iraq. These oil seeps have undergone biodegradation, showing large unresolved complex mixture (UCM) shapes, with degradation of normal alkanes and isoprenoids. The inorganic elements of the Abu-Jir oil seeps, i.e., S, Ni and V, suggest a marine carbonate-rich source rock deposited under reducing environment conditions. The biomarker ratios and parameters of hopane and sterane further suggest that the oil seeps were derived from source rock rich in lipids from phytoplankton and bacteria with less contribution of terrigenous organic debris. The chemical maturity indicators show that the Abu-Jir oil seeps were generated from early mature sulfur -rich source rock, thus in association with a high S content of more than 1.93%. The geochemical characteristics of the analyzed oil seep samples are similar, which is consistent with most of the crude oils in the northern and southern basins in Iraq, and were generated from the Middle Jurassic Sargelu Formation. The overall geochemical correlations and geological information confirm that the Abu-Jir Faultoil seeps in the western Iraq were sourced from the Middle Jurassic Sargelu Formation that reached an early maturity level of oil-generation window and that they migrated into the ground surface through the Abu-Jir major fault during the middle Miocene.

Oil-oil correlation by FTIR spectroscopy of asphaltene samples

In this paper, a new technique with easy interpretation, low cost, and reliable results is presented for oil-oil correlation purpose. In this technique, the structural characterization of asphaltene, because of its structural similarity with kerogene and resistance to secondary processes (e.g., migration, biodegradation, thermal maturity, and so on), was considered as a correlation parameter and asphaltenes structure similarity in different oil samples is the basis of geochemical correlation. FTIR spectroscopy was applied to detect and compare asphaltene structures with each other. The four oil samples from different oil fields in the Iranian sector of the Persian Gulf were investigated by FTIR spectroscopy and introduced indexes that represent structural characteristic of asphaltenes enabled us to perform geochemical correlation. To validation of this technique, the other common geochemical techniques (e.g., stable carbon isotope and biomarkers) were applied to geochemical correlation. These techniques completely supported and complemented the results of the asphaltene FTIR spectroscopy technique. The results of these three techniques show genetic relationships among these 4 oil samples and indicated that these oil samples belong to two distinct oil families. The First oil family originated from carbonate rich source rock and the second oil family was sourced from calcareous shale source rock.

HYDROCARBONS IN THE MIDDLE MIOCENE JERIBE FORMATION, DYALA REGION, NE IRAQ

The Lower Miocene Jeribe Formation in northern and NE Iraq is composed principally of dolomitic limestones with typical porosity in the range of 10–24% and mean permeability of 30 mD. The formation serves as a reservoir for oil and gas at the East Baghdad field, gas at Mansuriya, Khashim Ahmar, Pulkhana and Chia Surkh fields, and oil at Injana, Gillabat, Qumar and Jambur. A regional seal is provided by the anhydrites of the Lower Fars (Fat'ha) Formation.For this study, oil samples from the Jeribe Formation at Jambur oilfield, Oligocene Baba Formation at Baba Dome (Kirkuk field) and Late Cretaceous Tanuma and Khasib Formations at East Baghdad field were analysed in order to investigate their genetic relationships. Graphical presentation of the analytical results (including plots of pristane/nC17 versus phytane/nCl8, triangular plots of steranes, tricyclic terpane scatter plots, and graphs of pristanelphytane versus carbon isotope ratio) indicated that the oils belong to a single oil family and are derived from kerogen Types II and III. The oils have undergone minor biodegradation and are of high maturity. They were derived from marine organic matter deposited with carbonate‐rich source rocks in suboxic‐anoxic settings.A range of biomarker ratios and parameters including a C28/ C29 sterane ratio of 0.9, an oleanane index of 0.2 and low tricyclic terpane values indicate a Late Jurassic or Early Cretaceous age for the source rocks, and this age is consistent with palynomorph analyses. Potential source rocks are present in the Upper Jurassic – Lower Cretaceous Chia Gara Formation and the Middle Jurassic Sargelu Formation at the Jambur, Pulkhana, Qumar and Mansuriya fields; minor source rock intervals occur in the Balambo and Sarmord Formations. Hydrocarbon generation and expulsion from the Chia Gara Formation was indicated by pyrolysate organic matter, palynofacies type (A), and the maturity of Gleichenidites spores.Oil migration from the Chia Gara Formation source rocks (and minor oil migration from the Sargelu Formation) into the Jeribe Formation reservoirs took place along steeply‐dipping faults which are observed on seismic sections and which cut through the Upper Jurassic Gotnia Anhydrite seal. Migration is confirmed by the presence of asphalt residues in the Upper Cretaceous Shiranish Formation and by a high migration index (Rock Eval SI / TOC) in the Chia Gara Formation. These processes and elements together form a Jurassic/Cretaceous – Tertiary petroleum system whose top‐seal is the Lower Fars (Fat'ha) Formation anhydrite.

SOURCE ROCK EVALUATION AND PETROLEUM GEOCHEMISTRY, OFFSHORE SW IRAN

Mesozoic and Tertiary source rocks and crude oils from six oilfields in the Persian (Arabian) Gulf (Hendijan, Bahrgansar, Abouzar, Nowruz, Dorood and Foroozan) were studied using a variety of organic-geochemical techniques. Biomarker characteristics were combined with other geochemical data to identify the source rocks which generated the oil in these fields and to reconstruct their depositional environments, and also to characterize the diagenetic and catagenic processes which have occurred. The analyzed oils show a wide range of densities (19 to 39° API) and high sulphur contents. They were generated by Type II-S organic matter; they are not biodegraded and their maturity level is generally low. Two main oil groups were identified from statistical analysis and can be correlated with different source rocks using age-specific biomarkers and isotope data. Group 1 oils include those from the Hendijan, Bahrgansar and Abouzar fields and were probably generated by a mid-Cretaceous argillaceous source rock. Group 2 oils include those from the Nowruz, Dorood and Foroozan fields, and originated from Jurassic to Early Cretaceous carbonate-rich source rocks.

Geochemical comparison of fluid inclusion and present-day oil accumulations in the Papuan Foreland – evidence for previously unrecognised petroleum source rocks

Petroleum production in Papua New Guinea is limited to the Papuan Fold Belt. Present-day oil accumulations in fields such as Iagifu, Hedinia and Gobe are thought to be mainly derived from clay-rich, Jurassic marine source rocks containing terrestrially-derived organic matter that were deposited under oxic conditions. In this study, other generative source rocks in the Papuan Foreland are indicated using fluid inclusion (FI) oil data from three wildcat wells Koko-1, Bujon-1 and Kimu-1, which were drilled on the Bosavi Arch. Detailed organic geochemistry of these FI oils, and associated free oils or oil stains, suggests that none of these were generated from the aforementioned Jurassic source rocks. Instead, at least three different generative source rocks are indicated. Firstly, a marine, probably Late Cretaceous or younger source rock deposited under reducing conditions is indicated by the Bujon-1 FI oil. This source rock had a moderate contribution from higher plant organic matter, including oleanane and/or lupane. The Bujon-1 FI oil has similarities with FI oils from the Iagifu-7x and P’nyang-2X wells in the Papuan Fold Belt. Secondly, an algal-dominated, lacustrine source rock is indicated by the biodegraded Koko-1 RFT crude oil, the unbiodegraded FI oil from Koko-1, and the Bujon-1 oil stains from the Toro and Imburu formations. These lacustrine oils have high abundances of tricyclic terpanes, pregnane, homopregnane and gammacerane, contain β-carotane, and have high C 26/C 25 tricyclic terpane ratios. The source of the lacustrine oils is inferred to contain moderate amounts of terrestrial organic matter, indicated by a dominance of C 29 steranes and abundant aromatic higher plant biomarkers, and could be gypsiferous shales embedded in Oligocene-Miocene carbonates, or Triassic-age sediments deposited on igneous basement during early rifting associated with the break-up of Gondwana. The Kimu-1 FI oil was generated from a mature, marine, suboxic source rock, but has a different geochemical composition to free oil from a similar interval, which was derived from a carbonate-rich source rock. None of the FI oils correlate well with oil families previously described in Papua New Guinea. Accordingly, the oils recovered from FIs in this part of the Papuan Basin support the presence of laterally varying source rock compositions and qualities, and indicate that there are opportunities to develop new charge models for features across the Papuan Foreland. Furthermore, Koko-1, Bujon-1 and Kimu-1 FI oils have different geochemical compositions compared to the associated free oils or oil stains, indicating that each of these localities has a multi-phase charge history. Further work to lower exploration risk in the Papuan Foreland should be directed to understanding the distribution, maturity and expulsion history of these newly recognised potential source rocks.

Petroleum systems of the Upper Magdalena Valley, Colombia

In the Upper Magdalena Valley, Colombia, four petroleum systems were identified. Two petroleum systems are located in the Girardot sub-basin and the other two in the Neiva sub-basin. Limestones laterally changing to shales of the lower part of the Villeta Gp, deposited during Albian and Turonian marine flooding events, constitutes the main source rocks of the oil families. These rocks contain 1–4% TOC and type II kerogen. The littoral quartz arenites of the Caballos (Albian) and Monserrate (Maastrichtian) Fms. are the main reservoir rocks. Seal rocks are Cretaceous and Paleocene shales. Overburden includes the Cretaceous rocks and the Tertiary molasse deposited simultaneously with development of two opposite verging thrust systems during Cenozoic time. These deformation events were responsible for trap creation. Except for the Villarrica area, where the source rock reached maturity during the Paleocene, generation occurred during Miocene. Two oil families are identified, each in both sub-basins: One derived from a clay-rich source and the second from a carbonate-rich source rock lithofacies of the lower part of Villeta Gp. Geochemical source-rock to oil correlations are demonstrated for the three of the petroleum systems. Up-dip lateral migration distances are relatively short and faults served as vertical migration pathways. A huge amount of oil was probably degraded at surface, as a result of Miocene deformation and erosion.

Recognition of an Infracambrian Source Rock Based on Biomarkers in the Baghewala-1 Oil, India

Heavy, sulfur-rich oil produced from the Infracambrian (540-640 Ma) Jodhpur Formation in the Baghewala-1 well represents a new exploration play in the Bikaner-Nagaur basin in India and the Punjab basin in Pakistan. The Baghewala-1 oil is nonbiodegraded, and thermal-maturation-dependent biomarker ratios indicate generation from the source rock within the early oil window. Age-diagnostic and source-dependent biomarkers indicate that the oil originated from algal and bacterial organic matter with no higher plant input in an Infracambrian, carbonate-rich source rock deposited under anoxic marine conditions. These characteristics support a local origin of the Baghewala-1 oil from organic-rich laminated dolomites in the Infracambrian Bilara Formation. Significant amounts of petroleum could originate from equivalents of the proposed Bilara source rock in the Punjab basin, Pakistan, where the Precambrian to lower Paleozoic section is thicker and more deeply buried than in India. Deeper burial of the source rock in the Punjab basin than in the Bikaner-Nagaur basin could generate more mature equivalents of the Baghewala-1 oil. The Baghewala-1 oil is geochemically similar to another heavy oil from the Infracambrian Salt Range Series in the nearby Karampur-1 well in Pakistan and to oils derived from carbonate-evaporite facies of the Infracambrian Huqf Group about 2000 km (1243 mi) to the southwest in the Eastern Flank province of southern Oman. These findings are consistent with published evidence that subsiding rift basins in northwest India, Pakistan, and southern Oman were in close proximity during the Infracambrian along the Middle Eastern edge of Gondwanaland.

30-Norhopanes: their occurrence in sediments and crude oils

Sediments and crude oils have been analysed using GC-MS techniques and shown to contain two homologous series of hopanes, namely 30-nor-17α(H)-hopanes and 25,30-bisnor-17α(H)-hopanes, as well as the common 17α(H)-hopanes. Homologues (C 28 to C 34) of the 30-nor-17α(H)-hopane series have been identified in crude oils associated with carbonate source rocks. The abundances of these hopanes relative to the 17α(H)-hopanes in the soluble organic matter from carbonate sediments has been shown to depend upon sample maturity: the more mature samples having higher relative abundances of these norhopanes. A comparison of the relative abundances of the norhopanes in the soluble organic matter of sediments and in the hydrocarbon fraction released when the extracted sediments were pyrolysed showed that the 30-nor-17α(H)-hopanes were more abundant in the pyrolysis product. These observations indicate that the proportion of norhopanes relative to normal 17α(H)-hopanes in bound form in the kerogen, is greater than that present in the soluble form, and so kerogen cracking proceeds with increased maturity of the sediments, and a relative enrichment of these norhopanes occurs in the soluble fraction. The series of 25,30-bisnor-17α(H)-hopanes has been identified in a severely biodegraded crude oil from a putative carbonate source. This observation, together with the reported occurrence of enriched 25-norhopanes in severely biodegraded crude oils, suggests that 25,30-bisnor-17α(H)-hopanes may be biomarkers for severely biodegraded crude oils from carbonate-rich source rocks.

Oil Families in the Eastern Mediterranean Offshore and Southern Israel: Biomarker and Trace Element Analysis: ABSTRACT

Oil samples were obtained from producing wells and DSTs from the eastern Mediterranean offshore and the southern coastal plain and Dead Sea area in Israel. The oil samples were fractionated by liquid chromatography and analyzed by capillary gas chromatography and gas chromatography-mass spectrometry to define their gross chemical and biomarker composition. The nickel and vanadium content of the samples was analyzed by emission spectrography. The oils may be classified into three different families which agree with their geographical distribution. The biomarker distributions and nickel/vanadium ratios of the oils from the Dead Sea region suggest they were derived from a carbonate-rich source rock deposited in a highly reducing hypersaline environment. The oils from the coastal plain Helez-Kokhav field were also generated from a predominantly carbonate-rich source rock. However, they probably were contributed from a clastic rock deposited in a slightly less reducing depositional environment, as indicated by the presence of diasteranes and higher pristane/phytane and nickel/vanadium ratios. The Ziv 1 oil from the eastern Mediterranean offshore was probably generated from a predominantly clastic, marine source rock. All the oils analyzed seem to have been generated from mature source rocks. The maturity of their host rocks is much lower, indicating the oilsmore » reached their present location by lateral and/or vertical migration. The Dead Sea region oils have suffered varying amounts of water-washing and biodegradation, whereas the Helez-Kokhav and Ziv 1 oils have suffered limited water-washing and only little (if any) biodegradation.« less