Marine Carbonate Source Rocks Research Articles

Anthropogenic petroleum signatures and biodegradation in subantarctic Macquarie Island soils

Special Antarctic Blend (SAB) diesel is the main fuel used on Macquarie Island and has been identified as the primary contaminant in several past spill events. This study evaluates the environmental impact of petroleum spills at high latitudes, in the soils of subantarctic Macquarie Island. Soil samples were collected from seven locations, including the “fuel farm” and main powerhouse that have been contaminated by petroleum in the past, and five reference locations, away from station infrastructure and from any obvious signs of contamination. Soils were solvent extracted and analysed using gas chromatography-mass spectrometry. The results show that both contaminated and uncontaminated sites contained a suite of different chain-length hydrocarbons. The more contaminated samples from the fuel farm and main powerhouse contained higher concentrations and a greater range of hydrocarbons that typically indicate numerous spills of varying ages. The hydrocarbon signature of samples collected near the fuel farm and at some of the main powerhouse sites was typical of SAB diesel. However, the hydrocarbon signature at other main powerhouse sites suggest contamination with a heavier fuel with different characteristics, including lower pristane/phytane ratios. Traces of C21–C35 cyclic biomarkers in the spill sites may be derived from additional heavier fuels, and include a signature characteristic of crude oil derived from marine carbonate source rocks. Reference samples had lower concentrations of hydrocarbons, and these were dominated by high molecular weight n-alkanes with an odd-carbon-number predominance, typical of higher-plant derived lipids. Some reference samples also contained geochemical signatures that suggest that they too were contaminated by fuel oil. Variable levels of biodegradation of fuels in soils are consistent with a heterogenous site and a relatively slow rate of biodegradation. The occurrence of fresh spilled fuel overprinting biodegraded fuel from earlier spills is compelling evidence of multiple spills and complex mixing in the environment.

Characteristics and Significance of Acid-Soluble Organic Matter in Marine Carbonate Source Rocks

Since the 1950s, major breakthroughs have been made in the field of carbonate oil and gas exploration, and large reservoirs have been found in carbonate strata in many countries; however, the validity of highly evolved carbonate source rocks has been controversial. Because of the loss of organic carbon during acid-solution processing in conventional total organic carbon (TOC) determination, we decided to use a new method of reducing acid-solution losses in order to more effectively quantify acid-soluble organic matter in carbonate rock samples. Different levels of acid-soluble organic matter were present in different types of samples, and there was no positive correlation between the content of acid-soluble organic matter and conventionally measured TOC values. However, the thermal evolutionary maturity of samples with high acid-soluble organic matter content is relatively low, and the high hydrocarbon generation conversion rate of acid-soluble organic matter and conventional TOC in carbonate rocks is an important reason for the low residual TOC in highly evolved carbonate rocks. The new method is helpful in re-evaluating the abundance of organic matter in carbonate rocks and in providing evidence for studying hydrocarbon generation and the hydrocarbon capacity of carbonate source rocks.

An integrated petrographical, petrophysical and organic geochemical characterization of the Lower Turonian Abu Roash-F carbonates, Abu Gharadig field, Egypt – Inferences on self-sourced unconventional reservoir potential

Marine carbonate source rocks are ubiquitous worldwide and many of these can act as self-sourced unconventional reservoirs. This work focuses on the Lower Turonian Abu Roash-F Member from the prolific Abu Gharadig field, Western Desert, Egypt which consists of argillaceous and bioclastic limestones. Thin section petrographic analysis indicated the presence of various microfacies assemblages dominated by planktonic foraminifera in association with abundant calcispheres indicating an open-marine, deep-shelf depositional setting. The X-Ray Fluorescence data exhibits overall poor detrital influx throughout the AR-F while the Mo and V enrichment in the lower part represents Late Cenomanian/Early Turonian (C/T) oceanic anoxic event (OAE2) associated with the global sea-level rise. Geochemical analysis suggests that the studied AR-F has good to very good total organic carbon (TOC) content (up to 3.57 wt%) consists of Type-II kerogen (HI > 400 mgHC/gTOC), thermally mature (Tmax ∼ 438.5 °C) and presently within the oil generation window. The TOC-rich (>2.5 wt%), highly anoxic lower AR-F showed higher oil production probability which is inferred as a sweet spot zone. Petrophysically AR-F is very tight and impervious with 0.9–2.6% porosity and negligible permeability (<0.0033 mD), dominated by nano- and microporosities. Micritization is found to be the most dominant diagenetic process reducing the AR-F storage capacity, followed by calcite cementation filling the bioclast tests and fractures, chemical compaction (stylolites), and minor dolomitization. 2D CT scanning revealed some minor vuggy or fracture pores but those were isolated and lacks in connectivity, which therefore did not improve the flow capacity of AR-F. Therefore, stimulation is necessary to bring this tight carbonate reservoir into production. This study offers critical insights on the AR-F Member which is an excellent source rock and at the same time holds potential as a promising unconventional reservoir.

THE LA LUNA/RÍO NEGRO(.) PETROLEUM SYSTEM AT THE URDANETA WEST FIELD, LAKE MARACAIBO BASIN, NW VENEZUELA: 1D BASIN MODELLING AND SECONDARY OIL MIGRATION

This paper investigates the timing of hydrocarbon generation in the northern part of the Urdaneta West field in the NW of the Lake Maracaibo Basin, NW Venezuela, based on 1D basin modelling at three wells referred to as wells X, Y and Z. Kitchen areas were identified and secondary migration directions were inferred based on analyses of the thermal and burial history of the Upper Cretaceous La Luna Formation source rock and the geochemistry of 20 oil samples from the Río Negro Formation reservoir. Aliphatic hydrocarbons in the oil samples were analysed by gas chromatography – mass spectrometry (GC-MS) while the vanadium-nickel and sulphur contents were determined by energy dispersive X-ray spectrometry and inductively coupled plasma optical emission spectroscopy, respectively. Bulk and molecular characterizations indicated that the oils originated from a marine carbonate source rock containing oil-prone Type II kerogen, consistent with generation by the La Luna Formation. Burial and thermal history modelling in the study area indicated that the La Luna source rock at wells X, Y and Z reached the oil window during the late Eocene, mid-Eocene and early Paleocene respectively. 1D model results from the three wells showed that hydrocarbon generation began in the early Eocene. The transformation ratio of the La Luna Formation source rock in the modelled wells reached values of 35%, 98% and 100% by the end of the Eocene. In the Urdaneta West field, two different oil charges appear to have mixed in the Río Negro reservoir. Both oil charges were generated by the La Luna Formation source rock but at different times. A first charge of less mature oil occurred in the middle-late Eocene (Phase 1 generation), and a second, more mature oil charge took place in the Miocene – Quaternary (Phase 2 generation). The kitchen area for the first oil charge is inferred to have been located to the north and NE of Urdaneta West; that for the second oil charge to the south of the field. This migration model is supported by observed variations in the geochemical compositions of the oil samples analysed from different wells in the Urdaneta West field.

Geochemical characteristics, origin and carbon isotope reversal of the presalt natural gas in the Lower Paleozoic Ordovician carbonates, Ordos Basin, China

The origin and potential source of the presalt natural gas in the Lower Paleozoic Ordovician carbonates within the Ordos Basin, China, is heavily debated, and the causes of carbon isotope reversal are currently unclear. This study analyzes the source and origin of the presalt natural gas and determines the reasons for carbon isotope reversal. The results show that the nonhydrocarbons contain CO2, H2S, and N2 and some gas samples have high H2S contents of 9.02%–23.58%. The dryness coefficient (C1/C1+) of 91.06%–99.99% (ave. 98.34%) suggests that the presalt gas is mainly a dry gas with some wet gas and that it originates from a high-to over-mature source. However, the results show that the presalt natural gas is primarily a wet-gas-cracking gas, rather than a kerogen-cracking gas, with a certain amount of coal-type gas mixing and it mainly originated from oil-prone marine carbonate source rocks rather than the Permian–Carboniferous coal measures. The gas has different types of carbon isotope reversal patterns, and the δ13C2 values become negative at Roequ > 1.5%. The mixing between the oil-cracking and wet-gas-cracking gas at Roequ > 1.5% results in carbon isotope reversal (δ13C1 > δ13C2), rather than Rayleigh and migration fractionation. The occurrence of thermochemical sulfate reduction (TSR) is supported by the high abundance of H2S in the presalt gas, reservoir bitumen in dissolved pores, secondary calcite with negative δ13Ccarbonate of −21.1‰ to −9.7‰, and diagenetic cubic pyrite. It is evident that the heavy δ13C2 values (greater than −28‰) and the carbon isotope reversal of δ13C2 > δ13C3 of the presalt natural gas at Roequ < 1.5% are related to TSR. This study also establishes a new model of the carbon isotope reversal of the natural gas, which is primarily controlled by its thermal maturity and TSR. Six carbon isotope patterns can be well explained and are supported by real gas samples from the presalt strata, and two types of carbon isotope reversal are predicted.

Biodegradation and the origin of surface bitumens in the Palaeocene Kolosh Formation, Northern Iraq

The bitumen from surface exposures of the Palaeocene Kolosh Formation in three areas (Duhok, Shaqlawa and Dokan) of northern Iraq were investigated using GC, GC-MS, carbon and hydrogen isotope ratios of aromatic, NSO and asphaltene to determine their state of alteration (biodegradation, water washing and abiotic oxidation), thermal maturity and potential source rocks. These samples have a high percentage of NSO and asphaltene and minor amounts of saturated and aromatic hydrocarbons. These bitumens have a distinguished biomarker distribution, which can be attributed to different levels of biodegradation. The samples of Group 1 are moderately biodegraded: their normal alkanes and isoprenoids have been removed, whereas their hopanes and steranes are intact or have been very slightly altered. The samples of Group 2 are heavily to very heavily biodegraded; their steranes and hopanes are degraded without the formation of 25-norhopanes. These samples are more oxidized than those of Group 1. The bitumens have different origins, and their terpane and sterane ratios indicate that they were generated by early mature marine carbonate source rocks that were likely to have originated from Jurassic–Lower Cretaceous Formations.

Upper Jurassic-Lower Cretaceous Source-Rock Evaluation and Oil—Source Rock Correlation in the Abadan Plain, Southwest Iran

Eight oil samples from Lower Cretaceous Fahliyan reservoirs and 51 core and cutting samples from Upper Jurassic-Lower Cretaceous Garau Formation in Abadan Plain, Southern Iran, were analyzed using bulk property and molecular methods in order to identify their geochemical characteristics such as maturity and source depositional environment, as well as to correlate them to respective source rock(s). Rock-Eval pyrolysis and vitrinite reflectance measurements indicated that the Garau Formation, classified as a good-to-excellent source rock, the kerogen is mainly of Type II and the maturity is in peak oil generation. The crude oils of the Fahliyan reservoir are classified as light oil (API more than 35), non-biodegraded, saturate fraction, slight even/odd predominance, and front-end biased distribution in gas chromatogram. According to molecular and isotopic data, the oils were generated by a marine carbonate source rock which was deposited under the anoxic condition. Furthermore, all the studied samples reveal compositional similarity and hence can be assigned to one oil family, originating from a common source rock. Based on compositional similarities of biomarkers and isotope data in the studied crude oils and source rock, the Upper Jurassic-Lower Cretaceous Garau Formation can be regarded as the main source rock of the oils.

Organic geochemical characteristics of Jurassic petroleum system in Abadan Plain and north Dezful zones of the Zagros basin, southwest Iran

Jurassic succession has resulted in prolific oil and gas reservoirs in southwest Iran. In order to geochemically investigate the Jurassic petroleum system and assess the source rock of these hydrocarbons, 32 source rock samples (from well cutting and surface section) and 4 condensate samples were analysed using geochemical approaches. Rock-Eval pyrolysis and vitrinite reflectance measurement were done on rock samples. Then, condensate samples and source rock extracts were subjected to gas chromatography, gas chromatography–mass spectrometry and isotopic analyses in order to establish oil–oil and oil–source rock correlation. The hydrocarbon generation prediction was then confirmed by petroleum system modelling. The results indicated that the middle Jurassic Sargelu Formation with average total organic carbon (TOC) and hydrogen index values of 3.8% and 600 mg HC/g TOC, respectively, can be classified as good to excellent source rock with kerogen of type II. The maturity indicators revealed late oil to wet gas generation window for the Jurassic Sargelu Formation. Biomarker parameters showed marine carbonate source rock with advanced level of thermal maturity for the source rock of the condensates. Furthermore, there were good correlations between Jurassic Sargelu Formation and the studied oil and condensate samples which proved the Sargelu Formation as the main source rock of the Jurassic petroleum system in the study area. The basin modelling results also confirmed late oil to wet gas window maturity for the Sargelu Formation enabling it as a source rock for generating gas condensate accumulation in southwest Iran. The hydrocarbon generation from Sargelu Formation began in the late Cretaceous and its peak expulsion occurred in the Miocene time.

Quick Evaluation of Present‐Day Low‐Total Organic Carbon Carbonate Source Rocks from Rock‐Eval Data: Middle–Upper Ordovician in the Tabei Uplift, Tarim Basin

AbstractPrevious studies have postulated the contribution of present‐day low‐total organic carbon (TOC) marine carbonate source rocks to oil accumulations in the Tabei Uplift, Tarim Basin, China. However, not all present‐day low‐TOC carbonates have generated and expelled hydrocarbons; therefore, to distinguish the source rocks that have already expelled sufficient hydrocarbons from those not expelled hydrocarbons, is crucial in source rock evaluation and resource assessment in the Tabei Uplift. Mass balance can be used to identify modern low‐TOC carbonates resulting from hydrocarbon expulsion. However, the process is quite complicated, requiring many parameters and coefficients and thus also a massive data source. In this paper, we provide a quick and cost effective method for identifying carbonate source rock with present‐day low TOC, using widely available Rock‐Eval data. First, we identify present‐day low‐TOC carbonate source rocks in typical wells according to the mass balance approach. Second, we build an optimal model to evaluate source rocks from the analysis of the rocks' characteristics and their influencing factors, reported as positive or negative values of a dimensionless index of Rock‐Eval data (IR). Positive IR corresponds to those samples which have expelled hydrocarbons. The optimal model optimizes complicated calculations and simulation processes; thus it could be widely applicable and competitive in the evaluation of present‐day low TOC carbonates. By applying the model to the Rock‐Eval dataset of the Tabei Uplift, we identify present‐day low‐TOC carbonate source rocks and primarily evaluate the contribution equivalent of 11.87×109 t oil.

GEOCHEMICAL EVALUATION OF CRUDE OILS FROM THE CARACARA AND TIPLE AREAS, EASTERN LLANOS BASIN, COLOMBIA: PALAEO BIODEGRADATION AND OIL MIXING

This study presents an organic geochemical characterization of heavy and liquid oils from Cretaceous and Cenozoic reservoir rocks in the Tiple and Caracara blocks in the eastern Llanos Basin, Colombia. Samples of heavy oil were recovered from the Upper Eocene Mirador Formation and the C7 interval of the Oligocene – Miocene Carbonera Formation; the liquid oils came from these intervals and from the Cretaceous Guadalupe, Une and Gachetá Formations. The heavy oil and most of the liquid oils probably originated from multiple source rocks or source facies, and showed evidence of biodegradation as suggested by the coexistence of n‐alkanes and 25‐norhopanes. The results indicate a close genetic relationship between the samples in the Carbonera (C7 interval), Mirador and Guadalupe Formation reservoirs. These petroleums are interpreted to result from at least two separate oil charges. An early charge (Oligocene to Early Miocene) was derived from marine carbonate and transitional siliciclastic Cretaceous source rocks as indicated by biomarker analysis using GC/MS. This initial oil charge was biodegraded in the reservoir, and was mixed with a later charge (or charges) of fresh oil during the Late Miocene to Pliocene. A relatively high proportion of the unaltered oil charge was recorded for heavy oil samples from the Melero‐1 well in the Tiple block, and is inferred to originate from Cenozoic carbonaceous shale or coaly source rocks. Geochemical parameters suggest that oils from the Gachetá and Une Formations are similar and that they originated from a source different to that of the other oil samples. These two oils do not correlate well with extracts from transitional siliciclastic source rock from the Upper Cretaceous Gachetá Formation in the Ramiriqui‐1 well, located in the LLA 22 block to the north. By contrast, one or more organofacies of the Gachetá Formation may have generated the heavy oil and most of the liquid oil samples. The results suggest that the heavy oils may have formed as a result of biodegradation at the palaeo oil‐water contact, although deasphalting cannot entirely be dismissed.

Oil shows geochemistry and fluid inclusion thermometry of Mid Cretaceous carbonates from the eastern Basque Cantabrian Basin (N Spain)

Abstract Surface liquid and solid hydrocarbons are common in Cretaceous carbonate exposures throughout the Basque Cantabrian Basin (N Spain). This study investigates the oil shows that appear in the upper Albian-lower Cenomanian reefal limestones cropping out in the eastern margin of the basin in order to assess potential source rocks and common characteristics with other oil occurrences in the basin. Specifically, the study focuses on (i) the petrography and fluid inclusion thermometry of the host rock and cements, and (ii) geochemistry of the hydrocarbons including biomarkers and isotopes. Geochemistry results indicate that the studied oils, in a way similar to previously reported hydrocarbons from the eastern Basque Cantabrian Basin, were generated from marine carbonate source rocks deposited in a hypersaline environment. However, their isotopic signatures are notably different, and thus discard a common source rock. Moreover, the studied oils are notably different from those reported elsewhere in the basin, both in the western and northern parts. The petrography of the calcite cements and the fluid inclusion thermometry suggests a scenario of condensates to light oils HC migration trapped in burial calcite cements at a minimum temperature of 174 °C. The generation, migration and entrapment of these oils took likely place between Turonian and Campanian time in close association with the elevated heat flow resulting from the rift extension. Following this stage, a second entrapment of heavy to asphaltene-rich oils occurred at 72 °C, likely during the Late Cretaceous to early Cenozoic uplift related to the early stages of inversion of the Basque Cantabrian Basin. The elevated temperature of the oil entrapment suggests the occurrence of abnormal geothermal gradients in the eastern Basque Cantabrian Basin during the middle Late Cretaceous, which is ultimately associated with the opening of the Bay of Biscay.

Accumulation and potential analysis of self-sourced natural gas in the Ordovician Majiagou Formation of Ordos Basin, NW China

Abstract The characteristics of the marine carbonate source rocks and the accumulation and potential of self-sourced natural gas in the Ordovician Majiagou Formation of the Ordos Basin are investigated based on recent exploration by using geochemistry and gas-source correlation methods. Massive source rocks are developed around the salt depression, east of the paleo-uplift in the Ordovician Majiagou Formation during the Caledonian; and the natural gases produced by argillaceous dolomite and dolomitic mudstone are the major contributors of the Ordovician gas field. Besides widespread carbonate weathering crust reservoir, internal grain band dolomite reservoir are also well-developed in the Majiagou Formation, and both can act as favorable reservoirs. The natural gas of the Majiagou Formation is mainly self-sourced oil-type gas generated by in-situ source rock and accumulated near the source area. There is only limited local accumulation of natural gas produced in the upper strata and stored below. The Majiagou Formation around the salt depression has favorable conditions for large scale natural gas generation and accumulation, and has the advantage of collecting large area natural gas of self-generation and self-preservation. The frontier depression areas of the paleo-uplift to the west, north and south of Jingbian gas field are the potential Ordovician exploration targets in the future.

The geochemistry and origin of lower Permian gas in the northwestern Sichuan basin, SW China

The lower Permian series in northwestern Sichuan basin of China is a favorable region for natural gas accumulation with several potential source rocks and high-quality reservoirs. However, the tectonic evolution in this area has gone through long-term and complicated activities and the origin of gases in the lower Permian series is complex. For the wise exploration strategies planning, the origin and accumulation of natural gas in lower Permian reservoir have been addressed. And the results reveal that: (1) Three sets of potential source rocks, including the mudstone of Lower Cambrian Qiongzhusi formation, Lower Silurian Longmaxi formation and the marine carbonate source rocks of Lower Permian, have been identified as the gas sources in Lower Permian reservoirs. (2) The gases mainly contain by hydrocarbon gases, with the ratio of C1/C2+ > 0.99, and the characteristics of carbon isotopes are various and several wells’ are reversed or close to reversed. The δ13C2 values of Hewanchang and Wujiaba gas fields are ranging from −33.35‰ to −36.34‰(PDB), similar to the production of sapropelic organic matter. The Shuangyushi and Kuangshanliang gas fields, with the δ13C2 values ranging from −28‰ to −30‰(PDB), are source mixed gas. And the δ13C2 values of Jiulongshan gas field are the heaviest with the value range from −25.23‰ to −28.4‰(PDB). (3) The biomarkers of reservoir extracts are consistent with those of the lower Permian source rock, but the bitumen scales in lower Permian are not as much as those in the lower Cambrian or Lower Silurian series, which reveals that the crude oil creaked gas formed in lower Permian series falls a great deal than that in Cambrian and Silurian series. Based on the comprehensive researches of natural gas composition, carbon isotope, biomarkers of extract and other parameters, the natural gases in lower Permian series are mixed by the crude oil creaked gas from deep formation and the lower Permian source rock, and the scale of fracture determines the amount of creaked gas mixed in the lower Permian reservoir.

Chemometric classification and geochemistry of oils in the Iranian sector of the southern Persian Gulf Basin

Crude oil samples collected from several oilfields across the southern Persian Gulf Basin from Jurassic to Cretaceous reservoirs were chemometrically classified into two genetically distinct oil families. Family A oils, occurring in the western areas, are restricted to the Jurassic series. Family B oils, mostly occurring in the eastern areas, were generated from a younger, homogeneous marine carbonate source rock. An improved geochemical understanding of Family A oils is achieved in this study, and a refined paleo-depositional model for their source rock is presented. These high-maturity oils were generated from a Middle Jurassic carbonate source rock formed within a shallow, anoxic intra-shelf basin that was connected to the Neo-Tethys marine environment. An initial phase of biodegradation is suggested to have affected family A oils during their initial accumulation phases, but the imprint has likely been masked with mixing of multiple charges or phase fractionation. Similarly, Family B oils appear to be controlled by mixing of at least two separate charges or phase-fractionation processes, although the trap charging dynamics of the Cretaceous accumulations agrees with a stronger probability for secondary alteration processes. Based on these findings, we conclude that the present-day geochemistry of both oil families is the result of a complicated sequence of events, including mixing of at least two separate charges with varying maturities or phase separation. These new insights can have practical implications for assessing volumetric mass balance relationships in advanced hydrocarbon generation models, identifying low-risk plays, and ranking prospects.

Fingerprinting of biomarker characteristics of some Egyptian crude oils in Northern Western Desert as evidence for organic matter input and maturity level assessment

This study describes the fingerprinting of crude oils from different Egyptian oil formations using gas chromatography (GC) and gas chromatography mass spectrometry (GC–MS). The samples were obtained from Gindi, Abu El gharadig, south deep Abu El gharadig, Dahab- Merier and Faghur basins from Western Desert. Diagnostic biomarkers parameters applied in this study provide evidences about the source of organic matter, the depositional environment and maturity of the studied oils. The results showed that the crude oils of Faghur basin are believed to be originated from mixed source predominately terrestrial with chief contribution of clastic rocks deposited under oxic conditions. However, the crude oils from Gindi, Abu El gharadig, South deep Abu El gharadig and Dahab- Merier basins were generated from marine carbonate source rock deposited under anoxic depositional environment.

Organic geochemistry characterisation of crude oils from Mishrif reservoir rocks in the southern Mesopotamian Basin, South Iraq: Implication for source input and paleoenvironmental conditions

Seven crude oils from Cretaceous Mishrif reservoir rocks in the southern Mesopotamian Basin, South Iraq were studied to describe oil characteristics, providing information on the source of organic matter input and the genetic link between oils and their potential source rock in the basin. This study is based on biomarker and non-biomarker analyses performed on oil samples. The analysed oils are aromatic intermediate oils as indicated by high aromatic hydrocarbon fractions with more that 50%. These oils are also characterized by high sulfur and trace metal (Ni, V) contents and relatively low API gravity values (19.0–27.2° API). The results of this study indicate that these oils were derived from a marine carbonate source rocks bearing Type II-S kerogen that were deposited under sulphate-reducing conditions. This is primary achieved from their biomarkers and bulk carbon isotope and inorganic element contents (i.e., S, Ni and V). The absence of 18a (H)-oleanane biomarker also suggests a source age older than Late Cretaceous. The biomarker characteristics of these oils are consistent with those of the Late Jurassic to Early Cretaceous source rocks in the basin. However, biomarker maturity data also indicate that the oils were generated from early maturity source rocks. This appears to result from the type of kerogen of the source rock, characterized by a high-S kerogen (Type II-S).

New knowledge of hydrocarbon generating theory of organic matter in Chinese marine carbonates

Abstract The marine carbonates of the Tarim Basin are taken to study the relationship between source rock and oil and gas reservoirs and discuss the possibility and mechanisms of mature and low-TOC (less than 0.5%) marine carbonates being source rock. By studying the matching relationship between source rocks in Tarim Basin and hydrocarbon reservoirs in Tahe oilfield and analyzing the hydrocarbon-generating organism combination and its correlation with geochemical characteristics of oil and gas reservoirs, this study established a method to evaluate hydrocarbon generation substance of marine carbonate source rocks. It is concluded that the crude oil of the Tahe oilfield in the Tarim Basin is not derived from muddy source rocks, but has the obvious characteristics derived from carbonate source rocks. It revealed that the underestimated hydrocarbon-generating substance (organic acid salts) in the highly evolved marine carbonate rocks and high quality hydrocarbon-generating organism are the key to high-evolution carbonate rocks being as source rock. Organic acid salts have high hydrocarbon conversion rate and are mainly cracked into natural gas at high temperature. The development model of the source rocks of the Cambrian-Lower Ordovician carbonate source rocks in the Tarim Basin is dominated by the shelf model.

Geochemical characteristics of crude oils dependent specific and biomarker distributions in the central-southern Gulf of Suez, Egypt

ABSTRACTSpecific geochemical analyses included API gravity, sulfur content, gas chromatography, and the advanced gas chromatography-mass spectrometry for biomarker distributions, in conjunction with stable carbon isotope geochemistry, to characterize the depositional environmental conditions and maturation assessment of the studied crude oils. For this purpose ten crude oils were collected from Miocene, Upper Cretaceous, and Nubia Sandstone representing the central-southern Gulf of Suez. The results showed that two different oil types identified as Miocene oils are characterized by a dominant oleanane and low gammacerane biomarkers, suggesting an overall angiosperm land plants input of terrigenous organofacies source rock. Pre-Miocene oils are distinguished by a dominant gammacerane and low oleanane biomarker distributions, which may be generated from fully mature marine carbonate source rocks. The higher sterane isomerization parameters, C29αßß/(αßß + ααα) and C29 ααα 20S/(S+R), further support the higher thermal maturation level for the Pre-Miocene oils rather than the Miocene type.

Origin of crude oils from oilfields in the Zagros Fold Belt, southern Iraq: Relation to organic matter input and paleoenvironmental conditions

Crude oil samples from Cretaceous and Tertiary reservoir sections in the Zagros Fold Belt oil fields, southern Iraq were investigated using non-biomarker and biomarker parameters. The results of this study have been used to assess source of organic matter, and the genetic link between oils and their potential source rocks in the basin. The oils are characterized by high sulphur and trace metal (Ni, V) contents and relatively low API gravity values (17.4–22.7° API). This indicates that these oils are heavy and generated from a marine source rock containing Type II-S kerogen. This is supported by their biomarker distributions of normal alkanes, regular isoprenoids, terpanes and steranes and the bulk carbon isotope compositions of their saturated and aromatic hydrocarbons. The oils are characterized by low Pr/Ph ratios (<1), high values of the C35 homohopane index and C31-22R/C30 hopane ratios, relatively high C27 sterane concentrations, and the predominance of C29-norhopane. These biomarkers suggest that the oils were generated predominantly from a marine carbonate source rock, deposited under reducing conditions and containing plankton/algal and microorganisms source input. The presence of gammacerane also suggests water column stratification during source rock deposition.The biomarker characteristics of the oils are consistent with those of the Middle Jurassic Sargelu carbonate as the effective source rock in the basin. Biomarker maturity data indicate that the oils were generated from early maturity source rocks.

Biomarker characteristics of oils from Garmian Oil Fields and potential Jurassic source rocks, Kurdistan,NE Iraq: implications for oil–oil and oil-source rocks correlation.

The Middle Jurassic Sargelu Formation in Sangaw North -1 (SwN-1) borehole, Sangaw&#x0D; North Block, Garmian area, Kurdistan region, was used for geochemical analyses. Two&#x0D; crude oils from PLK-8 and Sarqala-1 wells in Pulkhana and Sarqala oil fields, one&#x0D; condensate from KM-3 well in Kor Mor gas field and seepage oil from ChiaSurkh oil&#x0D; field were chosen for organic geochemistry investigation, oil-oil and oil-source rocks&#x0D; correlation. Tectonically, the study area is located in the southeastern part of the Foothill&#x0D; Zone in Zagros Fold Belt. The biomarkers ratios and molecular compound distributions &#x0D; showed that the oils, condensate and rock extracted sample of Sargelu Formation were derived&#x0D; from marine carbonate source rocks bearing marine algae and kerogen type II that deposited under&#x0D; reducing condition. Low presence of gammacerane indicated normal salinity condition&#x0D; during the depositions. The GC-FID traces of oils and condensate showed lack of any&#x0D; remarkable biodegradation, but rock-extracted of Sargelu Formations is strongly&#x0D; contaminated by polyethylene glycol according to the GC-FID chromatogram.&#x0D; Compositional similarity of sterane, hopane, isopernoid and n-alkane compounds among&#x0D; the crude oils and crude oils with extracted sample of Sargelu Formation suggested that&#x0D; the oils might be sourced from the same or similar source rocks that deposited under&#x0D; similar conditions. On the other hand, Sargelu Formation is supposed to be one of the&#x0D; sources of the generated crude oils. However, the maturity-related parameters showed no&#x0D; similarity between the crude oils and extracted sample of Sargelu Formation.