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Al-Ameri T.K.,University of Baghdad | Al-Temimi A.K.,University of Baghdad | Zumberge J.,GeoMark Research Ltd.
Marine and Petroleum Geology | Year: 2016

Bulk properties, stable carbon isotopes, whole crude Gas-Chromatography and oil mode ratios of sterane and terpanes data of analyzed samples of oil from the Cretaceous Formation reservoirs of East Baghdad oil field are from five producing wells (EB21, EB68, EB92, EB5 and EB31) from reservoirs of Zubair, Khasib, and Tanuma Formations. They are discussed with aids of characters, hopane, tricyclic terpane, isotopic δC13 saturate, aromatics, and pristine-phytane diagrams. The analized oil have indicated light and medium oil in the Zubair reservoirs and heavy oil for the Khasib and Tannuma oil, with about 15% asphalt and porpherine range of 16.7–35.1 Ni and 68–117 ppm, giant reservoirs. The oil source environment and lithology are of marine algal type II and deltaic type II/III that are non biodegraded deposited in anoxic environments of carbonate and shale. Source maturation at the time of the oil generation, aided by pristine-phytane and Tmax equivalent from MDR (Methyldibenzothiophene ratio) diagrams, are showing mature with Tmax 430–435 °C while source age assessment are taken from δC13 (%) and the calculated C28/C29 sterane ratio to be of Middle and Upper Jurassic as well as Lower Cretaceous age that could be correlated mainly with the Chia Gara and Zubair Formations as well as the Middle Jurassic Sargelu Formation source rocks for oil that are accumulated in the reservoirs of Zubair, Khasib and Tannumah Formations. Source rocks are mainly Upper Jurassic-Lower Cretaceous Chia Gara Formation with contribution from the Middle Jurassic Sargelu and Lower Cretaceous Zubair Formations. The richness of the source rocks, mostly due to shale rich in TOC, and the type of kerogen is mixed type II/III and type III. The formations have good petroleum potentiality (PP) and the OM reaches the Early of hydrocarbon generation. Oil, and gas are the most probable product, and the generated hydrocarbons can be expelled at this level of thermal maturity which is confirmed by petromod software basin modeling to suggest migration and accumulation during the Upper Cretaceous time. Hydrocarbon dynamic in East Baghdad Oil Field are performed using seismic section, logs and porosities. Model assessments of the hydrocarbon generation, migration paths and accumulation sites as well as places of enriched oil are used to assess reservoir location and suggestion for drilling sites. © 2016 Elsevier Ltd Source

Al-Ameri T.K.,University of Baghdad | Al-Mimar H.S.,University of Baghdad | Zumberge J.,GeoMark Research Ltd.
Arabian Journal of Geosciences | Year: 2015

Oil biomarkers and isotope values of the analyzed samples from the Sa’adi and Yamama Formation reservoirs of Santonian and Valanginian ages, respectively, from well Da-1 as well as Yamama Formation extracts are plotted on sterane triangle, hopane diagram, tricyclic terpane diagram, pristane to phytane ratio with canonian variables, δ13C saturate, aromatics, and pristine-phytane diagrams and have indicated a source environment and lithology of marine algal type II that are nonbiodegraded and deposited in anoxic environments of carbonate and shale. Source maturation at the time of the oil generation is assessed by plots of oil, and the analyzed values of the Yamama source rocks on the pristine-phytane diagram indicate these to be mature with Tmax equivalent of 435 °C based on plots of methyldibenzothiophene ratio (MDR) and vitrinite reflectance of Ro = 0.70–0.85 based on methylphenothrene ratio (MPI). Source age assessment is taken from δ13C (%) and the calculated C28/C29 sterane ratio indicates early Lower Cretaceous age. The Yamama Formation in this study showed excellent hydrocarbon potential with extracted organic matter of up to 16,674 ppm with a total organic carbon (TOC) equivalent of 16.64 wt%. Correlation of the analyzed data from Ad’daimah field with other oil fields in the Mesan Governorate indicates the same characteristics and revealed this to be clustered in one place in all the diagrams, but the source age shows two oil families where the first is sourced from Upper Jurassic-Lower Cretaceous as in the case in the Ad’daimah field while the second is sourced from Middle and Upper Jurassic as in the case in the Halfaya field. Source-oil correlation is confirmed in this study by plots of values from the analysis of Sa’adi and Yamama oil of well Da-1 with the extracts from the Yamama-Sulaiy formations in isotopic δ13C saturate and aromatics, calculated C28/C29 sterane ratio diagram, sterane triangle, and MPI versus Ro. These showed grouping of the oil and extracts of the analyzed data into one place of depositional environment, maturation, and age characteristics that indicate a very good correlation with excellent hydrocarbon generation from the Yamama Formation that measures up to 16,674 ppm of extracted organic matter. PetroMod software basin modeling has confirmed hydrocarbon generation from the Yamama Formation under burial thermal temperature of 114–120 °C with 285–300 mg HC/g TOC for 95 % hydrocarbon transformation from the disseminated organic matters with critical point of hydrocarbon migration and accumulation at 10 million years ago. Palynomorphs have indicated ages of Valanginan-Berriassian for the Yamama Formation and Tithonian-Berriassian for the Sulaiy Formation. Marking places of source rocks and oil reservoir on seismic section across well Da-1 for the Jurassic and Cretaceous strata have shown model assessments of the hydrocarbon generation places of the Yamama Formation, migration pathways and accumulation site, as well as places of enriched oil to assess reservoir sites and suggest for risk assessments of drilling sites for hydrocarbon production from the Yamama and Sa’adi formations. On the other hand, seismic sections in Halfaya and Buzargan fields showed hydrocarbon migration from the Sargelu Formation. © 2014, Saudi Society for Geosciences. Source

Kelly A.E.,Massachusetts Institute of Technology | Kelly A.E.,University of California at Riverside | Kelly A.E.,Arizona State University | Love G.D.,University of California at Riverside | And 2 more authors.
Organic Geochemistry | Year: 2011

The Neoproterozoic Era is of widespread geobiological interest because it marks the critical transition from a world of microbes to one where animals become an established feature of the landscape. Much research into this time period has focused on the ventilation of the oceans, as this is widely considered a primary factor driving the diversification of complex, multicellular life. In this study, Proterozoic to Cambrian aged oils from eastern Siberia were analyzed for their hydrocarbon biomarker contents and compound specific carbon isotopes in order to further our understanding of the prevailing environment and its microbial and metazoan communities. Geochemically, these oils are broadly comparable to those of the Ediacaran-Cambrian sedimentary rocks and oils of the South Oman Salt Basin. Organic matter in the source sedimentary rocks included significant contributions from green algae, demosponges and bacteria including cyanobacteria and methanotrophic proteobacteria. Although the ages of the Siberian oils and putative parent source rock intervals are poorly constrained, the geochemical similarities between the Ediacaran Oman Huqf and Nepa-Botuoba-Katanga family of Siberian oil samples are impressive, leading to the inference that their source rocks are coeval. On the other hand, oils from the Baykit High are distinctive, likely older and possibly of Cryogenian age. © 2011 Elsevier Ltd. Source

Al-Ameri T.K.,University of Baghdad | Pitman J.,U.S. Geological Survey | Naser M.E.,University of Baghdad | Zumberge J.,GeoMark Research Ltd. | Al-Haydari H.A.,University of Baghdad
Arabian Journal of Geosciences | Year: 2011

1D petroleum system modeling was performed on wells in each of four oil fields in South Iraq, Zubair (well Zb-47), Nahr Umr (well NR-9), West Qurna (well WQ-15 and 23), and Majnoon (well Mj-8). In each of these fields, deposition of the Zubair Formation was followed by continuous burial, reaching maximum temperatures of 100°C (equivalent to 0.70%Ro) at depths of 3,344–3,750 m of well Zb-47 and 3,081.5–3,420 m of well WQ- 15, 120°C (equivalent to 0.78%Ro) at depths of 3,353–3,645 m of well NR-9, and 3,391–3,691.5 m of well Mj-8. Generation of petroleum in the Zubair Formation began in the late Tertiary, 10 million years ago. At present day, modeled transformation ratios (TR) indicate that 65% TR of its generation potential has been reached in well Zb-47, 75% TR in well NR-9 and 55-85% TR in West Qurna oil field (wells WQ-15 and WQ-23) and up to 95% TR in well Mj-8, In contrast, younger source rocks are immature to early mature (<20% TR), whereas older source rocks are mature to overmature (100% TR). Comparison of these basin modeling results, in Basrah region, are performed with Kifle oil field in Hilla region of western Euphrates River whereas the Zubair Formation is immature within temperature range of 65–70°C (0.50%Ro equivalent) with up to 12% (TR=12%) hydrocarbon generation efficiency and hence poor generation could be assessed in this last location. The Zubair Formation was deposited in a deltaic environment and consists of interbedded shales and porous and permeable sandstones. In Basrah region, the shales have total organic carbon of 0.5–7.0 wt%, Tmax 430–470°C and hydrogen indices of up to 466 with S2=0.4–9.4 of kerogen type II & III and petroleum potential of 0.4–9.98 of good hydrocarbon generation, which is consistent with 55–95% hydrocarbon efficiency. These generated hydrocarbons had charged (in part) the Cretaceous and Tertiary reservoirs, especially the Zubair Formation itself, in the traps formed by Alpine collision that closed the Tethys Ocean between Arabian and Euracian Plates and developed folds in Mesopotamian Basin 15–10 million years ago. These traps are mainly stratigraphic facies of sandstones with the shale that formed during the deposition of the Zubair Formation in transgression and regression phases within the main structural folds of the Zubair, Nahr Umr, West Qurna and Majnoon Oil fields. Oil biomarkers of the Zubair Formation Reservoirs are showing source affinity with mixed oil from the Upper Jurassic and Lower Cretaceous strata, including Zubair Formation organic matters, based on presentation of GC and GC-MS results on diagrams of global petroleum systems. © Saudi Society for Geosciences 2010 Source

Al-Ameri T.K.,University of Baghdad | Zumberge J.,GeoMark Research Ltd.
Marine and Petroleum Geology | Year: 2012

Structured organic matters of the Palynomorphs of mainly dinoflagellate cysts are used in this study for dating the limestone, black shale, and marl of the Middle Jurassic (Bajocian-Bathonian) Sargelu Formation, Upper Jurassic (Upper Callovian - Lower Oxfordian) Naokelekan Formation, Upper Jurassic (Kimeridgian and Oxfordian) Gotnia and Barsarine Formations, and Upper Jurassic - Lower Cretaceous (Tithonian-Beriassian) Chia Gara source rock Formations while spore species of Cyathidites australis and Glechenidites senonicus are used for maturation assessments of this succession. Materials' used for this palynological study are 320 core and cutting samples of twelve oil wells and three outcrops in North Iraq. Terpane and sterane biomarker distributions, as well as stable isotope values, were determined for oils potential source rock extracts of Jurassic-Lower Cretaceous strata to determine valid oil-to-source rock correlations in North Iraq. Two subfamily carbonate oil types-one of Middle Jurassic age (Sargelu) carbonate rock and the other of mixed Upper Jurassic/Cretaceous age (Chia Gara) with Sargelu sources as well as a different oil family related to Triassic marls, were identified based on multivariate statistical analysis (HCA & PCA). Middle Jurassic subfamily A oils from Demir Dagh oil field correlate well with rich, marginally mature, Sargelu source rocks in well Mk-2 near the city of Baiji. In contrast, subfamily B oils have a greater proportion of C 28/C 29 steranes, indicating they were generated from Upper Jurassic/Lower Cretaceous carbonates such as those at Gillabat oil field north of Mansuriyah Lake. Oils from Gillabat field thus indicate a lower degree of correlation with the Sargelu source rocks than do oils from Demir Dagh field. Palynofacies assessments are performed for this studied succession by ternary kerogen plots of the phytoclast, amorphous organic matters, and palynomorphs. From the diagram of these plots and maturation analysis, it could be assessed that the formations of Chia Gara and Sargelu are both deposited in distal suboxic to anoxic basin and can be correlated with kerogens classified microscopically as Type A and Type B and chemically as Type II. The organic matter, comprised principally of brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminifera test linings, and phytoclasts in all these formations and hence affected with upwelling current. These deposit contain up to 18 wt% total organic matters that are capable to generate hydrocarbons within mature stage of thermal alteration index (TAI) range in Stalplin's scale (Staplin, 1969) of 2.7-3.0 for the Chia Gara Formation and 2.9-3.1 for the Sargelu Formation. Case study examples of these oil prone strata are; one 7-m (23-ft) thick section of the Sargelu Formation averages 44.2 mg HC/g S2 and 439 °C Tmax (Rock-Eval pyrolysis analyses) and 16 wt% TOC especially in well Mk-2 whereas, one 8-m (26-ft) thick section of the Chia Gara and 1-m (3-ft) section of Naokelekan Formations average 44.5 mg HC/g S2 and 440 °C Tmax and 14 wt% TOC especially in well Aj-8. One-dimension, petroleum system models of key wells using IES PetroMod Software can confirm their oil generation capability. These hydrocarbon type accumulation sites are illustrated in structural cross sections and maps in North Iraq. © 2012 Elsevier Ltd. Source

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