Arab J Geosci (2011) 4:915–932 DOI 10.1007/s12517-009-0115-4
ORIGINAL PAPER
Cretaceous petroleum system of the Khasib and Tannuma oil reservoir, East Baghdad oil field, Iraq Thamer Khazal Al-Ameri & Riyadh Y. Al-Obaydi
Received: 14 July 2009 / Accepted: 14 December 2009 / Published online: 27 January 2010 # Saudi Society for Geosciences 2010
Abstract Gas chromatography, palynomorph constituents, and maturation are analyzed for oil samples of the Campanian Khasib and Tannuma Formations in the wells of East Baghdad oil field for biomarker studies, while palynomorph constituents and their maturation, Rock Eval pyrolysis, total organic carbon (TOC) analysis are carried on for the Upper Jurassic and the Cretaceous Formations of core samples from the same wells for dating and evaluation of the source rocks. The gas chromatography of these oils have shown biomarkers of abundant ranges of n-alkanes of less than C22(C17–C21) with C19 and C18 peaks to suggest mainly liquid oil constituents of paraffinic hydrocarbons from marine algal source of restricted palaeoenvironments in the reservoir as well as low nonaromatic Cþ 15 peaks to indicate their slight degradation and water washing. Oil biomarkers of Pr :=Ph: ¼ 0:85;C31 =C30 1:0, location is in the triangle of C27–C29 sterane, C28/C29 of 0.6 sterane, oleanane of 0.01, and CPI = 1.0, could indicate anoxic marine environment with carbonate deposition of Upper Jurassic–Early Cretaceous source. The recorded palynomorph constituents in this oil and associated water are four miospore, seven dinoflagellates, and one Tasmanite species that could confirm affinity to the Upper most Jurassic– Lower Cretaceous Chia Gara and Ratawi Formations. The recorded palynomorphs from the reservoir oil (Khasib and Tannuma Formations) are of light brown color of TAI ¼
2:8 3:0 and comparable to the mature palynomorphs that belong to Chia Gara and Lower part of Ratawi Formations. Chia Gara Formation had generated and expelled high quantity of oil hydrocarbons according their TOC weight percent of 0.5–8.5 with S2 ¼ 2:5 18:5 mg Hc=g rock, high hydrogen index of the range 150–450 mg Hc/g Rock, good petroleum potential of 4.5–23.5 mg Hc/g rock, mature (TAI ¼ 2:8 3:0 and T max ¼ 428 443C), kerogen type II, and palynofacies parameters of up to 100 amorphous organic matters with algae deposited in dysoxic–anoxic to suboxic–anoxic basin, while the palynomorphs of the rocks of Khasib Formation are of amber yellow color of TAI = 2.0 with low TOC and hence not generated hydrocarbons. But, this last formation could be considered as oil reservoir only according their high porosity (15–23%) and permeability (20–45 mD) carbonate rocks with structural anticline closure trending NW-SE. That oil have generated and expelled during two phases; the first is during Early Palaeogene that accumulated in traps of the Cretaceous structural deformation, while the second is during Late Neogene’s. Keywords Oil field . Cretaceous . Palynomorphs and palynofacies . Petroleum system . Biomarkers . PetroMod software
Introduction T. K. Al-Ameri Department of Geology, College of Science, University of Baghdad, P.O. Box 47062, Jadiriyah, Iraq R. Y. Al-Obaydi (*) College of Sciences for Women, University of Baghdad, Jadiriyah, Iraq e-mail:
[email protected]
This study is based on the assumption that palynomorphs of spores, pollen, acritarchs and dinoflagellates, as well as alkane peaks of organic remnant (biomarkers) measured on chromatogram of gas chromatography (GC) and gas chromatography–mass spectrometry (GC-MS) might resist geological processes in the oil generation within the kerogen and become a part of oil components (Medvedeva
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and Klimushina 1987, Kumar 1981) for palynomorphs and Whelan et al. (1993), Cole et al. (1994), Hunt (1996), and Peters et al. (2005) for oil biomarkers. In this scenario, these constituents could be migrated within the oil and becoming oil biomarkers in the reservoir rocks, and hence the migration pathways of oil from the kerogen of the source rocks to the oil of the reservoir rocks might be predicted. Such phenomena can give help in oil exploration strategies. And hence, additional hydrocarbon traps could be suggested in the field of exploration according the basin parameters. To apply this idea on a developing oil field for predicting additional traps, the oil of the Upper Cretaceous, Khasib and Tannuma formation reservoirs, and Jurassic–Lower Cretaceous source rocks of wells in East Baghdad (EB) oil field (Fig. 1) are selected for this study. These reservoirs (Khasib and Tannuma) are characterized by tight limestone–wackstones which were fractured to variable degrees. However, they have low porosities and high permeability.
Fig. 1 Location map of Iraq showing a northeast Arabian Peninsula of the region Iraq with locations of basins and oil fields and b central Iraq and neighboring Iran with locations of the wells on which this study is based
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East Baghdad oil field is part of the Arabian Basin in a regional extent and specifically within Mesopotamian Fore deep Basin. Locating this studied area in the Arabian Peninsula Basins map prepared by the U.S. Geological Survey (Pollastro et al. 1999) with special emphasis on Iraqi region of northeastern Arabian Peninsula (Fig. 1a), East Baghdad oil field could be grading tectonically northeastward toward the Zagross Fold Belt and westward toward the boundary with the Widian Basin of Interior Platform while its southward extensions is the Mesopotamian Fore deep Basin that contain deposits of the Tethys Ocean during the Jurassic and Cretaceous Periods. That ocean were of mainly dysoxic– anoxic palaeoenvironments along the equator and of tectonically unrest (Sharland et al. 2001) that permitted preservation of high organic matters and development of highest world oil and gas reserve in the Arabian Region. The generalized lithostratigraphic section constitutes marine and subordinate lagoon beds deposited in the
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Fig. 1 (continued)
southern Tethys Ocean as sediment of carbonates, shales, and anhydrites on a geologic time extending through the Jurassic, Cretaceous, and Palaeogene up to the Middle Miocene Lower Fars (Fatha) Anhydrite (Fig. 2), with gentle folding, as graben–horst structural system of 100 km long and extending NW-SE of Baghdad Urban area and with normal faults (Al-Magid 1992). The outcrops cover Pliocene, Pleistocene, and recent sediments that extend between well EB-2 southwestern Baghdad and well EB-57 northwestern Baghdad (Fig. 1b). In order to study a complete petroleum system of hydrocarbon generation, migration, and accumulation by organic geochemical analysis with no mixing from oil of underlying and overlying strata, it is attempted to start from the lowest seal rocks of regional extent in a lithostratigraphic section up to the highest seal rock of regional extent to restrict the vertical limits of the hydrocarbon dynamics, while the graben–horst structural system is the limiting factor of probable lateral dynamicity of the generated hydrocarbons. This stratigraphic framework is the system for the
occurrence of both of the kerogen generating oil from the source rocks and oil traps for the generated oil, migrated, and hence accumulated in reservoir rocks. Such stratigraphic seals in East Baghdad oil field could be based on lithostratigraphic sections of Van Bellen et al. 1959; Sharland et al. 2001 and well sites descriptions of the studied wells. These could be illustrated in Fig. 2 and represented by: 1- Upper regional seal of Middle Miocene Lower Fars Formation of nonpermeable anhydrite lithology, of 400 m thick, comprise highest seal for stopping the vertical migration of the oil, while some may seep to the ground surface through its fractures. 2- Lower regional seal of Upper Jurassic Kimmeridgian Gotnia Anhydrites, of nonpermeable 80 m thick, comprise lowest seal to prevent mixing hydrocarbon supply from the Jurassic source rocks to some extent with our Cretaceous and Cenozoic petroleum system. This study is aimed for oil-source rock correlation, predicting migration pathways within East Baghdad oil
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Fig. 2 Stratigraphic column of East Baghdad Oil Field with hydrocarbon generation parameters and seal within the total petroleum system of this field
field and suggestion for hydrocarbon traps as well as organic geochemical studies of the kerogen of the Lower Cretaceous source rocks and oil of the Khasib and Tannuma formation reservoirs.
Material and methods This article is based on core and cutting samples from mainly shale and limestone of Jurassic Late Bathonian–Early
Callovian Sargelo Formation up to Lower Cretaceous–Lower Cenomanian Maudud Formation from selected oil wells in East Baghdad oil field (Fig. 1b). Collected rock sample locations (Fig. 3) are 86 samples from well EB-1 of depths 3,315–4,842 m, 13 samples from well EB-2 of depths 3,342–3,925 m, 16 samples from borehole EB-3 of depths 3,143–3,635.5 m, ten samples from well EB-57 of depths 2,274–3,253 m, six samples from well EB-11 of depths 2,935–2,943 m, and 18 samples from well EB-80 of depths 2,632–2,790 m. Crude oil samples are collected
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Fig. 3 Lithostratigraphic correlation diagram of the proposed source rocks for the total petroleum system in East Baghdad Oil Field with stratigraphic locations of rock samples
from each of Campanian Khasib Formation oil reservoir of well EB-31 (and EB-62) depth 7,689 ft and Tannuma Formation oil reservoir of well EB-51 (and EB-11) depth 7,903 ft. Determination of total organic carbon (TOC), Rock Eval pyrolysis for the kerogen type, and organic maturation were based on the same rock samples and analyzed in the laboratories of the National Iraqi Oil Exploration Company at 1999; gas chromatography (GC) and gas chromatography–mass spectrometry (GC-MS) analysis are done in Geomark Research Ltd. in Houston, TX, USA at 2008; and palynomorph extraction are done for the crude oil in the Geochemical Laboratory of the Department of Geology in Baghdad University at 1999. Standard palynological processing techniques were used to extract the acidresistant organic matter from the rock samples, especially
the source rocks in the Palynological Laboratory of the Department of Geology, College of Science, University of Baghdad at 1999 and hence stored in the same place.
Hydrocarbon generation assessments Source rocks parameters of: (1) Quantity of organic matters by TOC analysis; (2) Types of organic matter by pyrolysate examination through Van Krevelen diagram and palynofacies types; and (3) Maturation of the organic matter by the same pyrolysate examination and by thermal alteration indices based on color changes scale of Staplin (1969; for comparison with other scales, see Batten 1996b), are performed by kerogen analyses, in all of the core and cutting samples collected from boreholes EB-1, EB-2, EB-3, and EB-
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57 for Chia Gara up to the Shuaiba Formations and boreholes EB-80, EB-11, and EB-4 for Nahr Umr and Maudud Formations. Results of these analyses are partly plotted on Fig. 2 and hence the mature source rocks with possible oil and wet gas generation could be assessed from parts of the Chia Gara, Ratawi, Zubair, and probably, Shuaiba Formations. Chemical analysis TOC analysis in weight percentages indicate that rocks of Shuaiba Formation is poor quantity of organic matter while rocks of Zubair Formation are of 80% intermediate, 6% rich, and 14% very rich with TOC of up to 4.7 wt.% of the source rocks, Ratawi Formation rocks are of 61% poor, 31% intermediate, and 8% rich with TOC of up to 1.5 wt.%, and rocks of Chia Gara Formation are of 40% rich and 60% very rich with TOC of up to 8.5 wt.%. Another tool for determining the organic richness of source rocks is the pyrolysate extracts of S1 and S2 (kilogram of hydrocarbons per ton of rocks) which determine the rock ability to generate hydrocarbons in a petroleum potential (PP) contest. Plotting the analysis of PP (S1 +S2) with TOC content from this study on Tissot and Welte (1984) diagram (Fig. 4b) could indicate that the highest hydrocarbon generation is Chia Gara Formation as a source rocks, with mainly very
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high total organic carbon content of 1.0 to 8.5 wt.% and good petroleum potential of 4–28 kg HC/ton rocks. On the other hand, plotting the pyrolysis analysis of the studied boreholes determined in hydrogen index (S2/TOC= mg Hydrocarbon/g Corg.) with maximum temperature for hydrocarbon pulse in the pyrolysis devise (Tmax; 1980) and Van Krevelen diagram of Espitalie et al. (1980; Fig. 4a) for borehole EB-1 (as a representative) could indicate that Chia Gara Formation is a source rocks of kerogen type II and of mature organic matter content with 430–450 C Tmax and hydrogen index (HI) of up to 450 mg HC/g rocks, while rocks of Ratawi and Zubair Formations are of Kerogen type II and III and mainly immature organic matter with 420–435 C Tmax and HI of up to 250 mg HC/g rocks. Therefore, it is most appropriate to suggest from this diagram that Chia Gara Formation could indicate the highest hydrocarbon generation. Palynofacies Four principal types of palynofacies (PF1–4), with secondary palynofacies types of four for PF1 and two for each of PF2–4, have been recognized in the palynological preparations analyzed from the Jurassic and Lower Cretaceous succession in boreholes of East Baghdad oil field. These are
Fig. 4 Hydrocarbon generation potential of the proposed source rocks based on pyrolysis on a Van Krevlen diagram and b potential diagram
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following the procedures of Al-Ameri et al. (2001) who based the palynofacies identification on the occurrences of relative frequencies of the four categories of palynological matter that were distinguished by Bujack et al. (1977), namely amorphogen (amorphous organic matter, AOM), hylogen (macrophyte plant debris; phytoclast in part), melanogen (wood), and phyrogen (palynomorphs, structured organic matters) and their ability to generate hydrocarbons with increasing maturation (Fig. 5). The relative proportions of components of the palynomorphs assemblages were also taken into consideration (of Al-Ameri 1983; Firth 1993; Waterhouse 1995). Maturation assessments for the palynofacies types of this study are based on the spore species Gleichenidites senonicus (Fig. 6) according to thermal maturation index of Staplin (1969; for comparison with other scales, see Batten 1996b). These spores showed long range of extent from the Upper Jurassic strata of the Chia Gara Formation to the late Upper Cretaceous of the Shiranish Formation. For well EB-1 as a case study, depths of shallower than 3,500 m constituting upper part of the Zubair Formation and upward, are of yellow color G. senonicus spore with TAI=2.0 equivalent to vitrinite reflectance of Ro ¼ 0:3 indicating immature organic matter constituent while lower part of Zubair Formation and part of Ratawi Formation are of orange color with TAI ¼ 2:0 2:5 equivalent to Ro ¼ 0:3 0:5 indicating transitional organic matter constituents.
Fig. 5 Palynofacies scheme of hydrocarbon generations in well EB-1
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Lower part of Berriasian Ratawi and the Tithonian Chia Gara Formations, with depths of 4,300 m down to the lowest regional seal of Gotnia Formation, are constituting mature organic matter of dark orange and light brown with TAI ¼ 2:7 3:0 and TOC ¼ 1:0 8:5 wt:%. Accordingly, Chia Gara Formation coincides with oil generation zone. Diagrammatic presentation of these palynofacies in succession in every studied borehole (Fig. 5, as representative for borehole EB-1), along with palaeoenvironments according to inshore index based on proportions of continental derived spores and pollen to marine inhibitor dinoflagellate cysts, maturation based on spore coloration of Stalin’s scale correlatable with vitrinite reflectance (Ro), and values of total organic carbon, could delineate the hydrocarbon generation potential for each depth. The only succession taken into consideration is strata above the lowest regional seal of Gotnia Anhydrites Formation which could prevent oil generated from Jurassic Formation to be mixed with the Cretaceous–Tertiary total petroleum system of this locality. According these assumptions, the most appropriate palynofacies for the hydrocarbon generation is PF3B of the Chia Gara Formation and lowest part of Ratawi Formation. This palynofacies comprise 50–80% AOM, 5–10% phyrogen, 5–10% hylogen, and 5–30% melanogen and hence up-graded the organic matter to high degradation to achieve overwhelming amorphous organic
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belong to palaeoenvironments of the deltaic marine equivalence to southern Iraq (Al-Ameri and Batten 1997) but of immature organic matter to transitional mature organic matter with no hydrocarbon generation in East Baghdad.
Fig. 6 Thermal maturation scheme with depths for the spore species Gleichenidites senonicus in well EB-1
matter leading to hydrocarbon generation. The palynomorphs constituents of PF3B are generally well preserved with dominance of marine algal dinoflagellate cysts up to 75% (63% average) such as Areosphaeridium sp., Apteodinium sp., Callaiosphaeridium assymetricum, Chlamydophorella nyel, Comparadinium cossinium, Cribroperidinium edwardsii, Coryphantha longicornis, Ctenidodenium sp., Cyclonephelium distinctum, Exocosphaeridium phragmites, Lithodinia jurassica, Subtilisphaera perlucida, Solea senegalensis, Oligosphaeridium complex, Svalbardella cooksoniae, Rhynchodiniopsis gongylos, and foraminiferal test linings, fungi, and algae of the genus Tasmanites of up to 30% of the palynomorph constituents which yield some hydrocarbon constituents into their cystine and could be considered highly oil prone (Tyson 1995). The deposits with which this palynofacies is associated are predominantly limestone with subordinate marl, shale, and dolomites as well as disseminated pyrite crystals to indicate deposition in restricted marine palaeoenvironment (Tyson 1995). This palynofacies have been recorded mainly from the deeper drilled exploratory borehole EB-1, depth 4,360–4,477 m of the lower part of Ratawi Formation and the Chia Gara Formation (of mature organic matter). The subordinate levels within Zubair Formation in EB-1 depths 3,340 and 3,550 m and EB-3 depths 3,587 and 3,635 m
Chia Garan phase of hydrocarbon generation and expulsion It is evident from the chemical and palynological analysis of the kerogen of Chia Gara up to Maudud Formations that the main phase of oil generation and expulsion is the PF3B-Chia Gara Formation. Palaeoenvironments of Chia Gara Formation are predominantly dysoxic–anoxic and suboxic–anoxic environments, evidenced by graphical presentation of ternary kerogen plots following Tyson (1995) and Al-Ameri et al. (1999) based on phytoclast, palynomorphs, and AOM with upwelling currents based on abundant foraminifera. Accordingly, the accumulated sediments of the Chia Gara Formation were conductive to the preservation of much organic matter, although most has been biodegraded. These organic matters reached a total organic carbon of 0.5–8.5 wt.% for the majority of samples analyzed. The mean by which the degradation of the Chia Gara Formation organic matters took place is partly implied by the common occurrence of fungal remains along with an inferred bacterial component. The activities of these organisms would have been responsible for the formation of abundant AOM that may reach up to 100%. This material is similar in composition to oil-prone kerogen type A of Thompson and Dembicki (1986) and the mesoliptinites of Rahman and Kinghorn (1994, cf discussion of terminology in Batten 1996a). Rock Eval pyrolysis demonstrated mainly kerogen type II and an oil extraction range (S2) of 2.5–18.5 mg of hydrocarbons per gram of rocks with PP of 4.5–23.5 mg hydrocarbons per gram of rocks. The organic matter is mature, the thermal alteration index (TAI) being 2.8–3.0 (Staplin 1969; for comparisons with other scales, see Batten 1996b) with Tmax values by pyrolysis analysis are 428–443°C and hence capable of generating liquid hydrocarbons. This oil is separated from the Jurassic oil by the regional seal of Gotnia Anhydrite, and hence there is no possible mixing of the oil of the Jurassic with the oil of the Cretaceous source and reservoir rocks with some exception of faults in places. The evidences for oil expulsion to commence oil migration from Chia Gara source rocks to the traps of the reservoir, such as the Khasib and Tannuma Formations are the following: 1- Increasing measurements of pristain to phytain isoprenoid ratio in the analyzed samples of the studied source rocks to more than 1.0 (according to Galimov et al. 1980). 2- Increasing migration index (S1/TOC) to 0.5–0.9 in the samples analyzed for Chia Gara Formation (0.2 could
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3-
4-
5-
6-
indicate commencement of migration according to Smith 1994). Increasing deposit overpressure in Chia Gara Formation to values more than the ordinary hydrostic pressure of the formation (following Hunt 1996). Increasing values of electrical resistivity logs in the wells within depths of Chia Gara Formation to more than 50 Ω-m (following Durand 1983). Presence of micro fractures in the strata of Chia Gara Formation to indicate the high pore pressure as a result from the first gas generation (following Bordenave 1993). Increasing quantity of generated hydrocarbons especially in the main phase of hydrocarbon generation (PP= more than 5 mg HC/g rocks) in the Chia Gara Formation to 4.5–23.5 mg hydrocarbon per gram of rock (following Tissot and Welte (1984) and Hunt (1996) who indicated more than 5 mg HC/g rocks).
Oil of the Khasib and Tannuma formation reservoirs Correlation of the oil from the reservoir with the Kerogen of the source rocks could be based on the analysis of the constituent present in both oil and kerogen. Oil analysis that that could help in such correlation are palynomorphs in microscopic views (following Kumar 1981, Medvedeva et al. 1987) and alkanes abundance revealed by gas chromatography (following Hunt 1996), as well as biomarkers (following Seifer 1977; Palacas 1984; Matavelli and Novelli 1990 and Peters et al. 2005) and the trace elements (viz sulfur, nickel, and vanadium). These constituents could be used for predicting the palaeoenvironments of the source rocks and resistant enough (during oil generation) to flow with the oil from the source rocks to the reservoir rocks. Palynomorph constituents of Khasib’s oil The palynomorph assemblages isolated from the oil samples taken from Middle Cretaceous Khasib Formation Reservoir contain some spores and dinoflagellate cysts with Tasmanites (Fig. 7). Palynological techniques for isolating these palynomorphs are subjecting the crude oil to boiling in order to eliminate the heavy materials as a residue and in carbon disulfides to dissolve the asphaltines, as well as dissolution in organic solvent such as ethyl alcohol, acetone, benzene, and kerosene. These followed by sieving with 20 μm nylon mesh and stacked on slides by cellusize and Canada balsam to make them ready for microscopic studies. The recorded palynomorphs from these analyses are algae, phytoclast, spores, and dinoflagellate cysts that are used for stratigraphic delineation according to a comparison
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with palynological record from the kerogen of the source rocks in this oil field: 1- Gleicheniidites senonicus is spore species that have been recorded from the whole succession of the upper Jurassic and the Cretaceous and hence have no stratigraphic value for this study. 2- Gleicheniidites sp. is spore species that have been recorded from Barremian to Cenomanian stages. 3- Concavissimisporites variverrucatus is spore species that have been recorded from Berriasian to Aptian stages. 4- Spore sp. 1 recorded from Tithonian to Berriasian stages. 5- Circulodinium distinctum is a dinoflagellate species of proximochorate cyst that have been recorded from Berriasian to Albian stages. 6- Subtilisphaera perlucida is a dinoflagellate species of cavate cyst that have been recorded from Tithonian to Alnian stages. 7- Subtilisphaera senegalensis is a dinoflagellate species of cavate cysts that have been recorded from Tithonian to Aptian stages. 8- Oligosphaeridium complex is a dinoflagellate species of chorate cyst that have been recorded from Tithonian to Aptian stages. 9- Oligosphaeridium pulcherrimum is a dinoflagellate species of chorate cyst that have been recorded from Berriasian to Albian stages. 10- Dinoflagellate sp. 3 is a dinoflagellate species of proximochorate cyst that have been recorded from the Tithonian stage. 11- Circulodinium cf inconspicuum is a dinoflagellate species of proximochorate cyst that have been recorded from the Berriasian to Albian stages. 12- Tasmanites sp. is of algal affinity that has been recorded from the Tithonian stage.
According to these palynomorph species, it is evident that the main palynomorph constituents of the oil belong to older strata of the source rocks lying above the Gotnia Anhydrites seal. These palynomorphs could be assigned stratigraphically to the Tithonian and Berriasian stages by correlation with references of Al-Ameri et al. (1999), Davey (1979), Miliod et al. (1975), and Traverse (2008). These palynomorph are similar in East Baghdad oil field to palynomorphs recorded in this study from rocks of Chia Gara Formation. The palynomorphs of younger ages such as Gleichenidites sp. could have been picked by the migrated oil from the younger immature strata. These palynomorphs have resisted degradation during oil generation and hence migrated with the oil to the oil reservoir of Khasib Formation.
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Fig. 7 Oil palynomorphs of Campanian Khasib and Tannuma Formations comparable to Berriasian–Hauterivian age
Gas chromatography–mass spectrometry oil analysis Analysis of the bulk oil properties, stable isotopes composition, whole crude GC, and Terpanes of mz = 191 amu and steranes of mz=amu biomarkers by GC-MS are done in this study for the Khasib Formation oil of well EB-31 (and EB62) depth 7,689 ft and Tannuma Formation oil of well EB51 (and EB-11) depth 7,903 ft. Graphical presentations of these data and charts of their analysis are illustrated in Fig. 8a–d. Peaks of the resultant chart from these analyses show organic remain that have little or no change from their parent organic molecules in living organisms (Hunt 1996,
Philp 2003, and Peters et al. 2005) and hence they could have persisted in petroleum, rocks, and sediments as biomarkers that include pristane, phytane, steranem triterpane, and porpherins. Accordingly, affinities of these peaks could be evaluated to find correlation of the oil with the kerogen of the source rocks. These correlations could be possessed into source environments, source age, and source maturation. 1) Source environment: The recorded peaks in the analyzed oil samples of this study are the alkanes C17–C21 that correlate with organic matters of marine
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Fig. 8 Biomarker diagrams of Khasib and Tannuma Formations oil in East Baghdad Oil Field. a Sterane triangle with green dot is the plot position of this study. b Tricyclic terpane plot of global source environment and lithology with purple dots for the oil of wells EB-31 and EB-05. c Age-related biomarkers, red ranges are the extent in this study. d Geomark Research, Ltd. charts of the performed oil analysis for boreholes EB-5 and EB-31
algal sources of restricted palaeoenvironment of the kerogen formations in the Chia Gara source rocks that have generated the oil, and among these are C18–C19 that confirm the lipid occurrence from the algal sources. Anoxic marine environment of mixed carbonate and shale could be assessed accordingly in comparison with Peters et al. (2005) by the values of API ¼ 17:5 20:5, Pristane=Phytane ¼ 0:8 0:9, Phytane= nC8 ¼ 0:34 0:38, Saturate= Aromatic ¼ 0:35 0:9, hopane index pc C31 R=H ¼ 0:36 0:38, and low trisnohopane C27 Ts/Tm.
could indicate marine carbonates by comparison with global standard environments of Peters et al. (2005).
Plots of steranes C27, C28, C29 values of Khasib’s oil on sterane triangle (Fig. 8a) and plot of tricyclic terpane ratio of 0.90–0.91 C22/C21 versus 0.30–0.31 C24/C23 (Fig. 8b)
Plots of the value of tricyclic terpanes of very low value, Oleanane of less than 20%, and C28/C29 of about 0.7 on age-related biomarkers scheme (Fig. 8c) of Peters et al.
2) Source age: The basis for suggesting age to the kerogen that formed the Khasib and Tannuma Formations oil are the oil values of C28/C29 Sterane ¼ 0:6 0:7, oleanane C30=0.1, the stable carbon isotopes of δ¹³C (‰) of C15 þ Saturate 27:58, C15 þ Aromatic 27:85 and Canonian variable −3.7 and the palynomorphs of the oil. Accordingly, Upper Jurassic to Lower Cretaceous age could be assessed with affinity to Chia Gara Formation with Tithonian–Berriasian ages.
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Fig. 8 (continued)
(2005) could confirm age of Upper Jurassic and Lower Cretaceous ages for the kerogen that formed the oil. 3) Source maturation: Oil alkanes that gave calculated CPI of 0.95–1.15 and low trisnorhopane C27 Ts/Tm of 0.16–0.17 and C29 Ts/Tm of 0.08 that could assess kerogen source of low mature level while thermal alteration index (TAI) of the oil palynomorphs (Fig. 7) of 2.8 (Staplin’s scale) could assess comparable maturation character to Chia Gara Formation during hydrocarbon generation. Accordingly, Chia Gara Formation could have been the main source rocks for the hydrocarbons accumulated in Khasib and Tannuma Formations.
Trapped oil along the migration pathway The analysis of oil-source correlation for the recorded oil accumulation in Khasib and Tannuma Reservoirs could lead to the direction of the migration pathway, especially with aid of seismic section (Fig. 8) or any subsurface structural section of the basin. Chia Gara Formation hold kerogen source for the oil It is evident now from our palynological and gas chromatographic analysis of the kerogen of Chia Gara, Ratawi,
Zubair, Shuaiba, and Nahr Umr Formations (of probable source rocks) and the kerogen and oil of the Khasib and Tannuma Formation reservoir rocks that “the kerogen of Chia Gara Formation and Lower part of Ratawi Formation is the source for Khasib and Tannuma’s oil.” Evidences for this are the following: 1- Tithonian–Berriasian age of the palynomorphs extracted from Khasib’s oil and Chia Garan kerogen (Fig. 7), which could be confirmed by C28/C29 sterane biomarker of the oil (Fig. 8b). 2- Carbonate deposits of Chia Gara Formation are showing by sterane and hopane biomarkers from Khasib’s oil (Fig. 8a). 3- Restricted marine environments for both of the kerogen of Chia Gara Formation and the oil of the Khasib Formation. 4- The high total organic carbon ðTOC ¼ 0:5 8:5 wt:%Þ of Chia Garan kerogen and of mainly algal marine affinity for both of the kerogen of Chia Gara Formation and oil of the Khasib Formation. 5- Mature organic matter of TAI ¼ 0:8 3:0 for both of the Chia Garan kerogen (Fig. 4) and Khasib and Tannuma’s oil with 9.5–1.1 CPI for the oil. 6- Chromatogram peaks of C18 and C19 of dimethyl cyclopentane hydrocarbons for the kerogen of Chia Gara Formation and the oil of Khasib Formation.
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Fig. 8 (continued)
PetroMod software for timing hydrocarbon generation and accumulations 1D petroleum system modeling (following Pitman et al. 2004) was performed on deep well EB-1, southern part of East Baghdad Oil Field for Chia Gara Formation to find timing of hydrocarbon events. This program could be based on formation depths and ages, erosion ages, TOC, source rock kinetics, initial hydrogen index, and well temperatures. The deposition of Chia Gara Formation was followed by continuous burial, reaching maximum temperature of 120–140°C (Fig. 9a) at depths 4,430–4,569 m and possessed 95% transformation ratio of its organic matters to hydrocarbons which indicates completed oil generation (Fig. 9b) while the overlying upper part of Ratawi Formation and Zubair Formation has only 50% of their organic matters had transformed to hydrocarbons at temperature range of 100–120°C. Higher in succession in Maudud and Nahr Umr Formations, only 1.0% had transformed to hydrocarbons which could be considered equivalent to no generation.
Generation of petroleum in the Chia Gara begun in the Upper Cretaceous time 100 million years ago and completed 100% of its efficiency in the Lower Tertiary (Late Eocene) time 40 million years ago taken from transformation ratios curve (Fig. 9c). Trap formation is taken from the abrupt subsidence line in burial thermal history during the Upper Cetaceous time at 70 million years ago (Fig. 9a), which conform to the Global Cretaceous/Tertiary Event of its effect on the Arabian Plate (Sharland et al. 2001), while the second phase of traps formation could be based on abrupt change in the thermal subsidence line during the Miocene time at 10 million years ago and which conform with the closing phase of the Alpine Orogeny effect on northeast Arabian Plate. These generated and expelled hydrocarbons had possessed vertical migrations along faults (Fig. 10) and compression joints in the anticline crest. They had charged the already formed traps of the Middle Cretaceous (Cenomanian) Khasib and Tannuma Formations that formed during the Upper Cretaceous time by the mecha-
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Fig. 9 Timing of hydrocarbon generation and accumulations of East Baghdad Oil Field, well EB-1 based on 1D PetroMod software program. a Thermal history of the basin in Baghdad Oil Field. b Hydrocarbon transformation ratios. c Timing of hydrocarbon generation
nism of basement movements in preexisted trends as response to thick sediment accumulations in the Mesopotamian Basin and the global cratonic reaction to plate collision (Al-Sharhan and Nairn 1997 and Sharland et al. 2001). Accordingly, these traps are mainly structural. Migration pathways Plotting localities of the Chia Gara Formation source rocks and Khasib and Tannuma Formation reservoir rocks on the seismic section led us to the predicted lines of migration pathways (Fig. 11). These are secondary lateral migration of the expelled hydrocarbon along the permeable calcareous sandy and shale beds interlayer within Chia Gara Formation to the zone of the normal faults to complete the migration but in vertical passageway and hence arrived to the Khasib and Tanuuma Formation anticline traps to fill their closures in vertical distance and lateral extension from the highest point or crest to the spill plane, that is, the level at which the oil spills below the trap into adjacent permeable bed. The
dismigration could compliment the pathways along tensional joints until their vertical migration have been stopped in the Lower Fars Anhydrite seal of regional extent. Accordingly, and along the proximity to hydrocarbon migration pathways, it could be suggested that the oil trapped by local subsidiary seal to form local reservoirs of the following pays: 1- Stratigraphic traps as lenses of fractured calcareous shale of Chia Gara (Albeyati 1998) and Ratawi Formations. 2- Structural fault traps for Shuaiba and Ahmedi Formations sealed in situ secondary filling of the fractured area along the faults by calcareous material. 3- Structural trap of Khasib Formation with a major low height and wide anticline closure of limestone characterized by (according to Al-Gailani 1996) average porosity of 15% and average permeability of 45 mD.
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Fig. 9 (continued)
4- Dismigration pathways from Khasib Formation along the tension joints on the crest of the anticline have formed the oil accumulation at younger pays such as Tannuma, Hartha, and Lower Fars Formation reservoir rocks until the vertical migration is stopped by the major anhydrite seal of the Lower Fars Formation. Crude oil composition and products Both crude oils of Khasib and Tannuma Formations reservoirs are nonbiode-
graded, evidenced by correlating shapes of the whole crude gas chromatography with Peters et al. (2005). The bulk properties of the accumulated crude oil in the Khasib Formation reservoir indicated from C15+ composition and whole crude gas chromatography (Fig. 10a) of the oils of well EB-51 from depths 2,395–2,410 m are heavy oil of 17.4 API and mainly C12–C23 with abundant aromatic materials (44.6%) and less saturates (22.0%) of mainly paraffinic and naphthenic hydrocarbons with ratio of
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Fig. 10 Whole crude gas chromatography of the oils in a Khasib Formation of well EB-51 depth 2,395–2,401 m and b Tannuma Formation of well EB-31 depths 2,325–2,335 m with suggested distillates
n Paraffin=Naphthene ¼ 0:69. The heavy compounds are of 15.8% NSO and 17.6% asphaltenes with wax. Hence, the main distillated hydrocarbons from this crude oil, accordingly correlating our analysis with Hunt (1996), are kerosen (C11–C13), diesel fuel (C14–C18), heavy gas oil (C19–C25), and subsidiary lubricating oil (C25–C40).
On the other hand, the oil dissipated and accumulated in Tannuma Formation reservoir immediately above the Khasib Formation is lighter oil than the Khasib’s crude oil. The whole crude gas chromatography (Fig. 10b) of the oil of well EB-31 from depths 2,325-2,325 m is of 18.8 API which contain light alkanes of C4–C12 as well as the
Fig. 11 Seismic cross section played with hydrocarbon source, reservoir, and seal rock units in East Baghdad Oil Field. Double lines arrow indicate directions of migration pathways while F1 and F2 are normal faults
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ordinary alkanes of C12–C23 which overwhelmed the Khasib’s crude oil. This Tannuma’s crude oil is of higher aromatic (49.3%) and less saturates (21.4%) with n Paraffin=Naphthene ¼ 0:46. The heavy compounds are less than Khasib’s crude oil; they are 13.1% NSO and 16.2% asphaltenes. This last oil could distillate gasoline (C4–C11) as well as the other constituents of kerosin, diesel fuel, and heavy gas oil.
Conclusions It is evident from this study that many scientific and economic ideas are discussed within each paragraph. Apart from these are the main erect ideas in East Baghdad Oil Field of: 1. Crude oil source of Upper Cretaceous Khasib and Tannuma Reservoirs are mainly the kerogen of the Upper Jurassic–Lower Cretaceous Chia Gara Formation. 2. Palynofacies and organic geochemistry could form the main base for hydrocarbon exploration not only in East Baghdad Oil Field but could also be used anywhere as well. 3. Hydrocarbon generation and expulsion of the Chia Gara Formation are performed during Upper Cretaceous–Lower Tertiary times of 30–90 million years ago and hence charged the already existed Cretaceous traps. 4. Trapped oil of all the sources are preserved along the total petroleum system between the highest regional seal of Middle Miocene Lower Fars Anhydrites and the lowest seal of Upper Jurassic Gotnia Anhydrites with some other local seals of nonpermeable shales and limestones. 5. Bulk properties of the trapped crude oil are heavy oil with mainly aromatic constituents with some asphalt and NSO. Acknowledgment We would like to give sincere thanks to Iraqi Oil Exploration Company for the supplies of rock samples and crude oil. Pyrolysis for these rock samples are performed in the Iraqi Oil Exploration Company while oil analysis of these samples were done in Geomark Research, Ltd. in Houston, TX, USA, to whom I give sincere acknowledgments. Acknowledgment is also due to Janet Pitman of the USGS for her help in the performance of the software PetroMod 1D for East Baghdad Oil Field.
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