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1.
1D (Petromod) hydrocarbon charge modeling and source rock characterization of the Lower Cretaceous and Upper Jurassic underlying the prolific Cretaceous and Tertiary reservoirs in the Basra oilfields in southern Iraq. The study is based on well data of the Majnoon, West Qurna, Nahr Umr, Zubair, and Rumaila oil fields. Burial histories indicate complete maturation of Upper Jurassic source rocks during the Late Cretaceous to Paleogene followed by very recent (Neogene) maturation of the Low/Mid Cretaceous succession from early to mid-oil window conditions, consistent with the regional Iraq study of Pitman et al. (Geo Arab 9(4):41–72, 2004). These two main phases of hydrocarbon generation are synchronous with the main tectonic events and trap formation associated with Late Cretaceous closure of the neo-Tethys; the onset of continent–continent collision associated with the Zagros orogeny and Neogene opening of the Gulf of Suez/Red Sea. Palynofacies of the Lower Cretaceous Sulaiy and Lower Yamama Formations and of the Upper Jurassic Najmah/Naokelekan confirm their source rock potential, supported by pyrolysis data. To what extent the Upper Jurassic source rocks contributed to charge of the overlying Cretaceous reservoirs remains uncertain because of the Upper Jurassic Gotnia evaporite seal in between. The younger Cretaceous rocks do not contain source rocks nor were they buried deep enough for significant hydrocarbon generation.  相似文献   

2.
The depositional facies and environments were unraveling by studying 21 subsurface sections from ten oilfields in the central and southern Iraq and a large number of thin sections of the Nahr Umr (siliciclastic deposit) Formation (Albian). This formation is mainly composed of sandstone interlaminated with minor siltstone and shale, with occurrence of thin limestone beds. Nahr Umr Formation is subdivided into three lithostratigraphic units of variable thicknesses on the basis of lithological variations and log characters. Mineralogically and texturally, mature quartz arenite and sandstones are the common type of the Nahr Umr Formation. The sandstones are cemented by silica and calcite material and have had a complex digenetic history. Compaction, dissolution, and replacements are the main diagenetic processes. Prodelta, distal bar, distributary mouth bar, distributary channel, over bank, and tidal channel are the main depositional environments recognized for the Nahr Umr Formation, within the studied wells. This formation was deposited in shallow marine and fluvial–deltaic environments and exhibit progradational succession of facies. Eight sedimentary facies that have been identified in the Nahr Umr Formation include claystone lithofacies, claystone siltstone lithofacies, lenticular-bedded sandstone–mudstone lithofacies, wavy-bedded sandstone–mudstone lithofacies, flaser-bedded sandstone–mudstone lithofacies, parallel and cross lamination sandstone lithofacies, trough cross-bedded sandstone lithofacies, and planar cross-bedded sandstone lithofacies. The depositional model of the Nahr Umr Formation environment was built based on the lithofacies association concepts.  相似文献   

3.
Cation and anion concentrations and boron isotopic ratio of brines in the Mishrif Formation (U. Campanian-Tuoronian) from North Rumaila, South Rumaila, Majnoon, Zubair, and West Qurna oilfields southern Iraq were investigated. The aims of this study are to define the type, origin of the oilfield waters, and its flow model in the subsurface oil traps. Mishrif brines are characterized by having higher concentrations of sodium (50,500–84,200 ppm), chlorine (102,100–161,500 ppm), and boron (21.9–31.1 ppm) with lower sulfate contents (187–1350 ppm) relative to the modern seawater. Samples have slightly depleted in δ 11B (35.4‰) relative to seawater fall near the seawater intrusion of the diagram Cl/Br Vs δ 11B and occupied the field of evaporated seawater on the diagrams of Cl vs B and 1/Br vs δ 11B. The brine of Na-chloride type is characteristics of the Mishrif reservoir in all oilfields except WQ which defined by facies of Na-Ca-chloride type. A weak acidic brine of a salinity six-time greater than seawater plays a role in generating the formation pressure and controlling the fluid flow. The reservoir rock-fluid interactions were interpreted using boron isotopes which eventually reveal an ongoing dilution process by the present seawater intrusion and injection water used for the secondary production under conditions of high-temperature digenetic reactions. The 11B in the oilfield water is resulted from uptake of the tetrahedral borate after precipitation of calcium carbonate, while 10B is sourced from the thermal maturation of organic matters.  相似文献   

4.
A worldwide data set of 1,085 samples containing organic matter of the type II/III kerogen from Carboniferous to Cenozoic was used to analyse the evolution of the hydrogen index (HI), quality index (QI), and bitumen index (BI) with increasing thermal maturity. The HImax, QImax and BImax lines were defined, based on statistical analysis and cross-plots of HI, QI and BI versus the vitrinite reflectance (%Ro) and T max (°C). The constructed HI, QI and BI bands were broad at low maturities and gradually narrowed with increasing thermal maturity. The petroleum generation potential is completely exhausted at a vitrinite reflectance of 2.0–2.2 % and T max of 510–520 °C. An increase in HI and QI suggests extra petroleum potential related to changes in the structure of the organic material. A decline in BI signifies the start of the oil window and occurs within the vitrinite reflectance range 0.75–1.05 % and T max of 440–455 °C. Furthermore, petroleum potential can be divided into four different parts based on the cross-plot of HI versus %Ro. The area with the highest petroleum potential is located in “Samples and methods” with %Ro = 0.6–1.0 %, and HI > 100. Oil generation potential is rapidly exhausted at “Results and discussion” with %Ro > 1.0 %. This result is in accordance with the regression curve of HI and QI with %Ro based on 80 samples with %Ro = 1.02–3.43 %. The exponential equation of regression can thus be achieved: HI = 994.81e?1.69Ro and QI = 1,646.2e?2.003Ro (R 2 = 0.72). The worldwide organic material data set defines two range of oil window represented by the upper and lower limits of the BI band: %Ro 0.75–1.95 %, T max 440–525 °C, and %Ro 1.05–1.25 %, T max 455–465 °C, respectively.  相似文献   

5.
In the Haushi-Huqf (Eastern Central Oman) as in other parts of the Arabian platform, a major sedimentary break is recorded between the Early Aptian carbonates (Shu'aiba Formation) and the Albian orbitolinid-rich marls (Nahr Umr Formation). The unconformity corresponds to a succession of events: (1) a brusque interruption of the regressive sequence of the Shu'aiba limestone (algae and small rudistid build-ups); (2) a stratigraphic gap related to the Late Aptian; (3) the development of a thick ferruginous crust (hardground) that covered the top surface of the Shu'aiba; the hardground is related to a forced flooding surface; (4) the Shu'aiba was rapidly drowned and buried under the Nahr Umr marls. Moreover, the Shu'aiba limestone was subject to faulting NW–SE-trending normal faults before lithification and formation of the ferruginous crust. The faulting episode is clearly dated: post-Early Aptian and pre-Albian. The signification of the faulting remains hypothetical. The syndiagenetic NW–SE normal faults may correspond to ‘en echelon’ faults, combined with transcurrent fault movements (for example the Haushi-Nafun Fault). The possible causes of these intra-platform transcurrent movements are discussed. To cite this article: C. Montenat, P. Barrier, C. R. Geoscience 334 (2002) 781–787.  相似文献   

6.
Organic geochemical analysis and palynological studies of the organic matters of subsurface Jurassic and Lower Cretaceous Formations for two wells in Ajeel oil field, north Iraq showed evidences for hydrocarbon generation potential especially for the most prolific source rocks Chia Gara and Sargelu Formations. These analyses include age assessment of Upper Jurassic (Tithonian) to Lower Cretaceous (Berriasian) age and Middle Jurassic (Bathonian–Tithonian) age for Chia Gara and Sargelu Formations, respectively, based on assemblages of mainly dinoflagellate cyst constituents. Rock-Eval pyrolysis have indicated high total organic carbon (TOC) content of up to 18.5 wt%, kerogen type II with hydrogen index of up to 415 mg HC/g TOC, petroleum potential of 0.70–55.56 kg hydrocarbon from each ton of rocks and mature organic matter of maximum temperature reached (Tmax) range between 430 and 440 °C for Chia Gara Formation, while Sargelu Formation are of TOC up to 16 wt% TOC, Kerogen type II with hydrogen index of 386 mg HC/g TOC, petroleum potential of 1.0–50.90 kg hydrocarbon from each ton of rocks, and mature organic matter of Tmax range between 430 and 450 °C. Qualitative studies are done in this study by textural microscopy used in assessing amorphous organic matter for palynofacies type belonging to kerogen type A which contain brazinophyte algae, Tasmanites, and foraminifera test linings, as well as the dinoflagellate cysts and spores, deposited in dysoxic–anoxic environment for Chia Gara Formation and similar organic constituents deposited in distal suboxic–anoxic environment for Sargelu Formation. The palynomorphs are of dark orange and light brown, on the spore species Cyathidites australis, that indicate mature organic matters with thermal alteration index of 2.7–3.0 for the Chia Gara Formation and 2.9–3.1 for the Sargelu Formation by Staplin's scale. These characters have rated the succession as a source rock for very high efficiency for generation and expulsion of oil with ordinate gas that charged mainly oil fields of Baghdad, Dyala (B?aquba), and Salahuddin (Tikrit) Governorates. Oil charge the Cretaceous-Tertiary total petroleum system (TPS) are mainly from Chia Gara Formation, because most oil from Sargelu Formation was prevented passing to this TPS by the regional seal Gotnia Formation. This case study of mainly Chia Gara oil source is confirmed by gas chromatography–mass spectrometry analysis for oil from reservoirs lying stratigraphically above the Chia Gara Formation in Ajeel and Hamrine oil fields, while oil toward the north with no Gotnia seal could be of mainly Sargelu Formation source.  相似文献   

7.
The current work investigates the hydrocarbon potentiality of the upper Jurassic–lower Cretaceous rocks in the Marib-Shabwah Basin, Central Yemen, through the Sabatayn-1 well. Therefore, palynological and organic geochemical analyses were carried out on 37 ditch cutting and 12 core samples from the well. Palynofacies analysis of the Madbi (late Oxfordian–early Tithonian) and Nayfa (Berriasian–Valanginian) Formations sediments indicates deposition of their organic-rich shale, calcareous shale and marl in middle to outer shelf environments under dysoxic–anoxic conditions, containing mainly kerogen of types II to III. However, the shales of the lower Sabatayn (Tithonian) Formation were deposited in an inner shelf environment of prevailing dysoxic–suboxic conditions, and show kerogen types III to II. Regional warm and relatively dry palaeoclimate but with local humid conditions developed near the site of the well is thought to have prevailed during deposition of the studied well sediments. The geochemical analyses of the Madbi Formation show higher total organic carbon content (TOC) than the overlying Sabatayn and Nayfa formations: it is varies between 1.2 and 7, and with average 4 wt% TOC, and the obtained S2 values (～3–10, average 7 mg HC/g rock) indicates that the Madbi Formation is mainly good source rock. It shows a good petroleum potential of 4–11 mg HC/g dry rock, and the Rock-Eval pyrolysis indicates mainly kerogen types II to III (oil to gas prone) of hydrogen index values (132–258, and only one sample from Lam Member is of 360 and average 215 mg HC/g TOC). The thermal maturation parameters as T max (425–440 °C), production index (average 0.13 mg HC/g rock) and thermal alteration index (2 to 2+) reflected that this formation is present at margin of maturation to early mature stage oil window. So, the Lam Member (upper part) of the Madbi Formation is considered the main hydrocarbon (oil and gas) source rock in the Marib-Shabwah Basin. Accordingly, we predict that the Meem Member is an active source for gas and oil accumulations in the overlying sandstone reservoir of the Sabatayn Formation in the Sabatayn-1 well.  相似文献   

8.
Seventy-two core and cutting samples of the Ratawi Formation from selected wells of central and southern Iraq in Mesopotamian Foredeep Basin are analysed for their sedimentary organic matters. Dinoflagellates, spores and pollen are extracted by palynological techniques from these rocks. Accordingly, Hauterivian and late Valanginian ages are suggested for their span of depositional time. These palynomorphs with other organic matter constituents, such as foraminifer’s linings, bacteria and fungi, are used to delineate three palynofacies types that explain organic matter accumulation sites and their ability to generate hydrocarbons. Palaeoenvironments of these sites were mainly suboxic to anoxic with deposition of inshore and neritic marine environments especially for palynofacies type 2. Total organic matters of up to 1.75 total organic carbon (TOC) wt.% and early mature stage of up to 3.7 TAI based on the brown colour of the spore species Cyathidites australis and Gleichenidites senonicus with mottled interconnected amorphous organic matter are used for hydrocarbon generation assessment from this formation. On the other hand, these rock samples are processed with Rock-Eval pyrolysis. Outcomes and data calculations of these analyses are plotted on diagrams of kerogen types and hydrocarbon potential. Theses organic matter have reached the mature stage of up to T max?=?438 °C, hydrogen index of up to 600 mg hydrocarbons for each gram of TOC wt.% and mainly low TOC (0.50–1.55). Accordingly, this formation could generate fair quantities of hydrocarbons in Baghdad oil field and Basrah oil fields. Organic matters of this formation in the fields of Euphrates subzone extends from Hilla to Nasiriyah cities have not reached mature stage and hence not generated hydrocarbons from the Ratawi Formation. Software 1D PetroMod basin modelling of the Ratawi Formation has confirmed this approach of hydrocarbon generation with 100 % transformations of the intended organic matters to generate hydrocarbons to oil are performed in especially oil fields of East Baghdad, West Qurna and Majnoon while oil fields Ratawi and Subba had performed 80–95 % transformation to oil and hence end oil generation had charged partly the Tertiary traps that formed during the Alpine Orogeny. Oil fields of Nasiriyah and Kifle had performed least transformation ratio of about 10–20 % transformation to oil, and hence, most of the present oil in this field is migrated from eastern side of the Mesopotamian Foredeep Basin that hold higher maturation level.  相似文献   

9.
The Sebahat (Middle Miocene to Early Pliocene) and Ganduman (Early Pliocene to Late Pliocene) Formations comprise part of the Dent Group. The onshore Sebahat and Ganduman Formations form part of the sedimentary sequence within the Sandakan sub-basin which continues offshore in the southern portion of the Sulu Sea off Eastern Sabah. The Ganduman Formation lies conformably on the Sebahat Formation. The shaly Sebahat Formation represents a distal holomarine facies while the sandy Ganduman Formation represents the proximal unit of a fluvial–deltaic system.Based on organic geochemical and petrological analyses, both formations posses very variable TOC content in the range of 0.7–48 wt% for Sebahat Formation and 1–57 wt% for Ganduman Formation. Both formations are dominated by Type III kerogen, and are thus considered to be gas-prone based on HI vs. Tmax plots. Although the HI–Tmax diagram indicates a Type III kerogen, petrographic observations indicate a significant amount of oil-prone liptinite macerals. Petrographically, it was observed that significant amounts (1–17% by volume) of liptinite macerals are present in the Ganduman Formation with lesser amounts in the Sebahat Formation.Both formations are thermally immature with vitrinite reflectance values in the range of 0.20–0.35%Ro for Ganduman Formation and 0.25–0.44%Ro for Sebahat Formation. Although these onshore sediments are thermally immature for petroleum generation, the stratigraphic equivalent of these sediments offshore are known to have been buried to deeper depth and could therefore act as potential source rocks for gas with minor amounts of oil.  相似文献   

10.
Palynomorphs recovered from core and cuttings samples from five boreholes in the East Baghdad Oilfield indicate a mid Albian–early Cenomanian age-range for the Nahr Umr Formation and the lower part of the overlying Mauddud Formation. Two palynomorph zones and four types of palynofacies have been identified. The latter are interpreted to indicate delta-top swamp and marsh, silty–muddy deltaic, inner silty and carbonate-rich platform, and limestone-platform environments. The palynofacies of the two types of platform accumulations suggest that these are potential sources of biogenic methane and condensates, and may yield more liquid hydrocarbons in areas where the formations are at greater depths than within the region studied.  相似文献   

11.
Selection of a suitable reservoir for fluid storage depends on the reservoir characteristics including permeability, porosity, depth, and reservoir volume. A prospective injection site requires certain quantitative or qualitative value for every parameter involved in a selection criterion. The Barremian?Clower Aptian Zubair Formation, at the Burgan oilfield in southern Kuwait, was selected as a potential site for a deep slurry injection project. The Zubair Formation is a major siliciclastic wedge; the target zone (second sand layer) ranges in thickness from 85.3 to 115.8?m with lateral extension measuring 35 by 20?km. The Zubair Formation parameters were evaluated, using log information, provided by Kuwait Oil Company, from three existing oil wells in the Burgan oilfield, and applying Nadeem and Dusseault (Environ Geosci 14(2):61?C71, 2007) geological assessment model for deep slurry injection. The results of the model show that the Zubair Formation is an excellent reservoir to receive injected slurried waste.  相似文献   

12.
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 $ {\hbox{C}}_{15}^{+} $ peaks to indicate their slight degradation and water washing. Oil biomarkers of $ \Pr ./{\hbox{Ph}}{.} = {0}{.85,}{{\hbox{C}}_{31}}/{{\hbox{C}}_{30}} < 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 $ {\hbox{TAI}} = 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 ${S_2} = 2.5 - 18.5\,{\hbox{mg}}\,{\hbox{Hc/g}}\;{\hbox{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 ( $ {\hbox{TAI}} = 2.8 - 3.0 $ and $ {\hbox{T}}\max = 428 - 443{\hbox{C}} $ ), 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.  相似文献   

13.
Reconstruction of Mesozoic and Cenozoic sedimentary ‘cover’ on the Precambrian shield in the Lac de Gras diamond field, Northwest Territories, Canada, has been achieved using Cretaceous and early Tertiary sedimentary xenoliths and contemporaneous organic matter preserved in volcaniclastic sediments associated with late Cretaceous to early Tertiary kimberlite pipe intrusions, and in situ, Eocene crater lake, lacustrine and peat bog strata. Percent reflectance in oil (%Ro) of vitrinite within shale xenoliths for: (i) Albian to mid-Cenomanian to Turonian ranges from > 0.27 to 0.42 %Ro (mean = 0.38 %Ro), (ii) Maastrichtian to early Paleocene from 0.24 to < 0.30%; (iii) latest Paleocene to early middle Eocene 0.15 to < 0.23 %Ro (mean = 0.18 %Ro). These levels of thermal maturity are corroborated by Rock Eval pyrolysis Tmax (°C) and VIS region fluorescence of liptinites, with wavelengths of maximum emission for sporinite, prasinophyte alginite and dinoflagellates consistent with vitrinite reflectance of 0.20 to < 0.50 %Ro. Burial–thermal history modeling, constrained by measured vitrinite reflectance and porosity of shale xenoliths, predicts a maximum burial temperature for Mid to Late Albian strata (∼115 Ma) of 60 °C with ∼1.2 to 1.4 km of Cretaceous strata in the Lac de Gras kimberlite field region prior to major uplift and erosion, which began at 90 Ma. Late Paleocene to middle Eocene volcanic crater lake lacustrine to peat bog strata were only buried to a few hundreds of meters and are in a peat-brown coal stage of thermal maturation.  相似文献   

14.
The Middle Jurassic Khatatba Formation is an attractive petroleum exploration target in the Shoushan Basin, north Western Desert, Egypt. However, the Khatatba petroleum system with its essential elements and processes has not been assigned yet. This study throws the lights on the complete Khatatba petroleum system in the Shoushan Basin which has been evaluated and collectively named the Khatatba-Khatatba (!) petroleum system. To evaluate the remaining hydrocarbon potential of the Khatatba system, its essential elements were studied, in order to determine the timing of hydrocarbon generation, migration and accumulation. Systematic analysis of the petroleum system of the Khatatba Formation has identified that coaly shales and organic-rich shales are the most important source rocks. These sediments are characterised by high total organic matter content and have good to excellent hydrocarbon generative potential. Kerogen is predominantly types II–III with type III kerogen. The Khatatba source rocks are mature and, at the present time, are within the peak of the oil window with vitrinite reflectance values in the range of 0.81 to 1.08 % Ro. The remaining hydrocarbon potential is anticipated to exist mainly in stratigraphic traps in the Khatatba sandstones which are characterised by fine to coarse grain size, moderate to well sorted. It has good quality reservoir with relatively high porosity and permeability values ranging from 1 to 17 % and 0.05–1,000 mD, respectively. Modelling results indicated that hydrocarbon generation from the Khatatba source rocks began in the Late Cretaceous time and peak of hydrocarbon generation occurred during the end Tertiary time (Neogene). Hydrocarbon primarily migrated from the source rock via fractured pathways created by abnormally high pore pressures resulting from hydrocarbon generation. Hydrocarbon secondarily migrated from active Khatatba source rocks to traps side via vertical migration pathways through faults resulting from Tertiary tectonics during period from end Oligocene to Middle Miocene times.  相似文献   

15.
Palynological and organic geochemical analysis are performed in this study for 220 samples of cores and cuttings collected from the Ordovician Khabour, Silurian Akkas, and Upper Devonian Kaista Formations in wells Akkas/1-6, Khleisya/1, KH5/6, and KH5/1 of West Iraq. Their diagnostic organic matters are abundant acritarchs (134 species belonging to 54 genera, including marine algae of Tasmanites, Deflandstrum, and brazinophytes) and a few spores (21 species belonging to 16 genera) and Chitinozoa (43 species belonging to 12 genera) as well as scolecodonts, graptolite siculae, cuticles, and amorphous organic matters. On the basis of acritarchs with tentative selections of Chitinozoa and spores, this succession is subdivided into ten palynozones (PZ1–PZ10) within a stratigraphic framework and correlated with equivalent strata in Saudi Arabia and Libya. Beds of the Khabour and lower part of Akkas Formations were deposited in anoxic–dysoxic marine shelf environments northern Gondwana Continent with provincial acritarchs. These deposits were extending from outer to inner neritic with affects of local upwelling currents and lagoons, especially in boreholes Akkas/1, KH5/1, and KH5/6. Hydrocarbon generations potential are assessed by plotting organic matter types in palynofacies context of Bujaks (1970) graphical model with depths along with log of thermal maturation indices on the basis of the color changes of the acritarchs Diexallophasis denticulata–Orthosphaeridium ternatus and Baltisphaeridium constrictum as well as kerogen types and total organic carbon (TOC). These organic matters are up to 16% TOC, especially for the hot shale of the Lower Silurian Akkaz Formation, very low asphalting and sulfur, saturated and aromatic hydrocarbons of more than 96%, and high peaks of C2–C20 gas chromatography that could indicate predominant gas generation with some light oils. The associated gases are mainly methane and ethane of CH4, C2H6, and C3H8. Accordingly, source potential for wet gas and condensates could be assessed for depth of 2,750–3,000 m and dry gas for depth of 3,570–3,650 m in well Akkas-1 only from the Ordovician Kabour Formation. Little oil might be generated from the lower Silurian Akkas formation in borehole Akkas-1 and KH5/6. These potential source rocks are extended toward Jordon, southwest Iraqi Desert and Syria. Accumulation sites of these generated gas and little oil could be within the sandstone porosities of 10–17% and permeability of 500 mD sealed by the non permeable shale's along closures of the structured anticline fold and fault of this field as well as along the unconformity boundary of the Upper Silurian Akkas Formation with the Upper Devonian Kaista Formation. Accordingly, Lower Paleozoic total petroleum system of generation, migration, and accumulations could be assessed for a basin includes West Iraq and their extensions in Jordon and Syria.  相似文献   

16.
Findings of the oil source affinity for oil sample collected from shallow borehole already drilled for ground water purposes at the Sakran area, NE Haditha city, western Iraq, is performed in this study by biomarker studies with addition to the analysis of gravity map. Petroleum geochemistry study is carried out on oil sample. The terpane and sterane biomarker distributions, as well as the stable isotope values, are used for determining the validity of oil to correlate its source. The results showed that the oil belongs to the Jurassic age, with high sulfur content (2.75 %) and value of C28/C29 up to 0.75. The tricyclic terpanes values as well as hopanes indicated a source rock affinity of carbonates, whereas the pristine/phytane ratio indicated marine algal source of kerogen type II. All these information could confirm that the source rock affinity was the Sargelu Formation (Jurassic), in which their age’s equivalent to the source in East Baghdad Oil Field and Tikrit Oil Field, with a difference from the oil family near the Akkas field, located to the west of the area. Chemical analyses of water sample collected from the borehole showed the following results: TDS?=?12,700 mg/l, EC?=?215,900 μs/cm, pH?=?6.8, DO?=?28 mg/l, and temperature?=?24 °C. Hydrochemical functions such as rNa/rCl (<1), (rNa–rCl)/rSO4 (<0) and rSO4/rCl (<1) indicate that the water is of marine origin, partially mixed with meteoric water. Analysis of the gravity map revealed two anomalous areas; the western one represents large anomaly with EW trend similar to the Anah graben to the north. The second one consists of many anomalies trending N–NW direction. The main local anomaly is identical with the seeps from the drilled borehole covering large area. The boundaries and trends of the main geological structures have been defined by gradient analysis procedure to the gravity data. The closed gravity anomalies with their large extensions reflect the importance of the results for further studies and promising area for oil reservoirs.  相似文献   

17.
Different bacterial and fungal strains, isolated from petroleum hydrocarbon-contaminated soil, were tested, in isolation as well as in combination, for their ability to degrade total petroleum hydrocarbon (TPH) in soil samples spiked with crude oil (2, 5 or 10 %, w/w) for 30 days. The selected combination of bacterial and fungal isolates, i.e., Pseudomonas stutzeri BP10 and Aspergillus niger PS9, exhibited the highest efficiency of TPH degradation (46.7 %) in soil spiked with 2 % crude oil under control condition. Further, when this combination was applied under natural condition in soil spiked with 2 % (w/w) crude oil along with inorganic fertilizers (NPK) and different bulking agents such as rice husk, sugarcane, vermicompost or coconut coir, the percent degradation of TPH was found to be maximum (82.3 %) due to the presence of inorganic fertilizers and rice husk as bulking agent. Further, results showed that the presence of NPK and bulking agents induced the activity of degradative enzymes, such as catalase (0.718 m mol H2O2 g?1), laccase (0.77 µmol g?1), dehydrogenase (37.5 µg g?1 h?1), catechol 1, 2 dioxygenase (276.11 µ mol g?1) and catechol 2, 3 dioxygenase (15.15 µ mol g?1) as compared to control (without bioaugmentation). It was inferred that the selected combination microbes along with biostimulants could accentuate the crude oil degradation as evident from the biostimulant-induced enhanced activity of degradative enzymes.  相似文献   

18.
As an important unconventional resource, oil shale has received widespread attention. The oil shale of the Chang 7 oil layer from Triassic Yanchang Formation in Ordos Basin represents the typical lacustrine oil shale in China. Based on analyzing trace elements and oil yield from boreholes samples, characteristics and paleo-sedimentary environments of oil shale and relationship between paleo-sedimentary environment and oil yield were studied. With favorable quality, oil yield of oil shale varies from 1.4% to 9.1%. Geochemical data indicate that the paleo-redox condition of oil shale’s reducing condition from analyses of V/Cr, V/(V + Ni), U/Th, δU, and authigenic uranium. Equivalent Boron, Sp, and Sr/Ba illustrate that paleosalinity of oil shale is dominated by fresh water. The paleoclimate of oil shale is warm and humid by calculating the chemical index of alteration and Sr/Cu. Fe/Ti and (Fe + Mn)/Ti all explain that there were hot water activities during the sedimentary period of oil shale. In terms of Zr/Rb, paleohydrodynamics of oil shale is weak. By means of Co abundance and U/Th, paleo-water-depth of oil shale is from 17.30 to 157.26 m, reflecting sedimentary environment which is mainly in semi deep–deep lake facies. Correlation analyses between oil yield and six paleoenvironmental factors show that the oil yield of oil shale is mainly controlled by paleo-redox conditions, paleoclimate, hot water activities, and depth of water. Paleosalinity and paleohydrodynamics have an inconspicuous influence on oil yield.  相似文献   

19.
The origin of the oil in Barremian–Hauterivian and Albian age source rock samples from two oil wells (SPO-2 and SPO-3) in the South Pars oil field has been investigated by analyzing the quantity of total organic carbon (TOC) and thermal maturity of organic matter (OM). The source rocks were found in the interval 1,000–1,044 m for the Kazhdumi Formation (Albian) and 1,157–1,230 m for the Gadvan Formation (Barremian–Hauterivian). Elemental analysis was carried out on 36 samples from the source rock candidates (Gadvan and Kazhdumi formations) of the Cretaceous succession of the South Pars Oil Layer (SPOL). This analysis indicated that the OM of the Barremian–Hauterivian and Albian samples in the SPOL was composed of kerogen Types II and II–III, respectively. The average TOC of analyzed samples is less than 1 wt%, suggesting that the Cretaceous source rocks are poor hydrocarbon (HC) producers. Thermal maturity and Ro values revealed that more than 90 % of oil samples are immature. The source of the analyzed samples taken from Gadvan and Kazhdumi formations most likely contained a content high in mixed plant and marine algal OM deposited under oxic to suboxic bottom water conditions. The Pristane/nC17 versus Phytane/nC18 diagram showed Type II–III kerogen of mixture environments for source rock samples from the SPOL. Burial history modeling indicates that at the end of the Cretaceous time, pre-Permian sediments remained immature in the Qatar Arch. Therefore, lateral migration of HC from the nearby Cretaceous source rock kitchens toward the north and south of the Qatar Arch is the most probable origin for the significant oils in the SPOL.  相似文献   

20.
The drilling sludge represents a complex environment, containing several types of pollutants that can be even used as nutrients by indigenous microorganisms, like hydrocarbon-degrading bacteria, having good potentialities for the biodegradation of petroleum products. In this study, a drilling sludge was collected from drilling quagmire. Physicochemical characterization of the drilling sludge was done. Its mineralogy was obtained by diffractometry. The indigenous aerobic sludge hydrocarbon-degrading bacteria were checked by counting on Bushnell–Haas medium, and their isolation and purification were performed by the selective microbial enrichment technique in a batch-enriched Bushnell–Haas culture, with crude oil as the sole carbon source. Isolates were characterized, and their power to emulsify crude oil was determined by emulsification index and oil spreading tests. Environmental conditions in the quagmire, like temperature, pH and moisture, were suitable for bacterial development. Physicochemical characteristics of the drilling sludge showed richness in chemical elements and promote microbial life. Fifteen different colonies of hydrocarbon-degrading bacteria were isolated and purified; they have diversified morphological and microscopic aspects. Most isolates had a good emulsification index (between 31 and 76 %). Oil spreading test gave clear zone diameters >28 mm, with a maximum of 60 mm. The results of these investigations prove the elementary, mineralogy and microbiology richness of drilling sludge and reveal the high diversity of its indigenous hydrocarbon-degrading bacterial flora. These properties can be exploited for the own restoration of petroleum quagmires in oil fields, by means of bioremediation applications and by integrating indigenous microorganisms.  相似文献   

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