GEOCHEMICAL CHARACTERIZATION OF POTENTIAL JURASSIC/CRETACEOUS SOURCE ROCKS IN THE SHUSHAN BASIN, NORTHERN WESTERN DESERT, EGYPT

Some 180 core and cuttings samples of shales and limestones from the Middle Jurassic – Late Cretaceous succession (Khatatba, Masajid, Alam El-Bueib, Alamein, Kharita, Bahariya and Abu Roash Formations) were collected from wells Ja 27–2, Tarek-1 and Jb 26–1 in the central, structurally-low part of the Shushan Basin and from well Lotus-1 in the structurally-elevated western part of the basin. All samples were screened for total organic carbon (TOC) content. Selected samples were then analyzed by Rock-Eval pyrolysis, and extracted for biomarker analyses. Visual kerogen analysis and vitrinite reflectance measurements were also undertaken and oil - source rock correlations were attempted. The results indicate that the thermal maturity of the samples can be correlated closely with burial depth. Samples from the central part of the basin are more mature than those from the west. Samples from the central part of the basin (except those from the Albian Kharita Formation) have reached thermal maturities sufficient to generate and expel crude oils. Extracts from the Middle Jurasic Khatatba and Early Cretaceous Alam El-Bueib Formations can be correlated with a crude oil sample from well Ja 27–2.
In well Lotus-1 in the west of the basin, four distinct organic facies can be recognized in the Jurassic-Cretaceous interval. One of the facies ("facies 4") has a sufficiently high TOC content to act as a source rock. Thermal maturities range from immature to peak oil generation, and the top of the oil window occurs at approximately 8000 ft.     

Geochemistry,generation and maturation of the hydrocarbons at Wadi Al-Rayan oil field,Western Desert of Egypt

`The present work aims to study the organic chemistry, the generation and maturation of the hydrocarbons encountered at Abu Roash Formation, Wadi El Rayan oil field. The analysis of source rocks indicates the presence of two organic facies. The first is characterized by high total organic carbon of 0.93–3.39%, strongly oil-prone (Type II), and good potential for oil generation (pyrolysis S2 yields 4.54–23.26 mg HC/g rock and HI 488–705 mg HC/g TOC). The second attains good range of organic carbon from 0.90% to 1.57%, which is a mixed oil and gas (Type II–Type III) of fair hydrocarbon generation (pyrolysis S2 yield of 1.98–5.33 mg HC/g). The kerogen type consists of unstructured lipids and some terrestrial material. Plot of Pr/n-C17 versus Ph/n-C18 indicates that the crude oil was derived from mixed source rock, while the maturity profile assigns oil windows (0.6 R_o%) matching topmost of Abu Roash G Member.     

Hydrocarbon potentiality and thermal maturity of the Cretaceous rocks in Al Baraka oil field,KomOmbo basin,south Egypt

This paper aims to evaluate the hydrocarbon potentiality and thermal maturity of the Cretaceous source rocks in Al Baraka oil field in KomOmbo basin, south Egypt. To achieve this aim, geochemical analyses (TOC), Rock eval pyrolysis and vitrinite reflectance measurements (R0) were carried out on the studied rocks. The analytical results of the samples that were collected from five exploratory oil wells revealed that almost Lower Cretaceous formations (Sabaya, Abu Ballas, Six Hills and KomOmbo C, B, A) and Upper Cretaceous formations (Dakhla, Duwi, Quseir, Taref and Maghrabi) are ranged from fair to excellent source rocks for hydrocarbon generation. Oil and gas are mainly the future products of the thermally transformed organic matters within almost samples of the Cretaceous formations, where the Lower and Upper Cretaceous formations contain mixed type II/III and III kerogen besides type II kerogen in KomOmbo (B) and Dakhla formations. The thermal maturity parameters clarified that the Lower Cretaceous formations are belonged to marginally mature (in Sabaya and Abu Ballas formations), whereas the rocks of KomOmbo (B) Formation are mature source rocks and fall in the stage of oil generation and reach to the late stage of oil generation (R0?=?1.25). On the contrary the Upper Cretaceous formations are ranged from immature to marginally mature source rocks and reach only the early stage of oil generation in Maghrabi Formation. This study indicated that there is still a good chance to find oil generated from the Dakhla, Duwi, Maghrabi, Sabaya and Abu Ballas formations if buried in greater depths as well as, KomOmbo B and A intervals which are source rock potentials.     

CRETACEOUS SOURCE ROCKS AT THE ABU GHARADIG OIL- AND GASFIELD, NORTHERN WESTERN DESERT, EGYPT

The Abu Gharadig oil- and gasfield is located in the north of the Western Desert of Egypt. In this paper, the geochemical characteristics of kerogens from Cretaceous shales at this field are described. The shale samples came from the Abu Roash Formation E and G Members (late Cenomanian- Turonian), the Bahariya Formation (early Cenomanian) and the Betty Formation (Neocomian- Barremian). Kerogen type and quality was evaluated by optical microscopy and by standard methods (elemental analysis, infrared spectroscopy and Rock-Eval pyrolysis). The results show that the shale samples analysed contain fair to high quantities of organic matter, and that this takes the form of marine amorphous sapropelic and structured liptinite macerals which can be classified as Types I and II kerogens.
Maturation indicators and burial history curves indicate that shales from the Abu Roash E and G Members are currently located in the oil-generation window. Oil generation in these units has taken place since the late Palaeocene-early Eocene—i.e. since the formation of structural traps in the Abu Gharadig area, which occurred in the Maastrichtian—Eocene. Shales in the Bahariya and Betty Formations passed through the oil window during the Late Cretaceous before the traps were formed, but the shales reached the wet-gas zone in the late Miocene - early Pliocene.
Most of the liquid hydrocarbons in the Abu Gharadig field are sourced by Cretaceous shales in the Abu Roash E and G Members; and most gas is generated by shales in the underlying Bahariya and Betty Formations. The Jurassic Khatatba Formation may also have generated some gas.     

Stratigraphy,Petrography, and Petrophysical Properties of the Subsurface Upper Cretaceous Sediments,Northwestern Desert,Egypt

Abstract

In this article, 33 core samples and 160 ditch samples of Upper Cretaceous age were studied at different depths from Horus well 1. Stratigraphic, petrographic, and petrophysical studies and well log analysis are used to study and evaluate the rock units. The studied core samples are dolomite (Abu Roash formation), shaly limestone, and argillaceous sandstone (Bahariya formation). The depositional environments of the studied rock units vary from deltaic to deltaic-marine. The effective porosity of the studied core samples is low and may be of secondary origin. The upper part of low Bahariya is considered a high category of reservoir. The stratigraphic significance of some benthonic foraminifera (Thomasinella, Nezzazata, and Nezzatine) furnishes new information on the age determination. Cenomanian-Santonian time is suggested for the studied interval (Bahariya and Abu Roash formations).     

Origin of Bahariya oil in Salam oil field,Western Desert- Egypt

The origin of Bahariya oil is a debatable issue. Bahariya Formation produces oil from the Lower sandstone unit by normal pressure mechanism, while the Upper Bahariya shale produces oil by fracking mechanism. The main question is: is there any genetic relationship between the two oils.To answer this question, “50” ditch samples, “12” extract samples and “2” oil samples represent Khatatba and Bahariya formations and Abu Roash ‘G’ Member, collected from six wells drilled in Salam oil field, have been geochemicaly analyzed, using LECO SC632, Rock–Eval- 6 pyrolysis, GC and GC/MS techniques.The analysis shows that the Total Organic Carbon content (TOC) for the studied formations ranges from fair to v.good, with poor to good hydrocarbon potentiality. The maturity evaluation using Tmax, and calculated Vitrinite reflectance (R_o) showed that the studied samples have good thermal maturation reaching the stage of oil generation. Also the analysis revealed that the kerogen is a mixture of type II/III kerogen, reflecting the potential generation of oil and gas. The GC and GC/MS data showed that the organic matter is a mixed marine/terrestrial input deposited in transitional environment under prevailing reducing conditions. The oil samples fingerprint of the saturated hydrocarbons fraction from Baharyia reservoir (Lower and Upper) members suggest that the oil samples have a mixed organic source with significant terrestrial organic matter input deposited under saline to hypersaline environment with slightly oxidizing environment.Based on the obtained results, it is suggested that the Bahariya oil has been sourced mainly from deeper horizons (Khatatba Formation) with some contribution from upper and lower Bahariya source rocks.     

Source rock evaluation of Kharita and Bahariya formations in some wells,North Western Desert,Egypt: Visual palynofacies and organic geochemical approaches

Palynofacies analyses were applied on ninety-one samples from the subsurface Albian – Cenomanian succession represented by Kharita and Bahariya formations, encountered in El-Noor, and South Sallum wells, located in the North Western Desert, Egypt, to visually characterize the content of dispersed organic matter, as well as, organic geochemical characterization to reveal the depositional paleoenvironments and source rock potentiality. The result recognized of five palynofacies associations in the studied interval. The deposition of Kharita Formation took place mainly in a steady and a relatively stable deltaic to marginal environment continued as well in the lower part of Bahariya Formation with minor changes. The marine influence became more common in the upper part of Bahariya Formation showing the exceptional high hydrocarbon potential recorded in the studied interval. This indicates marine transgression by the end of the early Cenomanian (Upper Bahariya) age. Samples from the Kharita Formation contain abundant brown phytoclasts which suggest gas-prone kerogen type III and IV. While Bahariya Formation includes translucent, brown cuticles and woody tracheid phytoclasts pointing to more promising gas-prone kerogen type III. The organic geochemical analysis shows poor to fair gas-prone source rock potential within the study section., Thermally, the color of the spore grains in Kharita and Bahariya formations show that dark yellow to orange, indicates immature besides their general little poor hydrocarbon generation potentiality.     

Integration of well log analysis data with geochemical data to evaluate possible source rock. Case study from GM-ALEF-1 well,Ras Ghara oil Field,Gulf of Suez-Egypt

Well logging methodology in geochemical evaluation is an important technique not only for its usefulness as a quick scan of potential source rock, but also in its ability to identify the organic richness (TOC%) of these rocks. Wireline logs can be used to identify source rock intervals in the primary stage of well drilling. Consequently, the logs used for source rock evaluations and calculation of Total Organic Carbon most commonly include density, sonic, gamma ray, neutron and resistivity by using several methods.In this research, a suite of geophysical logs and geochemical data were applied for determining the Total Organic Carbon content (TOC) and compare them together, in addition to source rock evaluation of the study formation.Application of such techniques take place in one well GM-ALEF-1 well located in the Ras Ghara oil Field, Gulf of Suez, Egypt, represented by Miocene rock, Rudeis Formation. A calculated TOC is compared with the measured one from the LECO SC632 after that Rock-Eval pyrolysis data also used to evaluate the TOC content mainly, organic richness, types of kerogen, and thermal maturity.The results of comparison showed that the Petrophysical method using ΔlogR and the LECO and Rock-Eval pyrolysis techniques have produced close results for Total Organic Carbon content, Hence it can be used as a fast and efficient way to regard the intervals rich in organic matter, further step takes place and the reach interval of organic matter is evaluated geochemically shows that the shale in Rudeis formation have fair to good organic richness, it has the potential to produce type II/III kerogen. It is marginally mature to mature source rock. The expected generated hydrocarbon is fair oil source with some gas.     

Stratigraphic distribution of the palynomorphs and the particulate organic matter in subsurface Lower/Middle Cretaceous deposits,Western Desert of Egypt: Palynological and geochemical approach

The stratigraphic distribution of the palynomorphs and particulate organic matter was studied in the subsurface Lower/Middle Cretaceous sections in Ii-26-1 and Ig-30-1 wells, located in north Western Desert of Egypt. Some important palynofacies parameters were employed as indicators of proximal–distal trends. The spatial and stratigraphical variations of six palynofacies categories had been illustrated. Optically, the type and nature of the recovered particulate organic matter together with their quantity were combined to reveal the prevailing paleoenvironmental conditions during deposition of the concerning sections. Thirty-seven samples were selected from the two wells to carry the total organic carbon (TOC) and Rock–Eval Pyrolysis analyses in order to geochemically evaluate the source rock.TOC and Rock–Eval Pyrolysis analyses illustrate extremely low TOC and HI values, demonstrating that the Alam El Bueib, Alamein, Dahab, Kharita and Bahariya formations are comprised principally of type IV kerogen and a few type III kerogen components. Therefore, they are inert to slightly gas prone, signifying a strong deficiency of hydrogen-enriched organic matter. Palynofacies analysis implies that all the studied formations have highly oxidized terrestrial organic matter (brown phytoclasts and black woods).     

Hydrocarbon source-rock potential of the Jurassic succession in eastern part of the North Western Desert,Egypt

The hydrocarbon potential is determined by the quantity and quality of organic matter encountered in the Jurassic sediments in two wells at the Northern Western Desert. It utilizes to define the zones of oil and gas using the well logging data for calculates the total organic carbon (TOC). The evaluation of source rock has been based on two steps; the first one depended on the geochemical parameters including TOC, S1, S2, Tmax, and Vitrinite reflectance (Ro %) of two wells JG-1 and JD-4. The second step was to calculate (TOC) from wireline logs. The well log types utilized in such kind of analysis are the density log, sonic log, resistivity log and gamma-ray log. The stratigraphic sequence, in the studied wells ranges in age from Paleozoic to Recent. The present work focuses on the Jurassic rocks represented by Khatatba Formation as they include the main source horizon. Based on the obtained results, Jurassic sediments called as fair to excellent source rock potential. The genetic type of organic matter can be identified through the study of pyrolysis data, which indicate that is rich in mixed oil and gas-prone kerogen except few samples reflect type I organic facies.     

Source rock potential of the Sayındere formation in the Şambayat oil field,SE Turkey

Upper Campanian–Maastrichtian Say?ndere Formation, located in southeastern Turkey, composed of pelagic limestone which was deposited relatively deep marine. In this study, well samples of the Say?ndere Formation were analyzed by Rock-Eval pyrolysis and the oil sample from this unit were analyzed by GC, and GC-MS to assess source rock characteristics and hydrocarbon potential. The TOC values of the Say?ndere Formation samples range from 0.34 to 4.65?wt.% with an average of 1.14?wt.% and organic matter have good TOC value. Hydrogen Index (HI) values range from 407?mg HC/g TOC to 603?mg HC/g TOC and indicates Type II kerogen. T_max values are in the range of 434 - 442?°C and indicate early-mid mature stage. The Say?ndere samples have fair to good hydrocarbon potential based on TOC contents, S2, and PY values. According to the HI versus TOC plot, most of the samples have good oil source. The oil sample contains predominant short-chain n-alkanes and plots in marine algal Type II field on a Pr/n-C17 versus Ph/n-C18 cross-plot indicating anoxic environment. Biomarker analysis shows that the deposition of oil source rock is carbonate-rich sediments.     

TOC determination of Gadvan Formation in South Pars Gas field, using artificial intelligent systems and geochemical data

Potentially, TOC content is affected by logging data in a source rock (density, sonic, neutron and resistivity logs). Hence, to analyze these logs, which we make a quick and reliable assessment of a source rock. So, it is a quick and economically cheaper method rather than direct geochemical analysis. A source rock interval poses to less density, lower velocity, higher sonic porosity, higher gamma ray values and increase in resistivity. In this research, Gadvan Formation was studied in two boreholes as potential of source rock. The log data of two wells were used to construct of intelligent models in a source rock of the South Pars Gas field in southwest of Iran. A suite of geophysical logs (neutron, density, sonic and resistivity logs) and cutting chip data samples data were applied for determining TOC content of this formation. Rock-Eval pyrolysis data reveal that Gadvan Formation is poor source rock (less than 0.5%). Hence we attempted a correlation between geophysical data and direct TOC content measurements of using ? Log R, Rock-Eval, neural network and fuzzy logic techniques.The results showed that intelligent models were successful for prediction of TOC content from conventional well logs data. Meanwhile, similar responses from other different intelligent methods indicated that their validity for solving complex problems.     

Evaluation of the nature,origin and potentiality of the subsurface Middle Jurassic and Lower Cretaceous source rocks in Melleiha G-1x well,North Western Desert,Egypt

The present work aims to evaluate the nature and origin of the source rock potentiality of subsurface Middle Jurassic and Lower Cretaceous source rocks in Melleiha G-1x well. This target was achieved throughout the evaluation of total organic carbon, rock Eval pyrolysis and vitrinite reflectance for fifteen cutting samples and three extract samples collected from Khatatba, Alam El Bueib and Kharita formations in the studied well. The result revealed that the main hydrocarbon of source rocks, for the Middle Jurassic (Khatatba Fm.) is mainly mature, and has good capability of producing oil and minor gas. Lower Cretaceous source rocks (Alam El Bueib Fm.) are mature, derived from mixed organic sources and have fair to good capability to generate gas and oil. Kharita Formation of immature source rocks originated from terrestrial origin and has poor to fair potential to produce gas. This indicates that Khatatba and Alam El Bueib formations take the direction of increasing maturity far away from the direction of biodegradation and can be considered as effective source potential in the Melleiha G-1x well.     

埃及西沙漠盆地中生界烃源岩特征及剩余资源分布

西沙漠盆地是埃及三大主要含油气区之一,已发现大量的油气田,现处勘探发现中期,预探风险增大。为此,在详细评价盆地烃源岩地球化学特征基础上,运用盆地数值模拟技术定量分析剩余资源潜力。研究认为,中侏罗统Khatatba组Safa段和Zahra段煤系暗色泥页岩以及上白垩统Abu Roash组AR-F段暗色泥页岩是盆地的3套主力烃源岩,各凹陷烃源岩广泛分布,厚度变化较大。Khatatba组烃源岩TOC含量在0.5%~10%,裂解烃S₂含量高,为中等-很好烃源岩;Abu Roash组AR-F段烃源岩TOC主要在0.5%~3%,裂解烃S₂含量中-高,属中等-好烃源岩。这3套烃源岩有机质干酪根类型以混合Ⅱ型为主,其次是Ⅲ型,少量为Ⅰ型。指出Khatatba组2套烃源岩全盆处于热演化成熟大量生排烃阶段,凹陷中心达高熟生烃、局部过熟生气阶段,油气并生;Abu Roash组AR-F段烃源岩仅Abu Gharadig和Natrun凹陷进入成熟生烃阶段。提出盆地北部地区主要由侏罗系Khatatba组烃源岩供给油气,东南部地区则有侏罗系Khatatba组和白垩系AR-F段双源供烃。计算表明,盆地剩余可采资源量达6.51×10⁸ t,剩余资源潜力很好;其中,南部Abu Gharadig凹陷古生界、侏罗系和下白垩统AEB,北部Matruh凹陷古生界、Faghur凹陷上白垩统,油气探明程度低,剩余资源可观,为下步勘探的有利方向。     

Organic geochemical characteristics of Middle to Late Eocene Shahbazan Formation in Dezful Embayment,SW Iran: A case study from Qaleh-Nar oilfield

Abstract

In a first attempt, Middle to Late Eocene Shahbazan Formation as a possible source rock in Dezful Embayment was geochemically investigated. Maturity indicators derived from Rock-Eval pyrolysis (T_max and PI) and gas chromatography (CPI) show that the organic matter, which dominated by a mixed type II/III kerogen, is thermally mature and has already entered the oil window. A fair to good petroleum-generative potential is suggested by moderate to relatively high values of total organic carbon (TOC) and potential yield (S₁+S₂). Deposition of Shahbazan Formation under low-oxygen condition, which is represented by low pristane/phytane ratio (<1), conduced to preservation of organic matter. This is in accordance with considerable TOC contents, ranging from 1.01 to 1.72?wt%. The relation between pristane/nC₁₇ and phytane/nC₁₈ as well as terrigenous/aquatic ratio (～1) represent the mixed marine and terrestrially sourced organic matter. Based on the results obtained from this study, Shahbazan Formation could have been acted as a prolific oil and gas source rock.     

KINETICS OF HYDROCARBON GAS GENERATION FROM MARINE KEROGEN AND OIL: IMPLICATIONS FOR THE ORIGIN OF NATURAL GASES IN THE HETIANHE GASFIELD, TARIM BASIN, NW CHINA

In this paper we derive kinetic parameters for the generation of gaseous hydrocarbons (C_1‐5) and methane (C₁) from closed‐system laboratory pyrolysis of selected samples of marine kerogen and oil from the SW Tarim Basin. The activation energy distributions for the generation of both C_1‐5 (Ea = 59‐72kcal, A = 1.0×10¹⁴ s^?1) and C₁ (Ea = 61‐78kcal, A = 6.06×10¹⁴ s^?1) hydrocarbons from the marine oil are narrower than those for the generation of these hydrocarbons from marine kerogen (Ea = 50‐74kcal, A = 1.0×10¹⁴ s^?1 for C_1‐5; and Ea = 48‐72kcal, A=3.9×10¹³ s^?1 for C₁, respectively). Using these kinetic parameters, both the yields and timings of C_1‐5 and C₁ hydrocarbons generated from Cambrian source rocks and from in‐reservoir cracking of oil in Ordovician strata were predicted for selected wells along a north‐south profile in the SW of the basin. Thermodynamic conditions for the cracking of oil and kerogen were modelled within the context of the geological framework. It is suggested that marine kerogen began to crack at temperatures of around 120°C (or 0.8 %Ro) and entered the gas window at 138°C (or 1.05 %Ro); whereas the marine oil began to crack at about 140 °C (or 1.1 %Ro) and entered the gas window at 158 °C (or 1.6%Ro). The main geological controls identified for gas accumulations in the Bachu Arch (Southwest Depression, SW Tarim Basin) include the remaining gas potential following Caledonian uplift; oil trapping and preservation in basal Ordovician strata; the extent of breaching of Ordovician reservoirs; and whether reservoir burial depths are sufficiently deep for oil cracking to have occurred. In the Maigaiti Slope and Southwest Depression, the timing of gas generation was later than that in the Bachu Arch, with much higher yields and generation rates, and hence better prospects for gas exploration. It appears from the gas generation kinetics that the primary source for the gases in the Hetianhe gasfield was the Southwest Depression.     

A Study of Microfacies and Petrophysical Analysis of Some Subsurface Cretaceous Rocks of Abu Gharadig-34 Well,Western Desert,Egypt

Abstract

The main aim of this study is to shed light on the microfacies association, petrophysical parameters, and depositional environment of different rocks such as sandstone, limestone, shale, siltstone, and dolomite of subsurface Cretaceous rock units (Abu Roash “C” member, Abu Roash “E” Member, and Bahariya Formation) from Abu Gharadig-34 well in the north western desert, Egypt. In this study, nine microfacies were identified. These microfacies include calcareous siltstone, bioclastic wackstone, ferruginous sublithic arenite, dolomitic lithic arenite, lithic arenite, fossiliferous bioclastic wackstone, glauconitic dolomitic sublithic arenite, ferroan dolomite, and ferruginous sandy siltstone. Generally, subsurface Cretaceous rock units are deposited in different depositional environments ranging from tidal flats to open circulation passes through restricted circulation shelves. Statistical analysis of the petrophysical data showed that the highest porosity was concentrated at Abu Roash “C” member, which had very good porosity and high permeability. The porosity increased when the bulk density decreased. The permeability of the studied samples was the same as the porosity, which increased when the bulk density decreased. It can be concluded that Abu Roash “C” member is a good reservoir in the Abu Gharadig-34 well.     

HYDROCARBON POTENTIAL OF THE LATE CRETACEOUS GONGILA AND FIKA FORMATIONS,BORNU (CHAD) BASIN,NE NIGERIA

The hydrocarbon potential of possible shale source rocks from the Late Cretaceous Gongila and Fika Formations of the Chad Basin of NE Nigeria is evaluated using an integration of organic geochemistry and palynofacies observations. Total organic carbon (TOC) values for about 170 cutting samples range between 0.5% and 1.5% and Rock-Eval hydrogen indices (HI) are below 100 mgHC/gTOC, suggesting that the shales are organically lean and contain Type III/IV kerogen. Amorphous organic matter (AOM) dominates the kerogen assemblage (typically >80%) although its fluorescence does not show a significant correlation with measured HI. Atomic H/C ratios of a subset of the samples indicate higher quality oil- to gas-prone organic matter (Type II-III kerogens) and exhibit a significant correlation with the fluorescence of AOM (r²= 0.86). Rock-Eval T_max calibrated against AOM fluorescence, biomarker and aromatic hydrocarbon maturity data suggests a transition from immature (<435°C) to mature (>435°C) in the Fika Formation and mature to post-mature (>470°C) in the Gongila Formation. The low TOC values in most of the shales samples limit their overall source rock potential. The immature to early mature upper part of the Fika Formation, in which about 10% of the samples have TOC values greater than 2.0%, has the best oil generating potential. Oil would have been generated if such intervals had become thermally mature. On the basis of the samples studied here, the basin has potential for mostly gaseous rather than liquid hydrocarbons.     

Biomarkers Assessment of Crude Oils and Extracts from Jurassic-Cretaceous Rocks,North Qattara Depression,North Western Desert,Egypt

Abstract

Crude oils together with extracts from the Middle Jurassic (Khatatba Formation), Barremian-Early Aptian Alam El Bueib Formation, and Early Albian Kharita Formation were collected from five wells (Ras Qattara-Zarif-5, Ras Qattara-Zarif-3, and Zarif-1, Zarif-2, SW Zarif-1) in the North Qattara Depression. Biomarkers (pristane/phytane, isoprenoids/n-alkanes, steranes, triterpanes, C₂₉ steranes 20S/20S + 20R, C₂₃ tricyclic/C₃₀ hopane, Ts/Tm, C₃₀ moretane/C₃₀ hopane ratios, homohopane and gammacerane indices) of the saturated hydrocarbon fraction were analyzed in order to assess the source and maturity of the crude oils and the extracts. The results suggested that the oils from Khatatba and Alam El Bueib formations are mature, derived from source rocks containing marine and terrestrial organic matter, respectively. The source environments and maturity of the oil from the Khatatba Formation is similar to that of the Khatatba source rock extract. The oil from the Alam El Bueib formation differs from the extracts of the Alam El Bueib and Kharita formations. The Khatatba formation seems to be an effective source rock in the North Qattara Depression.     

A Review of: “Electrochemical Hydrogen Technologies”Edited by Hartmut Wendt Elsevier Science Publishers,B.v,Amsterdam, The Netherlands 1990, xx + 512 pp.

Abstract:

The organic geochemical and biomarker analyses of the Miocene source rocks of some wells in the onshore Nile Delta, suggested that the Abu Madi Formation has poor immature to marginally mature source rocks of Type III Kerogen deposited under the terrestrial environment. The Sidi Salem Formation has fair-to-good mature source rocks of producing mixed oil and gas, originating mainly from marine organic sources. The Moghra Formation has mature good source rocks for Type (II/III) kerogen, derived from organic matter and rich in both terrigeneous and marine sources. The geochemistry of condensates revealed that the Abu Madi and Moghra condensates originated from marine organic matters with little input from a terrestrial source, while Sidi Salem condensate was derived from more contribution of terrestrial organic matters. Abu Madi condensate is less mature than Sidi Salem and Moghra condensate. The geochemical thermal modeling of the Miocene source rocks indicates that the Abu Madi formations are in the early stages of hydrocarbon up until the present time, while Moghra and Sidi Salem formations are in the mature stage of hydrocarbon generation up until the present time. This indicates that the studied condensates have probably migrated from deeply buried source rocks which are at a higher level of maturity rather than from less mature source rocks in the study area.