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.     

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.     

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.     

廊固凹陷原油成因类型与分布规律

基于34个烃源岩与50个原油样品的分子生物标志化合物分析结果,研究了廊固凹陷主要油田的原油成因类型与分布规律。分析结果表明,沙河街组三段下亚段与沙河街组四段上亚段烃源岩有不同的分子生物标志化合物组合特征:沙河街组三段下亚段烃源岩陆源有机质的输入量较高且富含沟鞭藻类,沉积于淡水较强的还原环境;沙河街组四段上亚段烃源岩陆源有机质输入量较少且低等水生生物输入较多,沉积于咸水强还原环境。在油源对比基础上,结合原油分子生物标志物参数进行聚类分析,划分了3种成因类型的原油。第Ⅰ类原油来自沙河街组四段上亚段烃源岩,主要分布于牛坨镇凸起周边地区;第Ⅱ类原油来自沙河街组三段下亚段烃源岩,主要分布在凹陷偏北部的旧州—王居一带;第Ⅲ类原油来自沙河街组三段下亚段烃源岩与沙河街组四段上亚段烃源岩生成的混源油,以沙河街组三段下亚段烃源岩生成的原油为主,主要分布在凹陷东部的河西务构造带和曹家务—柳泉构造带南部的部分地区。廊固凹陷各油藏紧邻烃源岩聚集成藏,其分布规律受控于不同层段烃源岩的发育与分布。曹家务和中岔口地区是第一类原油下一步的有利勘探目标区域,柳泉构造带王居地区是第二类原油勘探潜力较大区域。     

HYDROCARBON GENERATION POTENTIAL AND DEPOSITIONAL ENVIRONMENT OF SHALES IN THE CRETACEOUS NAPO FORMATION,EASTERN ORIENTE BASIN,ECUADOR

Marine shale samples from the Cretaceous (Albian‐Campanian) Napo Formation (n = 26) from six wells in the eastern Oriente Basin of Ecuador were analysed to evaluate their organic geochemical characteristics and petroleum generation potential. Geochemical analyses included measurements of total organic carbon (TOC) content, Rock‐Eval pyrolysis, pyrolysis — gas chromatography (Py—GC), gas chromatography — mass‐spectrometry (GC—MS), biomarker distributions and kerogen analysis by optical microscopy. Hydrocarbon accumulations in the eastern Oriente Basin are attributable to a single petroleum system, and oil and gas generated by Upper Cretaceous source rocks is trapped in reservoirs ranging in age from Early Cretaceous to Eocene. The shale samples analysed for this study came from the upper part of the Napo Formation T member (“Upper T”), the overlying B limestone, and the lower part of the U member (“Lower U”).The samples are rich in amorphous organic matter with TOC contents in the range 0.71–5.97 wt% and Rock‐Eval T_max values of 427–446°C. Kerogen in the B Limestone shales is oil‐prone Type II with δ¹³C of ?27.19 to ?27.45‰; whereas the Upper T and Lower U member samples contain Type II–III kerogen mixed with Type III (δ¹³C > ?26.30‰). The hydrocarbon yield (S₂) ranges from 0.68 to 40.92 mg HC/g rock (average: 12.61 mg HC/g rock). Hydrogen index (HI) values are 427–693 mg HC/g TOC for the B limestone samples, and 68–448 mg HC/g TOC for the Lower U and Upper T samples. The mean vitrinite reflectance is 0.56–0.79% R₀ for the B limestone samples and 0.40–0.60% R₀ for the Lower U and Upper T samples, indicating early to mid oil window maturity for the former and immature to early maturity for the latter. Microscopy shows that the shales studied contain abundant organic matter which is mainly amorphous or alginite of marine origin. Extracts of shale samples from the B limestone are characterized by low to medium molecular weight compounds (n‐C₁₄ to n‐C₂₀) and have a low Pr/Ph ratio (≈ 1.0), high phytane/n‐C₁₈ ratio (1.01–1.29), and dominant C₂₇ regular steranes. These biomarker parameters and the abundant amorphous organic matter indicate that the organic matter was derived from marine algal material and was deposited under anoxic conditions. By contrast, the extracts from the Lower U and Upper T shales contain medium to high molecular weight compounds (n‐C₂₅ to n‐C₃₁) and have a high Pr/ Ph ratio (>3.0), low phytane/n‐C₁₈ ratio (0.45–0.80) with dominant C₂₉ regular steranes, consistent with an origin from terrigenous higher plant material mixed with marine algae deposited under suboxic conditions. This is also indicated by the presence of mixed amorphous and structured organic matter. This new geochemical data suggests that the analysed shales from the Napo Formation, especially the shales from the B limestone which contain Type II kerogen, have significant hydrocarbon potential in the eastern part of the Oriente Basin. The data may help to explain the distribution of hydrocarbon reserves in the east of the Oriente Basin, and also assist with the prediction of non‐structural traps.     

Oil: Source rock correlations of Al Baraka oil field,Komombo basin,South Egypt: An implication from biomarkers characteristics

The objectives of this study are the correlation between the oil samples recovered from the Lower Cretaceous reservoirs and Lower and Upper Cretaceous source rocks. The investigated biomarkers of five oils indicated the oils were derived from mixed marine and terrigenous (lacustrine) organic matter and deposited under suboxic to anoxic conditions. These oils were also generated from source rocks of high thermal maturity at the peak oil window. So, based on the molecular indicators of organic source input,depositional environment and maturity parameters of oils and extracts, we can conclude that the oil recovered from Al Baraka oil field were derived from Lower Cretaceous source rocks especially KomOmbo (B) source rocks where it reached the oil window. Furthermore, we can indicate that the other lower Cretaceous formations as Abu Ballas Formation will have the opportunity to generate and expel oil at the deeper part of the basin as shown in the eastern part of the basin.     

Geochemistry of Cretaceous rocks,Pakistan: II. Interpretation of source,depositional environment and lithology of organic matter

The sediment samples from Cretaceous sequences, Lower Indus Basin, were investigated using biomarkers approach to predict the source, depositional environment and lithology of organic matter. The Parh and Upper Goru Formations demonstrate the presence of algal organic matter deposited under anoxic and suboxic conditions. The interpretation was supported by relatively high distribution of C₂₇ 5α (H), 14α (H), 17α (H) 20R (ααα-20R) steranes. The samples of Lower Goru Formation reveal mixed organic matter, predominantly terrestrial and oxic, as apparent from biomarkers distribution. The Sembar Formation specifies mixed input of organic matter more terrigenous input at intervals, deposited under anoxic and suboxic conditions. Geochemical analyses performed on Cretaceous strata show that hydrocarbons were derived from organic matter of mixed origin, predominantly terrestrial, deposited under anoxic and oxic conditions.     

Organic Geochemistry of Source Rocks, Condensates, and Thermal Geochemical Modeling of Miocene Sequence of Some Wells, Onshore Nile Delta, Egypt

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.     

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.     

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.     

RELATIONSHIP BETWEEN ORGANIC MATTER,SULPHUR AND PHOSPHATE CONTENTS IN UPPER CRETACEOUS MARINE CARBONATES (KARABOGAZ FORMATION,SE TURKEY): IMPLICATIONS FOR EARLY OIL GENERATION

In this paper, we discuss the relationship between the organic matter, sulphur and phosphate contents of Upper Cretaceous marine carbonates (Karabogaz Formation) in the Adiyaman Petroleum Province of SE Turkey. The results of organic geochemical analyses of core samples obtained from the Karabogaz Formation suggest that phosphate deposition occurred in settings where the water column was oxic to sub-oxic. However, the preservation of organic matter was favoured in anoxic environments. Moreover, the presence of sulphur (especially sulphur incorporated into kerogen) in organic matter-rich layers led to early oil generation. The results of stepwise py-gc analyses are consistent with a model in which, with increasing maturity, S-S and C-S bonds are the first to be eliminated from the macromolecular kerogen structure. Study of the maturity evolution of S-rich kerogen by laboratory pyrolysis implies that marginally mature and/or mature kerogen in the Karabogaz Formation, which may be classified as classic “Type II” kerogen, was most probably Type II/S at lower maturity stages. This enabled oil generation to occur at relatively shallow burial depths and relatively early stages of maturation. It is reasonable to conclude that Type II/S kerogen, overlooked in previous studies, was abundant in TOC-rich intervals in the Karabogaz Formation. Early generation (and expulsion) from Type II/S kerogen may have sourced the sulphur-rich oils in the Adiyaman area oilfields.     

Organic richness,kerogen types and maturity in the shales of the Dakhla and Duwi formations in Abu Tartur area,Western Desert,Egypt: Implication of Rock–Eval pyrolysis

The objective of this study is to assess the organic material for petroleum potential and characterize the relationships between organic material, thermal maturity, and the depositional environments. This is done using “14” samples from the shales of the Dakhla and Duwi formations in Abu Tartur area. The samples have been analyzed using the geochemical method of Rock–Eval pyrolysis. The analysis shows that the total organic carbon content lies between 0.56 and 1.96 wt%. It also shows that kerogen is a mixture of type II and III that is dominant, and is deposited in the shallow and restricted marine environment under prevailing reducing conditions. This type of kerogen is prone to oil and oil/gas production. The geochemical diagrams show that all the studied samples have good thermal maturation. The Dakhla and Duwi formations which have been divided into all zones are mature (have T_max over 435 °C), and have organic carbon content located at the oil window (T_max between 435 and 443 °C).     

川东北地区烃源岩与沥青生物标志物特征及古油藏油源辨识

川东北地区是我国重要的天然气产区,古油藏原油裂解成气是该区天然气的主要来源。针对该区古油藏油源研究存在的争议,对古生界—中生界主要烃源岩层系和长兴组—嘉陵江组储层沥青的生物标志物特征进行了分析和对比。结果表明：烃源岩有机质母源下古生界以水生生物为主;上古生界具有水生生物与高等植物混源的特征,以水生生物为主;中生界以高等植物为主,兼有水生生物。烃源岩沉积水体古生界主要为咸水,中生界主要为淡水。烃源岩沉积环境古生界以弱还原—还原环境为主,中生界以弱氧化—弱还原环境为主。生物标志物特征表明,上二叠统龙潭组烃源岩为长兴组—嘉陵江组古油藏主力烃源岩,下二叠统梁山组烃源岩也有一定的贡献。     

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.     

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

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

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.     

Palynostratigraphical studies on some subsurface middle Albian–early Cenomanian sediments from North Western Desert,Egypt

The Kharita and Bahariya formations are of great importance for Egyptian economy. They are the target of the oil and gas exploration in the Egyptian Western Desert. The present study investigated the palynostratigraphy, palynofacies and spore coloration of samples from these two formations in Negelah-1 Borehole. The investigations were used to evaluate their thermal maturity and potentiality to generate the hydrocarbons. The identified palynozones are Afropollis jardinus Acme Zone (late Albian–early Cenomanian) and Araucariacites australis Acme Zone (middle Albian). The first zone is differentiated into two subzones, which are Elaterosporites klaszii Interval Subzone and Cretacaeiporites densimurus Interval Subzone. The palynofacies analysis revealed that the Kharita Formation was deposited in proximal near shore marine environment under oxic conditions. Whereas the lower part of the Bahariya Formation was initially deposited in proximal near shore dysoxic marine conditions and the environment of deposition getting more distal to inner shelf dysoxic to anoxic marine conditions in the younger upper part. The samples from both formations include gas prone type III and IV. The spore color observations indicated that the samples from both formations are immature to yield gas and are not effective hydrocarbon source.     

岩石热声发射和盆模技术研究中扬子区西部下古生界海相页岩最高古地温和热成熟史

中扬子地区西部下古生界海相页岩热演化程度高,有机显微组分中无镜质组,沥青反射率具有不确定性,故热成熟度较难确定。综合运用岩石热声发射实验与干酪根红外光谱,并结合盆地模拟技术对中扬子地区西部典型井下古生界海相页岩经历的最高古温度及热演化成熟史进行了恢复。样品的热声发射信号随温度的升高变化显著,热凯瑟尔（Kaiser）效应明显;下寒武统水井沱组经历的最高古温度范围为293~324℃,上奥陶统五峰组-下志留统龙马溪组为210~256℃。同时利用二次加温验证热Kaiser效应敏感,表明热声发射技术可用于岩石经历的最高古地温的测定。在对典型井的下古生界海相页岩热演化成熟史模拟中结合最高古温度作为约束条件所得结果表明,模拟计算的下寒武统水井沱组和上奥陶统五峰组-下志留统龙马溪组镜质体反射率分别为4.0% ~4.5% 和2.6% ~3.2% ,处于高演化过成熟阶段,与干酪根红外光谱分析得出的有机质成熟度结果一致。     

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).