ORGANIC GEOCHEMISTRY OF POTENTIAL SOURCE ROCKS IN THE TERTIARY DINGQINGHU FORMATION,NIMA BASIN,CENTRAL TIBET

The Tertiary Nima Basin in central Tibet covers an area of some 3000 km² and is closely similar to the nearby Lunpola Basin from which commercial volumes of oil have been produced. In this paper, we report on the source rock potential of the Oligocene Dingqinghu Formation from measured outcrop sections on the southern and northern margins of the Nima Basin. In the south of the Nima Basin, potential source rocks in the Dingqinghu Formation comprise dark‐coloured marls with total organic carbon (TOC) contents of up to 4.3 wt % and Hydrogen Index values (HI) up to 849 mg HC/g TOC. The organic matter is mainly composed of amorphous sapropelinite corresponding to Type I kerogen. Rock‐Eval T_max (430–451°C) and vitrinite reflectance (R_r) (average R_r= 0.50%) show that the organic matter is marginally mature. The potential yield (up to 36.95 mg HC/g rock) and a plot of S2 versus TOC suggest that the marls have moderate to good source rock potential. They are interpreted to have been deposited in a stratified palaeolake with occasionally anoxic and hypersaline conditions, and the source of the organic matter was dominated by algae as indicated by biomarker analyses. Potential source rocks from the north of the basin comprise dark shales and marls with a TOC content averaging 9.7 wt % and HI values up to 389 mg HC/g TOC. Organic matter consists mainly of amorphous sapropelinite and vitrinite with minor sporinite, corresponding to Type II‐III kerogen. This is consistent with the kerogen type suggested by cross‐plots of HI versus T_max and H/C versus O/C. The T_max and R_r results indicate that the samples are immature to marginally mature. These source rocks, interpreted to have been deposited under oxic conditions with a dominant input of terrigenous organic matter, have moderate petroleum potential. The Dingqinghu Formation in the Nima Basin therefore has some promise in terms of future exploration potential.     

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.     

Source rock evaluation and organic geochemistry of Belayim Marine Oil Field,Gulf of Suez,Egypt

Geochemical evaluation of Belayim Marine Oil Field using TOC and Rock Eval Pyrolysis investigations for a total of 19 cutting samples (9 samples covering (Nubia-B Formation) from well BM-57, and 10 samples covering (Nubia-A, B Formations) from well BM-65) was performed. Furthermore, geochemistry analyses of two crude oil samples from Wells BM-29 and BM-70, which are recovered from the Upper Rudeis Formation were performed. The BM-70 oil sample is recovered by Drill Steam Testing, while the BM-29 oil sample is taken from the flow output. Moreover, the oil samples were subjected to GC/GC-MS analysis (Biomarker) by StratoChem Company.In general, TOC analyses showed that the Nubia-A and B formation sediments are fairly immature compared to good source rocks with very high Hydrogen Index indicative of kerogen type II. The geochemical investigations of two oil samples indicate that the Upper Rudeis oil of Belayim Marine was derived from a marine carbonate rich source, which is relatively rich in algal organic matter and has moderate sulfur content. The maturity of the analyzed oils (about 0.75% R0) falls short from the stage of peak hydrocarbon generation which is known to be reached at about 0.85% R0.     

HYDROCARBON POTENTIAL OF THE UPPER CRETACEOUS SUCCESSION AT WELL 16/U‐1, ONSHORE QAMAR BASIN,EASTERN YEMEN

An Upper Cretaceous succession has been penetrated at onshore well 16/U‐1 in the Qamar Basin, eastern Republic of Yemen. The succession comprises the Mukalla and Dabut Formations which are composed of argillaceous carbonates and sandstones with coal layers, and TOC contents range up to 80%. The average TOC of the Mukalla Formation (24%) is higher than that of the Dabut Formation (1%). The Mukalla Formation has a Rock‐Eval T_max of 439–454 °C and an HI of up to 374 mgHC/gTOC, pointing to kerogen Types II and III. The Dabut Formation mainly contains kerogen Type III with a T_max of 427–456°C and HI of up to 152 mgHC/gTOC. Vitrinite reflectance values ranging between 0.3 and 1.0% and thermal alteration index values between 3 and 6 indicate thermal maturities sufficient for hydrocarbon generation. Three palynofacies types were identified representing marine, fluvial‐deltaic and marginal‐marine environments during the deposition of the Mukalla and Dabut Formations in the late Santonian — early Maastrichtian.     

A PRELIMINARY EVALUATION OF JURASSIC SOURCE ROCK POTENTIAL IN KUWAIT

Jurassic sedimentary rocks in Kuwait are generally assigned to the Marrat, Dhruma, Sargelu and Najmah Formations (mainly limestones and calcareous shales) and the overlying Hith and Gotnia Formations which are composed of anhydrites and evaporites. This paper reports the results of organic-geochemical analyses of Jurassic carbonate and shale samples recovered from ten wells in Kuwait. Analytical techniques included TOC analysis, elemental analyses of kerogen, density separation and petrographic analyses. The thermal history of Kuwait was modelled and calibrated with maturity indicators from the studied wells.
The analytical results point to the presence of marine kerogen between Types II and III. Generally, the formations show amorphous rich sapropelic organic matter with high H/C ratios and low densities. Biodegradation of some samples resulted in elevated O/C ratios. The results of maturity studies indicate that most of the Jurassic Succession is mature, maturity differences being due to depth variations. Oil generation began in Late Cretaceous to Eocene time when structural traps had already been formed. Jurassic source rocks may therefore have supplied reservoir units in Kuwait. In particular, the Najmah Formation includes well-preserved amorphous marine algal type organic matter. The high TOC values and thermal maturity of this formation make it one of the most important potential sources of oil in Kuwait.     

SHALE‐GAS POTENTIAL OF THE MID‐CARBONIFEROUS BOWLAND‐HODDER UNIT IN THE CLEVELAND BASIN (YORKSHIRE), CENTRAL BRITAIN

The shale‐gas potential of mid‐Carboniferous mudrocks in the Bowland‐Hodder unit in the Cleveland Basin (Yorkshire, northern England) was investigated through the analysis of a cored section from the uppermost part of the unit in the Malton‐4 well using a multidisciplinary approach. Black shales are interbedded with bioturbated and bedded sandstones, representing basinal‐offshore to prodelta – delta‐front lithofacies. The total organic carbon (TOC) content of the shales ranges from 0.37 to 2.45 wt %. Rock‐Eval pyrolysis data indicate that the organic matter is mainly composed of Type III kerogen with an admixture of Type II kerogen. T_max (436–454°C), 20S/(20S+20R) C₂₉ sterane ratios, and vitrinite reflectance values indicate that organic matter is in the mid‐ to late‐ mature (oil) stage with respect to hydrocarbon generation. Sedimentological and geochemical redox proxies suggest that the black shales were deposited in periodically oxic‐dysoxic and anoxic bottom waters with episodic oxic conditions, explaining the relatively low TOC values. The Rock‐Eval parameters indicate that the analysed mudrocks have a limited shale‐gas potential. However, burial and thermal history modelling, and VR_r data from other wells in the region, indicate that where they are more deeply‐buried, the Bowland‐Hodder shales will be within the gas window with VR_r > 1.1 % at depths in excess of 2000 m. Therefore although no direct evidence for a high shale‐gas potential in the Cleveland Basin has been found, this cannot be precluded at greater depths especially if deeper horizons are more organic rich.     

HIGH‐RESOLUTION STRATIGRAPHY,PALYNOFACIES AND SOURCE ROCK POTENTIAL OF THE ÁGUA DE MADEIROS FORMATION (LOWER JURASSIC), LUSITANIAN BASIN,PORTUGAL

In the Lusitanian Basin (central‐western Portugal), the Lower Jurassic carbonate‐dominated succession is thought to have significant source rock potential. One of the most important units is the Água de Madeiros Formation (Upper Sinemurian – lowermost Pliensbachian) which is composed of alternating organic‐rich marls and limestones including black shale horizons. This paper is based on a study of this formation at its type locality at S. Pedro de Moel in western Portugal. Data includes Total Organic Carbon (TOC) measurements, palynofacies analyses and results of Rock‐Eval pyrolysis presented within a high‐resolution lithostratigraphic framework. TOC contents were measured in some 200 samples from the Água de Madeiros Formation covering a stratigraphic interval of 58 m, and vary widely up to a maximum of about 22 wt %. Kerogen assemblages are dominated by marine amorphous organic matter with varying contributions by phytoclasts and palynomorphs. A majority of the 85 samples analyzed by Rock‐Eval pyrolysis have S₂ values above 10 mg HC/g rock, reaching a maximum of 78 mg HC/g rock. These high S₂ values are correlative with maximum values of the Hydrogen Index which averages 355 mg HC/g TOC (maximum of 637 mg HC/g TOC). However in spite of these indicators of source‐rock potential, the Água de Madeiros Formation in the study area is thermally immature or very early mature, as indicated by T_max values below 437 °C and average vitrinite reflectance values of 0.43 % R_o.     

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.     

DEPOSITIONAL ENVIRONMENT AND SOURCE‐ROCK CHARACTERISATION OF ORGANIC‐MATTER RICH UPPER SANTONIAN – UPPER CAMPANIAN CARBONATES,NORTHERN LEBANON

Samples of Turonian – upper Campanian fine‐grained carbonates (marls, mud‐ to wackestones; n = 212) from four boreholes near Chekka, northern Lebanon, were analysed to assess their organic matter quantity and quality, and to interpret their depositional environment. Total organic carbon (TOC), total inorganic carbon and total sulphur contents were measured in all samples. A selection of samples were then analysed in more detail using Rock‐Eval pyrolysis, maceral analyses, gas chromatography – flame ionization detection (GC‐FID), and gas chromatography – mass spectrometry (GC‐MS) on aliphatic hydrocarbon extracts. TOC measurements and Rock‐Eval pyrolysis indicated the very good source rock potential of a ca. 150 m thick interval within the upper Santonian – upper Campanian succession intercepted by the investigated boreholes, in which samples had average TOC values of 2 wt % and Hydrogen Index values of 510 mgHC/gTOC. The dominance of alginite macerals relative to terrestrial macerals, the composition of C₂₇–C₂₉ regular steranes, the elevated C₃₁ 22R homohopane / C₃₀ hopane ratio (> 0.25), the low terrigenous / aquatic ratio of n‐alkanes, as well as δ¹³C_org values between ?29‰ and ?27‰ together suggest a marine depositional environment and a mainly algal / phytoplanktonic source of organic matter. Redox sensitive geochemical parameters indicate mainly dysoxic depositional conditions. The samples have high Hydrogen Index values (413–610 mg/g TOC) which indicate oil‐prone Type II kerogen. T_max values (414 – 432°C) are consistent with other maturity parameters such as vitrinite reflectance (0.25–0.4% VRr) as well as sterane and hopane isomerisation ratios, and indicate that the organic matter is thermally immature and has not reached the oil window. This study contributes to the relatively scarce geochemical information for the eastern margin of the Levant Basin, but extrapolation of the data to offshore areas remains uncertain.     

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.     

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.     

GEOCHEMICAL CHARACTERIZATION OF CENOMANIAN/TURONIAN BLACK SHALES FROM THE TARFAYA BASIN (SW MOROCCO)

Organic geochemical and petrological investigations were carried out on Cenomanian/Turonian black shales from three sample sites in the Tarfaya Basin (SW Morocco) to characterize the sedimentary organic matter. These black shales have a variable bulk and molecular geochemical composition reflecting changes in the quantity and quality of the organic matter. High TOC contents (up to 18wt%) and hydrogen indices between 400 and 800 (mgHC/gTOC) indicate hydrogen‐rich organic matter (Type I‐II kerogen) which qualifies these laminated black shale sequences as excellent oil‐prone source rocks. Low T_max values obtained from Rock‐Eval pyrolysis (404–425 MC) confirm an immature to early mature level of thermal maturation. Organic petrological studies indicate that the kerogen is almost entirely composed of bituminite particles. These unstructured organic aggregates were most probably formed by intensive restructuring of labile biopolymers (lipids and/or carbohydrates), with the incorporation of sulphur into the kerogen during early diagenesis. Total lipid analyses performed after desulphurization of the total extract shows that the biomarkers mostly comprise short‐chain n‐alkanes (C16–C22) and long‐chain (C25–C35) n‐alkanes with no obvious odd‐over‐even predominance, together with steranes, hopanoids and acyclic isoprenoids. The presence of isorenieratane derivatives originating from green sulphur bacteria indicates that dissolved sulphide had reached the photic zone at shallow water depths (～100m) during times of deposition. These conditions probably favoured intensive sulphurization of the organic matter. Flash pyrolysis GC‐MS analysis of the kerogen indicates the aliphatic nature of the bulk organic carbon. The vast majority of pyrolysis products are sulphur‐containing components such as alkylthiophenes, alkenylthiophenes and alkybenzothiophenes. Abundant sulphurization of the Tarfaya Basin kerogen resulted from excess sulphide and metabolizable organic matter combined with a limited availability of iron during early diagenesis. The observed variability in the intensity of OM sulphurization may be attributed to sea level‐driven fluctuations in the palaeoenvironment during sedimentation.     

COMPOSITION AND PETROLEUM POTENTIAL OF LAKE FACIES IN THE FA-MS-48-73 WELL, MAE SOON STRUCTURE, FANG OILFIELD, NORTHERN THAILAND

The Fang Basin is one of a series of Cenozoic rift‐related structures in northern Thailand. The Fang oilfield includes a number of structures including the Mae Soon anticline on which well FA‐MS‐48‐73 was drilled, encountering oil‐filled sandstone reservoirs at several levels. Cuttings samples were collected from the well between depths of 532 and 1146 m and were analysed for their content of total organic carbon (TOC, wt%), total carbon (TC, wt%) and total sulphur (TS, wt%); the petroleum generation potential was determined by Rock‐Eval pyrolysis. Organic petrography was performed in order to determine qualitatively the organic composition of selected samples, and the thermal maturity of the rocks was established by vitrinite reflectance (VR) measurements in oil immersion. The TOC content ranges from 0.75 to 2.22 wt% with an average of 1.43 wt%. The TS content is variable with values ranging from 0.12 to 0.63 wt%. Rock‐Eval derived S₁ and S₂ yields range from 0.01–0.20 mg HC/g rock and 1.41–9.51 mg HC/g rock, respectively. The HI values range from 140 to 428 mg HC/g TOC, but the majority of the samples have HI values >200 mg HC/g TOC and about one‐third of the samples have HI values above 300 mg HC/g TOC. The drilled section thus possesses a fair to good potential for mixed oil/gas and oil generation. On an HI/T_max diagram, the organic matter is classified as Type II and III kerogen. The organic matter consists mainly of telalginite (Botryococcus‐type), lamalginite, fluorescing amorphous organic matter (AOM) and liptodetrinite which combined with various TS‐plots suggest deposition in a freshwater lacustrine environment with mild oxidising conditions. T_max values range from 419 to 436°C, averaging 429°C, and VR values range from ～0.38 to 0.66% R₀, indicating that the drilled source rocks are thermally immature with respect to petroleum generation. The encountered oils were thus generated by more deeply buried source rocks.     

Source Rock Characteristics,Organic Maturity,and Hydrocarbon Potential of the Lower Paleozoic Sequences in the Taurus Belt of Turkey

Abstract

Like elsewhere in the world, Lower Paleozoic (Cambrian-Ordovician-Silurian) formations in Turkey are also exposed in limited areas. Lower Paleozoic sequences are exposed at various parts of the Taurus belt in southern Turkey. In this study, organic matter content, type, and maturity of organic matter and their hydrocarbon potential were investigated. In addition, the Lower Paleozoic is very restricted with respect to species and their diversity. Therefore, it is very important to investigate type and content of organic matter within the Lower Paleozoic sediments. In general, total organic carbon (TOC) values of Lower Paleozoic sequences are extremely low. TOC could not be measured in Cambrian, Ovac?k, and Çaltepe limestones. Shales in the Emirgazi region have very low TOC values. Ordovician and Silurian units also have low TOC values. Total organic carbon in these sequences is residual carbon. In the S ₂-TOK kerogen diagram, all organic materials are plotted in the Type III kerogen field. All samples were composed dominantly of residual organic matter and lesser amounts of Type III kerogen. According to T _max values, the Cambrian, Ordovician, and Silurian formations are over maturity character. In addition, these sequences have very low S ₁, S ₂, and HI values.     

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).     

SOURCE ROCK POTENTIAL OF ORGANIC‐RICH SHALES IN THE TERTIARY BHUBAN AND BOKA BIL FORMATIONS,BENGAL BASIN,BANGLADESH

Sandstones in the Miocene Bhuban and Lower Pliocene Boka Bil Formations contain all of the hydrocarbons so far discovered in the Bengal Basin, Bangladesh. Organic‐rich shale intervals in these formations have source rock potential and are the focus of the present study which is based on an analysis of 36 core samples from wells in eight gasfields in the eastern Bengal Basin. Kerogen facies and thermal maturity of these shales were studied using standard organic geochemical and organic petrographic techniques. Organic matter is dominated by Type III kerogen with lesser amounts of Type II. TOC is 0.16–0.90 wt % (Bhuban Formation) and 0.15–0.55 wt % (Boka Bil Formation) and extractable organic matter (EOM) is 132–2814 ppm and 235–1458 ppm, respectively. The hydrogen index is 20–181 mg HC/g TOC in the Bhuban shales and 35–282 mg HC/ g TOC in the Boka Bil shales. Vitrinite was the dominant maceral group observed followed by liptinite and inertinite. Gas chromatographic parameters including the C/S ratio, n‐alkane CPI, Pr/Ph ratio, hopane Ts/Tm ratio and sterane distribution suggest that the organic matter in both formations is mainly derived from terrestrial sources deposited in conditions which alternated between oxic and sub‐oxic. The geochemical and petrographic results suggest that the shales analysed can be ranked as poor to fair gas‐prone source rocks. The maturity of the samples varies, and vitrinite reflectance ranges from 0.48 to 0.76 %VR_r. Geochemical parameters support a maturity range from just pre‐ oil window to mid‐ oil window.     

UPPER TRIASSIC POTENTIAL SOURCE ROCKS IN THE QIANGTANG BASIN,TIBET: ORGANIC GEOCHEMICAL CHARACTERISTICS

Upper Triassic coal‐bearing strata in the Qiangtang Basin (Tibet) are known to have source rock potential. For this study, the organic geochemical characteristics of mudstones and calcareous shales in the Upper Triassic Tumengela and Zangxiahe Formations were investigated to reconstruct depositional settings and to assess hydrocarbon potential. Outcrop samples of the Tumengela and Zangxiahe Formations from four locations in the Qiangtang Basin were analysed. The locations were Xiaochaka in the southern Qiangtang depression, and Woruo Mountain, Quemo Co and Zangxiahe in the northern Qiangtang depression. At Quemo Co in the NE of the basin, calcareous shale samples from the Tumengela Formation have total organic carbon (TOC) contents of up to 1.66 wt.%, chloroform bitumen A contents of up to 734 ppm, and a hydrocarbon generation capacity (Rock‐Eval S₁+ S₂) of up to 1.94 mg/g. The shales have moderate to good source rock potential. Vitrinite reflectance (R_r) values of 1.30% to 1.46%, and Rock‐Eval T_max values of 464 to 475 °C indicate that the organic matter is at a highly mature stage corresponding to condensate / wet gas generation. The shales contain Type II kerogen, and have low carbon number molecular compositions with relatively high C_21?/C₂₁₊ (2.15–2.93), Pr/Ph ratios of 1.40–1.72, high S/C ratios (>0.04) in some samples, abundant gammacerane (GI of 0.50–2.04) and a predominance of C₂₇ steranes, indicating shallow‐marine sub‐anoxic and hypersaline depositional conditions with some input of terrestrial organic matter. Tumengela and Zangxiahe Formation mudstone samples from Xiaochaka in the southern Qiangtang depression, and from Woruo Mountain and Zangxiahe in the northern depression, have low contents of marine organic matter (Type II kerogen), indicating relatively poor hydrocarbon generation potential. R_r values and T_max data indicate that the organic matter is overmature corresponding to dry gas generation.     

Mineralogical,geochemical and hydrocarbon potential of subsurface Cretaceous shales,Northern Western Desert,Egypt

Twenty four Cretaceous shale core samples of Gibb Afia-1, Betty-1, Salam-1X and Mersa Matruh-1 wells were mineralogically and geochemically studied using XRD, XRF and Rock Eval Pyrolysis. Kaolinite, smectite and illite are the main clay minerals in addition to rare chlorite, while the non-clay minerals include quartz, calcite, dolomite and rare siderite. The shales were derived through intensive chemical weathering of mafic basement and older sedimentary rocks. These sediments were deposited in a near-shore shallow marine environment with some terrestrial material input. The shales have poor to fair organic content. It is marginally to rarely mature.     

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 PROPERTIES OF LACUSTRINE MUDSTONES AND COALS (OLIGOCENE DONG HO FORMATION), ONSHORE SONG HONG BASIN, NORTHERN VIETNAM

Oligocene lacustrine mudstones and coals of the Dong Ho Formation outcropping around Dong Ho, at the northern margin of the mainly offshore Cenozoic Song Hong Basin (northern Vietnam), include highly oil‐prone potential source rocks. Mudstone and coal samples were collected and analysed for their content of total organic carbon and total sulphur, and source rock screening data were obtained by Rock‐Eval pyrolysis. The organic matter composition in a number of samples was analysed by reflected light microscopy. In addition, two coal samples were subjected to progressive hydrous pyrolysis in order to study their oil generation characteristics, including the compositional evolution in the extracts from the pyrolysed samples. The organic material in the mudstones is mainly composed of fluorescing amorphous organic matter, liptodetrinite and alginite with Botryococcus‐morphology (corresponding to Type I kerogen). The mudstones contain up to 19.6 wt.% TOC and Hydrogen Index values range from 436–572 mg HC/g TOC. From a pyrolysis S₂ versus TOC plot it is estimated that about 55% of the mudstones’TOC can be pyrolised into hydrocarbons; the plot also suggests that a minimum content of only 0.5 wt.% TOC is required to saturate the source rock to the expulsion threshold. Humic coals and coaly mudstones have Hydrogen Index values of 318–409 mg HC/g TOC. They are dominated by huminite (Type III kerogen) and generally contain a significant proportion of terrestrial‐derived liptodetrinite. Upon artificial maturation by hydrous pyrolysis, the coals generate significant quantities of saturated hydrocarbons, which are probably expelled at or before a maturity corresponding to a vitrinite reflectance of 0.97%R₀. This is earlier than previously indicated from Dong Ho Formation coals with a lower source potential. The composition of a newly discovered oil (well B10‐STB‐1x) at the NE margin of the Song Hong Basin is consistent with contributions from both source rocks, and is encouraging for the prospectivity of offshore half‐grabens in the Song Hong Basin.