Levels Of Thermal Maturity Research Articles

Geochemical Evaluation of Campanian Sirte Shale Source Rock, Arshad Area, Sirt Basin, Libya

The present geochemical study deals with evaluation of Sirte Shale (Campanian) source rock in Arshad area which is located in the central Sirt Basin in north central Libya. Sirte Formation is composed mainly of shale, sandy shale, being partially sandy and calcareous facies indicating presence of possible source rocks. It contains enough amount of organic matter (>0.5 wt. %) to generate and expel hydrocarbons under suitable thermal maturity level in the area. The recorded kerogens belong to types III and IV. The pyrolysis results indicate deficient of hydrogen content and poor potential source rocks in all samples. The HI values of the analyzed samples prove predominance of type III (gas-prone) and type IV (non-hydrocarbon potential) kerogens. In general, pyrolysis results and derived parameters indicate poor generating potential for the Sirte Formation (Campanian) in the area and mature kerogen in the oil-window zone. The thermal burial history curves of selected wells in Arshad area indicate that Sirte Shale had been buried in the top peak oil generation or oil window (Late maturity, Ro: 0.9-1.35%) since 4 to 13.5 M. Y. ago at depth range 9100'-9600'. Time of hydrocarbon expulsion has started in the area since 15 M. Y. nearly during the Middle Miocene time (Serravallian age). In Sirt Basin, oil has migrated from the Campanian Sirte Shale source rock which has reached the oil-window at western flank of the South Ajdabiya Trough to the Mesozoic and Paleozoic reservoirs in Zaltan Platform and to the Upper Cretaceous Arshad sandstone reservoir in Arshad oil field as well. The migrated hydrocarbons most likely are entrapped in the structural closures of the different structural traps (folds and fault-blocks) in Zaltan Platform. Likewise, westward up-dip direction of gas migration took place from the Campanian Sirte Shale source rock as buried in the gas-window in the deep Wadayet (NW Ajdabiya Trough) to the Mesozoic and

Organic geochemistry and reservoir characterization of the organic matter-rich calcilutite in the Shulu Sag, Bohai Bay Basin, North China

Although extensive studies have been conducted on unconventional mudstone (shales) reservoirs in recent years, little work has been performed on unconventional tight organic matter-rich, fine-grained carbonate reservoirs. The Shulu Sag is located in the southwestern corner of the Jizhong Depression in the Bohai Bay Basin and filled with 400–1000 m of Eocene lacustrine organic matter-rich carbonates. The study of the organic matter-rich calcilutite in the Shulu Sag will provide a good opportunity to improve our knowledge of unconventional tight oil in North China. The dominant minerals of calcilutite rocks in the Shulu Sag are carbonates (including calcite and dolomite), with an average of 61.5 wt.%. The carbonate particles are predominantly in the clay to silt size range. Three lithofacies were identified: laminated calcilutite, massive calcilutite, and calcisiltite–calcilutite. The calcilutite rocks (including all the three lithofacies) in the third unit of the Shahejie Formation in the Eocene (Es3) have total organic carbon (TOC) values ranging from 0.12 to 7.97 wt.%, with an average of 1.66 wt.%. Most of the analyzed samples have good, very good or excellent hydrocarbon potential. The organic matter in the Shulu samples is predominantly of Type I to Type II kerogen, with minor amounts of Type III kerogen. The temperature of maximum yield of pyrolysate (Tmax) values range from 424 to 452 °C (with an average of 444 °C) indicating most of samples are thermally mature with respect to oil generation. The calcilutite samples have the free hydrocarbons (S1) values from 0.03 to 2.32 mg HC/g rock, with an average of 0.5 mg HC/g rock, the hydrocarbons cracked from kerogen (S2) yield values in the range of 0.08–57.08 mg HC/g rock, with an average of 9.06 mg HC/g rock, and hydrogen index (HI) values in the range of 55–749 mg HC/g TOC, with an average of 464 mg HC/g TOC. The organic-rich calcilutite of the Shulu Sag has very good source rock generative potential and have obtained thermal maturity levels equivalent to the oil window. The pores in the Shulu calcilutite are of various types and sizes and were divided into three types: (1) pores within organic matter, (2) interparticle pores between detrital or authigenic particles, and (3) intraparticle pores within detrital grains or crystals. Fractures in the Shulu calcilutite are parallel to bedding, high angle, and vertical, having a significant effect on hydrocarbon migration and production. The organic matter and dolomite contents are the main factors that control calcilutite reservoir quality in the Shulu Sag.

LOWER CARBONIFEROUS SHALES IN THE EASTERN TAURIDE BELT, SOUTHERN TURKEY: SOURCE ROCK CHARACTERISTICS

Lower Carboniferous (Tournaisian‐Visean) shales, sandstones and limestones are exposed at the surface in autochthonous units in the Eastern Taurides, southern Turkey. This study investigates the organic geochemical characteristics, thermal maturity and depositional environments of shale samples from two outcrop locations in this area (Belen and Naltas). The total organic carbon (TOC) contents range from 0.11 to 5.61 wt % for the Belen samples and 0.04 to 1.74 wt % for the Naltas samples. Tmax values ranging from 432–467 °C indicate that the samples are in the oil generation window Tmax and are thermally mature. Rock‐Eval pyrolysis data indicate that the organic matter in the shales is composed mainly of Type II and III kerogen.Solvent extract analyses of the samples show a unimodal n‐alkane distribution with a predominance of low carbon number (C13‐C20) n‐alkanes. Pr/Ph ratios and CPI values range from 1.57–1.66 and 1.08–1.11, respectively Pr/n‐C17 and Ph/n‐C18 ratios also indicate that the shales consist of mixed Type II/III organic matter.Sterane distributions are C27>C29>C28 as determined by the sum of normal and isosteranes, suggesting marine depositional conditions 20S/(20S+20R) and ββ (ββ+αα) C29 sterane ratios range from 0.51–0.54 and 0.53–0.57, respectively. These values are high and 20S/(20S+20R) sterane isomerisation has reached equilibrium values.Tricyclic terpanes are abundant on m/z 191 mass chromatograms and C23 tricyclic terpanes are the dominant peak, which indicates a marine depositional setting. C29 norhopane has a higher concentration than C30 hopane, and C30 diahopane and C29Ts are present in all the samples. Ts and Tm were recorded in similar abundances. Moretane/hopane ratios are very low. 22S homohopanes are dominant over 22R homohopanes, and the C32 22S/(22R + 22S) C32 homohopane ratios are between 0.58 and 0.59, indicating that homohopane isomerisation has reached equilibrium. C31 homohopanes are dominant and the abundance of homohopanes decreases towards higher numbers.Although regional variations in the level of thermal maturity of Upper Palaeozoic sediments throughout the Taurus Belt region largely depend on burial depth, organic geochemical data indicate that the Lower Carboniferous shales in the eastern Taurus region (Naltas and Belen locations) have potential to generate hydrocarbons. These shales are thermally mature and have entered the oil generation window.

BURIAL AND THERMAL HISTORY MODELLING OF THE MURZUQ AND GHADAMES BASINS (LIBYA) USING THE GALO COMPUTER PROGRAMME

The GALO computer programme was used to model the thermal and burial histories of the Murzuq and Ghadames Basins, Libya. The model was based on recent drilling and seismic data from the basins, and used published deep temperature and vitrinite reflectance measurements. The model provides more accurate results than previous studies which were based on constant geothermal gradients during the basins' histories, and variations in heat flux at the base of the sedimentary cover were chosen so that calculated values of vitrinite reflectance coincide with those observed. The Murzuq Basin and Libyan part of the Ghadames Basin contain similar source rock units but have different burial histories. In the Murzuq Basin, maximum present‐day burial depths of Cambrian sediments range from 2200 to 2800 m and only locally reach 3000 – 3600 m; in the Ghadames Basin, however, burial depths can exceed 4–5 km. The burial history of the Murzuq Basin includes several periods of intense erosion and lithospheric heating which produced significant lateral variations in thermal maturity, leading in places to unexpected results. For example, relatively shallow‐buried Lower Silurian source rocks in the A‐76 area on the flank of the Murzuq Basin have a thermal maturity of Ro = 1.24% which is higher than the maturity of the same interval in more deeply buried areas (wells D1‐NC‐58 or J1‐NC101). In the central part of the Ghadames Basin, the modelling suggests a higher level of thermal maturity for organic matter in Silurian strata (Ro 0.8 to 1.3%), confirming the generation potential of Lower Silurian “hot shales”. Significant hydrocarbon generation began here in the Late Carboniferous and continues at the present day. Modelling of the Late Devonian (Frasnian) Aouinat Ouinine Formation “hot shales” suggests limited hydrocarbon generation depending strongly on burial depth, with the main phase of hydrocarbon generation taking place during the final episode of thermal activation in the Cenozoic. In the wells studied in the Ghadames Basin, the “oil window” extends over a considerable part of the present‐day sedimentary column.

Organic geochemistry of Upper Carboniferous bituminous coals and clastic sediments from the Lublin Coal Basin

Abstract Bituminous coals and clastic rocks from the Lublin Formation (Pennsylvanian, Westphalian B) were subjected to detailed biomarker and Rock-Eval analyses. The investigation of aliphatic and aromatic fractions and Rock-Eval Tmax suggests that the Carboniferous deposits attained relatively low levels of thermal maturity, at the end of the microbial processes/initial phase of the oil window. Somewhat higher values of maturity in the clastic sediments were caused by postdiagenetic biodegradation of organic matter. The dominance of the odd carbon-numbered n-alkanes in the range n-C25 to n-C31 , high concentrations of moretanes and a predominance of C 28 and C29 steranes are indicative of a terrigenous origin of the organic matter in the study material. This is supported by the presence of eudesmane, bisabolane, dihydro-ar-curcumene and cadalene, found mainly in the coal samples. In addition, tri- and tetracyclic diterpanes, e. g. 16β(H)-kaurane, 16β(H)-phyllocladane, 16α(H)-kaurane and norisopimarane, were identified, suggesting an admixture of conifer ancestors among the deposited higher plants. Parameters Pr/n-C17 and Rdit in the coal samples show deposition of organic matter from peat swamp environments, with the water levels varying from high (water-logged swamp) to very low (ephemeral swamp). Clastic deposits were accumulated in a flood plain environment with local small ponds/lakes. In pond/lake sediments, apart from the dominant terrigenous organic matter, research also revealed a certain quantity of algal matter, indicated, i.a., by the presence of tricyclic triterpanes C28 and C29 and elevated concentrations of steranes. The Paq parameter can prove to be a useful tool in the identification of organic matter, but the processes of organic matter biodegradation observed in clastic rocks most likely influence the value of the parameter, at the same time lowering the interpretation potential of these compounds. The value of Pr/Ph varies from 0.93 to 5.24 and from 3.49 to 22.57 in the clastic sediments and coals respectively. The microbial degradation of organic matter in both type of rocks and during early stages of diagenesis is confirmed by a high concentration of hopanes, the presence of drimane homologues, bicyclic alkanes and benzohopanes. Moreover, bacteria could also have been connected with the primary input of organic matter, which is shown by the presence of e.g. C30 neohop-13(18)-ene.

Tracing the origin of thermogenic hydrocarbon signals in pockmarks from the southwestern Barents Sea

The glacially influenced southwestern Barents Sea is a promising area for petroleum exploration. The present study area, which is located in the Loppa High region, exhibits extensive pockmark fields covering an area of several square kilometers and containing thousands of pockmarks in high density. To investigate whether the pockmark formation was driven by petroleum leakage to the surface, acting thus as indicators for an active petroleum system, gravity cores from selected pockmark and reference sites were investigated using an organic geochemical approach. Various biomarkers indicative of thermogenic hydrocarbons such as short chain n-alkanes with a low carbon preference index, alkylcyclohexanes, αβ-hopanes, steranes and diasteranes mixed with biomarkers representing immature organic matter were detected in the pockmark, but also in reference cores outside of the pockmark and even from a non-pockmark area. The abundance and level of thermal maturity of the thermogenic hydrocarbons are comparable between the pockmark and reference sites. Additionally, their distribution with depth is quite similar to those of the immature biomarkers. These observations support the conclusion that the thermogenic hydrocarbon signal in the pockmarks is the result of reworked, eroded mature material mixed with immature organic matter distributed across the entire area, rather than the result of seepage events of thermogenic hydrocarbons through the pockmark system. The data show that in the Loppa High region the pure presence of petroleum-derived hydrocarbons in pockmark areas cannot be used to indicate the presence or leakage of deeper petroleum systems.

Vitrinite reflectance as a tool for determining level of thermal maturity for the Upper Jurassic Naokelekan and Barsarin Formations in Sargelu location, Kurdistan Region, NE Iraq

Ten samples from the Upper Jurassic Naokelekan and Barsarin Formations in an outcrop section near Sargelu Village were studied to evaluate their thermal maturity using vitrinite reflectance method. The studied beds appeared to be mature and within the oil generation window (0.79–1.25 % vitrinite reflectance in immersion oil (Ro)). Some of the reflectance histograms showed bimodal distribution indicating existence of nonindigenous populations which were all ignored during the measurements of the mean value of Ro. Comparison between the results obtained from vitrinite reflectance method and some other methods like pyrolysis and gas chromatography showed variations which finally more reality believed to be for the vitrinite reflectance method.

The Potential of Eocene Shale of Nanggulan Formation as a Hydrocarbon Source Rock

DOI: 10.17014/ijog.v8i1.152In western Indonesia, Eocene shale is generally considered as a potential source rock. The Nanggulan Formation outcropping at Kulonprogo Yogyakarta consists of a shale interval of Eocene in age. Analysis of its organic material content, kerogen type, and maturity level were conducted to know its potential. The laboratory analysis of eleven samples were done to measure its TOC content. Samples with TOC > 0.5% then were analyzed to measure its Rv and TAI. Maturity level was also calculated by TTI from burial history model. The result of analysis shows there are various TOC contents and seven samples of them are categorized into a good-excellent class (TOC > 1%). Kerogen content of those samples is type III (non fluorescene amorphous-humic kerogen). One sample has a good indication of hydrocarbon formation (PY = 9.0 mg HC/g rock). Unfortunately thermal maturity level of the samples is immature (highest Rv 0.39, Tmax 422oC, and TAI 2). Otherwise, TTI calculation result from subsurface burial history modelling indicates that some areas are mature having reached gas window since 0.4 mya, especially in the area which had been influenced by a volcanic intrusion at Oligocene (28.5 mya). Therefore, the Nanggulan Formation shale has a potential capacity as a source rock with some limitation in maturity level.

Hydrocarbon potential of the Sargelu Formation, North Iraq

Microscopic and chemical analysis of 85 rock samples from exploratory wells and outcrops in northern Iraq indicate that limestone, black shale and marl within the Middle Jurassic Sargelu Formation contain abundant oil-prone organic matter. For example, one 7-m (23-ft.)-thick section averages 442 mg HC/g S2 and 439 °C Tmax (Rock-Eval pyrolysis analyses) and 16 wt.% TOC. The organic matter, comprised principally of brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminiferal test linings and phytoclasts, was deposited in a distal, suboxic to anoxic basin and can be correlated with kerogens classified as type A and type B or, alternatively, as type II. The level of thermal maturity is within the oil window with TAI = 3− to 3+, based on microspore colour of light yellowish brown to brown. Accordingly, good hydrocarbon generation potential is predicted for this formation. Terpane and sterane biomarker distributions, as well as stable isotope values, were determined for oils and potential source rock extracts to determine valid oil-to-source rock correlations. Two subfamily carbonate oil types—one of Middle Jurassic age (Sargelu) carbonate rock and the other of Upper Jurassic/Cretaceous age—as well as a different oil family related to Triassic marls, were identified based on multivariate statistical analysis (HCA and PCA). Middle Jurassic subfamily A oils from Demir Dagh oil field correlate well with rich, marginally mature, Sargelu source rocks in well MK-2 near the city of Baiji. In contrast, subfamily B oils have a greater proportion of R28 steranes, indicating they were generated from Upper Jurassic/Lower Cretaceous carbonates such as those at Gillabat oil field north of Mansuriyah Lake. Oils from Gillabat field thus indicate a lower degree of correlation with the Sargelu source rocks than do oils from Demir Dagh field. One-dimension petroleum system models of key wells were developed using IES PetroMod Software to evaluate burial-thermal history, source-rock maturity and the timing and extent of petroleum generation; interpreted well logs served as input to the models. The oil-generation potential of sulphur-rich Sargelu source rocks was simulated using closed system type II-S kerogen kinetics. Model results indicate that throughout northern Iraq, generation and expulsion of oil from the Sargelu began and ended in the late Miocene. At present, Jurassic source rocks might have generated and expelled between 70 % and 100 % of their total oil.

Spectrochemical study of coalified Trigonocarpus grandis (Pennsylvanian tree-fern ovule, Canada): Implications for fossil–organ linkage

Five coalified ovules of the type Trigonocarpus grandis are investigated four of which co-occur with tree-fern foliage Alethopteris pseudograndinioides in the medullosalean forest (basal Cantabrian), and the fifth occurs in top Asturian D (Sydney Coalfield, Canada). Addressed are questions of variability (what is a coalified ovule?), comparison with petrified ovules, pyrolysates and the original make-up of the grandis seeds, and can similar chemistry proxy for organic connection between ovule and foliage?The results demonstrate variable preservation quality despite similar thermal-maturity levels in the geological interval in which the ovules were collected. Nevertheless, the proposed T. grandis model is based on evidence from epidermises associated with inner and outer integuments, and a two-layered nucellus with granulose exine that is covered by a diaphanous layer (tectum?) and nucellar cuticle. The latter separates the inner cuticle of the inner integumentary surface from the megaspore membrane. Parenchymatous and sclerenchymatous cell structures are rare, whereas evidence for integuments, vasculature, and sclerotesta is equivocal. Overall, these features compare with petrified seeds.13C nuclear-magnetic resonance analysis suggests that the A. pseudograndinioides tree fern bore T. grandis seeds. Pyrolysates from low and high molecular weights can almost exclusively be grouped with alkenes and aromatics; phenolics, furan and branched alkenes; and with n-alkene/n-alkane homologous series (~3 to 1) for cuticles from the inner integumentary surface which suggests a cutin-based, aliphatic-rich biomacromolecule. More generally, preservation is presumed correlative with aliphatic content, but not exclusively, and organ–organ linkage by spectrochemical means certainly has potential as a new research vector in palaeobotany.

Diamondoid Hydrocarbons as Maturity Indicators for Condensates from Southern Indus Basin, Pakistan

Diamondoid hydrocarbons have been examined in condensates reservoired in the Southern Indus Basin using GC‐MS. Bulk properties reveal that samples are waxy and low sulfur with the exception of Pakhro and Gopang which are nonwaxy. TIC show bimodal distribution of n‐alkanes along with high abundance of C20+ n‐alkanes indicating substantial contribution of terrigeneous OM in these samples. CPI close to one is consistent with mature nature of oils. The samples show two ranges of Pr/Ph ratios. Those within the range of 2.2–2.7 reflect marine depositional settings for OM while others with Pr/Ph >3 may have originated from terrestrial OM deposited under marine oxic conditions. The cross plot of Pr/n‐C17 versus Ph/n‐C18 indicate type III kerogen as main source of OM deposited under marine to marine oxic conditions. The values of diamondoid based maturity parameters, like methyladamantane index 54.1–75.8% and methyldiamantane index 34.9–56.3% indicate high level of thermal maturity corresponding to vitrinite reflectance 1.1–1.6%. No biodegradation is observed in any of these samples as shown by methyladamantanes/adamantane 3.99–5.52 and methyldiamantanes/diamantane 2.16–2.99 and supported by high values of API gravity (45.13°–60.02°) and absence of UCM.

Organic geochemical characteristics and interpreted depositional environment of the Khatatba Formation, northern Western Desert, Egypt

The Middle Jurassic Khatatba Formation in the northern Western Desert of Egypt was evaluated in terms of organic matter abundance, type and thermal maturity, as well as for some organic petrographic characteristics. Depositional environments were interpreted based on organic geochemical (Rock-Eval pyrolysis, extract analysis, and biomarker distributions) and organic petrological methods. Organic carbon contents range between 1.0 and 32.5 wt. %. The Khatatba shale and coaly shale samples have hydrogen index values in the range of 63 to 261 mg hydrocarbon (HC)/g total organic carbon, with mixed types 2–3 and 3 kerogens. Mean vitrinite reflectance (Ro) between 0.77 and 1.07% is in reasonably good agreement with pyrolysis Tmax (temperature at maximum of S2 peak) data (438–459C). Organic-rich sediments of the Middle Jurassic Khatatba Formation have very good source rock generative potential and have obtained thermal maturity levels equivalent to the oil window. The main generation products are gas with very limited liquid HCs (oil or condensate). Seven shale and coaly shale samples from Khatatba Formation were characterized using gas chromatography (GC) and GC–mass spectrometry techniques. The Khatatba samples are characterized by the predominance of C14-C24 alkanes, a pristane/phytane ratio of less than 2, abundant C27 regular steranes, and the presence of tricyclic terpanes. These are consistent with the suboxic marine-environment conditions for the Khatatba source rock. Biomarker parameters for these samples generally indicate a mixture of land- as well as marine-derived organic-matter input. The maturity indicators based on C32 22S/(22S + 22R) homohopane and C29 20S/(20S + 20R) and /( + ) sterane ratios reveal that the Khatatba samples are thermally mature and have reached the peak oil-window maturity supporting the Ro data.

Conodont thermal alteration patterns in Devonian and Carboniferous rocks of the Ahnet and Mouydir basins (southern Algeria)

Conodont colour alteration indices (CAI) have been used to recognize the thermal maturation of the Middle Devonian to Late Carboniferous sedimentary infill of the Ahnet and Mouydir basins in southern Algeria. The study is based on a large set of conodont samples obtained from 69 sections and outcrops. In the Ahnet Basin, the Middle and Upper Devonian rocks at the surface show a uniform thermal maturity level characterized by the CAI values of 2, which suggests maximum burial temperatures about 50 °C. In contrast, the Carboniferous exposures yield a wide range of CAI values from 1 to 3.5. Besides, the general tendency in maturity decreases upward in the sequence, there are anomalies related to heating by small local magmatic bodies. In the Mouydir Basin, the CAI values in the Middle and Upper Devonian outcrops range from 2 to 3.5. The pattern indicates that the majority of Middle Devonian rocks have experienced burial temperatures of about 120 °C, while thermal maturation of the Upper Devonian strata is clearly lower, with maximum heating temperatures about 50 °C at the edges of the basin. The observed thermal maturity has been mostly achieved during Late Carboniferous time, prior to the Variscan inversion, and only locally during the Mesozoic. It is a product of loading by Carboniferous overburden succession of which part is now removed, approx. 200–1300 m in the Ahnet Basin and up to 1200 m in the Mouydir Basin. The analysis of palaeotemperatures suggests an average geothermal gradient of 30 °C/km during Carboniferous time in the Ahnet–Mouydir area. In terms of hydrocarbon exploration the studied Devonian succession is predominantly mature for oil and gas. In contrary, the Carboniferous rocks are immature. Higher maturities are likely to occur in the subsurface.

The nature of porosity in organic-rich mudstones of the Upper Jurassic Kimmeridge Clay Formation, North Sea, offshore United Kingdom

Abstract Analyses of organic-rich mudstones from wells that penetrated the Upper Jurassic Kimmeridge Clay Formation, offshore United Kingdom, were performed to evaluate the nature of both organic and inorganic rock constituents and their relation to porosity in this world-class source rock. The formation is at varying levels of thermal maturity, ranging from immature in the shallowest core samples to mature in the deepest core samples. The intent of this study was to evaluate porosity as a function of both organic macerals and thermal maturity. At least four distinct types of organic macerals were observed in petrographic and SEM analyses and they all were present across the study area. The macerals include, in decreasing abundance: 1) bituminite admixed with clays; 2) elongate lamellar masses (alginite or bituminite) with small quartz, feldspar, and clay entrained within it; 3) terrestrial (vitrinite, fusinite, semifusinite) grains; and 4) Tasmanites microfossils. Although pores in all maceral types were observed on ion-milled surfaces of all samples, the pores (largely nanopores with some micropores) vary as a function of maceral type. Importantly, pores in the macerals do not vary systematically as a function of thermal maturity, insofar as organic pores are of similar size and shape in both the immature and mature Kimmeridge rocks. If any organic pores developed during the generation of hydrocarbons, they were apparently not preserved, possibly because of the highly ductile nature of much of the rock constituents of Kimmeridge mudstones (clays and organic material). Inorganic pores (largely micropores with some nanopores) have been observed in all Kimmeridge mudstones. These pores, particularly interparticle (i.e., between clay platelets), and intraparticle (i.e., in framboidal pyrite, in partially dissolved detrital K-feldspar, and in both detrital and authigenic dolomite) are noteworthy because they compose much of the observable porosity in the shales in both immature and mature samples. The absence of a systematic increase in organic porosity as a function of either maceral type or thermal maturity indicates that such porosity was probably unrelated to hydrocarbon generation. Instead, much of the porosity within mudstones of the Kimmeridge appears to be largely intraparticle and interparticle (adjacent to inorganic constituents), so the petroleum storage potential in these organic-rich mudstones largely resides in inorganic pores.

Organic matter in Silurian rocks from the Chernov uplift

This study presents data on the composition of organic matter from the Late Silurian sediments of the Chernov uplift. These sediments are characterized by low Corg contents, which may reach 1–3% in individual layers. A relatively high thermal maturity of organic matter is confirmed by polycyclic biomarker distributions and Rock-Eval pyrolyisis data. Despite its higher thermal maturity level (Tmax = 456°C), kerogen in carbonaceous shales from the Padymeityvis River exhibits good preservation of long-chain n-alkyl structures, which are readily identified in the 13C NMR spectra and by the molecular analysis of the kerogen pyrolysis products.

BIOMARKER CHARACTERISTICS OF CRUDE OILS FROM THE MURZUQ BASIN, SW LIBYA

Twenty crude oil samples from the Murzuq Basin, SW Libya (A‐, R‐ and I‐Fields in Blocks NC115 and NC186) have been investigated by a variety of organic geochemical methods. Based on biomarker distributions (e.g. n‐alkanes, isoprenoids, terpanes and steranes), the source of the oils is interpreted to be composed of mixed marine/terrigenous organic matter. The values of the Pr/Ph ratio (1.36–2.1), C30‐diahopane / C29 Ts ratio and diasterane / sterane ratio, together with the low values of the C29/ C30‐hopane ratio and the cross‐plot of the dibenzothiophene/phenanthrene ratio (DBT/P) versus Pr/Ph ratio in most of oil samples, suggest that the oils were sourced from marine clay‐rich sediments deposited in mild anoxic depositional environments. Assessment of thermal maturity based on phenanthrenes, aromatic steroids (e.g. monoaromatic (MA) and triaromatic (TA) steroid hydrocarbons), together with terpanes, and diasterane/sterane ratios, indicates that crude oils from A‐Field are at high levels of thermal maturity, while oils from Rand I‐Fields are at intermediate levels of thermal maturity. Based on the distributions of n‐alkanes and the absence of 25‐norhopanes in all of the crude oils analysed, none of the oils appear to have been biodegraded. Correlation of the crude oils points to a single genetic family and this is supported by the stable carbon isotope values. The oils can be divided into two sub‐families based on the differences in maturities, as shown in a Pr/nC17 versus Ph/nC18 cross‐plot. Sub‐family‐A is represented by the highly mature oils from A‐Field. Sub‐family‐B comprises the less mature oils from R‐ and I‐Fields. The two sub‐families may represent different source kitchens of different thermal maturity or different migration pathways.In summary, the geochemical characteristics of oil samples from A‐, R‐, and I‐Fields suggest that all the crude oils were generated from similar source rocks. Depositional environment conditions and advanced thermal maturities of these oils are consistent with previously published geochemical interpretations of the Rhuddanian “hot shale” in the Tanezzuft Formation, which is thought to be the main source rock in the Murzuq Basin.

Modeling of gas generation from the Alam El-Bueib formation in the Shoushan Basin, northern Western Desert of Egypt

The Shoushan Basin is an important hydrocarbon province in the northern Western Desert, Egypt, but the burial/thermal histories for most of the source rocks in the basin have not been assigned yet. In this study, subsurface samples from selected wells were collected to characterize the source rocks of Alam El-Bueib Formation and to study thermal history in the Shoushan Basin. The Lower Cretaceous Alam El-Bueib Formation is widespread in the Shoushan Basin, which is composed mainly of shales and sandstones with minor carbonate rocks deposited in a marine environment. The gas generative potential of the Lower Cretaceous Alam El-Bueib Formation in the Shoushan Basin was evaluated by Rock–Eval pyrolysis. Most samples contain sufficient type III organic matter to be considered gas prone. Vitrinite reflectance was measured at eight stratigraphic levels (Jurassic–Cretaceous). Vitrinite reflectance profiles show a general increase of vitrinite reflectance with depth. Vitrinite reflectance values of Alam El-Bueib Formation range between 0.70 and 0.87 VRr %, indicating a thermal maturity level sufficient for hydrocarbon generation. Thermal maturity and burial histories models predict that the Alam El-Bueib source rock entered the mid-mature stage for hydrocarbon generation in the Tertiary. These models indicate that the onset of gas generation from the Alam El-Bueib source rock began in the Paleocene (60 Ma), and the maximum volume of gas generation occurred during the Pliocene (3–2 Ma).

Advanced Workflow Package for Shale Assets Developed

Technology Update The growth in unconventional resource plays in the past several years has produced a burgeoning need for new software tools for organic shales. Geoscientists need tools to help them understand complex hydrocarbon generation, storage capacity, and migration paths in source rock reservoirs, enabling them to flag and map optimized pay. Engineers need tools to help them define optimum techniques to deliver the most shale gas and oil to the market and enable them to build the best reservoir models to exploit these resources. And for unconventional resource development to proceed as it should, these tools must work together in a common framework. An advanced integrated petrophysical evaluation software package, based on a calibrated workflow, was recently developed by Halliburton for organic shales. The concept behind it was to bring all the requisite pieces of an exploration shale play analysis into a single vantage point for an asset team. This is critical when very few vertical exploration wells are used to define the economics of these resource plays before full-scale horizontal development begins. The software’s workflow modules encompass the following capabilities: total organic carbon (TOC) and organic maturity estimation; fluid and minerals evaluation; advanced saturation modeling; mechanical properties and brittleness; 3D stress and stress orientation; permeability; and pay analysis. TOC Estimation and Organic Maturity To define the resource volume, one needs to determine an accurate volume of organic kerogen present in the rock. To determine potential hydrocarbon type, the level of thermal maturity must be established. To solve for kerogen, the TOC measured by core pyrolysis can be calibrated to logs, using eight industry accepted correlations. Organic maturity, VRo, is measured by actual vitrinite reflectance or calculated from pyrolysis-derived Tmax (temperature between 300°C and 600°C that generates peak hydrocarbons from existing kerogen). This maturity value is used to make the final TOC calibration and predict hydrocarbon type. Fluid and Minerals Evaluation The heart of the volumetric analysis is its probabilistic solver. Total porosity in organic shales can only be resolved by logs when relative amounts of geochemically derived minerals are measured and combined with the TOC calculation. Minimum requirements for this type of analysis include a triple combo log, neutron capture spectroscopy, and natural gamma spectroscopy. The software uses a probabilistic error minimization methodology to determine formation fluid and mineral volumes. The idea is to construct theoretical logs that closely replicate actual logs. Tool response equations are expressed in terms of fluid and mineral volumes and their corresponding tool response parameters. Most response equations are linear. Some, such as neutron, conductivity, and certain acoustic equations, are nonlinear. The inclusion of additional evaluation tools, such as the dipole sonic travel time curves DTC (compressional velocity) and DTS (shear velocity), helps add coherence to the analysis, as long as the correct acoustic equations are used for harder rock-clay shales.

An Organic Geochemical Characterization of Crude Oils from El Hamd and Bakr Oilfields in the Gulf of Suez, Egypt

Seven crude oil samples were collected from wells of the El Hamd and Bakr oil fields located in the central Gulf of Suez and their chemical composition, API gravity, sulfur content, and asphaltene content were determined. Nickel and vanadium contents were measured using atomic absorption spectroscopy. Saturated paraffinic hydrocarbon fractions were subjected to gas chromatography in order to investigate carbon number distribution. Terpanes and steranes biomarker distributions have been determined using gas chromatography-mass spectroscopy in order to characterize the type of organo-facies, oil classes, depositional environments of the studied crude oils, and to assess the thermal maturity level for oil generation. It has been found that mature oils are generated from marine shales and carbonates are enriched in marine algae with a contribution from terrestrial organic matters.

Source Rock Characterization Within the Stratigraphic Settings of the Orange Basin, South Africa

abstract The petroleum source rock potential of different system tracts of a Cretaceous unit of the Orange Basin, South Africa, was evaluated using Rock-Eval pyrolysis. Forty rock samples from eight wells were obtained within the systems tract, Lowstand System Tracts (LST), Transgressive System Tracts (TST), and Highstand System Tracts (HST), in the basin. The results revealed that LST is characterized by mainly marginally organic rich shale samples with a few organic rich rocks, variable organic matter types ranging from Type II to Type IV, and a few samples that are thermally mature but have low organic matter quality. Four samples from two wells (A_F1 and O_A1) in the LST had good petroleum generative potential but were not sufficiently mature for petroleum generation. TST is characterized with a few samples being marginally organic rich, with only one being organic rich, mainly Type III kerogen with few Type IV kerogen, and only a few samples are thermally mature that have low organic matter quality. HST is characterized by many marginally organic rich rock samples, mainly Type III with a few mixed Type II/III kerogen, and only a few samples were thermally mature. The results of this study show that the LST has the best prospect in terms of petroleum generation potential, followed by HST and TST in that order. The study also reveals that limited petroleum source rocks exist, which are also impacted by low thermal maturity levels. The basin is more gas prone than oil.