Brown Limestone Research Articles

Hydrocarbon generation potential of South Geisum Oilfield, Gulf of Suez, Egypt: Source rock evaluation and basin modeling for unconventional hydrocarbon prospects

This study aims to define the hydrocarbon generation potential of source rocks by assessing various factors including quantity of organic matter, types of kerogen, thermal maturity, and source of organic matter input. Depositional conditions of source rocks from Thebes, Brown Limestone, and Matulla formations in Well G-9, Well GA-2 and Well GW-6, are assessed through pyrolysis, vitrinite reflectance and 1D basin modeling. Results show the source rocks of Thebes and Brown Limestone formations exhibit favorable to excellent source rock characteristics with Type I–II kerogen and have the capacity to generate oil. Conversely, the source rocks of the Matulla Formation show fair to good source rock characteristics with Type II–III kerogen and have the capacity to produce both oil and gas. Thermal maturity shows the source rocks are at an immature stage. A 1D basin model is constructed for Well G-9 to simulate multi-tectonic episodes, burial events, and the history of thermal maturity. Sedimentation rates of Cretaceous to Eocene deposits are characterized by a low burial rate, which contrasts with the high burial and sedimentation rates for Miocene and post Miocene (Pliocene–Recent) strata. Overall, the South Geisum oilfield petroleum system is found to be immature based on integration of source rock evaluation and petroleum basin modelling.

The upper cretaceous carbonate sediments of the Ras Budran Field, Gulf of Suez, Egypt: stacking patterns and depositional controls

The present study interprets the carbonate stacking patterns and their depositional controls in the Upper Cretaceous strata of the Ras Budran Field in the Gulf of Suez, Egypt, on the basis of integrated well logging and a geological report provided. A set of well logs was run for two wells (RB-A2 and RB-B2), comprising gamma ray, resistivity, density, neutron, sonic, and photoelectric factor. Composite logs and geological reports were also used to help deduce the lithological and biological description of the stratigraphic units under investigation. The stacking patterns of the carbonate rocks yielded three types of electro-facies. The first facies covers the lower part of the Brown Limestone (early Campanian) and reflects a cylindrical (aggrading) stacking pattern. This facies indicates keep-up carbonate deposition in a heterogeneous facies accumulated in shallow water. The second facies covers the upper part of the Brown Limestone (late Campanian) and displays a funnel (prograding) stacking pattern. This facies indicates the depositional setting of a shallow shoreline. The third facies covers the Sudr Chalk (Maastrichtian), for which a serrated stacking pattern indicates an aggradational environment. This pattern indicates a marine depositional setting both distal and deep. Therefore, the formation and evolution of the cyclical stacking pattern of the carbonate rocks reflects variations in accommodation potential that determines the environmental changes. The evolution of these deposits is mainly attributed to a combination of eustatic sea-level fluctuations and tectonic episodes within the basin.

A static modeling approach to the Brown Limestone carbonate reservoir, Geisum Oilfield, Gulf of Suez, Egypt

The Gulf of Suez in Egypt contains more than 80 conventional oil fields with reservoirs from Precambrian up to Quaternary age. To date, these fields have all been conventional resources. This abstract will take part of the Gulf of Suez sequence within the fields of Petrogulf Misr Company and present a work process for unconventional resource assessment of the Brown Limestone formation within one of these areas. The Brown Limestone formation is a Late Cretaceous Pre-rift mega sequence succession and plays an important role in the conventional system of Gulf of Suez, Brown Limestone formation is not only as one of the important source rocks, but also a fractured carbonate reservoir in multiple fields especially is the southern Geisum oil field. However, this formation is characterized by uncertainty due to the complexity of reservoir architecture, various lithologies, lateral facies variations, and heterogeneous reservoir quality. These reservoir challenges, in turn, affect the effectiveness of further exploitation of this reservoir along the Gulf of Suez Basin. In this work, we conduct an integrated study using multidisciplinary datasets and techniques to determine the precise structural, petrophysical, and facies characteristics of the Brown Limestone Formation and predict their complex geometry in 3D space. The Brown Limestone formation is considered to be as a reservoir in the study area. The value of water saturation ranges from 15 to 45%, where the value of Effective Porosity ranges from 11 to 15% for the selected potential intervals in Brown Limestone due to the highly structural setting in the study area, so Reservoir thickness was used as the proxy for reservoir effectiveness where thicker reservoir had a higher chance of containing multiple intervals for good potential intervals.

Chemometric Differentiation of Oil Families and Their Potential Source Rocks in the Gulf of Suez

An oil–oil and oil–source rock correlation study was carried out using chemometric methods applied to geochemical data for 123 Upper Cretaceous—Lower Miocene putative source rock and 46 crude oil samples from the Gulf of Suez Rift basin. The Gulf of Suez has many organic-rich intervals. The pre-rift source units, such as the Brown Limestone and Thebes formations, contain very good-to-excellent organic content, whereas the Miocene rocks are rated fair to good. HI and Tmax pyrolysis data indicate variable kerogen type and maturation histories where most of the analyzed samples occur along the Type II and Type II/III kerogen pathways from immature to the main stage of oil window with %Ro < 0.9. Carbon isotope ratios’ biomarker data for the bitumen samples indicate predominantly anoxic source rock depositional conditions with substantial algal/bacterial marine and a minor terrigenous organic matter. The Gulf of Suez oils exhibit a wide range of chemical composition from heavy-to-medium gravity and moderate-to-high sulfur content. These oils originated from carbonate/marl source rocks rich in lipids from phytoplankton/benthic algae and bacteria with less contribution of terrigenous organic debris, deposited under anoxic conditions with different thermal maturity histories equivalent to at least the early oil window. Chemometrics using 16 source-related biomarker and isotope ratios identifies six genetic families in the Gulf of Suez. The oil families share common characteristics where the precursor organic matter was deposited in a restricted marine environment with limited land-derived organic matter. The major factor that greatly modifies oil composition in the Gulf of Suez is thermal maturation. However, migration history and spatial and temporal organofacies’ variations of the presumed source rocks are also important. The overall geochemical similarity of the Gulf of Suez oils confirms the mixed nature of these fluids and suggests that no single source rock horizon is likely to have sourced the oil in this promising province. Based on oil–source correlation data and a decision tree chemometric model, the Brown Limestone, Esna, Thebes, and Nukhul formations are the effective source rocks for oil families III, IV, and V, whereas none of the source rock extracts has been assigned for Family I or VI oils.

Oil-source correlation in the West Esh El Mellaha, southwestern margin of the Gulf of Suez rift, Egypt

There are several source rock units in the Gulf of Suez graben, but the Upper Cretaceous–Miocene sequence has probably produced most of the commercial hydrocarbons in this petroleum province. One hundred and nine shale, marl and marly shale samples collected from five wells in the West Esh El Mellaha Concession and surrounding area were studied by petrographic and organic geochemical methods to determine organic facies, depositional paleoenvironment, and thermal maturity. We also investigated the molecular and stable carbon isotopic compositions of nine oil samples to establish genetic relationships with the source rock samples.Pyrolysis data for samples from the Cenomanian–Santonian Matulla, Paleocene Esna, Eocene Thebes, Oligo-Miocene Nukhul and Lower–Middle Miocene Rudeis formations contain hydrogen-poor terrigenous Type-III to II/III kerogen. However, the Campanian–Maastrichtian Brown Limestone samples contain Type-II and Type-II/III kerogens indicating very good to excellent generation potential. The acyclic isoprenoids and normal alkane distributions and biomarkers in the source rock extracts indicate derivation from bacteria and algae, with varying contributions from land plants, deposited under suboxic to anoxic conditions in normal marine to higher salinity waters.The oil samples have high sulfur content and low to moderately high API gravity, typical of mature oils from pre-rift marine carbonate or calcareous shale lithofacies. Hierarchical cluster analysis (HCA) of 18 source-related biomarker ratios revealed four genetic families of oil samples. The two South Malak-1 oils (Family-4) are substantially different from the Rabeh E−8 and Rabeh E−10 (Family-1), Rabeh-1 and Hurghada-1 (Family-2) and Abu Marwa-1 and Wadi El Sahl-1 (Family-3) oil families, which are more closely related. Principal component analysis (PCA) and HCA based on the 18 ratios for the total data from extracts and oils indicate three groups. The South Malak-1 oils seem to be most closely related to the two Brown Limestone extracts. Group-1 oils appear to represent mixtures with one end member consisting of the South Malak-1 oils and the Brown Limestone source rock, but the other end member is not in the dataset.

Effect of Soil Moisture and Temperature on the Soil Inorganic Carbon Release of Brown Limestone Soil in the Karst Region of Southwestern China

In order to understand the influence of environmental factors on the carbonate conversion of the Karst soil, typical brown limestone and red soil samples were collected from the Karst ecosystem, and a 100-day incubation experiment was conducted. The characteristics of inorganic carbon release from the soil under three temperature gradients (15, 25, and 35℃) and water contents (30%, 65%, and 100% WHC) were studied by adding 14C-CaCO3 for 100 d. The results showed that under the different soil moisture and temperature conditions, the maximum rate and the cumulative amount of inorganic carbon release from the soil over 100 days varied between 0.7-16.8 mg·(kg·d)-1and 5.9-29.4 mg·kg-1, respectively, in the brown limestone soil, and varied between 39.7-103.3 mg·(kg·d)-1 and 83.3-135.1 mg·kg-1, respectively in the red soil. Under drought conditions (30% WHC), the cumulative amount of inorganic carbon release was the highest for the two soils and increased with increasing temperature. At 65% WHC and 100% WHC, increasing temperature can still promote inorganic carbon release from the soil. The temperature sensitivity of the soil inorganic carbon release in the brown limestone soil is greater than that of the red soil, which is significantly affected by soil moisture. The soil pH and MBC content were remarkably increased after adding CaCO3, and the difference between the two soils was significant. The variance partition showed that temperature and soil moisture can explain 7.6% and 2.0% of the soil inorganic carbon release variability, respectively. In conclusion, warming and drought aggravate inorganic carbon release from brown limestone soil in the southwestern Karst region. Therefore, in the context of global warming and more frequent extreme precipitation events, the effects of soil moisture and temperature on inorganic carbon conversion in soil should be fully considered when studying the soil carbon cycle and its dynamic changes in southwestern Karst. This research can provide a scientific basis for further understanding the influence of climate change on the global carbon cycle.

Naica’s crystal cave captivates chemists

Deep below a mountain near Naica, Mexico, miners searching for fresh ore deposits in 2000 came across an unexpected and awesome sight. Massive, milky-white crystals towered around them, filling a horseshoe-shaped cave. Luminous beams of gypsum bigger than telephone poles, nearly 12 m long and 1 m wide, gleamed in the miners’ lights, jutting in all directions out of the brown limestone walls, floors, and ceiling. The Cave of Crystals, as it became named, is nestled 290 m underground, topped by a mountain rich in lead, zinc, and silver. Since its discovery by the mining company Industrias Penoles, the subterranean chamber has drawn researchers from around the world, enticing them with both rare beauty and scientific mystery. Juan Manuel Garcia-Ruiz, a crystallographer at the University of Granada, traveled all the way from Spain to see the crystals for himself. Garcia-Ruiz had grown crystals in laboratory flasks since age 15, so

CRUDE OIL GEOCHEMISTRY AND SOURCE ROCK POTENTIAL OF THE UPPER CRETACEOUS – EOCENE SUCCESSION IN THE BELAYIM OILFIELDS, CENTRAL GULF OF SUEZ, EGYPT

This study evaluates the petroleum potential of source rocks in the pre‐rift Upper Cretaceous – Eocene succession at the Belayim oilfields in the central Gulf of Suez Basin. Organic geochemical and palynofacies investigations were carried out on 65 cuttings samples collected from the Thebes, Brown Limestone and Matulla Formations. Analytical methods included Rock‐Eval pyrolysis, Liquid Chromatography, Gas Chromatography and Gas Chromatography – Mass Spectrometry. Four crude oil samples from producing wells were characterised using C7 light hydrocarbons, stable carbon isotopes and biomarker characteristics. The results showed that the studied source rocks are composed of marine carbonates with organic matter dominated by algae and bacteria with minimal terrigenous input, deposited under reducing conditions. This conclusion was supported by n‐alkane distributions, pristane/ phytane ratios, homohopane and gammacerane indices, high concentrations of cholestane, the presence of C30 n‐propylcholestanes, and low diasterane ratios. The source rocks ranged from immature to marginally mature based on the Rock‐Eval Tmax together with biomarker maturity parameters. The analysed crude oil samples are interpreted to have been derived from source rock intervals within the Eocene Thebes Formation and the Upper Cretaceous Brown Limestone. The similarity in the geochemical characteristics of the crude oils suggests that there was little variation in the organofacies of the source rocks from which they were derived.

Biomarker characteristics of the Turonian–Eocene succession, Belayim oilfields, central Gulf of Suez, Egypt

This study assesses the hydrocarbon source rocks of the Belayim oilfields, central Gulf of Suez, Egypt. Detailed geochemical methods, including liquid chromatography, gas chromatography and gas chromatography–mass spectrometry, are used to characterize organic-rich facies of the Turonian–Eocene deposits. Crude oil samples are analyzed using C7 and stable carbon isotopes, in addition to analysis of the extracts, in order to throw light on the organic matter source, composition, and thermal maturity. The source rocks are mainly derived from algae and bacteria deposited under normal saline and reducing palaeoenvironmental conditions, with a minimal contribution from terrestrial organic and mainly clay-poor source rocks. This is evidenced by the n-alkane distribution, the pristane/phytane, homohopane, gammacerane index, the high concentration of cholestane, the presence of the C30n-propylcholestanes and low diasteranes ratios. The source rock extracts range from immature to marginally mature, based on biomarker maturity-related parameters. A similar scenario is envisaged from the crude oil samples which showed a partial positive correlation with the source rocks of the Eocene Thebes Formation, and the Upper Cretaceous Brown Limestone. Our data suggest that Turonian–Santonian Matulla Formation samples may signify the presence of some oil in the study area.

Palynology, palynofacies and petroleum potential of the Upper Cretaceous–Eocene Matulla, Brown Limestone and Thebes formations, Belayim oilfields, central Gulf of Suez, Egypt

Palynological, palynofacies and organic geochemical results of 46 samples retrieved from the Upper Cretaceous – Eocene Matulla, Brown Limestone and Thebes formations, Belayim oilfields, central Gulf of Suez, Egypt are presented. The two latter formations are not dated palynologically as their lithology is not promising for palynological yield. However the Matulla Formation is dated as Turonian–Santonian age, based on the combined evidence of pollen and dinocysts.Palynofacies analysis carried out under both transmitted and fluorescent microscopy indicated that both the Thebes and Brown Limestone formations are deposited under a distal suboxic–anoxic environment. On the other hand, the Turonian–Santonian Matulla Formation supported the existence of a marginal marine deposition under dysoxic–anoxic basin to proximal suboxic–anoxic shelf environments. Rock-Eval pyrolysis and TOC results indicated that most of the studied formations are thermally immature to marginally mature and have a good petroleum potential. They are organically-rich in both oil- and gas-prone kerogen Type-II and II/III, deposited under marine reducing conditions favorable for hydrocarbon generation and expulsion.

Contribution to the stratigraphy and sedimentation of the Cretaceous aquifers, SE Sinai, Egypt

Eight formations were recognized in WadiWatir area, SE Sinai; Malha Formation (Early Cretaceous), Galala Formation (Late Cenomanian), Abu Qada Formation (Early Turonian), Buttum Formation (Early Turonian), Wata Formation (Late Turonian), Matulla Formation (Coniacian-Santonian), Brown Limestone Formation (LateCampanian-Early Maastrichtian) and Sudr Chalk Formation (Early-Middle Maastrichtian). The planktonic foraminifera played the great role in age determination for the referred units, in addition to some benthonic foraminifera. Also, three microfacies types were identified; siliciclastic facies, mixed carbonate – siliciclastic facies and carbonate facies reflecting an oscillation of the Cretaceous sea from shoal to shallow marine and marine environments. The diagenetic processes (cementation, neomorphism, dolomitization, silicification, dissolution and compaction) show the impact of textural and mineralogical changes on the studied rock units, groundwater occurrences and possibilities. Furthermore, two main aquifers are dominant in the study area, Lower Cretaceous sandstones and Cenomanian-Turonian Limestones. The geomorphologic and geologic characteristics controlling the groundwater occurrences were discussed.

Effects of host rock mineralogical composition and sedimentary facies on development of geochemical halos in Shahmirzad Pb-Zn deposits, central Alborz, Iran

Strata-bound carbonate hosted PbZn deposits or Mississippi Valley-type (MVT) deposits represent an economically important class of ore that received much attention in terms of defining effects of host rock petrography and sedimentary facies on development of geochemical halos. However there are few works on relation between sedimentary facies and MVT mineralizations in Iran. The Cretaceous carbonate rocks in the central Alborz (CA), northern Iran, host numerous small PbZn deposits and occurrences. The Shahmirzad PbZn deposits, located in the south of CA, geographically can be split into two groups, the north east (NEDs) and north west (NWDs) deposits. The Upper Cretaceous sequence in the NWDs area is composed of massive light gray limestone without any signs of later changes such as dolomitization and silicification. Additionally, three principal micro-facies are present: skeletal mudstone/wackestone (F1), biolithoclastic packstone (F2) and allochthonous bioclastic floutstone (F3). In contrast, the Cretaceous sequence hosting the NEDs is composed of massive brown limestone with six different types of dolomite (Rd1, Rd2, Rd3, Rd4, Cd1 and Cd2, the two last types are related to ore mineralization and open space filling) distinguished based on crystal size, distribution, and crystal boundary shape. The sedimentary succession in the NEDs indicates that the sedimentation took place in inner, mid and outer ramp environments, resulting in three different carbonate facies. In this area 15 carbonate facies were identified. The permeability and mineral compositions of these areas have obviously influenced the quantity of major and minor elements such as Fe (in average 0.24% in the NWDs and 0.12% in the NEDs), Si (in average 1.86% in the NWDs and 0.44% in the NEDs), Al (in average 0.50% in the NWDs and 0.13% in the NEDs), K (in average 0.24% in the NWDs and 0.06% in the NEDs), Sr (in average 685ppm in the NWDs and 204ppm in the NEDs), Na (in average 0.03% in the NWDs and 0.01% in the NEDs), Zn (in average 46ppm in the NWDs and 188ppm in the NEDs) and Pb (in average 3.3ppm in the NWDs and 83ppm in the NEDs). Not only are minor and major elements affected by changes in host rock mineral composition, but REEs decreased in concentration in dolomitic host rocks of NEDs. Some of the noticeable differences between the NWDs and the NEDs REEs data are i.e. La (in average 3.52ppm in the NWDs and 1.47ppm in the NEDs), Ce (in average 5.20ppm in the NWDs and 2.21ppm in the NEDs) and Eu (in average 0.13ppm in the NWDs and 0.03ppm in the NEDs). The combination of these data and host rock characteristics indicate that host rock compositions and textures effectively controlled these variations. We believe that perhaps the lack of dolomitization and low permeable facies in the NWDs precluded migration of diagenetic fluids and hydrothermal solutions in the carbonate host rocks. On the other hand, the presence of broad dolomitization and permeable facies in the NEDs carbonate host rocks may create appropriate conditions for diagenetic and hydrothermal fluid migration and interaction with the host rocks.

Study of Echinoids of Gurpi formation, Iran

AbstractIn order to detailed study of Echinoids, some samples are collected from Brown limestone member of Seimare from Gurpi Formation with 213 meter thickness which located in the vicinity of Ilam province; settling over Ilam Formation continuously. Paleontological results indicated Campanian - maastrichtian age at this section. Detailed analysis of the 300 samples led to recognition of Bivalve especially Bivalve of Lofa, Brachiopods and five species of Echinoids such as: Salenia nutrix, Globator bleicheri, Orthopsis miliarisi, Goniopygus superbus, and Conulus douville

GEOCHEMICAL CHARACTERIZATION OF A BIODEGRADED CRUDE OIL, ASSRAN FIELD, CENTRAL GULF OF SUEZ

A crude oil sample from the Assran field in the Central Gulf of Suez (Egypt) was analysed geochemically and characterized in terms of a variety of source and maturity dependent biomarkers. Biodegradation was indicated by increasing concentration ratios of Pr/n‐C17 and Ph/n‐C18. However, biodegradation was only slight as GC‐MS analyses of the saturate and aromatic fractions showed that hopanes, steranes, aromatic steroids and polycyclic aromatic compounds including sulphur heterocycles remained intact. The sterane and hopane distributions showed a predominance of C27 steranes, a low diasterane index, an abundance of gammacerane, a high homohopane index and an oleanane index &lt; 0.2. The results indicate that the Assran‐10 crude oil was derived from a marine carbonate source deposited in a highly reducing saline environment with a high bacterial contribution, consistent with the Upper Cretaceous Brown Limestone or Lower Eocene Thebes Formation containing Type IIS kerogen. Maturity parameters based on changes in the stereochemistry at chirality centres in hopane and sterane nuclei, such as C30βα/(βα+αβ) and C31 22S/(22S+22R) hopanes and C29ββ/(ββ+αα) and C29 20S/(20S+20R) steranes, together with triaromatic sterane cracking ratios, indicate that the oil sample was marginally mature. The results also suggest that biodegradation is probably due to sulphate‐reducing anaerobic bacteria.

Hydrocarbon potentiality, burial history and thermal evolution for some source rocks in October oil field, northern Gulf of Suez, Egypt

This paper attempts to apply a one dimensional model on four source rocks (Belayim, Lower Rudeis, Thebes, and Brown Limestone formations), in East Warda concession, October oil field, throughout the different geological times. Moreover, the fundamental aspects of the petroleum system in the study area is evaluated through studying maturation and hydrocarbon potential in order to gain an understanding of onset of oil generation and expulsion. The position of three wells (syn. or pseudo wells) is proposed based on the available geological and thermal data. Also, the existing temperature database is enhanced by using the available temperature data for 220 wells in the Gulf of Suez and the Red Sea, 53 wells in the Mediterranean Sea, 29 wells in the Nile delta, 7 wells in Sinai, 2 wells in Upper Egypt and 39 wells in the Western desert. Finally, the timing of oil generation for Belayim, Thebes, Lower Rudeis and Brown Limestone source rocks in the Northern Gulf of Suez area is updated. From this study we conclude that, the cumulative yield of the Belayim and Lower Rudeis formations is lower than that of the Thebes and Brown Limestone formations.

Source Rock Depositional Environment and Maturation Assessment Dependent C7 Light Hydrocarbons from Crude Oils in the Gulf of Suez, Egypt

A collection of 14 crude oil samples representing 13 giant oil fields from the prerift and synrift reservoirs of the Gulf of Suez province were analyzed for C7 light hydrocarbons. The light hydrocarbon parameters C7 star plot diagrams in conjunction with the biomarker characteristics differences were used to distinguish the Gulf of Suez into two oil groups, the prerift and synrift oils, which are predominantly source related and maturity dependent. The biomarker properties indicate that the prerift oils exhibit oleanane index 23%, while the synrift oils are characterized by relatively higher oleanane index around 30% and low gammacerane index values <10%. The prerift oils are correlated with the Upper Cretaceous Brown Limestone and Sudr chalk formations, which are possibly representative of the carbonate-rich marine source rocks of type II kerogen. The synrift oils are correlated with Lower Miocene Rudeis siliciclastic source rocks of mixed types II-III kerogen. The prerift and synrift source rocks entered the oil generation window at vitrinite reflectance between 0.7 to 0.9 Ro%, equivalent to formation temperature at 110°C and 125°C, which permits the expulsion of mature crude oils to reservoir rocks according to their stratigraphic and structural relations. The higher sterane maturity parameters, i.e., diasterane index, C 29 ααα20S/(S + R), and C 29 αββ/(αββ + aaa), of the prerift oils imply a generation from carbonate rich marine source rocks at a very high maturity level in comparison with the relatively mature siliciclastic source rocks that generated the synrift oils in the Gulf of Suez rift basin.

SOURCE ROCK CHARACTERIZATION BASED ON BIOLOGICAL MARKER DISTRIBUTIONS OF CRUDE OILS IN THE SOUTHERN GULF OF SUEZ, EGYPT

The depositional environment and maturity of source rocks in the southern Gulf of Suez were evaluated using biomarker and isotope data from crude oils derived from a variety of source rock types of different geological ages. Two oils families were identified and are referred to as types A and B. Type A oils are characterized by a predominance of oleanane and relatively low gammacerane concentrations, suggesting that they were derived from a terrigenous source rock with a significant input of angiosperm material inferred to occur within the marginally‐mature syn‐rift Lower Miocene Rudeis Shale. By contrast, type B oils are distinguished by a predominance of gammacerane and relatively low oleanane concentrations, suggesting that they were generated from mature marine carbonate source rocks inferred to occur within the Upper Cretaceous Brown Limestone and Middle Eocene Thebes Formation. Maturity parameters including the sterane isomerisation ratios C29αββ/(αββ+ααα), C29ααα20S/(S+R) and TAS/(TAS+MAS), together with aromatic sulphur compound ratios (4‐MDBT / I‐MDBT; 4,6‐ / 1,4‐DMDBT; 2,4–/ 1,4‐DMDBT; and DBT / phenanthrenes), support the higher thermal maturity of type B oils relative to type A oils.The biomarker variablility reflects the occurrence of two distinct source rocks in the southern Gulf of Suez and suggests that two independent petroleum systems are present here. These appear to be confined to the pre‐rift (pre‐Miocene) and syn‐rift megasequences respectively.

Organic and Carbon Isotope Geochemistry of Crude Oils from Ashrafi Field, Southern Gulf of Suez Province, Egypt: Implications for the Processes of Hydrocarbon Generation and Maturation

Four crude oil samples representing the Miocene formations of Belayim, Kareem, and Nukhul, and the Pre-Miocene Nubia Sandstone of Ashrafi Field, offshore southern Gulf of Suez, Egypt. These crude oil samples were analyzed using a variety of organic geochemical techniques including both C7 and whole oil Gas Chromatography (GC), Gas Chromatography–Mass Spectrometry (GC–MS) in addition to stable carbon isotopes to the saturate and aromatic fractions. The organic geochemical results revealed that the Miocene and Pre-Miocene Nubia Sandstone oils generated from two different source rocks subjected to different maturation levels. The Miocene crude oil possesses geochemical properties rich in tricyclic terpanes and extended hopanes typical characteristics of oils generated from marine siliciclastic source rocks with angiosperm land plants input like Rudeis Formation as indicated from the oleanane index which exceeds 30% and low gammacerane index around 10%. Meanwhile the Pre-Miocene crude oil correlates with the marine carbonate sources of high salinity waters like Brown Limestone of Upper Cretaceous age as indicated from the oleanane index <10% and high gammacerane index >30%. The maturity parameters based on both ratios of 20S/(20S + 20R)-C29 ααα cholestane and TAS/(MAS + TAS) were found to be around 0.5 for the Miocene crude oils, meanwhile both the ratios for the Pre-Miocene crude oil were >0.5. The concluded results further support the very high maturation level of the Pre-Miocene crude oil than the Miocene crude of Ashrafi Field which concordant with the reservoir stratigraphic depths.

Organic Carbon Storage in Soils of Tropical and Subtropical China

Tropical and subtropical China occupies a total area of about215 Mha, but the contents and storage of soil organic carbon (C)on this land have not been well studied. This research wasconducted in this concern by jointly using soil survey data andthe regional soil map. It was estimated that the 0–20 cm Cdensity of the soil subgroups in the region varied from 1.2 to9.7 kg C m-2. In the major zonal soils, soil subgroup`young ∼' had generally a C density about 1.2–4.4 timeslower than its other natural counterparts. Furthermore, subgroups of thecultivated soil gave a C density about 20–63% lower than theirnatural counterparts (except subgroup `young ∼'), showingremarkable C losses caused by cultivation. For soil groups inthe east, brown soil had the highest C density (6.8 and 21.4 kgC m-2, for the upper 20 and 100 cm soil, respectively),followed by yellow soil, yellow brown soil and limestone soil (4.6–5.5 and 12.3–14.5 kg C m-2, idem). Torrid red soil, purplishsoil and fluvo-aquic soil had the lowest C density (2.0–2.2 and5.8–7.5 kg C m-2, idem) with the others ranking at amedium level. In the west, podzolic soil ranked the highest(17.9 and 55.8 kg C m-2, idem), followed by dark brownsoil, brown soil and limestone soil (6.9–11.6 and 21–29 kg Cm-2, idem), and again torrid red soil, purplish soiland fluvo-aquic soil ranked the lowest (3.9–5.1 and 11.4–14.1 kg C m-2, idem). Finally, a total of about 26.8±7.4 Pg organic C was estimated being stored in soils of the entire region.

The factors controlling the abundance and migration of heavy versus light oils, as constrained by data from the Gulf of Suez. Part I. The effect of expelled petroleum composition, PVT properties and petroleum system geometry

In the Gulf of Suez (GOS) petroleum systems the main factors which control the abundance and migration of heavy vs light oils are (a) the composition and PVT properties of the expelled fluids, (b) the geometry of the petroleum systems and (c) reservoir flow processes. Compositional and PVT modeling of the expelled petroleum fluids from the Brown Limestone and the Thebes Formation carbonate source rocks show the following. The fluids expelled below a transformation ratio of 0.5 are heavy oils (stock tank API gravity = 10–20°), have a low GOR, and contain 20–25% asphaltenes. These fluids are formed from source rocks which have mainly low to intermediate sulfur content and normal thermal stability. The further expelled fluids, up to a transformation ratio of around 0.97, are bubble point behaving fluids (oils) with stock tank API from >20–50°, and GOR ≈ 300–800 scf/bbl. and display a progressive decrease in asphaltene content. The latest ≈3% expelled fluids represent dew point behaving fluids (gas-condensates). The heavy, low GOR oils expelled below a transformation ratio of 0.5, have a very low saturation pressure and are not prone to asphaltene precipitation, unless they are mixed with higher GOR fluids. The PVT properties of these early expelled oils permit their efficient migration. This is consistent with an overabundance of low maturity asphaltenes in the GOS discovered heavy oils. The tendency for asphaltene precipitation is increased for the fluids expelled above a transformation ratio of 0.5, due to both a decrease in their asphaltene content, and an increase in GOR. Geometrically imposed mixing of fluids with large maturity-induced compositional differences, and reservoir flow processes have a significant effect on the PVT behavior of the migrating fluids, on asphaltene precipitation, and on the distribution of heavy vs light oils.