ORGANIC GEOCHEMISTRY OF OIL AND NATURAL GAS IN THE WEST DIKIRNIS AND EL‐TAMAD FIELDS,ONSHORE NILE DELTA,EGYPT: INTERPRETATION OF POTENTIAL SOURCE ROCKS

Crude oil in the West Dikirnis field in the northern onshore Nile Delta, Egypt, occurs in the poorly‐sorted Miocene sandstones of the Qawasim Formation. The geochemical composition and source of this oil is investigated in this paper. The reservoir sandstones are overlain by mudstones in the upper part of the Qawasim Formation and in the overlying Pliocene Kafr El‐Sheikh Formation. However TOC and Rock‐Eval analyses of these mudstones indicate that they have little potential to generate hydrocarbons, and mudstone extracts show little similarity in terms of biomarker compositions to the reservoired oils. The oils at West Dikirnis are interpreted to have been derived from an Upper Cretaceous – Lower Tertiary terrigenous, clay‐rich source rock, and to have migrated up along steeply‐dipping faults to the Qawasim sandstones reservoir. This interpretation is supported by the high C₂₉/C₂₇ sterane, diasterane/sterane, hopane/sterane and oleanane/C₃₀ hopane ratios in the oils. Biomarker‐based maturity indicators (Ts/Tm, moretanes/hopanes and C₃₂ homohopanes S/S+R) suggest that oil expulsion occurred before the source rock reached peak maturity. Previous studies have shown that the Upper Cretaceous – Lower Tertiary source rock is widely distributed throughout the on‐ and offshore Nile Delta. A wet gas sample from the Messinian sandstones at El‐Tamad field, located near to West Dikirnis, was analysed to determine its molecular and isotopic composition. The presence of isotopically heavy δ¹³ methane, ethane and propane indicates a thermogenic origin for the gas which was cracked directly from a humic kerogen. A preliminary burial and thermal history model suggests that wet gas window maturities in the study area occur within the Jurassic succession, and the gas at El‐Tamad may therefore be derived from a source rock of Jurassic age.     

GEOCHEMISTRY AND ORIGIN OF UPPER CRETACEOUS OILS FROM THE TERMIT BASIN,NIGER

Crude oil samples (n = 16) from Upper Cretaceous reservoir rocks together with cuttings samples of Upper Cretaceous and Paleogene mudstone source rocks (n = 12) from wells in the Termit Basin were characterized by a variety of biomarker parameters using GC and GC‐MS techniques. Organic geochemical analyses of source rock samples from the Upper Cretaceous Yogou Formation demonstrate poor to excellent hydrocarbon generation potential; the samples are characterized by Type II kerogen grading to mixed Types II–III and III kerogen. The oil samples have pristane/phytane (Pr/Ph) ratios ranging from 0.73 to 1.27, low C₂₂/C₂₁ and high C₂₄/C₂₃ tricyclic terpane ratios, and values of the gammacerane index (gammacerane/C₃₀hopane) of 0.29–0.49, suggesting derivation from carbonate‐poor source rocks deposited under suboxic to anoxic and moderate to high salinity conditions. Relatively high C₂₉ sterane concentrations with C₂₉/C₂₇ sterane ratios ranging from 2.18–3.93 and low values of the regular steranes/17α(H)‐hopanes ratio suggest that the oils were mainly derived from kerogen dominated by terrigenous higher plant material. Both aromatic maturity parameters (MPI‐1, MPI‐2 and R_c) and C₂₉ sterane parameters (20S/(20S+20R) and ββ/ (αα + ββ)) suggest that the oils are early‐mature to mature. Oil‐to‐oil correlations suggest that the Upper Cretaceous oils belongs to the same genetic family. Parameters including the Pr/Ph ratio, gammacerane index and C₂₆/C₂₅ tricyclic terpanes, and similar positions on a sterane ternary plot, suggest that the Upper Cretaceous oils originated from Upper Cretaceous source rocks rather than from Paleogene source rocks. The Yogou Formation can therefore be considered as an effective source rock.     

GEOCHEMISTRY AND ORIGIN OF CRUDE OILS AND CONDENSATES FROM THE CENTRAL PERSIAN GULF,OFFSHORE IRAN

Biomarker‐ and compound‐specific carbon isotope analyses were used to compare oil samples recovered from Late Jurassic and Early to Middle Cretaceous reservoirs at South Pars and nearby fields in the Iranian portion of the Persian Gulf, and condensate samples associated with the super‐giant gas accumulation in Permo‐Triassic reservoirs at South Pars. The results indicate that all of the oil samples, including heavy oil from South Pars and oil from the Salman, Reshadat, Resalat and Balal fields, are genetically related. The most probable source rocks for these oils are Jurassic marine limestones or marls deposited under anoxic conditions. Based on the methyl phenanthrene index, source rock maturity was inferred to be equivalent to vitrinite reflectance values of about 0.8% Rc. The distribution and maturity pattern of the source rocks suggest migration from a depocentre located to the south, with inferred migration distances of up to 250 km. There is no genetic relationship between the heavy oil which has accumulated in Mesozoic reservoirs at South Pars and condensates which are associated with the super‐giant gas accumulation in Permo‐Triassic reservoirs there. Based on biomarker compositions, the condensates at South Pars appear to be derived from shaly marine or lacustrine source rocks deposited under dysoxic conditions. The δ¹³C values of short‐chain n‐alkanes and isoprenoids in condensate samples suggest a common source and an equal maturity for the source rocks. Pristane/n‐C₁₇ versus phytane/n‐C₁₈ characteristics are in agreement with published data for Silurian‐sourced condensates. High thermal maturities equivalent to 1.7% Rc are also consistent with a Palaeozoic (Silurian) source rock.     

DIAGENETIC-GEOCHEMICAL PATTERNS AND FLUID EVOLUTION HISTORY OF A LOWER JURASSIC PETROLEUM SOURCE ROCK, MIDDLE ATLAS, MOROCCO

Pliensbachian to earliest Toarcian marls and argillaceous limestones exposed at the surface near Aït Moussa (Boulemane Province, Middle Atlas) include the only examples of effective petroleum source rocks so far known in the Moroccan Atlas rift basins. The outcrop interval includes hemipelagic, peri‐Tethyan low latitude source rocks with Type II kerogen (total thickness of 2.5 m with mean TOC of around 3.2%). Early diagenetic, anoxic remineralisation of sedimentary organic matter resulted in hydraulic fractures, calcite cementation, a negative shift of carbon and oxygen stable isotopes relative to marine values (Δδ¹³C = ‐1.1; Δδ¹⁸O = ‐2.0), framboidal pyrite, and relative enrichment of the middle weight rare earth elements (REE). In combination, these attributes of early diagenesis may assist in the identification of other source rock intervals of similar age and setting. Progressive burial produced three generations of Fe‐calcite cemented veins, followed by three generations of replacive dolomite and concluded by ankerite replacing dolomite. Compaction fluids initially caused a slight positive shift of δ¹³C values (Δδ¹³C =+0.4), a flattening of the REE distribution pattern and an increase in REE content, together related to the dewatering of clay. Dolomitizing fluids (dol‐2 and dol‐3) record a positive shift of δ¹³C values (Δδ¹³C =+0.9) suggesting the effects of methanogenesis or an uptake of heavy δ¹³C from underlying rock formations during fluid migration. Dol‐3 is an Fe‐bearing saddle dolomite that carries a positive Eu‐anomaly (Eu/Eu*= 8.1) best explained by ascending hydrothermal fluids which are presumably of Middle Eocene age. A first migration of bitumen is recorded as fluorescent inclusions in dol‐2 (Late Jurassic ‐ Cretaceous), but bituminous fluids remained normally pressured until the establishment of inclined stylolites during Late Eocene tectonic compression. Comparative organic‐geochemical analyses (GC, NMR of inclusions, non‐expelled and expelled bitumen) indicate that thermal maturation advanced significantly after the onset of migration. Differences in terms of Pr/n‐C₁₇, Ph/n‐C₁₈ ratios and aromaticity corroborate the effects of differential expulsion. An exploration strategy should consider both secondary migration via opened tectonic stylolites in association with late‐diagenetic fractures and a persisting tightness that then could have created an unconventional oil reservoir.     

ORGANIC GEOCHEMISTRY OF CRUDE OILS AND UPPER CRETACEOUS SOURCE ROCKS FROM CONCESSION 11, WEST SIRTE BASIN,LIBYA

This paper reports the results of Rock‐Eval pyrolysis and total organic carbon analysis of 46 core and cuttings samples from Upper Cretaceous potential source rocks from wells in the West Sirte Basin (Libya), together with stable carbon isotope (δ¹³C) and biomarker analyses of eight oil samples from the Paleocene – Eocene Farrud/Facha Members and of 14 source rock extracts. Oil samples were analysed for bulk (°API gravity and δ¹³C) properties and elemental (sulphur, nickel and vanadium) contents. Molecular compositions were analysed using liquid and gas chromatography, and quantitative biological marker investigations using gas chromatography – mass spectrometry for saturated hydrocarbon fractions, in order to classify the samples and to establish oil‐source correlations. Core and cuttings samples from the Upper Cretaceous Etel, Rachmat, Sirte and Kalash Formations have variable organic content and hydrocarbon generation potential. Based on organofacies variations, samples from the Sirte and Kalash Formations have the potential to generate oil and gas from Type II/III kerogen, whereas samples from the Etel and Rachmat Formations, and some of the Sirte Formation samples, have the potential to generate gas from the abundant Type III kerogen. Carbon isotope compositions for these samples suggest mixed marine and terrigenous organic matter in varying proportions. Consistent with this, the distribution of n‐alkanes, terpanes and steranes indicates source rock organofacies variations from Type II/III to III kerogen. The petroleum generation potential of these source rocks was controlled by variations in redox conditions during deposition together with variations in terrigenous organic matter input. Geochemical analyses suggest that all of the oil samples are of the same genetic type and originated from the same or similar source rock(s). Based on their bulk geochemical characteristics and biomarker compositions, the oil samples are interpreted to be derived from mixed aquatic algal/microbial and terrigenous organic matter. Weak salinity stratification and suboxic bottom‐water conditions which favoured the preservation of organic matter in the sediments are indicated by low sulphur contents and by low V/Ni and Pr/Ph ratios. The characteristics of the oils, including low Pr/Ph ratio, CPI ～l, similar ratios of C₂₇:C₂₈:C₂₉ ααα‐steranes, medium to high proportions of rearranged steranes, C₂₉ <C₃₀‐hopane, low Ts/Tm hopanes, low sulphur content and low V/Ni ratio, suggest a reducing depositional environment for the source rock, which was likely a marine shale. All of the oil samples show thermal maturity in the early phase of oil generation. Based on hierarchical cluster analysis of 16 source‐related biomarker and isotope ratios, four genetic groups of extracts and oils were defined. The relative concentrations of marine algal/microbial input and reducing conditions decrease in the order Group 4 > Group 3 > Group 2 > Group1. Oil – source rock correlation studies show that some of the Sirte and Kalash Formations extracts correlate with oils based on specific parameters such as DBT/P versus Pr/Ph, δ¹³C_saturates versus δ¹³C_aromatics, and gammacerane/hopane versus sterane/hopane.     

HYDROCARBONS IN THE MIDDLE MIOCENE JERIBE FORMATION,DYALA REGION,NE IRAQ

The Lower Miocene Jeribe Formation in northern and NE Iraq is composed principally of dolomitic limestones with typical porosity in the range of 10–24% and mean permeability of 30 mD. The formation serves as a reservoir for oil and gas at the East Baghdad field, gas at Mansuriya, Khashim Ahmar, Pulkhana and Chia Surkh fields, and oil at Injana, Gillabat, Qumar and Jambur. A regional seal is provided by the anhydrites of the Lower Fars (Fat'ha) Formation. For this study, oil samples from the Jeribe Formation at Jambur oilfield, Oligocene Baba Formation at Baba Dome (Kirkuk field) and Late Cretaceous Tanuma and Khasib Formations at East Baghdad field were analysed in order to investigate their genetic relationships. Graphical presentation of the analytical results (including plots of pristane/nC₁₇ versus phytane/nC_l8, triangular plots of steranes, tricyclic terpane scatter plots, and graphs of pristanelphytane versus carbon isotope ratio) indicated that the oils belong to a single oil family and are derived from kerogen Types II and III. The oils have undergone minor biodegradation and are of high maturity. They were derived from marine organic matter deposited with carbonate‐rich source rocks in suboxic‐anoxic settings. A range of biomarker ratios and parameters including a C₂₈/ C₂₉ sterane ratio of 0.9, an oleanane index of 0.2 and low tricyclic terpane values indicate a Late Jurassic or Early Cretaceous age for the source rocks, and this age is consistent with palynomorph analyses. Potential source rocks are present in the Upper Jurassic – Lower Cretaceous Chia Gara Formation and the Middle Jurassic Sargelu Formation at the Jambur, Pulkhana, Qumar and Mansuriya fields; minor source rock intervals occur in the Balambo and Sarmord Formations. Hydrocarbon generation and expulsion from the Chia Gara Formation was indicated by pyrolysate organic matter, palynofacies type (A), and the maturity of Gleichenidites spores. Oil migration from the Chia Gara Formation source rocks (and minor oil migration from the Sargelu Formation) into the Jeribe Formation reservoirs took place along steeply‐dipping faults which are observed on seismic sections and which cut through the Upper Jurassic Gotnia Anhydrite seal. Migration is confirmed by the presence of asphalt residues in the Upper Cretaceous Shiranish Formation and by a high migration index (Rock Eval SI / TOC) in the Chia Gara Formation. These processes and elements together form a Jurassic/Cretaceous – Tertiary petroleum system whose top‐seal is the Lower Fars (Fat'ha) Formation anhydrite.     

ORIGIN OF CRUDE OILS IN OMAN

The petroleum geochemistry of Oman provides a picture of considerable variey, since crude oils and their source rocks are found both throughout the country and throughout the stratigraphic column from the Infra-Cambrian to the Tertiary. This paper reviews the geological history history of the area and places the petroleum geochemistry within the geological context. The oils can be geochemically classified into five groups. Three groups can be related to god oil source rocks found in the pre-Cambrian Huqf Group, the Silurian Safiq and the Cretaceous Natin Formation. Another group of oils probably originates from the Upper Jurassic Diyab Formations, while the fifth group of crudes (named ‘Q’) cannot be correlated to a known source rock, but is inferred to have originated from an unsampled Huqf level. The “Huqf oils” are those that have been correlated to known Infra-Cambrian Huaf source rocks, and are characterized by a strong C₂₉ sterane predonominance and very light carbon isotope values of around-36.0%. In contrast, the ‘Q’ crudes, drived from the unknown source are characterized by a C₂₇ strerane predominance and carbon istope ratios of around -30.5%. Both the Huaf and ‘Q’ crudes also contain a series of characteristic compounds referred to as the ‘X’ compounds (all isomers of methyle and dimethyl alkanes). Oils reasoned to originate from Silurian Safiq source rocks have a week C₂₉ sterane precominance, a significant content of rearranged steranes and carbon isotope ratios of -30.5%. The oils thought to originate from the Jurassic Diyab Formation have a similar sterane distribution but heavier carbon isotope values of around -26.5%. Finally, the crude oils from the mid-Cretaceous Naith Formation source rocks are characteirzed by steranes with an equivalent distribution of C₂₇, C₂₈ and C₂₉ isomers, and carbon isotope values of around -26.9%. These variations in biomarker distributions and carbon isotope values are sufficiently distinct to ensure a high degree of certainty in the grouping of the crude oils.     

Petroleum Geochemistry of Lower Indus Basin,Pakistan: II. Oil-oil and Oil-source Rock Correlation

Nine crude oils and eight source rock samples from Cretaceous sequences, Lower Indus Basin have been characterized by means of diagnostic biomarker parameters in order to establish genetic liaison among them. The biomarker geochemistry indicators such as relative distribution of C₂₇-C₂₈-C₂₉ ααα-20R steranes, C₁₉ and C₂₃ tricyclic terpanes (TT), C₂₄ tetracyclic terpanes (TeT), hopanes distribution, steranes/hopanes ratio, presence of unidentified compound X (C₃₀ pentacyclic triterpane), and pristane (Pr) to phytane (Ph) ratio suggest that the crude oils contain predominantly terrigenous organic matter (OM). Based on these data, the analyzed crude oils from the Lower Indus Basin are genetically associated and could be classified into a single group. Geochemical correlation studies of crude oils and source rock sediments indicate that Lower Goru shales and Sembar could be the probable source rocks for the petroleum generated from Cretaceous strata, Lower Indus Basin, Pakistan.     

GENETIC CLASSIFICATION OF OIL FAMILIES IN THE CENTRAL AND SOUTHERN SECTORS OF THE GULF OF SUEZ,EGYPT

The results of geochemical analyses were used to classify ten oil samples from six fields in the central and southern sectors of the Gulf of Suez, Egypt. The samples were collected from sandstone pay‐zones ranging in age from Early Palaeozoic (Nubia‐C) to Miocene (Kareem Formation) at various present‐day depths. Molecular and stable isotope analyses indicate the presence of two genetic oil families (Families I and II) and suggest their probable source rocks. The biomarker characteristics of Family 1 oils include low Pr/Ph ratio, CPI < 1.0, depleted rearranged steranes, very low diahopane concentrations, high sulphur content, high metal content and V/Ni ratio, low oleanane index, abundance of gammacerane and C₂₇ steranes, and high relative abundance of homohopanes and C₃₀ 24‐n‐propylcholestanes. Source rock deposition took place under anoxic marine‐carbonate and hypersaline conditions. The NCR and NDR 24‐norcholestane ratios together with the presence of highly‐branched isoprenoids in this oil family are consistent with Upper Cretaceous – Lower Paleogene source rocks. These characteristics suggest that the Upper Cretaceous Duwi Formation/Brown Limestone or Lower Eocene Thebes Formation are the source rocks for the oils in this family, which occur in the central sector of the Gulf of Suez. Family II oils have geochemical characteristics that point to a mature source rock deposited in a weakly reducing or suboxic setting under normal salinity conditions. Abundant oleananes, high 24‐ to 27‐norcholestane ratios and abundant C₂₅ highly‐branched isoprenoids suggest a Paleogene source rock. The Lower Miocene Rudeis Formation is the best candidate to have generated these oils which occur in the southern sector of the Gulf of Suez.     

MONITORING GAS DISTRIBUTION AND ORIGIN IN THE CULZEAN FIELD,UK CENTRAL NORTH SEA,USING DATA FROM A CONTINUOUS ISOTOPE LOGGING TOOL AND ISOTUBE AND TEST SAMPLES

The high pressure – high temperature Culzean field, UK Central North Sea, contains lean gas condensate in the Triassic Joanne sandstones and the Middle Jurassic Pentland sandstones. A comprehensive gas analysis programme was installed as an integrated part of field development in order to monitor gas composition, distribution and origin in the reservoirs and overburden pre‐ production start‐up. Isotube OUT and isotube IN gas samples were collected. The isotube IN data show that some gas is recycled, including alkenes representing contamination from the degradation of mud additives; but concentrations are minor, and do not seem to affect the isotope values derived from the C₂ and C₃ isotube OUT gases significantly. ¹³C‐enriched methane derived from drill‐bit metamorphism is recorded in the isotube IN gas, but likewise in low concentrations. Gas data were also acquired from a Continuous Isotope Logging Tool (CILT) which measures real‐time gas concentrations and isotope values of C₁–C₃ each foot through the entire drilled section. The CILT thus provides a continuous trend of methane isotope values versus depth, and this trend is useful in identifying changes in gas composition. However, concerns related to CILT include: (i) C₁–C₃ stable carbon isotope detection limits for isotube OUT gas analyses are considerable lower than for CILT; due to the lower isotube gas concentrations required for measurement of C₃ isotopes, isotubes are able to map a shallower vertical thermogenic gas migration front in the overburden. (ii) Discrepancies between isotube OUT and CILT isotope values may be significant and cannot be assigned to analytical uncertainty; by contrast, test gas and isotube OUT isotope values are comparable. Hence, CILT isotope values from specific depths cannot stand in isolation but must be complemented by isotube OUT isotope measurements. Gas in the Pentland reservoir is the most coaly in composition due to self‐sourcing from the Pentland coals. The coals are the primary source rock for the gas encountered in the entire reservoir interval at Culzean, but the underlying Joanne sandstones contain contributions from highly mature marine shales in the Kimmeridge Clay Formation and/or Heather Formation. The Lower Cretaceous seal on top of the Pentland reservoir is relatively tight but some minor migration/leakage of thermogenic gas into the overburden is recorded by the detection of C₃ isotopes. Thermogenic gas also occurs in high porosity intervals in the Upper Cretaceous succession but this gas is interpreted to have migrated laterally in porous carrier beds and did not enter these intervals at the well locations.