Miocene Source Rocks Research Articles

Organic richness, hydrocarbon potentiality, maturity, and timing of petroleum generation of the Cretaceous and Miocene source rocks in the central Gulf of Suez, Egypt

ABSTRACTTotal organic carbon (TOC) and pyrolysis analysis of the Cretaceous and Miocene source rocks in the central Gulf of Suez were evaluated throughout the 25 rock samples collected from 6 formations, namely Wata, Raha, Nubia “A” (Cretaceous source rocks); and Nukhul, Zeit, and Belayim (Miocene source rocks) from Gharib-252, Gharib-153, Gharib-163, Gharib-164, Gharib-167, and Gharib-165 wells. These data are used to study the probabilities of the source rock in the Cretaceous and Miocene source rocks in the central Gulf of Suez for the hydrocarbon generation through identifying the organic richness, type of organic matters, and thermal maturation of these organic materials. The results revealed that the Cretaceous formations are immature source rocks, ranging from fair to good source rocks and have kerogen of type III and type III/II. Meanwhile, Miocene source rocks, ranging from immature to marginally mature source rocks, are considered to range from good to very good source rocks for potential generation of both oil and gas and are characterized by kerogen of type III/II and type II.

Hydrocarbon maturation modeling of Paleocene to Lower Miocene source rocks in the Niger Delta Basin: implications for hydrocarbon generation

This study evaluates the hydrocarbon generation potentials and time of generation for Paleocene to Lower Miocene source rock horizons from A-1, B-1, B-2, and C-1 wells in the Niger Delta Basin using 1D Petromod modeling software. Wells A-1, B-1 and B-2, and C-1 are located within the Central Swamp, the Coastal Swamp, and the Shallow Offshore depobelts, respectively. The thermal history was derived from the rifting–subsidence heat flow model. Maturity modeling were carried out by using Easy%Ro kinetic model and a heat flow history predicting present-day heat flow which were calibrated with measured temperature data. Results of the study suggest that these potential source rocks have attained maturity status to generate hydrocarbons, with vast differences existing in the timing of the onset of oil generation. Basin modeling suggests that Paleocene source rocks entered the oil generative window from the Oligocene to Miocene times with thermal maturity window that varies from gas generation to early-mature phase. The Eocene source rocks have also attained maturity from Miocene to Pliocene times, and their thermal maturity ranges from gas generation to early maturity stage. The Oligocene source rocks also began to generate oil during the Miocene and are currently within the early-mature to mid-mature stage. The thermal maturity window for the Lower Miocene source rocks ranges from immature to early-mature stage. The present modeling results reveals that higher levels of thermal maturity are attained in areas with high geothermal gradients and heat flow values while the cooler areas exhibits lower levels of maturation. The onset of the oil window lies at 2859 m at A-1 (Central Swamp), 3240 m at B-2 (Coastal Swamp), 4732 m at B-1 (Coastal Swamp), and 4344 m at C-1 (Shallow Offshore). The depth to the onset of oil window is found deeper in the Shallow Offshore and western parts of the study area than in the eastern and northwestern parts. The result of this study suggest that the Paleocene, Eocene, Oligocene, and Lower Miocene source rocks are the principal source rocks for oil and gas generation in the Niger Delta Basin.

Evaluation of organic matters, hydrocarbon potential and thermal maturity of source rocks based on geochemical and statistical methods: Case study of source rocks in Ras Gharib oilfield, central Gulf of Suez, Egypt

In this study, we apply geochemical and statistical analyses for evaluating source rocks in Ras Gharib oilfield. The geochemical analysis includes pyrolysis data as total organic carbon (TOC%), generating source potential (S2), production index (PI), oxygen and hydrogen indices (OI, HI) and (Tmax). The results show that the Cretaceous source rocks are poor to good source rocks with kerogen of type III and have the capability of generating gas while, the Miocene source rocks are good to excellent source rocks with kerogen of type III–II and type II and have the capability of generating oil and gas. The analyzed data were treated statistically to find some factors, clusters, and relations concerning the evaluation of source rocks. These factors can be classified into organic richness and type of organic matter, hydrocarbon potentiality and thermal maturity. In addition, cluster analysis separated the source rocks in the study area into two major groups. (1) Source rocks characterized by HI >300 (mg/g), TOC from 0.76 to 11.63wt%, S1 from 0.44 to 9.49 (mg/g) and S2 from 2.59 to 79.61 (mg/g) indicating good to excellent source rocks with kerogen of type III–II and type II and are capable of generating oil and gas. (2) Source rocks characterized by HI <300 (mg/g), TOC from 0.31 to 2.07wt%, S1 from 0.17 to 1.29 (mg/g) and S2 from 0.31 to 3.34 (mg/g) indicating poor to good source rocks with kerogen of type III and are capable of generating gas. Moreover, Pearson’s correlation coefficient shows a strong positive correlation between TOC and S1, S2 and HI and no correlation between TOC and Tmax, highly negative correlation between TOC and OI and no correlation between Tmax and HI.

The geodynamics of faults and petroleum migration in the Los Angeles basin, California

A two-dimensional multiphase fluid flow model, coupled with heat flow, using a hybrid finite element and finite volume method is developed and applied to fundamental issues of long-distance petroleum migration and accumulation in the Los Angeles basin, which is intensely faulted and deformed by transpressional tectonic stresses, yet host to the world9s richest oil accumulation. These simulations show that a combination of continuous hydrocarbon generation and primary migration from upper Miocene (∼10 – 5 Ma) source rocks in the central Los Angeles basin synclinal region, coupled with subsiding basin fluid dynamics, favored the massive accumulation and alignment of hydrocarbon pools along the Newport-Inglewood fault zone (NIFZ). According to our multiphase flow calculations, the maximum formation water velocity within fault zones likely ranged between 0.5 to 1.0 m/yr during the middle Miocene to Pliocene epochs (13–2.6 Ma). The estimated time for long-distance (∼25 km) petroleum migration from source beds in the central basin to oil fields along the NIFZ is approximately 90,000 to 220,000 years, depending on the effective permeability assigned to the faults (5 ∼ 50 md) and adjacent inter-bedded sandstone and siltstone “petroleum aquifers.” With an average long-distance flow rate of 0.2 m/yr and fault permeability of 20 md (2.0 × 10⁻¹³ m²), the total petroleum volume of the Inglewood oil field (450 million barrels ≈ 1.6 × 10⁵ m³) would have accumulated over a period of 180,000 years or less. The results also suggest that besides the thermal and structural history of the basin, the fault permeability, capillary pressure, and the configuration of aquifer and aquitard layers played an important role in controlling petroleum migration rates, patterns of flow and saturation, and the overall fluid mechanics of petroleum accumulation.

The formation environment and development modes of Cenozoic source rocks in the Qiongdongnan Basin

According to the drilling results, there are three sets of source rocks of the Cenozoic Group in the Qiongdongnan Basin, including the Yacheng Formation transitional facies mudstone, the Oligocene Lingshui Formation semi-enclosed marine facies mudstone, and the Miocene neritic-bathyal facies mudstone. The hydrocarbon generating conditions of the source rocks in the study area are mainly controlled by sedimentary environment and organic matter input. The abundance of organic matter in the Oligocene source rocks which were formed in a low-energy back shore environment is confined by organic matter input and hydrodynamic condition. The Miocene source rocks formed in the open marine environment lack terrestrial organic matter input, whose organic matter abundance is constrained by the primary production of the ocean and the preservation condition of organic matter. In addition, the redox conditions are also significant to the formation of source rocks in the study area. According to the differences in key factors controlling the development of source rocks in different time periods and structural belts revealed by drilling practice, three development patterns of source rocks have been put forward. The first one is the transitional facies model featuring a great deal of terrestrial organic matter and weakly hydrodynamic conditions which are apt to develop high effective source rocks in the Yacheng Formation. The second one is the semi-enclosed marine facies featuring abundant terrestrial organic matter, weakly hydrodynamic condition and fine preservation condition in the central depression zone, which are apt to form fine-quality source rocks in the Lingshui Formation. The third one is the marine facies model featuring strong hydrodynamics in the shore-shallow area of northern continental shelf and the lack of benthic algae which are against the development of source rocks. It can be predicted that the continental slope is the perfect place to form source rocks where adequate amounts of light favor the photosynthesis of plants, besides the fine preservation and weakly hydrodynamic conditions. In the deep sea area, although accompanied with weakly hydrodynamic conditions and a reduction environment, it is not suitable for the development of source rocks on account of less aquatic organisms causing low primary production.

Organic geochemistry of Miocene source rocks from the Banat Depression (SE Pannonian Basin, Serbia)

The origin, depositional environment and maturity of petroleum source rocks were determined via conventional whole rock and biomarker analysis of samples from wells in the Banat Depression, where the most important Serbian oil and gas fields are located. The organic matter (OM) in organic-rich upper Tertiary siltstones and marls consists predominantly of Type II kerogen. Numerous biomarker parameters indicated mixed algal-terrestrial OM, related to a brackish or freshwater environment, whose salinity decreased from Middle to Upper Miocene. The OM was deposited under variable redox conditions, reducing to sub-oxic. The wells in the Banat Depression experienced variable high rates of rapid heating, providing an opportunity for examining the applicability of different thermal indicators in a hyperthermal basin. Rock–Eval and numerous biomarker parameters indicate that the main stage of oil generation begins at ca.130 °C and vitrinite reflectance (Rc) ca. 0.63% and reaches a maximum at ca.145–150 °C and Rc ca. 0.72–0.75%, while the late stage of oil generation starts at ca.155 °C and ca. Rc 0.78%, which corresponds, depending on geothermal gradient, to relative depths of 2100–2300 m, 2600–2900 m and 3050–3100 m, respectively. The naphthalene and phenanthrene maturity parameters proved to be less applicable than the biomarker ratios, particularly in the early to moderate maturation range. The newly proposed parameter C(14a)-homo-26-nor-17α(H)-hopane/C 30hopane (C 30HH/C 30H) proved applicable to a wide range of maturity.

Confined pyrolysis of Tertiary lacustrine source rocks in the Western Qaidam Basin, Northwest China: Implications for generative potential and oil maturity evaluation

Abstract The parameter S 1 + S 2 (genetic potential) of Rock-Eval analysis is widely used as an evaluation of the genetic potential for the source rocks. Oligocene–Miocene saline lacustrine source rocks in the western Qaidam basin have low total organic C contents (TOC), most around 0.5% with a few exceptions >1.0%. Mineral matrix effects are substantial for source rocks with low TOC, resulting in relatively low S 1 and S 2 peaks. Based on the results of confined pyrolyses (sealed Au capsules) on 6 Oligocene–Miocene source rocks from the western Qaidam basin, with TOC ranging between 0.48% and 2.22%, the relationship between the S 1 + S 2 parameter and the maximum amount of extracted bitumen or saturated and aromatic hydrocarbons (SA) after the confined pyrolysis has been established as follows: bitumen (mg/g rock) = 1.4924 × ( S 1 + S 2 ) + 0.3201 ( r = 0.987), or SA (saturates + aromatics) (mg/g rock) = 0.7083 × ( S 1 + S 2 ) + 0.4045 ( r = 0.992). Based on these formulas, the amounts of hydrocarbons generated from source rocks can be reasonably estimated. The typical crude oils with low biomarker maturities in this region appear substantially different to the pyrolysates of these six rocks at 180–300 °C but comparable to the pyrolysates at 320 °C and higher temperatures based on molecular parameters. This result, in combination with the physical and gross compositions of the crude oils, suggests that the majority of these crude oils were generated from the source rocks during the main oil-generative stage, possibly at a maturity higher than R o 0.74%.

Comparison between the Middle Miocene and the Upper Miocene source rock formations in the Sava Depression (Pannonian Basin, Croatia)

The Sava Depression lies at the very south-western margin of the Pannonian Basin. There are 20 hydrocarbon fields altogether and 17 are still in production. The organic geochemistry data and their statistical analysis from the 25 exploration wells, indicate source rock formations in two stratigraphic levels, an older one of Middle Miocene age (Badenian and Sarmatian) and a younger one of Upper Miocene age (Lower Pannonian). Both source rock formations are composed of marls, calcitic marls, clayey limestones and shales. Source rock intervals lay at depths from 1200 to 3362 m. The Total Organic Carbon (TOC) of analyzed samples varies from 0.39 to 4.94%, while their total generative hydrocarbon potential is from 2.40 to 37.40 mg HC/g rock. The mean thickness of the intervals is 100–150 m. There is a regular linear increase of the maturity level with depth. Source rocks are mature, in the catagenetic phase of transformation that enables hydrocarbon generation. A favourable organic facies, mostly kerogen type II, (organic facies AB and B), with good hydrocarbon potential, dominates the north-western and central part of the depression. It can be connected with the deeper parts of the depression and/or protected, anoxic to dysoxic stagnant environments with a gradual transition from marine (Badenian/Sarmatian) to brackish depositional environments (Lower Pannonian). In the south-eastern part of the depression, the dominant kerogen type is II–III, (organic facies BC), which indicates a stronger influx of terrestrial material from the uplifted parts that are generally closer to the margins of the depositional basin. The Fisher test (F-test) of the variance similarity (homogeneity), clearly indicates that the Badenian/Sarmatian samples belong to a statistically different population from the Lower Pannonian ones, due to their different depositional environments.

THE ORGANIC MATTER CHARACTERISTIC OF LOWER MIOCENE FORMATION IN CUU LONG BASIN

Cuu Long basin is located mainly in South Vietnam continental shelf and a part of mainland belonging to Mekong estuary area. It has an oval shape, convex seawards and lies along Vung Tau-Binh Thuan coast. Cuu Long basin adjoins mainland northwestwards, separates from Nam Con Son basin by Con Son uplift, southwest part is Khorat - Natuna uplift and northeast part is Tuy Hoa strike-slips separated from Phu Khanh basin. Recent oil and gas quantity exploited from Cuu Long basin is evaluated to be produced dominantly from Oligocene organic-rich sediments. Some studies suggested that organic matter of lower Miocene shale deposits fails to come up to standard of source rock or very poor source rock. Lower Miocene sediments considered how to play a role in providing production into trap is the subject studied more in detailed in this report. The organic carbon (TOC %) in lower Miocene source rocks contains mostly kerogene type III is 0.64-1.32%. The depositional environment of the organic matter in the lower Miocene sediments is terrestral. Therefore the lower Miocene formation may be considered the source rocks, but has not generated hydrocarbon, because it has not passed the oil window. The depositional environment of the organic matter in the lower Miocene sediments is terrestry.

Spatial distribution and geochemistry of the nearshore gas seepages and their implications to natural gas migration in the Yinggehai Basin, offshore South China Sea

About 120 gas seepage vents were documented along the west and southwest coast of the Hainan Island, South China Sea, in water depths usually less than 50 m. The principal seepage areas include the Lingtou Promontory, the Yinggehai Rivulet Mouth, Yazhou Bay, the Nanshan Promontory and the Tianya Promontory. They occur along three major zones, reflecting the control by faults and lateral conduits within the basement. It is estimated that the total gas emission from these seepage vents is 294–956 m 3/year. The seepage gases are characterized by a high CH 4 content (76%), heavy δ 13C 1 values (−38 to −33‰) and high C 1/C 1–5 ratios (0.95–1.0), resembling the thermogenic gases from the diapiric gas fields of the Yinggehai Basin. Hydrocarbon–source correlation shows that the hydrocarbons in the sediments from seepage areas can be correlated with the deeply buried Miocene source rocks and sandstone reservoirs in the central depression. The 2D basin modeling results based on a section from the source rock center to the gas seepage sites indicate that the gas-bearing fluids migrated from the source rocks upward through faults or weak zones encompassed by shale diapirism or in up-dip direction along the sandstone-rich strata of Huangliu Formation to arrive to seabed and form the nearshore gas seepages. It is suggested that the seepage gases are sourced from the Miocene source rocks in the central depression of the Yinggehai Basin. This migration model implies that the eastern slope zone between the gas source area of the central depression and the seepage zone is also favorable place for gas accumulation.

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

: The organic geochemical and biomarker analyses of the Miocene source rocks of some wells in the onshore Nile Delta, suggested that the Abu Madi Formation has poor immature to marginally mature source rocks of Type III Kerogen deposited under the terrestrial environment. The Sidi Salem Formation has fair-to-good mature source rocks of producing mixed oil and gas, originating mainly from marine organic sources. The Moghra Formation has mature good source rocks for Type (II/III) kerogen, derived from organic matter and rich in both terrigeneous and marine sources. The geochemistry of condensates revealed that the Abu Madi and Moghra condensates originated from marine organic matters with little input from a terrestrial source, while Sidi Salem condensate was derived from more contribution of terrestrial organic matters. Abu Madi condensate is less mature than Sidi Salem and Moghra condensate. The geochemical thermal modeling of the Miocene source rocks indicates that the Abu Madi formations are in the early stages of hydrocarbon up until the present time, while Moghra and Sidi Salem formations are in the mature stage of hydrocarbon generation up until the present time. This indicates that the studied condensates have probably migrated from deeply buried source rocks which are at a higher level of maturity rather than from less mature source rocks in the study area.

The Hydrocarbon Potential of Miocene Source Rocks for Oil Generation in the South Gulf of Suez, Egypt

Sixteen cutting and four core samples, in addition two crude oil samples are representative for the Miocene source rocks and reservoirs in some wells in the southern part of Gulf of Suez. These samples were subjected to advanced geochemical tools (pyrolysis, elemental analyses, gas chromatography, and gas chromatography-mass spectrometry). In addition, burial history model of the deepest well is recognized. The results showed that the Middle-Upper Miocene source rocks are immature, originated mainly from mixed organic sources, have poor to fair potentiality to produce oil, and did not reach the early stage of hydrocarbon generation until the present time. Lower Miocene source rocks are mature, derived from marine organic sources, have good potential to generate oil and gas, and entered the early stage of hydrocarbon generation and oil window till present time. The crude oil samples are mature, originated mainly from marine sources, and show good correlation with the Lower Miocene source rocks. Therefore, the Lower Miocene source rocks may be considered an effective source for oil generation in the southern part of Gulf of Suez.

Methanogenic calcite, 13C-depleted bivalve shells, and gas hydrate from a mud volcano offshore southern California

Methane and hydrogen sulfide vent from a cold seep above a shallowly buried methane hydrate in a mud volcano located 24 km offshore southern California in 800 m of water. Bivalves, authigenic calcite, and methane hydrate were recovered in a 2.1 m piston core. Aragonite shells of two bivalve species are unusually depleted in 13C (to −19‰ δ13C), the most 13C-depleted shells of marine macrofauna yet discovered. Carbon isotopes for both living and dead specimens indicate that they used, in part, carbon derived from anaerobically oxidized methane to construct their shells. The δ13C values are highly variable, but most are within the range −12‰ to −19‰. This variability may be diagnostic for identifying cold-seep–hydrate systems in the geologic record. Authigenic calcite is abundant in the cores down to ∼1.5 m subbottom, the top of the methane hydrate. The calcite is depleted in 13C (δ13C = −46‰ to −58‰), indicating that carbon produced by anaerobically oxidized methane is the main source of the calcite. Methane sources include a geologic hydrocarbon reservoir from Miocene source rocks, and biogenic and thermogenic degradation of organic matter in basin sediments. Oxygen isotopes indicate that most calcite formed out of isotopic equilibrium with ambient bottom water, under the influence of gas hydrate dissociation and strong methane flux. High metal content in the mud volcano sediment indicates leaching of basement rocks by fluid circulating along an underlying fault, which also allows for a high flux of fossil methane.

Geochemistry and episodic accumulation of natural gases from the Ledong gas field in the Yinggehai Basin, offshore South China Sea

The Ledong gas field, consisting of three gas pools in a shale diapir structure zone, is the largest gas discovery in the Yinggehai Basin. The gases produced from the Pliocene and Quaternary marine sandstone reservoirs show a considerable variation in chemical composition, with 5.4–88% CH 4, 0–93% CO 2, and 1–23.7% N 2. The CO 2-enriched gases often display heavier methane δ 13C values than those with low CO 2 contents. The δ 15N values of the gases range from −8 to −2‰, and the N 2 content correlates negatively with the CO 2 content. The high geothermal gradient associated with a relatively great burial depth in this area has led to the generation of hydrocarbon and nitrogen gases from the Lower–Middle Miocene source rocks and the formation of abundant CO 2 from the Tertiary calcareous-shales and pre-Tertiary carbonates. The compositional heterogeneities and stable carbon isotope data of the produced gases indicate that the formation of the LD221 gas field is attributed to three phases of gas migration: initially biogenic gas, followed by thermogenic hydrocarbon gas, and then CO 2-rich gas. The filling processes occurred within a short period approximately from 1.2 to 0.1 Ma based on the results of the kinetics modeling. Geophysical and geochemical data show that the diapiric faults that cut through Miocene sediments act as the main pathways for upward gas migration from the deep overpressured system into the shallow normal pressure reservoirs, and that the deep overpressure is the main driving force for vertical and lateral migration of the gases. This gas migration pattern implies that the transitional pressure zone around the shale diapir structures was on the pathway of upward migrating gases, and is also a favorable place for gas accumulation. The proposed multiple sources and multiple phases of gas migration and accumulation model for the Ledong gas field potentially provide useful information for the future exploration efforts in this area.

Alkyl-tert. butyl ethers as components for enhancing octane level of gasoline

29 Oils and 12 cores (11 of Miocene age and 1 of Pretertiary age), representing some 3000 cuttings samples (of Mesozoic and Tertiary age), were investigated and correlated in order to find out whether the oils from the Croatian Subbasin of the Pannonian Basin (Sava, Drava and Slavonija-Srijem depressions) belong to the same oil generative basin.The oils were trapped in different types of reservoirs of Miocene sandstones and breccias, as well as in fractured Basement.For correlation, multiparameter approach is applied including biomarkers and isotope data.According to biomarker parameters, the oils are thought to originate from similar source(s) and could be classified in one broad group. Some biodegradition has been observed for the shallowly reservoired oils. Oils are found to differentiate regarding maturity rank. Bacterially reworked marine algal material mixed with more or less of land input and deposited in more or less suboxic environment is the probable source. Isotope data subdivide the oils into a rather spread group of the Sava trough oils and into the Drava trough oils. All the oils seem to belong most probably to Miocene source rock(s).

A New Geochemical-Sequence Stratigraphic Model for the Mahakam Delta and Makassar Slope, Kalimantan, Indonesia1

The generally accepted geochemical-stratigraphic model for the Mahakam-Makassar area downgrades the potential for commercial deep-water hydrocarbon accumulations on the outer shelf, yet fails to explain recent discoveries in this area. According to this model, effective middle Miocene coaly source rocks are restricted to updip shelfal areas, whereas age-equivalent rocks on the outer shelf are thermally postmature for generating oil and buried too deeply to preserve good reservoir quality. Our revised geochemical-stratigraphic model upgrades the potential of the outer shelf and directly influenced recent oil and gas condensate discoveries in this area. The middle Miocene source rock interval is not buried as deeply as was previously believed and is now within the oil window based on our regional seismic reinterpretation and source-specific kerogen kinetics. Genetically distinct petroleum accumulations are charged from local kitchens between anticlinal structural trends aligned parallel to the coastline. High-resolution geochemistry confirms that crude oil samples from these different trends (e.g., Handil-Nilam-Badak, Bekapai-Tunu-Attaka, Perintis-Sisi-Ragat) are genetically distinct. Two major (1, 2) and two minor (3, 4) petroleum systems dominated by terrigenous type III organic matter are recognized. The highstand, lowstand 1, lowstand 2, and transgressive systems tract oils account for about 46, 31, 15, and 8%, respectively, of the 61 oil samples and about 45, 32, 11, and 12%, respectively, of the estimated ultimate recoverable reserves from the fields represented by these samples. These fields account for about 13 of the 16 BBOE (billion bbl of oil equivalent) estimated ultimate recoverable reserves in the entire Kutei basin. (1) Waxy highstand oils (e.g., Handil, Nilam) occur mainly onshore in middle Miocene-Pliocene reservoirs. These oils originated from middle-upper Miocene coal and shale source rocks deposited in coastal-plain highstand kitchens now near the peak of the oil window. (2) Less waxy lowstand 1 oils (e.g., Perintis, Sisi, Ragat) occur offshore in middle-upper Miocene reservoirs. These oils originated from middle-upper Miocene coaly source rocks deposited in deep-water lowstand kitchens now mostly in the early oil window. (3) Lowstand 2 oils (e.g., Semberah 037) are similar to the lowstand 1 oils but occur mainly onshore in lower-middle Miocene reservoirs. These oils generally are more mature than lowstand 1 oils and originated from lower-middle Miocene coaly source rocks. (4) Nonwaxy transgressive oils (e.g., Badak) occur mainly onshore in middle-upper Miocene reservoirs. These oils were generated at low thermal maturity from middle Miocene suboxic marine shales deposited near maximum flooding surfaces. Our three-dimensional geochemical-stratigraphic models for highstand and lowstand source rocks indicate that less fractional conversion of the kerogen occurred than had been predicted by the generally accepted stratigraphic model and classic type III kerogen kinetics; furthermore, two-dimensional fluid flow modeling supports independent geochemical evidence for commingling of oils in the Tunu field from highstand and lowstand kitchens to west and east, respectively. Finally, our model successfully predicted that oil and gas, rather than gas only, End page 12---------------- would be discovered at the recently drilled deep-water Merah Besar and West Seno fields. Geochemical analyses of oils from the Merah Besar field confirm that they belong in the lowstand 1 oil group.

Geochemical characteristics of terrigenous- and marine-sourced oils in Hokkaido, Japan

Crude oils in Hokkaido, Japan, are divided into two genetic groups based on bulk properties, carbon-isotope compositions and biomarker distributions. One group is characterized by high carbon-isotope canonical variables ( Sofer, 1984), high wax and low sulfur content, high Pr/Ph ratios, low C 27/(C 27+C 29) sterane ratios, relatively low Ts/(Ts+Tm) ratios, and the absence of tricyclic terpanes and C 35 homohopanes. These characteristics suggest that the oils were generated mainly from terrigenous organic matter in source rocks deposited under highly oxic conditions. The other group is characterized by low canonical variables, low wax and high sulfur content, low Pr/Ph ratios, high C 27/(C 27+C 29) sterane ratios, relatively high Ts/(Ts+Tm) ratios, and the presence of tricyclic terpanes and C 35 homohopanes, properties that suggest that they were generated from marine shales. Based on the biomarker distributions, the terrigenous oils correlate to Paleogene coals and coaly shales, whereas the marine oils correlate to Miocene marine shales. The atomic H/C ratios of the coals indicate that they have oil-generating potential. The geographic distribution of the terrigenous and marine source rocks, and their thermal maturity control the distribution of the oils in Hokkaido. The geographic distribution of the Paleogene coal-bearing formations corresponds to the distribution of the terrigenous oils in central Hokkaido. The marine oils are restricted either to areas of high heat flow related to volcanic activity, or to the area with thick Neogene and Quaternary sediments, where the Miocene source rocks are buried deep enough for oil generation.

A Common Source Rock for Egyptian and Saudi Hydrocarbons in the Red Sea

The northern Red Sea area hosts a classic triple junction of the Red Sea, Gulf of Aqaba, and Gulf of Suez rifted basins. The sedimentary succession here can be divided into prerift (pre-Miocene) and synrift (Miocene and post-Miocene) megasequences. The prerift section has been penetrated in only a few wells drilled on the western (Egyptian) side of the Red Sea, whereas the synrift section is known on both the Egyptian and the Saudi sides of the Red Sea. Although the synrift units on both sides of the water are similar in facies, thicknesses, and depositional environments, they have different stratigraphic nomenclatures. The northern Red Sea consists of elongated troughs separated by elongated structural highs, both of which trend northwest-southeast (Gulf of Suez trend). These highs are dissected by cross elements trending northeast-southwest (Gulf of Aqaba trend) and east-northeast-west-southwest, and are looked upon as strike-slip faults dislocating these highs. Identified rich source rocks are present in the upper Senonian carbonates, the Sudr and Duwi formations on the western side of the sea, the early Miocene Rudeis Formation (Burqan Group), and the middle Miocene Kareem and Belayim formations (Maqna Group). The pre-Miocene and the early Miocene source rocks host oil-prone kerogen, whereas the middle and late Miocene source rocks contain oil- and gas-prone kerogen. All of these source rocks are sufficiently mature ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received January 18, 1996; revised manuscript received October 11, 1996; final acceptance March 21, 1997. 2Faculty of Science, UAE University, P.O. Box 17551, Al-Ain, United Arab Emirates. We are especially grateful to the Egyptian General Petroleum Corporation for supplying the materials and the necessary data on which the present work is based and the permission to publish it; we also thank C. G. St. C. Kendall and A. E. M. Nairn, who read the early draft of this paper and offered valuable comments. Thanks to AAPG reviewers D. Waples, R. J. Murris, W. Maze, and an anonymous reviewer for their constructive comments, which we have used to improve our paper. We acknowledge G. Cole, BHP Petroleum, for granting permission to use some of his previous work.

Organic facies and petroleum potential of the Oligocene- Lower Miocene source rocks from Crimea to Azerbaijan&amp;nbsp; :ABSTRACT

Organic facies and petroleum potential of the Oligocene- Lower Miocene source rocks from Crimea to Azerbaijan&amp;nbsp; :ABSTRACT

Chemistry and Origin of Miocene and Eocene Oils and Tars in the Onshore and Offshore Santa Cruz Basins, California: ABSTRACT

The Santa Cruz (La Honda) Basin is a small [open quote]slice[close quote] of the San Joaquin Basin that has been displaced c. 300 km to the northwest by the San Andreas Fault. The poorly-explored offshore area that now lies within the Monterey Bay NMS includes portions of the Outer Santa Cruz and Bodega basins. A modest amount (c. 1.3 MM bbl) of variable-quality oil has been produced from Eocene and Pliocene pay zones in the La Honda Field. Much smaller amounts of light oil ([ge]40[degrees] API) have been produced from three other fields (Oil Creek; Moody Gulch; Half Moon Bay). Large tar deposits also outcrop near the city of Santa Cruz. Proven source rocks in this basin include the Eocene Twobar Shale and three Miocene units: the Lambert Shale, Monterey Formation, and the Santa Cruz Mudstone. A high-gravity oil sample from the Oil Creek Field contains isotopically-light carbon ([delta][sup 13]C = - 28.2 per mil) and has a relatively high pristane/phytane ratio. This oil was generated at high temperature (c. 140[degrees]C) by pre-Miocene source rocks (probably the Twobar Shale). The presence of isotopically-heavy carbon in all other oil and tar samples demonstrates they were generated by Miocene source rocks. Butmore » the C[sub 7] oil-generation temperatures, sulfur content, vanadium/nickel ratios, and biomarker chemistry of these Miocene oils are significantly different than in Monterey oils from the prolific Santa Maria Basin (SMB). The sulfur content (8.0 wt%) and V-Ni chemistry of tarry petroleum recovered in the P-036-1 well (Outer Santa Cruz Basin) resembles the chemistry of very heavy (<15[degrees]API) oils generated by phosphatic Monterey shales in the SMB.« less