Early Mature Oil Research Articles

Organic geochemistry and oil-source rock correlation of the Cretaceous succession in West Wadi El-Rayan (WWER) concession: Implications for a new Cretaceous petroleum system in the north Western Desert, Egypt

Mesozoic rift basins of the north Western Desert host the majority of proven oil reserves in Egypt. These basins are bounded by poorly-explored structural highs (Kattaniya high, Qattara ridge) with unknown petroleum system. The recently-discovered oil in West Wadi El-Rayan (WWER) concession in the southern part of the Kattaniya high highlighted a need for understanding the petroleum potential of these transit regions. The present study integrates geochemical and basin modelling results to define potential source rocks and decipher the mechanism of oil generation, expulsion and migration. In WWER concession, oil is produced from the Upper Cretaceous (Upper Bahariya) sandstones. Rock-Eval pyrolysis results demonstrate that the Lower Cretaceous Alam El Bueib (AEB) and Upper Cretaceous Lower Bahariya shales below the reservoir contain mature source rocks (S2 up to 28.76, Tmax > 430 °C). WWER oil displays a uniform composition with high pristane/phytane (Pr/Ph > 3), saturates/aromatics (>5.5) and canonical variable values (CV > 6) pointing to a generation from a terrestrial source rock. This is consistent with high contents of C30 hopane, C29 steranes and diasteranes as well as the very low values of dibenzothiophane (DBT)/Phenantherane (<0.1) confirming oil generation from a clay-rich source rock deposited in a fluvio-deltaic environment.Oil-source correlation highlights a robust similarity in compositional biomarkers between the WWER oil and AEB rock extracts. Additionally, the maturity-relevant biomarkers such as Ts/Tm trisnorhopanes and H32 S/(R + S) homohopanes favor an oil expulsion phase during the early stage of oil window in accordance with the basin modelling results and the maturity level of AEB organic-rich facies. These findings shed the light on a new petroleum system in the north Western Desert where the AEB fluvio-deltaic shales are capable of generating early mature oil which migrates through the Cretaceous deep-seated extensional faults into the Bahariya sandstone reservoir.

Characteristics of the Upper Cretaceous Yogou transitional formation and source rock potential, Niger rift basin

A High-resolution Field-emission scanning electron microscopy (FE-SEM) technique was used to investigate the complex Upper Cretaceous Yogou transitional Formation and source rock potential. The source rock consists of complex interfingering laminae of claystone, sandstone and shale of marine-transitional environments. Thermal maturity from Rock-Eval pyrolysis placed it between immature to early mature oil windows with Tmax ranging between 419 0C and 440 0C. Organic matters in the studied location are mainly bitumen and kerogen in a ratio of 3:1. Both the organic matters have micro to nano-scale organic pores, indicating a relatively high thermal maturity phase of the organic matter constituents. Several forms of pyrites exist in the Formation; euhedral, detrital, framboids and sunflower pyrite. The framboidal pyrites are large to medium sizes with diameters ranging from 63.1 to 3.27 μm. With increasing depth, the frambiods diameter decreases but increase in abundance. Based on the framboidal pyrite distributions, the lower Yogou source rock has relatively high organic content than the upper Yogou source rock; the high abundance of detrital pyrites at 2590 m depth is evidence of paleo-erosional reworked sediments that may constitute a surface of unconformity or marine to terrestrial transition zone. The pyrites with high abundance at depth 2605 m are all recrystallized, supporting the post formation erosion/exposure to air and/or water. The petrographic investigation also revealed the presence of well-preserved juvenile pollen of several microns in dimensions in the upper Cretaceous source rock formation. Based on these well preserved fossils and the relative abundance of pyrite at the depth of 2585 m, a euxinic to anoxic environment prevailed in the low section of the Yogou Formation, whereas the upper section is dominated by oxic to anoxic environment, where pyrite and organic matters are relatively low. Micro-cracks running parallel to bitumen/host rock boundary are paths for primary oil expulsion and migration. Where these micro cracks are not present may be due to differences in facies and deformation styles between the brittle clasts and the ductile clays present in the Formation. The newly documented juvenile pollens are important discovery that will help in reconstructing the paleo-history of the Niger Rift Basin.

Geochemistry of the Cretaceous Chinkeh oil from Maxhamish field and Garbutt black shale in the Liard Basin, Canada: Implications for a liquid-rich shale hydrocarbon resource

The Cretaceous Garbutt Formation shale and crude oils from the Cretaceous Chinkeh Formation in Liard Basin were subjected to geochemical analysis including biomarker fingerprinting. The Chinkeh oils are sweet light oils with API gravity and geochemical markers typical for the late stage oil window maturity. The oils show good correlation to the Garbutt shale extracts for their sterane compositions, while there are some minor discrepancies amongst their terpane distributions. These differences include enhanced contribution of tricyclic terpanes, high C23 tricyclic terpanes versus C30 hopane and low C24 tetracyclic terpane versus C26 tricyclic terpanes for the Chinkeh oil compared with the Garbutt shale extracts. Although not analyzed during this study, the Triassic Toad/Grayling interval, as stratigraphic equivalents of the Montney and Doig formations in Western Canada Sedimentary Basin may account for the terpane compositional features. Therefore, it is likely that the Chinkeh oils are mainly sourced from the Cretaceous Garbutt shale with minor additional contributions from a Triassic source. The Garbutt Shale is immature in the Horn River Basin, while in the Liard Basin in a north to south transect the unit's thermal maturity ranges from early mature oil window to wet gas/condensate window, and thus may be prospective for unconventional liquid hydrocarbon resource recovery.

Formation and evolution of nanopores in organic-rich shales: Insights from the hydrous pyrolysis experiments in a closed system

In order to make a better understanding of the formation and evolution process of nanopores in organic-rich shales with increasing thermal maturity, an early mature oil shale from the Nenjiang Formation in Changling Depression of Songliao Basin was pyrolyzed with the presence of brine water in a closed system. The measurements of TOC, XRD, N2 adsorption were conducted on the initial and pyrolyzed samples. The results show that the development of nanoporosity within pyrolyzed shales can be divided into three phases with thermal maturity increasing: the intensive increase (Ro=0.61-2.09%), slight decrease (Ro=2.09-2.47%) and slight increase (Ro=2.47-4.01%). The significant occurrence of nanopores was associated closely with intensive hydrocarbon generation and expulsion at the mature to high mature stages, liquid hydrocarbons filling into the nanopores restricts their developments. The formation of pyrobitumen by oil secondary cracking at the early over mature stage decrease the occurrence of micropores and macropores, and hence reducing the pore volumes. The secondary phase of nanopores formation is at the late over mature stage, which is attributed to the mineral transformation and limited capability of hydrocarbon generation and expulsion. This study should be helpful in evaluating shale oil and gas resources in nature.

Oil accumulation, regional groundwater flow, and inert gas risk in the southern Danube Basin, Hungary

In spite of its considerable size and the presence of mature oil source rocks, the Neogene Danube Basin is characterized by the absence of commercial oil accumulations. However, important [Formula: see text] fields have been discovered in the basin, which have been possibly explained recently by displacement of oil by later migration of [Formula: see text] into the reservoirs. Previous studies performed independently in the southern, Hungarian part of the basin (known as the Little Hungarian Plain) have attempted to model petroleum generation/migration history, to identify sources of the [Formula: see text], and to understand the tectonic evolution of the basin and its deep-water flow regime. We were attempting to combine the results of these studies to interpret the fluid-migration history and reveal the influencing processes. This work supports the hypothesis that [Formula: see text] could have played a key role in preventing the formation of oil accumulations. During the latest Miocene, early mature oil and saline water, the latter formed by dissolution of up to now unidentified halites, moved together toward the Mihályi High, a regional uplifted structure in the central part of the basin. Modest amounts of oil could have been trapped there while saline water mixed with the low-salinity water of the reservoirs, with the [Formula: see text] arriving later and displacing the oil.

Relationship of oil seep in Kudat Peninsula with surrounding rocks based on geochemical analysis

This study aims to investigate the relation of oil seepage at Sikuati area with the structural and petroleum system of Kudat Peninsula. The abundance of highly carbonaceous rocks with presence of lamination in the Sikuati Member outcrop at Kudat Peninsula may give an idea on the presence of oil seepage in this area. A detailed geochemical analysis of source rock sample and oil seepage from Sikuati area was carried out for their characterization and correlation. Hydrocarbon propectivity of Sikuati Member source rock is poor to good with Total Organic Carbon (TOC) value of 0.11% to 1.48%. and also categorized as immature to early mature oil window with Vitrinite Reflectance (VRo) value of 0.43% to 0.50 %Ro. Based on biomarker distribution, from Gas Chromatography (GC) and Gas Chromatography-Mass Spectrometry (GC-MS) analysis, source rock sample shows Pr/Ph, CPI and WI of 2.22 to 2.68, 2.17 to 2.19 and 2.46 to 2.74 respectively indicates the source rock is immature and coming from terrestrial environment. The source rock might be rich in carbonaceous material organic matter resulting from planktonic/bacterial activity which occurs at fluvial to fluvio-deltaic environment. Overall, the source rock from outcrop level of Kudat Peninsula is moderately prolific in term of prospectivity and maturity. However, as go far deeper beneath the surface, we can expect more activity of mature source rock that generate and expulse hydrocarbon from the subsurface then migrating through deep-seated fault beneath the Sikuati area.

Organic-geochemistry characterization of the Paleogene to Neogene source rocks in the Sayhut subbasin, Gulf of Aden Basin, with emphasis on organic-matter input and petroleum-generation potential

Paleogene Umm Er Radhuma and Ghaydah and Neogene Sarar source rocks from Sayhut subbasin in the Gulf of Aden Basin were studied to provide information such as organic-matter types, paleoenvironmental conditions, and petroleum-generation potential. This study is based on whole-rock organic-geochemical analyses and organic petrology. The total organic carbon (TOC) contents of the Paleogene to Neogene source rocks range from 0.43% to 6.11%, with an average TOC value of 1.00%, indicating fair to very good source-rock potential. The Paleogene Ghaydah and Umm Er Radhuma source rocks are relatively higher in genetic petroleum potential than Neogene Sarar source rocks. Mainly oil and gas are anticipated from the Ghaydah and Umm Er Radhuma source rocks with hydrogen index (HI) values ranging from 95 to 715 mg hydrocarbon (HC)/g TOC. This is supported by the presence of significant amounts of liptinite macerals in the Ghaydah and Umm Er Radhuma source rocks. The Sarar source rocks are dominated by vitrinitic type III kerogen (HI < 200 mg HC/g TOC) and are thus considered to be gas source rocks. The Paleogene to Neogene source rocks have vitrinite reflectance (R o) values in the range between 0.30% and 0.77% R o, and pyrolysis maximum temperature values range from 412°C to 444°C (774°F to 831°F), consistent with the immature to early mature oil window. Therefore, the present-day kerogen type in the Paleogene to Neogene source rocks is original and should not have been altered by thermal maturity. The biomarker of organic matter suggests that the Paleogene to Neogene source rocks were deposited in a marine environment under suboxic to anoxic conditions. The biomarkers also indicate that the Paleogene to Neogene source rocks contain a mixture of aquatic organic matter (planktonic and bacterial) and terrigenous organic matter, with increasing terrigenous influence to Sarar source-rock samples. Highly hypersaline reducing conditions are also evidenced in Ghaydah and Umm Er Radhuma source rocks, as indicated by the presence of the gammacerane biomarker, low pristane to phytane ratios, and homohopane distribution patterns.

Organic geochemical and petrographic characteristics of the Miocene Salif organic-rich shales in the Tihama Basin, Red Sea of Yemen: Implications for paleoenvironmental conditions and oil-generation potential

This study is the first investigation which provides information regarding the organic geochemical and petrographic characteristics of Miocene Salif organic-rich shales from Tihama Basin in the Red Sea, Yemen. We evaluate organic matter content, type, maturity, and oil-generation potential as well as depositional environmental conditions. The total organic carbon (TOC) contents of the Miocene Salif shales vary between 0.59% and 5.40%, indicating fair to very good source rock potential. The Salif shales have hydrogen index values in the range of 64–576mgHC/g TOC. The organic matter in the Salif shales are dominated by Type II kerogen and mixed II–III kerogens with a minor contribution of Type III kerogen, as supported by kerogen microscopy. This is also confirmed by their biomarker and carbon isotope results, which indicate that the Salif shales were deposited in highly reducing marine conditions and received high contributions of aquatic organic matter (e.g., algal and microbial) and terrigenous organic matter. Consequently, the Salif Formation is likely to be an oil-source rock. Maturity indicators such as vitrinite reflectance and pyrolysis data (i.e., Tmax and PI) indicate that most of the Salif shale samples are generally thermally mature, at the early-mature to peak oil window stage. The new data presented in this paper suggest that early-mature oil has been generated from Miocene Salif organic-rich shales, so exploration strategies should focus on the known location of Miocene Salif organic-rich shales for predicting the location of the source kitchen.

Thermal History and Potential of Hydrocarbon Generated from Jurassic to Early Cretaceous Source Rocks in the Malita Graben, Northern Bonaparte Basin, Australia

The Malita Graben is located in the northern Bonaparte Basin, between the Sahul Platform to the northwest and the Petrel Sub-basin and Darwin Shelf to the south. The wells Beluga 1, Heron 1, Evans Shoal 1, Evans Shoal 2 and Seismic Line N11805 are selected to determine the thermal history and potential of hydrocarbon generated from the Plover, Elang, Frigate Shale (Cleia and Flamingo), and Echuca Shoals formations source rocks. The modeling was performed by using Basin Mod 1-D and 2-D techniques. The model results show that the geothermal gradients range from 3.05 to 4.05°C/100 m with an average of 3.75°C/100 m and present day heat flow values from 46.23 to 61.99 mW/m2 with an average of 56.29 mW/m2. The highest geothermal gradient and present-day heat flow values occurred on a terrace north of the Malita Graben. These most likely indicate that hot fluids are currently variably migrating into this structure. The lower geothermal gradient and heat flow values have been modeled in the southeast sites in the well Beluga 1. The northern Bonaparte Basin experienced several deformation phases including lithospheric thinning; hence, heat flow is expected to vary over the geological history of the basin. The higher paleo-heat flow values changing from 83.54 to 112.01 mW/m2 with an average of 101.71 mW/m2 during Jurassic rift event (syn-rift) were sufficient for source rocks maturation and hydrocarbon generation during Cretaceous post-breakup sequence (post-rift) in the study area. The Tuatara (Upper Frigate Shale) Formation source rock with type II & III kerogen dominantly showing mixed oil- and gas-prone, and Plover Formation with type III and gas prone have never reached the peak mature oil window in the well Beluga 1. This area indicates that the maturity of source rocks is low and considered to be from poor-to-good organic richness with poor-to-fair potential for hydrocarbons generation. The post mature Cleia (Lower Frigate Shale) and Echuca Shoals formations source rocks in the well Evans Shoal 1 and an early mature oil window Echuca Shoals formation source rock in the well Evans Shoal 2, characterized by type III kerogen dominantly showing gasprone are a fair-to-very good source richness with poor potential for hydrocarbons generation. The low to high maturity of Echuca Shoals and Petrel (Frigate Shale) formations source rocks in the well Heron 1, Plover Formation source rock in the Evans Shoal 1 well, and Cleia (Lower Frigate Shale) and Plover formations in the well Evans Shoal 2, showing gas-prone with type III and II & III kerogens predominantly, have reached the late mature oil and wet gas generation stages at present day. These last five formations source rocks are seen from poor-to-very good organic richness with poor-to-very good potential for hydrocarbons generation in the Malita Graben.

Changes in optical properties of liptinite macerals from early mature to post mature stage in Posidonia Shale (Lower Toarcian, NW Germany)

Detailed organo-petrological analysis was carried out on core samples of Posidonia Shale (Lower Toarcian) from two wells, which are located in northwestern Germany, Lower Saxony Basin. Organic matter in one well is early mature (VRr=0.5%), whereas organic matter in the other is post mature (VRr=3.5%).Results of organo-petrological analyses demonstrate that telalginite (Tasmanales alginite) in early mature oil shales appears brown to dark brown in reflected white light, whereas in fluorescence mode it shows a yellow color of high intensity. In contrast, in post mature oil shales, relics of former telalginite named “postmature telalginite” for the purposes of the maceral analysis occur in three forms of replacement of former telalginite bodies whose shape and size are preserved. One form consists of a “chain” of carbonate crystals or of a completely recrystallized calcareous mass. Both are associated with homogeneous and heterogeneous migrabitumen. The second form is completely composed of epigenetic pyrite. The third form of postmature telalginite is rare and consists of impsonite.In mature Posidonia Shale lamalginite is relative frequent and has been encountered in three forms: discrete (<10μm), filamentous (>10μm) and layered. In post mature Posidonia shale all these forms are no longer recognizable. Part of the micrinite dispersed in the mineral groundmass may have been derived from lamalginite.In oil shales of early mature stage, bituminite I is characterized by a very low reflectance and a brownish fluorescence color. It often includes yellow fluorescent liptodetrinite and has indistinct lense shape. On the contrary, in post mature oil shales on the basis of morphology, it appears as light gray lenses which consist of massive micrinite.Bituminite II in early mature oil shales occurs as thick elongated homogeneous lenses and streaks associated with tiny carbonate crystals and with yellow-brownish fluorescence often with greenish fluorescent oil expulsions. In post mature oil shales, postmature bituminite II consists of a network of micrinite between tiny carbonate crystals. Apart from these common bituminites, minor contents of other bituminites have been recorded.Sporinite in early mature oil shales has a very low reflectance and an orange-brown fluorescence of moderate intensity. In post mature oil shales, sporinite shows reddish-orange internal reflections and is filled with pyrite crystals or with weak fluorescing minerals which emphasize the sporinite form.This study demonstrates that the use of the terms postmature telalginite, postmature bituminite and postmature sporinite in the macerals analysis of post mature oil shales is highly profitable particularly in understanding the transformation processes which are the result of the formation of secondary products (secondary macerals and epigenetic minerals) in the primary liptinite macerals.

Source Rock Evaluation of The Eocene Shales in the Gökçesu Area (Bolu/Turkey)

Hydrocarbon potential of oil shale samples from the Gökçesu basin in Bolu, Turkey, was evaluated on the basis of organic geochemical, organic petrographic, gas chromatography, and thin-layer chromatography techniques. Organic materials were found to be oil-producing type (Type I and II kerogen). Thermal maturities, that indicate diagenetic and early mature oil formation stage, were determined with pyrolysis (Tmax), production index (PI), and spore color index (SCI) analyses. The amount of organic material ranging between 0.21 and 15.89% reveals that the unit has variable source rock potentials from weak to perfect. The productivity of the basin was probably high and organic matter preservation was enhanced by a stratified water column. As the basin began to fill with sediment and become shallower, TOC and HI values declined, as the basin water was better oxygenated and preservation conditions declined. On the basis of geologic data, organic geochemical analyses and organic petrographic studies, organic facies of Eocene shales is of AB and B types.

Organic geochemical characteristics of the Paleocene–Eocene oil shales in the Nallıhan Region, Ankara, Turkey

Units of Paleozoic, Mesozoic and Cenozoic age are exposed in the study area which extends along the Sakarya River by the Sarýcakaya town of Eskiþehir at west and Nallýhan district of Ankara at East. Paleozoic is represented with metamorphites consisting of glaucophane schist, muscovite schist and marble alternations and granites cutting them. The Mesozoic composing of Jurassic–Cretaceous Soğukçam limestones at the northern part of the area is in tectonic contact with other units. The Tertiary is characterized by the Paleocene–Eocene Kızılçay Group which consists of the Beyköy, Çamalan and Laçin Formations. The Çamalan Formation is composed of sandstone, limestone, oil shale and locally coal bands. In the area, as a result of intense tectonic activity by the late Eocene, sedimentary sequence that compacted within the Paleozoic metamorphic rocks were folded and fractured. The Paleocene–Eocene shales have adequate organic material content to form potential source rocks. In order to determine hydrocarbon potential of the unit, various organic geochemical analysis techniques were performed. According to pyrolysis results (TOC, S 1 and S 2), the Paleocene–Eocene shales are perfect source rocks for oil. On the basis of Rock-Eval pyrolysis analyses, kerogens are Type I and Type II kerogens. Spore Color Index and T max evaluations indicate that maturity of the unit is between diagenesis and early mature oil zone and at the beginning of the oil-producing stage. Organic facies of the Paleocene–Eocene shales are A, AB and B.

An atypical early mature oil in Block 35/1, Norwegian North Sea – hypersaline, carbonate Jurassic environment?

Block 35/1 with the dry Sturlason structure, is located on the northernmost part of the Marflo Ridge in the Norwegian part of the Northern North Sea. It is separated by deep faults from the Sogn Graben to the east and the Marulk Basin to the west. The 35/1-1 well proved only minor shows of gas and oil in the well. The Sturlason structure comprises a series of upthrown fault blocks in a structurally complex area. The well-established Brent Formation carrier and reservoir sandstone has shaled out this far north and the stratigraphically deeper Lower Jurassic Statfjord Formation and Triassic Lunde Formation sandstones were, in the exploration model, suggested as both carrier beds and reservoirs. The prolific Upper Jurassic Draupne (Type II organic matter, OM) and Heather (Type II/III OM) Formation source rocks were, based on seismic data, interpreted to be absent or thin over the prospect, thus implying lateral migration for filling the structure with petroleum. Structural back-stripping suggests that part of Block 35/1 was sub-aerially exposed as an island during deposition of the Upper Jurassic source rocks. This may have impacted the quality and nature of the fringing organic material due to a more oxic environment and a greater influx of Type III organic matter. The geochemical analyses were hampered by contamination from the use of oil-based mud (C 13–23 range hydrocarbons) while drilling. Despite this, traces of true indigenous C 4–10 and C 25+ range hydrocarbon are demonstrated. These results suggest presence of an evaporative condensate and heavy oil fraction originating from a source rock related to a hypersaline carbonate depositional environment. A buoyancy-driven fluid flow study, without taking faults into account, shows the difficulty in charging the prospect and clearly suggests the presence of sealing faults. The latter are also substantiated by a separate fault-seal analysis. Traps in flanking areas could, however, receive petroleum. Gas is also interpreted to be present in shallower sediments over the eastern flank of the Sturlason structure.

Structure and Facies Development in the Niger Delta Resulting from Hydrocarbon Maturation: ABSTRACT

A new depositional model relates the formation of the Niger Delta toe thrusts and growth faults to source rock maturation. Specifically, it is proposed that an oil-prone source rock at early maturity generates enough fluid and pressure to initiate major fault movement by gravity sliding. Recently acquired, high quality, deepwater seismic data show a well defined decollement surface that links toe thrusts, growth faults and counter regional faults in the progradational wedge. It is believed the decollement occurs in an Aptian-aged source rock known to be present in West Africa and Brazil. Regional cross sections were constructed through the delta, using the published positions of shorelines through time and assuming a maximum post Aptian sediment wedge of 8 kilometers. Maturation modeling was performed and the results at various times from Late Cretaceous to Recent were plotted and compared to paleopositions of the shelf edge and toe of slope. The modeling illustrates how the maturation of an Aptian source rock may have significantly influenced structural development and facies distribution in the delta. The present day time slice shows a strong correlation between the location of the early mature oil window of the proposed source rock and the position of the leadingmore » toe thrust in the delta. A, similar correlation is found between the location of the post gas-mature window and the position of significant fluvial facies accumulation. The fluvial facies occurs as the result of shoreline advance caused by the loss of source-related lubrication of the decollement surface.« less