Evaluation of Source Rock Quality in Chang-7 Member of Major Oil Fields in Ordos Basin

Petroleum is an important natural resource for human. The demand for petroleum in the next several decades will continue to be high, which requires the exploitation of more petroleum sources. Chang-7 member of the Ordos basin is proven to be the richest among all members, and this research took a focus on making a comparison between the source rock quality of Chang-7 member in four major oil fields in the basin, to provide a simple view of priority oil fields for exploitation in the future. The research analyzed the source rock quality of four oil fields from the TOC, A%, rock type, R0, sedimentary environment, and kerogen type, and found a superiority of source rock quality of Maling and Zhidan oil field in multiple dimensions, mainly triggered by their sedimentary environment. The research concluded that the oil fields that was once in the central-southern region of the basin contains a slightly better source rock quality among the chosen fields, which is related to a more stable sedimentary environment in the early Triassic.

Changing depositional environments in the semi-restricted Late Jurassic Lemeš Basin (Outer Dinarides; Croatia)

The up to 450 m-thick Upper Jurassic Lemeš Formation includes organic-rich deep-water (max. ~ 300 m) sedimentary rocks deposited in the Lemeš Basin within the Adriatic Carbonate Platform (AdCP). The Lemeš Formation was investigated regarding (1) bio- and chemostratigraphy, (2) depositional environment, and (3) source rock potential. A multi-proxy approach—microfacies, Rock–Eval pyrolysis, maceral analysis, biomarkers, and stable isotope ratios—was used. Based on the results, the Lemeš Formation is subdivided from base to top into Lemeš Units 1–3. Deposition of deep-water sediments was related to a late Oxfordian deepening event causing open-marine conditions and accumulation of radiolarian-rich wackestones (Unit 1). Unit 2, which is about 50 m thick and Lower early Kimmeridgian (E. bimammatum to S. platynota, ammonite zones) in age, was deposited in a restricted, strongly oxygen-depleted basin. It consists of radiolarian pack- and grainstones with high amounts of kerogen type II-S organic matter (avg. TOC 3.57 wt.%). Although the biomass is predominantly marine algal and bacterial in origin, minor terrestrial organic matter that was transported from nearby land areas is also present. The overlying Unit 3 records a shallowing of the basin and a return to oxygenated conditions. The evolution of the Lemeš Basin is explained by buckling of the AdCP due to ophiolite obduction and compressional tectonics in the Inner Dinarides. Lemeš Unit 2 contains prolific oil-prone source rocks. Though thermally immature at the study location, these rocks could generate about 1.3 t of hydrocarbon per m2 surface area when mature.

Study of the component composition of organic matter of the East Pre-Caucasian basin rocks based on the results of lithological, petrophysical and geochemical studies

This study introduces results of lithological, petrophysical and geochemical investigation of Lower Cretaceous (K1) and Middle Jurassic (J2a-b) rocks of East Pre-Caucasian basin. According to pyrolytic and bituminological studies method of separate determination of kerogen and bitumen concentration been developed. In accordance with this method differentiation of organic matter components in different lithotypes of rocks been described. Also relationship between bitumen and kerogen concentrations been revealed. The majority of samples have poor to fair organic richness and poor source potential. Kerogen type is commonly presented by type III and stages of maturity characterized by stages PC3 to MC3. Bitumen compounds have low concentrations of asphaltenes and aromatic hydrocarbons and mainly contains light and heavy resins. Based on petrophysical and geochemical studies a close relationship between the concentration of organic carbon and the weight concentration of potassium nuclides was obtained. This relationship indicates that kerogen in the sediments under consideration is associated with clay minerals, which is also confirmed by the mineral composition of the rocks.

Application of X-ray Diffraction (XRD) and Rock–Eval Analysis for the Evaluation of Middle Eastern Petroleum Source Rock

In this study, collected samples of nine different wells from the Middle East are used for various geochemical analyses to determine the hydrocarbon generation potential. The determination is carried out following the grain density, specific surface area, XRD, and Rock–Eval pyrolysis analyses. Four different types of kerogen are plotted based on the Rock–Eval analysis result. Kerogen type I usually has high hydrogen index (e.g., HI > 700) and low oxygen index, which is considered oil-bearing. Kerogen Type II has hydrogen index between type I and type II and oxygen index higher than type I (e.g., 350 < HI < 700) and is also considered to have oil-bearing potential. Kerogen type III has a lower hydrogen index (e.g., HI < 350) and is considered to have a primarily gas-generating potential with terrigenous organic matter origination. Kerogen type IV has a very low hydrogen index and higher oxygen index (compared with other types of kerogen), which is considered the inert organic matter. The kerogen quality of the analyzed samples can be considered as very good to fair; the TOC content ranges from 1.64 to 8.37 wt% with most of them containing between 2 and 4 wt%. The grain density of these examined samples is in the range of 2.3–2.63 g/cc. The TOC and density of the samples have an inversely proportional relationship whereas the TOC and the specific surface area (BET) has a positive correlation. The specific surface area (BET) of the examined samples is in the range of 1.97 m2/g–9.94 m2/g. The examined samples are dominated by clay, primarily kaolinite and muscovite. Additionally, few samples have a higher proportion of quartz and calcite. The examined samples from the Middle East contain kerogen type III and IV. Only two samples (JF2-760 and SQ1-1340) contain type I and type II kerogen. Considering Tmax and Hydrogen Index (HI), all of the samples are considered immature to early mature. Rock–Eval (S2) and TOC plotting indicate that most of the samples have very poor source rock potential only with an exception of one (JF2-760), which has a fair-to-good source rock potential.

Optical (visual) Kerogen assessment of Enugu Shale, Anambra Basin, Southeastern Nigeria: Implications for source rock potential and thermal maturation

Palynological analysis was carried out on Ten (10) samples from outcrops of the Campanian Enugu Formation, a component lithostratigraphic unit of the Anambra Basin, using the acid maceration techniques for recovering acidinsoluble organic-walled microfossils. Two main lithological units were encountered, which include: carbonaceous shale and siltstone. Result from kerogen laboratory examination reveals two (2) main groups of palynofacies association namely; palynofacies (A and B), based on the change in particulate organic matter constituents of organic residue extract. Palynofacies A is characterized by abundant opaques debris with common terrestrial phytoclasts, which occupy the southwestern and northwestern parts of the studied area, whereas palynofacies B dominates in the northeastern part, characterised by abundant phytoclasts followed by frequent opaques debris. Kerogen type III with gas-prone material is suggested for both palynofacies. The examined exine of spore/ pollen grain are pale yellow – yellow, with Thermal Alteration Index TAI of 1+ to 2- and Vitrinite Reflectane (R o) (0.3 % - 0.4 %) in palynofacies A, and yellow – yellow brown, with Thermal Alteration Index TAI of 2- to 2, and Vitrinite Reflectane (R o) of 0.3% - 0.5% in palynofacies B. These revealed source rock that is thermally immature to slightly mature but has potential to generate mainly gas. The kerogen data generated using transmitted light microscopy correlated well with geochemical data obtained using rock-eval pyrolysis method, and this shows the method a reliable tool for assessing petroleum potential in any given sedimentary basins.

New Finding on Oil Distribution in Jabung Block and its Implication to Pre-Talang Akar Formation (Pre-TAF) Play in the Block and South Sumatera Basin Respectively

The kerogen types at the origin of oil in the Jabung block are predominantly type-II and III based on Rock Eval pyrolysis, and are interpreted to originate from the fluvio-deltaic shale & coal of the Oligocene Talang Akar Formation (TAF). However, several outlying oils have been found in the wells NB-1 & NB-4 of the North Betara Field and indicate that kerogen type-I of lacustrine origin may also be in play. This scenario is further suggested by biomarker and carbon isotope ratios. In this paper, we infer that those oils are sourced from the Eocene Pre-Talang Akar Formation (Pre-TAF) section. This opens new exploration prospectivity for the Jabung area. Our analysis of selected petroleum system elements suggests that the lacustrine oils encountered in NB-1 & NB-4 originate from Eocene Pre-TAF source rock in deeper part and migrated into the younger Oligocene TAF sandstone as a sub-surface leak, or “a subsurface oil seep”. Oil migrated by fault vertically and then spread laterally to fill traps in TAF. A widespread unconformity at top pre-TAF may have provided an excellent seal at the origin a pre-TAF confined petroleum system, prevented the lacustrine oil from entering all the fields/structures in the Jabung block, This could explain the minimal distribution of the lacustrine oil at TAF level and above in the Jabung area. The Pre-TAF is associated with the early syn-rift phase in South Sumatra Basin. It also refers as Lahat or Lemat Formation in the basin and is a widely under-explored play, evidenced by the low reserve magnitude of fewer than 100 MMBOE. The distribution of Pre-TAF as source and reservoir rock is restricted to syn-rift depocenter area. From our latest interpretation, Pre-TAF in NEB Field, observed clearly from the 3D seismic data, is potentially well developed and of good quality, although no wells have penetrated the interval to date

Small Unconventional Hydrocarbon Gas Reservoirs as Challenging Energy Sources, Case Study from Northern Croatia

Small possible hydrocarbon gas reservoirs were analysed in the Bjelovar Subdepression in Northern Croatia. This area includes the Neogene–Quaternary, mostly clastics, sequences, reaching 3000+ metres in the deepest part. The shallow south-eastern part of the Drava Depression contains a subdepression characterised with several, mostly small, discovered hydrocarbon fields, where the majority are located on the northern subdepression margin. The reason is the large distance from the main depressional migration pathways and main, deep, mature source rock depocenters. However, two promising unconventional targets were discovered inside the subdepression and both were proven by drilling. The first are source rocks of Badenian, of kerogen type III in early catagenesis, where partially inefficient expulsion probably kept significant gas volumes trapped in the source rock during primary migration. Such structures are the Western Bjelovar (or Rovišće) and the Eastern Bjelovar (or Velika Ciglena) Synclines. The second promising unconventional reservoir consists of “tight” clastic lithofacies of mostly Lower Pontian located on the north-eastern margin of the subdepression. These are fine-grained sandstones with frequent alternations in siltites, silty and clayey sandstones. They are located on secondary migration pathways, but were never evaluated as regional reservoirs, although numerous drilling tests showed gas “pockets”.