scholarly journals Geokimia Organik Serpih Hidrokarbon Berumur Eosen di Daerah Sumatera Bagian Tengah

2020 ◽  
Vol 21 (1) ◽  
pp. 45
Author(s):  
Moh. Heri Hermiyanto Zajuli ◽  
Riecca Oktavitania ◽  
Ollybinar Rizkika
Keyword(s):  
Source Rock ◽  
Oil Shale ◽  
Oil And Gas ◽  
Type I ◽  
Gas Oil ◽  
Kerogen Type ◽  
Potential Source Rock ◽  
Key Word ◽  
Different Characteristics ◽  
Central Sumatra

This study focused on the region of Central Sumatra that geologically into the Central and South Sumatra Basin. The subjects were from the Eocene shale in the areas such as the Kasiro, Sinamar, and Kelesa Formation. Shale of Central Sumatra Basin tend to have different characteristics with shale of South Sumatra Basin. Maceral content of vitrinite and liptinit on shale in South Sumatra Basin larger than Central Sumatra Basin shale. Oxic-anoxic conditions affecting to the abundance maceral-maceral in both basins. Shale of the  Kasiro Formation have a tend to indicate kerogen type I, and II, while shale of the Sinamar and Kelesa Formation included into kerogen type I, II and III. Shale from the three formation have the potential as an oil and gas with different characteristics. Shale of the Kasiro Formation shale has the potential source rock which can produce more oil than gas. Meanwhile shale of the Sinamar Formation  tend to be potentially as the source rock either oil or gas, oil shale and shale gas, but more potential as oil shale.  Key word : Liptinite, Vitrinite, Eocene, Central Sumatera Basin, South Sumatera Basin

Effect of solvent swelling on pyrolysis of kerogen (type-I) isolated from Göynük oil shale (Turkey)

2009 ◽  
Vol 84 (1) ◽  
pp. 31-38 ◽  
Author(s):  
Murat Sert ◽  
Levent Ballice ◽  
Mithat Yüksel ◽  
Mehmet Saglam ◽  
Rainer Reimert ◽  
...  
Keyword(s):  
Oil Shale ◽  
Type I ◽  
Effect Of Solvent ◽  
Kerogen Type ◽  
Solvent Swelling

scholarly journals Petroleum Potential of Gombe Formation, Kolmani River-1 Well Gongola Basin, NE Nigeria

2020 ◽  
Vol 45 (5) ◽  
Author(s):  
T. A. Adedosu ◽  
S. A. Alao ◽  
T.R. Ajayi ◽  
A. Akinlua
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Oil And Gas ◽  
Organic Matter Content ◽  
Matter Content ◽  
Appreciable Amount ◽  
Oxic Condition ◽  
Petroleum Potential ◽  
Potential Source ◽  
Potential Source Rock

Gombe Formation is one of the promising potential source-rock of petroleum in the Gongola basin based on its appreciable amount of organic matter. The present study is therefore aimed at evaluating the hydrocarbon potential of Gombe Formation. Ditch-cutting samples were collected from the depth of 731.5 m to 1554.5 m from Gombe Formation that penetrated the Kolmani River-1 well. The source-rock potential was evaluated based on kerogen analysis and soluble organic matter content using Fourier Transform- Infra red spectroscopic (FT-IR) and Gas chromatography-Mass spectrometric (GC-MS) techniques respectively. There is presence of peak at 900-1000 cm-1 which is due to CH2 rocking vibration in long chain aliphatic substances, which is characteristic of liptinite macerals indicating good potential source-rock for oil and gas. The n-alkane ranges from C11-C33 maximizing at nC16 which suggests that the organic matter are majorly derived from marine organic matter. The Pr/Ph (1.49-1.92) shows that the organic matter was deposited under sub-oxic condition. The distribution of hopanes, homohopanes (C27-C29) steranes, (C0-C4) alkylated naphthalenes and (C0-C3) alkylated phenanthrenes indicate the presence of angiosperm, gymnosperm, algae, marine and bacteria input to the organic matter contained in the samples. Also the plot of DBT/P vs. Pr/Ph classifies the samples into zone 3 (i.e. marine shale and other lacustrine). Various maturity parameters computed from saturate biomarker and polycyclic aromatic hydrocarbon distributions shows that the samples are low mature with the moderately mature zone at the bottom (>1408.2 m) of Gombe Formation. In conclusion, the kerogen was probably derived from type II/III organic matter capable of generating both oil and gas and the moderately mature zone lies at the bottom of the Formation. Key words: Lacustrine, Gombe formation, Maturity, Hydrocarbon, Kerogen

HYDROCARBON PROSPECTIVITY OF THE DEEPWATER GIPPSLAND BASIN, VICTORIA, AUSTRALIA

2001 ◽  
Vol 41 (1) ◽  
pp. 91 ◽  
Author(s):  
T. Bernecker ◽  
M.A. Woollands ◽  
D. Wong ◽  
D.H. Moore ◽  
M.A. Smith
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Data Sets ◽  
Hydrocarbon Generation ◽  
The North ◽  
Potential Source Rock ◽  
Exploration And Production ◽  
Modelling Studies ◽  
History Of ◽  
Gippsland Basin

After 35 years of successful exploration and development, the Gippsland Basin is perceived as a mature basin. Several world class fields have produced 3.6 billion (109) BBL (569 GL) oil and 5.2 TCF (148 Gm3) gas. Without additional discoveries, it is predicted that further significant decline in production will occur in the next decade.However, the Gippsland Basin is still relatively underexplored when compared to other prolific hydrocarbon provinces. Large areas are undrilled, particularly in the eastern deepwater part of the basin. Here, an interpretation of new regional aeromagnetic and deep-water seismic data sets, acquired through State and Federal government initiatives, together with stratigraphic, sedimentological and source rock maturation modelling studies have been used to delineate potential petroleum systems.In the currently gazetted deepwater blocks, eight structural trapping trends are present, each with a range of play types and considerable potential for both oil and gas. These include major channel incision plays, uplifted anticlinal and collapsed structures that contain sequences of marine sandstones and shales (deepwater analogues of the Marlin and Turrum fields), as well as large marine shale-draped basement horsts.The study has delineated an extensive near-shore marine, lower coastal plain and deltaic facies association in the Golden Beach Subgroup. These Late Cretaceous strata are comparable to similar facies of the Tertiary Latrobe Siliciclastics and extend potential source rock distribution beyond that of previous assessments. In the western portion of the blocks, overburden is thick enough to drive hydrocarbon generation and expulsion. The strata above large areas of the source kitchen generally dip to the north and west, promoting migration further into the gazetted areas.Much of the basin’s deepwater area, thus, shares the deeper stratigraphy and favourable subsidence history of the shallow water producing areas. Future exploration and production efforts will, however, be challenged by the 200–2500 m water-depths and local steep bathymetric gradients, which affect prospect depth conversion and the feasibility of development projects in the case of successful exploration.

scholarly journals Hydrocarbon source rock evaluation of the Lower Cretaceous system in the Baibei Depression, Erlian Basin

2017 ◽  
Vol 36 (3) ◽  
pp. 355-372 ◽  
Author(s):  
Hua Liu ◽  
Jinglun Ren ◽  
Jianfei Lyu ◽  
Xueying Lyu ◽  
Yuelin Feng
Keyword(s):  
Organic Carbon ◽  
Total Organic Carbon ◽  
Source Rock ◽  
Lower Cretaceous ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Main Stage ◽  
Type I ◽  
Potential Source Rock ◽  
Erlian Basin

The K1s, K1d, K1t, and K1a Formations are potential source rock intervals for hydrocarbon formation, all of which are part of the Lower Cretaceous system in the Baibei Depression in the Erlian Basin in China. However, no well has found oil flow because the hydrocarbon-generating potential of the source rocks has not been comprehensively evaluated. Based on organic geochemical and petrological analyses, all the source rocks possess highly variable total organic carbon and S1 + S2 contents. Total organic carbon and S1 + S2 contents indicate that the K1a2 Formation through the K1d1 Formation are source rocks that have fair to good generative potential and the K1d2 Formation through the K1s Formation are source rocks that have good to very good generative potential. The organic matter in the K1a2 Formation is dominated by Type I and II kerogen; thus, it is considered to be oil prone based on H/C versus O/C plots. Most of the analyzed samples were deposited in reducing environments and sourced from marine algae; thus, they are oil prone. However, only two source rock intervals were thermally mature with vitrinite reflectance values in the required range. Hydrocarbon-generating histories show that the K1t and K1a2 intervals began to generate hydrocarbons during the depositional period of the K1d2 and K1d3 Formations, respectively, and stopped generating hydrocarbons at the end of the depositional period of the late Cretaceous. Therefore, the main stage of hydrocarbon migration and accumulation was between the depositional period of the K1d2 and K1s Formations, and the critical moment was the depositional period of the late K1s Formation. The generation conversion efficiency reached approximately 55% in the K1a2 Formation and 18% in the K1t Formation at the end of the Cretaceous sedimentary stage. In general, the effective oil traps are those reservoirs that are near the active source rock in the generating sags in the Baibei Depression.

Biomarker Characteristic of Kelesa Oil Shale As Evidence of The Source of Organic Matter, Depositional Environment, and Maturity Interpretation

2020 ◽  
Author(s):  
B., M. Hartono
Keyword(s):  
Mass Spectrometry ◽  
Gas Chromatography ◽  
Organic Matter ◽  
Source Rock ◽  
Oil Shale ◽  
Depositional Environment ◽  
Petroleum System ◽  
Lacustrine Environment ◽  
Biomarker Analysis ◽  
Central Sumatra

Biomarker analyses can provide information about the source of organic matter, depositional environment, and maturity of source rock that is very useful for basin evaluation and understanding the petroleum system. In this paper, the study focuses on biomarker characterization of the Kelesa Formation that is situated in the Central Sumatra Basin, one of the petroliferous basins in Indonesia. This Eocene formation is equivalent to the Pematang Formation that is well known as acting as source rock in the Central Sumatra Basin. Thirty fresh outcrop samples were taken for biomarker analysis, with specification fourteen samples for gas chromatography and sixteen samples for gas chromatography-mass spectrometry. The gas chromatography analysis was done with a Perkin Elmer Clarus 600 type instrument while the mass spectrometry was done using a Perkin Elmer Clarus SQ 8C instrument. The results show that the organic matter dominantly comes from terrestrial plants with minor input from planktonic algae. Moreover, possible Botryococcus braunii input in the sediment suggests that the Kelesa Formation has been deposited in a lacustrine environment. Since the Kelesa Formation was deposited in a lacustrine environment, this formation is expected to be highly oil-prone source rock. The maturity biomarker indicators suggest that the formation does not reach appropriate maturity to expel hydrocarbon. However, the formation still has very good potential for oil shale resources. This study supports the previous study in the Kelesa Formation, and improves the understanding of the depositional history of the Kelesa Formation and the potential of the Kelesa Formation as oil shale resources. Moreover, the authors hope that this study can support recent basin evaluation and improve the understanding of the petroleum system in the Central Sumatra Basin.

scholarly journals Biomarkers geochemistry of the Alpagut oil shale sequence: an evaluation of dispositional environments and source rock potential from Dodurga-Çorum basin (N-Turkey)

2022 ◽  
Author(s):  
S. Korkmaz ◽  
R. Kara-Gülbay ◽  
T. Khoitiyn ◽  
M. S. Erdoğan
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Oil Shale ◽  
Sedimentary Environment ◽  
Organic Matter Content ◽  
Type I ◽  
Terrestrial Organic Matter ◽  
High Hydrogen ◽  
Oil Shales ◽  
Biomarker Data

AbstractThe Cenozoic Çankırı-Çorum basin, with sedimentary facies of varying thickness and distribution, contains raw matters such as coal deposits, oil shales and evaporate. Source rock and sedimentary environment characteristics of the oil shale sequence have been evaluated. The studied oil shales have high organic matter content (from 2.97 to 15.14%) and show excellent source rock characteristics. Oil shales are represented by very high hydrogen index (532–892 mg HC/g TOC) and low oxygen index (8–44 mgCO2/g TOC) values. Pyrolysis data indicate that oil shales contain predominantly Type I and little Type II kerogen. The biomarker data reveal the presence of algal, bacterial organic matter and terrestrial organic matter with high lipid content. These findings show that organic matters in the oil shales can generate hydrocarbon, especially oil. High C26/C25, C24/C23 and low C22/C21 tricyclic terpane, C31R/C30 hopane and DBT/P ratios indicate that the studied oil shales were deposited in a lacustrine environment, and very low Pr/Ph ratio is indicative of anoxic character for the depositional environment. Tmax values from the pyrolysis analysis are in the range of 418–443 °C, and production index ranges from 0.01 to 0.08. On the gas chromatography, high Pr/nC17 and Ph/nC18 ratios and CPI values significantly exceeding 1 were determined. Very low 22S/(22S + 22R) homohopane, 20S/(20S + 20R) sterane, diasterane/sterane and Ts/(Ts + Tm) ratios were calculated from the biomarker data. Results of all these analyses indicate that Alpagut oil shales have not yet matured and have not entered the oil generation window.

scholarly journals Chronostratigraphy, palynofacies, source-rock potential, and organic thermal maturity of Jurassic rocks from Qatar

GeoArabia ◽  
2002 ◽  
Vol 7 (4) ◽  
pp. 675-696
Author(s):  
Mohamed I. A. Ibrahim ◽  
Hamad Al-Saad ◽  
Suzan E. Kholeif
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Reservoir Rock ◽  
Inert Material ◽  
Type I ◽  
Carbonate Sediments ◽  
Type Ii ◽  
Type Iii ◽  
Kerogen Type ◽  
Marine Algal

ABSTRACT Strontium isotope, palynological, and total organic carbon (TOC) analyses were made on core samples from the Izhara, Araej, and Hanifa formations of three wells in onshore Qatar. Eleven samples were analyzed for their 87Sr/86Sr ratios. The results gave a chronostratigraphic range of Early Jurassic (Hettangian) to Late Jurassic (Oxfordian), with an overall age range of 202.4 Ma to 157.8 Ma. Maximum flooding surfaces MFS J10 to MFS J50 occur in the Izhara, Araej, and Hanifa formations. The organic matter in the carbonate sediments of the Izhara, Araej, and Hanifa formations was almost exclusively of marine algal origin dominated by marine microplankton. Organic matter obtained from the Izhara Formation was mature to over-mature kerogen type-III to IV, gas-prone to inert material (mean TOC 0.31%). In the Araej Formation, mature oil-prone and gas-prone kerogen type-II and type-III organic matter occurred in both the lower and upper Araej members (TOC 0.13-0.69%). The stylolitic limestone of the Uwainat member of the Araej Formation has poor potential as a source rock for petroleum (TOC 0.03-0.13%), but is considered to be the main reservoir rock of the Middle Jurassic in Qatar. Mature, highly oil-prone organic matter (type-I and type-II kerogen) was present in black limestone of the Hanifa Formation (mean TOC 0.60%; maximum 0.93%). The limestone is considered to be the most likely petroleum source rock for the underlying and overlying limestone reservoirs of the Uwainat member of the Araej Formation (Bathonian) and the Arab-D member of the Arab Formation (Kimmeridgian) units, respectively.

scholarly journals Depositional sequence interpretation using seismic and well data of offshore Central Sumatra Basin

2021 ◽  
Vol 944 (1) ◽  
pp. 012002
Author(s):  
T B Nainggolan ◽  
U Nurhasanah ◽  
I Setiadi
Keyword(s):  
Sequence Stratigraphy ◽  
Source Rock ◽  
Depositional Environments ◽  
Depositional Sequence ◽  
Seismic Section ◽  
Biogenic Gas ◽  
Hydrocarbon Reservoir ◽  
Potential Source Rock ◽  
Well Data ◽  
Central Sumatra

Abstract Offshore Central Sumatra Basin is an integral part of Central Sumatra Basin known for producing hydrocarbon basins. The derivation of stratigraphic study of seismic and well data is intended to improve accuracy of geological interpretation. Sequence stratigraphy studies have a significant role in exploratory studies to determine which depositional sequence can be inferred as hydrocarbon reservoir and its correlation in petroleum system. This study aims to identify biogenic gas sequential interpretation using seismic and well data of offshore Central Sumatra Basin. The procedure to analyze sequence stratigraphy is to identify stratigraphy surface markers using GR log, then map these markers to the seismic section that has been tied with good data to determine the distribution of each stratigraphy sequence. This study area has five depositional sequences, which are predominantly formed in marine depositional environments. Potential source rock in this area is at DS-1 which has a lacustrine depositional environment with euxinic conditions. The euxinic shale at the upper TST-1 deposit could be a source rock with hydrocarbon migration through faults. Biogenic gas reservoir potential is in Petani Formation (DS-5). Shale in MFS-5 and HST-5 could be a hydrocarbon trap, whereas LST-5 and TST-5 sandstone deposits can be a reservoir.

Sign in / Sign up

Export Citation Format

Share Document