scholarly journals Middle Miocene Black Shale of Airbenakat Formation in Berau Areas, Jambi: are they potential source rock?

2019 ◽  
Vol 4 (2) ◽  
pp. 128
Author(s):  
Putri Dwi Afifah ◽  
Budhi Setiawan
Keyword(s):  
Source Rock ◽  
Black Shale ◽  
Middle Miocene ◽  
Geological Mapping ◽  
Source Rocks ◽  
Maximum Temperature ◽  
Rock Samples ◽  
A Value ◽  
Three Samples ◽  
Potential Source Rock

The research location is geologically located in Jambi Sub-basin composed by Peneta Formation (KJp), Airbenakat (Tma), and Muara Enim (Tmpm). Specifically this research focuses on the physical characteristics and geochemistry of Middle Miocene black shale from Airbenakat Formation. The purpose of this research is to determine whether the black shale of this formation has the potential as a source rock. The method of this research are field observation that includes the description of rock samples and geological mapping, and laboratory analysis including rock geochemical analysis. Three samples were taken from black and fine-grained shale. Total organic carbon (TOC) values of the three samples taken ranged from 0.38-0.42%, the weight of TOC indicates a potentially close enough to produce hydrocarbons. the pyrolysis results show that the S1 data gives a value below 0.5 HC/g and S2 gives a value below 2.5 HC/g, so it can be seen that the three rock samples that tested are not sufficient enough to produce hydrocarbons. Overall the sample has a S2/S3 ratio ranging from 0.09-0.23 and Tmax-HI data has values ranging from 8-19 mg HC/g TOC, so it can be seen that the ratio S2/S3 less than 1 and the value of the index hydrogen below 50 mg HC/g TOC, It can be concluded that the samples are derived from type IV kerogen. The maximum temperature (Tmax) of pyrolysis shows a value of less than 4350C, where the values range from 350-4280C. So, it can be interpreted that the three samples are immature source rocks because the catagenesis phase to produce hydrocarbons has not been achieved. The conclusions is the three samples of black shale tested indicate potential as immature source rock and has the close enough ability to produce hydrocarbons. The result of the analysis then comparable with the result analysis of Airbenakat Formation Black Shale in Palembang Sub-basin which has fair-well ability to produce hydrocarbons.  

scholarly journals Source rock characterization of mesozoic to cenozoic organic matter rich marls and shales of the Eratosthenes Seamount, Eastern Mediterranean Sea

2018 ◽  
Vol 73 ◽  
pp. 49 ◽  
Author(s):  
Sebastian Grohmann ◽  
Susanne W. Fietz ◽  
Ralf Littke ◽  
Samer Bou Daher ◽  
Maria Fernanda Romero-Sarmiento ◽  
...  
Keyword(s):  
Organic Matter ◽  
Mediterranean Sea ◽  
Source Rock ◽  
Eastern Mediterranean ◽  
Source Rocks ◽  
Eastern Mediterranean Sea ◽  
Potential Source Rock ◽  
Levant Basin ◽  
Rock Characterization ◽  
Rock Eval

Several significant hydrocarbon accumulations were discovered over the past decade in the Levant Basin, Eastern Mediterranean Sea. Onshore studies have investigated potential source rock intervals to the east and south of the Levant Basin, whereas its offshore western margin is still relatively underexplored. Only a few cores were recovered from four boreholes offshore southern Cyprus by the Ocean Drilling Program (ODP) during the drilling campaign Leg 160 in 1995. These wells transect the Eratosthenes Seamount, a drowned bathymetric high, and recovered a thick sequence of both pre- and post-Messinian sedimentary rocks, containing mainly marine marls and shales. In this study, 122 core samples of Late Cretaceous to Messinian age were analyzed in order to identify organic-matter-rich intervals and to determine their depositional environment as well as their source rock potential and thermal maturity. Both Total Organic and Inorganic Carbon (TOC, TIC) analyses as well as Rock-Eval pyrolysis were firstly performed for the complete set of samples whereas Total Sulfur (TS) analysis was only carried out on samples containing significant amount of organic matter (>0.3 wt.% TOC). Based on the Rock-Eval results, eight samples were selected for organic petrographic investigations and twelve samples for analysis of major aliphatic hydrocarbon compounds. The organic content is highly variable in the analyzed samples (0–9.3 wt.%). TS/TOC as well as several biomarker ratios (e.g. Pr/Ph < 2) indicate a deposition under dysoxic conditions for the organic matter-rich sections, which were probably reached during sporadically active upwelling periods. Results prove potential oil prone Type II kerogen source rock intervals of fair to very good quality being present in Turonian to Coniacian (average: TOC = 0.93 wt.%, HI = 319 mg HC/g TOC) and in Bartonian to Priabonian (average: TOC = 4.8 wt.%, HI = 469 mg HC/g TOC) intervals. A precise determination of the actual source rock thickness is prevented by low core recovery rates for the respective intervals. All analyzed samples are immature to early mature. However, the presence of deeper buried, thermally mature source rocks and hydrocarbon migration is indicated by the observation of solid bitumen impregnation in one Upper Cretaceous and in one Lower Eocene sample.

ACCURATE RECOGNITION OF SOURCE ROCK CHARACTER IN THE JURASSIC OF THE NORTH WEST SHELF, WESTERN AUSTRALIA

1992 ◽  
Vol 32 (1) ◽  
pp. 289 ◽  
Author(s):  
John Scott
Keyword(s):  
Source Rock ◽  
Organic Material ◽  
Source Rocks ◽  
Higher Plant ◽  
Pyrolysis Gas ◽  
Screening Analysis ◽  
North West ◽  
The North ◽  
Potential Source Rock ◽  
Rock Eval

The main potential source rock intervals are generally well defined on the North West Shelf by screening analysis such as Rock-Eval. The type of product from the source rocks is not well defined, owing to inadequacies in current screening analysis techniques. The implications of poor definition of source type in acreage assessment are obvious. The type of product is dependent on the level of organic maturity of the source rock, the ability of products to migrate out of the source rock and on the type of organic material present. The type of kerogen present is frequently determined by Rock-Eval pyrolysis. However, Rock-Eval has severe limitations in defining product type when there is a significant input of terrestrial organic material. This problem has been recognised in Australian terrestrial/continental sequences but also occurs where marine source rock facies contain terrestrially-derived higher plant material. Pyrolysis-gas chromatography as applied to source rock analysis provides, by molecular typing, a better method of estimating the type of products of the kerogen breakdown than bulk chemical analysis such as Rock-Eval pyrolysis.

Identification and Distribution of Lower Cretaceous Source Rocks in Ying’er Sag, Jiuquan Basin

2012 ◽  
Vol 616-618 ◽  
pp. 69-72
Author(s):  
Yi Bo Zhou ◽  
Guang Di Liu ◽  
Jia Yi Zhong
Keyword(s):  
Source Rock ◽  
Low Frequency ◽  
Sedimentary Facies ◽  
Organic Content ◽  
Source Rocks ◽  
Potential Source Rock ◽  
Wide Range ◽  
Strong Amplitude ◽  
System Tracts ◽  
High Organic Content

Based on the sequence stratigraphy study, the relation between dark mudstone ratio and sedimentary facies in different system tracts is observed and used to forcast the distribution of dark mudstones in the main formation combining with seismic data and well log. However, not all dark mudstones can generate hydrocarbon, so the source rock quality is quoted to calculate the thickness of the source rock within mudstone. The results show that the favored source rock in lake progressive system tracts and the bottom of highstand system tracts of Xiagou Formation and Chijinpu Formation are related to a group of reflectors with medium-strong amplitude, medium-low frequency and medium to comparatively good lateral continuity. The source rock of Xiagou Formation with high organic content and wide-range distribution is the major hydrocarbon source in Ying’er Sag, while Chijinpu Formation with thick dark mudstones is the potential source rock and the target of the further exploration.

scholarly journals Source Rocks’ Potentiality of the Sargelu Formation (Middle Jurassic) in the Taq Taq Oilfield, Kurdistan Region, Iraq

2021 ◽  
Vol 54 (2E) ◽  
pp. 59-85
Author(s):  
Dler Baban
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Source Rocks ◽  
Petrographic Analysis ◽  
Gas Generation ◽  
Organic Matters ◽  
Rock Samples ◽  
Generation Zone ◽  
Oil Generation ◽  
Palynological Study

Thirty rock samples were selected from the well Tq-1 that penetrated the Jurassic beds in the Taq Taq Oilfield to be studied the source rock potentiality of the Sargelu Formation. The formation is characterized by three types of microfacies, namely, foraminiferal packstone, grainstone microfacies, fossiliferous packstone microfacies, and foraminiferal wackestone which were deposited in an environment extending from middle to outer carbonate ramp. An average of 3.03 wt.% of total organic carbon was obtained from a Rock Eval pyrolysis analysis carried out on 24 selected rock samples. The petrographic analysis for such organic matters revealed that they are of kerogen types III and IV and they are currently in a post-mature state. Pyrolysis parameters showed that limited generation potential was remained for these sources to expel generated hydrocarbons. The palynological study showed that Amorphous Organic Matter forms the highest percentage of organic matter components with more than 70%, followed by phytoclasts with 10 – 25 % and palynomorphs of less than 10%. The organic matters within the Sargelu Formation are deposited at the distal part of the basin under suboxic to anoxic condition. The color of the organic matter components, examined under transmitted light, showed Thermal Alteration Index values between 3+ and 4-. Such values may indicate that these organic matters are thermally at the end of the liquid oil generation zone and beginning of condensate-wet gas generation zone. The thermal maturity of the Sargelu Formation depending on the calculated VRo% revealed that the formation in the studied oilfield is currently at the peak of the oil generation zone. The Sargelu Formation in the studied field is considered as an effective source rock, as it has already generated and expelled hydrocarbons.

scholarly journals MAJOR AND TRACE ELEMENTS GEOCHEMISTRY OF ĐỒNG HO SEDIMENTS (QUẢNG NINH, VIET NAM): IMLICATION FOR PALEOENVIRONMENTAL CONDITION

2018 ◽  
Vol 34 (2) ◽  
Author(s):  
Vượng Nguyễn Văn
Keyword(s):  
Trace Elements ◽  
Source Rock ◽  
Major And Trace Elements ◽  
Source Rocks ◽  
Annual Rainfall ◽  
Humid Climate ◽  
Clear Trend ◽  
Petroleum Potential ◽  
Potential Source Rock ◽  
Quang Ninh

The Dong Ho sedimentary formation consists of gravel, sand and sandstone, mudstone interbeded with asphalt layer or oil shale cropping out at Quang Ninh is considered as outcrop of petroleum potential source rock and correlated to source rock of the Cenozoic basins on the continental shelf of Southeast Asia. Geochemical investigation  of major and trace elements content variation from 14 typical samples selected from diferent layers leads to divide the Dong Ho formation into two parts: the lower part characterized by unclear variation while the upper part exposing a more clear trend. The paleoenvironmental proxy and the CIA, CIW, PIA and CPA indices of the Dong Ho formation revealed high weathering intensity. V/Ni and C/Cr s vary from 0.14 to 1.52; and from 0.02 to 0.52 respectively indicate to oxic depositional environment. The provenance of the Dong Ho sedimentary layers come from the recycling of sedimentary source rocks and deposited within freshwater lacustrine environment dominated with humid climate with estimated mean annual rainfall of 1533 mm / yr ± 181 mm before changing to wet and reductioin environment during diagenesis.

scholarly journals Petroleum Geology and Geochemistry of Oils and Possible Source Rocks of the Southern East Coast Basin, New Zealand

2021 ◽  
Author(s):  
◽  
Nils Erik Elgar
Keyword(s):  
Source Rock ◽  
Black Shale ◽  
Oil And Gas ◽  
East Coast ◽  
Source Rocks ◽  
Higher Plant ◽  
Marine Organic Matter ◽  
Potential Source ◽  
Good Potential ◽  
Oil Source

<p>The East Coast Basin of New Zealand contains up to 10,000 m of predominantly fine-grained marine sediments of Early Cretaceous to Pleistocene age, and widespread oil and gas seepages testify to its status as a petroleum province. A suite of oils and possible source rocks from the southern East Coast Basin have been analysed by a variety of geochemical techniques to determine the hydrocarbon potential and establish oil-oil and oil-source rock correlations. Results of TOC and Rock-Eval pyrolysis indicate that the latest Cretaceous Whangai Formation and Paleocene Waipawa Black Shale represent the only good potential source rock sequences within the basin. The middle to Late Cretaceous Glenburn and Te Mai formations, previously considered good potential source rocks, are organic-rich (TOC contents up to 1.30% and 1.52% respectively), but comprise predominantly Types III and IV (structured terrestrial and semi-opaque) kerogen and, therefore, have little hydrocarbon generative potential (HI values < 50). Early Cretaceous and Neogene formations are shown to have low TOC contents and have little source rock potential. The Waipawa Black Shale is a widespread, thin (< 50 m), dark brown, non-calcareous siltstone. It contains up to 1.9% sulphur and elevated quantities of trace metals. Although immature to marginally mature for hydrocarbon generation in outcrop, it is organic-rich (TOC content up to 5.69%) and contains oil and gas-prone Types II and III kerogen. The extracted bitumen comprises predominantly marine algal and terrestrial higher plant material and indicates that deposition occurred under conditions of reduced oxygen with significant anoxic episodes. The Whangai Formation is a thick (300-500 m), non-calcareous to calcareous siliceous mudstone. Although immature to marginally mature in outcrop, the Upper Calcareous and Rakauroa members have a TOC content up to 1.37% and comprise oil and gas-prone Types II and III (structured aqueous and structured terrestrial) kerogen. Bitumen extracts comprise predominantly marine organic matter with a moderate terrestrial higher plant component and indicate that deposition occurred under mildly reducing conditions, with periodic anoxic episodes indicated for the Upper Calcareous Member. Two families of oils are recognised in the southern East Coast Basin. The Kerosene Rock, Westcott, Tiraumea and Okau Stream oils comprise both algal marine and terrestrial higher plant material and were deposited under periodically anoxic conditions. They are characterised by high relative abundances of unusual C30 steranes (C30 indices of 0.24-0.40) and 28,30-bisnorhopane, low proportions of C28 steranes and isotopically heavy [delta] 13C values (-20.9 to -23.0 [per mil]). The Waipatiki and Tunakore oils from southern Hawke's Bay and the Kora-1 oil from the northern Taranaki Basin have similar geochemical characteristics and are also included in this family of oils. These same characteristics are also diagnostic of the Waipawa Black Shale and an oil-source rock correlation is made on this basis. The Knights Stream and Isolation Creek oils are derived from predominantly marine organic matter with a moderate terrestrial angiosperm contribution, and characterised by low relative abundances of C30 steranes (C30 indices of 0.06-0.12) and 28,30-bisnorhopane, high proportions of C28 steranes and isotopically light [delta] 13C values (-26.8 to -28.9 [per mil]). Also included in this family of oils, with a slightly greater marine influence, are the major seep oils of the northern East Coast Basin (Waitangi, Totangi and Rotokautuku). A tentative oil-source rock correlation with the Upper Calcareous and Rakauroa members of the Whangai Formation is based on their similar geochemical characteristics.</p>

scholarly journals The Upper Jurassic–Cretaceous petroleum system of southern Iraq: A 3-D basin modelling study

GeoArabia ◽  
2013 ◽  
Vol 18 (1) ◽  
pp. 179-200
Author(s):  
Qusay Abeed ◽  
Ralf Littke ◽  
Frank Strozyk ◽  
Anna K. Uffmann
Keyword(s):  
Source Rock ◽  
Lower Cretaceous ◽  
Upper Jurassic ◽  
Petroleum System ◽  
Source Rocks ◽  
Maximum Temperature ◽  
Basin Modelling ◽  
Petroleum Generation ◽  
D Model ◽  
Southern Iraq

ABSTRACT A 3-D basin model of the southern Mesopotamian Basin, southern Iraq, was built in order to quantify key aspects of the petroleum system. The model is based on detailed seismic interpretation and organic geochemical data, both for source rocks and oils. Bulk kinetic analysis for three source rock samples was used to quantify petroleum generation characteristics and to estimate the temperature and timing of petroleum generation. These analyses indicate that petroleum generation from the Yamama source rock (one of the main source rocks in the study area) starts at relatively low temperatures of 70–80°C, which is typical for Type II-S kerogen at low to moderate heating rates typical of sedimentary basins. Petroleum system analysis was achieved using the results from 1-D, 2-D, and 3-D basin modelling, the latter being the major focus of this study. The 1-D model reveals that the Upper Jurassic–Lower Cretaceous sediments are now within the oil window, whereas the formations that overlie the Yamama Formation are still immature in the entire study area. Present-day temperature reflects the maximum temperature of the sedimentary sequence, which indicates that no strong regional uplift affected the sedimentary rocks in the past. The 3-D model results indicate that oil generation in the Yamama source rock already commenced in the Cretaceous. At some locations of the basin this source rock reaches a present-day maximum temperature of 140–150°C. The most common migration pathways are in the vertical direction, i.e. direct migration upward from the source rock to the reservoir. This is partly related to the fact that the Lower Cretaceous reservoir horizons in southern Iraq directly overlay the source rock.

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.

Biogenic and Thermogenic Gas Potential of The Underexplored Southern Kutai Basin, Offshore East Kalimantan: A Case Study from South Sesulu Block

2021 ◽  
Author(s):  
Y. Artha
Keyword(s):  
Source Rock ◽  
Isotope Analysis ◽  
Source Rocks ◽  
Gas Chromatography Mass Spectrometry ◽  
Geochemical Data ◽  
Sedimentation Rates ◽  
East Kalimantan ◽  
Geochemical Evaluation ◽  
Potential Source Rock ◽  
Biomarker Analysis

The Southern Kutai Basin is currently less explored than the Mahakam area and others in the northern part of this Basin. Therefore, this research focuses on knowing the potential of active source rocks that can produce hydrocarbons, the volume that can be produced and its migration that can encourage exploration activities in this area. The method of this research is to conduct a geochemical evaluation as a screening of source rock which has the potential to generate biogenic and thermogenic hydrocarbons. Rock - Eval Pyrolysis, biomarker analysis in the form of Gas Chromatography - Mass Spectrometry (GC-MS) evaluated from eight exploration wells was used to determine the quantity, quality, maturity and environment of organic material deposition. 1D and 3D basin modelling using geochemical and geological evaluations to determine the presence of thermogenic hydrocarbon shows accumulations around the study area through migration analysis. Isotope analysis, thermal gradient and sedimentation rates are used to determine the environment and activity of anaerobic micro-organisms in generating biogenic gases. Geophysical analysis including interpretation and mapping of subsurface structures using 2D and 3D seismic are used to determine the distribution of potential source rock and its migration history. Geochemical data indicate that biogenic gas have been generated from within the Late Miocene tol recent sedimentary section where the quantity of organic matter is fair to excellent (0.51 – 7.31 %wt TOC) which represents the results of micro-organism activities where sedimentation rates avg 6,2 x 107 ton/year. Thermogenic gas; however, is estimated from the Late Oligocene to Early Miocene series of post rift sediment throughout the Kutai Basin.

scholarly journals Hydrocarbon Generation History of Tertiary Source Rocks in Phu Khanh Basin, Offshore Vietnam

2020 ◽  
Vol 9 (2) ◽  
pp. 59-65
Author(s):  
Huy Xuan Nguyen ◽  
Trang Thi Thu Nguyen ◽  
Van Nguyen Nguyen ◽  
Thi Hong Quyen Vo
Keyword(s):  
Source Rock ◽  
Middle Miocene ◽  
Development Planning ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Bottom Part ◽  
Field Development ◽  
Wet Gas ◽  
History Of ◽  
Southwest Part

The source rock maturity and the hydrocarbon generation history are evaluated in the deepwater Phu Khanh Basin. The average values of heat flow, paleo water depth, and surface-water interface temperatures range from 50.80–61.69 mW/m2, 150-3,500 m, and 2.30-250C, respectively. The Oligocene and Lower–Middle Miocene source rocks are presented. The Oligocene source rock is derived from the lacustrine environment; it is mature to overmature in the Southwest part of the Phu Yen Depression. The main oil phase started in the Early Miocene, and the amount of wet gas occurred only at the bottom part. The Lower-Middle Miocene source rock has been immature in both the Southwest and Northeast part of the Phu Yen Depression. Based on the geochemical analysis, these source rocks were predominantly a mixture of type II and type III kerogens. The total organic carbon and the hydrogen index values range from 1.8-2.5 % and 250-320 mg/g, respectively. The results can help define reservoir locations for future field development planning in the Phu Khanh Basin.

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