scholarly journals Geochemical characterization of Neogene sediments from onshore West Baram Delta Province, Sarawak: paleoenvironment, source input and thermal maturity

2017 ◽  
Vol 9 (1) ◽  
Author(s):  
Olayinka S. Togunwa ◽  
Wan H. Abdullah
Keyword(s):  
Oil And Gas ◽  
Saturated Hydrocarbon ◽  
Vitrinite Reflectance ◽  
Maturity Stage ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
Marine Organic Matter ◽  
Rock Formations ◽  
Neogene Sediments

AbstractThe Neogene strata of the onshore West Baram Province of NW Borneo contain organic rich rock formations particularly within the Sarawak basin. This basin is a proven prolific oil and gas province, thus has been a subject of great interest to characterise the nature of the organic source input and depositional environment conditions as well as thermal maturation. This study is performed on outcrop samples of Lambir, Miri and Tukau formations, which are of stratigraphic equivalence to the petroleum bearing cycles of the offshore West Baram delta province in Sarawak. The investigated mudstone samples are organic rich with a total organic carbon (TOC) content of more than 1.0 wt.%. The integration of elemental and molecular analyses indicates that there is no significant variation in the source input between these formations. The investigated biomarkers parameters achieved from acyclic isoprenoids, terpanes and steranes biomarkers of a saturated hydrocarbon biomarkers revealed that these sediments contain high contribution of land plants with minor marine organic matter input that was deposited and preserved under relatively oxic to suboxic conditions. This is further supported by low total sulphur (TS), high TOC/TN ratios, source and redox sensitive trace elements (V, Ni, Cr, Co and Mo) concentrations and their ratios, which suggest terrigenous source input deposited under oxic to suboxic conditions. Based on the analysed biomarker thermal maturity indicators, it may be deduced that the studied sediments are yet to enter the maturity stage for hydrocarbon generation, which is also supported by measured vitrinite reflectance values of 0.39-0.48% R

scholarly journals Geochemical Evaluation of the Cretaceous Mudrocks and Sandstones (Wackes) in the Southern Bredasdorp Basin, Offshore South Africa: Implications for Hydrocarbon Potential

Minerals ◽  
2020 ◽  
Vol 10 (7) ◽  
pp. 595
Author(s):  
Temitope Love Baiyegunhi ◽  
Kuiwu Liu ◽  
Oswald Gwavava ◽  
Nicola Wagner ◽  
Christopher Baiyegunhi
Keyword(s):  
South Africa ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Geochemical Data ◽  
Minor Amount ◽  
Hydrocarbon Potential ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
The Mean

The southern Bredasdorp Basin, off the south coast of South Africa, is only partly understood in terms of its hydrocarbon potential when compared to the central and northern parts of the basin. Hydrocarbon potential assessments in this part of the basin have been limited, perhaps because the few drilled exploration wells were unproductive for hydrocarbons, yielding trivial oil and gas. The partial integration of data in the southern Bredasdorp Basin provides another reason for the unsuccessful oil and gas exploration. In this study, selected Cretaceous mudrocks and sandstones (wacke) from exploration wells E-AH1, E-AJ1, E-BA1, E-BB1 and E-D3 drilled in the southern part of the Bredasdorp Basin were examined to assess their total organic carbon (TOC), thermal maturity, organic matter type and hydrocarbon generation potential. The organic geochemical results show that these rocks have TOC contents ranging from 0.14 to 7.03 wt.%. The hydrogen index (HI), oxygen index (OI), and hydrocarbon index (S2/S3) values vary between 24–263 mg HC/g TOC, 4–78 mg CO2/g TOC, and 0.01–18 mgHC/mgCO2 TOC, respectively, indicating predominantly Type III and IV kerogen with a minor amount of mixed Type II/III kerogen. The mean vitrinite reflectance values vary from 0.60–1.20%, indicating that the samples are in the oil-generation window. The Tmax and PI values are consistent with the mean vitrinite reflectance values, indicating that the Bredasdorp source rocks have entered the oil window and are considered as effective source rocks in the Bredasdorp Basin. The hydrocarbon genetic potential (SP), normalized oil content (NOC) and production index (PI) values all indicate poor to fair hydrocarbon generative potential. Based on the geochemical data, it can be inferred that most of the mudrocks and sandstones (wackes) in the southern part of the Bredasdorp Basin have attained sufficient burial depth and thermal maturity for oil and gas generation potential.

scholarly journals Thermal and structural modeling of the Scillato wedge-top basin source-to-sink system: Insights into the Sicilian fold-and-thrust belt evolution (Italy)

2019 ◽  
Vol 131 (11-12) ◽  
pp. 1763-1782 ◽  
Author(s):  
Martina Balestra ◽  
Sveva Corrado ◽  
Luca Aldega ◽  
Maurizio Gasparo Morticelli ◽  
Attilio Sulli ◽  
...  
Keyword(s):  
Short Range ◽  
Vitrinite Reflectance ◽  
Sediment Provenance ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
Thrust Belt ◽  
Ordered Structures ◽  
Source To Sink ◽  
Fold And Thrust Belt ◽  
Basin Fill

Abstract Temperature-dependent clay mineral assemblages, vitrinite reflectance, and one-dimensional (1-D) thermal and three-dimensional (3-D) geological modeling of a Neogene wedge-top basin in the Sicilian fold-and-thrust belt and its pre-orogenic substratum allowed us to: (1) define the burial history of the sedimentary succession filling the wedge-top basin and its substratum, (2) reconstruct the wedge-top basin geometry, depocenter migration, and sediment provenance through time in the framework of a source-to-sink system, and (3) shed new light into the kinematic evolution of the Apennine-Maghrebian fold-and-thrust belt. The pre-orogenic substratum of the Scillato basin shows an increase in levels of thermal maturity as a function of stratigraphic age that is consistent with maximum burial to 3.5 km in deep diagenetic conditions. In detail, Ro% values range from 0.40% to 0.94%, and random ordered illite-smectite (I-S) first converts to short-range ordered structures and then evolves to long-range ordered structures at the base of the Imerese unit. The wedge-top basin fill experienced shallow burial (∼2 km) and levels of thermal maturity in the immature stage of hydrocarbon generation and early diagenesis. Vitrinite reflectance and mixed-layer I-S values show two populations of authigenic and inherited phases. The indigenous population corresponds to macerals with Ro% values of 0.33%–0.45% and I-S with no preferred sequence in stacking of layers, whereas the reworked group corresponds to macerals with Ro% values of 0.42%–0.47% and short-range ordered I-S with no correlation as a function of depth. Authigenic and reworked components of the Scillato basin fill allowed us to unravel sediment provenance during the Neogene, identifying two main source areas feeding the wedge-top basin (crystalline units of the European domain and sedimentary units of the African domain), and to detect an early phase of exhumation driven by low-angle extensional faults that predated Neogene compression.

scholarly journals Organic geochemistry and mineralogical characterization of the Paleocene Ranikot Formation shales in selected areas of Southern Indus Basin Pakistan.

2021 ◽  
Author(s):  
Hussain Asghar ◽  
◽  
Saeed Abbas ◽  
Muhammad S. Khan ◽  
Samina Jahandad ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Organic Geochemistry ◽  
Vitrinite Reflectance ◽  
Xrd Analysis ◽  
Indus Basin ◽  
Gas Chromatography Mass Spectrometry ◽  
Mineralogical Characterization ◽  
Type Iv ◽  
Rock Eval

Southern Indus Basin is one of the promising regions in Pakistan as a commercially producing oil and gas perspective. The current research presents the geochemical characterization of the Ranikot Formation shales from Southern Indus Basin based on total organic carbon (TOC), Rock-Eval (RE) pyrolysis, organic petrography, gas chromatography-mass spectrometry (GC-MS), and x-ray diffraction (XRD) analyses. The average TOC of Ranikot shale is 4.6 wt. %, indicating very good hydrocarbon potential. Types III/IV kerogens were identified in Ranikot shale. The maceral data also suggest that the Type of kerogen present in Ranikot shale is dominantly Types II-III, with the minor occurrence of Type IV. The vitrinite reflectance, pyrolysis Tmax and methylphenanthrene indices values specify immature levels of the shales. The normal alkane data reflect that marine macrophyte, algae, and land plants were contributed to the organic matter of Ranikot shales. Dibenzothiophene/phenanthrene ratio (0.11), phytane/n-C18 ratio (0.53), pyrite, and glauconite elucidate that the depositional environment of the Ranikot shale is marine. The XRD analysis of the shale from the Ranikot Formation revealed that it is brittle shale and dominated by 39.5 to 50.9 wt. % quartz. The present study, integration with the US EIA report demarcated the Ranikot Formation influential horizon as a shale gas resource.

scholarly journals Hydrocarbon generation from Carboniferous-Permian coaly source rocks in the Huanghua depression under different geological processes

2020 ◽  
Vol 17 (6) ◽  
pp. 1540-1555
Author(s):  
Jin-Jun Xu ◽  
Qiang Jin
Keyword(s):  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Oil And Gas Exploration ◽  
Geological Processes ◽  
Light Oil ◽  
Huanghua Depression ◽  
Higher Temperature

AbstractNatural gas and condensate derived from Carboniferous-Permian (C-P) coaly source rocks discovered in the Dagang Oilfield in the Bohai Bay Basin (east China) have important implications for the potential exploration of C-P coaly source rocks. This study analyzed the secondary, tertiary, and dynamic characteristics of hydrocarbon generation in order to predict the hydrocarbon potentials of different exploration areas in the Dagang Oilfield. The results indicated that C-P oil and gas were generated from coaly source rocks by secondary or tertiary hydrocarbon generation and characterized by notably different hydrocarbon products and generation dynamics. Secondary hydrocarbon generation was completed when the maturity reached vitrinite reflectance (Ro) of 0.7%–0.9% before uplift prior to the Eocene. Tertiary hydrocarbon generation from the source rocks was limited in deep buried sags in the Oligocene, where the products consisted of light oil and gas. The activation energies for secondary and tertiary hydrocarbon generation were 260–280 kJ/mol and 300–330 kJ/mol, respectively, indicating that each instance of hydrocarbon generation required higher temperature or deeper burial than the previous instance. Locations with secondary or tertiary hydrocarbon generation from C-P coaly source rocks were interpreted as potential oil and gas exploration regions.

scholarly journals Burial history, thermal history and hydrocarbon generation modelling of the Jurassic source rocks in the basement of the Polish Carpathian Foredeep and Outer Carpathians (SE Poland)

2012 ◽  
Vol 63 (4) ◽  
pp. 335-342 ◽  
Author(s):  
Paweł Kosakowski ◽  
Magdalena Wróbel
Keyword(s):  
Organic Matter ◽  
Thermal History ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
Burial History ◽  
Se Poland ◽  
Carpathian Foredeep ◽  
Outer Carpathians

Burial history, thermal history and hydrocarbon generation modelling of the Jurassic source rocks in the basement of the Polish Carpathian Foredeep and Outer Carpathians (SE Poland)Burial history, thermal maturity, and timing of hydrocarbon generation were modelled for the Jurassic source rocks in the basement of the Carpathian Foredeep and marginal part of the Outer Carpathians. The area of investigation was bounded to the west by Kraków, to the east by Rzeszów. The modelling was carried out in profiles of wells: Będzienica 2, Dębica 10K, Góra Ropczycka 1K, Goleszów 5, Nawsie 1, Pławowice E1 and Pilzno 40. The organic matter, containing gas-prone Type III kerogen with an admixture of Type II kerogen, is immature or at most, early mature to 0.7 % in the vitrinite reflectance scale. The highest thermal maturity is recorded in the south-eastern part of the study area, where the Jurassic strata are buried deeper. The thermal modelling showed that the obtained organic matter maturity in the initial phase of the "oil window" is connected with the stage of the Carpathian overthrusting. The numerical modelling indicated that the onset of hydrocarbon generation from the Middle Jurassic source rocks was also connected with the Carpathian thrust belt. The peak of hydrocarbon generation took place in the orogenic stage of the overthrusting. The amount of generated hydrocarbons is generally small, which is a consequence of the low maturity and low transformation degree of kerogen. The generated hydrocarbons were not expelled from their source rock. An analysis of maturity distribution and transformation degree of the Jurassic organic matter shows that the best conditions for hydrocarbon generation occurred most probably in areas deeply buried under the Outer Carpathians. It is most probable that the "generation kitchen" should be searched for there.

scholarly journals Geochemistry and petrology of selected sediments from Bukit Song, Miri, Sarawak, Malaysia, with emphasis on organic matter characterization

2021 ◽  
Vol 11 (10) ◽  
pp. 3663-3688
Author(s):  
Amin Tavakoli
Keyword(s):  
Organic Matter ◽  
Depositional Environment ◽  
Vitrinite Reflectance ◽  
Xrd Analysis ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
Petroleum Potential ◽  
Type Iv ◽  
Two Samples

AbstractThe aim of this study is to provide a better understanding of the type of source input, quality, quantity, the condition of depositional environment and thermal maturity of the organic matter from Bukit Song, Sarawak, which has not been extensively studied for hydrocarbon generation potential. Petrological and geochemical analyses were performed on 13 outcrop samples of the study location. Two samples, having type III and mixed kerogen, showed very-good-to-excellent petroleum potential based on bitumen extraction and data from Rock–Eval analysis. The rest of the samples are inert—kerogen type IV. In terms of thermal maturity based on vitrinite reflectance, the results of this paper are akin to previous studies done in the nearby region reported as either immature or early mature. Ph/n-C18 versus Pr/n-C17 data showed that the major concentration of samples is within peat coal environment, whilst two samples were associated with anoxic marine depositional environment, confirmed by maceral content as well. Macerals mainly indicated terrestrial precursors and, overall, a dominance of vitrinite. Quality of the source rock based on TOC parameter indicated above 2 wt. % content for the majority of samples. However, consideration of TOC and S2 together showed only two samples to have better source rocks. Existence of cutinite, sporinite and greenish fluorescing resinite macerals corroborated with the immaturity of the analysed coaly samples. Varying degrees of the bitumen staining existed in a few samples. Kaolinite and illite were the major clays based on XRD analysis, which potentially indicate low porosity. This study revealed that hydrocarbon-generating potential of Bukit Song in Sarawak is low.

Hydrocarbon Generation Indication from Source Rock to Reservoir Rock: Case Studies of Anambra and Abakaliki Basins South-Eastern Nigeria

2016 ◽  
Author(s):  
Samuel Salufu ◽  
Rita Onolemhemhen ◽  
Sunday Isehunwa
Keyword(s):  
Case Studies ◽  
Source Rock ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Reservoir Rock ◽  
Hydrocarbon Generation ◽  
Geochemical Analysis ◽  
Anambra Basin ◽  
Oil Generation

ABSTRACT This paper sought to use information from outcrop sections to characterize the source and reservoir rocks in a basin in order to give indication(s) for hydrocarbon generation potential in a basin in minimizing uncertainty and risk that are allied with exploration and field development of oil and gas, using subsurface data from well logs, well sections, seismic and core. The methods of study includes detailed geological, stratigraphical, geochemical, structural,, petro-graphical, and sedimentological studies of rock units from outcrop sections within two basins; Anambra Basin and Abakaliki Basin were used as case studies. Thirty eight samples of shale were collected from these Basins; geochemical analysis (rockeval) was performed on the samples to determine the total organic content (TOC) and to assess the oil generating window. The results were analyzed using Rock wares, Origin, and Surfer software in order to properly characterize the potential source rock(s) and reservoir rock(s) in the basins, and factor(s) that can favour hydrocarbon traps. The results of the geological, stratigraphical, sedimentological, geochemical, and structural, were used to developed a new model for hydrocarbon generation in the Basins. The result of the geochemical analysis of shale samples from the Anambra Basin shows that the TOC values are ≥ 1wt%, Tmax ≥ 431°C, Vitrinite reflectance values are ≥ 0.6%, and S1+S2 values are > 2.5mg/g for Mamu Formation while shale samples from other formations within Anambra Basin fall out of these ranges. The shale unit in the Mamu Formation is the major source rock for oil generation in the Anambra Basin while others have potential for gas generation with very little oil generation. The shale samples from Abakaliki Basin shows that S1+S2 values range from< 1 – 20mg/g, TOC values range from 0.31-4.55wt%, vitrinite reflectance ranges from 0.41-1.24% and Tmax ranges from423°C – 466°C. This result also shows that there is no source rock for oil generation in Abakaliki Basin; it is either gas or graphite. This observation indicates that all the source rocks within Abakaliki Basin have exceeded petroleum generating stage due to high geothermal heat resulting from deep depth or the shale units have not attained catagenesis stage as a result of S1+S2 values lesser than 2.5mg/g despite TOC values of ≥ 0.5wt% and vitrinite reflectance values of ≥ 0.6%. The novelty of this study is that the study has been able to show that here there is much more oil than the previous authors claimed, and the distribution of this oil and gas in the basins is controlled by two major factors; the pattern of distribution of the materials of the source rock prior to subsidence and during the subsidence period in the basin, and the pattern and the rate of tectonic activities, and heat flow in the basin. If these factors are known, it would help to reduce the uncertainties associated with exploration for oil and gas in the two basins.

Burial History, Hydrocarbon Generation, and Migration in the Upper Paleogene Petroleum System of the Offshore North Sumatra Basin: Insights from 1D and 2D Basin Modeling.

2021 ◽  
Author(s):  
H. Lazuardi
Keyword(s):  
Seismic Data ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Andaman Sea ◽  
Indian Plate ◽  
Hydrocarbon Generation ◽  
Basin Modeling ◽  
Burial History ◽  
Eurasian Plate ◽  
And Migration

One-dimensional and two-dimensional basin modeling can be used to infer the burial history, hydrocarbon generation, and migration of hydrocarbon. In this paper, the study focuses on 1D and 2D basin modeling in North Sumatera Offshore as one of the prolific deep-water basins in Indonesia. The data consists of 5 exploration wells and 2D seismic data that are vitrinite reflectance, rock-eval data, and bottom-hole temperature. Well data’s have been used to calibrate heat flow and thermal evolution of the basin, while 2D seismic data have been used to support the basin modeling. Based on the result, the basin formed by the collision of the Australian Plate with the Eurasian Plate evolved due to block faulting that caused a pull-apart basin. In the Early Oligocene, changes in the movement of the Indian plate also changed tectonics from subduction to strike-slip fault resulting in Andaman Sea rifting. The southern part of the research area was affected by the Andaman Sea rifting, which caused unconformities in the Middle Miocene. The main generating source rock is the Bampo, Belumai, and Baong Formation, which is predominantly consist of Type III kerogen (gas prone) in the north and Type II/III (mix oil and gas prone) in the South. The timing of petroleum generation may have occurred is in the Early Pliocene. The Early oil generation which occurred simultaneously with the seal rock and may have been migrated to the Middle and Late Miocene reservoir through the faults as a vertical migration pathway. The results of this study allow us to improve the hydrocarbon prospect and reduce exploration risks.

Characteristics of the Overpressure Resulted from Hydrocarbon Generation

2013 ◽  
Vol 295-298 ◽  
pp. 2707-2710
Author(s):  
Hai Yan Hu ◽  
Hui Wang
Keyword(s):  
Organic Matter ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Junggar Basin ◽  
Hydrocarbon Generation ◽  
Sonic Velocity ◽  
Gas Generation

Overpressure is often encountered in the Jurassic tight sandstones in the central Junggar Basin. In this studt, a new mechanism of overpressure formation related to gas generation is proposed. Organic-rich mudstones have sonic velocity well-line reserves but their densities continue to increase in the over-compacted mudstone system resulting in the overpressure development during the conversion of the organic matter to oil and gas. The top of the overpressure zone correlates with the depth required for a large quantity of gas generation in which the vitrinite reflectance (Ro) is about 0.7%, showing that the overpressure in organic-rich mudstones is closely associated with gas generation.

scholarly journals Paleotemperature modeling of hydrocarbon generation centers and their role in the formation of «Paleozoic» oil deposits (Ostaninskoe field, Tomsk region)

Georesursy ◽  
2021 ◽  
Vol 23 (1) ◽  
pp. 2-16
Author(s):  
Valery I. Isaev ◽  
Margarita F. Galieva ◽  
Anna O. Aleeva ◽  
Galina A. Lobova ◽  
Vitaly I. Starostenko ◽  
...  
Keyword(s):  
Heat Flow ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Hydrocarbon Generation ◽  
Weathering Crust ◽  
Tomsk Region ◽  
History Of ◽  
Oil Deposits ◽  
Reflectance Measurements

Study and exploration of the pre-Jurassic oil and gas complex in Western Siberia is one of the aspects of hydrocarbon raw-material base development. The main scope of this study is to locate the source of Paleozoic hydrocarbons. The problem of modeling and assessing the role of Paleozoic-Mesozoic hydrocarbon generation centers in the formation of «Paleozoic» oil deposits in the section of the Ostaninskoe oil and gas condensate field (Tomsk region) is solved. In the formation of the oil and gas content of the pre-Jurassic basement two reservoirs are involved: the weathering crust and the roof of the bed-rock Paleozoic. The first was formed during the period of 213–208 Ma, and the second is genetically determined by epigenetic processes in the weathering crust. Potential hydrocarbon sources for the weathering crust and bed-rock Paleozoic reservoirs are Domanic type rocks in the crystalline basement: Larinskaya S1lr, Mirnaya D1mr, Chuzikskaya D2cz, Chaginskaya D3cg Formations, as well as Tyumenskaya J1-2tm and Bazhenovskaya J3bg Formations in sedimentary cover. To perform joint paleotemperature modeling of sedimentary basins of the «modern» Jurassic-Cretaceous and Paleozoic «paleobasins», the Ostaninskaya 438P well was selected, which is due to the presence of measured temperatures both in the Jurassic sections and in the pre-Jurassic formations, as well as fluid inflows from the pre-Jurassic horizons into the well. At the first step, the solution of the inverse problem of geothermics was obtained using reservoir temperatures and vitrinite reflectance measurements from the Mesozoic deposits: density of deep heat flow from the base of sedimentary section was determined, which is characterized by a quasi-constant value from the Jurassic to the present. The second step was to solve the inverse problem using vitrinite reflectance measurements from Paleozoic sediments. As a result, the heat flow value was obtained for the key moments of geodynamic history of the stratigraphic section, starting from the Silurian. By solving direct problems of geothermics with the given values of heat flow, the structural-tectonic and thermal history of four Paleozoic potential oil source formations (as well as Jurassic – Bazhenov and Tyumen Formations) has been retraced. The controversial aspects of the heat transfer model in the section of the Ostaninskoe field are considered. It has been established that the Tyumen and Bazhenov oil sources (most likely Bazhenov) are syngenetic (in terms of generation, accumulation and preservation time) for the weathering crust and the Paleozoic reservoirs. The role of the Chaginskaya Formation as gas source is insignificant.

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