Source rock characteristics and hydrocarbon generation potential in Brunei-Muara district, Brunei Darussalam: a comparative case study from selected Miocene-Quaternary formations

AbstractA comparative analysis on source rock properties has been carried out on the Miocene-Pliocene formations as well as the Quaternary terrace deposits using Rock–Eval pyrolysis results and organic petrography as well as some biomarkers results. Samples were obtained from outcrops of the Quaternary terrace deposits, Pliocene-aged Liang Formation together with the Miocene Miri and Setap Shale formations in Brunei-Muara district, with sample lithologies ranging from coal, coaly shale, shale and lignitic sand. High total organic carbon (TOC) and S2 values ranging from 41.8 to 62.4% and 7.40 mg HC/g rock to 122 mg HC/g rock, respectively, are identified in coals of the terrace deposit, Liang and Miri formations, making these as the best potential source rock due to the “good to excellent” generating potential. Meanwhile, a “fair to poor” potential is exhibited for the coaly shale, shale and lignitic sand samples as a result of their low TOC, HI and S2 values. The organic matter is composed of kerogen type III (gas prone) and type II-III (mixed oil and gas prone). Organic matter in all studied formations originate from a terrestrial-source, as proven by the abundance of huminite. Organic petrographical and biomarkers studies suggest that the coals and lignitic sand samples were deposited in a mangrove-type mire in a lower delta setting, under oxic and limnic to limnotelmatic conditions, except sample DD2-1, which is deposited in a less water-saturated environment. The samples display the presence of bi-modal and normal distribution of n-alkanes. For all of the samples, the dominating plant types in the palaeomire are of soft, herbaceous plants and this is supported by the low vegetation index and moderate Paq values. All the studied samples are thermally immature to early mature, as exhibited by the Tmax values that range from 300 to 437 °C and vitrinite reflectance readings of 0.22% to 0.46%.

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3D-Basin Modelling of the Lishui Sag: Research of Hydrocarbon Potential, Petroleum Generation and Migration

Energies ◽

10.3390/en12040650 ◽

2019 ◽

Vol 12 (4) ◽

pp. 650 ◽

Cited By ~ 4

Author(s):

Jinliang Zhang ◽

Jiaqi Guo ◽

Jinshui Liu ◽

Wenlong Shen ◽

Na Li ◽

...

Keyword(s):

Source Rock ◽

Thermal Evolution ◽

Vitrinite Reflectance ◽

Three Dimensional ◽

Source Rocks ◽

Rock Properties ◽

Hydrocarbon Generation ◽

Hydrocarbon Accumulation ◽

Southeastern Part ◽

Petroleum Generation

The Lishui Sag is located in the southeastern part of the Taibei Depression, in the East China Sea basin, where the sag is the major hydrocarbon accumulation zone. A three dimensional modelling approach was used to estimate the mass of petroleum generation and accumulated during the evolution of the basin. Calibration of the model, based on measured maturity (vitrinite reflectance) and borehole temperatures, took into consideration two main periods of erosion events: a late Cretaceous to early Paleocene event, and an Oligocene erosion event. The maturation histories of the main source rock formations were reconstructed and show that the peak maturities have been reached in the west central part of the basin. Our study included source rock analysis, measurement of fluid inclusion homogenization temperatures, and basin history modelling to define the source rock properties, the thermal evolution and hydrocarbon generation history, and possible hydrocarbon accumulation processes in the Lishui Sag. The study found that the main hydrocarbon source for the Lishui Sag are argillaceous source rocks in the Yueguifeng Formation. The hydrocarbon generation period lasted from 58 Ma to 32 Ma. The first period of hydrocarbon accumulation lasted from 51.8 Ma to 32 Ma, and the second period lasted from 23 Ma to the present. The accumulation zones mainly located in the structural high and lithologic-fault screened reservoir filling with the hydrocarbon migrated from the deep sag in the south west direction.

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Integration of the outcrop and subsurface geochemical data: implications for the hydrocarbon source rock evaluation in the Lower Indus Basin, Pakistan

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-018-0569-6 ◽

2018 ◽

Vol 9 (2) ◽

pp. 937-951 ◽

Cited By ~ 1

Author(s):

Sajjad Ahmad ◽

Faizan Ahmad ◽

Abd Ullah ◽

Muhammad Eisa ◽

Farman Ullah ◽

...

Keyword(s):

Organic Matter ◽

Source Rock ◽

Vitrinite Reflectance ◽

Indus Basin ◽

Hydrocarbon Generation ◽

Type Ii ◽

Hydrocarbon Source Rock ◽

Hydrocarbon Generation Potential ◽

Well Data

Abstract The present study details the hydrocarbon source rock geochemistry and organic petrography of the outcrop and subsurface samples of the Middle Jurassic Chiltan Formation and the Lower Cretaceous Sembar Formation from the Sann #1 well Central and Southern Indus Basin, Pakistan. The total organic carbon (TOC), Rock–Eval pyrolysis, vitrinite reflectance (Ro) % and Maceral analysis techniques were used and various geochemical plots were constructed to know the quality of source rock, type of kerogen, level of maturity and migration history of the hydrocarbons. The outcrop and Sann #1 well data on the Sembar Formation reveals poor, fair, good and very good quality of the TOC, type II–III kerogen, immature–mature organic matter and an indigenous hydrocarbon generation potential. The outcrop and Sann #1 well data on the Chiltan Formation show a poor–good quality of TOC, type II–III kerogen, immature–mature source rock quality and having an indigenous hydrocarbon generation potential. The vitrinite reflectance [Ro (%)] values and Maceral types [fluorescent amorphous organic matter, exinite, alginite and inertnite] demonstrate that maturity in both Sembar and the Chiltan formation at surface and subsurface fall in the oil and gas generation zone to cracking of oil to gas condensate zone. Recurrence of organic rich and poor intervals within the Sembar and Chiltan formation are controlled by the Late Jurassic thermal uplift preceding the Indo-Madagascar separation from the Afro-Arabian Plate and Early Cretaceous local transgressive–regressive cycles. From the current study, it is concluded that both Sembar and Chiltan formation can act as a potential hydrocarbon source rock in the study area.

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

Journal of Chemical Society of Nigeria ◽

10.46602/jcsn.v45i5.522 ◽

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

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

10.2118/afrc-2560967-ms ◽

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.

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Characteristics of the Overpressure Resulted from Hydrocarbon Generation

Applied Mechanics and Materials ◽

10.4028/www.scientific.net/amm.295-298.2707 ◽

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.

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HYDROCARBON PROSPECTIVITY OF THE DEEPWATER GIPPSLAND BASIN, VICTORIA, AUSTRALIA

The APPEA Journal ◽

10.1071/aj00005 ◽

2001 ◽

Vol 41 (1) ◽

pp. 91 ◽

Cited By ~ 5

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.

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Effects of igneous intrusions on source rock in the early diagenetic stage: A case study on Beipiao Formation in Jinyang Basin, Northeast China

Open Geosciences ◽

10.1515/geo-2020-0150 ◽

2020 ◽

Vol 12 (1) ◽

pp. 990-1002

Author(s):

Shouliang Sun ◽

Tao Zhang ◽

Yongfei Li ◽

Shuwang Chen ◽

Qiushi Sun

Keyword(s):

Source Rock ◽

Oil And Gas ◽

Thermal Evolution ◽

Vitrinite Reflectance ◽

Scientific Basis ◽

Source Rocks ◽

Temperature History ◽

Hydrocarbon Generation ◽

Intrusive Body ◽

Geochemical Parameters

AbstractMesozoic intrusive bodies play an important role in the temperature history and hydrocarbon maturation of the Jinyang Basin in northeastern China. The Beipiao Formation, which is the main source rock in Jinyang Basin, was intruded by numerous igneous bodies and dykes in many areas. The effects of igneous intrusive bodies on thermal evolution and hydrocarbon generation and migration in the Beipiao Formation were investigated. A series of samples from the outcrop near the intrusive body were analyzed for vitrinite reflectance (R0%) and other organic geochemical parameters to evaluate the lateral extension of the thermal aureole. The R0 values of the samples increase from a background value of ∼0.9% at a distance above 200 m from the intrusive body to more than 2.0% at the vicinity of the contact zone. The width of the altered zone is equal to the thickness of the intrusive body outcropped in the field. Organic geochemical proxies also indicate the intrusive body plays a positive and beneficial role in the formation of regional oil and gas resources. Due to the influence of the anomalous heat from the intrusive body, the hydrocarbon conversion rate of the source rocks of the Beipiao Formation was significantly improved. The accumulation properties and the storage capacity of the shales also greatly improved due to the intrusive body as indicated by the free hydrocarbon migration in the shales. This new understanding not only provides a reliable scientific basis for the accurate assessment of oil and gas genesis and resources in the Jinyang Basin but also provides guidance and reference for oil and gas exploration in the similar type of basin.

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Hydrocarbon Source Rock Potential of the Lacustrine Black Shale Unit, Mamfe Basin, Cameroon, West Africa

Earth Science Research ◽

10.5539/esr.v5n2p217 ◽

2016 ◽

Vol 5 (2) ◽

pp. 217 ◽

Cited By ~ 3

Author(s):

NJOH Olivier Anoh ◽

NJIE Sarah Mesanga

Keyword(s):

Organic Matter ◽

Source Rock ◽

Black Shale ◽

Oil And Gas ◽

Vitrinite Reflectance ◽

Hydrocarbon Exploration ◽

Hydrocarbon Source Rock ◽

Sedimentary Fill ◽

Kerogen Pyrolysis ◽

Rock Eval

The potential for conventional and/or unconventional hydrocarbon exploration requires the presence of organic-rich, thermally mature rock units containing oil or gas-prone kerogen. Thick black, organic rich shale intervals are well exposed along roadside cuts and river banks at several localities in the eastern part of the Mamfe Basin. Earlier described as anoxic lake bottom deposits, these fine grained rocks constitute the probable pod of active source rock in this basin and belonging to the middle stratigraphic unit of the three that make up the basin’s sedimentary fill. Samples collected from representative outcrop sections (Etoko mile 21, Bachuo Ntai, and Satom Bridge) in the study area were subjected to geochemical analytic techniques; Total Organic Carbon (TOC), Rock-Eval Pyrolysis and Vitrinite reflectance (%Ro) values were calculated. TOC data obtained range from 1.06% to 16.10% indicating good to excellent hydrocarbon generative potentials, Rock-Eval Pyrolysis data plotted along Kerogen Types I, II and III with oil and gas generative potentials. 4 out of 9 samples fall within the oil window from the calculated %Ro while temperatures corresponding to the peak of kerogen pyrolysis (Tmax) and Production Index (PI) for the 9 samples range from 398oC to 463oC indicating that the organic matter (OM) are immature to post mature.The black shale unit of this part of the basin therefore contains very high amounts of good to excellent quality of thermally matured organic matter which can produce and expel oil and gas respectively.

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A coal petrographic source rock evalution of the Rhaetic - Jurassic - Lower Cretaceous sediments of the B0rglum 1 and Uglev 1 wells, Denmark

Bulletin of the Geological Society of Denmark ◽

10.37570/bgsd-1984-33-22 ◽

1985 ◽

Vol 33 ◽

pp. 239-252

Author(s):

Birthe J. Schmidt

Keyword(s):

Organic Matter ◽

Source Rock ◽

Lower Cretaceous ◽

Plant Material ◽

Vitrinite Reflectance ◽

Border Zone ◽

Salt Diapir ◽

Organic Carbon Content ◽

Hydrocarbon Generation ◽

Hydrocarbon Source Rock

The Rhaetic - Jurassic - Lower Cretaceous sediments from the Børglum 1 and Uglev 1 wells have been investigated by coal petrographical methods to evaluate their hydrocarbon source rock potential. The methods include vitrinite reflectance analyses of maturity, optical qualitative rating of the composition of the dispersed organic matter in the sediments, along with an estimation of the total organic carbon content of the sediments. The composition of the sedimentary organic matter is highly influenced by the palaeogeographic conditions. In the Børglum 1 well the organic material is dominated by land-derived (mainly gas-prone) plant matter; this is also the case for the marine sediments due to introduction of plant material from the adjacent Fennoscandian Border Zone. The sediments in Uglev 1 also have a high content of terrestrial plant material, although there is more marine dominated (oil-prone) organic matter in the deposits of the Bream Formation. The most promising conditions tor generation of liquid hydrocarbons have been found in the Bream Formation in Uglev 1, but the investigated sediments are generally thermally immature, with a restricted potential tor hydrocarbon generation. The rank gradient for Uglev 1 (0.20 % Ro/km), which is situated over a deep-seated salt diapir is more than three times that of Børglum 1 (0.06 % Ro/km), which is placed more marginally in the Danish Subbasin. This is attributed to differences in the geothermal gradients (Børglum 1:19°C/km, Uglev 1: 32 and 37°C/km, uncorrected)

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Clay Minerals and Organic Matter from Deeply Buried Ordovician-Silurian Shale in Western Iraq: Implications for Maturity and Hydrocarbon Generation

Iraqi Journal of Science ◽

10.24996/ijs.2020.61.11.23 ◽

2020 ◽

pp. 3006-3023

Author(s):

Ali I. Al-Juboury ◽

Mohammed A. Al-Haj ◽

Adrian Hutton ◽

Brian Jones

Keyword(s):

Organic Matter ◽

Clay Minerals ◽

Mixed Layer ◽

Oil And Gas ◽

Vitrinite Reflectance ◽

Hydrocarbon Generation ◽

X Ray Diffraction ◽

Gas Generation ◽

X Ray ◽

Organic Mineral

The present work is conducted on the Paleozoic (Ordovician) Khabour and the (Silurian) Akkas shales in the Akkas-1 well of western Iraq. The study is aiming to determine the implications of clay mineral transformation, organic mineral distribution and maturity of hydrocarbon generation, using X-ray diffraction (XRD), scanning electron microscopy (SEM) in addition to organic matter concentrations. In the shale of the Khabour Formation, amorphous organic matter is common and includes various Tasmanite-type organic matter, vitrinite, inertinite, and bituminite. The main clay minerals observed include illite, chlorite, kaolinite, in addition to mixed-layer illite-smectite and rare smectite. In Silurian shale, high content of organic matter is recorded in addition to abundant vitrinite and low content of grainy organic matter (Tasmanites) and pyrite. Illite and kaolinite are commonly found in addition to chlorite and illite-smectite clay minerals. Conversion of smectite to mixed-layer illite-smectite (I-S) and an increase in vitrinite reflectance are commonly observed below 2500 m depth in the studied formations, which coincides with oil and gas generation. These results could be used as an indication of higher maturity and hydrocarbon generation in the deeply buried shale of the Khabour and Akkas formations in western Iraq.

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