Potential Hydrocarbon Source Rocks Research Articles

A new method to quantify the source contribution of mixed biodegraded oil based on pareto-optimized nonnegative matrix factorization and chord diagram visualization

The biogenic information of different components in crude oils with varying degrees of biodegradation is partially obscured, making traditional molecular indicators ineffective in determining the contributions of mixed sources. Previous studies have mainly focused on calculating mixed source proportion for normal oils, with few investigations involving biodegraded mixed oils. Developing a quantitative method for the mixed source contribution of biodegraded oils using machine learning (ML) algorithms is a significant attempt both to the exploration practice and theoretical progress. Taking the biomarker parameters resistant to biodegradation of 150 oil samples as input datasets, a new method called Pareto-Optimized NMF (PONMF) was proposed in this study, which combines multi-objective optimization (Pareto optimization) with non-negative matrix factorization (NMF) to analyze the relationship between biodegraded oils in the absence of source rock samples or original end-member (EM) oils while satisfying non-negativity constraints and additional constraint conditions. This method decomposes the matrix of crude oil samples into multiple end-members, each representing a possible input from a hydrocarbon source rock. Analysis of the end-member characteristics facilitates the deduction of potential hydrocarbon source layers and the traits of their depositional environments. This examination is supported by data derived from 15 prospective hydrocarbon source rock samples, which were employed to ascertain the actual geological significance of the end-members. The chord diagram depicts the visualization results of the overall relative contribution of source rock end members to crude oil in each area after the PONMF calculation results. The relative contribution of source rocks in different areas to the investigated crude oil samples is proportionate, and the arc length can reflect the contribution of the three sets of source rocks to a certain area. The findings indicate that the oils extracted from the stratified reservoirs in Eastern Chepaizi are primarily derived from the Permian source strata within the Shawan Depression, with a significant contribution ranging from 30% to 90% (EM2), and a lesser extent from the Carboniferous sources, contributing between 5% and 30% (EM1). Conversely, the provenance of oil in Western Chepaizi is overwhelmingly attributed to the Jurassic source interval located in the Sikeshu Depression, where EM3 accounts for over 85% of the source. Meanwhile, the oils in the Central Zone exhibit a composite origin, intermingling contributions from both EM1 and EM3. The advantage of this method is that it does not require direct access to hydrocarbon source rock samples or end-member oils but infers potential hydrocarbon source layers through the existing mixed-source oil samples. The PONMF method provides an effective tool for identifying the sources of biodegraded oils and can be used to study potential hydrocarbon source rock analysis for oils that have undergone biodegradation after hydrocarbon accumulation.

A comprehensive petrochemical study of coals of Jaintia Hills: unveiling their industrial applicability and potential as hydrocarbon source rocks

ABSTRACT The current investigation aims to classify Jaintia Hill coals into different types, ranks, and grades based on their geochemical and petrographic characteristics and to evaluate the potential utilization of these coals under the framework of different coal classification schemes, essential for various industrial, commercial, and residential applications. During the present study, representative coal samples were collected from the working coal mines of Khliehriat and Lad Rymbai areas of the East Jaintia hills of Meghalaya, India, and subjected to proximate analysis, ultimate analysis, and micro petrographic study. Using international and Indian classification schemes, an attempt has been made to propose the appropriate utilization of these coals. It has been observed that these coals have high vitrinite content and low ash content but have high sulfur content. The petrographic and geochemical data suggest that these coals can be utilized for gasification, hydrogenation, and as a coal blend for metallurgical coke-making in the steel industries. The coal samples were also investigated from the perspective of hydrocarbon source rock potential, and it was concluded that these coals have good source rock potential for gas and liquid hydrocarbon.

Source and geological significance of Jurassic asphalt in the Ruoqiang Sag of Southeast Depression, Tarim Basin, Northwestern China

The Southeast Depression of the Tarim Basin has a very low petroleum exploration degree, and currently, no industrial oil and gas have been discovered. Many hydrocarbon shows exist in the Ruoqiang Sag, where hydrocarbon sources and accumulation processes are unclear. Only two potential Jurassic hydrocarbon source rocks developed in the Ruoqiang Sag, the Yangye (J2y) lacustrine mudstone of the Middle Jurassic and the Kangsu (J1k) coal-bearing mudstone of the Lower Jurassic. In this study, the Jurassic asphalt found in the QD1 well, combined with the source rocks of drilling cores and outcrops, was used to explore the possible hydrocarbon source and forming process in the Ruoqiang Sag using oil-source correlation and hydrocarbon accumulation geochronology methods. The asphalts have lower light and heavy rare earth fractionation than the J2y mudstone, and the total rare earth element (ΣREE) content, chondrite-normalized curves, and δEu and Y/Ho values are similar to those of the J1k mudstone, especially for the J1k coal. The n-alkane ratios of the carbon preference index and the odd-to-even preference (OEP) of Jurassic asphalts are greater than 1.0, indicating that its source rock has experienced low thermal evolution. All Jurassic samples have similar source-related biomarkers but different maturity-related parameters, and the thermal evolution degree of asphalt is close to the J1k mudstone and coal but slightly higher than the J2y mudstone. Meanwhile, rhenium–osmium isotopes show the asphalts are formed in 192+30/−45 Ma, which is similar to the J1k sedimentation time. The asphalts contain coal macerals and probably derived from the asphaltene precipitated by the J1k coal during the early coalification. The low abundance of 25-norbornanes with a non- or slight petroleum biodegradation degree indicates the asphalt was generated relatively late and migrated into the J2y formation along the faults, possibly accompanied by the striking activities of the Altyn Tagh Fault during the Neotectonics movement. This study provides evidence for the J1k coal-bearing strata serving as the effective source rock in the Ruoqiang Sag and increases confidence for Jurassic petroleum exploration in the Southeast Depression of the Tarim Basin. The structural and lithological traps near hydrocarbon source stoves, where Jurassic strata were deeply buried and far from the Altyn Tagh Range, are favorable oil and gas exploration targets.

Litho- and biostratigraphy and hydrocarbon source-rock potential of the Jurassic–Paleogene strata in the Kala Chitta Range, northwestern Himalayas, Pakistan

In this study Jurassic–Paleogene strata were investigated to understand the litho- and biostratigraphic framework and hydrocarbon source-rock potential of various stratal packages. Biostratigraphic controls were used to establish the chronostratigraphic framework of Jurassic–Paleogene strata in the area. The Lower Jurassic (Hettangian) clastics saw an unconformity during the Sinemurian–Pliensbachian, while the Lower Jurassic (Toarcian)–Middle Jurassic (Bajocian) clastic–carbonate mixed strata is also separated by a Bathonian unconformity from the Middle Jurassic (Callovian) to the Upper Jurassic (Tithonian) carbonate sequence. The Upper Jurassic Oxfordian strata are missing, while the Upper Jurassic (Kimmeridgian)–Lower Cretaceous (Valanginian) glauconitic sandstone and clays are the conformable sequences. The Lower Cretaceous (Hauterivian)–Upper Cretaceous (Turonian) clastics is a conformable sequence that is separated by a Coniacian–Santonian unconformity from the Upper Cretaceous (Campanian) pelagic carbonates. The Cretaceous–Tertiary boundary is marked by laterites, while the Paleocene (Thanetian) sequence is represented by a shale- and sandstone-dominated sequence. The Paleocene (Thanetian)–Early Eocene (Ilerdian) siliciclastic–carbonate mixed sequence marks the last episode of Tethyan sedimentation. Total organic content (TOC), organic petrography and Rock-Eval pyrolysis (REP) techniques were used to evaluate the hydrocarbon source-rock potential, kerogen type and level of maturity of the hydrocarbons. The majority of studied samples show the occurrence of type IV kerogen. However, the Middle Jurassic (Callovian)–Upper Jurassic (Tithonian) carbonate sequence of the Samana Suk Formation, the Kimmeridgian–Valanginian Chichali Formation, the Paleocene (Thanetian) sequence of the Hangu Formation and the Paleocene (Thanetian)–Early Eocene (Ilerdian) Patala Formation confirms the Type III kerogen, poor–fair source-rock quality, immature–mature, gas- and oil-prone indigenous hydrocarbon occurrence in the region.

Organic geochemical, petrographic and palynological characterization of claystones of the Palaeogene Toraja Formation, and oil seeps in the Enrekang Sub-basin, south Sulawesi, Indonesia: Implications for hydrocarbon source rock potential

An organic geochemical, petrographical, and palynological evaluation was conducted on 30 claystone outcrop samples of the Toraja Formation, along with a geochemical analysis of an oil seep in the Enrekang Sub-basin. The aim of the study was to determine the correlation between oil and source rock in terms of age, depositional environment, organic material sources, and maturity level. The total organic carbon content of the claystone samples varies from 0.03 to 4.52 wt%, which are classified as poor to excellent. The claystones are immature to post-mature with a mixture of Type Ⅱ and Ⅲ kerogen. Their vitrinite reflectance values range from 0.47 to 4.52 %Ro. The samples of Toraja Formation rock and the oil seep source rock might have a similar depositional environment, a deltaic marine depositional setting with high oxidizing conditions. Organic material sources for rock and oil samples are dominated by terrestrial input. The oil is inferred to have originated from the Paleogene source rocks, which correlates in age with the Toraja Formation. The recovered palynomorphs from the studied rock samples suggest a late Eocene to Oligocene age with a strong terrestrial influence of shallow marine depositional setting. The biomarker analysis shows that the rock samples have a more substantial contribution from the terrigenous higher plants, while the oil sample indicates a higher degree of marine influence. The maturity levels are also different between the oil (peak mature) and the analyzed rock samples (immature). It is inferred that the oil seep source rock is equivalent to the analyzed rock sample but more mature, having been deposited under more marine conditions. The oil seep source rock is not exposed and is located in the deeper part of the basin. A deeper marine facies (i.e. distal delta front and prodelta facies) in front of the distributary mouth bar within a delta is interpreted as the source rock of the oil seep sample.

Petrographic and geochemical analysis of Barmer Basin Paleogene lignite deposits: Insights into depositional environment and paleo-climate

The current study attempts to characterize the samples from Kapurdi, Giral and Sonari lignite mines of Barmer Basin within Rajasthan Tertiary Lignite deposits using petrographic and geochemical techniques. The data generated has been studied in order to better understand the geochemical properties, hydrocarbon potential, depositional environment and paleo-climatic condition of the paleo-mires of these lignites. The proximate analysis of the samples reveals that the average ash content of the Barmer Basin is 11.93 %, the average moisture content is 14.08 %, average volatile matter yield is 42.03 % and the average fixed carbon is 31.95 %, which suggesting that the physical properties of lignite are dominated by volatile matter on dry basis. The ultimate investigation reveals the chemical properties of the lignite with the average carbon content found to be 58.79 wt%, hydrogen value 3.83 wt%, nitrogen percentage 1.60 wt% and sulphur content 2.75 wt%. This clearly indicates high sulphur concentration in Barmer lignite deposits, based on dry basis. The lignite samples subjected to FTIR studies identified aliphatic CH group, aromatic CO group, hydroxyl OH and Aldehyde HCO group. The Rock-Eval pyrolysis studies have been carried out to know the coalification profile of the deposits and hydrocarbon source rock potential. The varying behaviour between brown coal lithotype are primarily reflected by changes in oxygen index values, whereas hydrogen index values demonstrate a more pronounced correlation with coal type rather than the level of maturation. The results show the average total organic carbon (TOC) 47.29 %, S1 peak 2.18 mg HC/g, S2 peak 88.70 mg HC/g, S3 peak 19.22 % mg CO2/g, Tmax 410.53 °C, hydrogen index 219.2 mg HC/g TOC and oxygen index 46.33 mg CO2/g TOC. According to petrographic investigations, the huminite macerals dominate followed by liptinite and inertinite maceral groups in mineral matter-free basis. In all the three different lignite mines, the huminite group dominates with preserved sub-maceral ulminite indicating less transformation of structured plant matter. Reconstruction of depositional environment and paleo-climatic condition of the paleo-mires has been attempted by using organic petrographic indices. The high gelification index (GI) and low tissue preservation index (TPI) values suggest a prolonged wet environment during the decomposition of organic material, accompanied by a gradual subsidence process. The ground water influence index (GWI) and vegetation index (VI) denote ombrotrophic to mesotrophic hydrological conditions of basin at the time of deposition.

The transition from hydrothermal oxic conditions to restricted euxinia in the lower cambrian yurtus formation black shale, Tarim Basin

The Yurtus Formation is generally believed as one of the most potential hydrocarbon source rocks under the Cambrian gypsum-salt bed in the Tarim Basin of China. This formation exhibits unique geochemical characteristics during the Ediacaran-Cambrian transition period. In this study, we investigated the lower and upper black shales from the Yurtus Formation for the high-resolution geochemical analysis in order to further characterize the prevailing redox conditions and sedimentary mechanisms involved in the organic matter accumulation process. During the deposition of the lower black shale with high TOC in Unit2, the high concentrations of phosphorite and barite, and the REE geochemistry manifested a mixture of hydrothermal fluid and seawater. Through in-situ laser ablation–inductively coupled plasma–mass spectrometry (LA-ICP-MS), we explored the element distribution of the drill-core-preserved phosphate nodule, indicating that the phosphogenesis may be related to the involvement of bacteria activities under intermittently oxic bottom waters or consistently free oxygen conditions. Biomarker evidence by the identification of green sulfur bacteria demonstrated the occurrence of photic zone euxinia (PZE), and the trace metal patterns revealed intermittently bottom water oxygenation and stratified ocean which was consistent with the scenario of phosphate nodule formation. In contrast, the upper black shale with relatively low TOC was characterized by a detrital input, with significantly decreasing redox-sensitive trace mental enrichment (UEF, MoEF, VEF) and positive excursion of carbon isotopes, as well as a positive relationship between ∑REE and Al. The present study provides more explicit insights into not only the sedimentary mechanism of the black shale, but also the evolution of the Earth system at the key interval of the early Cambrian.

Lithofacies and depositional settings of Mesoproterozoic shales: Insights from the ∼1.65 Ga Chuanlinggou Formation, Yanliao Basin, North China Craton

Precambrian black shale has become a significant trend in petroleum exploration, and the Chuanlinggou Formation is the oldest potential hydrocarbon source rock deposit in the North China Craton. The Mesoproterozoic was a unique transitional stage in the evolution of the environment and life in Earth's history. Research on lithofacies and depositional settings in this stage has important scientific and oil and gas exploration significance. Outcrop observations, thin sections, and elemental and organic geochemical analyses were used to study the mineralogy, sedimentary structures, lithofacies assemblages and their relationships with the depositional environment. Three endmembers (silicate, carbonate and clay minerals) based on X-ray fluorescence were employed to establish the lithofacies classification suitable for the Chuanlinggou Formation in the Yanliao Basin. The lithofacies of the Chuanlinggou Formation were classified into six types, including calcareous mudstone, siliceous/calcareous mixed mudstone, argillaceous/siliceous mixed mudstone, silicate-rich argillaceous mudstone, clay-rich siliceous mudstone and siliceous mudstone. Four lithofacies assemblages (LAs) were identified according to the integrated lithofacies analysis from the bottom to the top of the section. Lithofacies assemblages 1 and 2 (LA1 and LA2), which were deposited in deep subtidal to shelf environments, have high petroleum potentials and are advantageous lithofacies assemblages for organic matter accumulation. The black shale developed early rift may not be as favorable as in the late rift, while the siliceous shale developed in the continental shelf-slope is a favorable lithofacies. A comprehensive cognition of the LA and depositional settings of the Chuanlinggou Formation might provide guidance for further petroleum exploration and sedimentary environments in the Mesoproterozoic.

Geochemical characteristics and organic matter enrichment of the lower cretaceous dolomite-rich interval in the Bayindulan sag, Erlian basin, northern China

A dolomite-rich interval was found in the Lower Cretaceous, Bayindulan Sag. Based on organic and inorganic geochemical data, the hydrocarbon source rock potential of this dolomite-rich interval and the factors that control organic matter enrichment were investigated. This dolomite-rich interval has TOC values ranging from 0.54% to 9.64% (average = 3.51%) and HI values varying from 263 to 974 mg HC/g TOC, suggesting good to excellent source rocks whose organic matter is dominated by type I/II1 kerogens. The dominance of short-chain and medium-chain n-alkanes (n-C16 to n-C23) in the n-alkane distribution of the extracted organic matters in the dolomite-rich interval implies that the planktonic organic matters acted as the dominant inputs for the dolomite-rich interval, with a minor contribution from higher plants. The low Pr/Ph values suggest a strongly reducing environment favoring the preservation of organic matters. The high amount of gammacerane indicates water stratification during deposition time, which also helps to maintain the strongly reducing conditions in the bottom water. Meanwhile, REE and trace elements indicate that the dolomite-rich interval is closely related to the exhalative hydrothermal events, and the upwelling hydrothermal fluids provided abundant nutrients into lake water, resulting in the bloom of aquatic organisms. Overall, the strongly reducing depositional environments, the strong stratified-waterbody and the hydrothermal fluids jointly control the organic matter enrichment in the dolomitic interval.

Seismic Sedimentologic Study on Sequence-Sediment Evolution in Fault Basin Regions

With potential hydrocarbon source rocks, the Mesozoic Lower Cretaceous interval in the Aitegle Sag of the Yingen-Ejinaqi Basin in China has a bright petroleum exploration prospect. Considering the scarcity of wells in Aitegle Sag, we have systematically carried out the research on the sequence structure and sedimentary system evolution of the Lower Cretaceous based on seismic, core, and logging data, guided by the Vail classic sequence stratigraphy, and innovatively introduced the self-organizing mapping neural network (SOM) learning algorithm to assist in seismic geological analysis. The results are as follows: (1) after RMSAmp, LyapIndex, FrctDim, and InfoEntr clustering, five zones are divided, which are corresponding to five seismic facies (showing medium-strong amplitude and parallel-subparallel reflection; medium-strong amplitude and wedge-shaped divergent reflection; medium-strong amplitude and continuous-relatively continuous, parallel-subparallel reflection; strong amplitude and continuous sheet-like or blank reflection; and weak amplitude and mound-shaped chaotic reflection, respectively), and interpreted as five subfacies including delta plain front, prodelta-shallow lake, semideep lake, deep lake, and sublacustrine fan. (2) The Lower Cretaceous formation includes one second-order sequence, three third-order sequences (SQ2–SQ4), and six system tracts. In the SQ2–SQ4 circle, the delta system formed by sediments from southeast varies remarkably in the progradational zones in different system tracts, and tectonic movements and sediment supply control the sequence stratigraphy in the study area as major factors. (3) It is feasible to apply SOM learning algorithm to seismic attribute clustering analysis. This method effectively realizes the combination of geophysical methods based on big data analysis and geological problem analysis, which not only strengthens the use of seismic data but also ensures the effectiveness and reliability of clustering results. These findings offer basic data and scientific supports for the exploration and development of unconventional reservoirs (e.g., shale and tight oil/gas reservoirs) in the Aitegle Sag and also provide new ideas for studying the sequence-sediment in the target zones in the fault basin regions with scarce wells.

Hydrocarbon indication in Rio Bonito Formation sandstone: Implication for CO2 storage in São Paulo, Brazil

São Paulo State has witnessed CO2 storage-based investigations considering the availability of suitable geologic structures and proximity to primary CO2 source sinks related to bioenergy and carbon capture and storage (BECCS) activities. The current study presents the hydrocarbon viability evaluations and CO2 storage prospects, focusing on the sandstone units of the Rio Bonito Formation. The objective is to apply petrophysical evaluations with geochemical inputs in predicting future hydrocarbon (gas) production to boost CO2 storage within the study location. The study used data from eleven wells with associated wire-line logs (gamma ray, resistivity, density, neutron, and sonic) to predict potential hydrocarbon accumulation and fluid mobility in the investigated area. Rock samples (shale and carbonate) obtained from depths >200 m within the study location have shown bitumen presence. Organic geochemistry data of the Rio Bonito Formation shale beds suggest they are potential hydrocarbon source rocks and could have contributed to the gas accumulations within the sandstone units. Some drilled well data, e.g., CB-1-SP and TI-1-SP, show hydrocarbon (gas) presence based on the typical resistivity and the combined neutron-density responses at depths up to 3400 m, indicating the possibility of other hydrocarbon members apart from the heavy oil (bitumen) observed from the near-surface rocks samples. From the three-dimensional (3-D) model, the free fluid indicator (FFI) is more significant towards the southwest and southeast of the area with deeper depths of occurrence, indicating portions with reasonable hydrocarbon recovery rates and good prospects for CO2 injection, circulation and permanent storage. However, future studies based on contemporary datasets are required to establish the hydrocarbon viability further, foster gas production events, and enhance CO2 storage possibilities within the region.

Geochemistry and Potential Hydrocarbon Source Rocks of Rambatan Formation in Karangkobar Area, Central Java

The purpose of the study in the Karangkobar area was to investigate the source rock potential of the fine-grained surface samples of clastic sediments. The use of surface samples for source rock potential study in Indonesia is still limited. We conducted geochemical laboratory analyses in this research, including Total Organic Carbon (TOC), Rock-Eval Pyrolysis (REP), and Gas chromatography–mass spectrometry (GCMS). Seventeen samples have been analyzed for their TOC content. The result shows that TOC values varied between 0.36–1.55%, indicating that the source rock potential level based on the surface samples is poor to fair organic richness. REP was conducted on 16 samples, and the results show that the hydrocarbon-generating characteristics (HI values) ranged from 15 to 163 mg HC/g TOC. The kerogens identified included type II and III kerogen, which indicated the oil and gas-generating potential. Pyrolysis temperature is at maximum (Tmax) in the 276–458 °C, indicating that the samples were thermally immature to mature. GCMS analysis of source rock indicated that the depositional environment of the organic material derived from an open marine and plankton environment. This study is essential to complete the understanding of the petroleum system in Central Java.

Preliminary source rock evaluation, paleo-depositional environment and hydrocarbon generation potential of the cretaceous organic-rich outcrops of Mayo-Figuil River, Babouri-Figuil Basin, Northern Benue Trough (Yola arm) Cameroon: Insights from bulk geochemistry

Babouri-Figuil sedimentary basin is considered the most northerly and one of the most attractive intracontinental Cretaceous basins in North Cameroon, which contains organic-rich deposits presumed to be oil shale levels. The fieldwork carried out as part of this study enabled to delineate six lithological units mainly consisting of black shales, marls, orange clay, black to grey clays and limestones. Twenty-two samples from the studied section were subjected to bulk organic (Rock Eval pyrolysis) and inorganic (biophiles XRF-trace element) geochemistry to investigate their hydrocarbon generation potential. Field data and organic geochemical analysis of organic matter reveal that three of the six lithological units are potential hydrocarbon source rocks; these are units 1 (1.50 ≤ TOC ≤3.98%), 2 (0.47 ≤ TOC ≤1.17%) and 4 (TOC = 24.74%) consisting mainly of black to grey clays and black shales. These source rocks are discontinuously distributed throughout the studied section with a cumulative stratigraphic thickness of 275 cm. The organic matter contained in unit 1 is mainly Type II/III (182 ≤ HI ≤ 382 mg HC/g TOC) with a significant contribution in Type II kerogen. It is mature (443 °C ≤ Tmax ≤448 °C) at the base (MF-1, -2, -3 and -4) and immature (Tmax = 416 °C < 435 °C) at the top (MF-5). Unit 2 contains early-mature type III organic matter (98 ≤ HI ≤ 155 mg HC/g TOC; 438–439 °C). Organic matter in unit 4 is also early-mature and has generated mainly oil (Type I or IIS). The combination of proxies of biophile trace elements (cross plots Ni/Co vs. V/Ni and V vs. Ni) indicates that this organic matter is of mixed source, both marine and terrestrial origin, deposited under oxic-dysoxic conditions. Thus, subject to further geochemical analyses and given the pessimistic predictions from outcrop samples, these units are conventional effective source rocks in place of the early reported immature oil shale levels.

Integrated organic geochemical/petrographic and well logging analyses to evaluate the hydrocarbon source rock potential of the Middle Jurassic upper Khatatba Formation in Matruh Basin, northwestern Egypt

The present national and international pursuit of converting Egypt into a regional hub of natural gas in the East Mediterranean region resulted in conducting extensive exploration activities in several areas of northern Egypt. Therefore, organic petrographic, geochemical, and geophysical analyses were carried out on the upper Khatatba Formation from the OBA 2-2A well in the Matruh Basin.Restoration of the original sedimentological and geochemical characteristics of the upper Khatatba Formation suggest deposition of this formation in deltaic settings. Few shale and partly calcareous shale units of the Upper Safa and the uppermost Zahra members accumulated in TST in prodelta settings under dysoxic-anoxic conditions. These shale units had an original gas/oil-prone organic facies BC. Other shales and partly calcareous shales of the Upper Safa and Zahra members accumulated in HST in deltafront settings under relatively oxic conditions and had an original lower gas-prone organic facies C.The Upper Safa Member had an original active fair to excellent organic richness (0.76–7.35, avg. 3.38 TOCo(live) wt%) and hydrocarbon source rock potential (S2o: 2.22–17.97, avg. 8.05 mg HC/g org. C). It was characterised mainly by original active mixed gas/oil-prone kerogen type IIIo(live)-IIo(live) (HIo(live): 200.27–297.34, avg. 238.03 mg HC/g TOCo(live)) and subordinately by gas-prone kerogen type IIIo(live) (HIo(live): 181.50 mg HC/g TOCo(live)). The Upper Safa Member had original poor to fair proportions of active oil-prone (0.15–1.47, avg 0.68 TOCo(live, oil) wt%) and higher fair to very good proportions of active gas-prone (0.61–5.88, avg. 2.70 TOCo(live, gas) wt%) kerogens. The Upper Safa Member originally possessed poor to very good oil (S2o(oil): 0.44–3.59, avg. 1.16 mg HC/g org. C) and good to very good gas (S2o(gas): 1.77–14.37, avg. 6.44 mg HC/g org. C) generation potential. The carbonates and partly calcareous shales of the uppermost Safa and the Zahra members possessed poor oil and gas generation potential due to their organic-lean status.The present-day organic geochemical characterization indicates that the Upper Safa Member still shows active fair to excellent organic richness (0.68–6.75, avg. 3.11 TOCpd(live) wt%). However, this member shows a relatively lower present-day good to very good/excellent source rock potential (S2pd: 1.33–10.78, avg. 4.83 mg HC/g rock) and lower active kerogen quality IIIpd(live) (HIpd(live): 115.97–198.21, avg. 151.07 mg HC/g TOCpd(live)). This is related to the current high thermal maturation (gas-window: Tmax: 459–468, avg. 469 °C, thermal alteration index: TAI of 4-) and conversion of the original kerogen IIIo(live)-IIo(live) into oil and gas. The present-day high organic richness, high remaining generative potential, high shale volume of the thermally mature gas-prone kerogen, classify the Upper Safa Member as an active fair to excellent shale gas play in the Matruh Basin. Intrabasinal and interbasinal correlations across northwestern Egypt indicate that the upper Khatatba Formation shows locally and regionally dual source and reservoir rock characteristics due to the lateral facies changes.

Integrated Magnetotelluric (MT), Gravity and Seismic Study of Lower Kutai Basin Configuration

This work describes a subsurface basin configuration of the Lower Kutai Basin (hereinafter LKB) in East Kalimantan, Indonesia, as inferred from combination of magnetotelluric (MT), seismic, and gravity data. LKB is structurally controlled mainly by the Samarinda Anticlinorium extending in a NNE-SSW direction and is one of the most prolific hydrocarbon basins in Indonesia. The phase tensor analysis of MT data from most stations and frequencies exhibited a 2D character with a relatively low skew (-3° &lt; β &lt; 3°). The geo-electrical strike direction was estimated at N30°E, which is in good agreement with the regional geological strike with a NNE-SSW direction. 2D MT inversion modeling was performed to infer the subsurface resistivity distribution associated with LKB’s configuration. From the integration of MT, seismic and gravity models it was shown that LKB’s configuration is composed mainly of sandstone, black shale, claystone, and basement rocks. The conductive zones of the MT models are associated with thermal alteration of black shale, which changes its mineralization, leading to lower resistivity. Hence, the black shale may be interpreted as potential hydrocarbon source rock in LKB.

Palynofacies Analysis of Selected Organic-rich Shales from Libyan Sahara: Implication to Palaeoenvironment and Hydrocarbon Source Rock Potential

Palynofacies analysis was carried out on three (3) packages of shale-cutting samples derived from a well drilled within Gadames Basin. These included: the upper package (Carboniferous at 5,530 ft), the middle package (Carboniferous/Devonian at 5,600 ft and 5,780 ft), and the lower package (Devonian at 6,700 ft). Two palynofacies were identified: "P-1", involving the upper and middle packages (Carboniferous/Devonian), and "P-2", involving the lower package (Devonian). P-1 and P-2 were considered to form one "palynofacies association" located at a mud-dominated oxic shelf (distal shelf) and are analogous to other palynofacies from other countries that are characterized by the dominance of terrestrial upon marine palynomorphs and moderate to low phytoclasts and AOM respectively that typically deposited within a shoreline zone (probably fluvial-deltaic source or marginal marine environment). Spore color index "SCI" evaluation for source rock and thermal maturation, in turn, indicates early mature oil/gas prone (kerogen type II&gt;III) to post mature kerogen type III&gt;IV "gas prone" for the studied cutting sample packages.

Hydrocarbon source rock potential and paleoecological studies of the Surma sediments of Manipur region, India: Insights from palynology and organic geochemistry

The palynological assemblages, organic content, Rock-Eval analysis and stable isotope ratios of three outcrop sections were studied of the Miocene Surma Group in Indo-Myanmar Range to characterize the lithology, and assess kerogen types. The well-preserved palynological assemblages from the ATF, AAN and AAS sections indicate a tropical-subtropical climate with humid conditions. The δ13C values of the organic matter in these sections ranges from −19.92 to −26.08 ‰, indicative of C3 vegetation. Among these sections, our data indicates ATF has the driest and AAN wettest climate. Results from Rock-Eval analysis suggests that all the rock samples have poor organic richness (TOC < 0.5 %) and poor hydrocarbon generation potential (S2 < 0.5 mgHC/g). The organic matter of these samples is mixture of Type III and Type IV. The Tmax and Productive Index values support the results of visual kerogen analysis suggesting immature with mature and contaminant zones. The Surma sediments are poor source of gaseous hydrocarbons based on the results of this work.

Geochemistry and hydrocarbon source rock potential of shales from the Palaeo-Mesoproterozoic Vindhyan Supergroup, central India

With increase in shale gas exploration, inorganic and organic geochemical investigations of shale have become extremely important. Here, we explore the six argillaceous (shale) intervals (Arangi, Koldaha, Rampur, Bijaygarh, Rewa and Sirbu shale) from Son valley sector, Vindhyan Basin with an aim to understand provenance conditions, palaeoclimate, tectonic setting and hydrocarbon generation potential. Whole rock geochemistry indicates Vindhyan sediments derived from felsic source(s) except for Sirbu shale that indicates additional influx of mafic rocks with differentiated felsic source. A comparative study of Vindhyan shale rare earth elements (REEs) points to Mahakoshals and Chhotanagpur gneissic complex (CGC) as probable sediment provenance for Vindhyan sediments. CIA analysis, after necessary corrections for K-metasomatism, suggests evolution in weathering and palaeoclimate indicating a transformation from moderate weathering conditions with warm and humid climate during lower Vindhyan deposition to intense weathering conditions with hot and humid climate during upper Vindhyan deposition. Trace (La/Y vs. Sc/Cr) and REE analysis indicates passive margin setting for Vindhyan sediments whereas a wide range spanning passive to active continental margin setting is also inferred using (Th-Sc-Zr/10) and (Th–La-Sc) ternary diagrams. However, these tectonic discriminant diagrams lack in explaining rift- or sag-related origin of any intracratonic basin such as the Vindhyan Basin. The total organic carbon (TOC) content in Vindhyan shales ranges from 0.29% to 8.44%. The thermally liberated hydrocarbon (S1) values range from 0.01 to 0.18 mg HC/g rock (milligram hydrocarbon per gram of rock sample), whereas hydrocarbon from cracking of the kerogen (S2) shows values ranging from 0.04 to 0.47 mg HC/g rock. Based on modified Van Krevelen correlation (HI vs. Tmax) diagram, organic matter from Arangi and Bijaygarh shales is characterized as thermally mature, Type III kerogen of gas prone character indicating good to very good gas generation potential.

The effect of oil-based drilling mud (OBM) on the assessment of hydrocarbon charge potential

Foundational to source rock assessment in exploration is an understanding of organic enrichment and hydrocarbon generation potential. With an increased use of oil-based drilling mud, particularly in deep water drilling, problems associated with contamination have complicated source rock assessment. Drilling fluid contamination is assumed to increase the apparent values of the basic screening source rock parameters such as total organic carbon (TOC) and total hydrocarbon generation (S1 + S2).It has been commonly assumed that the effect of contamination can be reduced or eliminated by pre-treating samples with organic solvents (i.e., extraction of the sample) prior to analysis. In this study, an attempt is made to characterize this extraction process on a suite of simulated cuttings samples that were contaminated and extracted prior to analysis to validate the assumptions presented in the literature.Results from these experiments show significant differences between values measured on the original and oil-based drilling fluid contaminated samples before and after extraction. After contamination and before extraction, measured TOC and Rock-Eval parameters indicate that the oil-based drilling fluids appear to be acting as an aggressive solvent, altering the apparent source rock potential. Contamination by oil-based drilling fluid appears to reduce the total organic carbon content and the residual generation (S2) potential, while increasing the free hydrocarbon content. This may be a result of the presence of solid bitumen or bituminite in the original sample, which are acted on by the oil-based drilling fluid. Following extraction of the contaminated samples, the TOC and residual generation potential undergo further reduction and the free hydrocarbons were nearly eliminated. It was also observed that uncontaminated samples, when extracted, experienced an increase in TOC and the S3 (CO2) peak. These increases may have resulted from the retention of small amounts of solvent.Unlike the common assumption in the existing literature, these data indicate that once oil-based drilling fluids contaminate a sample, pre-treatment extraction does not provide an accurate measure of either the original organic carbon or residual generation potential. The data indicate that the use of Rock-Eval pyrolysis results from extracted samples that have been contaminated by oil-based drilling fluid can result in a significant underestimation of the system's hydrocarbon source rock potential.

Evaluation of Hydrocarbon Source Rock Potential and Organic Geochemistry in North Arafura Shelf, Papua (Indonesia)

DOI:10.17014/ijog.8.3.401-416The results of this study identified two potential source rock intervals of Permian age in the North Arafura Shelf area of Papua, Indonesia. The first potential source rock interval (SR-1) was identified at 3834.9 m to 3838.6 m depth within the Kola-1 well, which is believed to be good to very good potential source rock with TOC in the range of 2.94 to 3.4 wt %, S1 0.78 to 0.97 mg HC/g, and S2 5.63 to 9.5 mg HC/g. The source rock is composed of type II and III kerogens with HI in the range of 164 to 275 mg HC/gTOC and reached the maturation stage with Ro of 0.83 - 0.86%, Tmax of 442 - 444 C, and Production Index (PI) of 0.09 - 0.12. The second potential source rock interval (SR-2) is at 3060.1 - 3136.3 m depth in the ASM-1X well and has fair potential to be source rock with TOC of 0.95 wt %, S1 of 1.01 mg HC/g, and S2 of 3.39 mg HC/g. This source rock has type II kerogen with a HI value of 357 mg HC/g TOC and has reached maturation as indicated by a Ro value of 0.63%, Tmax of 430 C, and PI of 0.23. Biomarker analysis revealed SR-1 is type III kerogen with terrigenous input and was deposited in an estuarine environment.