Petroleum Source Rock Potential Research Articles

Preliminary results of petroleum source rock evaluation of Mongolian Mesozoic oil shales

Jurassic and Cretaceous oil shale samples, collected from northern and central Mongolian basins, have been analyzed to determine their petroleum source rock potential. The contents of total organic carbon (TOC) and total sulfur, and source rock screening data were obtained by Rock-Eval pyrolysis. Cretaceous oil shales contain up to 17.4 wt.% TOC and Hydrogen Index (HI) values range from 638-957 mg HC/g TOC. Jurassic oil shale samples have similar TOC contents, ranging from 10.7 to 17.3 wt.%. HI values of Jurassic Tsagaan-Ovoo oil shale vary between 270-313 mg HC/g TOC. Average Tmax values of Cretaceous and Jurassic samples are 4370C and 4230C, respectively. This observed data indicates that both Jurassic and Cretaceous oil shales are excellent source rock. Cretaceous oil shales contain type I kerogen (highly oil prone), while Jurassic Tsagaan-Ovoo oil shale has mixed type II/III kerogen (mixed oil and gas prone). Based on Tmax and Production Index values, both Jurassic and Cretaceous oil shales are immature. Overall, the result of this study contributes organic geochemistry database of Mongolian oil shale and encourages source rock potential of both Jurassic and Cretaceous oil shale.

Characterization of Lower Cretaceous organic-rich shales from the Kom Ombo Basin, Egypt: Implications for conventional oil generation

• The shales of the Kom Ombo Formation are organic-rich sediments, with TOC value of up to 6.61 wt.%. • The organic facies are predominantly of Types II and II/III kerogen. • Kom Ombo shales were deposited in a marine under anoxic environmental conditions. • The shales reached peak oil-window and generated commercial amounts of oil. This study uses organic geochemical and petrographic analyses to characterise the organic-rich shales from the Lower Cretaceous Kom Ombo Formation in the Kom Ombo Basin. The overall results show that the Kom Ombo shales are considered to have good petroleum source rock potential with total organic carbon (TOC) content > 1 wt % and hydrocarbon yields of up to 27.62 mg hydrocarbons/g rock. Based on lipid biomarker ratios and carbon isotopes, the Kom Ombo shale contains a blend of organic matter derived primarily from algal marine and other aquatic organic matter, with some terrigenous land plants, deposited under anoxic conditions. These findings of organic matter (OM) input and depositional conditions are consistent with the high TOC content of up to 6.61 wt. % and mainly Types II and II/III kerogen, with small amounts of Type III kerogen, thus yielding both oil and gas, with oils of high to low wax contents. The geochemically determined dominance of oil generation potential is in agreement with the findings of considerable concentration of fluorescent liptinite macerals. The chemical and optical maturity results show that the majority of the examined Kom Ombo shale samples have entered the main stage of oil generation, exhibiting a range of early-mature to late-mature. Therefore, as highlighted in this study, the oil generation potential of the Kom Ombo shales may represent future conventional petroleum exploration opportunities.

Qualitative mineralogical analysis of Barracuda exploration well in the offshore Mannar Basin (the Indian Ocean) using FTIR and XRD techniques

The Mannar Basin plays a vital role in petroleum exploration in Sri Lanka, and its Barracuda exploration well was drilled up to 4206 m in depth. The objective of the current study is to identify mineralogy using Fourier-transform infrared (FTIR) and X-ray diffraction (XRD) analyses. The FTIR and XRD analyses confirm the presence of quartz, feldspar, clay minerals (e.g., kaolinite, montmorillonite), calcite, and hematite in all marlstone and mudstone samples. These sedimentary rocks can be identified as potential petroleum source rocks in the Mannar Basin. Quartz, carbonate, and hematite cementations are directly reduced porosity and permeability, and thus primary migration of hydrocarbons from potential source rocks. Clay minerals act as a seal for hydrocarbon migrations in the Mannar Basin. A variety of dominant clay mineral assemblages allows the reconstruction of several paleoclimatic chronozones in warm/wet and arid climates. In contrast, feldspar dissolution promotes the primary migration of hydrocarbon from potential petroleum source rocks. Consequently, this study concluded that common minerals such as quartz, carbonate, and hematite are associated with the trapping and binding processes of hydrocarbons.

Optical and geochemical assessment of petroleum source rock potential and palaeodepositional environments of Cretaceous mudstones, Koum Basin, North Cameroon

Limited organic matter (OM) characterisation studies on Cretaceous mudstone successions in the Koum Basin have resulted in a significant knowledge gap in the source rock potential; a petroleum system prerequisite. Field mapping and lithofacies analysis of outcrop sections point to fluvial channel and marginal to profundal lake deposits. Representative mudstone samples were evaluated using multiproxy organo-petrographic and bulk geochemical analyses to assess the kerogen type, thermal maturity, hydrocarbon generation potential, and deduce the paleodepositional environment. Results reveal that ∼90% of the samples are organic-lean and ∼10% organic-rich with TOC content of 2.81–6.91 wt%. Rock-Eval pyrolysis S2 yields of 14.50–54.18 mg HC/g rock and hydrogen index (HI) 784–846 mgHC/gTOC, suggest excellent potential for oil generation. High S1 values of 1.18–1.45 mg HC/g rock and low production indices (PI) of 0.02–0.03 indicate in situ generated free hydrocarbons. PI and Tmax of 438°C–443 °C, consistent with measured vitrinite reflectance (Ro% = 0.28–0.53%), Spore Colour Index (SCI = yellow to golden brown) and Thermal Alteration Index (TAI = 1.5 to 2.6) on the Chevron scale, portraying an immature to marginally mature OM. Oil-prone kerogen Type I-II dominates and to a lesser extent gas-prone Type III, derived from algal-terrestrial organic facies, typified by the predominance of amorphous OM 51.2%, liptinites 24.6%, vitrinite 16.4% and inertinite 7.8%. Based on lithofacies, and palynological evidence, a fluvio-lacustrine depositional setting with limited marine influence, under fluctuating warm humid to hot semi-arid paleoclimates, is inferred. A comparison with surrounding petroleum-producing basins further enhances the understanding of the Koum Basin's hydrocarbon potential within the West Central African rift system context.

Depositional environment and petroleum source rock potential of Mesozoic lacustrine sedimentary rocks in central Mongolia

Middle Jurassic (five samples from one location) and Lower Cretaceous (thirty-two samples from eight locations) lacustrine sedimentary rocks of central Mongolia were studied to determine their depositional environments and petroleum source rock potential. The Middle Jurassic shale contains sufficient organic matter (OM) with Type II/III kerogen to represent a mixed oil and gas potential source rock. Tmax and biomarker maturity indices suggest a thermally immature level. Pristane/phytane and the gammacerane index indicate that the shale accumulated in an oxic, freshwater environment. Terrigenous OM with input from algae and macrophytes was a major contributor as indicated by long-chain n-alkanes and the abundance of C29 regular steranes. The stable carbon and nitrogen isotope compositions and kerogen types agree with land plant derived OM. Lower Cretaceous shales are highly oil-prone but thermally immature, reflected by Rock-Eval data and biomarker parameters. Carbon preference index (CPI), n-alkane distributions, and C27/C29 ratios suggest that OM in Lower Cretaceous shales is a mixture of phytoplankton, macrophyte, and land plant. The contribution from algal OM is variable. Lower Cretaceous shales were deposited in stratified lakes with anoxic bottom waters and the salinity of paleolakes was variable, indicated by Pr/Ph and the gammacerane index, respectively. Organic geochemical characteristics and depositional environments of Middle Jurassic and Lower Cretaceous sedimentary rocks studied herein are similar to those of Jurassic source rocks in western Chinese basins and Lower Cretaceous source rocks in eastern Mongolian basins, respectively.

The Occurrence of Bedding-Parallel Fibrous Calcite Veins in Permian Siliciclastic and Carbonate Rocks in Central Thailand

Bedding-parallel fibrous calcite veins crop out at two Permian carbonate localities in the Phetchabun area, central Thailand, within the Nam Duk and Khao Khwang Formations. Samples are studied to determine their petrographic, geochemical and isotopic character, depositional and diagenetic associations and controls on the formation of fibrous calcite across the region. Biomarker and non-biomarker parameters are used to interpret organic matter sources in the vein-hosting units, the depositional environment and levels of source rock maturation in order to evaluate source rock potential in the two Formations. Carbon and oxygen isotope values of the veins and the host are determined to discuss the source of carbonates and diagenetic conditions. The petroleum assessment from the Khao Khwang and Nam Duk Formations suggests that both Formations are a petroleum potential source rock with type II/III kerogen deposited in an estuarine environment or a shallow marine environment and a slope-to-basin marine environment or an open marine environment, respectively. The bedding-parallel fibrous calcite veins from the Khao Khwang and Nam Duk Formations are divided into two types: 1) beef and, 2) cone-in-cone veins. The carbon and oxygen isotope compositions from the fibrous calcite veins suggest that the calcite veins could be precipitated from a carbon source generated in the microbial methanogenic zone. The results in this study provide a better understanding of the interrelationship between the bedding-parallel fibrous calcite veins and petroleum source rock potential.

Paleoenvironmental conditions and organic matter enrichment of the Late Paleoproterozoic Cuizhuang Formation dark shale in the Yuncheng Basin, North China

The Paleoproterozoic dark shale of the Cuizhuang Formation is the potential petroleum source rock in the Yuncheng Basin. Mineralogy, organic and inorganic geochemical analysis were applied in this study to evaluate the sedimentary paleoenvironments and its factors that control the enrichment of organic matter and to reconstruct the organic matter accumulation model of the Cuizhuang Formation dark shale. Quartz and clay minerals are the most abundant minerals in the Cuizhuang Formation dark shale. The TOC content of the dark shale is relatively fair, ranging from 0.13% to 1.09% and averaging of 0.51%, with the organic matter having a high thermal maturity (mean of 2.24 Ro%) and type I kerogen. The Cuizhuang Formation shale was deposited in a passive continental margin setting, and the climate was under moderate warm and humid conditions with low salinity of seawater as evidenced by the proxies of chemical alteration index (CIA) and Sr/Ba. The paleoproductivity proxies Ba bio , Ba%, Ba/Al, P 2 O 5 and P/Ti indicate low productivity with negative and no correlations with TOC content and thus didn't control the organic matter enrichment. The low productivity may have significantly played a role in limiting the organic matter formation resulting in relatively low TOC content. The anoxic redox environment of the dark shale is indicated by the proxies of V/(V + Ni) and V/Sc, with strong positive correlations of V and V/Al with TOC. The anoxic redox environment in deeper waters and a higher sedimentation rate than the grey and red shale played the main role of enriching the organic matter of the dark shale. Therefore, the Cuizhuang Formation dark shale in the Yuncheng Basin is regarded as a potential source rock, holding promise for petroleum exploration. • Paleoenvironment and its relationship with organic matter enrichment was revealed. • Low productivity resulted in low TOC content of the Cuizhuang Formation shale. • Reducing environment and higher sedimentation rate contributed to the organic matter enrichment of the dark shale. • The accumulation model of the dark shale organic matter in the Cuizhuang Formation was established. .

Paleoenvironments and source rock potential of Dorado North well in the Mannar Basin (Indian Ocean)

The Upper Cretaceous to Eocene sedimentary succession of the Dorado North exploration well in the Mannar Basin has been studied for paleoenvironment (organic matter richness, its composition, and depositional environment) and petroleum source rock potential. In this study, drillcore cuttings (n = 142) were analyzed using CHNS elementary analyzer. Results indicated that Lower Campanian sediments were depleted by total organic carbon content (TOC = 0.45%), under arid climate. The Lower Campanian to Upper Maastrichtian sedimentary sequence contains organic carbon rich (TOC = 1.64%) terrestrial (C/N ratio = 27.13) sediments. Consequently, this sedimentary sequence can be identified as a good source rock for gas generation. The formation of organic matter rich terrestrial sediments has been linked to sea-level changes and tectonic activities during the Late Cretaceous. Carbonate carbon contents are rich in the Lower Campanian to Upper Maastrichtian sedimentary sequence that indicates diversification of microorganisms under warm climatic conditions. The Paleocene to Eocene sedimentary sequence indicates poor to fair source rocks for possibly oil generation. However, the depositional environment was drastically changed from oxic (Early-Late Paleocene) to anoxic (Late Paleocene-Late Eocene) conditions. Consequently, the Eocene epoch is characterized by weak oceanic circulation in the Indian Ocean under greenhouse climate. In contrast, the deposition of carbonate platforms since the Late Paleocene (CaCO3 = 29.3%) can be related to the northward movement of the Indian plate into warmer tropical latitudes.

PETROLEUM POTENTIAL OF MAE TEEP ORGANIC SEDIMENTS, NORTHERN THAILAND

The selected 7 organic sediment samples (3 oil shale samples from Upper Oil Shale, Lower Oil Shale and Oil Shale in Coal A sub-unit, 3 coal samples from Coal A, Coal B and Coal C sub-unit and 1 leonardite sample from Leonardite sub-unit) collected at the northern wall of Mae Teep coal mine were conducted the Hydrocarbon Analyzer with Kinetics (HAWK) pyrolysis in order to assess their petroleum source rock potential. The calculated HI, OI, PI, S2+S3 and Ro were then used to classify the kerogen type and to evaluate the thermal maturity stage of these 7 studied organic sediment samples. Results of the study indicate that all of the organic sediment sub-units of Mae Teep organic sediments have good to excellent hydrocarbon generation potential. HI vs Tmax and HI vs calculated Ro cross-plots results indicate that organic sediments of Coal A, Coal B, Coal C, Oil Shale in Coal A and Upper Oil Shale sub-unit are in the thermal immature stage, while the organic sediments of Lower Oil Shale and Leonardite sub-unit are in the early thermal mature stage. Mae Teep organic sediments are considered to be the high potential hydrocarbon source rock since they have high kerogen yield (S2) (21.49 - 69.8 mg HC/g rock) and their total hydrocarbon generation potential (S1+S2) are also high (22.13-72.12 mg HC/mg rock). These may contribute them to be a good to very good source rock if their maturity reaches the thermal mature stage.

Tracing bottom-water redox conditions during deposition of Lower and Upper Jurassic organic-rich sedimentary rocks in the Lusitanian Basin (Portugal): Insights from inorganic geochemistry

The Lower Jurassic Água de Madeiros (AM Fm) and Vale das Fontes (VF Fm) Formations, and the Upper Jurassic Cabaços Formation (Cab Fm) are considered the most important units with petroleum source-rock potential in the Lusitanian Basin, and the likely sources for its widespread hydrocarbon occurrences. Nonetheless, the bottom-water redox conditions during their deposition remain debatable. To resolve this controversy, we investigated whole-rock inorganic geochemical data of the most significant organic-rich levels of the AM, VF and Cab Fms cropping out at basin scale. Significant variations in TOC, TS and redox-sensitive elements contents and their ratios are evident within and between the organic-rich levels of the studied units. A positive covariation between primary productivity proxies, TOC enrichment and paleo-redox proxies for the Lower Jurassic units clearly suggest an interdependence between enhanced primary productivity, organic matter accumulation and bottom-water redox conditions. For the AM Fm, the paleo-redox proxies indicate that the black shales deposition took place beneath bottom-waters that ranged from suboxic to strongly euxinic conditions, with a clear predominance of the latter. A TOC threshold of ~6–7 wt% clearly separates samples deposited under suboxic to anoxic conditions from those deposited under true euxinic conditions, and is interpreted as the minimum amount of organic matter (OM) accumulation within sediments required to sustain H2S production at rates that outpaced its consumption through precipitation of sulphides and/or OM sulphurization, allowing the diffusion of H2S to the bottom-waters. For the Vale das Fontes Fm, the paleo-redox proxies suggest a prevalence of suboxic to anoxic bottom-waters, despite all black shales displaying TOC contents greater than the above threshold. The less reducing conditions relative to the AM Fm euxinic black shales are attributed to: i) a larger proportion of continental OM; ii) lower reactivity of the OM reaching the sediment-water interface (decreasing oxygen consumption); and iii) higher availability of reactive iron (increasing the buffer effect to H2S produced through OM remineralization by sulphate-reducing bacteria). Both units display Mo-EF vs U-EF covariation patterns that deviate from the field of sediments deposited under unrestricted open-marine conditions, towards higher Mo enrichment relative to that of U, indicating an accelerated transport of aqueous Mo to the sediments, consistent with the operation of a metal-oxyhydroxide particulate shuttle linked to Mn and Fe redox cycling within the water column in a weakly-restricted basin. The Mo-COT regression-line slope indicates a moderate degree of bottom-water mass restriction, with [Mo]aq concentration of ~60–70% of the present-day seawater value and bottom-water renewal times of ~10–20 years, akin to the present-day Cariaco Basin. The redox conditions of the Cab Fm organic-rich levels are dependent on the location of the depositional environment in the basin, with deposition taking place beneath oxygenated bottom-waters at Cabo Mondego, and under suboxic conditions at Vale de Ventos and Pedrógão, the latter denoting a larger degree of oxygen depletion than the former. In this context, the overall potential for OM preservation should increase from Cabo Mondego to Vale de Ventos and Pedrógão.

Organic Geochemical Evaluation of Shale Units of Bokh Formation, Ogaden Basin, Ethiopia

Shale sample from Bokh Formation, Ogaden basin, Ethiopia was assessed for their petroleum potential by Rock-Eval pyrolysis. The Total Organic Carbon (TOC) values range from 0.76 to 0.86 wt%. These values exceed the minimum value of 0.5 wt% required for potential petroleum source rocks. The genetic potential (GP) and hydrogen index (HI) values range from 0.09 to 0.5 mg/g and 8 - 32 mgHC/gTOC, respectively. These values are generally lower than the minimal 2 mg/g GP and 200 mgHC/g HI required for a potential source rock. Several plots from the Rock-Eval pyrolysis data classify the samples as type IV kerogen with no potential to generate hydrocarbons. The Tmax and Production Index (PI) values range from 388°C to 453°C and 0.28 to 0.46, respectively. These values indicate that the shales are thermally matured. These results show that the shales from the Bokh Formation in Ogaden basin have no potential to generate hydrocarbons mainly crude oil, but are thermally matured and may generate natural gas.

Fluvial and lacustrine successions in the youngest part of the Murihiku Supergroup, New Zealand

Fossil-bearing Late Jurassic to Early Cretaceous volcaniclastic sandstones and siltstones from the Murihiku Supergroup are described from the Kaimango Syncline South Auckland, New Zealand. These constitute the youngest known sedimentary succession within the Murihiku Supergroup (Murihiku Terrane). We concentrate on the youngest Matira Siltstone Formation which has yielded a rich but relatively low-diversity macroflora of ferns and gymnosperms, diverse miospore palynofloras, with fair to good preservation, and sporadic occurrences of bivalve and gastropod faunas. Collectively, the paleontology and sedimentology of this formation is interpreted to represent paludal and lacustrine deposition, with intercalated sandstones thought to represent fluvial channelised or deltaic settings. U-Pb dating of detrital zircons (DZ) from sandstones in the youngest formations, Mangatara Measures and Matira Siltstone, have provided significant components in the age range 140 to 143 Ma, possibly straddling the Jurassic-Cretaceous boundary, although miospores suggest a Late Jurassic correlation. Lacustrine and paludal depositional environments have not previously been recognised from the Murihiku Supergroup and this raises the prospect of their enhanced petroleum source rock potential in frontier basins to the north and east of New Zealand.

Sedimentary environmental conditions and petroleum source rock potential of the Late Jurassic Arwa Member shales in Al-Jawf sub-basin, Yemen

This study is a part of the source rock geochemistry project in the onshore Sabatyen Basin, Yemen. The results of this study were used to improve our understanding of the petroleum resource potential of Al-Jawf sub-basin in the north-western part of the Sabatyen Basin. The shale samples of the Late Jurassic Arwa Member from two wells (Khyawan-01 and Himyar-01) were analyzed to evaluate the characterises of the organic richness, kerogen type, thermal maturity and petroleum generation potential in Al-Jawf sub-basin based on a compilation of geochemical and petrological data. The biomarker and stable isotope results were subsequently used to evaluate the organic source input and sedimentary environmental conditions during deposition of the Late Jurassic Arwa Member shales. The Arwa shales contain low to high organic matter, with variable TOC% values between 0.58 and 6.41, indicating fair to very good source rock generative potential. The Rock-Eval HI data are ranging from 73 to 816 mg HC/g TOC and display mainly Type III and II/III kerogens with a minor contribution of Types I/II kerogen, consistent with both oil and gas source rocks. The biological sources are predominately sapropelic organic matter, with significant contribution of higher plants input in the Arwa member shales as indicated from biomarkers and carbon isotope data and petrology study. The biomarker ratios of relatively low Pr/Ph, Pr/n-C17 and Ph/n-C18 values and relatively high values of HC34/HC35 indicate suboxic environmental conditions during deposition of the Arwa Member shales.The analyzed Arwa shale samples have temperatures of maximum pyrolysis yield (Tmax) in the range of 417–457 °C and vitrinite reflectance between 0.30 and 0.56 %Ro, consistent with immature to early-mature source rocks. It is interesting to know that the Arwa shale samples with high contents of TOC% (>1), HI (>300 mg HC/g TOC) and high thickness of more than 1000 m indicate that the Late Jurassic Arwa Member hold significant exploration potential for oil in the deeper locations. Therefore, the hydrocarbon exploration processes should be focused on the known deeper location of the Arwa Member for predicting the mature source rock.

Investigation of Petroleum Source Rock Potential and Maturity in Pologbene-001 from resistivity and density logs, Northern Depobelt Eocene Deposits, Niger Delta, Nigeria

Investigation of Petroleum Source Rock Potential and Maturity in Pologbene-001 from resistivity and density logs, Northern Depobelt Eocene Deposits, Niger Delta, Nigeria

Correlation of zooclast reflectance with Rock-Eval Tmax values within Upper Ordovician Cape Phillips Formation, a potential petroleum source rock from the Canadian Arctic Islands

The lower part of the Cape Phillips Formation (Upper Ordovician, Canadian Arctic) is an ideal unit to test the correlation of graptolite and chitinozoan reflectance, and to compare zooclast reflectance with Rock-Eval pyrolysis Tmax. The Cape Phillips Formation is an organic-rich limestone and shale containing abundant zooclasts, bitumen, and amorphous organic matter, and has biomarker characteristics consistent with a carbonate depositional environment and organic matter derived from marine algae.Random graptolite reflectance on thirty-seven samples in the Rograp range of 0.58%–1.02% (Tmax range of 424–441 °C) were examined. The correlation between random reflectance of graptolite and chitinozoan reflectance was determined to have the following linear model:(Rograp)=0.11+0.814×(Rochi)whereas the linear correlation between Rock-Eval Tmax (converted to vitrinite reflectance equivalent VRoeqv) and Rograp and Rochi were determined to be:VRoeqv(Tmax)=0.232+0.499×(Rograp)for random reflectance of graptolites.VRoeqv(Tmax)=0.231+0.482×(Rochi)for chitinozoan.Graptolite and chitinozoan reflectance are generally greater than vitrinite reflectance equivalent, but the difference between the equations to convert graptolite and chitinozoan reflectance to VRoeqv(Tmax) are so small that the equations could be used interchangeably and may represent a general solution to the conversion of zooclasts reflectance to VRoeqv(Tmax) in Lower Paleozoic rocks.The correlation between zooclast reflectance and Rock-Eval Tmax improves in samples that have undergone solvent extraction, indicating that hydrocarbons affect Tmax. Sample that has asymmetrical S2 peak on Rock-Eval pyrolysis also has very high total extract yield with resins and asphaltenes as the dominant extracted fractions. Rock-Eval analysis of samples before and after solvent extraction demonstrates that some portion of the soluble hydrocarbon is pyrolysed in the temperature range that overlaps the S2 peak. In extracted samples S2 peaks become more symmetrical and the Tmax value shifts compared to the unextracted samples.

Hydrocarbon source potential of Eocene-Miocene sequence of Western Sabah, Malaysia

An evaluation of the petroleum generating potential of onshore Eocene-Miocene sequences of Western Sabah, Malaysia was performed based on organic petrological and geochemical methods. The sequences analysed are the Belait, Meligan, Temburong and West Crocker formations of western Sabah. The Belait Formation which is Stage IV equivalent in the offshore represents one of the major source rock/reservoirs of the petroleum-bearing Sabah Basin. The Eocene-Early Miocene West Crocker and Temburong formations are deepwater turbidites whilst the Miocene Meligan and Belait formations are shallow marine fluvio-deltaic deposits. The vitrinite reflectance and pyrolysis Tmax values show that the Belait samples are generally immature for hydrocarbon generation, whereas the Meligan, Temburong and West Crocker samples are in the mature to late maturity stage of hydrocarbon generation. The overall bulk source rock properties of the Belait and Meligan show fair to good petroleum source rock potential with TOC more than 1 wt %, hydrocarbon yield in the range of 400–1300 ppm and moderately high HI for many of the samples. Most of the samples representing the Temburong and West Crocker formations have TOC less than 1 wt% and have no to fair hydrocarbon generating potential. Interestingly, the samples collected in the West Crocker Formation characterized by slump deposits (MTD) have TOC>2 and possess good to excellent hydrocarbon generating potential. The organic matter present in all of the studied formations is mainly of terrigenous origin based on the abundance of woody plant materials observed under the microscope. Consequently, the analysed sequences are predominantly gas prone, dominated by Type III and Type III-IV kerogen except for minor occurrence of mixed oil-gas prone Type II-III kerogen in the Belait Formation and in the slump mass transport deposits (MTD) of the West Crocker Formation.

Small-scaled lateral variations of an organic-rich formation in a ramp-type depositional environment (the Late Jurassic of the Boulonnais, France): impact of the clastic supply

We studied a potential petroleum source rock deposited in a clastic-dominated ramp environment: the Argiles de Châtillon Formation (Kimmeridgian-Tithonian, Boulonnais area, northern France). The formation was deposited along a proximal-distal gradient on this ramp affected by synsedimentary fault movements. A sedimentological, mineralogical and geochemical study was conducted to decipher the distribution patterns of sedimentary parameters along such a depth increase over the ramp. It comes out that smectite distribution unexpectedly mimics the lateral depth evolution despite the good floatability of the mineral. It is also observed that the Argiles de Châtillon could accumulate noticeable amounts of organic matter in spite of paleoenvironmental conditions that were not specifically prone to organic matter preservation and burial (sedimentation rate, mineral particle grain size, productivity, oxygenation level…). Conversely, reactive iron, when being present in limited abundance, must have allowed sulfide ions to react with organic molecules instead of forming iron sulfides, which fostered organic matter preservation and accumulation. This protecting role of organic sulfide incorporation (additional to other favorable factors) cannot exist if reactive iron is relatively abundant. Lastly, our results (still fragmentary) suggest that smectite minerals could carry reactive iron, which would have occasionally hampered organic-matter preservation.

Petroleum source-rock potential and thermal maturity of Zarama 10 and Zarama 11 oil wells in the Niger Delta, Nigeria

ABSTRACTDrilling cuttings and drilling mud samples were collected from Zarama 10 and Zarama 11 oil wells in the Niger Delta at various depths in order to characterize the extractable organic matter and biomarkers distribution patterns. The total organic carbon contents of the samples were determined using Walkley Black method. The distribution of n-alkanes, pristane, phytane, phenanthrene, and its alkylated derivatives were studied by gas chromatography-mass spectrometry. The total organic carbon values show that the samples satisfy the minimum amount of 0.5 wt% organic matter required to serve as a potential source-rock of petroleum. The distribution of n-alkanes and alkylated phenanthrenes shows that the samples contain admixture (marine and terrestrial) of organic matter. The pristane/phytane ratio (1.25–2.25) indicates sub-oxic depositional environment for the organic matter of the samples. Equivalent vitrinile reflectance values calculated from methyl phenanthrene index (MPI-1) were in the range of 1.23–1.38% for the well studied. The maturity parameters obtained were used to assess maturity, which revealed high maturity level of the two wells. Further, calculated vitrinite reflectance (Rc) confirmed that the sediments have a range of maturity within the “oil window.”

Hydrocarbon potential of cretaceous sediments from lower Indus Basin, Pakistan

ABSTRACTIn previous studies, Patala-Nammal Composite Total Petroleum System (TPS) was recognized as a potential source of hydrocarbon in the Upper Indus Basin, and Sembar-Goru Composite TPS in the Lower Indus Basin. However, petroleum source-rock potential of Cretaceous strata in the Indus Basin is poorly known. In the current study, Rock Eval and total organic carbon (TOC) analyses were conducted to investigate the thermal maturity and source-rock potential of Cretaceous unit in the Lower Indus Basin. The Parh Formation of the Lower Indus Basin is lean in organic contents (TOC < 0.73%) and consistent with immature type-III/IV kerogen. The Upper Goru Formation is fair in organic contents and presents similar characteristics to the Parh Formation with respect to the hydrocarbon generation zone. The Lower Goru Formation presents fair to very good organic contents. The members of Lower Goru Formation have enough organic matter (OM) and are mature, with the exception of Badin shales. The OM, throughout the formation, is predominantly gas prone. The Sembar Formation is fair in organic contents and mature with respect to hydrocarbons generation. These results support that the Lower Goru rocks are comparatively more prospective with respect to hydrocarbons.

Petroleum source-rock potential of the Piranj oil field, Zagros basin

Zagros basin constitutes one of the most prolific hydrocarbon producing habitats and the second largest basin in the Middle East. The Piranj oil field is part of The Middle Cretaceous–Early Miocene Petroleum System in Zagros basin and southwest of Iran. This study mainly focuses on organic matter characterization and thermal history of two potential source rock's name Gurpi and Pabdeh formations. To evaluate the candidate source rocks, 50 cuttings and core samples of these rock units from well M-11 (the only well drilled up to the probable source rocks) were analysed, using Rock-Eval pyrolysis and organic petrography. In addition, 1D basin modelling and reconstruction of burial history were applied to analyse the thermal history of these source rocks. The green shale, limestone and marls of Pabdeh formation with average 2.52%wt Total Organic Matter (TOC) and Hydrogen Index (HI) higher than 250 is more favourite source rock in comparison with dark shale and limestone of Gurpi formation by 1.8%wt and HI < 300. Moreover, Pabdeh formation can be classified generally as fair to very good source rocks, with kerogens of type II, while Gurpi formation contain mostly kerogens of type II/III. The average values of Vitrinite reflectance (VR) (from 0.44% to 1.23%) indicate that samples from the well M-11 have reached maturities corresponding to early to peak oil generation. Reconstruction of the thermal history suggests various steady heat flow values (53–91 mW/m2) resulted in the best fit between the observed and the calculated bottom hole temperatures (BHT) and Vitrinite reflectance (VR) in the model. Rock-Eval pyrolysis results and Vitrinite reflectance (VR) suggest that the most of samples are in the early mature to mature stage of hydrocarbon generation. Furthermore, according to the modelling results, petroleum generation from the studied source rocks has began after deposition of related seal-rocks and formation of traps which ensures entrapment and preservation of migrated hydrocarbon.