Results Of Rock-Eval Pyrolysis Research Articles

Understanding the burial history and the hydrocarbon potential of the late Paleozoic Claromecó foreland Basin (Southwestern Gondwana, Argentina) by combining organic geochemistry, organic petrology, and thermal modeling

The Claromecó foreland Basin (Carboniferous–Permian; southern Buenos Aires province, Argentina) is key to understanding the paleotectonic evolution of the southwestern Gondwana margin and is relevant to energy resource exploration. This study reconstructs the thermal and burial history of the Claromecó Basin by integrating geochemical data, organic petrology, and thermal modeling techniques. Cores samples of the Tunas Formation (Pillahuincó Group, Early Permian) were studied. A 1D thermal model was constructed, calibrated with vitrinite reflectance measurements (VRo %), and corroborated with fluid inclusion and apatite fission track data from previous studies. Rock-Eval pyrolysis results show TOC% values ranging from 0.13 to 60.35 wt%. The Hydrogen index (HI < 50 mg HC/g TOC) and Oxygen index (OI < 50 mg CO2/g TOC) indicate the dominance of Type III and Type IV kerogens, most likely resulting from the thermal maturation of an original Type III kerogen. Petrologic observations confirm the presence of macerals from the inertinite group, as well as minor amounts of vitrinite and liptinite. The Tmax displays a temperature range mostly from 460 to 610 °C. The VRo % values range from 1.5 to 2.0%. Geochemical data combined with VRo % measurements confirm a late catagenesis to metagenesis stage within the wet to dry gas window for coals and organic-rich strata.In order to constrain the thermal evolution of the basin infill, different scenarios were tested by varying the heat flow and the missing section thickness associated with the uplift and erosion of the basin (Permian–Cenozoic unconformity). The best calibration results were obtained with an erosion thickness of 3000 up to 4200 m and paleo heat flow peaks of either 60 or 80 mW/m2 during the Lower Permian–Lower Cretaceous. The Tunas Formation was deposited and buried during the Permian–Triassic (Gondwanides Orogeny phase), reaching a maximum temperature of 180 °C. The results obtained by combining geochemical analysis, organic petrology, and thermal modeling techniques indicate that the coal beds of the Tunas Formation could have a current potential as gas-prone source rocks. Despite that, the hydrocarbon generation capacity of coal levels is currently low due to the high percentage of residual (Type IV) kerogen. Further research could help clarify if the hydrocarbons potentially expelled by these source rocks have been lost due to migration or could be trapped somewhere in the basin.

1D basin modeling and hydrocarbon generation potential of the Late Carboniferous Limburg Group formations, Northwest European Basin, Netherlands

The Carboniferous rock samples of the Limburg Group formations were studied to investigate the source rock characteristics and the hydrocarbon generative potential. The source rock samples have been collected representing four rock units from three different wells. These samples were analyzed using Rock-Eval pyrolysis results and measured vitrinite reflectance values, and also by generating a one-dimensional basin model of K1 Field. The total organic carbon in these samples varies from 0.31 to 83.56% with a mean of 37.68%, suggesting that Limburg Group formations have excellent potential as a source of hydrocarbons. Kerogen in the Limburg Group formations is type II-III and type III, generate gas prominently. The outcomes of thermal maturation by Tmax and measured vitrinite reflectance reveal that the examined Limburg source rocks are located in the mature zone. The burial and thermal history models show irregular trend patterns due to uplift, erosion, and non-deposition events that took place in the K1 field (where the structural element is Cleaver Bank High). For the Maurits Formation, the oil generation took place at 2011 m at 230.1Ma ago and the top of the gas window was encountered 217.8Ma ago at 2535 m, whereas for the Hospital Ground Formation, the top of the oil window was encountered 186.8Ma ago at 2404 m and the gas generation took place at 2404 m at 161.9Ma ago.

How grain size influences hydrocarbon generation and expulsion of shale based on Rock-Eval pyrolysis and kinetics?

The differences between the Rock-Eval pyrolysis results of powder and grain samples have attracted wide attentions. Grain samples show lower hydrocarbon yield and different composition of the products. However, the effect of grain size on hydrocarbon generation and expulsion has not yet been quantitatively evaluated. In this study, we prepared each grain into a regular column with precise geometric parameters such as diameter, height, surface area, and volume, which is defined as an independent unit of hydrocarbon generation and expulsion. For comparison, a powder sample corresponding to each grain sample is collected simultaneously during the preparation process. The grain samples are used to simulate the mass of hydrocarbons expelled, while the powder samples are used to simulate the total mass of hydrocarbon generated. Our results show significant differences between the grain samples and the powder samples. All powder samples have a higher expulsion of free hydrocarbons (S1) than grain samples, and almost all grain samples have a higher expulsion of pyrolysis hydrocarbons (S2) than powder samples when the diameter of the grains is smaller than 3 mm. Temperature controls hydrocarbon generation, but grain size retards hydrocarbon expulsion. The influences of the “carry-over” phenomenon, oil adsorption and nanopore confinement are enhanced by grain size, which retards and inhibits hydrocarbon expulsion. Some free hydrocarbons (S1) cannot be expelled from the grain samples at 300 °C. Parts of the retained free hydrocarbons (S1) further cracked into small molecules, which can be expelled and detected as pyrolysis hydrocarbons (S2) at 300–650 °C. Four new parameters were proposed to quantify these influences, namely the S1retained, the S2extra expulsion, the HI difference parameter, and the TOC difference parameter. Diameter is more closely related to hydrocarbon expulsion rather than height. For grain samples, HI increases and TOC decreases with increasing diameter. Activation energies for hydrocarbon generation ranges from 43 to 67 kcal/mol for powder samples, while activation energies for grain samples are almost concentrated in 54–55 kcal/mol, indicating a high expulsion threshold for grain samples. As the grain diameter increases from 1.74 to 5.24 mm, the transformation ratio decreases and the generation rate increases, indicating that the grain size delays the expulsion of hydrocarbon. This laboratory simulation provides some new results to better understand the hydrocarbon generation and expulsion of shale rock under natural conditions.

Burial history and thermal maturity of the atypical petroleum system of the Paraná Basin (Irati and Ponta Grossa formations), Brazil

The main characteristic of the intracratonic sedimentary Paraná Basin, southern Brazil, is the atypical hydrocarbon generation through the heat from basic intrusive rocks. Potential hydrocarbon source shales from the Irati and Ponta Grossa formations were identified and characterised via stratigraphic data, total organic carbon (TOC - LECO) analyses and pyrolysis (Rock-Eval 6) of well samples. Geochemical analyses showed that in wells under study, the Irati Formation has organically rich shales, and the Ponta Grossa Formation has low potential for hydrocarbon generation. 1D generation modelling using 16-well 1D and PetroMod® software was developed aiming to establish the thermal and subsidence history in the area and to determine hydrocarbon generation and expulsion. Geochemical data from the wells was used, and information on sedimentology and stratigraphy was obtained from the literature. Thermal history was calibrated using values of vitrinite reflectance, Tmax and downhole temperature, and the geothermal gradient used in the models was 28–42 °C/km. The relative erosive thicknesses of the stratigraphic units were estimated. The results showed that in regions without igneous intrusions, the Irati shales are immature for hydrocarbon generation and do not have an organic matter transformation rate, which is consistent with the results of Rock-Eval pyrolysis and %Ro. However, in wells containing igneous intrusive rocks in the Irati shales, the transformation rates varied according to the thickness and number of intrusions, reaching 100% organic matter transformation; due to its quality (Type I kerogen), this rate is favourable for oil and gas generation. The Ponta Grossa source rock showed thermal maturation by subsidence corresponding to the oil generation window, with higher maturation anomalies near igneous intrusions. The organic matter transformation rate reached 70% in the absence of igneous intrusions and nearly 100% in the presence of igneous intrusions. Despite having good maturity, the characteristics regarding the quantity and quality of organic matter suggest a moderate potential for gas generation in the Ponta Grossa Formation in the study area. The depositional history model showed that the highest subsidence rate occurred during the Early Cretaceous and was related to the burial associated with the basalt thickness of the Serra Geral Formation.

Assessment of Mineralogical and Geochemical Composition of Oligocene/Eocene Black Shale Deposits in Beni Suef Area, Egypt

Black shale deposits are widespread in the Paleogene successions in the Beni Suef area, Egypt. In this work, the mineralogical composition, total organic carbon (TOC), and total sulfur (TS) contents of black shales were determined. The organic matter (OM), thermal maturation, and kerogen type can be determined using Rock-Eval pyrolysis. The results show that smectite and kaolinite are the dominant clay minerals in the analyzed samples. Al2O3 and SiO2 as major elements and Zr as a trace element are dominant constituents of terrigenous origin of the Dabaa and El Fashn formations. The total organic carbon content reaches 2.27 wt% at the El Fashn Formation in the Ghaida Al-Sharqia quarry but 0.36 wt% in the Oligocene Dabaa Formation in the Maydoum quarry. However, the total sulfur content reaches 0.58 wt% in the Dabaa Formation but 1.52 wt% in the El Fashn Formation. These results confirm that (1) the Dabaa Formation was formed in oxidizing environments and oxidized the high volume of OM and (2) the El Fashn Formation accumulated in reducing environments of mostly suboxic conditions. The Rock-Eval pyrolysis results of the black shale deposits reflected a kerogen type III of terrestrial origin of the El Fashn Formation due to the high OM content preservation in suboxic shallow marine environments. The Tmax and production index parameters of Rock-Eval pyrolysis reflected that the black shale deposits in the El Fashn Formation are immature, but with surface retorting, it can generate natural gas.

Organic geochemistry and petrology of source rocks from the Banqiao Sag, Bohai Bay Basin, China: Implications for petroleum exploration

The organic geochemistry and petrology of source rocks determine the hydrocarbon generation potential of the Banqiao Sag. In this study, organic geochemistry and petrology were used to determine the abundance of organic matter (OM), OM type, OM maturity, and sedimentary environments of the source rocks, collected from Cenozoic Shahejie Formation, Banqiao Sag, Bohai Bay Basin, China. Vitrinite and liptinite are the main maceral composition of the source rocks, and range from 18% to 81% and from 2% to 82% on a mineral matter free (MMF) basis, respectively. The values of vitrinite reflectance ( R o ) (0.36%–1.20%) and the T max values (397–486 °C) show that the thermal maturity range from low mature to peak-maturity. The abundance of OM varies between 0.22% and 4.37%, suggesting that the source rocks of the Shahejie (Es) Formation are mainly fair to good source rocks. The Rock-Eval pyrolysis results show that the source rocks have good petroleum generation potential. The amount of free hydrocarbons ( S 1 ) and hydrocarbons generated from pyrolysis ( S 2 ) range within 0.01–3.70 mg/g, and 0.04–29.17 mg/g. The hydrogen index (HI) varies between 18.18 and 741.13 mg HC/g TOC, with most of the samples appearing to be mainly Type II kerogen, and thereby exhibiting the ability to generate both oil and gas. The ratios of Pr/Ph, the cross plot of Pr/nC 17 –Ph/nC 18 , the cross plot of C 29 /C 27 –Pr/Ph, and ternary of dibenzothiophene, dibenzofuran, and fluorene, indicate that the Shahejie Formation deposited in suboxic and weak reducing environments. The main biological source is from advanced plants. The maceral composition and rock pyrolysis data indicate the kerogen type is a humic type or mixed sapropelic-humic type. The source rocks of the Shahejie (Es) Formation occur in the oil window, and the abundant organic richness, humic kerogen demonstrate that these rocks are effective oil and gas source rocks. The mudstone rocks in the Shahejie Formation are the main source of oil and gas and represent the main exploration target for the Banqiao Sag. This study enhances the great prospect of oil and gas production in the Banqiao Sag.

Migration directions of crude oils from multiple source rock intervals based on biomarkers: A case study of Neogene reservoirs in the Bodong Sag, Bohai Bay Basin

Identifying oil origins and reconstructing oil migration directions are vital for oil exploration in continental petroliferous basins, but they become difficult and complicated when multiple source rock intervals are encountered. This is the case of the Neogene fluvial reservoirs in the Bodong Sag, Bohai Bay Basin, east China, which show significant spatial heterogeneity in oil charging. Here, we take the LK9-2 Structure in the southeastern Bodong Sag as an example to determine the potential factors controlling the oil migration directions from multiple source rock intervals. Total organic carbon contents, Rock-Eval pyrolysis results and biomarkers were applied to distinguish the major oil sources and trace the oil migration pathways. The first–second and third members of the Eocene Shahejie Formation and the third member of the Oligocene Dongying Formation in the Bodong Sag all showed high potential of generating oils for the overlying Neogene reservoirs. However, oil–source correlation by biomarkers revealed that the Neogene oils of the LK9-2 Structure were mainly derived from the third member of the Dongying Formation. Oils generated from the underlying Shahejie Formation were, however, mostly blocked by the thick mudstones of the Dongying Formation. The dimethyldibenzothiophenes and benzo[b]naphthothiophenes parameters, indicative of oil migration directions, showed the failure of lateral oil migration within the Neogene reservoir layers, which had been cut by active shallow normal faults. Therefore, the uppermost thick source rock intervals and abundant active shallow normal faults in the way of lateral oil migration were the two major factors that controlled the oil migration directions from multiple source rock intervals and probably accounted for the many uncharged traps in the Bodong Sag.

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

A 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%.

Hydrocarbon-Generating Potential of Eocene Source Rocks in the Abakaliki Fold Belt, Nigeria / Potencial za nastanek oglikovodikov v eocenskih izvornih kamninah nariva Abakaliki

Abstract Subsurface information on source rock potential of the Eocene shale unit of the Abakaliki Fold Belt is limited and has not been widely discussed. The total organic carbon (TOC) content and results of rock-eval pyrolysis for nine shale samples, as well as the one-dimensional (1D) geochemical model, from an exploration well in the Abakaliki Fold Belt were used to evaluate the source rock potentials and timing of hydrocarbon generation of Lower Eocene source rocks. The TOC content values of all the samples exceeded the minimum threshold value of 0.5 wt.% required for potential source rocks. A pseudo-Van Krevelen plot for the shale samples indicated Type II–III organic matter capable of generating gaseous hydrocarbon at thermally mature subsurface levels. The 1D burial model suggests that the Eocene source rock is capable of generating oil and gas at the present time. The modelled transformation ratio trend indicates that a fair amount of hydrocarbon has been expelled from the source rocks. The results of this study indicate that the Eocene source units may have charged the overlying thin Eocene sand bodies of the Abakaliki Fold Belt.

Specifications for carbonate content quantification in recent marine sediments using Rock-Eval pyrolysis

The amount of CaCO3 in sediments and/or sedimentary rocks is usually measured by calcimetry while the nature of the carbonates is determined by X-ray diffraction. Recently, a carbonate recognition method based on the results of Rock-Eval pyrolysis was proposed in 2014 by Pillot et al. [1]. Rock-Eval pyrolysis is also widely used for the characterization of recent sediments. However, later in 2015 Baudin et al. [2] noticed that some of the characteristics of recent sediments tended to produce different results from those of more classical Rock-Eval analyses, causing bias in interpretations.In this study, the thermal stability of fossil and recent marine carbonated sediments was analyzed to identify differences in carbonate decomposition and to underline the importance of accounting for them in Rock-Eval analyses. The state of calcite preservation in recent marine sediments and sedimentary rocks at temperatures between 400 °C and 600 °C was characterized using different techniques (calcimetry, XRD, SEM imaging, etc.) for better interpretation of data obtained with Rock-Eval.Our results highlight a clear difference in the range of calcite decomposition temperatures during Rock-Eval analysis: between 550 °C and 775 °C for bulk clayey hemipelagic sediments versus 650 °C–840 °C after the same sediments were rinsed to get rid of the salt. During heating, water and hydroxide anions are released from clay minerals and react with salt crystals to form acid vapor. This acid vapor reacts with carbonates to produce CO2. The chemical decomposition of carbonate starts at temperatures that are lower than the typical range of decomposition temperatures, leading to overestimation of mineral carbon content (overestimation of the S5 peak) and to underestimation of organic carbon content (underestimation of the S4CO2 peak) with the Rock-Eval method. In the absence of clay minerals, such as in recent marine pure carbonate oozes, there is no evidence for this effect. It is therefore essential to prepare and rinse recent clay-rich carbonated sediment samples before Rock-Eval analysis to avoid misinterpretation.

Total organic carbon from well logging - statistical approach, Polish shale gas formation case study

Advanced statistical methods - artificial neural networks (ANN) and support vector machines (SVM) were used to calculate total organic carbon (TOC) on the basis of well logging. Data from three wells from the Silurian and Ordovician formations in the Baltic Basin from the north Poland were used. In learning procedures TOC data as Rock-Eval pyrolysis results were applied. Research was undertaken in four steps aiming to determine the best ANN in aspect of number and type of input variables. Regarding increase of cases number used in learning process data from two wells were combined and next, determined ANN and SVR were used to predict TOC. There were also made tests of number of input variables (results of standard and sophisticated well logs and laboratory data). Results obtained using standard logs when number of available cases for learning was big enough did not gave way to results based on very many input variables. [Received: October 29, 2016; Accepted: October 21, 2017]

Geochemical Evaluation of the Hydrocarbon Prospects of Carbonaceous Shale and Coal of Barail Group, Upper Assam Basin

The Upper Assam Basin is an important onshore petroleum province in India. The petroleum generation potential of Barail coal and carbonaceous shale in the different oil fields has been assessed to determine the source rock quality of the coal/shale unit or the argillaceous unit in the Upper Assam Shelf of Barail Group. Organic geochemical analyses involving elemental analysis, TOC and Rock-Eval pyrolysis were carried out on some selected subsurface core samples from different oil fields of Upper Assam to characterise their sedimentary organic matter. Rock-Eval pyrolysis showed good organic carbon richness, i.e., TOC (1.00%-69.21%), thus indicating good generative potential for petroleum. The Tmax data span of the studied samples is 396°C-433°C. Low Tmax values (<430°C) of the studied samples indicate that the organic matter in the coal and carbonaceous shale samples of Barail strata are either immature or less mature with respect to liquid hydrocarbon generation. The Rock-Eval pyrolysis results indicate the mixed type II and III kerogen, which is of good source rock quality, but thermally immature to generate petroleum. [Received: February 9, 2016; Accepted: September 20, 2016]

Palynofacies and geochemical analyses of the Silurian Tanezzuft Formation, NC115 concession, Murzuq Basin, south-west Libya: Implications for source rock potential and palaeoenvironment

A palynofacies and organic geochemical investigation has been undertaken on 46 core and cuttings samples taken from seven wells drilled in the NC115 Concession, Murzuq Basin, south-west Libya. Most of the samples yielded marine and non-marine palynomorphs in a fair to good state of preservation, which together with palynological data have been used to confirm the age, determine the environment of deposition, and evaluate the petroleum source potential of the Tanezzuft Formation. The palynological assemblage recovered from the basal Hot Shale contains an abundance of acritarchs, chitinozoans and cryptospores, with some taxa, such as Plectochitina sp., Evittia remota, and Tetrahedraletes medinensis, indicating an early–mid Rhuddanian (early Llandovery) age for this unit. The deposits overlying the Hot Shale yielded diverse assemblages of palynomorphs, the occurrence of Angochitina qusaibaensis and Leiofusa banderillae in particular indicating a late Rhuddanian–Telychian (Llandovery) age. Two palynofacies associations have been identified. The Hot Shale palynofacies (PF-A) contains Type-II ≥ I kerogen, which is highly oil-prone and reflects a distal suboxic–anoxic sedimentary environment. The palynofacies of the overlying deposits of the Tanezzuft Formation (PF-B) is dominated by Type-II/III kerogen, which is both oil- and gas-prone, and indicates depositional conditions that range from distal dysoxic–oxic shelf to mud-dominated oxic shelf (distal shelf). Rock-Eval pyrolysis results indicate that the Hot Shale is organically-rich with an average total organic carbon (TOC) content 7.23 wt%, whereas the TOC of the overlying deposits averages 0.62 wt%. The organic matter in the Hot Shale has the capability of generating more liquid hydrocarbons than the rest of the formation, which lies within the early oil-maturity window. A simulated burial history for the NC115 Concession allowed the time and magnitude of hydrocarbon generation from the main Silurian Tanezzuft Formation source rock to be determined. Oil generation from this source rock took place during the Carboniferous/mid-Cretaceous period, whereas the maturation level for gas had not been reached at this stage.

Characteristic of source rocks and origin of crude oils in the Raoyang Sag and Baxian Sag, Bohai Bay Basin, China: Insights from geochemical and geological analyses

Three potential source rock intervals were evaluated based on the results of Rock-Eval pyrolysis on nearly 700 rock samples and the origin of the twenty-two oil-fields was studied by the biomarker analysis on 62 source rock samples and 93 oil samples in the Raoyang Sag and Baxian Sag, Bohai Bay Basin. The first member of the Shahejie Formation (Es) was deposited in an anoxic and salted water column with the dominant contribution of algal organic matters, reflected by its rock samples with high gammacerane/C30-hopane, high ETR, high C35/C34 hopane, high steranes/hopanes, low pristane/phytane, low C27-diasterane/C27-sterane and low C19/C23 tricyclic terpane. Characterized by higher C19/C23 tricyclic terpane, higher pristane/phytane, lower steranes/hopanes and lower C35/C34 hopane than the Es1 rock samples, the biomarkers of rocks suggest that the third and forth members of the Es were deposited in the sub-oxic to anoxic environments with a significant terrestrial organism input. Further studies suggest that the best source rock interval for oil-generation is the Es1 source rock interval in the Raoyang Sag and is the Es3 source rock interval in the Baxian Sag by organic facies analysis of source rocks. Three source-related oil groups have been identified. There are two oil groups for the discovered oils in the Raoyang Sag. Group I oil, dominated by the Es1-derived oils, has been found in all the oil-fields in the Raoyang Sag, and Group II oil, mainly derived from the Es3 source rock interval, only distributes in the north-east area and in the south end of the Raoyang Sag. However, the three oil groups have been found in the Baxian Sag, but the Es3-derived oils are dominant in them and have been found in the major oil-fields in the east area and the Wen'an slope in the west area. Furthermore, the Es4-derived oils (Group III oil) mainly distribute in the Baxian Sag, without any findings in the Raoyang Sag because of the absence of the Es4 source rocks. As our studies, oils almost accumulate near their source rocks without a long-distance migration except the slope areas in the Raoyang Sag and Baxian Sag. Therefore, the source rock distribution is a key factor to oil accumulations in the Raoyang Sag and Baxian Sag, especially the efficient source rock distributions, which mainly developed in the organic facies A and B based on the geochemical and geological researches.

Source rock potential of the Early Cretaceous intervals in the Darquain field, Abadan Plain, Zagros Basin, SW Iran

The Darquain field is located in the Abadan Plain SW Iran, which has a high potential for exploration and production of hydrocarbon resources with poorly defined petroleum systems. The goal of this paper is to characterize the Cretaceous source rock potential in the Darquain field. A gamma-sonic log was used as a proxy to identify probable source rock zones and to select sample depths. A total of 37 samples were analyzed by Rock-Eval, elemental, Gas Chromatography (GC) and gas chromatographymass spectrometry (GC-MS) techniques. The petroleum generation potential, as well as origin of the organic matter of samples, have been investigated. The results of this study indicate that, in the Early Cretaceous successions, there are favorable source zones in Garau, Gadvan, and Kazhdumi Formations. These source zones predominantly contain organic matter from marine origin, suggesting kerogen type II, while some samples contain terrestrial organic matters, suggesting kerogen type III. The Lower Garau zone, with 1.14 to 14.29% total organic carbon (TOC), is an excellent source rock with a fair genetic potential in the range of 2.74 and 9.5 mg/g. Elemental analysis results in the Lower Garau zone allow the classification of kerogens as high-sulfur. There are very good source zones in the Kazhdumi Formation, with fair to good genetic potential. The results of Rock-Eval and petrophysical analyses show that gamma ray data can be used as a useful tool to determine the potential source zones, although where TOC is less than 1% there is inconsistency. The results obtained from the biomarker characteristics are in agreement with the results of Rock-Eval pyrolysis and indicated carbonate source rocks, which contain a mixture of marine organic matter with a minor amount of terrigenous organic matter. Biomarker characteristics also suggest that the organic matter was deposited in a marine environment under reducing conditions, and that Early Cretaceous source zones are at the stage of early oil window to peak of oil generation.

Hydrocarbon generation modeling and source rock characterization of the Cretaceous\u2013Paleocene Taratu Formation, Great South Basin, New Zealand

Hydrocarbon generation modeling and source rock characterization have been carried out on rock samples of the Taratu Formation in the Great South Basin, New Zealand. The Paleocene and Late Cretaceous Taratu Formation samples from Tara-1 well are utilized for geochemical studies. Rock-Eval pyrolysis results show that Taratu formation accommodates organic matter of excellent quantity and quality, with proliferous kerogen type II-III (oil and gas prone) and minor kerogen type III (gas prone). Hydrogen index (HI) of this formation ranges from 165.0 to 327.5 mg HC/g TOC and only Late Cretaceous source rock samples are thermally mature, with maximum pyrolysis temperature (Tmax) up to 459 °C and vitrinite reflectance (% Ro) from 0.40 to 1.15% Ro. One-dimensional basin modeling shows a best fit in a calibration of measured and modeled temperatures and vitrinite reflectance. The top of oil window was encountered 51 Ma ago at 3100 m and gas generation took place at 4132 m in 8 Ma ago.

Origin of petroleum accumulation in the Chaheji-gaojiapu structural belt of the Baxian Sag, Bohai Bay Basin, China: Insights from biomarker and geological analyses

Abstract The origin of petroleum accumulations in the Chaheji-gaojiapu structural belt of the Baxian Sag, Bohai Bay Basin was evaluated based on the results of Rock-Eval pyrolysis on 135 samples and a biomarker analysis on 26 source rock samples and 33 oil samples. The four possible source rock intervals have different biomarker assemblages and were deposited in different environments. For example, pristane/phytane, C27-diasterane/C27-sterane and C19/C23-tricyclic terpane ratios show an increasing trend, but (C28+C29)-tricyclic terpane/[(C28+C29)-tricyclic terpane + Ts] and steranes/hopanes parameters display a decreasing trend among the lower part of the first member (Es1L) and the middle (Es3M) and lower part (Es3L) of the third member of the Eocene Shahejie Formation. This finding indicates that a decreasing anoxic and alkaline environment with an increasing input of terrigenous organic matter developed during the deposition of the Es1L, Es3M and Es3L source rocks. However, the biomarker parameters of the forth member (Es4) of the Eocene Shahejie Formation display highly similar characteristics with the Es3L source rocks, except for the C29-sterane 20S/(20S + 20R) and C27-diasterane/C27-sterane ratios, which show obviously higher than the other source rock values. The Es3-derived oils are absolutely dominant in the Chaheji-gaojipu structural belt, based on the biomarker analysis of saturated hydrocarbon, with slight or no contributions from the Es1L and Es4 source rocks because of the low maturation for the Es1L source rock and the absence of vertical migrating channels for the Es4 source rock. Faults are vital to petroleum migration and accumulation in this area and demonstrate the following double effects: (1) the deep faults cutting off the Es3 source rocks are the key channels for oil vertical migration; (2) the shallow faults entrap oil and finally form the commercial oil pools. As a result, the fault block reservoir is the major oil-reservoir type in the Chaheji-gaojiapu structural zone, and the lithologic reservoir is another oil-reservoir type in this area. Based on 1D burial and thermal history modelling, the E3 and E4 source rocks reached the oil-generation peak at approximately 5 Ma and 20 Ma, respectively, but the Es1L source rock is still in the low-mature stage. Therefore, the process of the large oil migration and accumulation for the Es3 source rocks occurred during the late Neogene-Quaternary. Through this research, there are two considerable exploration potentials for this area, including condensate reservoirs in the deep strata and low-mature reservoirs in the Es1 stratum interval.

Estimating source rock parameters using wireline data: An example from Dezful Embayment, South West of Iran

Availability and high potential of wireline data to correlate with geochemical properties convinced petroleum geologists to use them for source rock detection and calculating their richness. In this research, intelligent techniques and mathematical relationships were used to evaluate source rock potential and organic matter type indirectly. Artificial neural networks (ANN) and ΔLogR techniques were successfully used to model the relation between wireline logs and Total Organic Carbon (TOC) content. Furthermore, wireline data and TOC values were used as input data to model a second ANN for S2 parameter (present hydrocarbon potential) calculation. Owing to its great ability in the course of solving non-linear problems with overwhelming complexity, the back propagation method was used to train the networks using 70 points datasets. Predicted TOC contents were validated by Rock-Eval pyrolysis results of which revealed dependency of the ΔLogR accuracy to the organic richness and lithology, and therefore higher precision of the ANN outputs in compare to the ΔLogR results.Hydrogen Index (HI) and kerogen type were also effectively predicted using mathematical relationship between TOC and S2 factors. Reliability of all steps of the methodology was approved using a 16 members retest dataset for which testing predicted parameters against measured data demonstrated good correlation coefficients combined with negligible errors. Finally, applicability of the methodology was checked by applying it on two wells in the Dezful Embayment to evaluate geochemical and depositional properties of the Paleocene-Early Oligocene Pabdeh Formation.

Rock-Eval Pyrolysis Results from the Bijeel 1 Well, Kurdistan Region, Iraq

We used Rock-Eval pyrolysis to examine the petroleum source potential of rock samples from the Bijeel 1 Well in Kurdistan Region of northern Iraq. The results show that Sargelu and Sehkaniyan marine Type IIS kerogen are potential sources of hydrocarbons and are thermally mature with respect to the oil window. In the samples that we studied, carbonate are more organic-rich and more oil-prone than carbonaceous shales and silty mudstones, which appear to be potential sources of natural gas. The Paleocene rocks from Bijeel 1 Well are thermally immature. Lithologically similar rocks may be present in the deeper parts of the subsurface of Iraqi Kurdistan located south of the Bijeel 1 Well, where they may have been buried deeply enough to generate oil and (or) gas. The Tertiary rocks are sparsely examined and mostly unexplored and no commercial production of hydrocarbons has been obtained. However, the existence of potential source rocks of oil and gas, as shown by our Rock-Eval results, suggests that undiscovered petroleum accumulations may be present in the area.

Hydrocarbon source potential of the Tanezzuft Formation, Murzuq Basin, south-west Libya: An organic geochemical approach

A detailed organic geochemical study of 20 core and cuttings samples collected from the Silurian Tanezzuft Formation, Murzuq Basin, in the south-western part of Libya has demonstrated the advantages of pyrolysis geochemical methods for evaluating the source-rock potential of this geological unit. Rock-Eval pyrolysis results indicate a wide variation in source richness and quality. The basal Hot Shale samples proved to contain abundant immature to early mature kerogen type II/III (oil–gas prone) that had been deposited in a marine environment under terrigenous influence, implying good to excellent source rocks. Strata above the Hot Shale yielded a mixture of terrigenous and marine type III/II kerogen (gas–oil prone) at the same maturity level as the Hot Shale, indicating the presence of only poor to fair source rocks.