Hydrocarbon Potential Of Source Rocks Research Articles

Identifying the hydrocarbon potential from seismic, geochemical, and wireline data of the Sallum intra-basin, North Western Desert of Egypt

ABSTRACT The current study's objectives are to identify the primary source rock's hydrocarbon potential and, using various approaches, examine the Sallum Concession's petroleum system, which lies in the extreme northwestern part of the Western Desert of Egypt. We integrated seismic, geochemical, and well logging data. As a result, the structure analysis indicates that the area is elevated topographic land, representing a high intra-basin about the surrounding Faghour, Matrouh, and Shushan basins. Therefore, the site is a significant concession with various source rocks; Khatatba (Safa member) and Alam El-Buieb (AEB-3A member) are the oil-prone source rocks of the northern and southern parts of the area with high TOC (up to 11.3%) and mid-mature stage (0.7-1.0% Ro) at depth below 8000 ft. On the other hand, the Paleozoic Desouqy, Zeitoun, and Shiffah formations, located below 12000 ft, are gas-prone source rocks with high organic contents (TOC 1.41-4.64%) and fair potential for gas generation and are currently in the mid-mature stage (0.7-1.0% Ro). We concluded that the concession's low oil production might result from a delay in Kerogen maturity and hydrocarbon migration. Finally, the East of Sallum concession is the only potential area because the wells in the west do not show reservoirs characteristics.

Constraining the geothermal parameters of in situ Rb–Sr dating on Proterozoic shales and their subsequent applications

Abstract. Recent developments in tandem laser ablation mass spectrometer technology have demonstrated the capacity for separating parent and daughter isotopes of the same mass online. As a result, beta-decay chronometers can now be applied to the geological archive in situ as opposed to through traditional whole-rock digestions. One novel application of this technique is the in situ Rb–Sr dating of Proterozoic shales that are dominated by authigenic clays such as illite. This method can provide a depositional window for shales by differentiating signatures of early diagenetic processes versus late-stage secondary alteration. However, the hydrothermal sensitivity of the Rb–Sr isotopic system across geological timescales in shale-hosted clay minerals is not well understood. As such, we dated the Mesoproterozoic Velkerri Formation from the Altree 2 well in the Beetaloo Sub-basin (greater McArthur Basin), northern Australia, using this approach. We then constrained the thermal history of these units using common hydrocarbon maturity indicators and modelled effects of contact heating due to the intrusion of the Derim Derim Dolerite. In situ Rb–Sr dating of mature, oil-prone shales in the diagenetic zone from the Velkerri Formation yielded ages of 1448 ± 81, 1434 ± 19, and 1421 ± 139 Ma. These results agree with previous Re–Os dating of the unit and are interpreted as recording the timing of an early diagenetic event soon after deposition. Conversely, overmature, gas-prone shales in the anchizone sourced from deeper within the borehole were dated at 1322 ± 93 and 1336 ± 40 Ma. These ages are younger than the expected depositional window for the Velkerri Formation. Instead, they are consistent with the age of the Derim Derim Dolerite mafic intrusion intersected 800 m below the Velkerri Formation. Thermal modelling suggests that a single intrusion of 75 m thickness would have been capable of producing a significant hydrothermal perturbation radiating from the sill top. The intrusion width proposed by this model is consistent with similar Derim Derim Dolerite sill thicknesses found elsewhere in the McArthur Basin. The extent of the hydrothermal aureole induced by this intrusion coincides with the window in which kerogen from the Velkerri Formation becomes overmature. As a result, the mafic intrusion intersected here is interpreted to have caused kerogen in these shales to enter the gas window, induced fluids that mobilize trace elements, and reset the Rb–Sr chronometer. Consequently, we propose that the Rb–Sr chronometer in shales may be sensitive to temperatures of ca. 120 ∘C in hydrothermal reactions but can withstand temperatures of more than 190 ∘C in thermal systems not dominated by fluids. Importantly, this study demonstrates a framework for the combined use of in situ Rb–Sr dating and kerogen maturation indicators to help reveal the thermochronological history of Proterozoic sedimentary basins. As such, this approach can be a powerful tool for identifying the hydrocarbon potential of source rocks in similar geological settings.

Geochemical Evaluation for the Hydrocarbon Potential of Source Rocks in Central Sirt Basin, (concession -59), case study, Libya

The Sirt Basin important oil producing area in Libya is one of the richest regions in terms of hydrocarbon resources. Exploration studies of this area have shown that the oils are mixtures of several charges and may be from different source rocks particularly in the upper Cretaceous sediments this study based on organic geochemistry and organic petrographic analysis carried out on 179 cutting samples collected from four wells. From Cenomanian to upper Eocene succession within the central Sirt basin, the main aim of this study geochemical evaluation of source rocks, thermal maturation and estimate the other source rock in the area. The recorded geochemical values varied in these wells from one formation to another depending on lithology, paleoenvironment and tectonic events. Our results exposed that, The total organic carbon (TOC) values using Rock-Eval analysis showed that the Sirt Shale is considered the most important regard to hydrocarbon source potential, since it was found to reflect a high total organic carbon content 4.98 %. , (TOC) ranging (average 2.61), type–II kerogen (oil prone) and, with Hydrogen index (HI) mostly below 500. Rachmat average HI = 176 (kerogen types II, III), Organic facies analysis classified Sirt Shale in class B with dominantly amorphous high quality organic matter deposited in anoxic marine environment. Maturity evaluation result of Ro %, SCI, and Tmax oC, Formations are late immature to early mature stages.

Effect of sediment source on source rock hydrocarbon potential; An example from the Kimmeridgian and Tithonian-aged source rocks of the central ridge, off-shore Newfoundland, Canada

This study presents an integrated approach using organic geochemistry and incident-light organic petrographic microscopy techniques to characterize kerogen type, hydrocarbon potential, thermal maturity, and the effect depositional environment has on five wells from Upper-Jurassic Kimmeridgian and Tithonian-aged source rock intervals in the Central Ridge area offshore Newfoundland, Canada. The results show that hydrocarbon potential in these organic-rich marine mudrocks is mainly dependent on depositional environment and present-day burial depth of the sediments. Oscillations and transitions between (i) rocks with dominant allochthonous organic matter (OM) (including primary/reworked vitrinite and inertinite macerals) representing high influence by continental sediments (e.g., deltaic and littoral depositional environment) and (ii) rocks with dominant autochthonous OM (fluorescing liptinites such as alginite and their degraded remains) indicating more distal, productive marine continental shelf depositional environment. The latter is of main interest to this study as it is the only rock type that has the capability to generate oil while the former has very little contribution to oil generation potential due to the abundance of hydrogen-poor organic matter. The secondary maceral, solid bitumen, occurs within the mature section in the deeper part of the basin. Measured %VRo on vitrinite macerals ranges from 0.62 to 0.82% on four of the five wells studied indicating early oil window to oil window thermal maturity due to the mixing of the organic matter types mentioned above. Integrating Fluorescent Red/Green (R/G) quotient measurements from high intensity fluorescing alginite range from 0.77 to 0.86. Conversion of these values to %VRo equivalent range 0.58–0.66% indicates that thermal maturity has not yet reached the primary oil generation window. Vitrinite reflectance equivalent derived from solid bitumen (%BRo) in the deepest buried well ranges 1.10–1.16% indicating wet gas thermal maturity.

Geochemical Evaluation for the Hydrocarbon Potential of Source Rocks in the Anza Basin

Anza basin is located in the extensional arm of the central African rift system in the North-Eastern part of Kenya. Cretaceous sedimentary rocks were sampled from the four wells namely, Chalbi-3, Sirius-1, Ndovu-1 and Kaisut-1. Anza basin occurs on a fault block within a Paleocene-Cretaceous rift basin. The methodological approach used for the evaluation of source rocks included petrophysical and geochemical methods to ascertain their potential. Well sections with a higher shale-volume ratio were sampled for geochemical screening to determine the organic richness and thermal maturity of potential source rocks, respectively. Source rock with organic richness ≥ 0.5% were evaluated further for their petroleum potential using Rock-Eval pyrolysis to determine their thermal maturity, organo-facies and in-situ generated hydrocarbons present in sedimentary facies. The geochemical evaluation of rock samples from the drilled wells’ sections of Chalbi-3 and Sirius-1 confirmed both oil and gas potential. Gas Chromatography and Mass Spectrometry (GCMS) were used to characterize the biomarker signatures and oil-oil correlation of Sirius-1 samples. A predictive model was developed to integrate the petrophysical and geochemical data to reveal hydrocarbons’ potential in the Anza basin.

Prediction of total organic carbon at Rumaila oil field, Southern Iraq using conventional well logs and machine learning algorithms

Abstract Total organic carbon (TOC) is an important parameter for assessing the hydrocarbon potential of source rocks. The standard method for analysis of TOC is the Rock-Eval pyrolysis on cutting and core samples. The coring process is always expensive and time consuming. Therefore, researchers around the world focused on developing techniques to estimate TOC and other organic parameters from readily available well logs data that are almost available in all wells. In this study, we evaluated the use of three machine learning models namely, random forest (RF), rotation forest (rF), k nearest neighbors (KNN) to estimate TOC based on conventional well logs data. The well logs involved gamma ray, acoustic, density, neutron, and deep resistivity. The efficacy of the models was tested against the most widely used backpropagation artificial neutral network (BPANN) and support vector regression (SVR) models. North Rumaila oilfield in southern Iraq was taken as a case study. The models were trained and tested using data from two wells in the field, namely R-167 and R-172. The number of TOC measurements used for training and testing were 40 (R-167) and 18 (R-172), respectively. The efficacy of the used algorithms was evaluated using mean absolute error (MAE), root mean squared error (RMSE), and correlation of determination (R2). The models are also visually compared using Taylor diagram and violin plot to distinguish the best performance model. Results indicated the KNN was the best followed by RF and then rF. The worst performance models were BPANN and SVR models. This study confirmed the ability of machine learning models for building efficient model for estimating TOC from readily available borehole logs data without the need for very expensive coring process.

Organic geochemistry, distribution and hydrocarbon potential of source rocks in the Paleocene, Lishui Sag, East China Sea Shelf Basin

Abstract The Lishui Sag, one of the most promising hydrocarbon exploration areas in the East China Sea Shelf Basin, has had no major breakthroughs after its exploration and development. Therefore, it is crucial to carry out a comprehensive assessment of this basin to illustrate the potential and distribution of source rocks in the Lishui Sag. Based on organic petrographic examinations, Rock-Eval pyrolysis, gas chromatography (GC) and gas chromatography–mass spectrometry (GC–MS) analysis, the organic geochemical characteristics and paleoenvironment of the source rocks were investigated. The results imply that the kerogen type of the source rocks in the Lishui Sag is dominated by Type III, with a small amount of Type II kerogen. Biomarkers show that the source rocks are characterized by a mixed origin of organic matter in a transitional environment. The lower Mingyuefeng (E1ml), lower Lingfeng (E1ll) and Yueguifeng (E1y) Formations show higher inputs of aquatic organic matter. The base limits of the total organic carbon (TOC) values of effective source rocks were determined to be 0.9 wt % in the E1m Formation, 1.0 wt % in the E1l Formation and 0.7 wt % in the E1y Formation. Based on an artificial neural network (ANN) model and the Δlog R method, the distribution of effective source rocks in the Lishui Sag was illustrated. Source rocks in the E1ml and Lingfeng (E1l) Formations can be expected to generate mixed liquid hydrocarbons, while samples from E1y Formation are oil prone source rocks with normal oil and light oil potentials. Additionally, the post mature source rocks of the E1y Formation may be the origin of natural gas. Upon full consideration of the potential and distribution of source rocks, the North part of the Lingfeng Uplift is the most favorable exploration zone.

Basin modelling of the SW Barents Sea

Abstract The SW Barents Sea is an epicontinental platform consisting of N- to NNE-oriented basins separated by basement highs. The basins were formed during four distinct rift-phases in the Carboniferous, Late Permian, Late Jurassic-Early Cretaceous, and Paleocene-Eocene. Progressive rifting culminated in continental breakup and seafloor spreading along the North Atlantic axis approximately at 55 Ma. We present tectonic and thermal models of basin evolution along two seismic profiles crossing the SW Barents Sea. The thermal and isostatic history of basins is constrained through time-forward basin modelling based on an automated inverse basin reconstruction approach. We estimate the effects of continental breakup and near-margin processes (magmatic underplating and sill intrusions) on the thermal history and kerogen maturity below the Vestbakken Volcanic Province. Basin models are calibrated against well data. The results imply that both breakup and underplating alter the thermal and isostatic history of sediments along the margin. The hydrocarbon potential of source rocks modelled along the margin suggests breakup has a permanent thermal effect on the present-day sediments promoted by lateral heat flow, while heat conduction by underplating is more diffuse, inhibited to some degree by deeply-buried, low-conductivity shales and limestones.

A New Scheme to Improve the Performance of Artificial Intelligence Techniques for Estimating Total Organic Carbon from Well Logs

Total organic carbon (TOC), a critical geochemical parameter of organic shale reservoirs, can be used to evaluate the hydrocarbon potential of source rocks. However, getting TOC through core analysis of geochemical experiments is costly and time-consuming. Therefore, in this paper, a TOC prediction model was built by combining the data from a case study in the Ordos Basin, China and core analysis with artificial intelligence techniques. In the study, the data of samples were optimized based on annealing algorithm (SA) and genetic algorithm (GA), named SAGA-FCM method. Then, back propagation algorithm (BPNN), least square support vector machine (LSSVM), and least square support vector machine based on particle swarm optimization algorithm (PSO-LSSVM) were built based on the data from optimization. The results show that the intelligence model constructed based on core samples data after optimization has much better performance in both training and validation accuracy than the model constructed based on original data. In addition, R2 and MRSE in PSO-LSSVM are 0.9451 and 1.1883, respectively, which proves that models established with optimal dataset of core samples have higher accuracy. This study shows that the quality of sample data affects the prediction of the intelligence model dramatically and the PSO-LSSVM model can present the relationship between well log data and TOC; thus, PSO-LSSVM is a powerful tool to estimate TOC.

Clay mineral diagenesis and source rock assessment in the Bornu Basin, Nigeria: Implications for thermal maturity and source rock potential

An understanding of the mineral and organic matter modifications during burial are critical in assessments of potential source rocks in petroleum exploration studies. Here, we examined the relationships between clay mineral diagenesis and organic thermal indicators (vitrinite reflectance and Rock-Eval Tmax) to constrain the thermal maturity and hydrocarbon potential of source rocks in the Mbeji-1 well in the northeastern part of the Cretaceous/Tertiary Bornu Basin. X-ray diffraction mineralogical data show that the <2 μm clay-sized fraction consist of mixed layer illite/smectite (I/S), kaolinite, illite, and Fe-chlorite clay mineral assemblages. The major diagenetic changes in the clay mineral evolution are transformation of random (R0) to ordered (R1) illite/smectite (I/S) mixed layer between ∼2500 m and ∼3640 m depths, decrease in smectite in I/S with burial, and appearance of chlorite at ∼2500 m. Total organic carbon and Rock-Eval pyrolysis parameters (HI, S2, Tmax) indicate presence of lean shales consisting of gas prone to inert terrestrial organic matters. Source rocks at shallower depths below 2500 m are immature while those below this level within lower Fika Formation to upper Gongila formations are marginally matured with respect to hydrocarbon generation. The variation between I/S transformation and VR for the Mbeji-1 well shows a delay in illitization process compare to organic matter maturity. We considered that other than temperature, insufficient and variable potassium availability, and short-heating time resulted in retarding the smectite illitization reaction relative to the organic matter parameters (vitrinite reflectance and Tmax). These differences further demonstrates that organic matter responds quickly to increasing temperature than mineral reactions at short heating time in young sedimentary basins.

Influence of refractory organic matter on source rock hydrocarbon potential: A case study from the Second White Specks and Belle Fourche formations, Alberta, Canada

Dilution by inert, refractory organic carbon can have a significant impact on the hydrocarbon potential of source rocks. In this study, a correction of total organic carbon, based on petrographic observations, is proposed to give a better indication of hydrocarbon generation potential. This correction shows that although the Second White Specks Formation is an excellent hydrocarbon source rock, hydrogen index and total organic carbon are influenced by dilution from refractory organic carbon of various sources. The results show that a higher degree of dilution occurs within the Belle Fourche Formation than the Second White Specks Formation. This dilution can have a significant impact on the hydrocarbon potential of the rock.Volumetric calculation of the inert carbon fraction using organic petrographic methods provides a semi quantitative method to correct total organic carbon values for the refractory organic carbon dilution effect. Incorporation of the dilution corrected organic carbon value in hydrogen index calculations allows a greater understanding of source rock hydrocarbon potential. This method provides better differentiation of the small scale variation between micro-facies and formation, as observed in the Second White Specks and Belle Fourche formations, than traditional bulk geochemical methodologies and previously proposed correction methodologies. Degree of dilution, either through transport of recycled allochthonous or autochthonous reworking of organic matter in-situ is highly variable and represents a significant challenge in the characterization of heterogeneous source rocks.This study investigates the organic petrology and geochemistry of a sediment core from the thermally immature area of the Upper Cretaceous Second White Specks Formation and Belle Fourche Formation. Reflectance and relative abundance of three maceral groups (bituminite, alginite, and refractory organic carbon macerals) showed significant organic matter compositional differences between micro-facies in the Second White Specks Formation. A change is also observed in organic matter composition from the upper part of the Belle Fourche Formation to the Second White Specks Formation. These compositional changes represent shifts in sediment source, sea floor oxygen levels, and depositional energy levels. These changes can be episodic, as observed between micro-facies, or longer time scale trends, as observed between the studied formations.

Organic geochemistry and hydrocarbon potential of source rocks from the Mohe Formation of the Upper Jurassic in the Mohe Basin, northeast China

The Mohe Formation is one of the important source rocks for oil-gas and gas hydrates in the Mohe Basin. In this paper, mudstone from cores of the M-1 and M-3 wells and argillite from cores of the MK-2 well of the Mohe Basin were studied. The depositional environment, organic matter source, thermal maturity, kerogen type, and hydrocarbon generation potential of the core samples were determined using organic and inorganic geochemistry. The dual sources of organic matter were terrestrial plants and aquatic organisms. The organic matter was deposited in a reducing lacustrine environment. The lake water salinity was higher when argillite was deposited. The late stage of the sedimentary filling of the lacustrine basin was characterized by high sulfate contents. The source rocks primarily contained Type II2–III kerogen. The present-day thermal maturity parameters reveal that the organic matter of the Mohe Formation is mature to overmature, indicating that this unit is capable of generating gas condensate and dry gas. In addition, we compared the organic geochemistry characteristics of mudstone and argillite. The results indicate that TOC, S1 + S2, and HI are lower in argillite than in mudstone. Although the biomarker maturity parameters cannot reflect the thermal evolution of the source rocks, they reflect the source of the organic matter and the depositional environment. The results provide important constraints for the evaluation of the hydrocarbon potential of lacustrine source rocks of the Mohe Formation from the Upper Jurassic and for the location of petroleum resources in the Mohe Basin.

Palaeoenvironment and its control on the formation of Miocene marine source rocks in the Qiongdongnan Basin, northern South China Sea.

The main factors of the developmental environment of marine source rocks in continental margin basins have their specificality. This realization, in return, has led to the recognition that the developmental environment and pattern of marine source rocks, especially for the source rocks in continental margin basins, are still controversial or poorly understood. Through the analysis of the trace elements and maceral data, the developmental environment of Miocene marine source rocks in the Qiongdongnan Basin is reconstructed, and the developmental patterns of the Miocene marine source rocks are established. This paper attempts to reveal the hydrocarbon potential of the Miocene marine source rocks in different environment and speculate the quality of source rocks in bathyal region of the continental slope without exploratory well. Our results highlight the palaeoenvironment and its control on the formation of Miocene marine source rocks in the Qiongdongnan Basin of the northern South China Sea and speculate the hydrocarbon potential of the source rocks in the bathyal region. This study provides a window for better understanding the main factors influencing the marine source rocks in the continental margin basins, including productivity, preservation conditions, and the input of terrestrial organic matter.

An isotopic study of hydrocarbon generation processes

The sources of reservoired liquid hydrocarbons in Australia differ substantially from their Northern Hemisphere counterparts. Not only are Australian source rocks largely of terrigenous origin but the concepts accepted as defining the hydrocarbon potential of source rocks have recently been challenged. Although isotopic measurements on Australian source rocks and liquid hydrocarbon products closely parallel those published from elsewhere, new interpretations of these data have been made, particularly with regard to D/H ratios in coals. As interesting as such results may be, the most important findings relate to the origins and histories of methane, the higher gaseous hydrocarbons and carbon dioxide, and the interpretation of these data in terms of hydrocarbon genesis. Simple Northern Hemisphere concepts which characterize gases as being biogenic, oil-associated, etc., on the bases of their isotopic and chemical compositions are clearly not applicable to the Australian scene. Indeed justification of such precise classifications in the Northern Hemisphere on the available evidence is also questioned. Isotopic and compositional data from gases from the Cooper, Bowen, Sydney and Gippsland Basins and from the North West Shelf (Australia) are reviewed, and assessed in terms of generation pathways.