Comparisons of pyrolysis parameters between source rocks and their clay-sized fractions: Implication for source material of hydrocarbon generation

In natural environments, organic-clay interactions are strong and cause organo-clay composites (a combination between organic matter [OM] and clay minerals) to be one of the predominant forms for OM occurrence, and their interactions greatly influence the hydrocarbon (HC) generation of OM within source rocks. However, despite occurring in nature, dominating the OM occurrence, and having unique HC generation ways, organo-clay composites have rarely been investigated as stand-alone petroleum precursors. To improve this understanding, we have compared the Rock-Eval pyrolysis parameters derived from more than 100 source rocks and their corresponding <2 μm clay-sized fractions (representing organo-clay composites). The results show that all of the Rock-Eval pyrolysis parameters in bulk rocks are closely positively correlated with those in their clay-sized fractions, but in clay-sized fractions the quality of OM for HC generation is poorer, in that the pyrolysable organic carbon levels and hydrogen index values are lower, whereas the residual organic carbon levels are higher than those in bulk rocks. Being integrated with the effects of organic-clay interactions on OM occurrence and HC generation, our results suggest that organo-clay composites are stand-alone petroleum precursors for HC generation occurring in source rocks, even if the source rocks exist in great varieties in their attributes. Our source material for HC generation comprehensively integrates the original OM occurrence and HC generation behavior in natural environments, which differs from kerogen and is much closer to the actual source material of HC generation in source rocks, and it calls for further focus on organic-mineral interactions in studies of petroleum systems.

Biomarkers in Source Rocks from Barreirinha Formation (Devonian): Distribution and Paleoenvironment Significance

The Barreirinha Formation-Upper Devonian, is the main petroleum source rock of the Amazon Basin, deposited during the great Devonian Transgression, contributing to significant accumulations of organic matter (OM) in anoxic conditions, which allowed its preservation. The present work had the objective of characterizing the molecular composition of biomarkers in outcrops samples of the Barreirinha Formation, aiming to evaluate the paleoenvironment, thermal evolution, and the preservation of OM total organic carbon (TOC) and Rock-Eval pyrolysis indicate considerable amounts of immature OM deposited in a low oxygenation environment. Gas chromatographymass spectrometry (GC-MS) and gas chromatography-tandem mass spectrometry (GC-MS/MS) data corroborate that the OM was deposited in a suboxic to the oxic environment and low salinity (absence or low relative abundance of β-carotane and gammacerane). 24-N-Propyl-cholestane was detected and identified by synthetic pattern co-injection. High concentrations of tetracyclic polyprenoids (TPPs) in ascending order from base to top, high hopane/sterane ratios, to suggest that the samples had a high molecular weight n-alkanes, C29 steranes, low thermal evolution, and anoxic depositional paleoenvironment.

Paleoenvironments and Hydrocarbon Potential of Upper Cretaceous Shales in Agbabu-1 Well, Dahomey Basin SW Nigeria

Upper Cretaceous shales partially exposed in the northern fringes of the Dahomey Basin are well developed in the subsurface in Southwestern part of the basin where Agbau-1 well is sited. These shales were evaluated in respect to their paleoenvironments and potentials for hydrocarbon using foraminiferal assemblages, biomarkers and Rock Eval pyrolysis studies. The dominance of benthonic foraminifera species suggests a shallow marine environment and high percentage of calcareous to arenaceous benthic www.eujournal.org 195foraminifera indicate high water salinity and hypersline environment. Dysoxic oxygen condition is also prevalent probably because most of the benthic foraminifera recovered are epifauna that live in a reduced oxygen condition. 1.90 wt%, 244 mgHC/gTOC and 429℃ average values of total organic carbon, hydrogen index and Tmax reveal that the Upper Cretaceous shales have relatively fair to good organic matter, predominantly Type II-III kerogen and currently immature. Though three is a trend of an increase in maturity down the hole. All the steranes have uniform distributions (C27>C28>C29), suggesting a relatively higher input from the marine red algae and a low level of land plant contribution to the source organic matter. Pristane/phytane ratios and C29/C27 steranes confirmed the organic matter type to be a Type II/III and anoxic source rock depositional condition as well as a reducing diagenetic system in the sediment water column. The Upper Cretaceous shales in Dahomey Basin can be targeted for exploration as an unconventional petroleum resource.

Significance of petroleum seepages in hydrocarbon exploration-case study of Khourian Desert, Central Iran

Hydrocarbon exploration has long been based on such costly and time-intensive methods as geophysical surveys, geological studies, and drilling. In recent years, however, researchers have started to consider such inexpensive alternatives as surface geochemistry for hydrocarbon exploration. Some 100 years ago, the leakage of hydrocarbons onto the surface in the form of micro- and macro-seepages motivated researchers toward drilling a well in the Khourian Desert in the south of Semnan Province, Iran. Upon drilling the well, researchers found evidences of non-released (free) hydrocarbons. These findings drove further study of the area using surface geochemistry while considering the nearby hydrocarbon accumulation in Qom Formation. Conventional and indirect surface geochemical methods provide an insight into the relationship between surface and subsurface hydrocarbons. In the present work, the results of the Rock–Eval pyrolysis showed total organic carbon (TOC) values in the range of 0.31–4.13 wt.% and S1 peaks between 0.07 and 27.35. Sulfur isotope analysis showed a sulfur isotopic value of −0.4. The study of hydrocarbon-oxidizing bacteria showed the presence of bacterial colonies in MSM at 1.22 × 106 cfu/g of soil sample. We further investigated surface changes due to the presence of free hydrocarbons and pH variations (4.9–8) resulted from the changes in the concentrations of calcium carbonate and iron. According to the results and given the presence of organic sulfur in the samples, the occurrence of Gach-i-turush and alike phenomena was proposed in this area. The results of geo-microbial prospecting method, surface secondary changes, and sulfur isotope studies were well in agreement with the characteristics of the existing hydrocarbon reserves in this area. Surface geochemical surveys can precede other geochemical and geophysical surveys to identify surface anomalies and hence focus on more probable locales of hydrocarbon accumulation in the Khourian Desert, central Iran.

Ensemble Learning for Predicting TOC from Well-Logs of the Unconventional Goldwyer Shale

Precise estimation of total organic carbon (TOC) is extremely important for the successful characterization of an unconventional shale reservoir. Indirect traditional continuous TOC prediction methods from well-logs fail to provide accurate TOC in complex and heterogeneous shale reservoirs. A workflow is proposed to predict a continuous TOC profile from well-logs through various ensemble learning regression models in the Goldwyer shale formation of the Canning Basin, WA. A total of 283 TOC data points from ten wells is available from the Rock-Eval analysis of the core specimen where each sample point contains three to five petrophysical logs. The core TOC varies largely, ranging from 0.16 wt % to 4.47 wt % with an average of 1.20 wt %. In addition to the conventional MLR method, four supervised machine learning methods, i.e., ANN, RF, SVM, and GB are trained, validated, and tested for continuous TOC prediction using the ensemble learning approach. To ensure robust TOC prediction, an aggregated model predictor is designed by combining the four ensemble-based models. The model achieved estimation accuracy with R2 value of 87%. Careful data preparation and feature selection, reconstruction of corrupted or missing logs, and the ensemble learning implementation and optimization have improved TOC prediction accuracy significantly compared to a single model approach.

Changing depositional environments in the semi-restricted Late Jurassic Lemeš Basin (Outer Dinarides; Croatia)

The up to 450 m-thick Upper Jurassic Lemeš Formation includes organic-rich deep-water (max. ~ 300 m) sedimentary rocks deposited in the Lemeš Basin within the Adriatic Carbonate Platform (AdCP). The Lemeš Formation was investigated regarding (1) bio- and chemostratigraphy, (2) depositional environment, and (3) source rock potential. A multi-proxy approach—microfacies, Rock–Eval pyrolysis, maceral analysis, biomarkers, and stable isotope ratios—was used. Based on the results, the Lemeš Formation is subdivided from base to top into Lemeš Units 1–3. Deposition of deep-water sediments was related to a late Oxfordian deepening event causing open-marine conditions and accumulation of radiolarian-rich wackestones (Unit 1). Unit 2, which is about 50 m thick and Lower early Kimmeridgian (E. bimammatum to S. platynota, ammonite zones) in age, was deposited in a restricted, strongly oxygen-depleted basin. It consists of radiolarian pack- and grainstones with high amounts of kerogen type II-S organic matter (avg. TOC 3.57 wt.%). Although the biomass is predominantly marine algal and bacterial in origin, minor terrestrial organic matter that was transported from nearby land areas is also present. The overlying Unit 3 records a shallowing of the basin and a return to oxygenated conditions. The evolution of the Lemeš Basin is explained by buckling of the AdCP due to ophiolite obduction and compressional tectonics in the Inner Dinarides. Lemeš Unit 2 contains prolific oil-prone source rocks. Though thermally immature at the study location, these rocks could generate about 1.3 t of hydrocarbon per m2 surface area when mature.

The Effect of High Power Laser on Organic-Rich Shales

The objective of this work is to characterize the effect of a high power laser (HPL) on organic-rich shales. The analysis combines machine learning with advanced characterizations to reveal the geochemical and mechanical transformations induced by high power laser in source rocks. Lab results showed that HPL improves permeability, increases porosity, modifies the mechanical structure of the rock, and may positively affect the maturity of source rocks. A high power laser was used in the lab to perforate and heat different types of source rocks with varying organic content. The process was characterized in real time using near-infrared spectroscopy and mid-IR thermography. The pre- and post-characterization process draws on different tools to evaluate the chemical and structural transformations induced by the HPL processes. This step included several spectroscopy techniques (e.g., FTIR, UV/VIS/NIR), Rock-Eval, and differential thermal analysis (DTA). The analysis leverages on clustering techniques to reveal the distinct effects of HPL on source rocks. The spectroscopy and geochemical analyses revealed that that HPL modifies the molecular structure of the rock. Yet, the fundamental structure of the rock remains intact. The changes are revealed by clustering analysis of the FTIR data before and after laser heating. The analysis show the formation of clusters after the process, which correspond to the maturation of the organic content. The success of the lab work proved that high power laser could enhance the properties of source rocks. The effects include permeability improvement, enhanced porosity, and changes in the molecular distribution of the organic content. The results of the analyses suggest that the laser can drive forward the maturity of the source rock. This work also illustrates how machine learning and multiphysics characterization can reveal the dynamics of the HPL processes and their effects. Ultimately, the outcome of this study will contribute to the development of novel HPL applications.

Organic geochemistry and mineralogical characterization of the Paleocene Ranikot Formation shales in selected areas of Southern Indus Basin Pakistan.

Southern Indus Basin is one of the promising regions in Pakistan as a commercially producing oil and gas perspective. The current research presents the geochemical characterization of the Ranikot Formation shales from Southern Indus Basin based on total organic carbon (TOC), Rock-Eval (RE) pyrolysis, organic petrography, gas chromatography-mass spectrometry (GC-MS), and x-ray diffraction (XRD) analyses. The average TOC of Ranikot shale is 4.6 wt. %, indicating very good hydrocarbon potential. Types III/IV kerogens were identified in Ranikot shale. The maceral data also suggest that the Type of kerogen present in Ranikot shale is dominantly Types II-III, with the minor occurrence of Type IV. The vitrinite reflectance, pyrolysis Tmax and methylphenanthrene indices values specify immature levels of the shales. The normal alkane data reflect that marine macrophyte, algae, and land plants were contributed to the organic matter of Ranikot shales. Dibenzothiophene/phenanthrene ratio (0.11), phytane/n-C18 ratio (0.53), pyrite, and glauconite elucidate that the depositional environment of the Ranikot shale is marine. The XRD analysis of the shale from the Ranikot Formation revealed that it is brittle shale and dominated by 39.5 to 50.9 wt. % quartz. The present study, integration with the US EIA report demarcated the Ranikot Formation influential horizon as a shale gas resource.

Sedimentology, Geochemistry, and Reservoir Potential of the Organic-Rich Tuwaiq Mountain, Hanifa and Jubaila Formations, Abu Dhabi, UAE

Objectives/Scope: The late Callovian to early Kimmeridigian deposited Tuwaiq Mountain, Hanifa and Jubaila Formations are among the most prolific source rocks in the middle east. These sediments have recently been considered as potential unconventional gas reservoir in UAE. This study integrates sedimentological, structural, geochemical and pore-scale datasets to provide a better understanding of the depositional framework and its effects on the reservoir properties. Methods, Procedures, Process: Dunham Classification (1962) which was later modified by Embry & Klovan (1971) is the basis of the descriptive lithofacies scheme used to characterize the organic-rich carbonate sediments. The association of these classified lithofacies based on their genetic relationship reflects their corresponding depositional environments. Petrographical and geochemical assessment including Rock-Eval pyrolysis were performed on selected samples. Mineralogical assessment was performed via whole-rock and clay-fraction XRD analysis, whereas pore-scale fabric/textural investigations were performed via conventional transmitted light microscopy and SEM using backscattered electron mode BS-SEM. Results, Observations, Conclusions: Sedimentological characterization of mud-dominated carbonate sediments indicates that they accumulated in a clastic starved, intrashelf basinal setting. The lack of textural variation is observed, highlighted by the dominance of mudstones noted across the Tuwaiq Mountain Fm., Hanifa and Jubaila Formations. Wackestones are the second most abundant texture observed. Wacke-packstones and packstones are rare but are present in the Tuwaiq Mountain Formation. also dominated by mudstone textures show presence of wackestones in form of thin beds. The occurrences of planktonic foraminifera along with thin shelled bivalves further emphasizes the low-energy, distal depositional setting. A quantitative description of the nature, density, and trends of the fracture network highlights the tectonic and structural history of the sediments. A certain degree of brittleness is associated with the organic-rich sediments, which is evident from the mineralogical analysis showing the abundance of calcite (&gt;82%). Rock-Eval data revealed high TOC content of the sediments. An evaluation of the HI and Tmax indicates that the sediments are dominantly gas prone (HI&lt;150mg HC/g TOC). Based on the calculated reflectance data (Ro: 0.06-3.30), the sediments display varied levels of thermal maturity, from immature to over mature. The vitrinite reflectance equivalent (%VRE) values assessed from microscopic investigations a range between 1.24-1.64, with the lower values suggesting late maturity with wet (condensate) gas generation and the higher values suggesting post maturity with dry gas generation. The TOC and TRA data highlight that the organic-rich, laminated mudstones associated with the Hanifa and Tuwaiq Mountain Formations have the highest TOC values (up to 4.25wt%) and the highest bulk volume (up to 3.39 %BV). It is also noted that the petroleum storage potential in these sediments largely resides with the mineral matrix pores along with the porosity hosted by the organic matter, which has been assessed by BS-SEM analysis. Novel/Additive Information: This integrated approach sheds light on the development of unconventional gas reservoirs. In addition, this study shows how the changes in depositional environment may have controlled the organic matter preservation. For a plausible way forward, this current understanding may be extrapolated to uncored intervals for representativeness.