Hydrocarbon Prospectivity Research Articles

A unified framework for evaluating robustness of Machine Learning Interpretability for Prospect Risking

In geophysics, hydrocarbon prospect risking involves assessing the risks associated with hydrocarbon exploration by integrating data from various sources. Machine learning-based classifiers trained on tabular data have been recently used to make faster decisions on these prospects. The lack of transparency in the decision-making processes of such models has led to the emergence of explainable AI. Local Interpretable Model-agnostic Explanations (LIME) and SHapley Additive exPlanations (SHAP) are two such examples of these explainability methods which aim to generate insights about a particular decision by ranking the input features in terms of importance. However, results of the same scenario generated by these two different explanation approaches have been shown to disagree or diverge, particularly for complex data. This discrepancy arises because the concepts of “importance” and “relevance” are defined differently across these approaches. Thus, grounding these ranked features using theoretically backed causal notions of necessity and sufficiency can serve as a more reliable and robust way to enhance the trustworthiness of these methodologies. We propose a unified framework to generate counterfactuals, quantify necessity and sufficiency, and use these measures to perform a robustness evaluation of the insights provided by LIME and SHAP on high-dimensional structured prospect risking data. This robustness test yields deeper insights into the models’ capabilities to handle erroneous data and reveals which explainability module pairs most effectively with which model for our dataset for hydrocarbon indicators.

Machine learning and AVO class II workflow for hydrocarbon prospectivity in the Messinian offshore Nile Delta Egypt

This study presents a comprehensive workflow to detect low seismic amplitude gas fields in hydrocarbon exploration projects, focusing on the West Delta Deep Marine (WDDM) concession, offshore Egypt. The workflow integrates seismic spectral decomposition and machine learning algorithms to identify subtle anomalies, including low seismic amplitude gas sand and background amplitude water sand. Spectral decomposition helps delineate the fairway boundaries and structural features, while Amplitude Versus Offset (AVO) analysis is used to validate gas sand anomalies. The entire seismic volume is classified into facies domains using machine learning, which isolates target features from seismic background data. The study area, covering 1850 km2, includes major structures such as the Rosetta fault and Nile Delta offshore anticline, with reservoirs consisting of layered sandstones and mudstones. Over 90 wells, including exploration and development wells, have been drilled in the area. Seismic amplitude data, including full and partial offset stacked, were analyzed to classify gas, water, and shale zones. The workflow’s performance is demonstrated through the successful identification of the low-amplitude Swan-E Messinian anomaly, characterized as a high-risk gas prospect. Machine learning techniques, specifically neural network models, were trained to differentiate seismic features such as low-amplitude gas sand from background-amplitude water sand and shale. By iterating over multiple attributes and validating the models on blind test sets and on a blind section, which excluded a known shallow gas field, the workflow significantly improved the ability to detect potential hydrocarbon reservoirs characterized by low seismic amplitude. The results show that this integrated approach reduces exploration risk, quantifies the chance of success, and enhances decision-making in well placement and hydrocarbon exploration. This method is particularly useful for identifying low seismic amplitude anomalies, which are often challenging to detect with conventional seismic analysis. (1) This study developed a workflow to detect low seismic amplitude gas fields in near-field exploration. (2) It uses a machine learning algorithm to classify and explore low-seismic-amplitude gas sand reservoirs. (3) This approach helps estimate the likelihood of success and reduces the risk associated with hydrocarbon exploration wells.

SEISMIC ATTRIBUTE ANALYSIS FOR HYDROCARBON PROSPECTING IN THE AGBADA FORMATION OF 'ZEE' FIELD, NIGER DELTA BASIN

The unconsolidated sandstone reservoirs of the Tertiary Nigeria Delta basin are prone to anomalous high amplitude seismic reflections from both hydrocarbon and non-hydrocarbon sources. In order to identify anomalous zone due to hydrocarbon presence, seismic attribute analysis was used to investigate the reservoirs and to detect Direct Hydrocarbon Indicators (DHIs) due to hydrocarbon saturation in the ‘Zee’ field reservoirs. The 3D seismic, well logs and checkshot data were used for structural interpretation which helped to identify the sandstone and hydrocarbon bearing reservoirs. Faults planes and horizon were mapped to highlight the structural geometry and reservoir surface detection respectively. Five different seismic attributes were used to qualitatively evaluate hydrocarbon prospect from seismic amplitudes. Seismic attributes revealed three (3) major normal growth faults across the field while two (2) reservoirs (shallow seated reservoir A and deep reservoir B) showed zones that contain hydrocarbon anomalies. Seismic amplitude responses and fault styles from the reservoir tops reveal structurally controlled fault dependent closure across the field. High seismic amplitude anomalies from RMS, Average Energy and Maximum Magnitude attributes significantly characterize the drilled parts of the field. This implies that the high amplitude anomaly is a DHIs in ‘Zee’ Field. Moreover, apart from the already producing zone in the field's central area, two (2) more areas marked X and Y situated on anticlinal structure at the North East corner of the field has similar high amplitude responses (bright spots). It suggests new hydrocarbon prospects that should further be investigated for more hydrocarbon discoveries.

Features of isolation and nature of low-resistivity oil-saturated reservoirs of the Middle Jurassic deposits of the Akshabulak Central field of the South Torgai oil and gas basin

At the current stage of development of the oil and gas industry of our country, additional exploration of existing fields, understudied promising areas, identification of missed horizons, methods of evaluation and development of non-standard reservoirs are of particular relevance. Reservoirs with low specific electrical resistivity can be referred to non-standard reservoirs, and there are some difficulties in assessing hydrocarbon prospects of these reservoirs. Low resistivity reservoirs can be productive reservoirs with high residual water saturation as well as reservoirs for which generally accepted interpretation techniques are ineffective. Proper analysis of the reasons that lead to underestimation of the resistivity of productive reservoirs allows choosing the most effective interpretation methods. The article is devoted to the study of the features of reservoirs with low electrical resistivity, their nature and role in the process of fluid accumulation. The basic methods of identification of low resistivity zones in reservoir rocks, their physical and chemical characteristics that cause low resistivity, including mineralogical composition, saturation, porosity, permeability and pore space structure, are considered, and their influence on the filtration-capacitance characteristics is analyzed. Approaches to integrating data from various methods (geophysical and geological-technological studies, laboratory measurements) are described. Special attention is paid to the influence of low resistivity on the interpretation of data from geophysical methods. The results of the study have significant practical potential for optimization of field development.

Dispersed organic matter from pre-Devonian marine shales: A review on its composition, origin, evolution, and potential for hydrocarbon prospecting

Dispersed organic matter from pre-Devonian marine shales: A review on its composition, origin, evolution, and potential for hydrocarbon prospecting

Determining Petrophysical Properties Using PLTs and Conventional Logs of the Middle Shale Member (4th Pay) of the Zubair Formation in the South Rumaila Oil Field, Southern Iraq

The petrophysical evaluation of the Zubair Formation's Middle Shale member (4th Pay) in the South Rumaila oil field has been conducted to characterize the reservoir and quantify its hydrocarbon prospects. Although the 4th Pay has a substantial oil reserve, it has never been studied. A gamma ray, resistivity, density, and neutron log were used to estimate the shale volume, porosity, water saturation, and hydrocarbon saturation for four oil-bearing subunits in the middle shale member (4th Pay), producing net pays of Middle Shale Member 7 (13 m), 10 (31 m), 20 (11 m) and 25 (16 m), respectively. Shale volume calculated using the Gamma-Ray Log method, averages between 0.05 % and 0.53 %. Effective porosity ranges from (0.08) % to (0.21) %, indicating good reservoir quality; permeability ranges from 0.9 to 193.6 mD, indicating well-sorted sands. Hydrocarbon saturation varies from 0.29 to 0.89, while water saturation ranges from (0.11) to (0.72). Production Log Tool and Nuclear Magnetic Resonance logs were used to estimate permeability. Production Logging Tool log permeability values ranged between 5.2 (Middle Shale Member 10, 3425 mD) and 49.7 (Middle Shale Member 25, 3448.5 mD), while Nuclear Magnetic Resonance log permeability values ranged between 5.81 (Middle Shale Member 10, 3425 mD and 49 (Middle Shale Member 25, 3448.5 mD). According to the correspondence between the two logs, the correspondence value equals 85%. Thus, the reservoir permeability can be calculated using the radial flow equation calculated from the Production Logging Tool log and generalized to areas where there is no core. Results show that permeability (K) is highest in subunits Middle Shale Member 20 and 25, which also have high porosity, low shale content, and fine grain sorting, making them key production subunits. Subunit Middle Shale Member, although lower in permeability, is the main reservoir with the most oil reserves. Subunits Middle Shale Member 5 and 7 have lower permeability due to high shale content and heterogeneity, with low porosity. Subunit Middle Shale Member 0 has very low permeability. The high oil shale content, due to its poor porosity and heterogeneity, renders it unproductive.

The re-evaluation of the source rock potential of Kolmani Field using outcrop data, ditch cutting data, and 2D seismic data for enhanced hydrocarbon prospectivity

The Kolmani Field, Gongola Basin, Upper Benue Trough, Northeast Nigeria has yielded positive results in regard to gas generation potential, but the source rock viability is questionable. To examine this issue, an in-depth geochemical analysis of the outcrop samples of the Bima, Yolde, and Pindiga Formations and ditch cuttings of 4230–6970 ft depth interval across Pindiga and Yolde Formation were conducted. The materials were analysed using total organic carbon (TOC) and Rock Eval Pyrolysis. The calculated TOC of the outcrop data includes shale samples from the Pindiga Formation with a TOC ranging from 0.03 to 0.54 wt%, Yolde Formation shale samples with a TOC ranging from 0.03 to 0.07 wt%, and Bima Sandstone shale samples with a TOC ranging from 0.04 to 0.09 wt% while the ditch cuttings TOC spans from 0.54 to 0.85 wt%. All outcrop samples indicated poor TOC while that of ditch cuttings indicated fair to moderate TOC. The Tmax displayed two different types of source rocks: immature (between 415 and 420 °C) and mature (435–473 °C). The kerogen type are Type III and Type IV kerogen, which are gas-prone and inert in nature, respectively. While the HI (S2/TOC) values revealed gas, the remaining hydrocarbon potential S1 (mgHC/g), suggested weak oil potentials. The normalised oil content (S1/TOC) indicates that hydrocarbons have been expelled.

Hydrocarbon generation potential of South Geisum Oilfield, Gulf of Suez, Egypt: Source rock evaluation and basin modeling for unconventional hydrocarbon prospects

This study aims to define the hydrocarbon generation potential of source rocks by assessing various factors including quantity of organic matter, types of kerogen, thermal maturity, and source of organic matter input. Depositional conditions of source rocks from Thebes, Brown Limestone, and Matulla formations in Well G-9, Well GA-2 and Well GW-6, are assessed through pyrolysis, vitrinite reflectance and 1D basin modeling. Results show the source rocks of Thebes and Brown Limestone formations exhibit favorable to excellent source rock characteristics with Type I–II kerogen and have the capacity to generate oil. Conversely, the source rocks of the Matulla Formation show fair to good source rock characteristics with Type II–III kerogen and have the capacity to produce both oil and gas. Thermal maturity shows the source rocks are at an immature stage. A 1D basin model is constructed for Well G-9 to simulate multi-tectonic episodes, burial events, and the history of thermal maturity. Sedimentation rates of Cretaceous to Eocene deposits are characterized by a low burial rate, which contrasts with the high burial and sedimentation rates for Miocene and post Miocene (Pliocene–Recent) strata. Overall, the South Geisum oilfield petroleum system is found to be immature based on integration of source rock evaluation and petroleum basin modelling.

The Mundeck Salt Unit: A Review of Aptian Depositional Context and Hydrocarbon Potential in the Kribi-Campo Sub-Basin (South Cameroon Atlantic Basin)

The Kribi-Campo sub-basin, located in the Gulf of Guinea, constitutes the southeastern segment of the Cameroon Atlantic Margin. Drilling in the Aptian salt unit revealed a sparse hydrocarbon presence, contrasting with modest finds in its counterparts like the Ezanga Salt in Gabon and the Rio Muni Salt in Equatorial Guinea. This discrepancy prompted a reassessment of the depositional context and hydrocarbon potential of the Mundeck salt unit. By integrating 2D seismic reflection and borehole data analysis, this study established the structural and stratigraphic framework of the area, emphasizing the salt unit’s significance. Borehole data indicate a localized salt unit offshore Kribi, with seismic reflection data revealing distinct forms of diapir and pillow. This salt unit displays a substantial lateral extent with thicknesses ranging from 4000 m to 6000 m. The depositional context is linked to the following two major geological events: a significant sea-level drop due to margin uplift during the Aptian and thermodynamic processes driven by transfer faults related to mid-oceanic ridge formation. These events were crucial in forming and evolving the Mundeck Salt. Regarding hydrocarbon prospects, this study identifies the unit as being associated with potential petroleum plays, supported by direct hydrocarbon indicators and fault-related structures. The findings suggest that untapped hydrocarbon resources may still exist, underscoring the need for further exploration and analysis.

Optimizing reservoir characterization: insights from integrated data analysis

The Onshore Hydrocarbon prospectivity of the Niger Delta X-field is examined through the integration of 3D seismic and recorded information from well log data. Probable reservoirs of hydrocarbon-bearing were delineated to tackle the non-uniqueness in the identification of hydrocarbon quantity of concern. Three significant faulting patterns or systems were delineated and their architectural attributes depict a typical Niger Delta embedded anticlinal structural pattern. The study field exhibited both synthetic and antithetic structures, hence only fault on delineated reservoirs was used for structural modeling. All well locations were sited within the fault-supported synthetic and anticlinal structures and the static characteristics within the well coordinates were analyzed through petrophysical assessment. Depicted reservoir sands show low gamma ray readings, low volume of shale, considerate hydrocarbon saturation and low water saturation. The established petrophysical models showed a better net-to-gross (NTG) ratio, for the entire delineated reservoir units. This has contributed to the assessment of hydrocarbon-bearing reservoir units before employing the strategy for field development scenario, in order to eliminate dry hole drilling campaign. These will contribute to the reduction of operational costs, having delineated the accurate geometry and petrophysical model of hydrocarbon reservoir units.

Hydrocarbon Prospectivity in the West Waha and Worsham-Bayer Fields, Delaware Basin

The west Waha and Worsham-Bayer field, located within the Delaware Basin of western Permian Basin, represents a significant hydrocarbon province with substantial production potential. This study aims to reevaluate the hydrocarbon resources and optimize recovery strategies for these fields by integrating seismic interpretation, petrophysical analysis, and volumetric assessment. Using data from 3D seismic reflection volumes, well logs, and production records, the research applied advanced techniques including seismic-to-well ties, structural and sequence stratigraphic interpretations, and fault-seal analysis. Key findings highlight the identification of four major reservoirs: UML, TF, FF, and ELB. The ELB reservoir, characterized by very high porosity, high permeability, and low water saturation, emerged as the most promising target for hydrocarbon production. The TF and FF reservoirs also demonstrated high potential, while the UML reservoir showed moderate characteristics but high-water saturation. Volumetric assessments supported these findings, confirming the ELB reservoir’s exceptional hydrocarbon potential. The study recommends drilling deeper into the Ellenburger Formation with Wells 42 and 98 to exploit deeper targets, acquiring additional 3D seismic data towards the southeastern basin, and employing enhanced seismic resolution for better facies distribution understanding. Furthermore, the development of a 3D reservoir model incorporating fracture networks and a detailed fault-seal analysis are advised to optimize hydrocarbon recovery. This research provides a comprehensive evaluation of the West Waha and Worsham-Bayer fields, offering actionable insights for maximizing hydrocarbon production through targeted exploration and advanced reservoir management strategies.

Integrated Sequence Stratigraphic and Seismic Facies Analysis for Hydrocarbon Prospectivity of the Taranaki Basin, New Zealand

This study analyses the hydrocarbon potential and basin characteristics of the Taranaki Basin in New Zealand, the country's primary petroleum-producing region. The research, which uses a robust methodology involving 2D seismic data, well logs, and other geological information, examines the basin's stratigraphy, structural features, and petroleum systems. Key findings include the identification of two genetic sequences with associated system tracts, multiple reservoir and source rock units, and both structural and stratigraphic trapping mechanisms. Seismic facies analysis revealed eight distinct facies types which characterize the depositional environments. Play fairway mapping identified sweet spots where all petroleum system elements overlap. Risk assessment highlighted factors like gas chimneys and fault-compromised seals. The study concludes by presenting the geologic chance of success for three identified plays and one prospect in different stratigraphic intervals. This comprehensive analysis provides new insights into the under-explored portions of the Taranaki Basin and its hydrocarbon potential. By enhancing the understanding of the basin's stratigraphic architecture and depositional history, this study aims to improve reservoir distribution and quality predictability. Moreover, integrating seismic facies analysis with sequence stratigraphy offers a robust tool for delineating potential hydrocarbon-bearing zones, thereby reducing exploration risk and aiding the efficient reassessment of existing prospective zones and future exploration efforts.

A Petrophysical Properties Evaluation Study of a Niger Delta Field Using Well Logs and Core Data

A petrophysical properties evaluation study of an onshore field “NEMA” was carried out to assess the petrophysical characteristics of the field in the eastern portion of the Niger Delta Basin. This was done in an effort to determine the hydrocarbon prospect and oil productivity potential of the reservoirs. The net/gross thickness was one of the examined parameters. (pay zone thickness), porosity, permeability, fluid saturation which were all inferred from geophysical wireline logs and core data. The wireline logs used in the investigation included density, resistivity, gamma ray, and spontaneous potential logs for five different wells from the “NEMA” oil field. Five reservoirs designated, NEMA 01, NEMA 04, NEMA 07, NEMA 09, and NEMA 12 were identified and correlated across the five wells in the field using gamma ray logs and shale resistivity markers. Based on the computation of petrophysical parameters, the porosity of the reservoirs ranged from 0.22 (22%) to 0.31 (31%); the permeability ranged from 851.58 mD to 1005.05 mD; the average net-to-gross thickness of the reservoir sand bodies was 140 ft; the water saturation value was less than 45%, while the hydrocarbon saturation was greater than 55%. We equally observed that our computed petrophysical parameters from well log data correlated well with the core computed values in NEMA 09. In conclusion, the delineated reservoirs were categorized as good hydrocarbon reservoirs. These results suggest huge hydrocarbon potential and a reservoir system whose performance is considered satisfactory for hydrocarbon production.

Characteristics of the structure and hydrocarbon prospectivity of the deeply buried strata in the eastern Precaspian basin

The article examines the geological structure and oil and gas prospects of the pre-salt complex in the eastern Precaspian Basin (PB). Based on the synthesis and comprehensive analysis of geological exploration (GE) results and the analysis of geological-geochemical criteria for hydrocarbon potential, the oil and gas geological zoning has been updated, and effective directions for GE have been identified. The justification of a new hydrocarbon resources base within the eastern PB margin can be ensured by further investigating of the deeply buried Devonian-Middle Carboniferous horizons in the known petroleum plays, as well as within the less explored Sakmar-Kokpektinsky segment of the Ural fold-and-thrust belt. Within the productive KT-I and KT-II formations, there is an unrealized hydrocarbon potential at depths of 5-6 km. Using the example of the Bozoba West area, the oil and gas prospects of the Visean-Bashkirian and Lower Permian strata are examined, highlighting the significance of faults as elements of the hydrocarbon system. The applied set of 3D seismic survey data and deep drilling allowed for the interpretation of deep seismic sections, up to depths of 7.0-7.5 km. The Middle-Upper Devonian strata are considered prospective but have not been extensively explored by deep drilling. To establish a new hydrocarbon resource base within the eastern Precaspian Basin margin, it is recommended to conduct advanced regional seismic surveys and parametric exploration drilling.

The impact of the Abimael Ridge on the salt tectonics in the southern Santos Basin, Brazil: The Esmeralda exploration block case

The Merluza Graben and Abimael Ridge are first-order basement structures that influence not only the thickness, geometry, and shape of the salt layers, but also the distribution and geomorphology of post-salt sequences in the southern Santos Basin.The basement highs, associated with the implantation of the Abimael Ridge, interpose as a physical barrier to the salt flow, as the plastic, mobile evaporite sequences tend to occupy areas with less overburden pressure. Given that most pre-salt targets rely on evaporite layers as a sealing element, these basement structures can either favor or hamper the risk analysis of hydrocarbon prospects recognized in the area.This study focuses on the Esmeralda exploration block, offered by the Brazilian Agência Nacional de Petróleo (ANP) in 2022. It examines the impact of alternate geological interpretations on the economic evaluation of pre-salt exploratory plays in the southern Santos Basin.

Petrophysical characterization of the Late-Cretaceous Logbaba Formation in the Kribi/Campo sub-basin, Cameroon: Implication on deep-water hydrocarbon exploration

Deep-water hydrocarbon exploration in the Kribi/Campo sub-basin offshore Cameroon is targeting the promising Campanian-Maastrichtian turbidite reservoirs. However, a detailed understanding of the petrophysical properties of these Upper Cretaceous reservoirs is not well documented. In this study, well logs from two boreholes W1 and W2 located in the southern part of the sub-basin provide a unique opportunity to assess the reservoir quality of the Upper Cretaceous Logbaba Formation. Four potential reservoir intervals with thickness ranging between 27 and 105.7 m were delineated in W1, compared with two intervals in W2 with thickness ranging between 72.2 and 93.6 m. Lithological analysis of these reservoir intervals indicates a heterogeneous reservoir matrix consisting of sand, limestone, and dolomite. These reservoir intervals are interpreted as turbidite sand deposits with a clay content ranging from 6.3 to 19.8%, porosity ranging from 15.5 to 21.3%, permeability ranging between 5.65 and 75.09 mD and a water saturation of 34.5–74.2%. Fluid free index, reservoir quality index, and flow zone indicator are insignificant and suggest reservoirs with poor transmissibility. These analyses reflects good petrophysical characteristics for the sandstones of Logbaba Formation. However, both wells were water-bearing with non-mobile hydrocarbon residuals and did not contain commercial quantities of hydrocarbons. There is no evidence of hydrocarbon migration in either reservoir, suggesting that the source rock and the hydrocarbon migration pathways are the main risk factors and reason for the failure of the wells. The findings from this study extend the understanding of the reservoir characteristics of the Upper Cretaceous Logbaba Formation, which will further enhance hydrocarbon prospectivity offshore Cameroon. Since these reservoirs are water-laden, they may serve as potential offshore saline aquifers for geological storage of CO2 offshore Cameroon.

Hydrocarbon prospectivity of the South Atlantic Orange Basin

Hydrocarbon prospectivity of the South Atlantic Orange Basin

BIOSTRATIGRAPHY, PALEOENVIRONMENT AND HYDROCARBON POTENTIAL OF FIKA MEMBER OF PINDIGA FORMATION, GONGOLA SUB-BASIN, NORTHERN BENUE TROUGH, NE NIGERIA

The Fika Member, a crucial stratigraphic unit within the Pindiga Formation, represents a significant geological entity with substantial implications for understanding the regional paleoenvironmental evolution and hydrocarbon prospectivity. This study integrates biostratigraphic analyses, sedimentological investigations, and hydrocarbon potential assessments to elucidate the depositional history, paleoenvironmental conditions, and source rock prospect of the Fika Member. Facies and their stratigraphical distribution analyses were conducted on the Fika Shale exposed mainly at Gabukka Stream 1 and 2. Twenty (20) samples collected were subjected for standard palynological and foraminifera analyses. A standard method of palynomorphs extraction that involves the use of Hydrofluoric and Hydrochloric acid was employed. For foraminifera analysis, washing and sieving method was used. It was discovered that agglutinated foraminifera are the dominance taxa in ten (10) out the twenty (20) samples studied. Based on the colours of the agglutinated foraminiferal and Foraminiferal Color Index (FCI) values suggest low thermal maturity for both oil and gas generation. The foraminiferal assemblages indicate marginal marine (fluvio marine) to shallow inner neritic environments. This is supported by the sedimentological data which indicates a shallow marine depositional environment. The biostratigraphic data suggest Santonian age for the Fika Member.

Depositional environments of the northeastern Yenisey-Khatanga sedimentary cover in relation to assessment of hydrocarbon prospects

Background. Although the recent years have seen a significant increase in the amount of geological and geophysical data on the oil and gas potential of the Yenisei-Khatanga trough, no notable hydrocarbon discoveries have been made within its northeastern part. This is primarily related to a lack of understanding of the development of sedimentary basins, along with the processes of oil and gas generation, migration, and accumulation. This determines the need to generalize and analyze the accumulated geological, geophysical, and geochemical data within the framework of a comprehensive basin analysis and revision of the existing geological models.Aim. Elucidation of the evolution of sedimentary basins in the northeastern part of the Yenisei-Khatanga trough and the adjoining Anabar-Khatanga saddle; updating the geological model of the sedimentary cover for further assessment of hydrocarbon systems.Materials and methods. Development of a numerical geologic model of the Yenisei-Khatanga trough and the adjoining Anabar-Khatanga saddle based on available publications and engineering reports. A basin analysis and paleogeographic reconstructions for the main time steps of sedimentary cover evolution.Results. The evolution of the sedimentary basins under study has been reconstructed, and the main stratigraphic units in the development of hydrocarbon systems have been identified. Depositional environments supporting the development of the essential hydrocarbon system elements have been delineated for further hydrocarbon system modeling and geological risk assessment.

Anadyr Basin Composite Tectono-Sedimentary Element, Chukotka Peninsula, NE Asia

The Anadyr Basin reflects the tectonic history of the Chukotka and Kamchatka peninsulas in the late Mesozoic and Cenozoic. It is located at the junction of the Novosibirsk–Chukotka, West Koryak and Koryak–Kamchatka fold and thrust belts (FTBs) along the NE margin of Eurasia. The basin includes a latest Cretaceous–Cenozoic succession that is divided by several unconformities caused by tectonic events within the surrounding thrust belts, resulting in several episodes of basin inversion, uplift and erosion. Accordingly, and in the framework of this memoir, the basin is described as a composite tectono-sedimentary element (CTSE). Four gas and oil discoveries are known from the onshore part of the basin. The hydrocarbon prospectivity of the area is determined by the presence of latest Cretaceous–Eocene source rocks and Miocene reservoirs. The purpose of this chapter is to provide an overview of geological and geophysical studies, as well as exploration work for oil and gas undertaken during the late Soviet period and in more recent times in the Anadyr Basin.