Hydrocarbon Prospectivity Research Articles

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

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

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.

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.

Seismic coloured inversion to explore the hydrocarbon prospectivity of a field in the Upper Assam basin

This study demonstrates an integrated approach using a seismic-coloured inversion to derive the hydrocarbon potential of a field in the Upper Assam basin. The well-log analysis indicated the presence of hydrocarbon in the form of gas, oil, and water in sandstones with thin streaks of limestone and shale layers. The Acoustic Impedance (AI) model was generated from post-stack seismic data using a coloured inversion. Shale volume (Vshale), density, porosity and water saturation are the petrophysical parameters spatially populated using a multilayered feed-forward neural network on the inversion-based AI model. The estimated range of model-derived parameters varies as Velocity: 2136–5034 m/s, Vshale: 0–48%, Density: 2.14–2.72 gm/cc, Porosity: 6–29%, Water saturation: 9–28%, and demonstrates a reasonable correlation to well-log data. Seismic attribute for thin-fault likelihood was used to interpret the major faults. From the combined analysis based on interpreted faults and modelled parameters, the northwestern part of the study area displays a thick hydrocarbon-bearing zone (due to increasing thickness and reservoir quality). This interpretation is based on the consideration that faults are open. Thus, assuming continuity in the sequence, this northwestern region can be considered as one of the promising candidates for further exploration.

Characterization of Carbonate Reservoir Potential in Salawati Basin, West Papua: Analysis of Seismic Direct Hydrocarbon Indicator (DHI), Seismic Attributes, and Seismic Spectrum Decomposition

Carbonate reservoir of Kais Formation in Salawati Basin, West Papua, is the most famous oil and gas reservoir in the eastern part of Indonesian Archipelago since 1970’s. Nowadays, new prospects in this area are more challenging and most relevant near the infrastructure of previous oil and gas fields. In this study, a relatively new seismic dataset was investigated to figure out new prospects in carbonate reservoir rocks in the area of interest. In this preliminary study, where seismic data are not supported by well data, direct hydrocarbon indicator (DHI), seismic attribute, and spectral decomposition (CWT: continuous wavelet transform) allow the authors to characterize the reservoir geometry and to predict pore fluids within the reservoir rocks. The reservoir geometry of carbonate reef of Kais Formation (C1) was identified by seismic reflectors with high amplitude contrast at the top C1. The hydrocarbon indicator was predicted by DHI where dim spots, flat spots, and polarity reversals are indicative of hydrocarbon prospects. From the attribute analysis, the attribute instantaneous amplitude detected the top carbonate C1, whereas pore fluids were predicted from high sweetness attribute. In addition, spectral decomposition CWT method confirms the top C1, identified as saturated rock by the frequency of 10 Hz, 20 Hz, and 30 Hz. Based on a seismic study in the researched area, the target zone is expected to be a very promising hydrocarbon reservoir, specifically a carbonate reservoir. As a result, the preferred well-test location is in a region with access to the Kais Formation limestone reef layer. This study can assist in reservoir characterization, especially in areas with limited well control.

About this title - The Bowland Shale Formation, UK: Processes and Resources

This volume showcases recent geological, geophysical and geochemical research on the UK Mississippian Bowland Shale Formation. Here, the Bowland Shale and equivalent units are described and interpreted in terms of sedimentary, geochemical, and mechanical properties and processes, basin-forming events, hydrocarbon prospectivity, mineralization, and heat and fluid flow in the subsurface.

Hydrocarbon prospectivity of selected block wells, Southern Niger-delta, Nigeria

Hydrocarbon prospectivity of selected block wells, Southern Niger-delta, Nigeria

Accentuating the Reservoir Potentials of Balkassar Field by Delineating the Fracture Trends and Hydrocarbon Prospects with the Aid of Seismic Attributes.

Carbonates constitute a significant proportion of the world's hydrocarbon reserves, accounting for approximately 43%. Despite their substantial potential, accurately characterizing these reserves is a challenging task due to their complex and anisotropic nature. In the upper Indus basin of Pakistan, Eocene carbonates exhibit strong production capabilities. However, the Eocene reservoir (comprising the Chorgali and Sakesar formations) and the deeper Lockhart formation of the Paleocene age present a considerable challenge. The Chorgali formation is dolomitic in composition, featuring both primary and secondary porosity, while the Sakesar formation has only secondary porosity resulting from tectonic activity. The delineation of tectonically induced porosities is a highly demanding task that requires exceptional quality seismic and well data for reliable results. To address the complex heterogeneities present in the Eocene reservoir of the upper Indus basin, a variety of seismic attributes, such as sweetness, instantaneous frequency, amplitude, curvature, similarity variance, lateral continuity, and fault likelihood, have been employed in conjunction with fundamental interpreting techniques. These advanced seismic attributes greatly contribute to delineating fracture zones and identifying sweet spots with remarkable precision. They also enable a focus on high-frequency data content and differentiate between shale beds and reservoir zones based on frequency and amplitude. This helps in the concise marking of fractured zones to enhance our understanding of secondary porosity. Moreover, these attributes help delineate the continuity of reflectors and pinpoint disruptions caused by compression forces and tectonic activities. This study aims to capture the heterogeneity and complexity of reservoir zones to address a critical question regarding the Balkassar structure. The Western lobe of the field, which demonstrates promising oil production, outperforms the structurally higher Eastern part, which lags behind in production. This research seeks to recognize the geological elements contributing to the superior performance of the Western lobe and provide guidance for maximizing the potential of the Eastern lobe through advanced characterization techniques.

Session 1. Oral Presentation for: New insights into the Kingia Sandstone facies distribution, and implications for hydrocarbon prospectivity, north Perth Basin, Western Australia

Session 1. Oral Presentation for: New insights into the Kingia Sandstone facies distribution, and implications for hydrocarbon prospectivity, north Perth Basin, Western Australia

Geoscience Visual Presentation G09: Unconventional hydrocarbon prospectivity of the Paleoproterozoic Fraynes Formation in Manbulloo S1, Northern Territory

Geoscience Visual Presentation G09: Unconventional hydrocarbon prospectivity of the Paleoproterozoic Fraynes Formation in Manbulloo S1, Northern Territory

A new method to quantify the source contribution of mixed biodegraded oil based on pareto-optimized nonnegative matrix factorization and chord diagram visualization

The biogenic information of different components in crude oils with varying degrees of biodegradation is partially obscured, making traditional molecular indicators ineffective in determining the contributions of mixed sources. Previous studies have mainly focused on calculating mixed source proportion for normal oils, with few investigations involving biodegraded mixed oils. Developing a quantitative method for the mixed source contribution of biodegraded oils using machine learning (ML) algorithms is a significant attempt both to the exploration practice and theoretical progress. Taking the biomarker parameters resistant to biodegradation of 150 oil samples as input datasets, a new method called Pareto-Optimized NMF (PONMF) was proposed in this study, which combines multi-objective optimization (Pareto optimization) with non-negative matrix factorization (NMF) to analyze the relationship between biodegraded oils in the absence of source rock samples or original end-member (EM) oils while satisfying non-negativity constraints and additional constraint conditions. This method decomposes the matrix of crude oil samples into multiple end-members, each representing a possible input from a hydrocarbon source rock. Analysis of the end-member characteristics facilitates the deduction of potential hydrocarbon source layers and the traits of their depositional environments. This examination is supported by data derived from 15 prospective hydrocarbon source rock samples, which were employed to ascertain the actual geological significance of the end-members. The chord diagram depicts the visualization results of the overall relative contribution of source rock end members to crude oil in each area after the PONMF calculation results. The relative contribution of source rocks in different areas to the investigated crude oil samples is proportionate, and the arc length can reflect the contribution of the three sets of source rocks to a certain area. The findings indicate that the oils extracted from the stratified reservoirs in Eastern Chepaizi are primarily derived from the Permian source strata within the Shawan Depression, with a significant contribution ranging from 30% to 90% (EM2), and a lesser extent from the Carboniferous sources, contributing between 5% and 30% (EM1). Conversely, the provenance of oil in Western Chepaizi is overwhelmingly attributed to the Jurassic source interval located in the Sikeshu Depression, where EM3 accounts for over 85% of the source. Meanwhile, the oils in the Central Zone exhibit a composite origin, intermingling contributions from both EM1 and EM3. The advantage of this method is that it does not require direct access to hydrocarbon source rock samples or end-member oils but infers potential hydrocarbon source layers through the existing mixed-source oil samples. The PONMF method provides an effective tool for identifying the sources of biodegraded oils and can be used to study potential hydrocarbon source rock analysis for oils that have undergone biodegradation after hydrocarbon accumulation.