INTEGRATED INTERPRETATION OF THE L59 PROFILE IN THE CENTRAL BASIN (DRC): STRUCTURAL ANALYSIS, SEISMOSTRATIGRAPHY, AND PETROPHYSICAL MODELING OF RESERVOIRS

INTEGRATED STRATIGRAPHIC AND PETROPHYSICAL ASSESSMENT OF THE MADUKY FIELD, NIGER DELTA, NIGERIA: IMPLICATIONS FOR RESERVOIR ARCHITECTURE AND HYDROCARBON PROSPECTIVITY

The Maduky Field, situated within the Coastal Swamp depobelt of the Niger Delta Basin, represents a structurally complex and geologically heterogeneous marginal field with untapped hydrocarbon potential. This study integrates 3D seismic interpretation, well log correlation, sequence stratigraphy, and petrophysical analysis to characterize its reservoir architecture and evaluate hydrocarbon volumes. Structural mapping reveals prominent listric growth faults and rollover anticlines that define three main field compartments, each with distinct depositional and trapping characteristics. Sequence stratigraphic analysis, guided by five regionally correlated Maximum Flooding Surfaces (MFSs), delineates Genetic Sequences and system tracts (HST, TST, LST), each with unique parasequence stacking patterns and reservoir geometries. The highstand and lowstand system tracts host the most prolific reservoirs, characterized by clean, coarsening-upward sand bodies with high net-to-gross ratios and favorable porosity-permeability relationships. Petrophysical evaluation across five wells indicates effective porosity values of 20–34%, permeability ranging from 2.50 to 18 mD, and low water saturation (8–35%), confirming reservoir quality suitable for commercial exploitation. Crossplots further demonstrate the controls of porosity and depositional environment on fluid distribution and reservoir performance. The study identifies key hydrocarbon-bearing units sealed by marine shales associated with MFSs and quantifies Stock Tank Oil Initially In Place (STOIIP) across fault blocks, highlighting potential development zones. These insights support the redevelopment of Maduky Field and provide a scalable model for optimizing marginal field performance in mature deltaic basins.

GEOPHYSICAL CHARACTERIZATION OF THE UPEMBA GRABEN: SEDIMENTARY THICKNESS ESTIMATION VIA SOURCE PARAMETER IMAGING (SPI) OF REPROCESSED MAGNETIC DATA

The Upemba Rift, located in the southeastern Democratic Republic of Congo, constitutes a sedimentary sub‑basin that remains largely underexplored despite its presumed petroleum potential. Covering an area of approximately 46,519 km², it recently attracted attention during the licensing rounds launched in 2022 by the Ministry of Hydrocarbons of the Democratic Republic of Congo. However, the absence of modern seismic data as well as detailed geological and geochemical surveys significantly constrains the assessment of its hydrocarbon prospectivity. The only available information derives from the magnetic survey conducted by CGG in 1986, which has already been interpreted in various studies. Within this context, the present study – Geophysical characterization of structures in the Upemba Graben and estimation of sedimentary thickness using the Source Parameter Imaging (SPI) method: Reprocessing and integrated analysis of magnetic data – aims to propose a preliminary sedimentary model and to shed light on the morpho‑tectonic evolution of the basin, thereby further highlighting its petroleum potential as well as the maximum sedimentary thicknesses of this intra‑cratonic basin. The results obtained are based on an integrated methodological framework combining a multimodel numerical approach, critical and comparative analysis, and an in‑depth morpho‑tectonic interpretation, together with sediment thicknesses derived from the SPI method, emphasizing their quantitative contribution. Taken together, these elements provide a robust preliminary argument that contributes to a better understanding of the morpho‑tectonic history and sedimentary dynamics of the Upemba Graben and its petroleum system, thereby paving the way for increased interest from potential partners and renewed momentum in future exploration campaigns.

3D Seismic Interpretation and Geological Modelling for Petroleum Reserves Estimation of I Sequence, Lower Miocene, X Field, Block Y, Malay – Tho Chu Basin, Viet Nam

Seismic attributes are widely used to enhance geological interpretation by extracting quantitative information from seismic data. They provide insights into both structural and stratigraphic features, enabling interpreters to detect subtle changes in lithology, continuity, and geometry of subsurface formations. Attributes are especially useful in improving the resolution of seismic images, helping to delineate horizons, identify fault patterns, and visualize depositional features. This study focuses on using seismic attribute analysis to clarify the distribution of sand bodies within a reservoir interval. The objective is to identify zones with favourable sand development, define their geometry and connectivity, and outline areas with high hydrocarbon reservoir potential. The interpreted I Sequence was divided into three sub-sequences, each modelled with a geological grid size of 50m×50 m and subdivided into 150 layers. The porosity model showed mean values ranging from 0.228 to 0.2484 across the main reservoir zones, while water saturation varied from 0.90659 to 0.92747. After calculating seismic attributes, the authors delineated sand bodies in the I38_upper layer located in the North–Northwest, Northeast, and smaller bodies in the South. In the I90 layer, sand bodies were identified in the North–Northeast, East, and Southeast, along with narrow, laterally restricted sands in the western part of the study area. The P2 reserve with 50% confidence for the most potential interval (I23–I38) was estimated at 86 million cubic meters after running 200 cases.

Geometrization of East Siberia complex carbonate reservoirs with integration of well-testing and seismic surveys

Complex carbonate reservoirs of Eastern Siberia are highly heterogeneous and difficult to predict seismically because of intrusive bodies, thin-bedded strata, and salinization zones. This study aims to evaluate the effectiveness of an integrated reservoir geometrization approach for refining the boundaries of productive zones, improving production drilling success, and reducing geological risks using an oil and gas condensate field in the Irkutsk Region as a case study. The leading method is a retrospective analysis by integrating long-term well testing, interference testing, numerical 2D flow modeling in Kappa Ecrin Saphir, seismic attribute maps (acoustic impedance and Vp/Vs ratio), and seismic facies analysis. The results show that the productive reservoir is only partly associated with basement highs and does not fully conform to their boundaries. By combining dynamic reservoir data with seismic information, the authors define the lateral extent of vuggy porosity zones more accurately. Initial rates, reservoir pressure measurements, and pulse interference tests confirm authors' results. This approach can enhance drilling success from 78,4 % to 86,4 % and provides an effective tool for optimizing well placement and development programs.

Signatures of Prograding Seismic Clinoforms in Cienaga de Oro (CdO) Formation, Lower Magdalena Valley Basin, Colombia: An Integrated Case Study

The Lower Magdalena Valley Basin (LMVB) of northwestern Colombia represents a mature hydrocarbon-producing province with a prolonged exploration and production history, marked by the first recorded gas discovery in 1943 (Arminio et al., 2011). Subsequent exploration programs have acquired more than 24,000 km of 2D seismic and approximately 7,000 km² of 3D seismic data, along with the drilling of more than 270 exploratory and development wells (Willis et al., 2017). These integrated exploration efforts have resulted in the identification of at least 20 major gas fields, with estimated reserves ranging from 20 to 435 BCF, besides numerous smaller hydrocarbon accumulations, several of which contain associated liquid hydrocarbons (Willis et al., 2017). Tectonically, the LMVB is developed along a convergent margin, associated with the interaction between the Caribbean/Pacific domain and the South American plate (Barrero et al., 2007; Arminio et al., 2011). The basin is underlain by continental crust and bounded to the west by the Sinú–San Jacinto accretionary prism, with deformation characterized by a combination of subduction-related processes and strike-slip tectonics. This structural framework has exerted a first-order control on basin architecture, accommodation development, and sediment routing.

): Implications for the seismogenic zone and the age of the subducting Philippine Sea Plate (