The dispersal patterns of the Late Cretaceous to Early Tertiary sediments in southern Anambra Basin were studied to delineate spatial facies distributions for improved mapping and hydrocarbon prospectivity. Seven lithofacies distinguished from eleven outcrop sections aided the interpretation of depositional environments for the different depositional units. Interpreted paleoenvironments ranged from estuarine/lagoonal to tidal delta and shallow marine depositional environments. Sequence stratigraphic interpretation of the deposits using vertical relationships between the delineated facies and foraminiferal and palynofacies assemblages and the interpreted environmental setting identified two complete sequences (SEQ-1 and -2) and two incomplete sequences (SEQ-3 and -4) in the study area. The sequiences are enveloped by three Type-1 Sequence Boundaries (SB), two Transgressive Surfaces of Erosion (TSE) and four Maximum Flooding Surfaces (MFS). The identified surfaces were used to delineate formation boundaries and as such would assist in the improved mapping of the Anambra Basin and adjoining depocenters. The massive sand units of the Highstand and Transgressive Systems Tracts constitute good (potential) reservoirs, while the transgressive shales would constitute seals for potential traps in the study area. The delineation of these petroleum system elements, especially those associated with the Transgressive and Highstand Systems Tracts has conferred great hydrocarbon prospectivity potential on the sedimentary sequences in the Basin. The absence of deep marine and slope complexes of the Lowstand Systems Tract (LST) in the interpreted sequences is indicative that the study area is the up-dip section of the Anambra Basin.

Encountering a reservoir in either a gas-down-to (GDT) or an oil-up-to (OUT) situation poses a challenge to development planning and reservoir management. The resulting uncertainties in the distribution, in-place and recoverable volumes of oil and gas may jeopardize expeditious execution of the field development project. To confirm the presence or absence of either oil or gas and establish a possible gas-oil-contact (GOC), in some cases the drilling of an appraisal wells(s) may be required. This paper describes a method that does not depend on dedicated appraisal wells to reduce GOC uncertainties and proves to be a valuable method to de-risk planned reservoir developments. Where credible pressure-volume-temperature (PVT) data are available from the subject reservoir, compositional-grading simulations (CGS) can be employed to evaluate the presence (or otherwise) of a GOC within a vertically continuous reservoir column. From a thermodynamic standpoint, the GOC is that depth at which the reservoir fluid transits from being gas-like to oil-like, and vice-versa. Considering some saturated and undersaturated oil reservoirs in the Niger Delta as case studies, this paper demonstrates the applicability of a combination of PVT and CGS to de-risk the presence of GOC without resorting to either a new well or a pilot hole. In the cases where well logs have established GOC, blind tests show excellent agreement between CGS results and well logs. Similarly, CGS accurately suggests the absence of gas-like fluids within the proven undersaturated oil reservoirs examined. Finally, the results of this study will document that CGS is reliable and cost-effective for reducing GOC uncertainties and de-risking field development projects. Consequently, this method is recommended whenever credible PVT data are available.

fax 01-972-952-9435. AbstractGround roll is a collection of surface waves generated by a seismic source. The vertical component of ground roll is composed of Raleigh waves. Raleigh waves have their most natural classification in terms of dispersion patterns. .All seismic waves will exhibit dispersive character in a medium which displays attenuation and the most important cause of Raleigh wave dispersion is the presence of velocity layering.Results obtained during field seismic data acquisition with a Seismic crew of Geosource Nig Ltd has shown that the Niger Delta is not a homogeneous half-space but exhibits non-homogeneous character with unequal phase and group velocities. Hence the predominance of dispersive waves in the Niger Delta is due to its nonhomogeneous character.The complex topographic nature of the Niger Delta give rise to scattered Raleigh waves and these can be attenuated by use of field arrays that attenuates scattered Raleigh waves from all azimuths. Frequency -wavenumber transform of time-offset records can be interpreted in terms of Raleigh wave dispersion. This has been utilized in this study as dispersion curves of the ground roll in areas of study are presented and interpretation of ground roll dispersion patterns made with this.This study covers the "Uti" area of Akwa Ibom state in the eastern Niger Delta and is part of an ongoing study on a more effective characterisation of ground roll in that area.Results of this study will be very useful to seismologists, geophysicists, geologists, researchers and the academia who would like to know the ground roll properties and dispersion patterns in the Eastern Niger Delta with a view to designing attenuation strategies for it.

Sandstone formations that have potential to produce sand during the life of the well account for a significant fraction of global recoverable volumes of oil and gas resources. The economics, environmental and safety implications of sand problems are critical enough to justify good knowledge of the potential for sand failure and production. Reliable evaluation of potential sand production is required to identify the needs for and the specification of sand-exclusion equipment during the project execution phase. To address these challenges, this paper presents a simple workflow that is premised on the petro-elasticity of the formation. Specifically, the proposed workflow uses cross plots of compressional sonic logs and density logs on reservoir-by-reservoir and well-by-well basis. From a petro-elastic standpoint, compressional sonic logs contain information on travel time required for sound waves to travel through the subject formation. The fundamental relationship between formation compaction (strength) and porosity has been explored to establish the trend of compaction, hence vulnerability of a sandstone formation to failure. In illustrating the applicability of the proposed concepts and workflow, some field examples from the Niger Delta are presented. Using wells with known history of sand failure and production, the workflow has been applied retroactively. The methodology presented is very useful for establishment of a quick screening sand control requirement. From a qualitative standpoint, it is found that the performances of the proposed workflow are in reasonable agreement with the history of sand failure and production in the example wells.

Electrofacies modelling, which includes identification and grouping, is a critical part of reservoir characterisation. Because it governs the estimation and distribution of key rock and rock-fluid properties, the electrofacies model, to a large extent ((if augmented with core-derived information), determines the quality of static and dynamic reservoir models. Unfortunately, owing to the lack of a universally acceptable method, the outcome of electrofacies modelling is not always unique. This explains the usual difficulty in achieving a meaningful comparison of different reservoirs or correlating different packages, even with the same set of well logs. To address the problem, this paper presents a set of mathematical models and simple workflows for quantitative characterisation and grouping of electrofacies in shaly sandstone formations. The gamma ray, density, and neutron, which are commonly available lithology-indicating and absolute-value reading logs, are integrated to define a quantity called composite shaliness parameter. The use of a simple scaling rule ensures that the values of the shaliness parameter are limited to the 0 - 100% range. To make the model universally applicable, the scaling of the shaliness parameter covers the ranges of values of the indicated logs in most shaly sandstone formations. Although the models and workflow are intended to be universally applicable to all shaly sands to enable global benchmarking of formations as may be necessary, provision is made for local applications. In the latter cases, a simple procedure for adapting the scaling rule to specific local problems is presented. Using field examples from the Niger Delta, the validity of the proposed method is examined. It is evaluated against mobility tests, core analysis and spectral gamma-ray log, which are techniques known for better reservoir characterisation at different scales. It is found that the results of the proposed method are in satisfactory agreement with findings from these reference characterisation techniques.