Abstract:
INTRODUCTION

The E-M Reservoir sands lie within a thick regressive ransgressive fluvio-deltaic to shallow marine part of the early Cretaceous synrift sequence. In the E-M field most of the hydrocarbons are found in the uppermost part of this sequence. Traps are sealed by thick marine claystones, which overlay the 1At1 unconformity.

The general pre-1At1 E-M field structure is interpreted as a half-graben, with the main boundary fault to the North. The southern margin to the half-graben is complex in places, showing interaction of northerly dipping antithetic faults with southerly dipping boundary faults. Many of the faults may show normal net displacement at deeper levels, but reverse offsets at the top of the upper shallow marine. This indicates at least one episode of inversion at around 1At1 to 6 At1 times. The E-M gas field has been on production for 3 years. Dynamic data indicates that the reservoir is more complex than the present reservoir model predicted and that the compartments within which the wells lie are smaller than presently mapped field polygons.

An assessment of the E-M structural model recognised that reverse faults may be more common than previously interpreted and that the field may be more compartmentalised.

The present 3D seismic dataset is not of sufficient resolution to confidently map smaller compartmentalisation within the field polygons. Multiple problems below the reservoir reduce data quality and this makes interpretation of deeper structures ambiguous.

Objectives

The challenge is to target the multiple attenuation in the in-line direction whilst the multiples are more easily identifiable in cross line direction.

Interpretation of this reprocessed dataset will focus on the development of a structural model that may aid the prediction of subtle and sub-seismic fault arrays. This will change some fault geometries (e.g. normal to reverse) and may introduce some subtle small-scale faults.

Executive summary

The offshore Cabinda, Angola Block 0 concession is operated by Chevron for partners Sonangol, Total, and ENI. The 5500 sq km concession produces nearly 400,000 bopd from 23 developed fields. Cumulative production in the block is 3.1 BBO. Eighty-four percent of production has come from fields located in less than 60 meters of water. The deepest water depth on the block is 200 meters, adjacent to the Congo River Canyon. Various play types exist in the block. The two play types responsible for the majority of production on Block 0 are pre-salt Lucula sandstone and Toca carbonates trapped along flanks of basements highs, and post-salt Pinda sandstone and carbonate and Vermelha sandstone trapped in rollover structures.

Obtaining the best possible seismic image of these very different play types is critical to continued exploration and production success on the block. The historical exploration drilling success rate is approximately 40%; the main exploration risk elements for a given prospect on the block are reservoir and trap geometry. Source and hydrocarbon migration risk are low. The challenge in Block 0 is to make a step change improvement in seismic data quality.

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