A 4D feasibility study was carried out to evaluate seismic detectability and the application of 4D technology in a green field in deepwater Nigeria. A 3D seismic survey, acquired prior to production, will serve as a baseline for future follow-up 4D survey if the production induced changes are sufficiently detectable.

Time-lapse Feasibility Studies were carried out for two producing fields in the Niger Delta to assess the probabilities of success of acquiring 4D surveys. The two fields are located within onshore Niger Delta. Agbada field is located on land 100km North West of Port Harcourt, Nigeria. The field was discovered in 1960 and has been producing since 1965. To date some 66 wells have been drilled in the field. It has a STOIIP of about 1.5 billion barrels. Current estimate of undeveloped hydrocarbon reserves stand at Expectation Volume of 285 MMbbl and 0.8 Tscf. However, the field is experiencing high water cut and declining production. Agbada Field is covered by several vintages of 2D lines and one vintage of higher quality 3D seismic data that was acquired in the 1993. Kolo Creek field is located within the swamp, 110km South West of Port Harcourt, Nigeria. The field was discovered in 1961 but started production in 1973. It has a STOIIP of 495 MMSTB and an FGIIP of 1.3 TCF. Total Oil production to date is 254MMstb representing 45% of the STOIIP; and there has been no gas production. This field is also experiencing declining production and high water cut. It is also covered by several vintages of 2D lines and one vintage of higher quality 3D seismic data that was acquired in 1997. For each of these fields, it was desired to determine whether time-lapse signals will be detectable and to ascertain the optimum time in which to carry out a time-lapse monitor survey. The history matched dynamic simulation models for each field were converted to acoustic properties through a suitable rock model, and resultant acoustic impedances were calculated. Synthetic seismograms were subsequently generated for several time steps and analyzed for production-induced 4D signals. The impact of various levels of random noise on the 4D response was also evaluated. The results from both of these studies demonstrated that, even in the presence of significant random noise, production induced 4D changes should be observable if the monitor seismic survey is acquired in or beyond 2006. These results will be discussed.

For reservoirs that are not fully appraised, fluid type and resource volumes above Shallowest Known Oil (SKO) or Deepest Known Oil (DKO) are often unknown. This paper discusses the workflow adapted to predict the fluid type above the SKO with reasonable certainty. This enables to book SPE compliant resource volume (SCRV) above SKO to be proposed for booking and up dip wells to be justified. As part of SCRV estimation for Field-X to book hydrocarbon volumes above the SKO, the oil properties, reservoir pressure data and seismic information were integrated utilizing the limitations and uncertainties around each data for the candidate reservoirs. The fluid properties (specifically bubble point pressure) are the most essential element in this analysis, which sometimes are not available or not of sufficient quality. This article will discuss the methodology and workflow adopted to use the existing limited information with their corresponding uncertainties to circumvent these limitations. This methodology was demonstrated as a reliable technology supporting SCRV for Field X, resulting in the increase of ~ 25-30 % of the oil SCRV. Furthermore it has potential to be applied to other fields with similar circumstances.

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The Kangaroo is a field located in the Deepwater Nigeria in water depths ranging from 950 to 1,500 meters. Structurally, the field can be described as a NW-SE trending shale-cored anticline with crestal faulting. Several wells have been drilled encountering primarily oil, in a series of Upper to Middle Miocene channelized turbidite reservoirs. The Kangaroo field is a brown field with challenges of unlocking its full potentials. The key subsurface uncertainties identified, were sand distribution and intra-reservoir connectivity. The existing reservoir models did not fully describe the reservoir net sand thickness and as a result, recent drillings have highlighted series of surprises warranting a study, to gain more insights into the sand distribution and reservoir heterogeneity. This study highlights a multi-stack simultaneous seismic inversion used in conjunction with rock physics analysis, for a detailed reservoir characterisation, re-mapping of key reservoirs and prediction of Net-to-gross away from well control. Five offset angle seismic sub-stacks have been inverted with a Simultaneous Inversion algorithm, ultimately converting the reflectivity seismic data into rock property models, generating acoustic impedance (Zp), shear impedance (Zs), and density (ρ). A feasibility study including crossplots of petrophysical and elastic properties from well data was carried out to establish rock property relationships in the interval of interest and this formed the basis for the seismic inversion studies. Key business driving value for this study, is the derivation of a robust estimates of net sand distribution, its impact on modelling reservoir parameters, and consequent estimation of in-place volumes.