First EAGE West Africa Workshop 2013 - Subsurface Challenges in West Africa

In this paper, we review some of the results from regional pressure analysis of the Deep Water/Ultra-Deep Water and Shelf areas, Niger Delta. Direct pressure data have been analysed to produce a set of maps of reservoir overpressure. Wireline logs from hundreds of wells were analysed for shale pressures, and compared to direct measurement of reservoir pressures where available. Shale pressure algorithms were qualified by careful analysis of overpressure mechanisms, with particular reference to the deep Shelf where temperatures reach 140oC in the Agbada shales. The comparison between sand and shale pressures leads to conclusions about regional reservoir connectivity, vertical pressure communication and seal effectiveness. Both regional and local relationships to describe fracture pressure and overburden have also been developed as part of this study, all of which lead to more confidence for safe and cost-effective well planning, as well as estimates of seal breach for highly pressured traps. In addition, the nature of regional reservoir connectivity predicts trapping geometries and relationships between hydrocarbons and fluid flow phenonema which would otherwise be ignored. Careful analysis of pressure data in producing fields confirms many of these relationships.

Significant lateral velocity heterogeneity occurring near the surface complicates processing of Gabon onshore seismic data. While implicitly PSDM imaging from the recording surface can deal with this type of heterogeneity, this paper discusses how in PSTM imaging a velocity-adaptive pseudo datum in primary static corrections may help coping with the near-surface heterogeneity. Tests performed on synthetic seismic data and the review of processing flows of real seismic data suggest, that the utilization of velocity-adaptive pseudo datum results in PSTM images superior to those based on primary static corrections using a flat pseudo datum.

The Mutamba Iroru Permit, operated by VAALCO Production (Gabon), Inc., since 2005, is located within the onshore portion of the South Gabon Sub-Basin, which contains some of the largest hydrocarbon accumulations within West Africa. The 30-50m thick Cretaceous Aptian-aged transgressive sandstones of the Gamba Formation form the main producing reservoir in the block. The primary hydrocarbon traps for Gamba sands in the block are four-way structural closures formed over tilted pre-Gamba fault blocks, sealed by the overlying Ezanga salt formation. Seismic imaging is very difficult below the often strongly deformed Ezanga salt formation, and is also problematic when attempting to define the flanks of the salt structures. It was recognized that Airborne Gravity Gradiometry (AGG) could assist the seismic interpretation by providing more accurate mapping of the flanks of the salt structures and help identify other sub-salt structural features. From November 2007 to February 2008 Fugro Airborne Surveys flew a 6,250 line-km FALCON AGG survey over the Mutamba Iroru Permit in a Cessna 208B Grand Caravan over 24 production flights. An integrated interpretation of the FALCON AGG data helped to delineate the outline, geometry and relative thickness of the low density Ezanga salt and near-surface cuvette features, and thus highlighted the sub-areas where seismic imaging is severely challenged. Once these geometries were better delineated, seismic imaging subsequently improved.

This research unites data with different sources, different scale and different precision. It proves that combining shale barriers based on seismic inversion and interbeds from well logging interpretation to represent the internal feature of the reservoir is more reasonable. Transforming the grid system and at the same time keeping the main geological features to optimize the model for reservoir numerical simulation is a good way to improve the convergence and benefit the dynamic historical matching.

Turbidity sediment with heterogeneous sand is observed in offshore Nigeria. High risks exist in the potential area where infilling wells is proposed for its uncertainty in terms of reservoir development. It is hard to fully describe the reservoir using routine seismic profile during the development period. Seismic inversion integrated with the sedimentary facies illustrated the sand connectivity and fluid distribution characteristics successfully. Sparse-spike inversion and stochastic simulation inversion methods are utilized in EBNE field to improve vertical and lateral resolution for sand and shale description. The sparse-spike inversion result reflects the reservoir spatial distribution in terms of seismic reflection characteristics and loggings, but the thin sand and shale can’t be distinguished. The impedance inversion, which is based on the stochastic simulation inversion method, has higher resolution. Both the thin and thick sands spatial distributions are clearly identified. 5 impedance data sets are generated using stochastic simulation method and 1of them chosen as the reasonable one based on logging interpretation and reservoir development characteristics. Detailed sand thickness mapping based on stratigraphic correlation results provided the basic element for potential analysis. Seismic inversion result is utilized to reduce sand distribution uncertainty for drilling candidate.

Gamma-ray (GR) logs are standard logs used for well correlation and are subject to multiple uncertainties such as calibration errors, tool design, differing vendors, and inappropriate environmental corrections. Data inconsistency needs to be corrected through the process of log normalization. GR normalization is one part of integrating all available data for stratigraphic interpretation and structural mapping. The onshore Tsiengui field is located in the northern part of the South Gabon Sub Basin. The reservoir, located in Gamba Sandstone and Dentale formations, is characterised by typical rift phase sequences. A standard GR normalization equation adapted to our study with the selection of two end-member lithologies was applied. The Ezanga Salt and Ezanga Shale located above the reservoir and both widespread and correlatable on a regional scale have been chosen. The normalization highlighted subtle differences in GR response which allowed differentiation between the Gamba Sandstone and the Dentale in areas where the Dentale consisted of sand and the contact was sand-on-sand. It also allowed for a better correlation of the sand and shales successions in the Dentale.

We present a case study from the Kwanza basin offshore Angola where we built a detailed tilted transversely isotropic (TTI) model over an area of more than 8000 km2. We incorporate general knowledge of the area and analysis of data anellipticity in the process, derive Thomsen’s δ in wells from a neighboring area and use spatially variable ε and δ fields, honoring the geometry of interpreted carbonate geo-body. The results are compared against images produced with both a much simpler regional TTI model and a legacy isotropic model. We demonstrate that, in spite of the lack of well control, high-quality TTI imaging is not only possible, but essential for producing geologically plausible and interpretable images in this complex area and that adding data- and interpretation-driven complexity in the TTI models could further improve the imaging of pre-salt targets.

On Anguille Marine, subsurface uncertainties interfere with a long production history and aging installations. To face this complex environment, a phased approach has been chosen to optimise the further development of the field, combining 3 main objectives: developing new reserves, ensuring the longevity of the existing production facilities, and reducing the environmental footprint of the company. This approach developed and implemented on Anguille is now being applied on another asset with similar problematic, Torpille Marine, in an effort of the company to fight the production decline and ensure an operated production plateau around 60.000 stb/d for the coming years.

Shell Gabon and Shell Projects & Technology are maturing plans to further develop the Gamba Ivinga oil field, Shell Gabon’s first producing asset in the Republic of Gabon, as part of an overall programme to arrest production decline, improve environmental performance, and secure the longevity of production and export facilities. Located adjacent to Gamba Terminal, some 250km to the south of Port Gentil, the Gamba Ivinga field has been on production for 46 years. Whilst production is well below plateau rates last seen in the 1970’s, production over the last 15 years has been relatively stable. Gross off-take is balanced by aquifer influx, with oil cut following an established trend.