--> Abstract: N'Sano Pinda - Characterization of a Finely Inter-Bedded Carbonate Siliciclastic Reservoir, Offshore Cabinda, Angola, by R. Minck, G. King, R. DaCosta, F. Domingos, B. Carleton, C. Laidlaw, and E. Leggett; #90933 (1998).

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Abstract: N'Sano Pinda - Characterization of a Finely Inter-Bedded Carbonate Siliciclastic Reservoir, Offshore Cabinda, Angola

Minck, R. and G. King - Chevron; R. DaCosta and F. Domingos - Sonangol, B. Carleton, C. Laidlaw, and E. Leggett - CABGOC

The Early Cretaceous Pinda Formation in N'Sano Field, Offshore Cabinda, Angola, contains approximately 170 MMSTBOOIP and produces about 20,000 BOPD. Water injection of 50,000 BWPD is necessary to maintain adequate pressure and manage gas production. A reservoir characterization was undertaken to provide detailed geologic input to a reservoir simulation. The objective of the simulation was to model production in the N'Sano Pinda reservoirs to 1) minimize gas production by optimizing water injection, 2) determine if any wells could be taken off Pinda production and applied to other reservoirs and 3) determine if any infill wells were needed.

Pinda reservoirs at N'Sano Field were deposited in a flat, highly cyclic, nearshore marine to lagoonal environment (Fig. 1). Stacking of parasequences resulted in vertically alternating reservoir rocks and seals (Fig. 2). These thin-bedded seals formed 24 different pressure compartments, each roughly equivalent to a parasequence, and eight major reservoir zones (Z1 to Z8), each roughly equal to a fourth-order sequence. Facies changes also caused lateral variations in permeability that hinder oil production and water injection by limiting aquifer support and reservoir continuity in some zones.

In situ mixing of Pinda sediments caused by channel, tidal, wave and current action caused a very heterogeneous mineralogy in Pinda sediments. The best reservoirs were deposited in high-energy environments, which winnow out sediments that decrease reservoir quality.

The N'Sano Pinda Reservoir Characterization used a categorical facies simulation to model permeability and reservoir continuity. Nine facies with different porosity-permeability transforms and mineralogy were identified from core data. A facies log for each of 13 wells was produced from log estimated mineralogy. Permeability logs were then calculated according to facies. The log data were loaded into a geostatistical modeling program, G2/GOCAD, to simulate porosity, permeability and facies.

The stratigraphic model output by the categorical facies simulation had high energy, high permeability facies on the crest of the structure where the producing wells are and low energy, low permeability facies off-structure where injector wells are located. This enabled accurate modeling of the limited aquifer support and limited reservoir continuity between injection and production wells in some zones.

The geostatistical model was scaled-up and loaded into a reservoir simulation. Results of the simulation showed a good match with historical oil and water production before any adjustments were made. This resulted in saving time due to the accuracy of modeling the spatial variability of reservoir parameters and an engineering model that honored geologic trends.

A single transform non-facies reservoir characterization was then run to compare with the multiple transform facies reservoir characterization. The non-facies characterization produced non-geologic trends and greater connectivity than the facies-based model. The two characterizations were run in comparable reservoir simulations. A comparison of the two simulations yielded a higher predicted total field oil production rate for the non-facies-based model.

AAPG Search and Discovery Article #90933©1998 ABGP/AAPG International Conference and Exhibition, Rio de Janeiro, Brazil