Use of DST for Effective Dynamic Appraisal: Case Studies
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis-Denney, contains highlights of paper SPE 97113, "Use of DST for Effective Dynamic Appraisal: Case Studies From Deep Offshore West Africa and Associated Methodology," by J.L.B. de la Combe, SPE, O. Akinwunmi, SPE, C. Dumay, and M. Tachon, Total S.A., prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October.

In the west Africa deep offshore region, most turbiditic-series reservoirs are structural traps with a stratigraphic component and severe faulting. Evaluation of connectivity and characterization of the reservoir heterogeneities before development decisions are the main challenges. Two extended drillstem tests (DSTs) acquired at a relatively early stage of the appraisal had a significant effect on the development projects.

Case Study 1

Well A was the third appraisal well of a Nigerian deepwater field. The well was the first in the southern fault block. Hydrocarbon presence had been proved in the central and northern compartments, but the southern compartment was separated from the central compartment by an east/west fault having significant throw.

Formation-testing-log (FTL) measurements confirmed the presence of oil in the reservoir sands. Preliminary pressure/volume/temperature (PVT) analyses carried out on the FTL samples indicated a fluid very close to saturation pressure, while permeability estimates from FTL mobility and magnetic-resonance (MR) -log data indicated permeability ranging from 1 to 3 darcies. Therefore, it was decided to run a DST on the reservoir interval with perforations across the entire sand portion of the reservoir.

Test Design. Well-test-design software was used to define an optimal test sequence. The major problem encountered in these deep offshore tests was programming a buildup test longer than 30 hours. Both gauge resolution and tidal effect strongly influence the late-time derivative, and even after deconvolution of tidal effect, it may not be possible to obtain a denoised signal because of high permeability of the unconsolidated sands in turbiditic channels. The other constraint was that bubblepoint pressure was very close to initial pressure. Thus, to avoid liberating gas in the reservoir, high flow rates could not be achieved.

The design required two buildup tests to account for transient depletion between the two buildup tests. Different models do not generate the same transient depletion: a channel model generates more transient depletion than a single-fault model. Therefore, the well-test analyst can diagnose events that are beyond the buildup derivative. The cumulative oil produced during the drawdown between the two buildup tests was computed to generate a 50-kPa depletion for a connected reservoir with 8.7×106 m3 of stock-tank oil originally in place (STOOIP). A main objective was to characterize the seismic attenuation on the east side of the well.

Data Overview. Because of problems during cleanup and a high skin value during the first buildup, BU1, another flow period and a second buildup, BU2, were performed. During the second flow period, with a large pressure drawdown, the derivative signature was perturbed by tidal effects after 10 hours' shut-in. The tidal effect was removed, and the buildup derivatives of BU2 and the final buildup, BU3, were compared after tide deconvolution. They were practically superposed. Therefore, BU2 and BU3 are selected for analysis because of their greater durations.