Reservoir Characterization of 1st Eocene Heavy Oil Carbonate Formation Using FMI* Fullbore Formation MicroImager in Wafra Field - A Case Study
Eloutefi, Nader M.2; Smith, John R.2;
Al-Khaldi, Fahad 2; Aviantara, Alexander A.1; Al-Khabbaz,
Mohammed 1
(1)Data & Consulting Services, Schlumberger Oilfield
Eastern Ltd., East Ahmadi, Kuwait. (2) PNZ Kuwait, Saudi Arabian Chevron Inc. -
Kuwait Gulf Oil Company (K.S.C), Joint Operations - Wafra, Wafra, Kuwait.
The Wafra field is a heavy oil carbonate reservoir lies in the northwest part of Kuwait / Saudi Arabia Partitioned Neutral Zone (PNZ). The structure of Wafra consists of two parallel anticlines, trending northwest - southeast. It is proposed that these anticlines are cut by northeast - southwest elements (strike slip faults). The reservoirs range from shallow to Paleocene - Eocene Formation.
The 1st Eocene carbonate reservoir is complicated due to multiple conditions such as heavy oil reservoir, heterogeneous lithology, varying scale of fracturization and provisional NE-SE elements. It has been a challenge to do proper reservoir characterization for this particular formation.
Vertical, deviated and horizontal wells have been analyzed for the best reservoir characterization approach. The FMI* Fullbore Formation MicroImager analysis includes (1) fracture / fault identification; (2) fracture corridor; (3) porosity and evaporites quantification; and (4) permeability estimation using porosity partitioning and heterogeneity methods which are calibrated with core.
Vertical wells show the most common fracture developments in 1st Eocene have a 100 dip and 1000 - 2800 strike azimuth and, in WAFB reservoir zone, 500 dip and 1400 - 3200 strike azimuth. In the deviated wells, fractures are developed in WAFD reservoir zone with 850 dip and 1750 - 3550 strike azimuth. The number of fractures in both vertical and deviated well is 5 and 9 fractures for an interval of 444 ft and 323 ft respectively. In the horizontal well 95 fractures are encountered in a 2104 ft interval. Three fracture corridors are also identified within this horizontal section.
The porosity, aperture and permeability contributed by fractures are analyzed with the high resolution FMI* Fullbore Formation MicroImager log. The permeability is derived from open hole logs and FMI* Fullbore Formation MicroImager logs by incorporating the dual porosity information using the newly-developed porosity partitioning model. The best interval in WAFB reservoir zone shows the secondary porosity range is 0 - 8% and permeability derived from secondary porosity is in the range of 20 - 400 md with average about 200 md. A combination of good permeability, good secondary porosity distribution and fractures makes this WAFB reservoir zone the best candidate for the production zone.
AAPG Search and Discovery Article #90135©2011 AAPG International Conference and Exhibition, Milan, Italy, 23-26 October 2011.