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March 7-10, 2010 – Manama, Bahrain
Geologic Controls from Pore Pressure Variation in Najmah,Sargelu Formations — A Case Study from Raudhatain Field, North Kuwait
(1) Exploration, Kuwait Oil Company, Ahmadi, Kuwait.
(2) Exploration, Kuwait Oil Company, Ahmadi, Kuwait.
(3) Exploration, Kuwait Oil Company, Ahmadi, Kuwait.
(4) Exploration, Kuwait Oil Company, Ahmadi, Kuwait.
(5) Exploration, Kuwait Oil Company, Ahmadi, Kuwait.
(6) Exploration, Kuwait Oil Company, Ahmadi, Kuwait.
(7) Exploration, Kuwait Oil Company, Ahmadi, Kuwait.
Najmah, Sargelu Formations have a complex petroleum system due to high pressure 17 to 15 ppg., low formation porosity and variable fracture porosity. Pore pressure is extremely variable and difficult to predict.A geological study is done in Raudhatain field to understand pore pressure variation.
Real time pore pressure, well logs, cores and image log fractures are used for the study. Fracture intensity logs from image log fracture data are generated. Correlations are prepared by integrating these data and well test result.Structure contour, Isochore and Pressure maps are prepared.
Structure maps at all stratigraphic levels show uniform trend. Open fracture intensity are high at structural high areas in Lower Najmah Limestone and Sargelu and strike parallel to the regional trend. Away from structural high area open fracture intensity is moderate with strike parallel to regional trend. Pore pressure maps at the top of these two intervals show maximum pressure atstructural high areas and uniform pressure gradient for rest of the area. Isochore maps at the top of these two intervals show uni directional depositional trend and maximum formation thickness at structural high. Well tested in Lower Najmah Limestone and Sargelu has surfaced oil.
Open fracture intensity in Upper Najmah Limestone and Najmah Shale are low and limited to structural high and its strike direction is inconsistent.Sharp contrast in pore pressure are observed between structural high and areas away from it. Isochore maps at the top of these two intervals show shift in depositional axis and maximum formation thickness are not always at structural highs.
In Upper Najmah Limestone and Najmah Shale limited fracture connectivity has resulted in more abrupt pressure variation.Maximum pore pressure are localised at structural highs due to high concentration of open fractures. In Sargelu and Lower Najmah Limestone high fracture intensity and consistent fracture strike have resulted in more uniform pressure variation away from structural high. Open fractures parallel to the regional trend act as conduit for reservoir fluid migration and helped in transmitting formation pressure. Maximum formation thickness at structural high also resulted in increase in effective reservoir thickness in Sargelu. The present study is a base work for building fracture network modeling.