The Natural Fracture Evaluation in the Unconventional Tight Oligocene Reservoirs - Case Studies from CuuLong Basin, Southern Offshore Vietnam

Abstract

Abstract The Oligocene Formation in CuuLong Basin, Southern offshore Vietnam, is predominantly fluvial-lacustrine sand and shale sequences deposited above the pre-Tertiary granite basement. The reservoir sands are usually tight with average porosity about 10%, and variable but mostly low permeability. In many wells targeting the granite basement, significant oil shows have been detected when drilling through the Oligocene section. However, it is usually difficult to get a well to flow naturally from this section due to the tight matrix. Therefore, the Oligocene sands were rarely paid much attention. With commercial discoveries of both oil and gas made in several fields in the CuuLong basin recently, reassessment of the potential for the Oligocene sands has been brought back to the agenda. Natural fractures or faults are among the most important aspects to evaluate when assessing this tight formation. This paper presents a few recent case studies on fracture characterization for the Oligocene reservoirs. The data used includes core, borehole images, conventional open-hole logs, mud logs as well as DST dynamic data. Natural fractures including both open and mineralized ones are quite common in the tight Oligocene formation even though the fracture density and type might vary from one well to another depending on the structural location of the well, proximity to faults and depth in the vertical sequence. It is believed that the naturally open fracture or fault plays an important role in enhancing the reservoir permeability for potential natural flow in a well. The healed fractures, on the other hand, might block the lateral reservoir communication. Locating the fractured zones is also important for perforation decision and frac job design, if stimulation is required for a well.