Well test analysis in naturally fractured reservoirs is generally based on the radial flow model. The radial flow model is however only applicable to purely homogeneous system and long time solution. It cannot provide complete formation analysis in a reservoir that exhibit anisotropy. This study therefore presents a new method of estimating permeability anisotropy in naturally fractured reservoirs.
Maximum and minimum permeability are obtained in one well test. The maximum permeability is attributed to the large scale fractures in the system while the minimum permeability may be due to the small scale fractures orthogonal to the large scale fractures. In a situation where the fractures are orienting in one direction, the minimum permeability will reflect the matrix permeability. The type of flow path developed (narrow or wide flow path) can also be predicted. This is useful in predicting the direction of fluid flow.
Application was made to four field examples, one of which was an interference test. The interference test was used as a validation process. The results obtained are in agreement with that of interference test method of analysis.
Naturally fractured reservoirs are anisotropic systems whose flow characteristics depend on the fracture network. Their permeability variation is not only stratigraphic in nature, but is also caused by the fractures' distribution, orientation and permeability impairment within the fractures, caused by pressure solution. The reservoir becomes more complex when both the matrix and fracture exhibit anisotropy and have the capability to flow into the wellbore as in double permeability case.
According to Nelson1, naturally fractured reservoirs can be divided into four categories.
Type 1 Fractures provide the essential porosity and permeability.
Type 2 Fractures provide the essential permeability while the matrix provides the essential porosity.
Type 3 Fractures assist permeability in an already producible reservoir. The matrix already has good permeability.
Type 4 Fractures provide no additional porosity or permeability, but create significant reservoir anisotropy (barriers) due to mineral filled.
Previous studies have shown that the fractures distribution and their permeability depend on the stress anisotropy. According to Price1, the two perpendicular orientations of most regional fracture sets are rotated to basin shape. As most basins are elliptical, one orientation of the orthogonal pattern parallels the long axis of the basin and the other parallel the short axes of the basin. High permeability fracture network will align with the maximum stress direction. Figure 1 is an example of such naturally fractured reservoir in offshore Abu Dhabi2. According to Gouth2, the interpretation of 3D seismic shows numerous low displacement NW-SE striking normal faults cutting the reservoir (Figure 1). These faults are oriented perpendicular to the dominant trend of the open fracture system and predate the formation of the open fractures. A second set of fractures is subparallel to the fault trends, but since they are described as mineralized, these fractures are assumed to be healed and have little effect on fluid flow. Thus the SW-NE trending open fractures formed the maximum permeability.
