Characterization and Modelling Study of a Triple Porosity Fractured Reservoir
Authors: Gouth Francois Michel , Aziz Sabah K. , Jeanjean Frederic , Soyeur Christophe , Moen-Maurel Laure 
Published: February 2016

An integrated, multi-disciplinary, fracture characterization & modeling study has been performed on a large oil reservoir in offshore Abu Dhabi.

This paper describes the methodology used for analyzing and integrating the geophysical, geomechanical, geological and reservoir data in order to achieve a comprehensive understanding of the fracture network and its effect on fluid flow.

The study has highlighted the existence of two scales of fractures developing in this reservoir and forming a triple porosity system in regions where they are interconnected:Diffuse fractures which strike N20 to N40. This scale develops mostly in the denser reservoir units. Its spacing is controlled by the mean curvature of the seismic Top-Reservoir surface and by the structural depth. On the crest, it forms a connected network of a few tens of mD of equivalent permeability i.e. about 10 times the matrix permeability.Large scale fractures forming a connected network on the crest of the structure. They are associated with N30 corridors and N90-N140 trending faults yielding an equivalent permeability of a few hundreds of mD, which is highly anisotropic with a main axis consistent with the maximum horizontal stress azimuth.

The originality of the work is based on the following:Intensive use of 3D seismic imaging to characterize the spacing of the large scale fractures, which were poorly sampled by the existing wells.Advanced use of pressure build up and interference tests to characterize the fracture permeability field i.e. average value, anisotropy ratio and extension.

The diffuse fractures were modeled using a DFN. The drivers (depth and curvature) used for the populating of the diffuse fractures in the full field model were also used for the large scale fractures since data suggest that both scales develop in the same areas. A strategy is proposed to lump together the two fracture scales in a dual porosity dual permeability reservoir model. The resulting dynamic model was easily history matched and required only slight adjustments.

Introduction

The A reservoir in S Field is a fractured and faulted Lower Cretaceous carbonate capable of oil production from 3 intervals. It consists of layered chalky intervals with relatively high porosity (~20%) and poor matrix permeability (2–10 md) interbedded with dense, highly fractured layers. The overall structure of the field is a broad, gently dipping dome with slight elongation oriented NE-SW (Fig.1). The average thickness of the two main sub-units is about 304 ft.

Production tests data, core observations, and FMI/FMS image logs confirm high fracture permeability with open fractures oriented N30E across the crest of the structure. The interpretation of 3D seismic shows numerous low displacement NW-SE striking normal faults cutting the reservoir (Fig.2). These faults are oriented perpendicular to the dominant trend of the open fracture system and predate the formation of open fractures. A second set of fractures is sub-parallel to the fault trends, but since they are described as mineralized these are assumed to be healed and have little effect on fluid flow.

Oil is strongly undersaturated and the bubble point is about 2800 psi below the initial reservoir pressure. Oil production from the A reservoir started in the seventies from one well drilled on the apex of the structure and showing large productivity that could only be related to fractures. Production was temporarily suspended three years later, and resumed in the eighties. Three extra wells were added at that time. Maximum production reached a few thousands of barrils per day. Production was suspended again two years later due to high water and salt content in the oil, and rapid pressure decline. Available reservoir performance history and pressure data suggested limited water drive and lack of reservoir energy leading to an estimated very low primary recovery.

Well data from the flank of the structure showed low productivity. Due to the degraded reservoir properties on the flanks, reservoir studies concluded that the best recovery mechanism for A reservoir was gas injection. A pilot well was drilled in October 1994 on the crest of the structure. As a result of gas flow through a network of fractures, rapid breakthrough of injected gas was observed at the producing wells. All producing wells were shut-in in May 1996 due to increasing GOR. Gas injection continued until 1999 at which time injection was stopped. Production was intermittently resumed since that time according to pressure response and well potentials. The further development of the field was then suspended pending a better understanding of the fracture network.