TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractCharacterization of naturally fractured reservoir is a recurring challenge for many oil and gas companies that manage and develop fractured reservoirs. Several techniques have been applied in the past to characterize these complex reservoirs; most of them have been proven unreliable. This paper will describe a methodology to improve the characterization of fractured reservoir using seismic attributes derived from prestack and post-stack high resolution inversion and spectral imaging. The methodology presented in this paper uses the simultaneous integration of geophysical, geologic, and engineering data to improve the reservoir description. At the root of this reservoir characterization technique is the increasingly accurate seismic data collected on most of the reservoirs world-wide. Extensive use of this seismic information is made possible through the use of pre-stack high-resolution elastic inversion, post-stack high resolution inversion, and spectral imaging. These processes allow the derivation of seismic attributes that are extremely relevant to fracturing and could also be used as input in the continuous fracture modeling approach. Based on this seismically driven reservoir characterization, the fractured reservoir properties could be accurately estimated in 3D. An application of this technology and workflow is presented on a very complex fractured reservoir.

This paper describes the application of the Continuous Fracture Modeling (CFM) workflow to the Sabria field in Tunisia. This workflow consists of four steps. The first step in the workflow is to interpret key seismic horizons and use them in high resolution inversion and spectral imaging to create impedance and frequency-dependent seismic attributes. The second step consists of building seismically constrained geologic models of lithology and other petrophysical properties. The third step consists of using the derived geologic models along with all the post-stack seismic attributes and additional geomechanical models to derive high resolution 3D fracture models. The fourth step is to use the derived fracture models in a reservoir simulator to verify the validity of the models by their ability to match past individual well performances and to design optimal well trajectories that intercept a large number of fractures and produce economical oil rates. This workflow was applied to the Sabria field in Tunisia and was followed by actual drilling. The seismic attributes and the appropriate geologic and geomechanical models were used as input in REFRACT, a fracture modeling software, to create accurate 3D fracture models. The resulting fracture porosity and permeability were input in a reservoir simulator. All the past individual well performances were matched, confirming the reliability and accuracy of the derived fracture models. The resulting simulation and fracture models were used to plan multiple horizontal boreholes, drilled underbalanced from a single platform. The resulting oil production from the boreholes and the recorded logs confirm the validity of both the fracture and simulation models. Introduction The increasing demand for gas and oil provides the incentive for E&P companies to seriously consider the significant reserves locked in tight reservoirs. Most of these reservoirs depend heavily on the presence of natural fractures that help bring the hydrocarbons to the wellbore; hence, the acute need to find the means to derive accurate 3D models of fracture density and orientation. The mainstream of the E&P industry is still searching for a fracture modeling approach that systematically delivers answers. The most commonly used fracture modeling approaches have generally been ineffective, as they contain unrealistic assumptions. An illustration of this problem is the assumption that seismic data used for 3D fracture modeling must be designed for wide azimuth seismic acquisition, and seismic information on fractures can only be produced from azimuthal anisotropy studies. The Sabria project described in this paper illustrates that the available post-stack 3D seismic can be successfully used in the Continuous Fracture Modeling (CFM) workflow. The outcome of this workflow was an accurate 3D description of the fractures with a vertical resolution of 3–5 meters and dynamic models that predicted accurately the reservoir performance. Before describing the technologies used to characterize the fractures in the Sabria field, a brief description of the mainstream methods using seismic data in fracture modeling are given below.

This paper describes a workflow that fully utilizes the pre-stack and post-stack seismic attributes to derive reliable geologic and fracture models that are validated by multiple blind wells and reservoir simulation. The first step in the workflow is to run post-stack seismic processes, which includes post-stack inversion and spectral imaging. The second step consists of applying a pre-stack seismic process called elastic inversion which will lead to various key seismic properties that provide good discrimination between reservoir facies. The third step consists of using the various post-stack and pre-stack seismic cubes to derive 3D geologic and fracture models. The fourth step is to use the derived models in a reservoir simulator to verify the validity of the models. This workflow was applied to a complex fractured carbonate field in offshore Tunisia which produces oil from the El Gueria formation. A large number of post-stack and pre-stack seismic attributes were generated in time and then depth converted within a 3D geocellular grid. These seismic attributes were used as input in REFRACT TM , Prism Seismic fracture modeling software, to create geologic and fracture models. The resulting porosity and permeability models were put into Eclipse TM reservoir simulator software. Individual well performances were matched at eighty percent of the wells, confirming the reliability and accuracy of the derived geologic and fracture models and the usefulness of the workflow.

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