Summary
This paper proposes a method for quantitative integration of seismic
(elastic) anisotropy attributes with reservoir-performance data as an aid in
characterizing systems of natural fractures in hydrocarbon reservoirs. This
method is demonstrated through application to history matching of reservoir
performance using synthetic test cases.
Discrete-feature-network (DFN) modeling is a powerful tool for developing
fieldwide stochastic realizations of fracture networks in petroleum reservoirs.
Such models are typically well conditioned in the vicinity of the wellbore
through incorporation of core data, borehole imagery, and pressure-transient
data. Model uncertainty generally increases with distance from the borehole.
Three-dimensional seismic data provide uncalibrated information throughout the
interwell space. Some elementary seismic attributes such as horizon curvature
and impedance anomalies have been used to guide estimates of fracture trend and
intensity (fracture area per unit volume) in DFN modeling through
geostatistical calibration with borehole and other data. However, these
attributes often provide only weak statistical correlation with fracture-system
characteristics.
The presence of a system of natural fractures in a reservoir induces elastic
anisotropy that can be observed in seismic data. Elastic attributes such as
azimuthally dependent normal moveout velocity (ANMO), reflection amplitude vs.
azimuth (AVAZ), and shear-wave birefringence can be inverted from 3D-seismic
data. Anisotropic elastic theory provides physical relationships among these
attributes and fracture-system properties such as trend and intensity.
Effective-elastic-media models allow forward modeling of elastic properties for
fractured media.
A technique has been developed in which both reservoir-performance data and
seismic anisotropic attributes are used in an objective function for
gradient-based optimization of selected fracture-system parameters. The
proposed integration method involves parallel workflows for effective elastic
and effective permeability media modeling from an initial DFN estimate of the
fracture system. The objective function is minimized through systematic updates
of selected fracture-population parameters. Synthetic data cases show that
3D-seismic attributes contribute significantly to the reduction of ambiguity in
estimates of fracture-system characteristics in the interwell rock mass. The
method will benefit enhanced-oil-recovery (EOR) program planning and
management, optimization of horizontal-well trajectory and completion design,
and borehole-stability studies.
Introduction
Anisotropy and heterogeneity in reservoir permeability present challenges
during the development of hydrocarbon reserves in naturally fractured
reservoirs. Predicting primary reservoir performance, planning development
drilling or EOR programs, completion design, and facilities design all require
accurate estimates of reservoir properties and the predictions of future
reservoir behavior computed from such estimates. Over the history of
naturally-fractured-reservoir development, many methods have been used to
characterize fracture systems and their effect on fluid flow in the reservoir.
These include the use of geologic surface-outcrop analogs; core, single-well,
and multiwell pressure-transient analysis; borehole-imaging logs; and surface
and borehole seismic observations.
To date, efforts to integrate seismic data into the workflow for
characterization of naturally fractured reservoirs have been focused on the use
of post-stack data. CDP stacking of seismic data takes advantage of redundancy
in seismic data sets for the attenuation of noise. Unfortunately, CDP stacking
also eliminates valuable information about spatial and orientational variations
in the data. Such variations are often related to fracture-system
characteristics. CDP-stacked seismic data are typically used to define the main
structural elements of the reservoir. Fracture density has been correlated
successfully with horizon curvature determined from seismic horizons. Seismic
attributes frequently can be correlated with reservoir properties such as shale
fraction, which often correlates with fracture-population statistics. Acoustic
impedance computed from seismic data frequently exhibits dim spots in the
presence of fractures.
© 2005. Society of Petroleum Engineers
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History
- Original manuscript received:
5 April 2004
- Revised manuscript received:
18 January 2005
- Manuscript approved:
25 January 2005
- Version of record:
15 April 2005
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