Relative Permeability of Naturally Fractured Reservoirs From Field Performance Data

1989 ◽  
Author(s):  
L.A. Owusu ◽  
I. Ershaghi
Keyword(s):  
Relative Permeability ◽  
Fractured Reservoirs ◽  
Field Performance ◽  
Performance Data ◽  
Naturally Fractured Reservoirs ◽  
Naturally Fractured

scholarly journals Integration of Seismic Anisotropy and Reservoir Performance Data for Characterization of Naturally Fractured Reservoirs Using Discrete Feature Network Models

2005 ◽  
Vol 8 (02) ◽  
pp. 132-142 ◽  
Author(s):  
Robert Will ◽  
Rosalind A. Archer ◽  
William S. Dershowitz
Keyword(s):  
Seismic Data ◽  
Elastic Anisotropy ◽  
Fractured Reservoirs ◽  
Seismic Attributes ◽  
Performance Data ◽  
Naturally Fractured Reservoirs ◽  
Fracture System ◽  
Reservoir Performance ◽  
Naturally Fractured ◽  
System Characteristics

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 move out velocity (ANMO), reflection amplitude vs. azimuth (AVAZ), and shear-wave birefringence can be inverted from 3D-seismicdata. 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 that3D-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.

Numerical Investigation of Wettability Effects on Two-Phase Flow in Naturally Fractured Reservoirs Using Complex System Modelling Platform

2021 ◽  
Author(s):  
Mohammad Sedaghat ◽  
Hossein Dashti
Keyword(s):  
Complex System ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Wettability Alteration ◽  
System Modelling ◽  
Naturally Fractured ◽  
Relative Permeability Curves

Abstract Wettability is an essential component of reservoir characterization and plays a crucial role in understanding the dominant mechanisms in enhancing recovery from oil reservoirs. Wettability affects oil recovery by changing (drainage and imbibition) capillary pressure and relative permeability curves. This paper aims to investigate the role of wettability in matrix-fracture fluid transfer and oil recovery in naturally fractured reservoirs. Two experimental micromodels and one geological outcrop model were selected for this study. Three relative permeability and capillary pressure curves were assigned to study the role of matrix wettability. Linear relative permeability curves were given to the fractures. A complex system modelling platform (CSMP++) has been used to simulate water and polymer flooding in different wettability conditions. Comparing the micromodel data, CSMP++ and Eclipse validated and verified CSMP++. Based on the results, the effect of wettability alteration during water flooding is stronger than in polymer flooding. In addition, higher matrix-to-fracture permeability ratio makes wettability alteration more effective. The results of this study revealed that although an increase in flow rate decreases oil recovery in water-wet medium, it is independent of flow rate in the oil-wet system. Visualized data indicated that displacement mechanisms are different in oil-wet, mixed-wet and water-wet media. Earlier fracture breakthrough, later matrix breakthrough and generation and swelling of displacing phase at locations with high horizontal permeability contrast are the most important features of enhanced oil recovery in naturally fractured oil-wet rocks.

Tensor Analysis of the Relative Permeability in Naturally Fractured Reservoirs

SPE Journal ◽  
2019 ◽  
Vol 25 (01) ◽  
pp. 162-184
Author(s):  
Mohammad H. Sedaghat ◽  
Siroos Azizmohammadi ◽  
Stephan K. Matthäi
Keyword(s):  
Relative Permeability ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Permeability Tensor ◽  
Absolute Permeability ◽  
Scalar Quantity ◽  
In Situ Conditions ◽  
Discrete Fracture ◽  
Naturally Fractured ◽  
The Absolute

Summary Fluid evidence shows that prediction of water breakthrough and oil recovery from fractured reservoirs cannot be performed accurately without upscaled relative permeability functions. Relative permeability is commonly assumed to be a scalar quantity, although the justification of that—specifically for naturally fractured reservoirs (NFRs)—is rarely attempted. In this study, we investigate the validity of this scalar-quantity assumption and how it affects fracture/matrix equivalent relative permeabilities, kri(Sw), achieved by a numerical simulation of unsteady-state waterflooding of discrete-fracture/matrix models (DFMs). Numerical determination of relative permeability requires a realistic model, a spatially adaptive simulation approach, and a sophisticated analysis procedure. To fulfil these requirements, we apply the discrete-fracture/matrix modeling to well-characterized outcrop analogs at the hectometer to kilometer scale. These models are parameterized with aperture and capillary entry pressure data, taking into account variations from fracture segment to segment, trying to emulate in-situ conditions. The finite-element-centered finite-volume method is used to simulate two-phase flow in the fractured rock, while also considering a range of wettability conditions from water-wet to oil-wet. Our results indicate that the fracture/matrix equivalent relative permeability is a weakly anisotropic property. The tensors are not necessarily symmetric, and the absolute-permeability tensor is the most influential factor, determining the level of anisotropy of kri. The anisotropy ratio (AR) changes with saturation, is influenced by the fracture/matrix-interface wetted area (Awf), and differs for each phase. In addition, the diagonal terms of the equivalent relative permeability tensor (krii), determined using our novel approach, can be different from those obtained using the assumption that kri is scalar. The magnitude of the difference is controlled by the absolute permeability, wettability, flow rate, and orientation of the fractures in the model. It is worth mentioning that the type and direction of imbibition can be determined by off-diagonal terms of the kri tensor. Furthermore, krii largely depends on the direction of the waterflood along the i-axis.

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