Experimental study on CO2-EOR in fractured reservoirs: Influence of fracture density, miscibility and production scheme

Interpretation and inversion of azimuthally varying nonhyperbolic reflection moveout requires accounting for both velocity anisotropy and subsurface structure. Here, our previously derived exact expression for the quartic moveout coefficient A4 is applied to P‐wave reflections from a dipping interface overlaid by a medium of orthorhombic symmetry. The weak‐anisotropy approximaton for the coefficient A4 in a homogeneous orthorhombic layer is controlled by the anellipticity parameters η(1), η(2), and η(3), which are responsible for time processing of P‐wave data. If the dip plane of the reflector coincides with the vertical symmetry plane [x1, x3], A4 on the dip line is proportional to the in‐plane anellipticity parameter η(2) and always changes sign for a dip of 30○. The quartic coefficient on the strike line is a function of all three η–parameters, but for mild dips it is mostly governed by η(1)—the parameter defined in the incidence plane [x2, x3]. Whereas the magnitude of the dip line A4 typically becomes small for dips exceeding 45○, the nonhyperbolic moveout on the strike line may remain significant even for subvertical reflectors. The character of the azimuthal variation of A4 depends on reflector dip and is quite sensitive to the signs and relative magnitudes of η(1), η(2), and η(3). The analytic results and numerical modeling show that the azimuthal pattern of the quartic coefficient can contain multiple lobes, with one or two azimuths of vanishing A4 between the dip and strike directions. The strong influence of the anellipticity parameters on the azimuthally varying coefficient A4 suggests that nonhyperbolic moveout recorded in wide‐azimuth surveys can help to constrain the anisotropic velocity field. Since for typical orthorhombic models that describe naturally fractured reservoirs the parameters η(1,2,3) are closely related to the fracture density and infill, the results of azimuthal nonhyperbolic moveout analysis can also be used in reservoir characterization.

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Model-based amplitude versus offset and azimuth inversion for estimating fracture parameters and fluid content

Geophysics ◽

10.1190/geo2016-0196.1 ◽

2017 ◽

Vol 82 (2) ◽

pp. M1-M17 ◽

Cited By ~ 12

Author(s):

Jiao Xue ◽

Hanming Gu ◽

Chengguo Cai

Keyword(s):

Seismic Data ◽

Shear Fracture ◽

Influencing Factor ◽

Fractured Reservoirs ◽

Fracture Density ◽

Inversion Algorithm ◽

Fluid Content ◽

Fracture Parameters ◽

Amplitude Versus Offset ◽

Amplitude Versus

The normal-to-shear fracture compliance ratio is commonly used as a fluid indicator. In the seismic frequency range, the fluid indicator lies between the values for isolated fluid-filled fractures and dry fractures, and it is not easy to discriminate the fluid content. Assuming that the fracture surfaces are smooth, we use [Formula: see text], with [Formula: see text] and [Formula: see text] representing the normal fracture weakness of the saturated and dry rock, to indicate fluid types, and to define a fluid influencing factor. The fluid influencing factor is sensitive to the fluid properties, the aspect ratio of the fractures, and the frequency. Conventionally, the amplitude versus offset and azimuth (AVOA) inversion is formulated in terms of the contrasts of the fracture weaknesses across the interface, assuming that the fractures are vertical with the same symmetry axis. We consider fractures with arbitrary azimuths, and develop a method to estimate fracture parameters from wide-azimuth seismic data. The proposed AVOA inversion algorithm is tested on real 3D prestack seismic data from the Tarim Basin, China, and the inverted fracture density show good agreement with well log data, except that there are some discrepancies for one of the fractured reservoir sections. The discrepancies can be ascribed to neglect of the dip angle for the tilted fractures and the conjugate fracture sets, and to the validity of the linear-slip model. The fractured reservoirs are expected to be liquid saturated, under the assumption of smooth fractures. Overall, the inverted fracture density and fluid influencing factor can be potentially used for better well planning in fractured reservoirs and quantitatively estimating the fluid effects.

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Geomechanical key parameters of the process of hydraulic fracturing propagation in fractured medium

Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles ◽

10.2516/ogst/2019026 ◽

2019 ◽

Vol 74 ◽

pp. 58 ◽

Cited By ~ 1

Author(s):

Rouhollah Basirat ◽

Kamran Goshtasbi ◽

Morteza Ahmadi

Keyword(s):

Hydraulic Fracturing ◽

Numerical Models ◽

Fractured Reservoirs ◽

Natural Fracture ◽

Propagation Path ◽

Fracture Density ◽

Strength Parameters ◽

Propagation Process ◽

Fractured Medium ◽

Hf Propagation

Hydraulic Fracturing (HF) is a well-stimulation technique that creates fractures in rock formations through the injection of hydraulically pressurized fluid. Because of the interaction between HF and Natural Fractures (NFs), this process in fractured reservoirs is different from conventional reservoirs. This paper focuses mainly on three effects including anisotropy in the reservoir, strength parameters of discontinuities, and fracture density on HF propagation process using a numerical simulation of Discrete Element Method (DEM). To achieve this aim, a comprehensive study was performed with considering different situations of in situ stress, the presence of a joint set, and different fracture network density in numerical models. The analysis results showed that these factors play a crucial role in HF propagation process. It also was indicated that HF propagation path is not always along the maximum principal stress direction. The results of the numerical models displayed that the affected area under HF treatment is decreased with increasing the strength parameters of natural fracture and decreasing fracture intensity.

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Experimental study of dynamic imbibition during water flooding of naturally fractured reservoirs

Journal of Petroleum Science and Engineering ◽

10.1016/j.petrol.2018.11.008 ◽

2019 ◽

Vol 174 ◽

pp. 1-13 ◽

Cited By ~ 9

Author(s):

Behrouz Harimi ◽

Mohsen Masihi ◽

Abouzar Mirzaei-Paiaman ◽

Esmaeil Hamidpour

Keyword(s):

Experimental Study ◽

Fractured Reservoirs ◽

Naturally Fractured Reservoirs ◽

Water Flooding ◽

Naturally Fractured

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Effects of fractures on NMO velocities and P‐wave azimuthal AVO response

Geophysics ◽

10.1190/1.1484514 ◽

2002 ◽

Vol 67 (3) ◽

pp. 711-726 ◽

Cited By ~ 16

Author(s):

Feng Shen ◽

Xiang Zhu ◽

M. Nafi Toksöz

Keyword(s):

Aspect Ratio ◽

Fractured Reservoirs ◽

Crack Density ◽

P Wave ◽

Fractured Reservoir ◽

Fracture Density ◽

Fracture Detection ◽

Fluid Content ◽

Fracture Parameters ◽

Fractured Medium

This paper attempts to explain the relationships between fractured medium properties and seismic signatures and distortions induced by geology‐related influences on azimuthal AVO responses. In the presence of vertically aligned fractures, the relationships between fracture parameters (fracture density, fracture aspect ratio, and saturated fluid content) and their seismic signatures are linked with rock physics models of fractured media. The P‐wave seismic signatures studied in this paper include anisotropic parameters (δ(v), (v), and γ(v)), NMO velocities, and azimuthal AVO responses, where δ(v) is responsible for near‐vertical P‐wave velocity variations, (v) defines P‐wave anisotropy, and γ(v) governs the degree of shearwave splitting. The results show that in gas‐saturated fractures, anisotropic parameters δ(v) and (v) vary with fracture density alone. However, in water‐saturated fractures δ(v) and (v) depend on fracture density and crack aspect ratio and are also related to Vp/VS and Vp of background rocks, respectively. Differing from δ(v) and (v), γ(v) is the parameter most related to crack density. It is insensitive to the saturated fluid content and crack aspect ratio. The P‐wave NMO velocities in horizontally layered media are a function of δ(v), and their properties are comparable with those of δ(v). Results from 3‐D finite‐difference modeling show that P‐wave azimuthal AVO variations do not necessarily correlate with the magnitude of fracture density. Our studies reveal that, in addition to Poisson's ratio, other elastic properties of background rocks have an effect on P‐wave azimuthal AVO variations. Varying the saturated fluid content of fractures can lead to azimuthal AVO variations and may greatly change azimuthal AVO responses. For a thin fractured reservoir, a tuning effect related to seismic wavelength and reservoir thickness can result in variations in AVO gradients and in azimuthal AVO variations. Results from instantaneous frequency and instantaneous bandwidth indicate that tuning can also lead to azimuthal variations in the rates of changes of the phase and amplitude of seismic waves. For very thin fractured reservoirs, the effect of tuning could become dominant. Our numerical results show that AVO gradients may be significantly distorted in the presence of overburden anisotropy, which suggests that the inversion of fracture parameters based on an individual AVO response would be biased unless this influence were corrected. Though P‐wave azimuthal AVO variations could be useful for fracture detection, the combination of other types of data is more beneficial than using P‐wave amplitude signatures alone, especially for the quantitative characterization of a fractured reservoir.

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