Daniel R. Burns

Spatial orientation and distribution of reservoir fractures from scattered seismic energy

Wepresentthedetailsofanewmethodfordeterminingthereflection and scattering characteristics of seismic energy from subsurface fractured formations. The method is based upon observations we have made from 3D finite-difference modeling of the reflected and scattered seismic energy over discrete systems of vertical fractures. Regularly spaced, discrete vertical fracture corridors impart a coda signature, which is a ringing tail of scatteredenergy,toanyseismicwaveswhicharetransmittedthrough or reflected off of them. This signature varies in amplitude and coherence as a function of several parameters including: 1 the difference in angle between the orientation of the fractures and the acquisition direction, 2 the fracture spacing, 3 the wavelength of the illuminating seismic energy, and 4 the compliance, or stiffness, of the fractures. This coda energy is most coherent when the acquisition direction is parallel to the strike of thefractures.Ithasthelargestamplitudewhentheseismicwavelengths are tuned to the fracture spacing, and when the fractures have low stiffness. Our method uses surface seismic reflection tracestoderiveatransferfunctionthatquantifiesthechangeinan apparent source wavelet before and after propagating through a fracturedinterval.Thetransferfunctionforanintervalwithnoor low amounts of scattering will be more spikelike and temporally compact. The transfer function for an interval with high scattering will ring and be less temporally compact. When a 3D survey is acquired with a full range of azimuths, the variation in the derived transfer functions allows us to identify subsurface areas with high fracturing and to determine the strike of those fractures.Wecalibratedthemethodwithmodeldataandthenapplied ittotheEmiliofieldwithafracturedreservoir.Themethodyielded results which agree with known field measurements and previously published fracture orientations derived from PS anisotropy.

Effects of in-situ permeability on the propagation of stoneley (tube) waves in a borehole

We investigated the theoretical relationship between propagation characteristics of Stoneley (tube) waves in a borehole and in situ permeability by using a modified formulation of a borehole model with a formation that behaves as a Biot porous medium. We found that Stoneley‐wave attenuation and phase‐velocity dispersion increased with increasing permeability and porosity, and decreased with increasing frequency. In rocks with low to medium permeabilities (less than 100 mD), variations in formation velocity and attentuation were major contributors to variations in Stoneley‐wave properties at normal logging frequencies. However, in high‐permeability rocks (greater than 100 mD), coupling between the borehole and pore fluids associated with in situ permeability was more important than lithological changes in controlling Stoneley‐wave properties. Pore‐fluid viscosity had an effect on Stoneley‐wave propagation equal but opposite to permeability, and hence must he taken into account. We compared our theoretical ...

Electroseismic and seismoelectric measurements of rock samples in a water tank

An electromagnetic (EM) or seismic wave can induce seismic or EM waves because of the electrokinetic conversion based on the electric double layer in a fluid-saturated porous medium. We tested a new method for observing electroseismic and seismoelectric conversions in rock samples. Our method is designed to overcome the shortcoming of previous attempts to separate signals generated by a continuous electric or seismic source in a small container. We first observed acoustic fields around electrodes excited by an electric pulse in a water tank or in a water-saturated porous sample. In our approach, we immersed rock samples in a water tank and measure the seismic or electric responses using electric or acoustic pulses conveyed through the immersed electrodes or hydrophone. We measured electroseismic- and seismoelectric-frequency responses in Berea Sandstone and Westerly Granite samples at a frequency range of 15–150 kHz . The measurements clearly separate the effects of the electric source, background noises,...

Azimuthal offset‐dependent attributes applied to fracture detection in a carbonate reservoir

Offset‐dependent attributes—amplitude versus offset (AVO) and frequency versus offset—are extracted from 2‐D P‐wave seismic data using the multiple signal classification technique. These attributes are used to detect fracture orientation in a carbonate reservoir located in the Maporal field in the Barinas basin of southwestern Venezuela. In the fracture normal direction, P‐wave reflectivity is characterized by a large increase of amplitude with offset (large positive AVO gradient) and a large decrease of frequency with offset (large negative frequency versus offset gradient). In the fracture strike direction, P‐wave reflectivity shows a scattered variation in AVO but a small variation in frequency with offset. Our results also show that the reservoir heterogeneity can lead to large variations of AVO signatures and that using azimuthal offset‐dependent frequency attributes can help lessen the ambiguity when detecting fracture orientation.

Fracture Properties From Seismic Scattering

The seismic trace is a complex aggregate of reflected and scattered signals from subsurface formation interfaces and heterogeneities. Although many varieties of random noise may also be present in the trace, we know from reacquiring the same seismic survey that seismic data are highly repeatable, indicating that significant information about the subsurface is contained in the trace but not yet used by our standard analysis methods. Seismic scattering is a type of signal contained in the data that is generally not utilized.

A dispersive-wave processing technique for estimating formation shear velocity from dipole and Stoneley waveforms

A model‐guided dispersive‐wave processing technique has been developed to estimate formation shear‐wave velocity from borehole acoustic logging waveforms. These waveform data can be the Stoneley waves in monopole logging or the flexural waves in dipole logging. In this technique, the waveform recorded on a given receiver is compared to the waveform from a second receiver that is numerically propagated to the given receiver’s position using a trial formation shear‐wave velocity. The numerical propagation step uses the proper dispersion relation for the wave mode (dipole or Stoneley). The phase difference between the two waveforms is minimized by varying the shear velocity. The velocity value that minimizes the phase difference is chosen as the final shear velocity at which the waveforms attain the optimum phase match. In this procedure the dispersion effect is automatically accounted for by using the model theory and is demonstrated by a comparison with the results of the semblance method. Using this techn...

Stability of finite difference numerical simulations of acoustic logging-while-drilling with different perfectly matched layer schemes

In acoustic logging-while-drilling (ALWD) finite difference in time domain (FDTD) simulations, large drill collar occupies, most of the fluid-filled borehole and divides the borehole fluid into two thin fluid columns (radius ∼27 mm). Fine grids and large computational models are required to model the thin fluid region between the tool and the formation. As a result, small time step and more iterations are needed, which increases the cumulative numerical error. Furthermore, due to high impedance contrast between the drill collar and fluid in the borehole (the difference is >30 times), the stability and efficiency of the perfectly matched layer (PML) scheme is critical to simulate complicated wave modes accurately. In this paper, we compared four different PML implementations in a staggered grid finite difference in time domain (FDTD) in the ALWD simulation, including field-splitting PML (SPML), multiaxial PML(MPML), non-splitting PML (NPML), and complex frequency-shifted PML (CFS-PML). The comparison indicated that NPML and CFS-PML can absorb the guided wave reflection from the computational boundaries more efficiently than SPML and M-PML. For large simulation time, SPML, M-PML, and NPML are numerically unstable. However, the stability of M-PML can be improved further to some extent. Based on the analysis, we proposed that the CFS-PML method is used in FDTD to eliminate the numerical instability and to improve the efficiency of absorption in the PML layers for LWD modeling. The optimal values of CFS-PML parameters in the LWD simulation were investigated based on thousands of 3D simulations. For typical LWD cases, the best maximum value of the quadratic damping profile was obtained using one d0. The optimal parameter space for the maximum value of the linear frequency-shifted factor (α0) and the scaling factor (β0) depended on the thickness of the PML layer. For typical formations, if the PML thickness is 10 grid points, the global error can be reduced to <1% using the optimal PML parameters, and the error will decrease as the PML thickness increases.

Variable Grid Finite-Difference Modeling Including Surface Topography

We have developed two-dimensional viscoelastic finite-difference modeling for highly complex topography. Realistic modeling of seismic wave propagation in near surface is complicated by many factors, such as strong heterogeneity, topographic relief and large attenuation. In order to account for these complications, we focus on implementations in velocity-stress staggered grids and employ 0(2,4) accurate viscoelastic finite-difference scheme including an irregular free surface condition to topography relief and a variable grid technique in the shallow parts of the model. To examine the validity of the method, we carried out several numerical tests. The result of the tests shows that approximately ten grid-points per shortest wavelength is enough for accurate calculation. The method is accurate as well as stable and enable us to handle complex structure in finite-difference modeling.

Sequential approach to joint flow‐seismic inversion for improved characterization of fractured media

Seismic interpretation of subsurface structures is traditionally performed without any account of flow behavior. Here we present a methodology for characterizing fractured geologic reservoirs by integrating flow and seismic data. The key element of the proposed approach is the identification—within the inversion—of the intimate relation between fracture compliance and fracture transmissivity, which determine the acoustic and flow responses of a fractured reservoir, respectively. Owing to the strong (but highly uncertain) dependence of fracture transmissivity on fracture compliance, the modeled flow response in a fractured reservoir is highly sensitive to the geophysical interpretation. By means of synthetic models, we show that by incorporating flow data (well pressures and tracer breakthrough curves) into the inversion workflow, we can simultaneously reduce the error in the seismic interpretation and improve predictions of the reservoir flow dynamics. While the inversion results are robust with respect to noise in the data for this synthetic example, the applicability of the methodology remains to be tested for more complex synthetic models and field cases.

Fracture quality from integrating time-lapse VSP and microseismic data

Tight gas reservoirs are problematic to produce, often requiring multiple stages of hydraulic fracturing in order to create connected pathways through which hydrocarbons may flow. In this paper, we propose a new methodology to characterize the quality of hydraulic fractures. Using synthetic VSP and microseismic data, we test the concept that the rock volume containing open, gas-filled fractures will scatter seismic energy more profusely than a volume containing closed, nonproductive fractures. By measuring the amount of scattered energy in a time-lapse 3D VSP study taken before and after the hydraulic fracturing episode, we hope to compare the productive flow quality of different regions of the hydraulically fractured rock. The microseismic recordings allow us to locate areas which have been hydraulically fractured and create imaging operators to extract the scattered signals from the time-lapse VSP data.