John H. Queen

Using borehole electroseismic measurements to detect and characterize fractured (permeable) zones

In 1996, we measured Stoneley‐wave‐induced electrical fields in an uncased water well drilled in fractured granite and diorite near Hamilton, Massachusetts. Stoneley waves generated by sledgehammer blows to the surface casing produced a flow of pore fluid in permeable zones intersected by the borehole. In turn, this flow induced a streaming electrical field. Even though these electrical signals were very small (tens of microvolts), we were able to detect them using electrodes placed in the borehole, after power line and telluric signals were canceled by remote referencing and notch‐filtering. Amplitude analysis of the electrical fields confirmed that they were induced by fluid flow in the fractured formation. The normalized amplitudes of these electrical fields correlate with the fracture density log and agree with the theoretical model for this electroseismic phenomenon. Our Biot‐theory‐based model predicts that borehole electroseismic measurements can be used to characterize permeable zones. According t...

Fracture detection using crosswell and single well surveys

We recorded high‐resolution (1 to 10 kHz), crosswell and single well seismic data in a shallow (15 to 35 m), water‐saturated, fractured limestone sequence at Conocos borehole test facility near Newkirk, Oklahoma. Our objective was to develop seismic methodologies for imaging gas‐filled fractures in naturally fractured gas reservoirs. The crosswell (1/4 m receiver spacing, 50 to 100 m well separation) surveys used a piezoelectric source and hydrophones before, during, and after an air injection that we designed to displace water from a fracture zone. Our intent was to increase the visibility of the fracture zone to seismic imaging and to confirm previous hydrologic data that indicated a preferred pathway. For the single well seismic imaging (a piezoelectric source and an eight‐element hydrophone array at 1/4 m spacing), we also recorded data before and after the air injection. The crosswell results indicate that the air did follow a preferred pathway that was predicted by hydrologic modeling. In addition,...

Velocity and attenuation anisotropy: Implication of seismic fracture characterizations

Recent observations from several walkaround, walkaway, and 3D VSPs from various parts of the world have shown that anisotropy symmetry directions (or fracture orientations) estimated from traveltime or velocity anisotropy do not necessarily agree with symmetry directions from amplitude or attenuation analysis. We have also consistently found that attenuation anisotropy in reservoir intervals is generally stronger than in overburdens. We argue in this article that, instead of reconciling the differences between various attributes, we should try to understand the mechanisms and use the difference in velocity and attenuation anisotropy which may contain additional information about subsurface fracture systems.

Color display of the localized spectrum

This paper develops a new display technique for seismic cross‐sections, called spectral color. The need to visualize frequency information in seismic data is recognized uniformly and often is accomplished through the color display of instantaneous frequency. The spectral content of a reflected event can carry information about the reflecting horizon’s characteristics which will not be resolved in the instantaneous state of the record. Spectral color is devised to overcome the problem of displaying an entire localized spectrum at each time sample and offset of a seismic section. The localized spectrum is calculated with a relatively new time‐frequency representation called the S-transform, which combines a Fourier technique with adaptive windowing in the frequency domain. A color (RGB triplet) based on the localized spectral content is calculated and the pixel is displayed at the appropriate position in the seismic section. As a result, the seismic cross‐section is displayed in an intuitive manner that is ...

Numerical modeling of scattering from discrete fracture zones in a San Juan Basin gas reservoir

Summary Numerical modeling of the seismic response to discrete fracture zones has been conducted to aid gas exploration in the San Juan Basin. A 2D, anisotropic, finite-difference code was used with vertical fracture zones represented by a single column of anisotropic grid points. Scattering, including strong P-to-S mode conversions was observed using surface seismic acquisition geometry. Fractures (or joints) were represented by their stiffness. Since field scale stiffness measurements are lacking, we used a fracture stiffness value derived from lab studies and a conceptual model. Two scales of fracturing were investigated using a basic 5-layer model. Observable scattering was demonstrated in a more realistic 45-layer model. The moveout of the fracture generated events on common midpoint (CMP) gathers is such that standard processing would treat this energy as “noise”. Observation of coherent scattered events implies that direct imaging of gas-filled fracture zones is possible.

Channel waves in cross-borehole data

Layered geological formations with large seismic velocity contrasts can effectively create channel waves in cross‐borehole seismic data. The existence of channel waves for such waveguides can be confirmed by ray tracing, wave equation modeling, and modal analysis. Channel wave arrivals are identified in cross‐borehole data recorded at Conoco’s Newkirk test facility. For these data, where velocity contrasts are about 2 to 1, tomography based on first arrival traveltimes, is limited due to problems with extreme ray bending and seismic shadow zones. However, it may be possible to extract geological information using channel wave information. The seismometer differencing method appears to be a promising approach for detecting waveguide boundaries by use of cross‐borehole data.

Cost-effective imaging of CO2 injection with borehole seismic methods

Currently there is a critical need to increase oil and gas recovery from existing and new reservoirs. In addition, the ever-increasing need to sequester CO2 in the subsurface places further emphasis on accurate imaging methods to validate CO2 injection strategies. Two obstacles to increased efficiency are (1) a thorough understanding of the geologic complexity and fluid distribution and (2) the scaling relationships between fine scale/point measurements and larger scale/volumetric measurements. Although initially expensive, borehole methods may offer a cost-effective solution when integrated into a drilling and development program. New technology such as fiber-optic sensors emplaced during drilling and completion, microhole drilling, and other advances in sensors will make borehole technology much more cost effective when used over the long run. If deployed in a multicomponent and time-lapse fashion, seismic methods also offer the ability to define contrasts in properties, detecting subtle changes in prop...

Frequency-dependent seismic anisotropy and its implication for estimating fracture size in low porosity reservoirs

The use of seismic anisotropy for characterizing subsurface fracture orientations and intensity has become increasingly popular. However, the reluctance of reservoir engineers to accept seismic anisotropy as a routine technique for fracture characterization is partly because of its inability to provide information about sizes and volume of fractures. Although both grain-scale micro-cracks and formation-scale macro-fractures are considered causes of seismic anisotropy, reservoir engineers are more interested in the latter as permeability in many hydrocarbon reservoirs is believed to be dominated by formation-scale fluid units (on the order of meters). We intend to fill this gap by developing new practical applications of seismic anisotropy including new theoretical models and new analysis methods.

Utilizing crosswell, single well and pressure transient tests for characterizing fractured gas reservoirs

As part of its Department of Energy (DOE)/Industry cooperative program in oil and gas, Berkeley Lab has an ongoing effort in cooperation with Conoco and Amoco to develop equipment, field techniques, and interpretational methods to further the practice of characterizing naturally fractured, heterogeneous reservoirs. The focus of the project is an interdisciplinary approach, involving geology, rock physics, geophysics, and reservoir engineering. The goal is to combine the various methods into a unified approach for predicting fluid migration.

Simulation of multiple scattering of seismic waves by spatially distributed inclusions

A 2D elastodynamic boundary element method (BEM) is used to solve multiple scattering of elastic waves. The method is based on the integral representation of an elastic wave-field by assuming a fictitious source distribution on the scattering objects or inclusions, i.e. a mathematical description of Huygens’ principle, and the fictitious source distribution can be found by matching appropriate boundary conditions at the boundary of the inclusions. Numerical studies show that in the presence of cracks, spatial and scale-length distributions are important and different spatial arrangements of the same scatters lead to profound differences in scattering characteristics, in particular the frequency contents of the transmitted wave-fields. The frequency characteristics, such as the frequency of peak attenuation, can be related to spatial size parameters of the model.