A new wellbore seismic technique uses the vibrations produced by a drill bit while drilling as a downhole seismic energy source. The technique is described as “inverse” VSP because the source and receiver positions of conventional VSP are reversed. No downhole instrumentation is required to obtain the data and the data recording does not interfere with the drilling process. These characteristics offer a method by which borehole seismic data can be acquired, processed, and interpreted while drilling. Interchanging the conventional VSP source and receiver positions improves the efficiency of recording multioffset surveys for imaging a 3-D data volume in the borehole vicinity. The continuous signals generated by the drill bit are recorded by a pilot sensor attached to the top of the drillstring and by receivers located at selected positions around the borehole. The pilot signal is crosscorrelated with the receiver signals to compute traveltimes of the arrivals and to attenuate incoherent noise. Deconvolution and time shifts of the pilot signal compensate for the effects of propagation from the drill bit to the top of the drillstring. By repeating this process for an interval of the well, a VSP‐equivalent data set is generated. Results from a test well demonstrate that the processed drill‐bit data are comparable to conventional VSP data.

Acoustic transversely isotropic (TI) media are defined by artificially setting the shear‐wave velocity in the direction of symmetry axis, VS0, to zero. Contrary to conventional wisdom that equating VS0 = 0 eliminates shear waves, we demonstrate their presence and examine their properties. Specifically, we show that SV‐waves generally have finite nonzero phase and group velocities in acoustic TI media. In fact, these waves have been observed in full waveform modeling, but apparently they were not understood and labeled as numerical artifacts. Acoustic TI media are characterized by extreme, in some sense infinite strength of anisotropy. It makes the following unusual wave phenomena possible: (1) there are propagation directions, where the SV‐ray is orthogonal to the corresponding wavefront normal, (2) the SV‐wave whose ray propagates along the symmetry axis is polarized parallel to the P‐wave propagating in the same direction, (3) P‐wave singularities, that is, directions where P‐ and SV‐wave phase velocities coincide might exist in acoustic TI media. We also briefly discuss some aspects of wave propagation in low‐symmetry acoustic anisotropic models. Extreme anisotropy in those media creates bizarre phase‐ and group‐velocity surfaces that might bring intellectual delight to an anisotropic guru.

A carbon dioxide flood pilot is being conducted in a section of Chevron's McElroy field in Crane County, west Texas. Prior to CO 2 injection, two high-frequency crosswell seismic profiles were recorded to investigate the use of seismic profiling for high-resolution reservoir delineation and CO 2 monitoring. These preinjection profiles provide the baseline for timelapse monitoring. Profile #1 was recorded between an injector well and an offset observation well at a nominal well-to-well distance of 184 ft (56 m). Profile #2 was recorded between a producing well and the observation well at a nominal distance of 600 ft (183 m). The combination of traveltime tomography and stacked CDP reflection amplitudes demonstrates how highfrequency crosswell seismic data can be used to image both large and small scale heterogeneity between wells: Transmission traveltime tomography is used to image the large scale velocity variations; CDP reflection imaging is then used to image smaller scale impedance heterogeneities. The resolution capability of crosswell data is clearly illustrated by an image of the Grayburg-San Andres angular unconformity, seen in both the P-wave and S-wave velocity tomograms and the reflection images. In addition to the imaging study, cores from an observation well were analyzed to support interpretation of the crosswell images and assess the feasibility of monitoring changes in CO 2 saturation. The results of this integrated study demonstrate (1) the use of crosswell seismic profiling to produce a high-resolution reservoir delineation and (2) the possibility for successful monitoring of CO 2 in carbonate reservoirs. The crosswell data were acquired with a piezoelectric source and a multilevel hydrophone array. Both profiles, nearly 80 000 seismic traces, were recorded in approximately 80 hours using a new acquisition technique of shooting on-the-fly. This paper presents the overall project summary and interpretation of the results from the near-offset profile.

Figure 1. P-wave velocity and attenuation tomograms (in color) calculated by Quan and Harris (1997) at BP's Devine test site. -1 /Q total -1 . The various curves in each graph represent data from: KTJ-

Summary We present the results of a seismic analysis of two hydrofractures spanning the entire diatomite column (1110-1910 ft or 338-582 m) in Shell's Phase II steam drive pilot in South Belridge, California. These hydrofractures were induced at two depths (1110-1460 and 1560-1910 ft) and imaged passively using the seismic energy released during fracturing. The arrivals of shear waves from the cracking rock ("microseismic events") were recorded at a 1 ms sampling rate by 56 geophones in three remote observation wells, resulting in 10GB of raw data. These arrival times were then inverted for the event locations, from which the hydrofracture geometry was inferred. A five-dimensional conjugate-gradient algorithm with a depth-dependent, but otherwise constant shear wave velocity model (CVM) was developed for the inversions. To validate CVM, we created a layered shear wave velocity model of the formation and used it to calculate synthetic arrival times from known locations chosen at various depths along the estimated fracture plane. These arrival times were then inverted with CVM and the calculated locations compared with the known ones, quantifying the systematic error associated with the assumption of constant shear wave velocity. We also performed Monte Carlo sensitivity analyses on the synthetic arrival times to account for all other, random errors that exist in field data. After determining the limitations of the inversion algorithm, we hand-picked the shear wave arrival times for both hydrofractures and inverted them with CVM. Finally, to correct for the areal inhomogeneity of the rock, we calculated the distortion of conical waves that were generated by air gun blasts in a remote observation well. This novel technique improved significantly the accuracy of the event locations in the shallow hydrofracture. The azimuth of both hydrofractures was N21 4 E. In each treatment well, there were two separate hydrofractures at two different depths that correspond to the diatomite layers with higher permeabilities. Both shallow hydrofractures were asymmetrical. Initially, the upper, NE wing was 230 ft long, whereas the lower SW wing was only 30 ft long. The deep hydrofracture was symmetrical and the wings of its two parts were initially 130 and 10 ft long, respectively. These conclusions agree well with temperature surveys in the surrounding observation wells during steam injection. Introduction The late and middle Miocene diatomaceous oil fields in the San Joaquin Valley, California, are located in Kern County, some forty miles west of Bakersfield. The largest oil volumes are found in the South, Middle and North Belridge Diatomite and Brown Shale, Lost Hills Diatomite and Brown Shale, Antelope Hills, McDonald Anticline, Chico-Martinez Chert, Cymric Diatomite, McKittrick, Railroad Gap, Belgian Anticline, Asphalto, Elk Hills, Buena Vista Antelope Shale, and Midway Sunset Reef Ridge and Antelope Shale. The major producers of diatomite oil are Shell, Mobil, Chevron, Santa Fe, Crutcher Tufts, Exxon, Texaco, and Unocal. An estimated original-oil-in-place in the Monterey diatomaceous fields exceeds 10 billion barrels and is comparable to that in Prudoe Bay in Alaska.