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Comprehensive Use of VSP Technology at Elk Hills Field, Kern County, California*
By
R.J. Brewer1 and Don Greenfield2
Search and Discovery Article #40091 (2003)
*The viewer is referred to two other articles about VSP, written by the senior author, The Look Ahead VSP Survey: Its Utility and Future, Search and Discovery Article #40060 (2002) and VSP Data in Comparison to the Check Shot Velocity Survey, Search and Discovery Article #40059 (2002).
1Halliburton Energy Services, Houston, TX ([email protected]).
2Occidental of Elk Hills, Inc.
Introduction
To understand accurately subsurface rock
formation and pay zone seismic travel times and velocities within the historic
Elk Hills oil field in Kern County, San Joaquin Valley, California (Figure 1),
Occidental of Elk Hills, Inc. in 1999 embarked on one of the first coordinated
and comprehensive VSP survey data acquisition programs in the country. The
trend-setting effort, uncommon in the United States, has helped produce more
accurate surface seismic time-to-drill depth conversions. This result has been
more accurate drilling prospect maps. VSP data has proven to be an effective
means to lower drilling ambiguities as 
well
as overall drilling costs in the Elk
Hills field. It was concluded that rigorous integration of the all the VSP data
recorded during the campaign into a entire surface and borehole seismic data set
significantly improved the accuracy of a complex subsurface structural mapping
process. Knowledge of the challenging stratigraphy of the area has also been
enhanced. The result has been markedly improved success rates for exploration
and development well drilling.
Occidental purchased the Elk Hills field from the United States government in late 1998. As part of a comprehensive plan to assist development drilling and to prepare for exploration drilling, Oxy acquired an 80 square mile seismic survey and completed preliminary mapping throughout the Elk Hills field. Previous 2D and limited 3D seismic acquisition had proved problematic at best, yielding poor data. Near surface low velocity air sands and extreme topographic variability (Figure 2) hampered surface seismic data quality. Careful pre-3D acquisition testing and extensive quality control yielded a 3D seismic volume that was magnitudes better than any previous acquisition efforts (Figures 3 and 4).
It has long been known that VSP data has the established advantage of being generally higher frequency and better quality than surface seismic. The VSP’s one-way travel path from energy source to receiver helps prevent dissipation of frequency and amplitude. Consequently, following the 3D seismic acquisition, a comprehensive wellbore velocity data acquisition program was initiated. Although there were nearly 5,000 wells within the Elk Hills field, prior to the checkshot/VSP acquisition program, there were only 11 checkshots within the Elk Hills Field and another 6 checkshots surrounding the field (Figure 5). During the 1980's, one or two VSPs had been acquired. However, no digital VSP records were extant; and only checkshot data remained.
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The original acquisition plan called for at least one velocity point for each square mile. As the benefits of velocity data became apparent, the effort was increased. Velocity points exceeded one per square mile in many drilled areas of the field. The first phase of the project included both checkshots and VSPs while subsequent phases recorded virtually all VSPs. Zero offset
VSP surveys utilizing a vibroseis energy source located as close as
possible to the wellhead were acquired in selected, recently-drilled
development wells as While zero offset VSPs were the goal, many times vibrators had to be offset in order to suppress noise attributable to ground roll and "ringing" pipe. Every effort was made to keep offsets less than 500 feet. However, due to excessive noise and topographic problems, one VSP was acquired with a 1,000-foot offset. Although this offset was considered excessive, the survey was acquired to test the viability of the data. The resultant data were excellent. Whenever
possible, 50-foot level intervals were acquired with a dual station
downhole geophone tool assembly from TD to near surface. These 50-foot
intervals were chosen after careful modeling indicated that this spacing
would be sufficient to correlate with 3D surface seismic and avoid
aliasing. Dual tool deployment helped save as much as 40% rig time over
a single tool operation. In-field data processing, to produce a corridor stack from the field records, was employed on virtually every survey to give quick-look verification of data quality at the wellsite and to expedite overall data integration and interpretation. On numerous wells, the in-field corridor stacks and 3D seismic data ties were enhanced by convolving the corridor data with a wavelet extracted from the 3D surface seismic. The digital wavelet data were provided to the logging engineer so that field comparisons could be performed immediately. VSP and seismic data correlation quality varied throughout the field but was generally very good. Further high-end VSP processing techniques have been used to enhance the correlation quality significantly. Figure 7 shows one of the excellent VSP-3D seismic ties in the eastern portion of the field. At the beginning, postulated expenditures for the aggressive acquisition project were a concern. Monetary concerns were mitigated and cost reductions were made possible by competitive bidding along with an Oxy/contractor agreement that guaranteed an average number of VSPs per month in return for significant cost breaks. This agreement has thus far saved Oxy approximately 40% to 50% over individually contracted VSPs.
A
significant part of the exploration and development methodology employed
by Oxy involves being able to produce accurate time-depth functions at
any X-Y location encompassed by the surface seismic 3D and a time-depth
function and/or synthetic seismogram for every
Utilizing a
cost effective and aggressive velocity acquisition program along with
innovative analysis has enabled interpreters to incorporate all
geophysical and geological data into a comprehensive picture and to
predict accurately drill depths to targeted horizons. A good example of
this predictive capability is the 351-17G Some
practitioners have reportedly recommended that ideally one VSP survey be
acquired for each 1-2 square miles of 3D surface seismic coverage. The
Occidental of Elk Hills project has demonstrated that the recommendation
is a good one. The elimination of drilling ambiguities is important to
the optimization of a multi- |
Figure 1:
Location map of Elk Hills Field, Kern County, San Joaquin Valley,
California.
Figure 2:
Digital terrain model showing extreme topographic variations. Yellow and
red denotes higher elevations and blue lower elevations.
Figure 3:
Elk Hills Oil Field highlighting the locations of major structural
features, 
Figure 4:
Comparison of high effort, high quality 2D seismic data versus the high
effort 3D seismic data.
Figure 5:
Velocity data prior to VSP/Checkshot acquisition program: 11 checkshots
in the field and 5 checkshots around the field. Several VSPs had
previously been acquired; but there were no digital data, and paper
records were poor.
Figure
6: Velocity data after acquisition program: seven new check
shot velocity surveys and 36 new VSPs. 
Figure 7:
VSP/3D seismic data correlation. VSP data was convolved with an
extracted wavelet from the 3D seismic and incorporated into the 3D
dataset to facilitate 
Figure 8:
Elk Hills south flank location, 351-17G.
Figure 9:
Seismic backdrop cross section through the 351-17G 
Figure 10:
Comparison of pre-drill velocity function (KNRVP generated from
substantial checkshot/VSP data) with actual velocity function from VSP
data shot in 351-17G 
