uGeneral statement

uFigure captions

uSonic logs & check shots

uHistory of VSP

uVSP perspective

uDownhole VSP tools

uReduced risk / saved money

uThe future

uGeneral statement

uFigure captions

uSonic logs & check shots

uHistory of VSP

uVSP perspective

uDownhole VSP tools

uReduced risk / saved money

uThe future

uGeneral statement

uFigure captions

uSonic logs & check shots

uHistory of VSP

uVSP perspective

uDownhole VSP tools

uReduced risk / saved money

uThe future

uGeneral statement

uFigure captions

uSonic logs & check shots

uHistory of VSP

uVSP perspective

uDownhole VSP tools

uReduced risk / saved money

uThe future

uGeneral statement

uFigure captions

uSonic logs & check shots

uHistory of VSP

uVSP perspective

uDownhole VSP tools

uReduced risk / saved money

uThe future

uGeneral statement

uFigure captions

uSonic logs & check shots

uHistory of VSP

uVSP perspective

uDownhole VSP tools

uReduced risk / saved money

uThe future

uGeneral statement

uFigure captions

uSonic logs & check shots

uHistory of VSP

uVSP perspective

uDownhole VSP tools

uReduced risk / saved money

uThe future

General Statement

The idea of lowering a geophone down a well bore to get a better handle on rock velocity is hardly a new concept. Geophysicists have engaged in the practice with increasing precision since the1930s -- around the time when the first geophones were designed to withstand the rigors of the borehole.

The presence of a drilled well presents a truly unique opportunity to:

·        Investigate a target formation more closely with acoustic measurements.

·        Minimize subsurface attenuation phenomena.

·        Measure depth accurately.

·        Overcome the formidable limitation of all surface geophysical measurements -- the lack of accurate depth control.

Figure Captions

Figure 1. Typical equipment setup and seismic ray paths in a borehole seismic survey. In a checkshot velocity survey, only the first directly arriving signals sensed by the downhole geophone are used. In vertical seismic profiling, both directly arriving and reflected signals are used.

Figure 2. Zero or near offset VSP (left panel) and a corridor stack of VSP traces (right panel). The VSP has been corrected to two-way time so that reflections from horizontal reflectors appear at the same time on traces recorded at different levels. The corridor stack (right) is a partial summation or stacking of the VSP traces (left). Stacking, a summing of data to produce a single output trace, enhances the signal to noise ratio of seismic data.

Figure 3. Extracted line from 3-D surface seismic -- well trajectory marked. Note poor data quality resolution of possible unconformity above truncated dipping beds.

Figure 4. Processed VSP/CDP transform image recorded from vertical incident VSP survey.

Figure 5. VSP/CDP transform image spliced into seismic data. Figures 3 and 4 combined to yield superior interpretation tool.

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Sonic Logs and Check Shots

Geophysicists are familiar with the velocity survey's one-way acoustic travel time as a critical component that is necessary to help convert surface seismic's two-way travel time to depth. In the absence of the check shot velocity survey, accurate velocity information can sometimes be extracted from the tried and true sonic log. Relying solely on sonic logs, however, may entail considerable risk involving interval velocity errors.

What may not be clearly acknowledged are how limited check shot data are -- and how very limited sonic logs travel times are inconsistently aiding the time to depth conversion process. The sonic log excels as a formation boundary and indirect porosity measurement log, but it can only see one-two feet into the formation under good downhole conditions -- and can be subject to cycle skipping and washed-out zones.

When the sonic log is used to produce a synthetic seismogram for surface seismic correlation purposes, one hopes that a check shot velocity survey is available from the same well to calibrate the sonic log. Calibration and correction of the sonic log often may be needed because the production of a synthetic seismogram from a sonic log is a hybridization and transform process that can introduce seismic travel time error if cycle skipping, tool sticking, and washed-out zone effects are present in the sonic log. The sonic log is also of very limited use in identifying interval velocity inversions -- or any abrupt rock density and velocity change that are an appreciable distance from the well.

The check shot velocity survey can be used to produce a corrected sonic log, allowing sonic log pitfalls to be alleviated by enabling a data processing analyst to correlate effectively and more accurately through questionable zones that were traversed by the sonic logging tool downhole.

A check-shot-corrected sonic log also makes it easier to determine interval velocities between key formations, since familiar formation boundaries can be readily recognized from the sonic log. If density log information is also available, a more accurate synthetic seismogram log integration usually results.

A check shot velocity survey measures a much larger cylindrical volume of rock compared to the relative soda straw volume measured by the sonic log. The check shot survey and the more precise vertical seismic profile (VSP) should at least be considered in the logging program of every exploration and key development well being planned to minimize or eliminate the ever-present and costly danger of surface seismic time to depth conversion error.

Borehole seismic data are the most effective correlation bridge available between the well bore and the surface seismic data. Borehole seismic data that include the check shot velocity survey and the VSP can measure large volumes of rock -- and will indicate the presence of velocity anomalies, which may be totally missed by the sonic log. These velocity anomalies must be measured and dealt with accurately when mapping the velocity fields that are so critical to an effective surface-seismic time to drill-depth conversion process.

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Some History on VSP

The vertical seismic profile (VSP) is a truly remarkable, versatile, and, unfortunately, under-utilized innovation--under-utilized perhaps because of its greater cost than the more routine check shot velocity survey and the possible over-reliance within the industry on 3-D surface seismic data.

The effective utility of the VSP was developed by the Soviets in the 1960s, made its way into Europe, and finally arrived in earnest in the United States in the 1970s. The VSP was quite an industry sensation when it started to be used in this country because of its "a look ahead" of the drill bit capability and its use as an aid in predicting the depth at which a target formation would be encountered after drilling continued.

The Look Ahead or Prediction Ahead of the Bit (PAB) VSP, which is actually an inversion routine performed during the data processing of ideally zero-offset VSP survey data, has proven itself as a useful exploration tool over the years. It has been used to predict the depth of overpressured zones ahead of drilling offshore wells and to locate granite-sediment and salt-sediment interfaces.

A zero- or near-offset VSP survey has the energy source positioned as close as possible to the well head to focus the energy down and ahead of the well bore -- and is the preferred geometry for well correlation as opposed to the offset VSP survey configuration, which positions the energy source away from the well head to image a distance laterally away from the well.

Look ahead offset VSP surveys also have been used recently successfully to locate subsurface features such as pinnacle reefs in East Texas. The look-ahead VSP survey may seem like quite a leap of faith to the uninitiated -- until one realizes that all surface seismic data (2-D and 3-D) are all look-ahead, as all measurements are made at the surface!

VSP Perspective

The VSP is simply a precision level step change up from the check shot velocity survey.

The basic difference between the check shot survey and the VSP is that the VSP measures nearly all seismic waveforms in the well bore (up-going and down-going energy), whereas the check shot velocity survey measures basically only the down-going energy (Figure 1). Note that a VSP is also a check shot velocity survey -- but a check shot velocity survey is not a VSP!

Check shot velocity survey measurements are typically taken every 250-500 feet downhole and were designed to measure the down-going waveforms used in velocity determination. VSP measurements are much more closely spaced (50-100 feet).

The VSP, like the check shot survey, also measures down-going energy. The smaller measurement interval (level interval) required by the VSP is necessary also to record the reflected energy in the well bore. The basic computed product of the VSP is known as a corridor stack, which in appearance resembles the synthetic seismogram. In reality it is a vastly superior well correlation tool, because it contains actual seismic reflection data as well as the down-going wave field.

The down-going wave field is all that a check shot velocity survey records. The corridor stack made from the VSP is the well bore converted to a full reflection waveform seismic trace basically free of multiples (Figure 2). Another significant limitation of relying only on check shot velocity surveys is that the surface seismic data that they are being correlated with contain almost entirely reflected waveforms. Surface seismic does not measure down-going energy because all the detectors are at the surface.

VSP surveys are routinely performed in many parts of the world -- especially in Europe, because of the recognized superiority and versatility of the VSP over the simpler and less expensive check shot survey. More and more VSP surveys are being conducted -- especially offset surveys and a more detailed variation of the offset survey called the walk-away VSP survey -- as the advantages become clearer and survey reliability increases.

Pre-survey ray trace modeling has gained wide acceptance and is used to design more accurately offset VSP surveys and offset energy source placement. The computed product of the offset VSP is known as a VSP/CDP transform -- basically a high-resolution, mini-seismic section resembling a surface seismic CDP (Common Depth Point) stack display.

The VSP/CDP transform has been converted or "transformed" from its original recorded one-way time to two-way time and displayed at a convenient scale to match the surface seismic data it is to be correlated with (Figure 3). The VSP/CDP transform data set can be migrated, filtered, and processed just like any surface seismic data set.

Because VSP data has a broader bandwidth and contains high frequency events, subtle features like small faults, stratigraphic changes, and amplitude anomalies can be observed in the vicinity of the well bore, whereas they are not discernible on the surface seismic coverage in the same area (Figure 4). Note the marked improvement in resolution that the VSP/CDP transform yields in this example (Figure 5): It is a VSP/CDP transform display made from a vertical incident VSP survey, recorded to provide better resolution over a 2-D reconstruction line from a 3-D seismic volume prior to deepening this directional well bore.

A vertical incident VSP survey requires the energy source to be positioned at the surface directly over the downhole geophone tool. Vertical incident geometry is generally preferred over the rig source option and has proven to be a more accurate way to obtain velocity control and image a highly deviated borehole. Displaying the VSP/CDP Transform and the seismic section together yields a far more useful product for interpretation.

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Downhole VSP Tools

Downhole tool design has improved significantly over the last 20 years. Three-component geophone configurations are routine -- the tools have evolved from single component analog designs to digital multi-tool designs or actual downhole geophone arrays composed of up to 24 or more individual tools or satellites.

Multi-station tools greatly reduce the historic bane of bore hole seismic surveys -- rig time consumption -- and record higher quality data. Slim (1-inch and 11/16-inch O.D.) downhole geophone tools have proven their versatility and have made it possible to record high quality VSP data in producing wells.

Logging While Drilling (LWD) sonic, check shot and VSP tools are available to meet the real-time demands of directional drilling. LWD tools designed to record borehole seismic data are becoming increasingly more sophisticated as LWD logging replaces conventional wireline logging on many directional wells.

Reduced Risk and Saved Money

The two most important benefits of running a VSP survey are reduced risk and saved drilling dollars. The VSP survey reduces risk by measuring the seismic velocities accurately in the well bore; this allows accurate time-to-depth conversion of the surface seismic data. VSP data also has been used to help reprocess older seismic data to yield more clearly interpretable results.

The accurate velocity information from the VSP helps make the velocity analysis involved in processing and stacking surface seismic data more precise. VSP data also can be used to remove multiples from surface seismic data by providing parameters for an earth filter inversion process known as signature deconvolution. Accurate time-to-depth conversion is a must in producing reliable drilling prospect maps, and it helps avoid missed drilling targets.

Money is saved early on with VSP surveys conducted in the first wells drilled in a play by increasing the accuracy of the interpretation and mapping process -- and later, as more wells are drilled and the velocity field is better understood.

Most of the VSP surveys performed are of the zero- or near-offset type, which is primarily used for velocity determination and surface seismic correlation. Offset VSP surveys are gaining wider acceptance, as they have proved successful in locating stepout locations to discovery and producing wells.

The Future

The sonic log and the check shot velocity survey have been the standard seismic correlation tools for many years and have proven their utility -- but today's exploration and production challenges require more precision. The VSP survey meets that challenge, and is currently considered to be the ultimate and most effective tool available for matching the well bore to the sizable investment of surface seismic data that each exploration company makes. More VSP surveys will be needed in the future -- and may become a standard logging service -- as we strive to meet the accuracy demands of our industry.

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