Borehole seismic – now and the future

There are as many ways to measure the physical world as there are things to measure. Sometimes this blurs the big picture.

One example is the incongruity between how surface seismic and well log information are measured: the former in time, the latter in depth. Each is a priceless tool, but used as independent buckets of information, they leave the water a little murky with assumption, thereby leaving room for less-than-optimal decision making and disappointing financial performance.

Fortunately, vertical seismic profiling (VSP) is bringing together new business processes and technology to make reservoir description crystal clear. VSPs have been used for several decades, but recent advances in data acquisition capabilities and processing techniques have made them indispensable for optimum reservoir management.

Borehole seismic, orVSP, indexes seismic and wireline information. It brings together time and depth, and geology and geophysics for a more dependable picture of the target. And that makes it the only available technology for linking these two decision-making disciplines. The end result delivers:
• More effective and efficient data processing and interpretation;
• Better returns on information investments from well logs, surface seismic and reservoir geophysics data;
• More scalable well interpretation solutions;
• Less financial risk for all parties involved in a project; and
• Greater potential for enhanced field development.

Typically, a velocity function is used to deliver depth images from surface seismic, resulting in assumption and interpretation. A borehole seismic survey records seismic time data, measured at known depths. It replaces the surface-based statistics with a true reference point against which to judge the veracity of the surface seismic data, confirming time and depth, identifying multiples, and correcting the position of the image.

A VSP gives better resolution also, since the data is recorded near the reservoir using the latest digital acquisition technology. Users see smaller features (both in the vertical scale and laterally away from the well), can confirm borderline seismic interpretations, and can obtain a whole new world of detail through a smaller, more focused snapshot. And it’s a snapshot that removes the subjectivity normally found in surface seismic, replacing it instead with real contextual measurement. Users aren’t on the surface guessing; they are below ground recording objectively, using sensors close to the reservoir to help calibrate the surface seismic processing flow.

Data acquisition difference

When VSP and surface seismic data are acquired at the same time, it is possible to derive additional VSP-acquired parameters, which can be used to assist the surface seismic processing flow and imaging. Borehole seismic is also normally recorded by three- or four-component receivers, enabling both compressional and shear data to be acquired, rather than compressional waves only, as with most conventional surface seismic surveys.

That means getting a better feel for reservoir properties. Each VSP survey is designed with geometries specifically tailored for the problem at hand. For example, deriving amplitude-variation-with-offset (AVO) from VSP demands that receivers be placed directly above the target reflector while the source is moved along a line. All of the receivers are coupled directly to the formation, improving data fidelity. Multilevel borehole receiver arrays can be installed temporarily or permanently, with data being recorded at all levels from each surface shot, dramatically improving the time taken to perform a survey

The work flow differs significantly from conventional seismic as it contains not only shear wave information, but the downward traveling wavefield (surface seismic can only record upward traveling energy). Direct measurement of the down-going wave fields for the determination of accurate phase, multiple identification, and measurement of energy absorption (Q attenuation). The downhole tool delivers a measurement in depth. And it’s all done with less data attenuation and higher resolution.

But on the characterization front, the VSP provides control points with which the interpreter can increase confidence in surface seismic. The surface seismic time is transformed into an accurate depth at the well. Then it all comes together: 3-D visualization, 2-D or 3-D VSP data combined with other well parameters, and 3-D surface seismic. And the surface seismic processing parameters can be adjusted using deterministic borehole seismic measurements.

Breaking new ground

Merging these two resources is hardly a new concept. What is new is the global success some focused teams have had in actually executing these projects with unprecedented effectiveness – and outside of the traditional time/depth benefits that have heretofore comprised the process’s claim to fame.

Robust, multilevel arrays with bigger capacity are establishing the parameters for conventional seismic data. Companies are increasingly seeking more than basic zero-offset projects, realizing the value of more robust operations such as 3-D VSP and its long-term implications for return on investment.

The industry now is seeing impressive growth, not only in using borehole seismic data to validate and improve surface seismic, but also as a tool for real-time geo-steering and hazard avoidance during drilling. It is not only helping eliminate risk at the well level; it is also moving into the more ambitious realm of field development. Borehole seismic is no longer an exploration tool only.

There are a number of ways this technology can facilitate better returns from surface seismic investments, by calibrating or complementing the surface seismic image. These include VSP AVO, VSP anisotropy, 3-D VSP, VSP inverse Q, and time-lapse calibration, as well as shear wave and OBC calibration.

Surface seismic AVO calibration and anisotropy detection make for a more true model, nailing down reservoir size and location, as well as filling in the missing pieces of lithology, porosity, pore fluids, and aligned fracture orientations. 3-D VSP slashes operating costs from the far less scalable conventional surface seismic approach. It can also calibrate 4-D seismic and produce 3-D migration in time and depth, and can be a big contributor to smarter field development.

VSPs also do a much more economical and effective job of determining the location of a salt flank than does surface seismic. Using offset imaging, where the source is located away from the rig during the acquisition phase, 3-D salt proximity or 3-D imaging, VSP can provide a much more accurate picture of salt bodies, greatly improving estimates of reserves and resulting in better well placement.

The end result of all these applications is better reservoir characterization. To really see what is down there, more and more companies are adding a borehole seismic aspect to their seismic acquisition processes, because time and again, the benefits of better description outweigh the cost.

Real-time applications
The second main application of borehole seismic is for real-time geo-steering and hazard avoidance during drilling. This includes:
• Time/depth for drill bit placement on seismic time section during drilling;
• Velocity model for seismic section re-migration during drilling; and
• Velocity estimate for indications of overpressured zones ahead of the drill bit.

These real-time applications are big money savers, and are moving borehole seismic interest and information from the desk of the geophysicist to the desks of reservoir engineers, geologists and drillers – those concerned with the field’s bigger picture.

This is not conventional VSP territory, but the world’s biggest operators are throwing their weight behind this application. Once preconceptions of VSP’s role in the upstream value chain are shed, the compelling economics of being able to look ahead of the drill bit with greater clarity speaks for itself.

Together, these two VSP value areas deliver significant economic impact to both individual projects and overall field economics. Because of its rifle-shot scope of vision and improved clarity, 3-D VSP can be cheaper than a broadly-scaled conventional surface seismic shot, which can easily cost several million dollars.

The improved accuracy of this well-calibrated seismic enables wells to be placed more accurately, minimizing the excessive financial risk that comes with drilling in the wrong spot. And the clearer, higher-resolution image of the reservoir, of course, helps the interpreter map the reservoir more accurately, not to mention book more accurate stock tank oil in place.

Even small improvements in determining features can deliver huge financial returns. One simple VSP conducted in the Middle East allowed a client to confirm and accurately interpret a subtle tuning feature in his poor quality seismic data. This sparked a reinterpretation of the field’s extent, and ultimately saved millions in wasted drilling costs; the field wasn’t as big as was originally thought.

Pitfalls and misconceptions
With VSP coming into its full potential, there still exists a learning curve for proper implementation. Companies make two common types of mistakes when putting VSPs in action: planning mistakes and expectation mistakes. Both can stunt profitability.

Some VSP projects have gone awry as a result of either a lack of sufficient planning or as a result of delaying the planning phase until it’s too late to get maximum returns. The design of the survey itself is of major concern, as is gaining a proper understanding of the constraints of the acquisition.

This gets back to the basics: the tool locations, the reflection point and the surface source. Though it may seem simple, it is critical to pick these correctly or they won’t shed light on the target area. The entirety of the project must be considered – operational aspects as well as geophysical design.

Even the most basic operational issues have slipped by some major energy players on VSP projects: What is the well plan? Are there any restrictions on the well? Was there cement behind the casing? (It is not possible to attach a geophone with nothing bridging the casing to the formation and expect to get anything useful from it.) Proper survey design prior to the job is paramount.

The second common type of mistake involves pernicious misconceptions regarding the role of this technology. People pay for its use, don’t properly utilize it, and then question its value.

Sure, operations geologists and petrophysicists are getting value on the well at hand, but it is important to look at the bigger picture. Even though it’s well-based, VSP must be viewed as a long-term development tool that keeps delivering year after year. It’s not simply another logging run in the hole, it’s another weapon to optimize the field – and a company’s financial performance – over several business quarters to come.

That is why it is important to look for a specialist when evaluating VSP providers. A group focused on this discipline can help a company make the most on its investment, while a contractor that provides VSP as one notch in an infinite service line may be distracted by what else it can sell as a complement.

Future developments
In the future, VSP will continue to gain the attention of bigger-picture development personnel. As fields increase in complexity, and become more fragmented and difficult to drain, tools such as VSPs will be necessary for economically viable hydrocarbon recovery.

Multiple migration
VSFusion is leading the way in these new developments. The migration of downgoing multiples in a walkaway or 3DVSP dataset now brings us the ability to look, for the first time, at data that comes from above the receivers. This technique dramatically extends the lateral and vertical reach of VSP – allowing high-resolution pictures of the reservoir in a section that resembles a normal seismic line.

Virtual source
VSFusion is also at the forefront of the new Virtual Source technique. This is a mathematical method of replacing the receivers in the borehole with virtual sources. This allows illumination of areas where there has been poor imaging in the past, such as steep sided structures, beneath or beside salt bodies, and under gas clouds. It also can be used to assist in 4D studies, providing a stable source that remains unaffected by near surface or overburden variations – where most of the problems in 4D surveys lie.

Multi-component
VSP will accelerate the acceptance and use of shear wave data from surface seismic surveys.

Bob A. Hardage of the Bureau of Economic Geology at The University of Texas at Austin, who has followed VSP applications for three decades, comments, “VSP technology must, and will, move into the arena of analyzing the basic physics and geological importance of multicomponent seismic imaging. The result will be that geoscientists will begin to rely on VSP to help them apply seismic stratigraphy principles to images provided by the full elastic wave field, rather than to limit this valuable science to information provided by only P-wave images.”

The industry is expected exciting things from VSP over the next decade, and VSFusion is well placed to deliver on this expectation.