In the world of borehole geophysics, Brian Hornby claims to be both the biggest champion and the biggest skeptic. After all, this type of technology is not meant to be used for exploration geophysics but rather as a calibration tool for surface seismic in complex environments. When the resulting data fail to provide additional information, the exercise quickly becomes one of futility.

Hornby, head of Hornby Geophysical Services LLC, spoke at a recent Geophysical Society of Houston luncheon about the technical challenges of achieving a truly useful 3-D vertical seismic profile (VSP) as well as some of the newer technologies on the market. While the talk was highly technical at times, it boiled down to a rather basic theme, as evidenced by the title, “Beyond time-to-depth: Achieving business value using high-end borehole geophysics.”

He laid out his case by asking luncheon participants to pretend that they were subsurface managers for a project. “You’re drilling wells, and you hold the checkbook to decide which technologies you’ll use in these wells,” he said. “What does it take for you to say, ‘This adds value?’”

Although focus of the talk was on “beyond time-todepth,” Hornby made some initial comments on the more standard time-to-depth VSP application. The time-to-depth aspect, Hornby said, accounts for probably 70% to 80% of all of the borehole surveys. “This is the area we have to get right,” he said. “There’s no simple borehole seismic survey. Even in vertical wells getting time to depth can be troublesome.”

Complex overburdens, dipping beds and salt can complicate surface seismic surveys, and this is where VSPs can come in handy. But they don’t always provide the additional information needed for informed decisions.

Business barriers
Because of the nature of the oil and gas business, new technologies often get overhyped before the kinks have really been worked out. “New technology advances create excitement in the industry that can lead to a bandwagon mentality,” he said. “The cooler sounding the technology, the more the excitement, and it becomes sort of like a boom or bust in the stock market. The oil company’s goal is to achieve value, and the vendors rush to commercialization, resulting in overselling.

“This may not be intentional; they’re trying to fulfill the demand they’re seeing. But the technology may be too immature to actually achieve something that will affect a particular project.”

3-D VSPs also have suffered from being shown to be “just as good as surface seismic.” “So what?” Hornby asked. “You already have the seismic; you’re drilling wells on it. If the VSP image looks something like it, academically that’s great. But does it add anything to the project?”

3-D VSP imaging

The objective of a 3-D VSP is to provide a 3-D image volume that delivers crisper resolution than surface seismic and will image areas, such as beneath salt, which are poorly imaged on the surface seismic.

3-D VSP imaging has been a development process, Hornby said. Early examples showed promise but delivered poor image quality, mostly because of inadequate tools and imaging solutions. They also suffered some of the overhyped fate due to over-optimistic feasibility modeling.

Hornby is a huge proponent of instrumenting the wellbore as much as possible. While earlier tools might have been a few hundred meters in length, he promotes tools that are 2,438 m to 3,050 m (8,000 ft to 10,000 ft) in length. He also promotes 3-D finite modeling prior to the survey and the use of the latest imaging algorithms and anisotropic velocity models during processing.

For instance, at its Wamsutter Field in Wyoming, BP used a 160-level tool to perform a VSP survey. Hornby said the well was full of receivers with a large, dense shot pattern. “A lot of modeling went into that,” he said. Results from the survey were very promising.

Given these types of findings, companies are developing both wireline-conveyed and tubing/drillpipe-conveyed land systems, one of which will have 1,000 levels of capability when its development is complete.

Offshore, the size of the prize is enough to spur companies to action. Hornby said that 1,220-m (4,000-ft) arrays are possible, but the tools will still need near-term development to get to the 2,438-m tool he envisions. Simulations, meanwhile, indicate that fully instrumented wells will provide the best data. Again, vendors are working to develop tools, mostly wireline-conveyed,
to meet these goals.

Permanent arrays
This is one of the areas of greatest interest in borehole geophysics. Permanently installed sensors can deliver larger-scale 3-D VSP imaging using multiple instrumented wells with a surface source vessel and can deliver low-cost and effective reservoir monitoring capability.

Costs can be greatly reduced over conventional 3-D VSP due to removal of the rig time cost and lack of requirement
to deploy surface or seabed seismic sensors for reservoir monitoring. For the downhole technology there are two main options:
• Dedicated 3-D fiber-optic sensors. These provide high-quality three-component data but are expensive and of limited array size; and
• Distributed acoustic sensing (DAS). This technology uses an existing fiber-optic cable and pulses light down the cable. The light is backscattered by impurities in the fiber, and the phase and amplitude effects are changed by any strain in the fiber caused by seismic waves or acoustic waves hitting the fiber. A surface box translates the received laser signal into seismic signals.

The big and potentially game-changing advantage of DAS is delivery of a very large borehole seismic array (fully instrumenting the well as essentially the array of sensors is everywhere an optic fiber is instrumented in the well) at very low cost and with minimal or no change to well completion procedures. The downhole sensor is simply plain optic fiber, which could easily be included in the standard well completion cabling bundle (e.g. for downhole pressure/temperature [P/T] measurement). The “low-hanging fruit” for DAS is that many wells are already instrumented with fiber for downhole optic P/T gauges or distributed temperature sensing (DTS). So by adding a surface box while a seabed node survey is being acquired near a well, a full 3-D VSP survey can be acquired at very little cost and with no impact or intervention in the well.

However, Hornby said, there are some issues with data quality. First, signal-to-noise (S/N) is an issue with current DAS systems and is seen to be 20 db or more below highquality dedicated seismic sensors. The impact of this is that the higher frequencies that 3-D VSP targets may not be received with the DAS system, and the high noise floor can limit the useful depth the system can be used at. Hornby said that all of the companies that manufacture these systems are working to get the noise floor down.

Another issue is that the amplitude in DAS surveys falls off very quickly. “If your source is oriented along the fiber, you get a good signal,” he said. “If it’s orthogonal to the fiber, it’s horrible.” As shown by recent field trials, special installation procedures for newly completed wells such as helix-winding the fiber can potentially deliver a more angle-independent result and better imaging.

Traffic lights
Hornby rated the different borehole geophysics systems with a simple traffic light system. Green means the technology
brings business value now. Yellow is some business value but more work needed; red is no business value. The traffic lights look at the potential now, in one to five years and in five years plus.

None of these high-end technologies gets the green light today, but 3-D VSP, amplitude vs. azimuth and anisotropy, microseismic hydraulic fracture monitoring for event location, and salt proximity get green lights within five years. DAS, microseismic hydraulic fracture monitoring for source mechanisms and crosswell imaging get green lights five years or more out.

In the case of 3-D VSPs, Hornby said he’s looking for “the definitive survey. The interpreter says, ‘Wow, now I
can take this to the bank,’” he said. “Once that happens, we move to do business as usual.”