It's not for lack of trying. Today, the vast majority of rigs working in North America are drilling for gas. As conventional gas reservoirs have become exhausted, the industry has directed considerable technological clout toward filling the production gap with gas from tight sandstones, shales and coalbeds.

In unconventional reservoirs, the biggest challenge is establishing conduits from the far reaches of the reservoir to the wellbore. By far, the most practical and economical approach to the problem has been to stimulate the formations using hydraulic fracturing. In the past decade, most fracture stimulation has been carried out in sandstone reservoirs treated with only a single hydraulic stage, but results were so encouraging that the technique has been extended to more challenging targets.

Following some early successes, hydraulic fracturing has found a home in North America, where some 70% of the world market currently resides. Of this market, nine out of every 10 wells stimulated are gas wells.

Maximizing reservoir contact is the name of the game today, and to this end the entire reservoir-development plan has been devoted. Operators have quickly learned that precisely placing multiple fractures in a horizontal wellbore drilled through the heart of the reservoir can expose more than 1,000 times more rock than a vertical wellbore can.

Capitalizing on this idea has paid huge dividends. For example, two out of three U.S. land wells serviced by Schlumberger in 2002 were treated with a single-stage hydraulic fracture. Just three years later, the number dropped to less than 50%, while 25% received two-stage treatments and 30% were treated with three or more.

As an example, tight gas wells in the Rockies are often treated with more than 10 fracture stages to effectively stimulate multiple, thin pay zones distributed over gross intervals spanning thousands of feet.

The exploitation of shale reservoirs is the fastest-growing segment of the U.S. land market. Typically, permeabilities in these reservoirs are measured in nanodarcies. To obtain commercial production rates from such low-permeability rock, it is increasingly commonplace to drill long horizontal wells to try to intersect natural fractures in the shale. Then multiple hydraulically stimulated fractures are placed along the length of the wells to further enhance conductivity with the reservoir.

Using horizontal drilling and multistage fracturing techniques, operators have been able to produce reservoirs believed to be uneconomic only a few years ago. Still, it was believed that, with the addition of innovative technology, the productive yield from application of these techniques could be further enhanced.

In the past, many hydraulic-fracture treatments amounted to brute force application of hydraulic pressure to split the rock, then the resulting fissures were packed with sand to keep them propped open after the well was placed on production. Little attention was given to trying to understand exactly where a fracture went once it propagated from the wellbore.

One could never be sure whether a treatment reached its full potential. In fact many well-intentioned treatments propagated into aquifers, which flooded the fractures with saltwater, often cutting off gas production altogether. In other instances, fractures meandered into poor-quality sections of the reservoir, never living up to their designed potential.

Geoscientists believed that if they could measure dynamically the propagation of a hydraulic fracture, they could learn how to control it and ensure that it went deep enough to maximize production potential while avoiding aquifers. One technique that shows great promise is monitoring the infinitesimal sounds that rocks make when they crack hundreds of feet from the wellbore.

Technology has provided the means to record these so-called microseisms, or mini-earthquakes, using highly accurate 3-D geophones. Moreover, the sounds can be discriminated from all the other noises surrounding field operations. Initially applied by using surface arrays of geophones to listen for evidence of rocks cracking, the microseismic technique has recently been enhanced by emplacing the geophones in nearby offset wells.

But the technique had its detractors, who pointed out that it took so long to process the data that, no matter how accurate, any interpretation of fracture propagation was received long after the frac crew had departed. Often it was determined that even if the microseismic images identified a fracture as suboptimal, coming back to re-treat it was uneconomic.

Skilled jewelers spend hours examining raw gemstones under a microscope before applying the precise blow that splits them into beautiful diamond solitaires. The difference between success and a pile of worthless dust is the ability to place the fracture exactly along the diamond's natural stress line. So it is with hydraulic fracturing, except that, unlike the jeweler, the geoscientist has hitherto been unable to see the target.

Now, fracture geometry can be directly measured in real time through a new diagnostic service, StimMAP. By mapping hydraulic fracture systems as they are created, which means judicious application of pressure, diverters and isolation devices can help "steer" the fracture to its desired target.

Key to the development of this service has been the ability to process and interpret the microseisms in real-time, accurately characterizing the location, geometry and dimensions of the hydraulic-fracture system in 3-D space.

To obtain the microseismic data, downhole monitoring is conducted in nearby offset wells. Special tools are able to discriminate the sounds from the fracture as it propagates from the noise of pumping units and other surface equipment. The interpretation integrates the microseismic data with dynamic data from the stimulation, such as pressure response, flow rates and volumes.

A key ingredient is derived from microseisms received after the pumps are shut off. These sounds, created as earth stresses are equalized, provide valuable clues as to the direction of the fracture tip. All data can be processed on location to generate a 3-D image of the fracture system, providing the opportunity to resume pumping to extend the fracture or re-engineer subsequent stages to reach untreated sections of the reservoir.

The ability to monitor fracture geometry in real time brings several benefits. Knowing how a fracture is propagating allows operators to stop pumping at the precise point that desired results are obtained. This ensures that frac resources are not wasted, reaching barely incremental reservoir volumes. One operator in the Barnett shale saved more than 6,000 barrels of fracture fluid on a single treatment by knowing when to stop pumping.

Besides reducing the operator's completion costs 15%, real-time hydraulic fracture monitoring enabled access to new portions of the reservoir previously unstimulated.

Controlled placement of the fracture systems leads to controlled conductivity that can affect ultimate reservoir recovery as well as minimize subsequent intervention costs. An array of diverters and fracturing fluids help steer the fractures to access the highest-quality reservoir volumes. Techniques also immediately perform a true test of the reservoir's post-frac performance so results can be quantified.

Like the blow of the jeweler's chisel, hydraulic fracturing must apply just the right amount of force, for the right amount of time, at the right spot and be able to prove that it has achieved the right result.



Ian Bryant is worldwide manager for Schlumberger stimulation. He is a past chairman of the Society of Petroleum Engineers' development geology and geophysics committee, and has made more than 40 contributions to books and professional journals. StimMAP is a mark of Schlumberger.

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