Data indicate sweet spots, dead zones

Shales – Similar, Yet So Different

American Association of Petroleum Geologists (AAPG)
Seeing in 3-D detail: At the foot of the Canadian Rockies, the Montney shale play is being developed in a fairway of higher TOC (yellow/red).
Seeing in 3-D detail: At the foot of the Canadian Rockies, the Montney shale play is being developed in a fairway of higher TOC (yellow/red).

Shale gas plays in North America have rapidly become so numerous – and productive – there’s a tendency to think of them as being conventional rather than unconventional.

Despite the well-publicized public concern about the safety of hydraulic fracturing involved in shales production, the already hot action in shale plays appears to be heating up further.

This reportedly is being spurred in part by BP’s now-infamous Big Spill in the Gulf of Mexico and the ensuing government-imposed moratorium on leasing, deepwater drilling, etc.

Even before this near-unfathomable mess occurred, newcomers to the shale were latching onto opportunities to stake out claims in the high-flying plays via acquisitions or joint ventures. These included some of the larger companies based in the United States as well as international firms.

Many industry participants anticipate this trend to intensify given the iffy situation in the Gulf, which has long held forth as the backbone of domestic energy production.

Under the circumstances, few would argue that the timing of the shale gas “boom” has turned out to be fortuitous.

Murray Roth
Murray Roth

Recent estimates of recoverable gas from unconventional shale reservoirs in the United States exceed 500 Tcf (USGS/EIA 2009), with potential for another 200 Tcf in Canada, according to AAPG member Murray Roth, president of Transform Software and Services in Littleton, Colo.

The EIA Annual Energy Outlook 2010 reports that shale plays make up 2.75 Tcf of current U.S. natural gas production, with this number expected to reach 6 Tcf in 2035.

Roth noted that North American shale gas reservoirs currently account for six of the 22 largest gas fields worldwide based on estimated recoverable reserves, with average recovery factors about 20 percent.

Head Scratchin’

Since the now-legendary George Mitchell and his dedicated Mitchell Energy team of experts succeeded in devising the particular fracing technique needed to spur economic production from the original big daddy of shale gas plays – the Barnett – shale-focused technology has evolved considerably.

This includes horizontal drilling and completions, supported by 3-D seismic, microseismic and FMI (Fullbore Formation MicroImager), FMS (Formation Micro Scanner) among other measurements.

Sounds like the operators have mastered the shales, huh?

How naïve.

Nothing is simple in this industry, and even some of the most experienced shale players often have to step back and do a bit (a lot?) of head scratchin’.

There are shales, and there are shales.

North American shale gas basins generally follow a trend of thrust belts and a Mississippian/Devonian shale fairway from western Canada and into the western, southern and eastern United States, according to Roth.

Serving as source, trap and seal, shale beds have characteristics that vary not only from region to region but also within specific plays and fields. In fact, there often are significant well-to-well variations in gas production within a single field.

“Part of this variability in production performance is related to evolutionary and company-to-company differences in best practices fracturing,” Roth said. “Surprisingly, after nearly 30 years of development and over 14,000 wells, wellbore lengths and completions parameters in the Barnett Shale of Texas can vary by factors of two or more, pointing to the challenge and non-uniqueness of production optimization.”

Where there is large variability in production from well to well, it clearly tends to challenge any assumption that shales and their indigenous hydrocarbons are simple and consistent.

Meeting the Challenge

Transform is throwing the book at the challenge.

“Our approach is to integrate all of the geophysical, geological and engineering data,” Roth said. “Engineers tend to want to treat the shales as ‘gas factories,’ laying down a well every 10 or 20 acres and developing the fields in a very methodical mode.

“This works in some cases, but an integrated approach is needed for optimization in most plays,” he noted. “For instance, well-to-well production can often vary by a factor of two or more if you haven’t used seismic data to determine where the fairways are.”

To try to understand the variances in gas shales, Transform has conducted a study that integrates published data, type logs, accessible seismic and microseismic data along with five years experience across most significant North American shale gas basins, according to Roth.

The tabulation of shale gas reservoir characteristics and well log analysis highlights key production differentiators including clay content, pressure and total organic carbon.

“It’s our work with 3-D seismic and microseismic that clearly supports the concept of shale gas ‘sweet spot’ fairways and converse ‘dead zones,’” Roth said.

“Whether it’s faulting in the Woodford, karst collapse chimneys in the Barnett, natural fracturing in the Marcellus or relative clay content across many plays, seismic and microseismic data provide valuable calibration and prediction tools for mapping productive and/or non-productive fairways,” he noted.

There’s motivation aplenty for folks to perform some scientific detective work on the slew of shale deposits.

Roth noted that 60 potentially economic shale gas plays have been identified in North America, and shale “fever” is spreading quickly overseas in Poland, Germany, Austria and other countries.

And it’s not all about gas, owing to the relatively high price for crude oil.

For example, activity is full-speed-ahead in the highly productive Bakken shale oil play in North Dakota, and also in gas-liquids-rich shale plays such as the Eagle Ford in Texas.

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