Using Image Data for Mineralogy

Hydrocarbon production from shale reservoirs continues to fly in the face of the early naysayers who predicted that these rocks would spit out considerable volumes up front, only to become dormant immediately thereafter.

Even amid the ongoing challenging price environment, shale production numbers are sufficient to encourage a relatively high level of new leasing activity.

Much of this active scene can be attributed both to all-new technology and successful tinkering with what’s been tried before.

Still, it’s no slam-dunk.

Conventional reservoirs harbor relatively sizeable pores with good permeability, whereas unconventional accumulations demand a great deal of specialized coaxing to move through the limited exit avenues indigenous to tight rocks.

Understanding the complex makeup of these reservoirs is essential, and it requires considerable evaluation and time.

Independent Whiting Petroleum is doing its part to stay on top of the challenge. The company assembled its own rock laboratory that uses the latest techniques to yield an enhanced understanding of pore systems and oil movement through these tight rocks.

It’s all about data and interpretations generated using imaging technology. In fact, certain petrographic and petrophysical data of unconventional pore systems can’t be acquired any other way, according to AAPG Member Lyn Canter, rock lab manager at Whiting.

Image Caption

Distribution of brittle (light grey) and ductile (dark grey) minerals.

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Hydrocarbon production from shale reservoirs continues to fly in the face of the early naysayers who predicted that these rocks would spit out considerable volumes up front, only to become dormant immediately thereafter.

Even amid the ongoing challenging price environment, shale production numbers are sufficient to encourage a relatively high level of new leasing activity.

Much of this active scene can be attributed both to all-new technology and successful tinkering with what’s been tried before.

Still, it’s no slam-dunk.

Conventional reservoirs harbor relatively sizeable pores with good permeability, whereas unconventional accumulations demand a great deal of specialized coaxing to move through the limited exit avenues indigenous to tight rocks.

Understanding the complex makeup of these reservoirs is essential, and it requires considerable evaluation and time.

Independent Whiting Petroleum is doing its part to stay on top of the challenge. The company assembled its own rock laboratory that uses the latest techniques to yield an enhanced understanding of pore systems and oil movement through these tight rocks.

It’s all about data and interpretations generated using imaging technology. In fact, certain petrographic and petrophysical data of unconventional pore systems can’t be acquired any other way, according to AAPG Member Lyn Canter, rock lab manager at Whiting.

She noted that these techniques have enabled improved drilling efficiency, evaluation of reservoir intervals for hydraulic fracture potential and the optimization of horizontal drilling targets in real time.

Specialized SEM

In fact, the rock lab team is employing scanning electron microscope (SEM) technology, which has been around for a number of years.

But with a nod to the “everything old is new again” adage, Whiting uses a specialized scope built to help with automated mineralogy, which is a technique designed for the mining industry for assay work more than a decade ago. This automated mineralogy has been ported to sedimentary rocks in the oil and gas industry. Canter noted that other companies also have this capability.

One key aspect of the X-ray detectors onboard the SEM used in Whiting’s rock lab is the ability to identify the elements present at a particular spot on the rock samples placed in a sample tray.

“We can set the rate and the size of the sample, so if we need to collect a lot of X-ray spectra, we can,” Canter said. “This thing scans the samples and through an algorithm, combines these data into likely mineral occurrences.

“We can set the 25 most common sedimentary minerals we think should be in groups of samples and can analyze for those, so it’s quantitative,” she noted. “We also receive as a product of this a 2-D false-color mineral map that shows the distribution of all minerals in that sample. That influences how you interpret certain things like wireline logs, facies.

“Also, certain minerals have very different degrees of hardness and density, so you can start to group your minerals into like categories that help you understand how that zone, if it’s porous and a target for you, might respond to a certain type of stimulation in completing the well.

“All of that is done with that one machine,” Canter emphasized. “We use that particular SEM to help us understand our reservoirs with an emphasis on those kinds of properties we would be collecting.”

It’s a tedious operation, which requires characterization at the micro- and nano-scales.

If clays are layered, this impedes fracturing breakdown whereas dispersed clays are a different story. So the ability to group a locale into brittle vs. ductile is a big deal.

Spatial Distribution

Canter emphasized that spatial distribution of minerals is key to understanding mechanical properties and how they vary by zone.

For example, an operator may be evaluating the reservoir potential of a mud rock that has competent grains such as quartz, calcite or feldspars touching in 3-D space. If there is organic porosity in between those grains in terms of how the primary organics are distributed and then thermally matured, the rigid framework preserves the porosity. In contrast, if the grains are not touching, the whole zone would compact.

But a pore is more than a pore.

“If we have a certain pore throat diameter of, say, five nanometers and oil gravity at 30 degrees API, the question is whether that oil will move through those pore throats in the production time you have,” Canter said. “Gas and condensate, no problem, and volatile oil possibly, no problem.

“Based on what product you have and the size not just of the pores but the throats, which are really the bottleneck in the whole thing, you have to think of the hydrocarbon molecule types that would be able to move through those throats,” she cautioned.

“To QC that early on in a play concept is important because it speaks to deliverability and producibility,” she said, “and that’s what drives economics.

“We want those answers sooner rather than later when involved in new plays or a new concept.”

Success with a recent well in Whiting’s Bakken/Three Forks play in the Williston Basin in North Dakota documents the advantages afforded via application of this advanced technology.

“The Middle Bakken is the typical target in the Basin when you’re in a new or questionable area,” Canter said. “We recently drilled a well near the edge of the thermal maturity of the Bakken shales, so we were flirting with a line between immature, onset of maturity and mature enough to expel hydrocarbons.”

A vertical core was acquired and hot-shotted to the imaging lab in Denver for analysis, which was accomplished within days while the rig remained onsite.

The in-house lab results from evaluating the zones for reservoir character, facies and mineralogy convinced Whiting to switch the horizontal target to the Three Forks, thereby expanding the productive area of the play.

“Little did we know until we pulled a core through both formations that we had a facies change that gave us a much more clay-rich Middle Bakken section,” Canter noted. “The Three Forks was better behaved in terms of what you expect to see in that position in the Bakken, which is good dolomite intercrystalline porosity.”

Expect to hear a great deal more about the use of this ultra-precise imaging equipment in the Williston Basin.

Whiting senior vice-president Mark Williams said recently that the industry is asking about what can be expected of the total resource potential in the Basin.

The company’s experts are working on it.