Core Competency

For Whiting Petroleum Corp., October 2010 marked a turning point. The Denver-based company was deep into its Bakken program in the North Dakota portion of the Willis-ton Basin, and questions were mounting faster than answers. The Bakken was a unique reservoir and nothing like it had been developed before. This was an oil play in shale, and many in the industry were not convinced that oil could be successfully produced from shales.

Whiting was attacking the Bakken problem with science: pulling lots of core on its wells in Sanish Field, an early find in the vanguard of the expanding play. It was quickly apparent to Whiting that the oil-prone Bakken was far more complex than a shale-gas resource play.

In truth, the Mississippian-Devonian Bakken reservoir is a package of moderate-porosity but low-permeability rocks and organic-rich shales. The Bakken hydrocarbon system consists of an upper shale, a dolomitic siltstone-to-sandstone middle member, and a lower shale. Additionally, other potential reservoirs in the neighborhood such as the overlying lower Lodgepole and underlying Upper Three Forks appeared to have potential.

Whiting geoscientists were frustrated by the long waits they were experiencing for core data from commercial labs. “We would see something of interest and send out a sample for analysis,” says Mark Williams, senior vice president, exploration and development. “By the time the results came back, it would be months later. The turnaround time on routine core analysis was very slow, up to five months at times.”

A 3-D image generated by Whiting Petroleum shows slot pores in a Middle Bakken siltstone sample from McKenzie County, North Dakota.

That’s not acceptable in a red-hot play, where knowledge is evolving each day. Additionally, Whiting was working in the new and puzzling unconventional world, asking innovative questions. The production of natural gas from shale was moderately understood; the production of crude oil from shales and associated reservoirs was not understood at all. What indeed was going on in the Bakken?

“We needed to see the sub-microscopic level,” says Lyn Canter, senior geosciences advisor. “The critical issue is the interaction between oil molecules and reservoir rocks. We had no empirical way of measuring that, and we weren’t getting reliable permeability values.”

Logs, lab measurements and basic petrography workups were supplying confusing and conflicting results, and Whiting was not getting the answers it was seeking.

Building a lab

The company took a bold step. It decided to build an in-house core lab, complete with two scanning electron microscopes (SEMs). This investment would pay off, it believed, by dramatically boosting knowledge of its reservoirs.

In truth, going to SEMs was almost like stepping back into the past. When major oil companies dominated the U.S. industry, SEM work was standard practice. But as the industry aged and majors turned their attention to international and deepwater pursuits, the use of SEM technology for reservoir investigations fell by the wayside.

Nonetheless, industrial users in the medical and semi-conductor fields had significantly advanced SEM technology. When Whiting decided to jump back in some 20 years after SEM’s heyday in oil, it found a much-improved and extremely beneficial technology.

Mark Williams (left), Lyn Canter and Mark Sonnenfeld, Whiting geoscientists, examine images from the Helios Nanolab scanning electron microscope.

“We believed these were the tools we needed to better understand the Bakken,” says Williams. These days, SEM technology delivers high-resolution, three-dimensional images of reservoir rock. Much as subsurface understanding was revolutionized by the leap from 2-D to 3-D seismic data, so has the understanding of the sub-microscopic world of ultra-tight reservoirs been revolutionized by modern-day SEM technology.

The company purchased two SEMs: a Qemscan 650 and a Helio Nanolab 650. The former is an electron beam that operates under atmospheric conditions and can handle wet samples. Whiting uses this device to spatially map and quantify the relative abundance of minerals in prospective reservoirs.

The Helios scope is capable of much higher resolution, and can be used to create 3-D working models of the samples. “At this scale, we can now see pores at the scale of oil molecules,” says Williams.

“The first challenge was to prove that the technology was good and the data were meaningful,” says Cliff Bugge, SEM lab engineer. “We showed that we could see and manipulate reservoir samples at that scale and completely render them in 3-D.”

In some ways, Whiting is an old-school outfit. It pulls a great deal of core, on the order of one a week or so. To maximize the benefit of all this rock, the company also went back to the days of in-house core labs. It converted a file room in its headquarters in downtown Denver into a core layout room.

“We hold collaborative, large group discussions here,” says Canter. “It’s not just geologists—we have engineers, petrophysicists, managers and more, all involved.”

Realizing the benefits

Getting up close and personal with the rocks has already yielded tangible benefits for Whiting.

In the Bakken play, the company has identified new potential reservoirs from core study. It has also greatly enhanced its evaluation of overlying beds for suitability as frac barriers. In a dramatic result, core confirmed that a particular unit was loaded with oil-saturated microporosity. That enabled Whiting to book more recoverable oil on its assets.

But it is its intense focus on reservoir imaging that really gives Whiting a competitive advantage, says Williams.

In some seminal work on pore throats in the Bakken shale, for instance, the Whiting team demonstrated why moveable oil was not able to pass through the pore throats of the shale. Instead, the majority of the oil is being produced from the dolomitic siltstones and sandstones in the Middle Bakken.

The seven-person lab group does not restrict its work to the Bakken. It also provides support to most of Whiting’s exploration and development projects. In addition, Whiting leverages its lab expertise by offering to analyze competitor core data in order to enhance its own understanding of the exploration plays in which it is interested.

SEM imaging has also yielded fresh insights into such problems as formation damage and mineral reactivity. “There are certain things that will do more harm than good,” says Cantor.

At Whiting’s North Ward Estes Field in West Texas, a major tertiary recovery asset, the Yates reservoir is particularly finicky. The loosely consolidated sand grains are coated with a particularly reactive clay. When this clay comes into contact with water and acid, it becomes mobile. “It becomes just like toothpaste, plugging up all the pores,” says Williams.

Using the Qemscan SEM, Whiting was able to manipulate environmental conditions of reservoir samples thereby simulating conditions in the subsurface. The work ultimately confirmed that using slick water for completions would prevent the problem, as the potassium stabilizes the clay and prevents it from mobilizing.

Throughout Whiting, geoscientists can now receive accurate, fast characterization of the composition and pore network of its target reservoirs, along with comprehensive and quantitative maps of all constituent minerals. In addition to the primary information, these empirical values are used to more precisely calibrate log data.

After all, it’s always about the reservoir. As the industry increasingly moves into more complex and diffuse resource plays, it requires better tools to discern what is happening at the reservoir level. And those sophisticated insights can be applied across all varieties of properties, from conventional to unconventional alike.

For Whiting, its proprietary rock lab allows it to quickly see and assess what is going on at the reservoir level. It’s where the rubber meets the road.