Shales Require Creative Approaches

Barnett Teaches Lessons

Challenges in both new and old shale gas plays are forcing operators into innovative approaches.

Theinto new areas has even resulted in cutting-edge geology and geochemistry.

“They’re finding out that mineralogy is very important,” said Brian Cardott. “A shale is not just ‘a shale.’”

Cardott is an organic petrologist and coal geologist at the Oklahoma Geological Survey in Norman, Okla., and serves as chair of AAPG’s Energy Minerals Division Gas Shales Committee.

Gas shales could hardly be a bigger story.

By current estimates, the shale resource in the United States could total 500 to 700 trillion cubic feet of gas in place.

In his presentation on Oklahoma shale potential, Cardott includes a map showing 19.

There’s plenty of area left to roam, plenty of room to run.

Some of the most innovative thinking in shale exploration and development today has resulted from a changed perspective.

Downhole tools, 3-D seismic, micro-seismic, geochemical logs and special analysis software are being applied as operators begin to see shale plays more in terms of reservoirs than of producing zones.

These type of “resources plays in general seem to be of interest to the industry,” said Scott Reeves, executive vice president in the Houston office of Advanced Resources International.

“It’s one of the more interesting unconventional plays because it’s so undefined,” he added. “But where the real opportunity lies is international.”

For a current overview of shale gas and a look at Canadian potential, Cardott recommended the 2006 Geological Survey of Canada report “The ‘Shale Gas’ Concept in Canada: a Preliminary Inventory of Possibilities” (Open File 5384).

“One of the biggest challenges in shales today is where to find them and where they can be productive, because no one has done an overall assessment,” Reeves said.

Even when a potential shale play can be targeted, operators must confirm the presence and producibility of gas, he noted.

“The first thing is to make sure you have the hydrocarbon resource in place,” Reeves said. “Second, you’ve got to have the deliverability.”

Where We’re Headed

Both Cardott and Reeves were part of the “Mid-continent CBM & Gas Shale Symposium” in Tulsa in October.

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Challenges in both new and old shale gas plays are forcing operators into innovative approaches.

Theinto new areas has even resulted in cutting-edge geology and geochemistry.

“They’re finding out that mineralogy is very important,” said Brian Cardott. “A shale is not just ‘a shale.’”

Cardott is an organic petrologist and coal geologist at the Oklahoma Geological Survey in Norman, Okla., and serves as chair of AAPG’s Energy Minerals Division Gas Shales Committee.

Gas shales could hardly be a bigger story.

By current estimates, the shale resource in the United States could total 500 to 700 trillion cubic feet of gas in place.

In his presentation on Oklahoma shale potential, Cardott includes a map showing 19.

There’s plenty of area left to roam, plenty of room to run.

Some of the most innovative thinking in shale exploration and development today has resulted from a changed perspective.

Downhole tools, 3-D seismic, micro-seismic, geochemical logs and special analysis software are being applied as operators begin to see shale plays more in terms of reservoirs than of producing zones.

These type of “resources plays in general seem to be of interest to the industry,” said Scott Reeves, executive vice president in the Houston office of Advanced Resources International.

“It’s one of the more interesting unconventional plays because it’s so undefined,” he added. “But where the real opportunity lies is international.”

For a current overview of shale gas and a look at Canadian potential, Cardott recommended the 2006 Geological Survey of Canada report “The ‘Shale Gas’ Concept in Canada: a Preliminary Inventory of Possibilities” (Open File 5384).

“One of the biggest challenges in shales today is where to find them and where they can be productive, because no one has done an overall assessment,” Reeves said.

Even when a potential shale play can be targeted, operators must confirm the presence and producibility of gas, he noted.

“The first thing is to make sure you have the hydrocarbon resource in place,” Reeves said. “Second, you’ve got to have the deliverability.”

Where We’re Headed

Both Cardott and Reeves were part of the “Mid-continent CBM & Gas Shale Symposium” in Tulsa in October.

Cardott discussed “Frontier Gas-Shale Plays of Oklahoma,” and Reeves delivered the keynote address, “Unconventional Gas: Where We’ve Been and Where We’re Headed.”

In talking about Oklahoma plays, Cardott identified three key questions to be resolved:

  • What is the minimum thermal maturity needed for shales containing oil-generative organic matter to be economic gas shales?
  • What is the importance of natural versus induced fractures?
  • What is the importance of free gas versus sorbed gas?

Questions about thermal maturity, organic matter content and shale composition have become increasingly important to geologists working the new shale-gas plays.

Vitrinite reflectance is the most common thermal maturity indicator for Oklahoma shale, with a lower oil-window cutoff of 0.5 percent Ro, according to Cardott.

As new plays develop, geologists are realizing that shale type, composition and mineralogy can be critical factors. In Oklahoma, the Woodford shale resembles the silica-rich Barnett, Cardott said.

By contrast, the Caney shale is more clay rich.

Operators have found that clay shales in general do not respond as well to fracture stimulation as silica-rich shales.           

“They’re at the start of the learning curve for the Caney shale more than the Woodford,” Cardott noted.

Barnett Lessons

Two years ago, the Barnett shale play in Texas was barely out of its infancy; today it’s the grandfather of Mid-continent shale gas.

Reeves said lessons drawn from the Barnett can help geologists better understand new shale prospects, even when characteristics differ.

“What we’ve seen is that the presence of brittle material in the shale really helps,” he said.

“This has been documented in the Bakken and Mancos. On the gas side, it’s been discussed widely only in the Barnett. People have suggested the presence of brittle material seems to lead to more productive wells,” he added.

The low predictability of shale gas production can be an obstacle for operators working in new play areas.

Reeves said his company utilizes its COMET3 reservoir simulator designed for non-conventional reservoirs like coalbed methane and shale gas.

“In the early stages of development you don’t have enough data to drive it, but people still need to make decisions,” he said.

To counter the scarcity of data in new plays, Advanced Resources has successfully coupled its reservoir simulator with a Monte Carlo simulation approach, Reeves said.

“The beauty of it is that it captures all of the possibilities of the physics,” he explained.

Fractured Learning Curves

As a means of measuring the calculated formation pressure of a potential shale gas reservoir, Schlumberger has developed a wireline system and analysis methodology.            

Learning curves also apply to drilling and fracing in new shale plays. A shift from vertical to horizontal drilling opened up shale zones more effectively and boosted initial production rates in the Barnett.

According to Schlumberger, there were only four horizontal wells in the Barnett shale in 1999. By the end of 2004, there were 744.

Operators now approach most shale plays with the expectation of horizontal drilling.

“A lot more attention is being given to horizontal wells in shale than has been given in the past,” Reeves noted.

He said horizontal applications in shale could follow the more advanced approaches used in coalbed methane development, such as pinnate-pattern drilling.

“I don’t see why that would not be applicable in shale,” he said.

Studies, testing and debates continue over the most effective methods of fracturing gas shales.

“For 150 years, shale gas was mostly from fractured reservoirs,” Cardott said. “The better potential is when you can fracture the reservoir yourself.”

Yet the best fracing approaches for shale aren’t obvious, as operators focus on the characteristics and importance of natural fractures and on the right frac fluid-proppant combinations.

In new play areas, hole placement in relation to natural fractures may determine optimal drilling direction.

Early on, industry considered natural fractures essential for good shale gas production. Then their importance was downplayed  --  but the current view once again emphasizes the value of naturally fractured reservoirs.

Operators avoid highly fractured areas in some shale plays, however, hoping for better control of fracture treatments.

Almost all fracs in gas shale horizontal wells have aimed at creating multiple traverse fractures in relation to the borehole. A new theory of long fracing proposes the creation of longitudinal fractures.

The geological setting of a shale play also affects fracing decisions. Cardott said shale operators found that the presence of a natural frac barrier kept their wells from watering up.

“Then they discounted certain areas that don’t have the frac barrier because they wanted to stay away from the water. Now if they do everything correctly, they can have a good well without the frac barrier,” he said.

That approach helped the Barnett play move out of its core area and could have applications in Mid-continent shale plays.

An early thought held that gel fracs are not effective in shale, leading to a preference for water, slickwater or nitrogen-foam fracs.

Current work targets enhanced pumping fluids for better fracturing and more efficient suspension and delivery of proppants, as well as better proppant design.           

An Innovative Approach

Several factors will determine the future of shale gas plays.

Most of them point to the need for continued innovation.

Natural gas prices have fallen while shale development costs have zoomed upward. Operators seem likely to concentrate on improved exploration, production efficiencies and best practices to control costs.

A combination of current knowledge and new approaches will be needed as shale plays move into more geologically complex areas.

And the opening of shale gas plays outside the United States will require innovative techniques to overcome new challenges.

Because shales and settings can vary so widely, operators say there is not one “biggest problem” in approaching a new play area.

Instead, shale plays present a series of problems to be solved and obstacles to be overcome. Shale exploration and production requires continuous innovation.

“Almost every shale play has undergone a watershed event  --  and frequently that happens by accident,” Reeves noted. “They limp along for a while and then somebody discovers a little trick, and the thing just explodes.”

In the future, Reeves expects shale gas operators to borrow a page from coalbed methane production and utilize nitrogen or CO2 injection for enhanced recovery.

“If you’re looking out on the horizon that may be a technology to consider,” he said. “What you’re probably looking at there is what’s going on with enhanced coalbed methane.”

In the United States, operators have moved well up the shale gas learning curve but still have plenty of room for experimentation and new ideas.

Oddly enough, a better understanding of shale has driven the industry back to geoscience for prospect evaluation, drilling placement and steering, and reservoir analysis.

Said Reeves:

“I’m a petroleum engineer and I’ve been doing unconventional gas pretty much my whole career. It became painfully obvious  --  put your money into finding the right place to drill in the first place.”  

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