The Challenge Of Producing Gas From Shale

The following article comes from the May, 2009 issue of the "AAPG Explorer". Reading about the many logging tools and other methods allegedly used to evalute these shales and make drilling, fracing, and completion decisions, leads me to wonder if maybe some people are making this more complex than it needs to be. Of course service companies want to sell as many of their products and services as possible, and that should be taken into consideration.

At the same time, these shale gas plays are relatively new and experience will provide more efficiency. Meanwhile I think there is much to be learned.
Peter

Shale Calls for the Unconventional

By LOUISE S. DURHAM
EXPLORER Correspondent (source)

Natural gas prices in the $3/Mcf-and-under range understandably are causing many operators to scale back on budgets, production and new drilling projects.

Just don’t expect this to be a permanent scenario.

The consensus is that once the economy turns around, hydrocarbon demand will make an about-face as well.

The waiting game doesn’t necessarily imply wasted time as it offers continued opportunity to delve deeper into potential techniques to better evaluate some of the more challenging and often perplexing plays being explored/ produced.

High on this list are the numerous shale gas plays that have sprung to life over the past couple of years in various regions of the country.

Gas shales differ from conventional reservoirs in that they function not just as reservoir rock but also source rock and seal. Economical production from this complex rock demands extensive hydraulic fracturing and often requires horizontal wells.

Successful wells depend on an in-depth understanding of the geology, petrophysics and geomechanics of the particular shale formation. In fact, an integrated approach to shale gas evaluation can be key to conquering the complexities of these rocks to optimize production of the natural gas they hold.

“It’s fairly obvious to anyone who works in these plays that conventional methods just don’t work,” said Duane Sommer, senior petrophysical engineer at Baker Hughes.

“Our integrated interpretation methodology designed specifically to evaluate shale gas reservoirs focuses on conventional resistivity, neutron, density, advanced acoustic logs,” Sommer said, “and we add magnetic resonance, geochemical, geomechanics and borehole image logs to determine an array of information.”

That array includes lithology, mineralogy, rock mechanical properties, total organic carbon and gas-in-place in the formation, he added.

Specific Challenges

However, not all shales are created equal, so there are differing factors that must be taken into account.

For instance, borehole imaging is not that important in the high-profile Haynesville shale play because there’s no significant fracturing in the Haynesville, Sommer said. In contrast, it’s quite important in the Barnett play and some others.

He noted also that in the Haynesville the actual presence of gas is a given, but it presents other challenges:

• How to optimize getting that gas out of the ground.
• Selecting the best intervals for the completion.
• How to implement the frac job to get the best production possible.
• Where to place the horizontal leg if going lateral.

The goal with all the shales is to gather all the data possible.

“One of the things we found in the Haynesville, especially, is the intervals that seem to produce the best and have the most silicious material,” Sommer said. “They have more quartz than limestone.

“Part of that is the geomechanics,” he explained. “That rock breaks easier – making it easier to frac – so we look at the geochemical logs in combination with the advanced acoustics which we do rock mechanical properties with and look at what intervals will frac easiest.”

Identifying the Interval

The next step is to look at some of the standard logs or magnetic resonance to try to get a better idea of porosity. This can vary significantly in different plays, e.g., porosity is quite low in the Barnett but ranges from 8 to 10 percent in the Haynesville, according to Sommer.

“When we put all our information together, first we find which intervals in the well will fracture easiest,” he said. “Of those we identify which have the best porosity, which has total organic carbon in or near that interval to supply the gas itself.

“We’re trying to pick the interval we think will be most successful for completion,” Sommer noted. “If you’re going lateral instead of just perfing and fracing, you still want to drill the lateral in that same interval.”

The acquired data are presented to the client in a large, wide plot that Sommer likens to a facies curve that shows crucial information such as:

• The target type of rock.
• A piece of rock that would be a barrier to a fracture.
• Rock to stay away from.

“We’re trying to make it as simple as possible for someone to look at the well,” Sommer said, “and even if they don’t understand all the pieces, to be able to say OK, this is where we need to be, where we need to frac, where we need to perf or where to drill our lateral.

“In a nutshell, that’s our approach,” said Sommer, who noted the overall presentation remains the same even though the individual pieces change from basin to basin.

“The general process,” he said, “usually works for all.”