3-D Mapping Helps Firms Find Pockets of Natural Gas

Pockets of natural gas lie beneath the surface in north-central Arkansas.

First recognized as extractable by Southwestern Energy Co. in 2005, the gas company — and many others that followed — have sought since to determine the most economical method for pumping the resource out of the Fayetteville Shale Play.

Geoseismic mapping has become the go-to technology for locating the gas pockets. The process creates an image of a region’s geology similar to how a magnetic resonance imaging machine, or MRI, maps a human body to allow doctors to see what lies beneath a patient’s skin. The geoseismic images of subsurface terrain allow those drilling wells to understand where impediments exist and to alter a drill’s course to avoid problems, thereby improving a well’s efficiency.

“We use the 3-D to see where faults are, the depths of the shale and the thickness, and doing all this is reducing the number of dry holes we’re drilling,” Mike Rhodes, Southwestern’s geophysical operations manager, said. Rhodes oversees geoseismic mapping for Southwestern, which plans to invest $63 million this year in mapping Arkansas, he said.

Wildcatters formerly used crude methods to determine where a pocket of gas or oil might be. After World War II, two-dimensional imaging became available and remains in use today. But the companies active in the Fayetteville Shale rely most prominently on three-dimensional mapping.

Use in the Shale

The geoseismic images do not tell geologists where the petroleum deposits are. Instead, the images allow geologists to determine rock formations that might contain oil or gas, said Doy Zachry, a geologist at the University of Arkansas at Fayetteville. The formations geologists look for are slightly elevated above a layer of rock containing hydrocarbons. The lighter oil and gas molecules rise above the heavier water molecules and become trapped in the elevated formations, Zachry said. Companies active in the Fayetteville Shale Play also use the imaging to assist in horizontal drilling, Zachry said.

“In the case of the Fayetteville Shale, it is an unconventional reservoir in that, most of the time, shales do not form good reservoirs,” he said.

Shale is not as permeable as other rocks, trapping gas more tightly. Shale also does not create the elevated formations that trap hydrocarbons. Horizontal drilling has become common practice in shale plays because the drill bores up to 3,000 feet horizontally through the layer of shale, releasing entrapped gas at each point along the way. The geoseismic images allow those guiding the drill bit — known as “geosteerers” — to avoid fault lines in the rock, Zachry said.

“The seismic work in the FSP is used to recognize where there is a fault,” Zachry said. “They like to stay away from faults, but otherwise they have to know how to curve into the proper layer.”

Reducing the Guesswork

Before geoseismic mapping, finding pockets of hydrocarbons involved much more guesswork, Zachry said. Geologists determined what geological layers were present by finding outcrops of the rocks at surface level. As more and more wells were drilled in an area, the cores drilled recorded the Earth’s layers, Zachry said, allowing comparison of layer depths at various locations.

Those methods were common before the Fayetteville Shale Play became active, but Southwestern did use a primitive method in the region during the play’s early days.

Rhodes compared 2-D geoseismic models to straight lines, providing little peripheral information. The images created by two-dimensional imaging do not provide the depth needed to avoid problems in the geology that can cause a “dry well,” a well unable to produce.

“When we started out in the Fayetteville Shale, we actually recorded a lot of 2-D,” Rhodes said. “We tried to drill the first Fayetteville Shale wells on the lines.”

How it Happens

Three-dimensional mapping is time-consuming and laborious, Rhodes said. Southwestern had access to about 975 square miles of 3-D geoseismic imaging in the Fayetteville Shale, he said. The company does much of the imaging itself but also buys the rights to examine maps produced by other companies.

The process of preparing a site for geoseismic mapping requires about 200 people from start to finish. Several permits, including one issued by the Arkansas Oil & Gas Commission, must be acquired before the mapping begins. The AOGC issued 66 permits in 2008, of which 31 were issued to Seeco Inc., a subsidiary of Southwestern.

After permitting the area, hundreds of sensors, known as “geophones,” are spaced equidistantly across the area to be mapped. A total of 288 geophones are spread across one square mile, Rhodes said.

“You spread [the geophones] out like a blanket, and they do catch everything that comes back,” Rhodes said.

What come back are the reflected sound waves. Several blasts of sound, or “folds,” are set off in each area to provide the required amount of data, Rhodes said. The surface crew can determine whether data is usable at that point but cannot yet see the three-dimensional image they are seeking.

“We’re talking about thousands and thousands of channels of data,” Rhodes said. “There is a lot of processing steps that go into taking data in the field and interpreting it.”

Each geoseismic map remains the property of the company that created it, Rhodes and Zachry said. But with natural gas exploitation of the shale expected to last decades, Rhodes expects Southwestern to employ its cache long into the future.

“We plan on drilling up here for a long time,” Rhodes said. “So this data will be used for a long time to come.”