The use of preliminary test wells and seismic data have helped lead the way to drilling in an area of the San Juan Basin where many energy companies had given up, says an exploration executive from WPX Energy in Denver.
AAPG member Steven Natali, senior vice president of exploration for WPX, a new spinoff of the Williams Companies, says the Mancos Shale Formation in New Mexico’s San Juan Basin now appears accessible to drillers.
For decades operators knew that the Mancos Shale exhibited strong gas shows during drilling along the northern margin of the San Juan Basin.
“A lot of drillers had tried to drill it and frac it and came up empty,” Natali told attendees at the 3-D Seismic Symposium in March. “So we went to drill some science wells.”
The annual conference, as in past years, was sponsored by the Rocky Mountain Association of Geologists and the Denver Geophysical Society.
“In the last few years the San Marcos had been seen as declining,” Natali said. “But with the Mancos Shale, the San Juan is about to enjoy a 20-year renaissance.”
Natali’s company has a legacy acreage position within the Rosa Federal Unit, located in the deepest part of the basin where the Mancos Shale is a uniform 1,800-feet thick.
“In the Rosa unit, it’s definitely in a dry gas window. Mancos is relatively uniform and almost all completions in the Rosa area were in a limited area,” he said.
The Mancos Shale has similar characteristics over a large area, Natali said – “basically, it’s one great big bowl.”
WPX’s preliminary work began in the spring of 2008, when it began an exploratory program to confirm the presence of continuous, over-pressured gas accumulation. Its original gas in place calculations came up to more than 300 bcf per section trapped within the Mancos Shale section in the Rosa Unit area.
The company drilled four vertical test wells in West Rosa.
“We cored eight different clusters,” Natali said. “Each has its own mineralogy. Four had good reservoir quality. Then we delved further. Fecal pellets are laid down in packs with excellent permeability.
“That’s where you find the gas and how you’re going to move it,” he said.
After extensive log and core analysis, four zones were identified as potential prospects. However, the Cyan zone, which contained the most gas in place, looked doubtful since it had a higher clay content, making it a poor candidate for fracture stimulation.
“We spent a lot of time studying natural fractures – the results were that the Cyan would be tough,” Natali said. “You’re never going to get anything out of it. So we decided to give it up and go for some others.”
The company decided to focus on two other zones, the Olive and Black zones, which looked more promising.
In 2010 the company acquired a 47-square mile, land and marine 3-D survey over the western half of the Rosa unit and a 35-mile 2-D seismic grid over the eastern portion of the Rosa unit.
Two horizontal wells were drilled into the two different zones in the western portion of the Rosa and four additional vertical science wells were drilled in the eastern half of the Rosa unit with the cutting of additional core.
The two horizontal wells were drilled with oil-based mud during the drilling of the 5,000-foot laterals and tested the Olive and Black zones of the Mancos Shale. Each lateral received 12 hydraulic fracturing stages using plug-and-perf technology, for a total of 5.6 million gallons of water.
The water was brought in from Lake Navajo to the well pad over a three-mile water line, Natali said.
“It had uniform frac performance from stage to stage,” he said.
Assuming a 160-acre drainage, the Olive Zone has 5.5 bcf and the Black zone has 6.9 bcf.
“We’ll know a lot more in another year,” he said.
The four vertical test wells drilled in the eastern portion of the Rosa Unit showed core measurements and electric log characteristics similar to those in the western portion. Factors strongly suggest relative uniform reservoir characteristics over a three-township area, he said.
“All core data says east Rosa is at least as good or better than west Rosa,” Natali said. “Early indicators are we should see some similar characteristics as west Rosa.”
Although well reserves cannot be accurately predicted at present, the wells can reasonably be assumed to be in excess of four bcf each, he said.
“Now we need 3-D of 70 square miles – and we’re in the process of acquiring it in east Rosa,” he said.
Currently, a purpose-built rig is being constructed and is scheduled to arrive this summer where it will embark on year-round multi-well pad drilling of horizontal wells, he said.
“In August we will start year-round drilling,” Natali said. “We will drill eight wells per section and will have buried lines of water coming in.”
But current low natural gas prices may influence production.
“Gas pricing will determine the pace of production,” he admitted. “In 2008 when we started, we thought we’d have $8.25 per mcf. But we will need to move slowly now. We need to get gas prices up to $5 per mcf and get costs down to $6 million.
“Gas prices need to come our way and they will,” he said.
“If all portions of the Rosa Unit were to demonstrate the productivity measured in the first two horizontal wells, total recoverable reserves in the Rosa Unit would exceed 3 tcf of dry, pipeline quality gas,” Natali said.