NGFE Reports: A to Z, from drilling to production

Getting the most out of shale gas prospects

No one expected it, according to Tom Gardner, Manager of Exploration Engineering, Southwestern Energy Corporation. At the Global Shale Gas Summit in Warsaw, Poland he recounted that his company’s operations in the Fayetteville shale in Texas had come up with naught in January 2006.

“It took 25 years to get Barnett up to speed and it took Fayetteville about five years,” said Gardner who provided an overview of existing shale gas technology and Southwestern Energy’s experience in the Fayetteville shale.

Southwestern, he said, was focused on exploration & production of natural gas; 75% of the company’s budget goes straight to the drill bit.

“We weren’t looking for it at the time,” he explained of shale gas. “In 2001, the Barnett shale was beginning to make the news and Shelby had an ‘ah ha’ moment. They dilled two wells in isolation away from the Weddington, realized they had some volumes that made sense and got US$ 10 million for a leasing campaign.”

Gardner reported, “Today, the Fayetteville is roughly the size of Connecticut. The initial development was in nine sections. In 2009 we operated, drilled and completed over 500 wells and will drill 680 in 2010.”

He said it was a relatively shallow reservoir, which becomes economic at about 13 feet of depth.

According to Mr. Gardner, Southwestern Energy’s concept involved reducing uncertainty, and gathering as much data as possible. The company also studied analogies, and acquired data from other contractors.

“It’s difficult when management is on you to get some answers,” he said, offering the advice: “Only test something if it can change something that you’re planning to do. Test one variable at a time and build repeatability. Learn from others and keep and open mind.”

Data management, he said, was critical. “When you start drilling 400-500 wells a year it can be difficult to incorporate that data.”

Gardner called his company’s experience “Best practice evolution,” offering up some of the hits and misses.

“The rigs we picked up weren’t going to get the job done. We went to pad wells and built a substantial best practices manual, we use 3D seismic which can help us set our landing points, and geo-steering is continuing to improve, increasing penetration rates.”

Exploration technologies employed by Southwestern Energy at Fayetteville included micro-seismic, gas chromatography, 3D/2D seismic, geochemical, production, perforation variations, acid soluble cement, and coiled tubing (experimenting with various lubricants).

He said, “We anticipate seeing our rig times dropping as we move to pad wells.”

Completion design and execution challenges, according to Gardner, included inclusion of 3D seismic and continued integration of all disciplines.

“You want to challenge the norm,” he said of shale gas exploration. “Some crazy idea out there just might work. We destroy value when we become complacent.”

He added, “Have the right people doing the right things and stay disciplined.”

In response to a query from the audience regarding how to facilitate data sharing among operators, Gardner said, “It’s important to form data sharing alliances to move that learning curve to make it as short as possible. We’re all trying to increase efficiency, so as long as it doesn’t hurt you competitively, that’s what should be done.”

“One of the things we’ve seen is the integration across disciplines,” said Chris Usher, Senior Vice President and Chief Technology Office at Global Geophysical, who spoke about the geophysical tools being used in shale exploitation. “With the challenges of unconventionals we see that these people really need to come together – those performing seismic, micro-seismic, and engineers.”

Mr. Usher said that Global Geophysical has become a leading franchise for geophysical data and that the company now possessed a growing data library of 10,000 square kilometers of high-resolution data.

“It’s driving down the costs to make the shale development possible,” he said. Look at the costs in different basins and they’re all different, but by looking at the seismic, it’s a very small expense compared to the overall costs of operating these fields. These tools have a tremendous benefit of unlocking the secrets of these reservoirs.”

Now, said Usher, one of Global Geophysical’s customers in Eagle Ford doesn’t do anything without preliminary seismic information.

“Microseismic has been embraced by drillers and it’s really matured. Gives you info in real time as your doing your completions. It’s been a tremendous learning curve. Seismic will be increasingly embraced before implementation. Now only 3-5% of wells are monitored with micro-seismic, which might be because of expense. It could be at every frac.”

He added that affordable techniques like these were driving down overall costs.

“Microseismic costs are coming down and this can provide for hazard avoidance,” argued Usher. “Consider the costs of hitting a 50 foot fault that you didn’t anticipate.”

“We believe that by listening to all of the fracs we’re going to get a better understanding of all the fracturing networks that are there,” he explained. “Seismic will be embraced earlier in the exploitation cycle, understanding where sweet spots are. All these tools are going to come together; so the earlier you use them, the better. If you’re thinking about exploiting Poland’s resources, it’s good to do just that.”

Geographix’s Fred Poland, Senior Product Manager, Geology Solutions, pledged to share some insights from the US with conference participants regarding exactly where to “apply the drill bit.”

“When you start to drill how are you going to stay within the zone?” he asked, evaluating the 2- and 3-dimensional applications.

“We studied what leading North American shale gas operators were doing, like Chesapeake who’s done the most on the planet. We’ve worked very closely with them, they’re our number one software client.”

Mr. Poland continued, “We put together a workflow to see what the key drivers were to integrate 2D/3D. They need to incorporate a dynamic depth converted seismic backdrop and be able to easily update 2D to 3D.”

“You probably get more bang for the buck fully integrating the project database and a geomodel- this is a huge time saver,” he explained. “Generation of an accurate TVT type log is critical; as you encounter dip, you will either stretch or squeeze that type log. This models the curve going forward.”

Poland outlined the benefits of being able to update a 3D model from a 2D one, including a dramatic increase in productivity, highly accurate TVT models, dynamic depth converted seismic backdrop, creating the most accurate geo-model possible.

Copyright Natural Gas for Europe. This article or portions thereof may be use with proper attribution and linking to NGFE.