If operators take the “glass half full” approach and use their idle time wisely during the industry’s current downturn, the seismic industry – at least parts of it – could experience an upswing.
It’s no secret that when oil and gas prices drop, industry players first scale back on drilling and seismic acquisition – their most costly expenditures.
It’s certainly a punch in the side to the seismic industry, which has been moving full steam ahead since the shale oil and gas boom hit the United States in the early 2000s.
Major service companies such as Baker Hughes Inc. (which is being acquired by Halliburton Co.), Schlumberger Limited and Weatherford International recently announced layoffs of 7,000, 9,000 and 8,000 employees, respectively. Halliburton recently announced the elimination of 1,000 positions in Houston.
However, companies that specialize in seismic processing and seismic monitoring could see their businesses grow.
“Falling oil and gas prices is a double-edge sword. It’s bad in some respects, but good in others,” said past AAPG treasurer Deborah Sacrey, owner of Auburn Energy, a Houston-based geological consulting company.
“It’s a bad time to drill wells and acquire additional seismic, but it’s a good time to dig into the seismic data you have and reprocess it,” Sacrey said. “People have been going so fast and furious to drill wells that they haven’t been paying close attention to their seismic data to see if their well locations were located optimally for the best production.”
Along the same lines, now also is a good time to revisit the optimization of well completions and eliminate unnecessary stages and pumping that could cost hundreds of thousands of dollars, said AAPG member Peter Duncan, co-chairman and founder of Houston-based MicroSeismic Inc.
“Reducing the cost for the wells you need to drill,” he said, “that’s where the focus is these days.”
Wringing Seismic Data Dry
In general, onshore acquisition of seismic can cost tens of thousands of dollars per square mile – more costly compared to reprocessing data, said Mike Dunn, senior director of geophysics, geology and reservoir management for Landmark, a Halliburton business line.
“It’s a good time to do reprocessing because it’s a lot cheaper,” he said. “If you can get more information from your existing data, why not do it?”
For example, in the Gulf of Mexico, initial velocity models were built to expedite data sales, and as a result shortcuts were often taken, Dunn said.
“You can improve your seismic data by including new well information and updating those models,” he said.
In terms of its use in unconventional plays, seismic remains in infancy stages, Dunn explained. Much more information can be gleaned from seismic data with the right tools and techniques, which are constantly evolving and being brought to market.
In many cases, the application of new processing technology can open up new geologic plays, Dunn said. For example, in the deepwater Wilcox Basin in the Gulf of Mexico, a play remained unknown until the early 21st century – a time when improved processing techniques exposed large structures below the salt.
“By improving overall data quality, operators can still explore and discover plays that were not identified previously in many basins around the world,” Dunn said.
If seismic data is older than five or six years, reprocessing can likely optimize well locations, Sacrey said, explaining that companies might have pieces of 3-D seismic that need to be merged or re-bended or additional seismic attributes that might need to be further scrutinized.
Sacrey also said she is noticing that some seismic processing companies are lowering their prices to encourage operators to reprocess their data.
“Processing technology changes so much these days,” she added. “Take advantage of this ever-evolving field. Think of a towel – take your seismic data, wring it out and get all you can out of it.”
Optimizing Completion Processes
For Duncan, the current downturn is like déjà-vu: “I’ve seen several of these cycles before, he said, “and I’m not panicking.
“I know from the service side that when times are tough, you have to hunker down, polish your product and be even more diligent about meeting your customers’ needs,” he added.
Duncan is finding that when “every penny counts,” some operators are focusing on making their existing well completions more effective by refrac’ing and monitoring those “refracs” as an alternative to drilling.
“It’s beginning to drive my business,” he said.
In a trend that began late last summer, operators have begun to rely on refracs to maintain production – a delicate process that Duncan said requires more monitoring than initial fractures.
“A lot of operators are going back in and recompleting their wells and are seeing production increasing again,” he said. “It may not be back to the original volumes, but it is still significant.”
With the infrastructure already in place, there is no need to drill another well.
“You are simply getting more life out of what already exists,” Duncan said. “And it keeps your staff employed.”
Whether a well is being completed for the first time or is undergoing a refrac, real-time fracture monitoring can help detect mechanical and geological failures that are often caused by faults that become reactivated when a rock is hydraulically fractured. The faults become “thieves,” Duncan explained, by soaking up fluid and proppant over several fracturing stages.
When detected through monitoring, faults can be sealed and grouted off to promote the fracturing of new rocks.
In recent refrac projects, Duncan has found that diverters often fail, and most of the frac energy is concentrated near the heel of the well. Microseismic monitoring helps operators quickly diagnose this problem and find a solution.
Furthermore, real-time monitoring can curtail the pumping process, saving both time and proppant loss. When the surface area of a frac is no longer increasing, shutting down pumping during the “lazy stages” can provide a cost savings ranging from $20,000 to $50,000 per hour, Duncan said.
Monitoring also can help reduce the number of stages in a hydraulic fracturing operation by detecting overlapping stages that could be spaced out, Duncan said. Eliminating a stage can save operators anywhere from $100,000 to $400,000.
On the other hand, an additional stage might be needed to recover more hydrocarbons.
If wellbore spacing is an issue, monitoring can determine if the distance between wells is sufficient.
“Make sure you are not spending too much to harvest the most hydrocarbons from your field,” Duncan said. “You don’t want overlapping drainage areas in your well.”
Gas in the Interim?
While current oil and gas prices are allowing operators to take what could be a productive pause, too much downtime has some fearing a repeat of the 1980s oil glut.
“There seems to be an attitude difference between the larger companies and the smaller companies,” Sacrey noted. “The larger companies have the cash base to retrench and wait this out. They have time to take a second look at their data and completions.”
It is the small and mid-sized companies – namely those who hopped on board the shale boom locomotive and have driven it to present day – who can’t take too much time out.
“Those who got into shale late or who are underfunded are most at risk,” Sacrey said. “They don’t have time to go back and take a new look at their seismic data.”
With oil and gas prices currently at a disconnect, Sacrey speculates that some operators might shift their focus to gas, especially as the U.S. regulatory agencies continue to approve the construction of facilities – such as those in Oregon, Louisiana, Texas and Florida – for the exportation of liquefied natural gas (LNG) to counties that don’t have free-trade agreements with the United States.
“That’s the beauty of the industry in the United States. It’s diversified,” she said. “There are niches. One niche may be hurting while others are flourishing.”