KENEDY, Tex. — These are lean days in the South Texas oil patch, with once-bustling roads and hotels now empty as the price of oil has plungedand rig after rig sits idle.
Still, production has barely declined, a testament to the rapid gains that oilproducers are making in coaxing ever more oil from older wells and the few new wells they are still drilling — and doing both while investing far less money.
The Norwegian oil giant Statoil, for instance, is experimenting here in the Eagle Ford shale field with a host of new drilling tools and techniques.
It is trying out different grades of sand to blast along with water and chemicals to better loosen the hard rock deep underground and increase a well’s production, and varying the depths of wells to squeeze out even more oil. It is using new well chokes that technicians can operate remotely from a computer or even a smartphone to quickly adjust flows to maximize production without overtaxing pipelines.
“There’s a proverb in Norway that says necessity teaches the naked woman how to knit,” said Bjorn Otto Sverdrup, a Statoil vice president, as he and another executive of the Norwegian oil company toured the Eagle Ford shale field the other day.
The knitting is progressing. Even as the company cut the number of rigs it runs here from three to two since last year, it has managed to lift production by one-third, a feat that would have been unimaginable a few years ago.
It has cut the average cost of drilling from $4.5 million to $3.5 million a well, in part by reducing the time it takes to drill from an average of 21 days to 17 through better planning and laying off slower crews.
Statoil’s example is just one of many for an industry reeling from the collapse of oil prices since last summer. Companies have laid off thousands of workers, and some are having trouble paying their debts. They have decommissioned more than half of the country’s oil rig fleet. Companies like Anadarko Petroleum and EOG Resources have drilled hundreds of wells without completing them, saving their expenditures on hydraulic fracturing until the price of oil recovers.
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But a majority of the major companies are managing to survive by increasingly using techniques traditionally more common to manufacturing plants than to oil fields to achieve economies of scale.
In some shale fields where companies typically drill up to eight wells on each production pad, companies are no longer drilling one well at a time. Using rigs that can move on tracks or legs, they are drilling and completing several wells at a time, slashing the time it takes to drill each well.
The result has already been a slower decline in domestic shale oil production than many experts had expected, and the promise of a spike in output if the global market price continues to rise as it has in recent weeks.
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The Energy Department still expects the average daily production for the year to be moderately higher than in 2014, rising from 8.7 million barrels a day to 9.2 million.
“We can’t control the commodity prices, but we can control the efficiency of our wells,” said Ben Mathis, Statoil’s Eagle Ford operations manager. “The industry has taken this as a wake-up call to get more efficient or get out.”
Using new fiber-optic sensors thousands of feet below the ground, operators are receiving streams of data allowing them to analyze rocks in real time to make quick decisions.
The sensors can determine how far a fracturing job is penetrating hard rocks to plan the spacing of wells more accurately. That way, producers are assured that one well is not draining oil from another and that no significant section of the shale is left untapped.
And by keeping track of temperatures, pressure and vibration on equipment that is out of sight, sensors and advanced software can predict when equipment needs servicing before it breaks down.
“You are more efficient because you are forced to be more innovative,” said Patrick Pouyanné, chief executive of Total, the French oil and gas giant. Mr. Pouyanné estimated that the break-even price for operating in 75 percent of the shale oil fields a year ago was $75 a barrel, but that is now down to roughly $60 because of innovation and lower service company costs. He predicted that the break-even cost could go as low as $50 before long.
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Companies like BP, Chevron and Devon Energy have turned to GE Oil & Gas to help improve exploration and production controls to save power and keep equipment running longer and more efficiently.
The company is deploying meters that can determine how much water is mixed with gas and oil before production even begins. A harder pump rate brings up more water and oil, but water is expensive to treat at the surface and reinject in disposal wells. When oil prices are low, the operator can decide not to produce wells with high water content but save them for completion when prices recover.
Developing new variable-speed controls and algorithms that determine the flow of wells, GE Oil & Gas has figured out ways to turn on and off pumps that formerly operated 24 hours a day, cutting fuel consumption by up to 20 percent. With lower pump use, repair and maintenance costs have fallen enough to bring down the cost of production by two or three dollars a barrel.
In the case of Whiting Petroleum’s Bakken shale holdings in North Dakota, new speed controls on its well pumps reduced equipment repair downtime by 48 percent and helped increase the productivity of its wells by 28 percent in recent months.
“Our industry is very slow to adapt to change, so these shake-ups can be good for challenging operators to find better ways to do things,” said Ron Holsey, general manager for automatization and optimization for GE Oil & Gas.
One of GE Oil & Gas’s most active partners in cutting costs is Statoil. Using a concept the company calls “the perfect well,” Statoil collects data from its own wells and those of partners and competitors and then holds seminars for its employees to determine which drilling and fracking techniques work best.
Statoil is testing new ways to drill and complete wells more efficiently, including replacing diesel for power with natural gas coming from the same field. It is also testing ways to reduce shipments of sand and water in hydraulic fracturing that break and keep open fissures in shale rocks so oil can ooze out. One way is to use bubbly liquefied carbon dioxide to replace some of the water in hydraulic fracturing, a technique Statoil will test this summer in North Dakota.
“These things we are working on are everlasting,” said Bill Maloney, the Statoil executive vice president in charge of development and production in North America, “because the perfect well doesn’t go away when the price of oil goes back up.”
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