From The Wall Street Journal

Shale companies from Texas to North Dakota have been managing their wells to maximize short-term oil production. That has long-term consequences for the future of the American energy boom.

By front-loading the wells to boost early oil output, many companies have been able to accelerate growth. But these newer wells peter out more quickly, so companies have to drill new ones sooner to sustain their production.

In effect, frackers have jumped on a treadmill and ratcheted up the speed, becoming ever more dependent on new capital to keep oil production humming, even as Wall Street is becoming more skeptical of funding the industry.

The emphasis on maximizing early oil output, largely by small and midsize shale drillers, contrasts sharply with how big oil companies such as Chevron Corp. and Exxon Mobil Corp.are seeking to develop some of the same areas.

“You don’t try to grow production fast,” Chevron Chief Executive Mike Wirth said in a recent interview. “You really look at the entire life cycle of the asset.”

Though most shale companies have yet to consistently generate more cash than they spend, their rapid expansion has turned the U.S. into the world’s largest oil producer. That growth has begun to slow, however. U.S. production fell slightly to 11.87 million barrels a day in January, from 11.96 million barrels a day in December, after rising steadily for much of last year, according to the Energy Information Administration.

Chevron announced plans last month to more than double its production to 900,000 barrels of oil and gas a day in the Permian Basin of West Texas and New Mexico over the next five years. Exxon said it expects its output in the oil field to reach one million barrels of oil and gas daily as soon as 2024. But the companies say they are doing so patiently, with an eye toward extracting more oil over the life of the wells.

Neil Chapman, who oversees Exxon’s exploration and production business, told investors last month that Exxon is trying to be systematic about extracting the most it can from its acreage.

“There is a certain amount of energy in this reservoir, and when you drill them up, that energy starts to dissipate,” Mr. Chapman said.

Another side effect of front-loaded wells: They are unleashing enormous amounts of natural gas. That’s because gas escapes more easily than oil from underground reservoirs as pressure falls.

Gas production in the two largest U.S. oil fields, in Texas and North Dakota, grew 43% from January 2018 to the same period this year as oil output grew 35%, according to EIA data. There isn’t enough pipeline capacity to bring all of that fuel to market, so companies in West Texas effectively have had to pay people to take it away. Prices at the Waha trading hub fell to a record average low of negative $5.25 per million British thermal units for gas that flowed on Thursday, with some gas sold for as little as negative $9, according to S&P Global Platts.

Large quantities are also going up in smoke, as companies burn gas they cannot move or sell, a practice known as flaring. Operators in the Permian and North Dakota burned more than 1 billion cubic feet of gas daily in October, according to public data and Rystad Energy. The resulting greenhouse-gas emissions are equivalent to the daily exhaust from about 6.9 million cars, according to estimates from the World Bank and Environmental Protection Agency.

Many wells are producing more oil overall than those of a few years ago, thanks to improved techniques and technology. But in some cases, newer wells are producing more gas and less oil than wells drilled just a few years earlier, or than companies anticipated.

Because oil is more valuable than gas, the shift in the gas-oil ratio means that these wells are less profitable. Higher gas production paired with lower oil output also can be a sign of fatigue, symptomatic of lowered pressure in an overall subsurface pool or reservoir.

In the Williston Basin, which extends into North Dakota and Montana, newer wells drilled by EOG Resources Inc. are producing less oil and more gas than their predecessors, according to data from ShaleProfile, an industry analytics platform. The company’s wells there that began producing in 2013 generated an average of about 227,000 barrels of oil in their first year. At that point, they were producing on average 1,122 cubic feet of gas for every barrel of oil.

Wells in the same area that began producing four years later generated an average of roughly 134,000 barrels of oil in their first year, a 41% decline, data show. Meanwhile, the ratio of gas to oil produced climbed to an average of 2,027 cubic feet of gas for every barrel of oil.

EOG said it wasn’t unexpected for well results in an area to vary year-to-year. “These performance factors are predictable,” a spokeswoman said.

In the Permian Basin, Laredo Petroleum Inc. expects to wring an average of 15% less oil and 13% more gas than previously forecast from its wells over five years, the company told investors in February.

Laredo is adjusting by increasing the space between its future wells, though doing so means it will have fewer overall locations to drill. The company didn’t respond to requests for comment.

While exploration and production companies are modifying their approach, Julie Francis, an analyst at energy consultancy Wood Mackenzie, said they face an uphill climb because of the increasingly rapid decline of their shale wells, likening the situation to trying to refill a leaky cup.

“They will have to invest more in order to grow,” she said.

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