The shale industry faces an uncertain future as drillers try to outrun the treadmill of precipitous well declines.
For years, companies have deployed an array of drilling techniques to extract more oil and gas out of their wells, steadily intensifying each stage of the operation. Longer laterals, more water, more frac sand, closer spacing of wells – pushing each of these to their limits, for the most part, led to more production. Higher output allowed the industry to outpace the infamous decline rates from shale wells.
In fact, since 2012, average lateral lengths have increased 44 percent to over 7,000 feet and the volume of water used in drilling has surged more than 250 percent, according to a new report for the Post Carbon Institute. Taken together, longer laterals and more prodigious use of water and sand means that a well drilled in 2018 can reach 2.6 times as much reservoir rock as a well drilled in 2012, the report says.
That sounds impressive, but the industry may simply be frontloading production. The suite of drilling techniques “have lowered costs and allowed the resource to be extracted with fewer wells, but have not significantly increased the ultimate recoverable resource,” J. David Hughes, an earth scientist, and author of the Post Carbon report, warned. Technological improvements “don’t change the fundamental characteristics of shale production, they only speed up the boom-to-bust life cycle,” he said.
For a while, there was enough acreage to allow for a blistering growth rate, but the boom days eventually have to come to an end. There are already some signs of strain in the shale patch, where intensification of drilling techniques has begun to see diminishing returns. Putting wells too close together can lead to less reservoir pressure, reducing overall production. The industry is only now reckoning with this so-called “parent-child” well interference problem. Also, more water and more sand and longer laterals all have their limits. Last year, major shale gas driller EQT drilled a lateral that exceeded 18,000 feet. The company boasted that it would continue to ratchet up the length to as long as 20,000 feet. But EQT quickly found out that it had problems when it exceeded 15,000 feet. “The decision to drill some of the longest horizontal wells ever in shale rocks turned into a costly misstep costing hundreds of millions of dollars,” the Wall Street Journal reported earlier this year.
Ultimately, precipitous decline rates mean that huge volumes of capital are needed just to keep output from declining. In 2018, the industry spent $70 billion on drilling 9,975 wells, according to Hughes, with $54 billion going specifically to oil. “Of the $54 billion spent on tight oil plays in 2018, 70% served to offset field declines and 30% to increase production,” Hughes wrote.
As the shale play matures, the field gets crowded, the sweet spots are all drilled, and some of these operational problems begin to mushroom. “Declining well productivity in some plays, despite application of better technology, are a prelude to what will eventually happen in all plays: production will fall as costs rise,” Hughes said. “Assuming shale production can grow forever based on ever-improving technology is a mistake—geology will ultimately dictate the costs and quantity of resources that can be recovered.”
There are already examples of this scenario unfolding. The Eagle Ford and Bakken, for instance, are both “mature plays,” Hughes argues, in which the best acreage has been picked over. Better technology and an intensification of drilling techniques have arrested decline, and even led to a renewed increase in production. But ultimate recovery won’t be any higher; drilling techniques merely allow “the play to be drained with fewer wells,” Hughes said. And in the case of the Eagle Ford, “there appears to be significant deterioration in longer-term well productivity through overcrowding of wells in sweet spots, resulting in well interference and/or drilling in more marginal areas that are outside of sweet-spots within counties.”
In other words, a more aggressive drilling approach just frontloads production, and leads to exhaustion sooner. “Technology improvements appear to have hit the law of diminishing returns in terms of increasing production—they cannot reverse the realities of over-crowded wells and geology,” Hughes said.
The story is not all that different in the Permian, save for the much higher levels of spending and drilling. Post Carbon estimates that it the Permian requires 2,121 new wells each year just to keep production flat, and in 2018 the industry drilled 4,133 wells, leading to a big jump in output. At such frenzied levels of drilling, the Permian could continue to see production growth in the years ahead, but the steady increase in water and frac sand “have reached their limits.” As a result, “declining well productivity as sweet-spots are exhausted will require higher drilling rates and expenditures in the future to maintain growth and offset field decline,” Hughes warned.