Re-fracking brings 'vintage' oil and gas wells back to life
WILLISTON, N.D. – A fracking boom isn’t enough for U.S. oil and gas producers – they’re now starting the re-fracking boom.
The development highlights how producers must constantly invest and tinker, both to raise overall oil recovery rates that can be as low as 5 percent and to limit steep drops in production suffered by wells drilled into tight oil deposits.
Canada’s Encana Corp. invested $2 million to re-frack two wells in Louisiana’s Haynesville shale formation earlier this year, after seeing its production in the area dip
27 percent from 2012 levels.
“There were a significant number of wells that we considered unstimulated,” said David Martinez, Encana’s senior manager for Haynesville development.
Using minuscule plastic balls – known as diverting agents – pumped at high speeds with water into the old wells, most of which are 3 to 5 years old, Encana blocked some of the older fractures, or cracks.
“The thought is that the diverting agent will go to the cracks with the least amount of pressure,” bypassing cracks with higher pressure and boosting the pressure of the entire well so output climbs, Martinez said.
He said the process can’t be as precisely controlled as an initial round of hydraulic fracturing, in which water, chemicals and sand are blasted into rock to unlock oil and gas.
Fracking has been used on about 1 million wells bored since 2007, and oil and gas companies now fracture as many as 35,000 wells each year, according to FracFocus, the national fracking chemical registry.
Re-fracking cost Encana about $1 million per well, compared with about
$12 million for wells it drilled in 2012. Encana is no longer drilling new wells in the Haynesville formation, executives said.
Since it isn’t clear how long the benefits of a re-fracking last, Encana plans to collect more data when it re-fracks five more Haynesville wells this quarter, Martinez said.
If those prove fruitful, it may consider expanding the practice to its holdings in the Denver-Julesburg Basin of Colorado and the Eagle Ford formation in Texas.
Another Haynesville operator, Dallas-based Exco Resources Inc., said it boosted output from a 2010 re-fracked test well by 1.3 million cubic feet of gas per day. It didn’t say how much gas it was producing before the re-fracking. Average initial production from new wells Exco drilled in the second quarter was 12.9 million cubic feet per day.
Some of Exco’s Haynesville wells after four years were producing about a fifth of what they did in their first year, with output declining 69 percent that first year alone, according to the company.
Exco believes the technology can be applied to 400 of its so-called “vintage” wells that were drilled several years ago using what is now outdated technology.
The company is planning a re-fracking campaign for 2015, Hal Hickey, Exco’s president, told investors on a July 30 conference call.
“We’ve been at the forefront” in the Haynesville formation, he said.
Bakken bearing out
Marathon Oil Corp. is now targeting some of its older wells in the Bakken field in North Dakota and using the latest technology, including re-fracturing, to increase crude output.
Marathon owns or has a stake in about 2,300 wells in the Bakken, though it won’t say how many wells are in production.
When horizontal drilling was just starting to take off in the Bakken in 2007 and 2008, “(well) completion technology was quite different than it is today,” said Lance Robertson, Marathon Oil’s vice president of North American production operations.
For example, some early Bakken wells were readied for production by using a single frack stage, or a single section that creates multiple fissures in rock, and about half a million pounds of sand. Now, companies use an average of 30 to 35 frack stages and as much as 6 million pounds of sand per well, Robertson said.
“We go back in and use the best available technology,” Robertson said in an interview.
Marathon’s re-fracked wells have so far exceeded the company’s expectations, delivering returns that are large enough to merit additional investment, the company said.
About 100 of Marathon’s Bakken wells are good candidates to be fracked for a second time, executives said.
So far, re-fracking has not prompted companies to book higher reserves, said Allen Gilmer, chief executive of DrillingInfo, a well analytics company.
Marshall Watson, a petroleum engineering professor at Texas Tech University, cautions that re-fracking needs to be better understood before it becomes commonplace.
“Re-fracks can work in isolated cases,” Watson said. “Sometimes they do, and sometimes they don’t.”
Yet, as re-fracking gets fresh attention, concern lingers about disposal of frack wastewater, particularly in areas that suffer from drought.
In Colorado, home of the Denver-Julesburg Basin, where almost 2,900 wells have been developed since 2011, water demand for hydraulic fracturing is forecast to double to 6 billion gallons by 2015, more than twice the annual use of the city of Boulder, according to Ceres, a nonprofit group that tracks environmental records of publicly traded companies.
“It sort of shows how much we don’t know about fracking and why it fails sometimes,” said Andrew Logan, the director of the oil and gas program at Ceres. “This has the potential to severely stress water supplies beyond even currently strained levels.”
The oil industry, however, says the effects of fracking are known and don’t pose a danger.
“Hydraulic fracturing is a safe, proven technology that has been used for over 60 years to increase production of oil and natural gas – changing America’s energy trajectory from scarcity to abundance,” said Zachary Cikanek, a spokesman for the American Petroleum Institute in Washington.
For now, the energy industry is hoping this initial bump in the number of wells re-fracked presages a fresh boom, whereby unconventional wells are given a jump-start every few years to keep oil and gas – and profits – flowing.