HOUSTON, June 28 (Reuters) - In the remote Eagle Ford shale fields of South Texas, drillers racing to pump crude from new wells are finding themselves in a most unexpected line of work: the utility business.
Struggling to tap into a regional electricity grid built for small towns and vast cattle ranches, companies including Marathon Oil Corp are saving time by installing new power lines themselves. Despite the heavy initial outlays, the new lines will reduce power costs at some of the 5,000 wells drilled across the region.
Power sales into the Eagle Ford region have surged fourfold in the past two years, according to AEP Texas, a unit of American Electric Power, which operates high-voltage transmission lines and a distribution network across much of South Texas. Last year, demand for power increased by 373 megawatts, equivalent to nearly 400 new Walmart stores.
The boom arrived without warning as hydraulic fracturing and horizontal drilling allowed drillers to tap shale reserves, and it has transformed the rural landscape into a thriving hub of energy activity. Oil output has risen from nothing to 500,000 barrels per day in three years. Eagle Ford may top 1 million bpd next year, which would make it the country’s largest onshore oil source.
“We were never ready for that,” says Robert Knowles, an AEP Texas distribution engineer.
The current shortage is not of power supply, but insufficient access to the power grid. While a well can be drilled in less than 30 days, it can take more than six months for a utility to install the heavy-duty double-circuit 69-kilovolt, or larger 138-kv, lines needed to power big equipment.
In the interim, operators who want to get their wells pumping quickly use diesel- or gas-powered mobile generators that can cost three times as much to run. It’s a boon for companies such as Aggreko, the world’s biggest provider of portable generators, but a bane for drillers who crave a stable, cheap source of power.
Now some are taking matters into their own hands, paying as much as $150,000 a mile to install their own distribution lines.
In Oklahoma, SandRidge Energy Corp saved $100,000 per month per well after installing its own distribution lines, which allowed it to use electric submersible pumps that can bring about three times more fluid to the surface than similar natural gas-lift systems, former Chief Executive Tom Ward said in March.
Although power is less than 10 percent of total production costs, it’s an area ripe for savings as the shale revolution moves into a new phase, with the focus shifting from a mad scramble for acreage to cost controls and operating efficiency.
In 2008, fewer than 1 million people lived in the Eagle Ford area, which is about twice the size of Vermont. Counties were served by small, single-circuit 69-kv power lines and older substations. Electric demand was declining.
All that has changed since 2010, when companies such as EOG Resources Inc and ConocoPhillips descended on the region, bringing heavy trucks that strain rural roads and thousands of workers seeking temporary housing.
“The infrastructure across the board is under stress,” said Thomas Tunstall, director of a University of Texas at San Antonio (UTSA) economic research center.
Oil companies don’t need grid access to drill wells, since onsite generators are built into their rigs. Trucks that perform hydraulic fracturing - the injection of chemical-laced water and sand to break open shale rock to release oil and gas - also bring their own horsepower to drilling sites.
However, once a well is completed, power is needed to recover, or “lift,” oil and gas to the surface. In North Dakota’s Bakken shale oil patch, that demand ranges from 22 to 40 kilowatts per well site, according to a study on power use conducted last year by engineering firm KLJ.
In the Eagle Ford, utilities monitor the rig count as a harbinger of coming demand. The number of wells in the Eagle Ford is expected to reach 24,000 in 2022, according to a “moderate” growth forecast from UTSA.
More power is needed to separate crude from gas and to compress and transport the resource to market and for saltwater disposal wells. Gas also requires processing to separate the hydrocarbons before the dry gas is put into the pipeline system.
It adds up quickly. In the Bakken area, where rapid oil development began about a year earlier than in the Eagle Ford, power demand is expected to nearly double to 2,288 MW in the five years to 2017, according to the KLJ report. Growth is accelerating now as larger industrial projects are built.
“The well-load growth is pretty consistent, but in the next five years we’re expecting a significant build-out of oil transport infrastructure,” says KLJ consultant Mike Wamboldt.
The contrast in demand can be immense. A pair of 5,000-horsepower motors - equal to about 1 MW of power demand - may be required to serve a single pipeline pumping station in the Eagle Ford, a vital piece of equipment placed along the line to boost internal pressure and keep oil flowing.
“That’s the equivalent of building 10 Walmart stores in a town with a population of 1,500 people,” says AEP’s Knowles.
Shale oil output graphic:
The challenge in the Eagle Ford will not be quickly overcome. Even in the Bakken, about one in five oil wells were still not connected to the grid as of mid-2012, KLJ said.
To solve these issues, energy producers are working more closely with utilities than they have in the past.
Marathon said earlier this year that it has installed distribution lines on land it leases.
“This strategy provides us with more flexibility, higher reliability, lower long-term maintenance costs and less surface impact,” said Marathon spokeswoman Lee Warren.
Constructing such a line can cost from $80,000 to $150,000 per mile, according to an industry source. But producers typically are required to pay utilities for new distribution lines anyway.
EOG Resources - which was the No. 1 driller in the Eagle Ford last year, completing 800 wells - is working with several Eagle Ford electric cooperatives to better control costs for new power lines, an EOG spokeswoman, K Leonard, said.
Some companies are taking a different approach while waiting for electric power to reach their facilities.
Energy Transfer Partners installed a dual-drive, electric motor and natural-gas-fueled engine to supply 59,000 horsepower for a gas processing plant in Jackson County. The plant was able to operate initially on gas, allowing it to start up six months earlier than if it had waited for grid power, said David Coker, president of Energy Transfer Technologies of Dallas, which installed the equipment.
AEP Texas is installing mobile and skid-mounted substations to get more electricity to remote sites while it pares the time needed to plan and build permanent substations.
Meanwhile, business for companies like Aggreko is booming. The Glasgow, Scotland-based firm has opened two new service centers in Texas this year just to serve the industry.
“We can mobilize in a matter of hours, rather than weeks or months, or years that permanent power might take,” said Brian Fahnestock, Aggreko’s U.S. Mid-South general manager.