| HOUSTON, June 28
HOUSTON, June 28 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
"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
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
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:
EFFICIENT AND COST-EFFECTIVE
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
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.