American Oil and Gas Reporter - October 2015 - 72

Encana has employed to improve production is using gas lift as its primary artificial lift method. "We have increased base
production by 1,500 barrels a day by injecting gas," he states. "We have to compress the gas and inject it down the backside of the wellbore. It mixes with the
heavier fluids to improve efficiency."
Encana indicates it also has introduced plunger lift to the Eagle Ford play.
The company has brought in a crew from
the Piceance Basin, where plunger lift has
a long history as an effective method of artificial lift, he details. Since then, he reports, base production has increased in conjunction with the application of gas lift.
Honing The Approach
According to Balmer, Encana's ongoing quest to improve efficiency extends far
beyond better artificial lift. An example he
cites is the extent to which the company
has trimmed cycle time. Although spudto-rig-release once required 15-17 days,
Encana now can achieve that consistently in only 12, and has drilled one well in
only 10 days.
He adds that Encana also has learned
much from its stimulation experiments that
have sought to determine the ideal proportion of sand, water and pressure. "We have
found that moving clusters more closely
together makes better wells," he reveals.
"It is not necessary to use three times as
much sand. We are learning as we go."
Under the formula it is employing
now, Encana has decreased cluster spacing to closer than 50 feet, Balmer reports.
He goes on to note that some areas of the
Eagle Ford offer the challenge of faults that
may cause the zone to immediately drop
as much as 50 feet. He says the company
meets that challenge by predicting fault lo-

cations with geosteering. "We have been
able to keep wells in the pay through the
length of the lateral," he continues. "The
directional drillers and the geoscientists in
our office work hand-in-hand. We have not
shot a ton of seismic, so we simply have
to adjust on the fly in areas with faults."
Although its completions have used as
much as 3,500-4,000 pounds of proppant
a foot, Balmer says Encana may have
found a sweet spot at 2,000 pounds/foot.
"When we took over the program, our
drilling and completion cost was $7.5 million a well," he details. "Now, our target
is $5.6 million a well."
He explains that Encana's laterals average 5,000 feet and 25 fracture stages, although he contends the company has
made stellar wells with shorter laterals. He
says the company continues to experiment
with different designs, tweaking components such as sand volumes and stage spacing to identify trends.
Acreage Characteristics
Balmer describes the area in which Encana is operating as the "volatile oil window." To the southeast of its leasehold,
wells make more gas, producing about 85
percent liquids (crude oil and NGLs) and
15 percent gas, he points out. He says the
Graben area on the northwest side of its
leasehold is structurally complex and features more faulting.
As for estimating Encana wells' EURs,
Balmer suggests it is too early because Encana only has begun infill drilling. He indicates the best wells' average 800,000
boe, but output for wells in the Graben area
could be more challenging.
In its second-quarter report, Encana reported that it had reduced drilling and completion costs almost 30 percent and predict-

Encana's Patton Trust South facility provides processing for 32 Eagle Ford wells, 17 of
which were put on production in 2015. The company says an expansion has increased
the facility's oil processing capacity from 3,500 barrels a day to 20,000 bbl/d; its natural gas capacity is 50 million cubic feet a day.

72 THE AMERICAN OIL & GAS REPORTER

ed its total Eagle Ford production soon
would exceed 50,000 boe/d, a 15 percent
leap from third quarter 2014. The company also announced that its undrilled well
inventory stood at more than 600 locations,
a 70 percent increase since Encana acquired the asset.
Despite low commodity prices, Balmer
contends the creativity that permeates
the oil and gas industry will find a way to
make the Eagle Ford even more profitable.
"We can do it at $40," he assesses. "Necessity is the mother of invention. If the
price is $40 a barrel, we will find a way
to drill and complete wells to be profitable.
If the price drops, we will find a way to do
it even more cheaply. We have been able
to chop $2 million off our well costs in
only one year. The revolution of the oil
patch is fantastic, and the additional technology is pretty amazing." ❒

New Gulf Resources Has
Promising Well Results

TULSA-New Gulf Resources LLC
has announced results from its Buda-Rose
project in Texas.
NGR confirms that it owns and operates more than 53,000 net acres and
1,000 drilling locations prospective for
Buda-Rose in Madison, Grimes and
Walker counties, Tx. Additionally, it is
drilling vertical wells that commingle production from up to five zones.
The company says its Six Shooter well
in Madison County resulted in a 30-day
average production in excess of 473 barrels of oil equivalent a day from the commingled lower Cretaceous Buda, Georgetown, Edwards, and Glen Rose formations.
In addition, NGR notes its Iron Duke
well produced 595 boe/d in its initial 24hour commingled production test from
only the Buda and Georgetown formations.
"We are seeing contributions from
multiple lower Cretaceous zones in each
of our wells while lowering our costs,"
suggests Chairman and Chief Executive
Officer Ralph Hill.
The company says its most recent
vertical well was drilled to approximately 11,000 feet in fewer than seven days.
NGR is running one rig in the Buda-Rose
play.
"We have studied and tested individual
zones across our acreage, and we now can
optimize a manufacturing approach at the
appropriate time," Hill states. "Additionally, we are analyzing which zones we can
drill horizontally, which should enhance the
value of our position materially."
❒

American Oil and Gas Reporter - October 2015

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