American Oil and Gas Reporter - October 2019 - 43

Maximizing Recovery
Frank Bracken III is chief executive
officer of Fort Worth-based Lonestar Resources Inc., a pure Eagle Ford player. He
says his company is concentrating on
maximizing hydrocarbon recovery per
foot of lateral utilizing petrophysics and
engineered completion designs.
"We use lots of petrophysics and geophysical analysis to land the drill bit in a
specific target to maximize reservoir
properties," he explains. "We do a lot of
advanced log analysis. In fact, we run
logs to the total depth after we drill to design our fracturing treatments. That is
unique in the industry."
He claims operational experience also
is important in optimizing well results,
pointing out that Lonestar has been involved in the Eagle Ford since 2012. "We
think the Eagle Ford is exceptional rock,"
Bracken notes. "The Eagle Ford is unique
among unconventional shale plays in that
it was pioneered and developed in a $100
oil price environment. Companies could
put in wells, not focus on improving well
results, yet still make very high returns.
Like any unconventional play, there was
a huge land grab when the Eagle Ford
first took off. The industry was trying to
hold as much as acreage as possible by
production as fast as possible."
That approach does not lend itself to
developing best practices, Bracken notes.
"Best practices evolve more slowly. We
can use information from the earlier wells
that were drilled and de-risk our activity.
There is no need for us to rush development to hold acreage by production, and
competition is relatively low in the Eagle
Ford today compared with when we were
getting started in the play."
Bracken says Lonestar Resources' operational activities encompass 11 Texas
counties, which it divides into three distinct
regions: the western Eagle Ford (Dimmit,
La Salle and Frio counties), central Eagle
Ford (Gonzales, Karnes, Fayette, Wilson,
DeWitt and Lavaca counties) and eastern
Eagle Ford (Brazos and Robertson counties). However, Bracken says Lonestar intends to sharpen its focus on its
highest-graded assets and divest of its eastern Eagle Ford position by year's end.
"The eastern Eagle Ford wells are good,
but they do not compete with some of the
wells in our western and central regions,"
he says. "We want to keep our attention on
the areas where we get the best returns."
Lonestar operates 85% of its Eagle

Ford position, and approximately 95% of
its acreage is held by production,
Bracken notes.
"Spacing varies widely from one area
to the other, ranging from 400 feet in DeWitt and Karnes counties to up to 700
feet in La Salle County," he maintains.
"We can review the historical well spacing and correlate ultimate recoveries. We
have an abundance of well data, and
again, we do a lot of rock analysis, which
helps us optimize spacing."
The majority of Lonestar's wells
today have 10,000-12,000 foot laterals
and generally are completed with ±300foot frac stage intervals. "We have really
focused on acquiring acreage in geometries that allow us to drill long laterals.
There is a lot better rate of return on the
extended laterals," Bracken explains. "As
far as completions, everything we do is
custom designed. We take a technically
informed view when we tailor our completions specific to what the logs tell us."
Increased Production
Lonestar Resources reported a 22%
increase in net oil and gas production to
13,630 barrels of oil equivalent a day during the second quarter, and that climbed
to 16,000 boe/d in July thanks to its new
Horned Frog and Sooner assets. Production was 78% crude oil and NGLs on an
equivalent basis.
In its western region, Lonestar's
newest wells on its 4,975-acre Horned
Frog South property represent continued
progress in the advancement of its geoengineered completion practices, according to Bracken.
"On a per-foot basis through the first
30 days, our 2019 wells have recorded
production rates that are 20% higher than
our initial pad at Horned Frog, the
Horned Frog Nos. A1H and B1H (completed in 2015) and 7% higher than our
most recent Horned Frog wells, the
Horned Frog G1H and H1H (completed
in 2018)," the company reported in its
second-quarter earnings report. "Our
2019 Horned Frog wells recorded maximum 30-day rates that eclipsed 200 boe/d
per foot, and are registering oil production rates that are 17% better than our
2018 completions on a per-foot basis."
Bracken reports that the company
began flowback operations on two wells
in June in its western region. The Horned
Frog F 1AH, with a 12,461-foot perforated interval, recorded a maximum 30-

day production rate of 549 bbl/d of oil per
day, 674 bbl/d of NGLs and 7,283 Mcf/d
of gas (2,436 boe/d on a three-stream
basis). The Horned Frog F 61H has a
12,170-foot perforated lateral and a maximum 30-day production rate of 578
bbl/d of oil, 74 bbl/d of NGLs and 7,605
Mcf/d of gas (2,550 boe/d).
In Karnes County in its central region,
Lonestar's four Georg 3H-6H wells delivered average maximum initial production
rates of 1,045 boe/d, he goes on. Those
four wells follow six wells that Lonestar
placed on stream in 2018. The four wells
this year had increased lateral lengths of
18% compared with the 2018 wells and
outperformed the type curve by 19%.
Lonestar Resources also began flowback operations on three wells on its
Sooner property in DeWitt County, which
it acquired last November. The Buckhorn
No. 4H, which has 6,157 perforated feet,
tested at 542 bbl/d oil, 1,311 bbl/d NGLs
and 9,857 Mcf/d gas (3,496 boe/d) on a
24/64-inch choke. The Buckhorn 5H
(5,981-foot lateral) tested at 3,333 boe/d
on a 22/64-inch choke and the Buckhorn
6H (6,021-foot lateral) tested at 3,549
boe/d on a 22/64-inch choke.
"We have built a fairly substantial position in the core of the Eagle Ford, and
we have built the infrastructure," Bracken
maintains. "We believe we will continue
to be dominant in the Eagle Ford. Scale
and success breeds more of the same."
Eagle Ford Entry
Houston-based Callon Petroleum Company has been a pure Permian Basin operator, with activity in both the Midland and
Delaware sub-basins, but will be adding
the Eagle Ford Shale play to its portfolio
soon. Callon announced in July that it has
reached a definitive agreement to acquire
Carrizo Oil & Gas in an all-stock transaction
valued at $3.2 billion. The deal is expected
to close in the fourth quarter.
"We are excited about this transformational transaction, creating a differentiated oil and gas company by integrating
core asset bases in premier basins," Callon
President and Chief Executive Officer
Joe Gatto says. "Together with Carrizo,
we will accelerate our free cash flow,
capital efficiency and deleveraging goals
through an optimized model of largescale development across the portfolio.
We will also benefit from leading cash
margins to navigate commodity price
volatility and allow for reliable, continuous
OCTOBER 2019 43

American Oil and Gas Reporter - October 2019

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