American Oil and Gas Reporter - July 2016 - 60

SpecialReport: Horizontal & Innovative Drilling
rather than consulting out functions such
as directional drilling and mud or cement
engineering. Even before Purple Hayes, we
were the lowest-cost operator in the Utica. A big reason for that is the in-house
specialists we have in every facet of
drilling, completion and production. They
are outstanding."
Very Encouraging Results
Purple Hayes began producing on
May 3 after 24 hours of flowback. Through
early June, Hulburt reports production
from the choked-back well had remained
unchanged from its initial rate of 5
MMcf/d of gas and 1,200 bbl/d of condensate. Just as importantly, downhole pressures had not budged either.
"We are holding back production because we believe very strongly that tightly managing pressure drawdown achieves
better recoveries in Utica wells. We set the
initial production rate at a level we believed
would cause pressure to fall by 150 psi a
week. We are extremely happy to see basically no pressure decline and very constant production levels over the first
month," Hulburt reported in early June.
"Pressure and production have stayed almost perfectly flat, but water production
has fallen more rapidly than in other area
wells. Even the best wells show some pressure decline after a few weeks."
Chemical tracers indicate that all parts
of the lateral are contributing production.
"In the first two weeks, the toe was not
contributing, but it kicked in by the third
week," Hulburt observes. "It is early and
we will continue monitoring the tracer surveys, but that is very encouraging."
One of the difficulties in forecasting
Purple Hayes' production is that the lateral is so long it covers two type curves,
with the toe of the well in a heavier liquids
model. Consequently, Hulburt says
Eclipse's internal projections are based on
a weighted average of both type curves.
"Condensate yields typically drop by
60 THE AMERICAN OIL & GAS REPORTER

50 percent over the first 12 months in our
shorter-lateral offsets, but because this well
is so heavily choked, we expect less of a
drop in the gas-to-condensate ratio in the
first year," he reasons. "You eventually see
reduced condensate yields no matter what
you do, but the controlled pressure management should delay the decline onset."
In addition to the ultralong lateral, Purple Hayes is the first well to incorporate
all three variables in Eclipse's optimized
Utica completion design: 100-percent
slickwater, tighter stage spacing, and
managed pressure drawdown. "Our hope
is that Purple Hayes' EUR will be the same
as shorter-lateral offset wells at significantly lower cost per foot," Hulburt expresses. "Should the recovery factor end better
than our normal type curve assumptions,
it would be a result of the optimized frac
design."
Given the heavy condensate yields, offsets usually require artificial lift within 1824 months of production startup, depending on the degree of choking. Accordingly, Hulburt says valves were built into the
Purple Hayes completion to allow gas lift
to commence without having to re-enter
the lateral to conduct a workover.
The Next Phase
While still in the preliminary planning
stages, Hulburt reveals that Eclipse Resources' 2017 drilling program includes a
four-well pad with two laterals in excess
of 19,000 feet and two about 10,000 feet
long.
"That will give us a direct comparison
of recovery per foot using shorter versus
longer laterals," he explains. "We definitely anticipate drilling more superlaterals in
the condensate-rich area because the economics are so much better than shorter-lateral wells. There is no reason not to. It is
a greater amount of land work and planning, but we essentially get three wells for
the cost of two."
That implies the ability to replace

five-eight shorter laterals on each pad with
two-three superlaterals, but Hulburt acknowledges that constructing ultralong laterals introduces constraints in pad drilling.
"The length means we cannot have much
step-out. For example, we need to keep the
vertical section as straight as possible in
superlaterals, and cannot drill out 2,000
feet from a pad before making the horizontal turn, which often is done with shorter
laterals," he says. "In addition, we think
it is important to drill updip in the condensate area so liquids drain back toward the
vertical hole, which means all the wells
must go in the same direction."
While superlaterals may be applicable
to other shale plays, Hulburt says the economics are most compelling in areas
such as the Utica and Marcellus, where topography and population densities increase pad costs. "Pads cost $1.5 million$2.0 million in the liquids portion of the
Utica, and $2.5 million and up in the dry
gas portion," he remarks. "The vertical section also is relatively expensive. The ability to spread those costs over a longer
reservoir interval makes superlaterals
worthwhile. You could replicate this design in, say, the Permian Basin, but it
would not generate the same cost benefits
because you can build a pad there for
$100,000."
Longer term, Eclipse Resources is investigating the potential of creating "super-multilaterals" from the same vertical
pilot hole. "Multilateral drilling is the second phase of our Utica engineering project, and we have teams working on it. In
fact, we have engineering designs to drill
Utica multilaterals and think it is technically feasible," Hulburt concludes. "However, there are several aspects of a multilateral operation where you have a single
point of failure. That makes it much more
challenging. We do not yet have enough
redundancy in the design to move forward
with it, but it is the next step."
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American Oil and Gas Reporter - July 2016

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