American Oil and Gas Reporter - January 2016 - 39

Outlook 2016
the exact level of DUC wells. Estimates range from 3,000 to
5,000 wells, but most of that inventory was established way
before the oil slump began last summer.
The jump in DUC inventory started in 2013, when producers began to adopt pad drilling. With pad drilling, up to 10 wells
can be sitting behind each drilling rig, waiting to be completed. As the rig count rose, so too, did the normal inventory of
wells.
The DUC inventory has come down slowly with the lower
rig count, but half-if not more-of the total number of DUCs
will always be there. Of the other half, likely 30-50 percent
were drilled when prices were high and either missed the target reservoir (and will be abandoned) or were drilled as exploratory wells in "step-out" locations remote from any oil infrastructure (and will not be profitable until prices return to
much higher levels).
The remainder of the inventory, numbering only in the hundreds, is a direct result of the lower-price environment, where
producers have drilled wells, but are deferring their completion specifically to a later date when prices are higher.
Therefore, we do not believe there is a significant amount
of production sitting in inventory, waiting to come on line. Also,
it is unlikely that all companies will start eating into their DUC
backlogs at once, or that sufficient completion equipment and
crews will be activated overnight. Consequently, we do not believe there will be a "surge" in production because of this inventory when oil and gas prices recover.

After years of increasing well productivities, EIA statistics show a leveling in the amount of new-well oil
production per rig in tight oil plays. With operators deploying advanced well architectures and completion designs concentrated on high-graded sweet spots, why is productivity
plateauing? What are the big-picture implications, especially with year-to-year rig counts down more than 65 percent?
What decline rates do you expect to materialize in these plays?
QUINNELL: There are more established areas such as the
Bakken Shale, where it seems the industry has hit the top end
of productivity gains, and where it is becoming harder and
harder to improve efficiencies. Initial production rates have
leveled over the past several years and drilling days per well
have improved only marginally. However, operators in Permian Basin tight oil plays are still seeing significant increases in productivities as a result of the more recent uptick in
horizontal activity, which continues to yield higher initial production rates from new wells.
Also, Permian producers have moved to pad drilling more
recently, which is driving down drilling days, so we continue
to expect some increases in efficiencies in the Permian. This is
one reason we believe Permian production will remain relatively robust in 2016, compared with the Bakken and Eagle
Ford.
Shale-play decline rates are steep, and we believe they sometimes are an overlooked aspect of what will drive production
decreases with such a sharp decrease in rig activity. In 2008,
base production was declining at 15-20 percent. In 2014, that
had risen to almost 30 percent, even with oil rig counts of 1,400-

1,500 all year.
If no new drilling had occurred after reaching peak production in April 2015, U.S. oil production would be at 5.1 MMbbl/d
by the end of 2019 because of steep declines in shale plays erasing virtually all the growth we have seen over the past seven
years. With rig counts falling throughout 2015 to below 550 by
the end of the year, the longer rig counts stay low, the more impact decline rates in tight plays eventually will have on U.S. oil
production.

What have operators learned to date about the
break-even price in tight oil plays? Which plays appear to be the most economic at lower prices? What are the
prospects for increased conventional shallow vertical oil
drilling? How do the economics of conventional onshore vertical plays stack up against horizontal unconventional resource plays at lower oil prices?
QUINNELL: The biggest thing that producers have learned
about the break-even price is that they have been able to drive
it down and make the economics in certain areas work in this
low-price environment. Service and rig costs are down 30-40
percent since the start of the downturn, and this is helping drive
down break-even prices.
In addition, operators have continued to get more efficient by
driving down drilling days and increasing well productivities
through differentiated well completion techniques, and by highgrading to the best spots, which also are driving down breakeven prices. However, in a $40 a barrel price environment, there
are many plays and operators that are stressed. That is why we
continue to see decreased rig activity across the country.
In general, the economics of conventional vertical oil drilling
are subpar to unconventional resource plays. This clearly was
evident in the Permian Basin. When prices were $90-$100 a
barrel, there was a decent amount of vertical drilling. But as
prices dropped even into just the $80/bbl range, nearly all vertical drilling ceased. The break-even price for horizontal wells
in the Delaware Basin, which is in the western part of the Permian, range from $25 to $80 a barrel, while the economics of
vertical drilling in conventional geology in the Central Basin
Platform range between $60 and $90 a barrel.

Supply And Demand:
Growth Is Operative Word

Despite persistent low prices, EIA estimates annual domestic natural gas production increased 5.4
percent in 2015. In fact, EIA says production from shale plays
reached an all-time high of 45.6 billion cubic feet a day in
May. However, by late 2015, EIA models were projecting declining production in all major shale plays-the first time the
agency had forecast an across-the-board slide in shale gas
JANUARY 2016 39

American Oil and Gas Reporter - January 2016

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