American Oil and Gas Reporter - October 2019 - 56

SpecialReport

Father of the Wolfberry
where economics are better, many operators can make money
in a ~$40/bbl price environment. In the fringe, we need prices
in the range of $50-$60/bbl.
I expect the majors will be occupied for several years
developing the shale plays, whereas conventional reservoirs,
ROZ plays and waterfloods may be part of the niche for independents that choose to forgo buyouts.
The amount of associated gas production will continue to
climb as we drill more oil wells; whether anyone will buy it is
another question. But, of course, if there are buyers for the gas,
it will help the economics of each oil well and lead to more
wells being drilled.

Fifty years ago, Jim Henry cofounded the predecessor to Henry
Resources. From day one, the company focused on drilling
Spraberry wells in the Midland Basin. Henry is shown here in
2000 receiving an award from the Permian Basin Petroleum Association, which he had served as president. Presenting the
award is Steve Castle, who proceeded Henry as PBPA president
and was president of the 2018 Permian Basin International Oil
Show, which had recognized Henry as PBIOS Honoree in 2014.

growth? Where does the smaller independent fit in? What
kinds of projects will they target?
HENRY: Small independent oil companies don't have the
huge financial resources required to develop these unconventional
reservoirs. But, of course, the majors do. In my opinion, the
majors will likely buy out most of the small and medium-sized
independents in these horizontal resource plays and will develop
these reserves at a faster pace than the independents could have.
But I will add that there will be a niche for small independents
that can maintain moderate capital budgets. Namely, these companies will be able to efficiently and effectively develop pieces
of acreage that are smaller and more isolated in a way that the
majors never could. Moreover, the independents that do will be
bought out and are surely in for windfalls.

Permian oil production has grown from less than 1
million barrels a day to nearly 5 MMbbl/d in the
span of only five or six years. What do you expect the trend
line to look like for oil production during the next five years?
Do you expect oil production in the Delaware and Midland
basins to peak anytime soon? What role will conventional
reservoirs and residual oil zones play in the production
picture going forward? How about associated natural gas
and NGL production?
HENRY: Well, of course, no one knows what will happen
with production, but we all can speculate. I think it is reasonable
that, perhaps, Permian Basin oil production will increase at
about 5% annually during the next three years, and then begin
increasing at the rate of 10% or so for the next few years after
that. I don't see a peak any time soon because there is a huge
number of locations that can be drilled and completed economically
at an oil price of $50 a barrel. In fact, in the heart of the play
56 THE AMERICAN OIL & GAS REPORTER

As a follow-up, what does the general profile of a
Permian barrel of oil look like today compared with
10 years ago? If Permian oil production is getting noticeably
lighter, what are the implications for operators? What does
it mean to downstream markets?
HENRY: The API gravity of the "average" Permian barrel
certainly has changed over the past 10 years. Fifteen years ago,
the majority of Permian barrels were sour with an API gravity
around 32 degrees. Today the average Permian barrel is sweet
and certainly much lighter with an average API gravity greater
than 40 degrees. These barrels are not as light or as high gravity
as natural gas liquids, but are much more like NGLs than the
barrels produced 10-15 years ago.
As far as the impact on producers, we will likely take larger
and larger deductions to the market prices as we stretch the
downstream markets to take lighter barrels. The impact on the
downstream markets has been, and will continue to be, capital
modifications to take these lighter barrels.

Data from the U.S. Energy Information Administration
shows that Permian new-well productivity climbed
from 315 bbl/d per rig in July 2015 to 607 bbl/d per rig in
July 2017 to 672 bbl/d per rig in July 2019. However, there
has been speculation that average well productivities may be
starting to decline. How do you see well productivities trending
across the basin?
HENRY: There is a concerted effort by all the Permian
Basin operators to improve the productivity of each well they
drill and complete, by means ranging from greater well spacing,
less time between "parent" and "child" well development, and
improved completion designs (e.g., increased sand per foot and
decreased inter-cluster spacing). This sort of tweaking will
continue until the optimal reserves per well is attained. However,
it must be noted that some of these practices, particularly
increased well spacing, may result in fewer total wells being
drilled even while yielding greater reserves per well.
I also will point out the interesting fact that, much more so
than in times past, many operators are now quite willing to
share data with other operators. The whole industry is benefitting
from what would have been private knowledge. This sharing
has obvious benefits for well productivities.

Part of the increased well productivities can be
attributed to longer laterals. The perforated lateral
lengths of new Permian horizontals averaged 8,500 feet in

American Oil and Gas Reporter - October 2019

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