(John Kemp is a Reuters market analyst. The views expressed are
By John Kemp
LONDON Aug 29 Doubts about the sustainability
of the North American oil and gas boom centre on rapidly
declining output from many shale wells after they are initially
Shale sceptics point to the need to drill an ever-increasing
number of new holes just to replace the declining output from
existing wells, let alone expand production. At some point it
will become impossible to keep up, they argue.
The problem has been likened to the Red Queen's Race in
Lewis Carroll's "Through the Looking-Glass" where the chess
piece warns Alice that "it takes all the running you can do,
just to keep in the same place".
Geologists have worried about the problem of replacing
declining output from old wells for more than a century. U.S.
geologist Carl Beal voiced concern that the "limit of production
in this country is being approached" as long ago as 1919.
"Although new fields undoubtedly await discovery," he wrote,
"the yearly output must inevitably decline, because the
maintenance of a given output each year necessitates the
drilling of an increasing number of wells."
"Such an increase becomes impossible after a certain point
is reached, not only because of a lack of acreage to be drilled,
but because of the great number of wells that will ultimately
have to be drilled," Beal explained in a careful monograph for
the U.S. Bureau of Mines on the "Decline and Ultimate Production
of Oil Wells".
Shale's doubters point to the faster decline rates on
horizontally drilled and fractured wells bored into shale
compared with conventional wells drilled into more-permeable
reservoirs to suggest the replacement problem is much worse for
unconventional oil and gas plays.
But there are plenty of reasons to think the focus on
decline rates is misplaced and is unlikely to constrain North
American oil and gas output in the next decade.
First, oil and gas producers have learned to drill and
fracture wells much faster, using mass production techniques
borrowed from manufacturing, so the same number of rigs and
crews can drill many more wells than before.
Second, the sceptics focus too much on the decline rate
rather than the total amount of oil and gas recovered from a
well over its lifetime, which is more relevant to the
sustainability of the shale revolution.
The relationship between initial production (IP), the
decline rate (DR), and the estimated ultimate recovery (EUR) is
subject to tremendous uncertainty. It varies significantly from
play to play, county to county and even well to well.
But in general, producers want oil and gas wells with a
large EUR and high IP, because that means they receive more
revenue overall, and more of it in the first few months after
the well is completed rather than having to wait for years.
Wells cost millions of dollars to drill and fracture, and
all the costs must be paid up front, either by the producer
using their own funds or with borrowed money. The faster the oil
and gas are produced, the faster the costs are covered and the
more profitable the well will be.
WELL DECLINE CURVES
From a financial standpoint, rapid decline rates are not a
problem. What matters is the EUR. But the relationship between
IP, decline rate and EUR is fairly loose and notoriously
difficult to pin down.
There is some evidence to suggest oil and gas wells that
have high initial flow rates tend to decline fastest but yield
the most oil and gas over their lifetime.
"In general, wells of small initial yearly production
decline more slowly than those of large," Beal said of
conventional fields. But the more barrels per day a well
produced in its first year of production, the more it was likely
to produce during its lifetime.
Still, it remains notoriously tricky to predict ultimate
production accurately from initial flow rates because there is
so much variability and the data is not readily available.
(There is a clear data availability bias in much of the
published research. Most analysis uses commonly available data
on the total number of wells and average daily production for
large aggregates, such as whole states, and then tries to draw
conclusions about the sustainability of shale production, even
though such numbers are not really relevant.)
For individual wells and plays, forecasters use "decline
curves" based on the average of past experience to estimate how
much oil and gas a well might eventually produce.
Even so, the forecasts can be out by a wide margin.
"Estimates of future production based on the first few months of
initial production can differ significantly from later estimates
for the same well," according to the U.S. Energy Information
For example, one well examined by the EIA was predicted
ultimately to yield 574,000 barrels of oil based on the first
year of monthly production data, but that was later slashed to
just 189,000 barrels once four years of data was available.
In another case, an initial EUR of 105,000 barrels based on
12 months of production data was raised to 224,000 barrels based
on four years of data.
In general, however, it is possible to make a reasonably
stable and accurate forecast of EUR after about three years,
when almost all wells will have produced more than half their
eventual output, according to the EIA ("U.S. tight oil
production: alternative supply projections and an overview of
the EIA's analysis of well-level data", April 2014).
There is plenty of evidence that oil and gas production
companies are improving productivity and extracting more oil and
gas from each shale well.
The EIA analysed EURs from more than 5,000 wells drilled
into the Eagle Ford shale formation in Texas . The average EUR
was almost 170,000 barrels, but it has been rising, with wells
drilled in 2012 (191,000 barrels) and 2013 (169,000 barrels) far
more productive than wells drilled near the start of the play in
2009 (57,000 barrels) and 2010 (117,000 barrels).
There is enormous variability in the play, with wells in
DeWitt county expected to average 334,000 barrels compared with
226,000 in Karnes and 80,000 in Webb. Even in DeWitt, EUR varies
from 98,000 barrels (25th percentile) to 440,000 (75th
But across the United States there is a clear trend of
rising average EUR from shale wells.
Productivity improvements can be traced to several factors.
Shale producers are drilling and fracking longer laterals,
increasing the amount of shale accessed by each well.
Through a combination of trial-and-error and better seismic
work, drillers are increasingly able to target the
highest-yielding parts of shale plays, improving average
recovery factors and minimising the cost of drilling subpar
Other productivity improvements are in the pipeline. In most
sedimentary basins, including North Dakota's Bakken and west
Texas's Permian, there are multiple oil- and gas-bearing
formations, layered one on top of another like a stack of
pancakes. The most advanced drillers are experimenting with
wells that have several laterals at different depths to produce
from different formations all from the same surface hole.
Well-spacing is another area where improvements are being
tried. Minimum spacing is set to ensure two wells do not
communicate with one another underground (drain the same part of
the formation). But the minimum gap between wells is being
reduced to cover the whole shale formation more completely as
producers learn more about how big an area each well drains.
Individual shale wells are therefore becoming more
productive, and plays are being exploited more efficiently and
completely. And there are good reasons to think that the shale
revolution is still in its infancy, with scope for further
efficiency as current best practice is applied more widely.
There are also plenty of other shale plays in the United
States, and internationally, with subtly different geology,
which makes them harder to produce at present, but which might
be brought into successful production with comparatively minor
For all these reasons, the shale boom is not about to bust
any time soon. As long as the oil is needed, and prices remain
fairly high, shale production is set to grow.
(Editing by Dale Hudson)