More Oil, More Water
How Produced Water Will Create
Big Cost Problems for Shale Operators
Trent Jacobs, JPT Senior Technology Writer
I
f crude prices, rig counts, and tight oil
production demonstrate a stronger
upward trend in the months to come,
US shale operators may find themselves
with more produced water than they bargained for.
The concern is that a surge of produced water could eat into profit margins even as oil prices improve by
driving up costs for hauling and disposal.
Many shale producers can ill afford a
significant spending hike on such services when, according to IHS Markit,
produced water management can represent half of a shale well’s operating expenses.
The severity of this issue will depend
on how aggressively shale producers
seek to rebound from the downturn by
drilling new wells. It also will depend on
how quickly they activate the estimated
4,000 oil-rich, drilled-but-uncompleted
wells (DUCs) that have amassed over the
past 2 years as both a cost-cutting and a
production management maneuver.
“If you get a lot of new completions
in a short amount of time, that means
you are going to get a whole bunch of
water too, and this is something that
the industry needs to be thinking about
and planning for,” said Piers Wells,
co-founder and chief executive offi-
cer of Digital H2O, a company that uses
analytics-based models to forecast oilfield water resources.
Because it is the most active and prolific shale play, the Permian Basin of
Texas is already under pressure. As
shown by Digital H2O’s model, the
recent uptick in drilling there and in the
adjacent Delaware Basin is yielding produced water volumes that are approaching what many of the disposal wells can
take away.
“While they may not be at full pressure
utilization today, many are getting close
and, in a higher-price environment, you
will see many more areas shifting into
Source: Getty Images.
high utilization,” Wells said. “The thing
that people need to be aware of is that
this could all happen really, really fast.”
With far less drilling activity happening, North Dakota’s Bakken and Texas’
Eagle Ford shales are not facing quite
the same situation as the Permian currently is. However, higher prices would
start to change that, and there are also
more than 2,000 DUCs in those two
plays that if brought on line in quick succession have the potential to drive waterhandling costs higher.
Produced water management is complex and expensive for shale producers partly because they have fewer
options than their conventional counterparts on what to do with it. One
major disadvantage is their inability
to reinject into unconventional reservoirs, underscoring that disposal wells
will always play an outsized role in
shale developments.
And proving that even virtuous solutions have their limits, if every shale well
in the US was hydraulically fractured
with recycled produced water, it would
account for only a single-digit fraction
of the total volume of water generated
each day.
Those studying water management
practices say that if operators start adopt-
ing longer-term strategies, they can gain
leverage over rising wastewater costs.
Their recommendations include lessening reliance on inefficient water trucks
by building more water pipelines along
with permanent processing and treatment facilities.
Michael Dunkel, a vice president for
the engineering consultancy CH2M, has
been involved with water infrastructure
projects in Texas and Oklahoma and said
a number of operators are on the cusp
of investing more capital on this front.
However, he noted that a meaningful
expansion of water facilities in the shale
sector will be years in the making.
Forecasted Permian Basin Produced
Water at Different WTI Prices
390
380
Millions of Barrels
370
363
360
360
350
342
340
344
346
334
330
333
320
310
300
Reported Production
USD 30 WTI Price
USD 50 WTI Price
USD 70 WTI Price
Jul-17
Jun-17
Apr-17
May-17
Mar-17
Jan-17
Feb-17
Dec-16
Oct-16
Nov-16
Sep-16
Jul-16
Aug-16
Jun-16
Apr-16
May-16
Mar-16
Jan-16
Feb-16
290
Oil prices are directly correlated to both oil and water production in US shale
plays, which is why they may be the best predictor of how intense the issue of
excess produced water becomes. Because it is the largest onshore producing
region, the Permian Basin of Texas is likely to feel the squeeze before other
areas. Source: Digital H20.
“It will be slow to evolve,” he emphasized. “But 5 years from now, I am confident that there will be a lot more water
infrastructure in place, both to move
around source water and to interconnect
disposal water, which will give greater
flexibility in transporting it to different
disposal wells.”
Price Matters
The place to watch will be the Permian
where, according to the Baker Hughes
rig count, there are more rigs turning
to the right than in any other place on
Earth. Having maintained solid growth
throughout the downturn, the Permian
is producing about 2 million B/D of oil—
and about 11 million B/D of water.
Assuming that even modest gains
in crude prices will encourage more
drilling in the Permian, as has been
the case since June, Wells said one of
his firm’s clients there is expecting the
prolific region to see a “wall of water”
next year.
It is an assertion that the firm’s model
for produced water largely agrees with—
36
depending on prices. Wells said that if
prices maintain a holding pattern of
around USD 50/bbl, the model expects
many disposal wells in the Permian to
soon begin flirting with their upper injection limits.
The screws tighten at around
USD 70/bbl. It is a price point many in
the business are longing for, but Digital
H2O’s model shows that it will overstrain
many disposal networks in the Permian
and other high-producing basins.
Wells noted that lead times to plan,
permit, and drill new disposal wells could
be at least a year. If demand outpaces
supply, then bottlenecks could form and
operators may be forced to expand their
batteries of water storage tanks in order
to keep producing unconstrained.
Uniquely Unconventional
There are several reasons why this particular produced water problem is unique
to unconventional developments.
In the conventional world, operators have the luxury of reinjecting much
of their produced water back into pro-
ducing formations for waterflooding or
enhanced oil recovery. Unfortunately for
shale producers, neither of those practices are applicable to nanoscale permeability reservoirs, yet.
Shale wells are also drilled in much
tighter clusters from pad sites than what
one would see in conventional developments. This concentrates the volumes of
produced water and places high demand
on nearby disposal wells.
As to why operators did not plan for
this earlier, during the beginning of the
shale revolution they had to be somewhat nomadic, in search of the best fairways and sweet spots. This left them
uncertain about exactly where future
production would come from, making it hard to invest in multimilliondollar water facilities that could not
be moved.
And lastly, while some data show that
shale wells produce less water than conventional wells on average, they generate significantly more in the early life
of the well. Industry-reported numbers
show that a typical shale well unloads
30-40% of the water that it will churn
out over an entire decade in the first year
of production.
About 20% of that water, termed
flowback, includes the fluids used for
hydraulic fracturing, which are also
growing in volume. To get more proppant into fractures, many operators are
using two or three times the volume of
water for fracturing that they were just
3 years ago.
Laura Capper, president of Houstonbased technology consultancy CAP
Resources, explained that though water
cuts from shale wells begin leveling
off after year 1, their front-loaded production creates especially high demand
for disposal services in areas where operators are ramping up.
“What you have is a hot play, where
all of a sudden you’re doing considerably more business there than you used
to and you’re trying to inject the water
close to the wellsite,” she said, adding
that, “those neighboring injection wells
are getting substantially higher injection
volumes than the ones that are maybe 50
miles away and only running at say 10%
of their volume capacity.”
JPT • DECEMBER 2016
More Pipes, More Infrastructure
When it comes to whether companies
should be using trucks or pipes to transport water, Capper said investing in the
latter should be a “no brainer” decision.
Operators can be charged more than
USD 100 per truck per hour to move
their water. Shale producers use thousands of these trucks each day to carry
only 130 bbl of water a time. The trucks
are hard on public roads, and represent
a sizable proportion of the oilfield traffic
that is attributed to an increased number
of collisions around active shale plays.
Pipelines, on the other hand, can
move water continuously, and quietly,
while avoiding many of the safety and
environmental risks that come with
trucking. Aware of these issues, a handful of larger shale producers have committed to building long networks of
water pipelines.
There is also a burgeoning industry of
third-party companies that act as midstream operators for produced water. A
recent example of this is a 30-mile pro-
duced water pipeline that was completed
in July by a company called Oilfield Water
Logistics. Located in the Delaware Basin
of New Mexico, several operators including Chevron will have access to the pipeline that will transport 150,000 bbl of
produced water each day—which otherwise would require more than 1,000
water trucks.
In addition to a need for more pipes,
more processing infrastructure will be
required to handle and treat the produced water before it heads back to the
subsurface. Just like a garbage disposal
in a home, disposal wells run smoother
and last longer when solids and other
harmful elements are removed prior
to injection.
And while there are a number of new
well-side treatment technologies available, in this case bigger is better. Dunkel said that based on his research, small
and mobile treatment systems will not
be a viable answer for mid- to largesized operators who have intensive
water needs.
“The issue is actually very simple; it’s
not that their capital cost is too high or
that the technology itself doesn’t work—
in many cases they do work well,” he
said. “But if you have to have two people
on site to run the system, the per barrel
costs are just too high and the labor cost
alone is almost a non-starter.”
Elaborating on this point, Dunkel
estimated that a two-person staff for a
5,000 B/D water treatment system costs
an operator about USD 5,000 a day. But
if those two workers, or even a third,
operated a 50,000 B/D water treatment facility, economies-of-scale kick
in and make small well-side options far
less attractive.
Dunkel said more operators are thinking about infrastructure today than
before the downturn, but with cash flows
still suffering, many have placed their
plans on hold.
One exception is the water treatment
and handling facility that Pioneer Natural
Resources is building for its unconventional development in the Permian. Pub-
A snapshot of Grady County, Oklahoma, in 2014 highlights that even during periods of high drilling activity there is far
more produced water generated in a shale play than can be used by oil and gas companies. The costs and logistics of
recycling that water to drinking quality are also extreme. Source: Laura Capper.
JPT • DECEMBER 2016
37
lished company materials show that the
facility will handle source water for fracturing operations and also recycle produced water for fracturing operations.
Speaking to the vast nature of shale
developments, the permanent infrastructure is supported by 100 miles of mainline, 10 pumping stations, and an additional 500 miles of subsystem piping.
Pioneer says that upon completion, the
project will move the equivalent of 2,000
truckloads of water a day.
In addition to recycling, more produced water can be removed from the disposal equation if the multipurpose water
facilities of the future come equipped
with evaporation units.
Another idea being discussed is
for shale producers to join forces and
create water management co-ops. This
would help smaller companies deal
with the high costs of infrastructure
but it will come with competitive and
regulatory challenges.
Outside of Texas, liability laws make it
difficult or impossible for oil companies
to transfer ownership of produced water
unless it is heading down a disposal well.
There are also operational considerations regarding who gets “first rights”
to the services if a shared facility temporarily lost some of its capacity to take or
supply water.
Big Limits on Recycling
If you thought stepped-up recycling
efforts would be the ultimate answer to
the question of what to do with produced
water, you would be wrong. Though recycling is seen as important for lessening
the sector’s reliance on fresh water, shale
producers will never drill and complete
enough wells to reuse all their produced
water for hydraulic fracturing.
Capper said her analysis shows that
while the majority of slickwater fracture
jobs in the US now use recycled water,
prior to the downturn when there was
considerably more drilling taking place,
the amount of water needed for fracturing vs. the total volume of produced
water was fractional.
Using one of Oklahoma’s most active
areas as an example, Capper’s data show
that from 2012–2014 overall injection
volumes in Grady County quadrupled,
and daily injection volumes per disposal
well tripled.
She estimated that at the peak only 3%
of that briny wastewater, which in 2014
totaled 80 million barrels, was needed
to support the county’s entire oil and gas
operations. It could require an annual
spend of USD 400 million to treat the
other 97%.
“On top of that, we would have to dispose of some 16,500 railcars of associated salt,” said Capper. “No matter how you
slice it, it is difficult to make the numbers
work in a 100% recycling scenario—
thus industry’s extreme dependence on
relatively low-cost disposal wells.”
All of this highlights two things: that
disposal wells will always be critical to
shale developments, and that though
there is a need, it will not be easy to make
large volumes of recycled produced
water available to outside industries.
The latter idea is termed beneficial
reuse and may not always involve treating produced water to drinking quality
if it is used for agriculture. In California, treated produced water has been
used for many years for the irrigation
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Seismicity To Drive Costs Higher
High-rate injection activity in disposal wells connected to
fault-prone formations has been cited by both industry
and government experts as the primary contributing
factor to induced seismicity in the US.
In areas where regulatory actions over induced
seismicity have limited the supply of disposal wells,
operators who want to increase production will have
to spend more money hauling loads of excess water
out of a quake zone.
The epicenter of this scenario is in northern
Oklahoma’s Mississippi Lime play where injection-linked
earthquakes have led regulators to force shut-ins or
curtail injections at hundreds of disposal sites spread
across more than 10,000 sq. miles. In 2016, the state
experienced three 5.0-magnitude quakes while the rest
of the country saw two.
“While the regulatory restrictions will undoubtedly
impact operators, the problem is in fact manageable,
albeit with more planning and analysis, which costs
money,” said Capper, who recently contributed to a
state-by-state risk analysis on disposal wells.
She said for those companies working in potential
seismic risk zones—which also include parts of Texas,
of tangerines and almond groves. Texas
A&M University also recently concluded
a study that used treated produced water
to grow cotton.
Arkansas, and Ohio—the short-term solution to avoiding
induced seismicity will involve a more “granular”
approach to monitoring injection volumes and downhole
pressures. It will also be key to understand local
geological factors that may facilitate seismicity.
By taking these steps, Capper explained that observant
operators should be able to stay under the thresholds
thought to trigger seismicity, something she added has
been proven to work in certain areas where disposal
activity was restricted. Though she emphasized that it
can take 18 months or more for injection reductions to
result in fewer observable, or felt, earthquakes.
The idea taking shape around disposal wells in
seismic risk zones is that geomechanics must trump
logistics. If the industry can demonstrate an ability to
self-regulate injection activity, and where necessary use
a more dispersed network of disposal wells, additional
government-enforced restrictions may be avoided.
“We know where these events have happened, so they
should be able to manage their businesses there,” Capper
said. “But it’s still going to be an additional cost burden
to the industry in that you will probably have to drive
your water trucks farther out, or pipe it farther away.”
But aside from these isolated examples, this concept has not been warmly
embraced or benefited from the type
of extensive, and expensive, research
that is needed to prove to the wider
public and relevant government agencies that it can be done safely on a
larger scale. JPT
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