American Oil and Gas Reporter - September 2017 - 87

ConventionSection: North Dakota Petroleum Council
Society of Petroleum Engineers concluding
that repeated stress cycles caused by shutins may damage reservoirs. A 2013 SPE
study of 280 wells in multiple basins
concluded, among other things, that a
delay from the end of fracture stimulation
until first production is detrimental. Other
considerations from the paper cited by
NDPC's amicus brief include:
* The benefits for reservoir/wellbore
connectivity of keeping wells on line
once production has begun;
* Related damage that continues to
accrue during subsequent shut-in events;
and
* The detriments to good reservoir
and well connectivity posed by excessively
rapid reduction of wellhead flowing pressure.
"The other thing is the safety in having
to retool," Dillé adds. "If you have an
area on pipe from your wells to larger
distribution systems, that network is essentially safe. A pipeline closure means
shutting off gathering systems and bringing
trucks to the well site. North Dakota is
having trouble finding enough labor because the state is competing for workers
with everybody else in the country. During
a slowdown, people go to other industries.
North Dakota would have to make sure
it has enough trucks, truckers and rail
cars. Replumbing at the wellsite would
complicate things further."
NDPC cites a number of other significant costs associated with shutting down
the pipeline. Activating parked trains involves inspection fees, maintenance updates and switching out of and into rail
yards storing unused train cars. For example, the group offers a rough cost estimate of $100 a car per switch and $2,500
a car for transportation, so that mobilizing
75 unit trains of 100 cars each will cost
North Dakota producers about $20 million,
before accounting for maintenance updates
and inspection fees.
"This is not to mention the untold
burden to be borne by employees of
North Dakota producers who would be
asked to manage the logistical nightmare
that would ensue," NDPC states.

Adding Costs
According to NDPC, reverting from
pipeline to rail also will raise North
Dakota producers' transportation fees for
the duration of a shutdown, with the
group's members conservatively estimating the shift to rail will cost at least an
additional $3 a barrel, comparing recent

rail costs to load, transport and unload
crude oil with the same Gulf of Mexico
markets DAPL makes accessible.
The differential may prove much
greater, especially if producers are forced
to compete for inadequate rail resources,
NDPC warns. Even applying the $3 a
barrel figure and assuming only 250,000
barrels of oil a day would be forced to
shift from DAPL to rail, the increased
transportation costs would drain about
$23 million a month from North Dakota
producers.
An initial shutdown can leave some
producers unable to deliver promised
volumes to refinery customers, NDPC's
filing continues, forcing refiners to replace
lost volumes from other sources and requiring North Dakota producers to remarket volumes to alternative buyers.
Based on re-marketing experiences associated with logistical failures, NDPC
members can expect an additional loss
of $0.50-$1.00 a barrel in sales prices
for such "distressed" crude sales, the
brief continues.
Harm to the North Dakota crude oil
market will be immediate and last at least
for the duration of a shutdown, NDPC
warns. Member companies and North
Dakota officials familiar with the state's
oil market agree that the cost reductions
and expanded competition associated with
DAPL will buoy the market price for all
North Dakota crude oil, including both oil
shipped on the pipeline and that transported
by other means, the brief holds. The North
Dakota Pipeline Authority estimates a $1$2 a barrel impact, the brief states.
"This estimate, given that North Dakota
produces approximately 1 million barrels
of crude oil a day, translates to $30 million-$60 million a month in gross value,"
NDPC says.
Stopping crude transportation on DAPL
will shrink companies' operational flexibility in a way difficult to quantify, but
will be nonetheless harmful to the industry
and the market for North Dakota oil,
NDPC explains.
The brief also points out that not only
operators and royalty owners benefit from
North Dakota's production, but also state
agencies and schools. The state's tax
commissioner has estimated that DAPL's
impact may boost North Dakota tax revenues by $100 million a year, or more
than $8 million a month. The brief cites
Associated Press estimates of $110 million
in tax revenue a year, with $100 million
in oil taxes from higher crude prices and

$10 million in North Dakota property
tax revenue.

Lake Sakakawea
Even amid the urgency of keeping
DAPL on line, NDPC has continued work
on a number of other important fronts.
Among them, Ness cites some key victories from the 2017 legislative session,
including passage of SB 2134, while the
group continues to assess the impact of a
line-item veto that affects legislation on
calculating gas royalties on state trust
lands.
SB 2134 directs the Department of
Mineral Resources to refer to an original
Corps survey of the high water mark on
the Missouri River when determining
mineral ownership prior to creation of
Lake Sakakawea at the time Garrison
Dam was built.
"We passed SB 2134, which helps
the process to basically analyze existing
ownership," Ness relates. "The North
Dakota Industrial Commission has issued
a contract with a third party that has
eight months to come out with a second
report. For the most part, we have done
our job and now individual owners and
operators-or the state-can make its case
on these and run track by track analyses.
This is a huge issue going forward and
one that also is prohibiting development
of multiple lateral wells in some of these
fields where ownership is unclear."
Meanwhile, Governor Burgum used
his line-item veto power to annul a portion
of legislation that dealt with the issue of
gas royalty deduction on trust lands, Ness
says. Land Board interests had indicated
that deductions were not allowed under
the existing lease agreement, which has
been in place since the 1940s, he says.
It has been allowed in practice, however, Ness observes, but he predicts the
issue is likely to appear in the courts. r

Coming In October

An update on some of the critical
lessons the industry has learned to
date in drilling and completing wells
in the play, including the latest insights on recoverable in-place reserve assessments in the Eagle Ford,
and how the ongoing evolution of
horizontal drilling and hydraulic
fracturing designs are impacting
long-term recovery factors.
SEPTEMBER 2017 87

American Oil and Gas Reporter - September 2017

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