American Oil and Gas Reporter - June 2020 - 35

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SpecialReport: Production Restarts
crossflow between reservoirs of differing pore pressure gradients
during every shut-in period, and the transfer of fluids back to
the wellbore after production restoration is not usually very
efficient or complete. The degree to which reserves are
permanently lost depends on permeability in each reservoir, the
reservoirs' thicknesses, and the pore pressure differential between
them. Crossflow is also an issue in horizontal well drainage
volumes, but it is not usually between separate reservoirs.
In a horizontal drainage volume in a single stratigraphic
reservoir, there are usually wide variations in permeability,
most often caused by variable natural fracturing density and
differences in the placement and degree of propped stimulation.
Along a given horizontal wellbore, therefore, the wellbore
drains some portions of the reservoir substantially more efficiently
than others during its early history. When the wellbore is shut
in, pressure tends to equalize. Upon restoring production, a
substantial period of time is sometimes required for the wellbore
pressure distribution to return to its former character. Unfortunately,
it is not clear where this will be a real issue, or how it can be
measured, mitigated or forecasted.
Some researchers have highlighted the negative impact of
cyclical shut-ins and restarts on the stability of proppant packs
and subsequent decreased production tied to the proppant
damage. It is probable that these concerns are valid in more
conventional wells when the reservoirs of interest have moderate
to high permeability, and the proppant is not of sufficient
quality to withstand the closure stress imposed upon it. However,
most North American unconventional production scenarios are
not deeply dependent on high fracture conductivity for success,
and an extended shut-in followed by resumption of production
should not be expected to have substantial geomechanical stressrelated issues.
Midlife Wells
The vast majority of unconventional producers decline in
a semi-predicable manner because of pressure depletion.
Within a few short years (or even months), these wells become
subject to their own class of unique challenges. Among those
changes is a potential change in reservoir rock wettability in
and near propped fractures. From a statistical point of view, it
appears that connate (bound) water often decreases and free
water increases. The result is that in several plays across
North America, water-to-oil ratios and water-to-gas ratios
increase upon restoration of production after extended shutin periods. The degree to which this is a problem appears to
be localized to plays where wettability is easily altered or reversed.
Operators often utilize a mandatory shutdown initiated by
midstream or surface facilities as an excuse to perform needed
subsurface repair, so it could be difficult to attribute increased
water to this specific phenomenon from public data alone.
Midlife producing wells also can suffer from surface facilities
degradation, and in a little-appreciated twist, that rate of
degradation can accelerate during prolonged shut-in periods as
a result of exposure to oxygen inside equipment that was not
present during active production and a number of minor, but
additive factors.
High-rate gas wells that produce water are healthy and
happy, as long as they are lifting produced water in what is
known as "mist flow." As pore pressures decrease, production

rates decrease, and at some time in middle or late life, there
comes a point where the mist becomes a slug. Liquid loading
from that point forward is the bane of the producer. For these
wells, a slowdown or shut-in must eventually lead to some sort
of artificial lift expenditure to kick-off the well once prices sufficiently improve.
Both oil and gas wells in the midlife production period face
the same parent-child risk of EUR loss due to asymmetric fracturing of a DUC or PUD offset-except that in this case, the loss
is in the future when the offset is stimulated. There is no
evidence to support a generalization that simply shutting in a
midlife well helps to prevent the asymmetric fracturing and
loss of recoverable reserves.
Legacy Wells
As production curves for both oil and gas wells flatten out at
just barely commercial rates, there are a multitude of events
that can trigger an end-of-life scenario. For legacy stripper oil
wells, artificial lift (rods, pump or tubular failure) is the most
frequent cause of permanent production cessation. However,
the nature of rod-pumped completions is such that they are built
for intermittent pumping, so this class of wells may not be particularly impacted by extended shut-ins and subsequent restarts.
A fiscal consideration stemming from this is that a well just
barely inside the definition of a stripper for tax purposes might
be bumped out of that classification if the transient bump in
production after restarting increases the annual average to
outside that classification range.
As with midlife wells, further degradation of surface facilities
can become an issue with older wells. An extended shutdown
followed by a restart often brings to light mechanical issues
that may have been present during the later stages of production,
but were not detected. These may include leaks, corrosion,
erosion or even functionality of the measurement devices themselves.
For a legacy gas well, the endpoint of life is most often
severe liquid loading, scale, sanding up or a hole in the vertical
portion of tubulars. The trigger for such events is typically an
extended shut-in due to unforeseen circumstances. Like the
midlife gas well scenario, a legacy gas well is statistically
subject to watering out. Although the root or contributing causes
could be mechanical in nature, changes in wettability are
possible, largely because of various interventions over the years,
many of which contain a plethora of surface active agents.
Several operators with large inventories of legacy gas wells
have developed decision trees that assist in accelerating the
decision making process by "databasing" and updating costs of
various remedial actions-including plugging-in order to obtain
a quick look at NPV and/or cash flow associated with end-oflife action steps. In this case, remedial work is almost always a
negative NPV proposition. Consequently, most operators have
elected to completely avoid shut-ins or slowdowns of this classification of wells.
Older oil and gas legacy wells also can face the same issues
with respect to crossflow, and with respect to interaction with
offset producers during shut-in periods, but usually to a lesser
degree than they would have earlier in their life cycles. Most
geomechanical experts agree that stress effects likely have
minimal impact on legacy producers, even with repeated cycling
of production.
JUNE 2020 35



American Oil and Gas Reporter - June 2020

Table of Contents for the Digital Edition of American Oil and Gas Reporter - June 2020

Contents
American Oil and Gas Reporter - June 2020 - Intro
American Oil and Gas Reporter - June 2020 - 1
American Oil and Gas Reporter - June 2020 - 2
American Oil and Gas Reporter - June 2020 - Contents
American Oil and Gas Reporter - June 2020 - 4
American Oil and Gas Reporter - June 2020 - 5
American Oil and Gas Reporter - June 2020 - 6
American Oil and Gas Reporter - June 2020 - 7
American Oil and Gas Reporter - June 2020 - 8
American Oil and Gas Reporter - June 2020 - 9
American Oil and Gas Reporter - June 2020 - 10
American Oil and Gas Reporter - June 2020 - 11
American Oil and Gas Reporter - June 2020 - 12
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