American Oil and Gas Reporter - June 2020 - 36

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SpecialReport: Production Restarts
Miscellaneous Issues
There are a few other miscellaneous subsurface equipment
issues that may pop up as a result of extended shut-in periods
followed by restarts, namely tubular corrosion at the fluid
interface and seal failures.
In regard to tubular corrosion, nearly all unconventional and
conventional wells alike produce at least two phases (gas and
water/oil and water/gas and oil) and sometimes three (oil, gas
and water). When a well is shut in, the fluids in the wellbore do
not immediately cease their movement. Phase separation begins,
and pressure equalization continues for some time.
Eventually, however, fluid movement is negligible, and the
interface between oil and water or between gas and water can
promote steel tubular goods corrosion. Anaerobic bacteria, or
the presence of even minute amounts of dissolved oxygen or
carbon dioxide, can initiate corrosion that ends up impacting
tubular integrity upon restarting a well.
Occasionally, engineered seals are placed in downhole equipment to facilitate the isolation of different pressure environments.
Over the years, dramatic improvements in sealing material
technologies have resulted in outstanding performance over
long service periods in hostile temperature and pressure differentials. However, the enemy of these products is not the extreme
pressure or temperature or movement, but changes in extreme
temperature or pressure or movement. A prolonged shut-in, followed by a restart with wild temperature, pressure and movement
can be the trigger that initiates failure.
Key Takeaways
The COVID-19 lockdown and commodity price slide
produced a completely unforeseen and unexpected result: an
avalanche of webinars and online workshops for industry professionals, along with the free time required to participate in
them. One of the subject matters covered by several of these
online events was the impact of slowdowns and shutdowns on
both production rates and EURs. There were several key takeaways from the information presented, and quite a few concepts
were systemically noted.
For instance, when considering wells that have not yet been
drilled, DUCs and new producers, the primary drivers for the
well triage process are purely fiscal, as opposed to technical. A
slowdown is generally preferable to a shutdown in relatively

new wells, since choking back high-rate producers is a relatively
simple operation with low technical risk from a recoverable reserves standpoint.
A few large and mid-size operators were reportedly comfortable
with simply adjusting their active drilling and completions operations in the downward direction, as opposed to a strong emphasis on working with existing producers. The various reasoning
provided for this was not uniform. Some claimed lack of manpower, and some cited an inability to quantify the risks associated
with restarts. Others said that the contractual and regulatory
complexities associated with shutting in existing producers
were overwhelming.
The parent-child well interaction dilemma was the single
biggest technical obstacle to executing new undrilled PUD and
DUC decisions. This is understandable, given that reserves lost
to asymmetric fracturing from a child development well toward
an existing producer at its midlife point can meet the definition
of "fiscally material" if repeated over dozens or hundreds of
drainage areas.
From a technical perspective, it is clear that legacy and midlife
wells are the most difficult scenarios to work. Operators in states
that have provided regulatory relief by extending allowable shutin periods for this class of wells may have more options available
as commodity prices improve. As noted, unconventional gas
wells face more technical restart issues at midlife than do unconventional oil, primarily because of liquid loading.
Smaller operators without significant drilling and completion
programs need to assess the technical risks associated with
restarts of midlife and mature wells, even if it means that the
assessment is partly qualitative. If there are multiple reservoir
types, fluids and well construction practices, then the assessment should look at each of the potential parameters that
could impact the recovery rates and EURs of the wells in
question.
The domestic industry already has demonstrated to the rest
of the world that restricting flow from unconventional wells is
best enabled by restricting the rate of drilling, stimulation and
completion. The primary drivers are fiscal, as opposed to
technical. However, for the large number of wells that have
been shut in, operators will have to evaluate both technical and
financial considerations as they start bringing assets back on
line and restoring productivity.
❒

DOUG
WALSER

Doug Walser is a subsurface asset valuation acceleration specialist with Hydraulic Fracturing
Group LLC. Walser has 40 years of experience in the Permian Basin, Mid-Continent,
Appalachian Basin, Rocky Mountains and South Texas. He has specialized in calibrating 3-D
fracture modeling using a number of methods, including historical production transient
analysis and calibration by various fracture mapping processes. Most recently, Walser has specialized in methods to quantify the potential to improve the recovery factors of North American
resource plays. He holds a B.S. in natural gas engineering from Texas A&I University.
36 THE AMERICAN OIL & GAS REPORTER



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
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