American Oil and Gas Reporter - January 2019 - 74

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Tech Trends
FIGURE 2A
DSU-A (Non-Tank Development)

FIGURE 2B
DSU-B (Tank Development)

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DSU-C (Tank Development)

Middle
Spraberry

Middle
Spraberry

Middle
Spraberry

Lower
Spraberry

Lower
Spraberry

Lower
Spraberry

Spraberry
Shale

Spraberry
Shale

Spraberry
Shale

Dean
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FIGURE 2C

Dean

Sequential Development
First production of wells directly after completion, allowing for
frac hits and potentially compromised child well SRVs
Spraberry Shale 10 wells/mile density

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*
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Wells 1 and 2 experienced 36 days of lower production because
of the interference frac hits. This was not an isolated event in
our experience; production losses have occurred with every sequential well completion and production startup. Some wells
returned to their forecast levels while others never resumed
their previous paces.
Using all observed frac hit data, production loss was quantified
as a function of distance. This relationship is used to understand
and incorporate the economic effects of frac hits in development
planning when using a sequential development technique. Indications of compromised child well SRV also are evident, which
is consistent with microseismic data, frac modeling results and
production analysis.
In addition to the sequential development test, one horizontal
infill program was executed as part of the sequential development
study to shed more light on the economics of infilling for
stranded reserves within the Spraberry formation. In the onemile DSU study, two Spraberry infill wells were drilled and
completed 150 feet above seven producing Spraberry wells and
approximately 650 feet below four producing Middle Spraberry
wells. At the time the two infill wells were completed, the 11
existing wells' combined production was roughly 3 million
barrels of fluid during a period of 24-28 months.
While completing the infill wells, seven of the 11 existing
wells, positioned both above and below the infill wells,
experienced interference frac hits. Production from the wells
with frac hits decreased 30-100 percent and took several months,
if ever, to return to prehit trends.
In addition, the two infill wells' output dropped (50 percent
EUR reduction) compared with all other wells producing in the
FIGURE 3
Continuous Tank Development Approach

74 THE AMERICAN OIL & GAS REPORTER

Dean

Tank development
Top-down completion-lateral pressure wall
Complete and turn all wells on at the same time
Spraberry Shale 16 wells/mile density

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*
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Tank development
Utilization of pressure wall to act as a barrier for frac hits and
preferential growth between completing and producing wells
Spraberry Shale 16 wells/mile density

Spraberry. We attribute this to a compromised SRV caused by
the pressure sinks above and below the wells. This hypothesis
is supported by frac modeling results, which predicted immediate
growth into pressure sinks, proppant settling away from the
wellbore and smaller SRVs. Considering current operational
costs and oil prices, it is not economic to drill additional infill
wells at this time. This perspective emphasizes the need to understand optimal multiple stratigraphic horizon spacings to
balance stranding economic oil and maximizing value.
Tank Development Concept
To overcome the pitfalls at DSU-A, the goal in DSU-B and
DSU-C (Figures 2B and 2C) was to optimize the development
strategy rather than use a mitigation technique, leading to the
creation of the multidisciplinary tank development approach
that aims at optimizing both surface and subsurface operations
and exploiting a volume of rock at one time to maximize
reservoir potential.
Ideally, all wells in a given area are drilled, completed and
then brought on line at the same time to minimize the effects of
frac hits associated with pressure sinks. However, understanding
the practical balance between optimal development and production
goals prompted the development and implementation of a
"pressure wall" concept to minimize well interference while
optimizing production and stimulation.
In this context, a pressure wall is a lateral and/or vertical
volume of reservoir that has been completed ("pressured up"),
but not turned on line for flowback. Because of completion
energy, the reservoir within the pressure wall is above pore
pressure and acts as a barrier to frac hits and preferential energy
growth between completing and producing wells. A volume of
unstimulated rock acts as a buffer between drilling and completion
operations (Figure 3). Prior to implementing this buffer, QEP
Resources had experienced multiple frac hits that resulted in
drilling operation downtime and associated cost increases.
Tank development must therefore be accomplished by continual
timely development of a DSU, such that each drilling rig is
followed by a completion crew that creates a pressure wall, which
in turn, is followed by simultaneous flowback and production of
all wells. The three ideal steps to deploying tank development are:
· Completing wells in a "top-down" manner whenever possible to minimize stimulation fluid and pressure leak-off into
shallower, lower-pressure zones and open naturally fractured
rock, generating more near-wellbore complexity;
· Bringing wells on line only when there is a pressure wall
separating producing wells from completing wells; and
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