American Oil and Gas Reporter - August 2020 - 60

pages 58-63_Layout 1 8/12/2020 2:24 PM Page 60

SpecialReport: Marcellus/Utica Update
FIGURE 2

4,000

3,500

Well A Parent Casing Pressure, (psig)

Proxy Well to Well A Parent Casing Pressure, (psig)

Parent Casing Pressure Responses to Child Stage Starts for Proxy Example (Left) and Well A/B (Right)

3,000

2,500

2,000

1,500

1,000

BUILDUP
PRESSURE,
PSI

BUILDUP
RATE, PSI/HR

FALL-OFF
PRESSURE
PSI

FALL-OFF
RATE, PSI/HR

BUILDUP/
FALL-OFF
RATIO

547

-445

423

-124

-3.4

3,000

2,500

2,000

1,500

1,000

BUILDUP
PRESSURE,
PSI

BUILDUP
RATE, PSI/HR

FALL-OFF
PRESSURE
PSI

FALL-OFF
RATE, PSI/HR

BUILDUP/
FALL-OFF
RATIO

-65

-26

-14

500

500
Period of Full Offset Frac with Each Stage Starting Time Overlaid as Dashed Vertical Line

mixture of 100- and 325-mesh grain sizes
was selected for field trial. This nondissolving diversion media is cost-effective
and requires only small operational adjustments to adopt during fracturing.
Well A's completion design is typical
for Bradford County. The plug-and-perf
slickwater frac had pumped 100-mesh sand
as 7% of total proppant and 40/70 Ottawa
white sand as the remaining 93%. The
pump schedule had included a pad volume
after formation breakdown, a small acid
flush for perforation cleanup, followed by a
proppant-laden fluid with sand concentrations
increased in a stair-step fashion. Well B
would mimic the parent well's design, including stage length, proppant loading, fluid
volume and cluster design. The only change
would be adding a far-field diverter as a
fraction of total sand volume. This approach
ensured that the added far-field diverter
would be the primary variable tested.
The goals of the field trial on the twowell pad included:
· Adding far-field diverter to the
pump schedule without any environmental,
health and safety impacts or efficiency
losses;
· Monitoring the parent well's casing
pressure in real time and maintaining
buildup pressure below 500 psig;
· Executing a real-time strategy on
location to identify an invasive stage presence and deploy additional mitigation
protocols if needed; and
· Maintaining or improving the unit
economic portfolio for well group A
and B.
60 THE AMERICAN OIL & GAS REPORTER

Period of Full Well B Frac with Each Stage Starting Time Overlaid as Dashed Vertical Line

Well A was shut in for 11 days prior
to starting completion activity on Well
B. During this time, pressure increased
from 1,000 psig while flowing to 2,100
psig. Fluid levels were determined to ensure a clean wellbore and a consistent
fluid level for hydrostatic calculations. A
backpressure valve was installed in the
tubing hanger to isolate the 5,000 psirated production valves from potential
high frac hit pressures.
The second operational challenge was
to monitor and record Well A's casing
pressure in real time. An electronic pressure sensor was installed under the backpressure valve/tubing hanger. Since Well
B is on the same pad as Well A, the frac
spread operator, Universal Pressure
Pumping, ran a data line to its frac van
to enable high-frequency casing pressure
monitoring. This allowed on-site and
online users of the company's virtual
frac database to plot casing pressures
against other recorded trends. All data
was synchronized automatically, ensuring
utmost accuracy in comparing rates,
pressures, surface/downhole concentrations, etc.
Procedures were developed to facilitate
the on-site storage and handling of the
silica flour, which was packaged in 2,000pound "supersacks." After completing an
initial 0.5 pound per gallon, 100-mesh
stage, 2,000 pounds of diverter material
was slowly released onto the sand belt
and mixed with 100-mesh sand. The combined material then was conveyed to the
blender and mixed to a 1.0 ppg slurry.

Field Trial Results
Pressure data was monitored for each
subsequent stage as Well B was completed.
While frac hits were observed in every
stage (right-hand chart in Figure 2), they
were much less dramatic than those in a
nearby proxy example that had no diversion agent additives (left-hand chart in
Figure 2). The average buildup pressure
was 88 psig, well below the 500 psig
goal. Two early stages did show a buildup
greater than 300 psig, so future jobs may
consider a lower goal, for a more aggressive mitigation program.
All stages were pumped to 100% of
designed proppant placement. In nearby
wells that had not used a diverter, the
child well had a higher average treating
rate than the parent, despite similar average
treating pressures in both wells. The opposite is true for the Well A/B diverter
trial. The rate for Well B was significantly
less than the parent at similar average
treating pressures. The phenomenon could
be random, or it could be an indication
that the diverting material successfully
prevented preferential fracture length
growth into depleted zones, increasing
pressure and/or limiting rate when max
pressure is a constant.
Well B has underperformed to type
curve expectations. With a lower normalized rate and lower flowing casing
pressure, its production was 30% below
the area type curve as of November
2019, shortly after completing the well.
Conversely, Well A's performance has
exceeded expectations. Figure 3 plots

American Oil and Gas Reporter - August 2020

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