American Oil and Gas Reporter - June 2014 - 79

SpecialReport: Offshore & Subsea Technology
sample was then re-sieved, and any material
that fell through the smallest designated
sieve was considered fines.
At 10,000 psi, the results of the test
indicated that a substantially small fraction
of crushed sample (much less than 10
percent) could be considered fines. Therefore, at closure pressures around 10,000
psi, the solid inhibitor did not significantly
impact the integrity of the proppant when
used at a loading less than 66 percent.
Confident in the results, the frac pack
operation in the subsea well was commenced using 13,895 pounds of 20/40mesh proppant, of which 1,389 pounds
(10 percent) was high-strength solid scale
inhibitor. The single-zone frac pack was
carried in 1,200 feet of water at a total
vertical depth of 10,861 feet. Bottomhole temperature and pressure were 199
degrees and 5,430 psi, respectively, and
fracture pressure was 6,892 psi.
The carrier fluid was a borate crosslinked frac fluid system with a 5 percent
potassium chloride base. The frac fluid was
pumped at an average rate of 12 bbl/minute.
The average pressure during the frac job
was 5,700 psi, and maximum pressure at
screen-out was 7,791 psi. The net pressure
gained during the job was approximately
1,300 psi, and a tip screen-out was achieved.

Increases in net pressure generally reflect a
wider, more conductive fracture.
The well was put on production and
immediately flowed both oil and water.
Initial daily production was 636 barrels of
oil and 635 barrels of water at a bottomhole pressure of 4,240 psi. All post-fracpack production data indicated that the
job was a success. Several months and
several fluid sample tests later, the analysis
of the residual scale inhibitor in the pro-

duced water demonstrates that the inhibitor
is still present and inhibiting scale in the
formation.
After 120,000 barrels of produced water,
the scale inhibitor residual began to reach
the terminal point. Future applications call
on using a higher percentage of solid inhibitor and higher quantities of total proppant to establish a treating scenario that
can reach the goal of 1 million barrels of
produced water.
r

STEPHEN SZYMCZAK is the product line director for StimPlus™ at
Baker Hughes. He has 30 years of experience in the development, application, sales and marketing of specialty
chemicals in oil and gas production
and stimulation. Szymczak's focus is
on advancing technologies that provide
multiyear flow assurance by placing
solid and liquid additives in the formation during hydraulic fracturing.
He holds a B.A. in chemistry from the
University of Missouri in St. Louis.
WILLIAM STEINER is pressure
pumping product line technology manager at Baker Hughes. With 40 years
of oil and gas industry experience, he
has held roles as a laboratory technician, formulation chemist, technical
director and products manager. Steiner
holds three patents in the chemical
field. He holds B.A. degrees in chemistry and mathematics from Concordia
College, and has taken graduate-level
chemistry classes from the University
of Florida, and business classes from
the University of Wisconsin.
JUNE 2014 79

American Oil and Gas Reporter - June 2014

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