American Oil and Gas Reporter - February 2018 - 81

SpecialReport: Gulf of Mexico Update
the annulus and choke. The proppant
placed into the formation was 1,116
pounds/foot measured and true vertical
depth with 80 feet of excess blank height
coverage in the wellbore. The excess
proppant was reversed out and the service
tool was removed from the well.
Completion operations then continued
by installing the production packer and
tubing with subsurface safety control
valve, chemical injection mandrel and
downhole pressure/temperature gauge assemblies. The tubing was landed in the
horizontal subsea tree and tested. A total
of 1,192 barrels of fluids was pumped
during the prefrac stimulation and frac
pack treatment.
Treatment Results
Once tubing was landed, the well was
rigged up for flowback. Flowback data
were recorded for more than 63 hours.
Figure 4 shows water and oil recovery
data. Water recovery increased for 14.3
hours and then plateaued. A total of
2,023.9 barrels of water were collected.
After 11.2 hours of flowback, 1,192
barrels were recovered. The extra water
recovery most likely was attributable to
other fluids pumped and lost to the formation and water blocks that were opened.
Figure 4 also shows the amount of
cumulative oil recovered as function of
time. First oil was observed after 3.8
hours and continued to increase as more
water was recovered. After 5.0 hours, oil
recovery increased sharply. Both oil and
water plateaued after 14.13 hours. During
the job, it was observed that the flowback
fluids were coming out of the well more

FIGURE 4
Flowback Results for Gulf Well using Neutral Wettability LWC
1,800

Water

1,600

1,800

Oil

1,600

1,400

1,200

1,000

800

600

400

200

0.0

2.3

2.6

2.8

3.1

3.8

3.9

4.0

4.3

4.6 4.8 5.0
Time (hrs)

6.8

8.3 10.1 12.3 14.6 17.1 33.8 48.8

Cumulative Water (bbls)

Case Study Well
For the deepwater Gulf of Mexico
well application, no modifications were
made nor additional equipment added in
the completion operation with the neutral
wettability proppant versus traditional
proppant. The completion was performed
by installing a 97⁄8-inch, 62.8-pound liner
cemented across the productive interval.
Drilling fluid then was displaced to clear,
solids-free brine using wellbore cleanout
tools and filtering until establishing only
clean, solids-free brine.
Positive and negative tests were performed to establish wellbore integrity.
The cleaning assemblies were pulled out
of the well and a sump packer was set on
electric line to establish bottom and depth
correlation references. Tubing-conveyed
perforating then was run to depth, and
the zone of interest was perforated in an
overbalanced mode. Once losses were
acceptable and the wellbore was stable,
the assembly was removed from the well.
The frac pack assembly then was run
to bottom and set in place. The assembly
consisted of:
* An external sump seal assembly;
* A shrouded sintered mesh screen;
* Blank pipe;
* Frac pack extensions;
* A frac pack seal bore packer (external and permanent components);
* An internal sump seal assembly;
* A mechanical sliding sleeve;
* Internal isolation tubing;
* A hydraulic production sleeve and
double pin sub made up to frac pack extensions (internal and permanent com-

ponents) along with wash pipe with pressure/temperature gauges;
* A mechanical sleeve shifting tool;
and
* A frac pack service tool and packer
setting tool (internal retrievable components).
Frac pack operations then began utilizing an offshore stimulation vessel to
perform initial diagnostic circulating and
injection rates. A prefracture stimulation
was performed using a solvent system
ahead of an organic/nonorganic acid
blend, followed by organic mud acid
blend with an ammonium chloride overflush. All blends incorporated additives
tested for compatibility and flowback
properties.
During treatment, significant pressure
responses were observed, indicating an
effective stimulation. Immediately following the acid treatment, a minifrac was
performed to measure formation properties, followed by a step-rate test to further
evaluate formation properties, confirm
the closure envelope and obtain treatment
redesign parameters. The treatment schedule was based on modeling the observed
formation responses and desired fracture
characteristics. The frac pack was pumped
at 18.5 barrels a minute, pumping a total
of 65,194 pounds of 30/50-mesh neutral
wettability LWC proppant, with a maximum concentration achieved through a
ramped schedule of 10 pounds of proppant
added per gallon.
Tip screen-out was observed with more
than 650 psi of net pressure gained, although final wellbore screen-out was induced at 1 bbl/minute taking returns via

Cumulative Water (bbls)

heit. During fluid injection and leak off,
a total of 91 milliliters of filtrate was
recovered. After low-rate water cleanup,
the initial regain conductivity was 60
percent and after high-rate cleanup 61
percent. After cleaning up with only
water for an additional 50 hours, this
test had a "water only" regain conductivity of 61 percent and showed little
sign of improving.
Following gas cleanup and further
water cleanup, the final regain conductivity
was 94 percent, showing that the pack
retained almost all conductivity after
cleaning from the fracturing fluid. After
completing the test, the cell was opened
and observed for any remaining gel and
damage. No obvious signs of any residual
gel or filter cake damage were observed
within the proppant pack.

FEBRUARY 2018 81

American Oil and Gas Reporter - February 2018

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