American Oil and Gas Reporter - October 2018 - 82

FIGURE 3
Frac Model of Hybrid and Slickwater Pump Designs

Hybrid

economically challenged area. The well
accessed fewer than 50 feet of net pay
within the landing zone, and fracture
modeling software predicted the ability
to access nearly the full zone with slickwater fluid, similar to the more expensive
hybrid gel design (Figure 3). This helped
to eliminate the question of whether the
fluid could achieve optimal fracture height,
and focus on fluid cost as well as regained
conductivity during production.
Moreover, this well also benefitted

by having several long laterals landed
within the same interval in the surrounding
area for production comparison purposes.
As a parent well with no direct lease line
offsets, this was imperative in candidate
selection to calibrate the results.
This well used a different stimulation
company than the previous wells, and
the entire HVFR chemical suite replaced
the vendor's chemicals, as opposed to
the friction reducer only. As such, the efficiencies of the system were realized

FIGURE 4
Normalized Oil Production Rate of HVFR Well Versus Offsets
(Rolling Seven-Day Average)
10,000
HVFR Well
Avg. Offset

20:1 boe/d

1,000

100

40
50
Normalized Date

82 THE AMERICAN OIL & GAS REPORTER

immediately on surface, where the footprint was decreased by having one fluid,
HVFR, take the place of chemical containers for friction reducer, gel, surface
and delayed cross-linker, as well as eliminating the need for a gel hydration unit.
This well was another operational
success, pumping all design stages. Likely
because of the thinner pay and geological
area, treating pressures were higher, resulting in more conservative HVFR loadings at 3.0 gpt. The contract with the
stimulation company required a maximum
proppant concentration of 4.0 ppg. This
was still very cost advantageous to the
previous hybrid design.
Even at higher average pressures, field
personnel described the HVFR fluid as an
"on-demand chemical," in that the significant
decrease in hydration time and viscosity
assessment while pumping enabled them
to increase loadings much quicker as pressure necessitated. Accordingly, chemical
cost per stage decreased 33 percent on this
HVFR well compared with previous wells
treated by the same stimulation company.
After successful drill-out operations,
the well was placed on standard flowback.
After 30 days of production, it was outperforming its direct offsets by 62 percent
on a barrel of oil equivalent a day basis,
using a 20-to-1 Mcf conversion rate (Figure
4). Because of the nature of the thin reservoir, the longevity of the production will
be essential to document and analyze, but
this well also was deemed a success.
Third Case Study
The final case history was selected as
a combination between the previous two
cases. Geologically similar to the first
case study, this parent well is in a thick
pay zone area with consistent results in
surrounding sections for reliable production comparisons. It was hoped that the
well would offer another valuable data
point when comparing operational efficiencies, chemical costs, and effectiveness
of the HVFR during treatment and flowback. Unfortunately, the well experienced
many operational issues, none of which
were caused by the HVFR fluid, but influenced success nonetheless.
The well was stimulated by a third
stimulation company, providing yet another cost comparison with prior wells
pumped by the service provider. It also
was another opportunity to pump the
full chemical suite, and benefit from the
smaller surface footprint. A new benefit
discovered with this stimulation crew
was the decrease in liquid additive pumps
required at the blender on location. Prior
wells had issues maintaining the high
number of pumps needed to move all of
the chemicals in the hybrid design. By

American Oil and Gas Reporter - October 2018

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