American Oil and Gas Reporter - August 2019 - 89

SpecialReport: Hydraulic Fracturing Technology

Seeking Scale In Shale
As illustrated in Figure 2, the industry
has seen explosive growth in proppant
usage per well, which is related directly
to the overall growth in the amount of
proppant supplied to the North American
hydraulic fracturing market. In 2012,
roughly 76 billion pounds of proppant
(frac sand, resin-coated sand and ceramics)
were supplied to North America. In 2018,
the proppant industry set a record of
more than 200 billion pounds.
But even as proppant quantity has increased dramatically, proppant quality
has deteriorated, driven by what might
be described as "just good enough economics." The use of higher-quality proppants such as resin-coated sands and ceramics has been marginalized, and companies now are focusing on even lowercost, poorer-quality sands sourced in close
proximity to well sites.

FIGURE 2
North American Proppant Consumption (billions of pounds)
240
200
Proppant Mass (Blbs)

viscosity friction reducers. In addition,
there has been a general change to cheaper
and lower-quality, locally sourced sands.
Overall, the industry is using fewer chemical additives and smaller additive volumes
to place a pound of sand in formation.
Denser fracture distribution is related
to:
· Stage counts are higher and stage
intensity is increasing. The average stage
count in resource plays has increased to
about 40 a well, partially as a result of
longer laterals, but also because of higher
stage intensity. Average stage spacing was
about 350 feet a stage in 2010 and was
reduced to about 200 feet/stage in 2017.
· Pump rates per lateral foot increased
from 0.16 to 0.42 barrels a minute/foot
from 2010 through 2017 to improve diversion along the lateral. This change
also has caused frac fleet sizes-measured
in horsepower-to increase rapidly.
· Perforation strategies have changed
toward extreme limited-entry with fewer
perforations and more clusters/fracture
initiation locations per stage for better
overall fracture distribution. Operators
also are grouping perforation clusters
along the lateral in similar type rock (enabled by measurement-while-drilling data)
to create more equal fracture growth from
each perforation cluster and "leave no
rock behind." The industry has developed
a range of chemical additives and particulate diverters to temporarily block flow
into subsets of stage clusters, aiming to
achieve a more equivalent distribution of
fractures and surface area complexity.

160
120
80
40
0
1990

2000

2010

2020

Data sources: U.S. Silica, PropTester/KELRIK

FIGURE 3
Use of Slickwater versus Guar-Based Gel Frac Fluid Systems

Reduction in job with gel

Increase in slickwater jobs

In general, larger proppant volumes
more than make up for poorer proppant
quality in the production response of
horizontal shale wells. A typical horizontal well has hundreds of fractures
reaching into the wellbore, meaning that
each frac carries an even smaller proportion of the total hydrocarbon flow.
This dramatically lowers the need for
fracture conductivity.
Also, the industry is beginning to indicate a preference for smaller proppants,
first shifting to 40/70 mesh, and more recently to 100+ mesh proppants. This
change is tied to the preference for lowcost, locally-sourced sands.
Companies are striving constantly to
find better chemical products and to pump
fewer of them. That is not only because
we are good people, but also because it
is good business. For example, the graphs
in Figure 3 demonstrate how slickwater
fluid systems, which use fewer chemicals
and less of them, gradually are displacing
more conventional and expensive guar-

based gels that contain more products.
This is an industrywide trend through
the shale revolution.
Limited-Entry Perforating
The driving force behind "limited entry" is increasing perforation friction by
artificially elevating bottom-hole wellbore
pressures above any pressure differentials
in the behind-pipe fractures. In a frac
job, this can be achieved through pumping
at a higher rate, pumping through smaller
perforations, and pumping through fewer
perforations.
Creating fracture complexity and a
denser fracture system is a balancing act.
It may be best to maximize a shale well's
production early by creating a fracture
every few feet along the well's lateral
section. However, the maximum achievable
pump rate often is limited in a frac job
by the blender or by the associated maximum pressure at the wellhead.
This may limit the maximum rate to,
say, 80-110 barrels a minute, which in
AUGUST 2019 89

American Oil and Gas Reporter - August 2019

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