Chemical Engineering February 2012 - 15

FRACTURING WITH LPG
G
asFrac Energy Services Inc. (Calgary, Alta.; www.gasfrac.
com) is among a small minority of companies avoiding the
use of water as a fracturing fluid altogether. GasFrac uses
gelled liquefied petroleum gas (LPG) in place of conventional frac
fluids. Although the use of LPG as a frac fluid avoids many of
the supply and treatment issues found with water, GasFrac chief
technology officer Robert Lestz says the impetus for using LPG
was really to increase well productivity.
As a frac fluid, LPG has several advantages: whereas a large
portion of water-based frac fluids remain in the reservoir, where
they can contribute to reduced performance, virtually all of the
LPG is recovered along with the produced natural gas (also oil).
ability, pressure and temperature gradients,
mineral content - and about
the chemistry of the water initially
used in the fracturing job. Ideally, fracturing
water should be high-quality,
disinfected water that is free of chemicals
that could interfere with those
used in the fracturing or that might
damage the formation, Manz says.
" The best water for fracturing would
essentially be clean salt water with
low levels of divalent cations and low
bacteria load, " Grottenthaler suggests.
Kroff has completed studies that indicate
using fracturing water with
higher levels of chlorides (~80,000
ppm) boosts gas production at the well
compared to fresh water with total
dissolved solids (TDS) at low (~400
ppm) levels.
In addition to additives, flowback
water contains some natural formation
water that has been in contact
with the reservoir formation for millions
of years and thus contains minerals
native to the reservoir rock.
Although water is by far the most
commonly used fracturing fluid, other
techniques can avoid some of the water
use-and-treatment challenges associated
with water-based fracturing fluids.
For example, using liquefied natural
gas as a fracturing fluid presents
unique advantages, but also safety
challenges (see box, top of page).
Flowback water
After a fracturing treatment on a gas
well, the pumping pressure is relieved
and fracturing fluid, mixed with water
from the rock formation, begins to flow
back through the well casing to the
wellhead. In treatment-and-reuse scenarios,
this is the water that will serve
as the basis for fracturing fluid for the
next job. Otherwise, this water must be
treated before discharging to a municipal
water treatment facility, because
such plants are not designed to handle
typical fracturing-flowback water.
In most cases, wells recover between
The capillary effect of the LPG inside the fractures in the rock,
coupled with the LPG's solubility with natural gas and miscibility
with oil from the formation, keep the shale pore openings clear
and allow higher well productivity. Also, since mineral salts are
not soluble in LPG, they are not conveyed back to the surface as
they are with flowback water. With LPG, a lower overall volume
is needed to frac each well, and handling LPG plays into core
competencies of the oil and gas industry.
Fracturing with LPG presents safety risks. To mitigate them, Lestz
says that nitrogen gas blankets are used to isolate the frac fluid
from air, and all operations at the wellhead are completed remotely
during fracing, so that no personnel are close to the wellhead. ❏
20 and 40% of the water that was
pumped into the well for fracturing,
although the amount can be higher.
The portion of the fracturing water
that does not return occupies pores
and fractures in the shale formation
that have been vacated by the gas.
The well flowback rate is highest
initially and then decreases. There
can be wide variation in flowback
rates across geographical locations
and because of operator bias. A typical
flow profile could be the following:
the flowback rate over the first 1 to
5 days after fracturing is around 100
to 150 bbl/h, and recovers 10-25% of
the initially injected water; then over
the next 10 days, the rate decreases to
20 to 60 bbl/h and recovers another 8
to 12%. From 15 to 30 days past the
end of the fracturing job, 5 to 10 bbl/h
might flow, and for one to three months
past, 10 bbl/d may be recovered.
Treatment challenges and goals
While most flowback water from
shale fracturing operations shares
some characteristics, the physical and
chemical variations in water from different
geologic basins and even within
regions in a single basin are much
more pronounced. For example, levels
of total dissolved solids (TDS) can
range from 5,000 ppm to greater than
200,000 ppm. Other variable constituents
that need to be considered for
treatment operations include the following:
hydrocarbons (oil and grease),
bacteria, suspended solids, soluble
organics, iron, calcium, magnesium,
trace constituents (benzene, boron,
silicates) and possibly others, such as
naturally occurring radioactive materials.
As an example of the variability,
Kimball shared data comparing levels
of common constituents in water from
four different fractured wells (Table 1).
Moreover, flowback volume and water
properties can vary throughout the
lifetime of the well.
So the main challenge for engineers
is structuring water treatment strategies
around these variations on a regionally
specific basis. Shelley Martin,
a scientist in the office of research and
development at the Dept. of Energy's
National Energy Technology Laboratory
(Pittsburgh, Pa.; www.netl.doe.
gov), says regional differences in water
properties demand a localized approach
to treatment technology. " The goal is to
tailor water treatment technologies to
the particular region where the water
is coming from, " Martin says.
CDM Smith's Kimball explains that
generally, water treatment goals for
reuse are the cost-effective removal
of hydrocarbons, friction reducers and
other polymer additives, as well as the
elimination of inorganic scale-forming
compounds and bacteria.
Among the major fracturing water
challenges in shale wells is inhibiting
scale accumulation on the surface of
the formation, which can impede gas
flow and permeability, and reduce production.
In the view of Kroff's Grottenthaler,
" The number one problem
for water treatment is barium sulfate,
because its formation is virtually irreversible. "
Barium sulfate can also form
particulate matter that interferes
with the proppant. Following barium
sulfate, the next biggest problem for
water treatment is reducing bacteria,
Grottenthaler says. Dealing with iron
sedimentation and other scale-forming
substances, such as calcium and
magnesium are also important.
Among the viable technologies for
removing organics are oil-water separators,
dissolved air flotation, chemical
oxidation, biological processes, activated
carbon treatment, walnut shell
filters, organo-clay adsorbents and air
strippers. For inorganic treatment,
oftten-used technologies are chemical
precipitation, lime/soda softening,
clarifiers, ion exchange membranes,
sand filtration and others.
Describing an example treatment
scheme for incoming fracturing flowCHEMICAL
ENGINEERING WWW.CHE.COM FEBRUARY 2012 15
http://www.gasfrac http://www.netl.doe http://WWW.CHE.COM
Chemical Engineering February 2012

Table of Contents for the Digital Edition of Chemical Engineering February 2012
