American Oil and Gas Reporter - February 2015 - 88

SpecialReport: Improved Oil Recovery

Surfactants May Boost Bakken Output
By Dongmei Wang
GRAND FORKS, N.D.-Oil recovery
from the Williston Basin's Bakken formation
relies on the reservoir's natural pressure to
push the oil through the rock to the well.
However, after producing a relatively small
fraction of oil, the reservoir's natural pressure
decreases and subsequent production falls,
typically leaving behind 95 percent of the
oil. Fortunately, the Bakken's huge reserves
allow the region to produce roughly 1
million barrels of oil a day because production is in its early stages. However, the
pressure eventually will drop and oil production will decrease, if not stop.
Declining oil prices have aroused concern that Bakken drilling will drop dramatically. Furthermore, while existing
wells will continue to flow-since the expenditures to drill, complete and hydraulically fracture them already have
been made-but production will decline,
rapidly in some cases. In a lower oilprice environment, what can be done to
extract all that remaining oil?
Researchers at the University of North
Dakota are analyzing new ways to recover
the vast amount of remaining oil that lies
beyond the reach of current technology.
Inquiry that has been funded under the

Research Partnership to Secure Energy
for America program suggests it is possible
to fracture with specially treated water
to drive much larger quantities of oil
from the shale and into the wells.
UND initiated a RPSEA-sponsored
research project (number 09123-09) that
evaluated enhanced oil recovery potential
from the Bakken Shale through surfactant
imbibition coupled with gravity drainage
in 2011, along with the North Dakota Industrial Commission, TIORCO LLC,
NALCO Champion's CorsiTech, and Hess
Corp. The project was completed in 2014.
Project Goals
One research objective sought to identify formulations that promoted imbibition,
which involves sucking water into the
rock and expelling oil while minimizing
clay swelling and formation damage. Another goal was to determine if surfactant
formulations could alter the Bakken
Shale's wettability. Experiments balanced
the temperature, pH, salinity and divalent
cation content of various aqueous fluids
to enhance oil recovery from shales of
ultralow porosity and permeability in the
Bakken formation's upper shale and middle member. The ultimate objective of
this research was to determine the potential

FIGURE 1
Bakken Formation Core Material

of surfactant formulations to imbibe into
and displace oil from shale, and to investigate the viability of a field application.
In North Dakota, the Bakken formation
generally consists of three informal units,
termed Lower Bakken, Middle Bakken
and Upper Bakken. The middle member's
thickness ranges from 40 to 70 feet.
Lithologies vary from argillaceous dolostones and siltstones to clean, quartz-rich
arenties and oolitic limestones with shale.
Middle member reservoir temperatures
range from 80 to 120 degrees C.
Based on chemical analysis of formation
waters and statistical data from 200 well
samples in the Williston Basin's pre-Mississippian formation (of which the Bakken
is the top), and chemical analysis of Bakken
water, brine salinities range from 150,000
to 300,000 milligrams per liter-15-30 percent by weight-total dissolved solids, a
salinity five-10 times that of sea water.
Figure 1 shows Bakken formation core
material, while Figure 2 illustrates the
laboratory setup. UND research shows
the Bakken Shale is generally oil-wet,
meaning the rock surfaces are coated
with oil. The researchers have examined
water treatments-mixtures of water and
surfactants similar to dish detergent-that
will make the rock absorb water and
expel oil. In other words, the process
alters the rock's wettability.
After this change, the rock's imbibition
draws in the surfactant-water and expels
oil in the process. The same fracture systems
and horizontal wells that already produce
Bakken oil then will collect that oil.
Some Results
Wettability has been studied using
cores from different depths in three Bakken
wells. Aqueous surfactant formulations
were tested for their capability to alter
shale rocks' wettability. They found:
* Most Bakken Shale cores were oilwet or intermediate-wet before the surfactant formulation was introduced.
* When the UND research group examined whether the imbibition process
would work if brine alone contacted the
rock, 25 percent of the tests recovered a
substantial amount of oil. However, for
the remaining 75 percent of cases, the surfactant formulation was needed to recover
additional oil. Research cannot yet predict
under what conditions brine will suffice.
* Surfactant formulations consistently

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