The now-famous Bakken formation has produced its billionth barrel and counting.
No matter this milestone, research continues.
There's always something more to learn.
AAPG member Zell Peterman, U.S. Geological Survey scientist emeritus, is busy with colleagues examining Williston Basin Bakken formation water and the role of shale filtration.
"Upper and Lower members of the Bakken are organic-rich black shales that were deposited in deep anoxic environments," Peterman noted. "The middle unit is mostly a fine-grained, commonly dolomitic, siltstone deposited in a shallower environment.
"Water from wells producing oil out of the Bakken is about an order of magnitude more saline (27 to 34 percent) than modern sea water (3.5 percent)," he said. "Evaporation of sea water in tidal flats and dissolution of evaporites are commonly proposed mechanisms
to explain saline water in deep formations.
"The latter is the prevailing explanation of saline waters in carbonate and some clastic reservoirs in the Williston Basin," Peterman commented. "But neither process adequately explains the salinity and element ratios of Bakken formation water."
Consequently, Peterman and others are conducting an isotopic and geochemical study of this formation water (brine) to elevate understanding of the long-term hydrodynamics of this unit.
The analysis will enable the group to compare their findings with formation water from adjacent units and to constrain the origin and evolution of the water, according to Peterman.
"Strontium isotopes, as shown by previous workers, are especially useful in compartmentalization within a stratigraphic unit," he emphasized. "Stable isotopes provide information on the origin of the water itself, and dissolved constituents record the effect
of long-term water-rock interaction and potential mixing of different waters."
Ion Filters?
The group has been studying formation waters in the Williston Basin for some time, beginning at the Fort Peck Reservation oil field in Roosevelt County, Montana, where the Mississippian-age Charles formation has been pumping out oil for 60 years.
The Charles is a conventional reservoir, and some of the older wells are producing 100 barrels of brine for every barrel of oil.
The formation water study there was environmentally related.
"Those brines in the injection wells are so salty they corroded the casings and the brines were coming back up and contaminating the shallow aquifer," Peterman said.
"I had some data saying the Bakken brines are different than what's in the Mississippian carbonates such as the Charles formation," he said.
So they decided to take a look-see to ascertain if the Bakken brines are distinct, which means they can be separated from the older brines.
"If they're different, then the Bakken production can't be blamed for previous contamination," Peterman emphasized. "Our aim is to understand the origin of the brines."
Oil field brines have been studied for decades, and various theories have been proposed as to how they form and what they mean.
Saline water in the Bakken can't be attributed to dissolved evaporite deposits, as the Bakken doesn't contain any evaporites, according to Peterman.
On the other hand, you can't look to salt concentration coming from evaporation of seawater in a tidal flat environment because the Bakken rocks weren't formed in a tidal flat.
Peterman presents his group's proposed resolution to this conundrum.
"When the Bakken silts were deposited, they had a lot of sea water in them, perhaps up to 50 percent by volume," he said.
"As the younger rocks were deposited and compressed, our hypothesis – and only a hypothesis – is that at some point the two shales on top and bottom became what you might call ion filters," Peterman stated. "Then, as the water was expelled, the salt was
left behind."
Admittedly not an oil geologist, Peterman asserted that the oil companies' interest likely will be piqued by this type of study to understand the fluid history of their reservoir rocks.