The osmotic power of formate brines strengthens shales in the rocks surrounding wellbores and provides enhanced wellbore stability

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30 OIL & GAS TECHNOLOGY • rsy vkSj xSl ÁksS|ksfxdh
Special report: Drilling
Osmotic strength
How the osmotic power of formate brines is being exploited to stabilise
and strengthen well bores while drilling through shale
Shale is the most common sedimentary
rock encountered when drilling oil and
gas wells. In its simplest form, shale
is very simply compacted mud, comprising
a poorly cemented mixture of very fine clay
and quartz particles.
By definition shale is laminated and
fissile, showing a tendency to splinter
into thin fragments. Unless cemented and
strengthened by deep burial processes,
shale rocks tend to be quite weak and are
easily destabilised by
the drilling process.
Splinters of shale rock
detaching from
the borehole walls
during drilling and
tripping can cause
a variety of expensive operational problems,
including stuck pipe.
Supporting the well bore
To avoid creating shale disintegration
problems, any sections of borehole drilled
through shale rock need to be hydraulically
supported by the drilling fluid until cased off.
The hydraulic support is provided by keeping
the hydrostatic pressure of the drilling fluid
greater than the pore pressure of the shale,
in overbalance, and
ensuring that the fluid
applies a steady radial
compressive stress on
the borehole walls.
The key word
here is steady – the
supporting fluid pressure should not fluctuate
violently and it should not leak off into the
shale over time.
Unfortunately fluid pressure fluctuations
and pressure loss into shale over time are the
characteristic features of some traditional
drilling muds. Their high solids content and
associated thick rheology creates swab and
surge pressures when tubulars are run into
and out of the well bore. More seriously, the
filtrates of traditional water-based drilling
muds can easily flow into the pores of shale
rock and cause a pressure invasion front to
advance outwards into the rock surrounding
the borehole. At this point, the pore pressure
in the shale rises, the hydraulic support
provided by the fluid is lost and the shale
surrounding the borehole may begin to fail.
Water activity
The conventional solution to the problem
of pressure invasion in shale has been to
use oil-based drilling muds. These fluids are
emulsions of aqueous salt solutions in an
oil-phase, held together and aided by the
addition of emulsifiers, oil-wetting agents,
viscosifiers, fluid loss control agents and
weighting solids. Oil will not flow easily into
water-wet shale due to capillary resistance
effects, and so pressure invasion is negligible
unless the fluid overbalance is very high.
But something even more interesting
happens if the water phase emulsified in
the oil-based mud (OBM) contains a lot
of salt and has a lower water activity (aw)
than the water contained in the pores of
the shale5. Water activity is a measure of
the energy status of the water in a system,
Table 1 – Some oil and gas fields where formate
brines have been used as drilling fluids

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English Eyebrow
Special report: Drilling
and water will flow strongly from a high
water-activity environment to a low water-
activity environment. If the two fluids are
on opposite sides of a selectively permeable
membrane, the differential pressure required
to stop the flow of water, known as osmotic
pressure, can be as high as 4,000 psi. It has
been found that osmotic flow of water can
take place when an OBM containing low aw
brine is in contact a shale formation. The
net effect of the osmotic process is that
native formation water is sucked from the
shale into the OBM, against the overbalance
mud pressure, with the immediate effect of
lowering the pore pressure and strengthening
the shale surrounding the borehole.
Making the most of osmotic power
The discovery that compressed and
intact shale rock could act as a selectively
permeable membrane, and allow beneficial
osmotic flow of water from shale into OBM,
led researchers in Shell to experiment with
water-based fluids of low water activity and
very high osmotic pressure. Osmotic pressure
is a colligative property that is a function
of the type and concentration of solute
molecules dissolved in water. Solutions with
the highest content (measured in moles/litre)
of certain types of salt molecules tend to
have the lowest aw and exert the highest
osmotic pressure. The best-known oilfield
brines with low aw are calcium chloride
(with aw levels down to 0.3) and potassium
and/or cesium formate (with aw levels down
to 0.2). But even these are put in the shade
by cesium acetate brine, which in its most
concentrated form, has as remarkably low
aw of less than 0.1 – similar to concentrated
sulphuric acid.
The results of Shell’s research into the
effect of formate brines on shale confirmed
that their low aw could induce osmotic
back-flow in shale, leading to reduced pore
pressures and a strengthening of the shale
rock surrounding a borehole. These findings
were supported by further work conducted
by the University of Texas and the US Gas
Research Institute.
As added benefits, the viscosity of
potassium and cesium formate brines
reduces the rate at which they can flow
into shales, and they naturally inhibit
shale swelling. Furthermore, the low solids
content and low rheology of formate-based
drilling fluids reduce the swab and surge
pressures that are known to destabilise
boreholes in weak rock formations.
Table 1 lists the names of >30 oil and
gas fields that are known to have been
drilled with formate brines since their
introduction in 1993. The total number of
fields drilled with formate brines will be
much higher.
The formate brines have been particularly
useful in environmentally sensitive areas like
the Barents Sea, where they have been used
to drill entire wells from top to bottom.
Future fluid
The low water activity of cesium acetate
brine has a profound effect, not just on
its osmotic pressure and ability to stabilise
shale, but also on its other colligative
properties. Our laboratory investigations have
discovered that cesium acetate brines have
remarkably low freezing points over a wide
density range, very high boiling points for
a water-based fluid (up to 186oC measured
in our laboratory) and low vapour pressures
(down to 200 Pa). The low freezing points
indicate that cesium acetate brine will have
extraordinary hydrate inhibition properties
too. With this admirable portfolio of
properties, cesium acetate brine may have a
promising future as a drilling and completion
fluid. Its very low water activity could also
be exploited in hydrate dissolution, gas
dehydration, de-icing, air conditioning and
refrigeration applications. n
This article was written by John Downs
and Siv Howard, Cabot Specialty Fluids
Figure 1 – The water activity of formate and acetate brines as a function of brine density Figure 2 – Radical reduction in pore pressure of shale when exposed to
formate brine of low aw. Note the restoration of pore pressure when the
formate brine was displaced to sodium chloride brine