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30 OIL & GAS TECHNOLOGY • rsy vkSj xSl ÁksS|ksfxdh

Special report: Drilling

Osmotic strengthHow the osmotic power of formate brines is being exploited to stabilise and strengthen well bores while drilling through shale

S hale 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

31rsy vkSj xSl ÁksS|ksfxdh • OIL & GAS TECHNOLOGY

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