The potent mixture behind fracking fluids

The potent mixture behind fracking fluids by Carrie Tait, September 6, 2012, The Globe and Mail Report on Business
You can find guar gum in barbeque sauce, ice cream, chocolate milk and cheese. You can find in it face creams, shaving cream and toothpaste. And you can find plenty of it in the oil patch, where guar bean gum serves as one of the most common frack fluid additives. Trican Well Service Ltd. , Canada’s largest pressure-pumping outfit with operations around the globe, buys guar bean gum powder, which looks and acts like cornstarch, from India. The Calgary-based company says guar gum is the frack fluid additive it uses most, as well as the most cost-effective thickener. Hydraulic fracturing companies use dozens of additives – plenty of which are harmful chemicals – when trying to crack rocks below the surface so the oil and natural gas trapped inside them can escape. Water is the No. 1 ingredient in frack fluid, and the additives – used to control the fluid’s viscosity, carry sand, kill bacteria, and perform other functions – are a key part of the rock fracturing process. The recipes change depending on geology.

Fracking is not a drilling technique. Instead, the process happens after wells have been drilled and lined with multiple layers of cement and steel casing near groundwater, and at least one layer throughout the rest of the well.
In short, hydraulic fracturing involves pumping frack fluid, sand, and sometimes nitrogen, down a well at extreme pressures, forcing fissures in rocks that are otherwise impermeable. Frack fluid goes first. So-called “slick water” fracks, which dominate the Marcellus play in Pennsylvania, use less additives and are therefore relatively cheap. Slick water frack fluid feels like slimy water, has the viscosity of milk, and sports a yellowish tinge.

The fluids used in so-called foam fracks and gelled water fracks are thicker – indeed, the stuff is nicknamed “ploppy gel” because of the way it would splatter if it hit the ground. Ploppy gel feels silky, and the off-white colour changes depending on the additive blend. If the snotty mixture is poured from a beaker, it moves as a blob rather than stream of water. Guar gum is used in gelled water fracks.

Frack fluid is made in the so-called blender, a large truck where the ingredients are mixed together. When sand is added, the fluid remains silky, but gritty. Pumper trucks push frack fluid through a pipe connected to the wellhead and down the wellbore. A separate pipe containing nitrogen may also be used, with the fluid and nitrogen mixing below the surface. They are pumped at extremely high pressures, and, if all goes according to script, will cause the target rock layer to crack. A typical fracture will be about one centimetre wide, 30 metres high, and 100 metres long, and comes with smaller splinters. As the fracture grows, sand is added to the frack fluid and into the cracks, which are typically between 800 and 3,500 metres below the surface, and stretch horizontally between 1,000 and 1,800 metres. Once the crack is open, sand is pumped in. The pumps are then stopped, and without the pressure, the fracture closes in on the sand. The closing rocks trap the sand, but the grains are course enough to leave room for the rest of the frack fluid to flow back into the wellbore. The sand, however, remains, holding open the man-made fracture. A successful frack will host between 10 and 50 tonnes of sand depending on the geology.

It may take as little as 15 minutes for the rock to close in on the sand after the pressure subsides. But it can also take up to a day, depending on the permeability of the rock. Without pressure generated from pumping sand and water, the frack will retract to its “effective” size – about half a centimetre wide, 20 metres high, and 80 metres long. In multistage horizontal fracks, which are common in unconventional oil and gas plays, the fracking company then isolates another section of the rock layer so it can force more fissures.

Geologists and engineers watch frack jobs in real time from offices such as Trican’s headquarters in Calgary. They can change the frack fluid recipe, size and amount of the sand grains, pressures, and nitrogen levels on the fly when the job does not go according to plan. They are in constant communication with the fracking supervisor on site, who radios orders to folks running the pumper trucks, the blender and other machines. They are all watching screens with graphs and charts detailing different pressure levels, fluid blends and location of the blends in the pipes. Once all the fracks are complete – this can be done in a day, or it may take several – the frack fluid is removed from the pipes. It may flow back to the surface naturally, due to pressure changes, or it may have to be “swabbed” out – a pumping technique. This frack fluid is then treated so it can be reused or disposed of as wastewater.

With the fracking process over, oil or natural gas will start to flow through the wellbore. The sand remains in place, but the hydrocarbons can now flow freely through the gaps between grains. Gas may naturally rise to the surface, but oil will need to be pumped. Frack fluid will be part of the initial mix, and it will be separated from the oil or gas. Eventually the well will produce largely oil or gas, alongside so-called “produced water.” This water was previously contained in the rock formation with the oil and gas. It contains minerals dissolved from the formation, and can be harmful. Like frack fluid, it too has to be separated and handled carefully because it can cause harm. [Emphasis added]

[Refer also to: Trican Donates $5 Million to Fight Childhood Cancer

AEA: Support to the identification of potential risks for the environment and human health arising from hydrocarbons operations involving hydraulic fracturing in Europe “A proportion (25% to 100%) of the water used in hydraulic fracturing is not recovered, and consequently this water is lost permanently to re-use, which differs from some other water uses in which water can be recovered and processed for re-use.”

The National Energy Board’s 2009 Primer for Understanding Canadian Shale Gas – Energy Briefing Note “Flow-back water is infrequently reused in other fracs because of the potential for corrosion or scaling, where the dissolved salts may precipitate out of the water and clog parts of the well or the formation.”]

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