Well, yes and no sweeties.
Let’s take a quick look at some of the differences and similarities that are often discussed on social media shall we?
The fracture stimulation itself
First, cherubs, please don’t fall into the trap of assuming that hydraulic fracturing is somehow new. It’s not. In fact, oil and gas producers have been injecting fluids and proppants into their wells to improve yields for decades. It’s a well established practice the world over, including the UK.
It is true to say, pumpkins, that advances in directional drilling and reservoir stimulation techniques now mean we can extract oil and gas from source rock more easily than ever before, and that per well, this appears to be much bigger in scale than fracture stimulation uses in older, conventional reservoirs.
But contrary to the popular misconceptions often touted by anti-fracking activists, it may actually use less fluid overall.
Because, dears, the ability to drill horizontally now means a greater area of rock is accessible to operators with a single surface penetration – where before they’d perhaps need 10 vertical wells (with all the attendant drilling and completions activities, and each well requiring some degree of stimulation) they can now get the same amount of gas or oil from just one well that incorporates multiple hydraulically fractured stages. But the overall quantity of fracturing fluid used may not be all that different when compared to the cumulative fluid volumes that would have been used previously in all those separate vertical wells.
Now, of course, the geology and fracture mechanics are what really determine how much fracturing fluid is used in any given location and any particular stimulation poppets. Which is what operators like IGas are trying to understand by taking samples of rock at their Barton Moss site, and Cuadrilla at Clifton Marsh, to help them design their fracture treatments and model things like fracture propagation.
Wells per pad (the so called ‘super pad’)
There’s a lot of talk, dears, about so called ‘super pads’ of 40 wells being associated with the modern day search for shale gas in the UK. But, as I’ve pointed out before, flowerpots, that’s a good thing because it means we’ll see a much smaller surface footprint.
And that’s because the sort of operation envisaged in this multi-well pad scenario would see just 10 vertical wells drilled, each with perhaps 4 horizontal wells branching off deep underground.
Operators will be able to access a larger volume of gas from a condensed number of sites rather than having lots of separate vertical only wells dotted around the countryside.
‘Super pads’ will generate thousands of truck movements
Well, darlings, this is clearly just a red-herring in the debate because whether it’s 40 wells all at individual drill sites or 40 wells on a single pad, the amount of truck movements delivering water and fracturing fluid additives or hauling away waste will be the same.
But, when it comes to constructing the sites and drilling the wells, multi-well pads would actually have a lower traffic impact, dears, because the equipment would be delivered once and only removed when that particular pad is completed – imagine all the mobilisation and demobilisation activity saved by this approach versus lots of individual single well sites?
Improving the flow of hydrocarbons from conventional reservoirs that are more permeable than shale (such as limestone and sandstone) inevitably uses lower injection pressures dears. It’s a question of physics and fluid dynamics.
In shale, which is virtually impermeable, fracturing fluid necessarily has to be injected in at higher pressures. Is this a problem sweeties? Not really. The regulations demand the wells have to be constructed to withstand the pressures, so they are.
But not just because the rules say so, my loves, but because operators want to make their wells profitable and nothing eats into your profits like rework and repairs that stem from not doing it right first time, every time – and that’s the same whether you’re drilling wells, building houses or manufacturing widgets.
Some people would have us all believe that air emissions from modern day shale gas extraction will somehow be higher and more prevalent than in older wells drilled in conventional reservoirs.
But considering that the wells are built and completed to the same standards, dears, there’s simply no justification for this claim.
The storage issues identified elsewhere in the world won’t pose the same problems here, pumpkins, as noted below.
In the US, a report last year (McKinsey et al) suggested that people living close to shale gas wells were at a higher risk of developing certain illnesses.
Key, sweeties, is that this was a prediction. Not an observation of an increased incidence, but a prediction.
The report has been heavily criticised, and the authors themselves admit it contains defects. Which is why Public Health England didn’t take too much cognisance of it in their review last year.
Now, it may well be the case in other parts of the world, particularly where fracturing fluid containing volatile organic chemicals is stored in open tanks and where flowback waste is stored in open pits and volatiles are allowed to gas-off, that there is an increased risk of public exposure to potentially harmful substances.
But that’s there, dears, and this is here, where such practices just won’t be authorised. Look at any of the existing IGas onshore wells, like Gainsborough, or Perenco at Wytch Farm – all fluids neatly and properly stored in tanks, not pits.
I often see it said that shale gas extraction will create vast quantities of waste and that this is much more so than in wells that tap conventional gas reservoirs and that are fracture stimulated.
But that’s false, dears, because conventional reservoir rocks, that are porous and permeable, contain large quantities of ‘formation water’ – ages old sea water trapped under ground for millennia.
In fact, sweeties, conventional reservoirs often give up more of this ‘produced water’ than they do oil or gas.
Shale rock, on the other hand, being virtually impermeable, contains very little formation water and so you get back what you put in – up to half soon after flow starts and the rest gradually over the producing life of the well.
Flowback waste contains radioactive material and heavy metals at higher concentrations than tap water
Yes, poppets, this is true.
But it’s also rather meaningless as a comparison, isn’t it? Because, as most people will realise, tap water is extensively treated with chemicals to reduce impurities, filtered, and dosed with biocides to kill off harmful pathogens before it’s delivered to our homes.
It certainly doesn’t just come straight out of the ground.
But if it did, you’d find it laced with metals and naturally occurring radioactive materials because they’re everywhere in the Earth’s crust – it’s why we mine to obtain them.
Onshore oil and gas companies have been encountering these substances, and successfully dealing with them when extracting hydrocarbons from conventional reservoirs, for years. It makes scant difference whether you’re extracting from a conventional or unconventional reservoir – and fluid volumes / pressures associated with fracture stimulation certainly have no obvious influence, sweeties.
So, pumpkins, there you have it. What some people are trying to present as somehow different, bigger, dangerous – isn’t really.
Yes, there are differences in scale, but in some cases those differences will be positive (ie. smaller impacts, not greater) dears.
Until next time xxx