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Bottoming out

Well that unusual red sandstone that we met about one mile down persisted – all the way to 1800m in fact.  After that the rock type changed again, and we seemed to be in an unusual mixture of strata which we suppose are some of the oldest beds from the Carboniferous period. These unusual strata proved to be very hard, however, so drilling rates reduced considerably. Once it was clear that we weren’t going to go back into the enticing red sandstones anytime soon, and when we got to the point where our coffers contained only small change, we decided to declare an end to deepening the borehole.  This was at a depth of 1821m – which gives us the deepest borehole ever drilled on Tyneside, and in fact the deepest direct heat use borehole in the UK (it’s a wee bit deeper than the Southampton Borehole).

Before we pulled all the tools out of the borehole we gave it a good flushing out, removing the dense drilling mud and replacing it with clean water. Then we started the lengthy procedure of demobilising the drilling rig. One pleasant surprise awaited us when we finally lifted off the Blow-Out Preventer: those red sandstones in the bottom 300m of our borehole contain water under such pressure that it rose right to the top of the well.

After cooling down a little bit, the level settled down just a few centimetres from ground level. That is potentially very useful for us, as the shallower this artesian water level is, the more heavily the deep sandstones could in principle be pumped in future. We capped the borehole off for the time being with a specially constructed cap that includes a water pressure gauge and a valve we can open to drain water out, if we ever want to (it may be, for instance, that the water pressure increases seasonally – we’ll have to wait and see). Finally, we covered the borehole chamber with a strong concrete cover, to keep everything safe and sound until we return to test the borehole in the autumn.

So now the borehole is enjoying its summer holidays: we are basically leaving it to “rest”, which means that the water in the borehole will be gradually mixing with the native groundwater, so that when we go back in for testing, it will give us representative measurements of temperature and other parameters. We remain optimistic that we have a very good chance of developing deep geothermal energy on the site – but we’ll have to wait till our autumn test work is complete before we can say quite how much heat the borehole will yield in the long term.

Filed under: Renewable energy

Comments: 5 Comments on Bottoming out
Posted on: Aug 19 2011

5 Responses to “Bottoming out”

  1. Prof Paul Younger says:

    Until we have our own data, we can only base our future projections on the long-term performance of established geothermal wellfields elsewhere in the world, where (irrespective of initial absolute temperature), the local depletion of stored thermal energy is such that individual wellfields tend to need to be rested after about 40 years of continual use. At that point “make-up wells” are drilled along geological strike to provide the extra thermal energy required. As recovery in thermal profile is exponential (as is well known from thermal conduction theory), the resting wellfields can usually be brought back on stream a lot sooner than the 40 years it took to deplete them.

    We are not, at present, considering hydraulic stimulation of the geothermal reservoir – we have a huge “freeboard” of head to draw on, and can likely get large yields without attempting to enhance the natural permeability. Having said that, I do not subscribe to the hysteria against fracking: it’s been done safely for years for many purposes (e.g. many of the communities in the Scottish Highlands only have clean water thanks to fracking from wells drilled into otherwise poorly permeable strata, such as Torridonian Sandstones), and to the extent it might give rise to barely-measurable micro-seismic activity, this is harmless; to maintain otherwise would be equivalent to calling for a ban on all aviation on the grounds that it is noisy: it undoubtedly is, but the benefits are held (by society as a whole) to greatly outweigh the nuisance. The only potential issue I see with fracking is if it’s not handled well at surface, and you get spills of chemical additives or produced waters. This is no different from any other industrial process, and can be readily managed using long-established environmental control practices.

    I’m not sure what you are on about in relation to the “Nordic” countries. They have a large preponderance of ground-source heat pump systems, exploiting shallow unconsolidated sediments and rocks of any and every lithology which is found locally. In passing I’d note that, contrary to your suggestion, these lithologies hardly ever include basalt, which is very rare in the Precambrian Fenno-Scandian Shield, which underlies most of Sweden and southern Norway. (The northern part of Norway has Caledonide rocks similar to those in Scotland, the Lake District and North Wales, which include some andesites, but again precious little basalt). The lack of basalt doesn’t really matter anyway as, again contrary to your suggestion, basalt does NOT have a “higher heat content” compared to other rocks. On the contrary, basalts are very poor producers of primary heat by radioactive decay, and are terrible heat conductors. In fact the granites (and metamorphic rocks of similar composition) which comprise the Fenno-Scandian Shield are very similar to the ultimate heat source for our project – the deeply-buried Weardale Granite of the North Pennines.

    Finally I’m not sure why you consider British sedimentary rocks to be “sensitive” – this sounds rather like anthropomorphism to me. Sensitive to what? To fracturing? It is just as feasible (in fact in some ways easier) to fracture basalt or granite as to fracture deeply buried, lithified sedimentary rocks.

  2. AleaJactaEst says:

    A quick question to the Prof – “payback time over 10-25 years…” have you done reservoir analysis that shows how the reduction on heat reservoir temperature will affect the wellbore stability and surrounding groundwater aquifer for the region?. I am of course, drawing analogies to the “greens” resistance to natural gas well “fraccing” which is effectively what geothermal wells will be doing to the formations in and around the borehole. Might I also comment that these boreholes bear no resemblance to those successful ones in the Nordic countries where geothermal energy is derived from basaltic source rocks which have much higher bulk densities, much more shallow and higher heat content and are not as sensitive as our local sedimentary strata.

  3. Paul Steverson says:

    I would like to congratulate the prof and his team on completing the well.

    Can I ask a few questions regarding the cost of the well?
    Specifically, the hardware cost, and the software cost (the design, the cost of the permits required and the risk assessments (no doubt required by the planning authorities.)

    What thermal output (in Kws) is necessary and for what lifespan in order to get a payback for all your hard work.?

    I understand that when doing a ‘wildcat’ well there are no guarantees, but when the geological area under investigation is ‘mapped’ there will be a point when a positive payback could be achieved for further wells and also one when there will never be a payback, and it would be better to invest one’s money elsewhere.

    Anyway I am delighted for you that the water pressure is favourable, and I look forward to the next chapter of revelations.
    Yours Sincerely

    Paul Steverson

    • Professor Paul Younger says:

      Thank you very much for your interest in our progress. As regards to the cost, so far we’ve spent about £1.2M in total, and have a £40K testing programme in prospect this autumn. Once our forthcoming test work is complete, we will be able to determine whether we can reasonably proceed to get a few hundred KW or several MW from the resource. Fitting the well out for further use will require around £50K for the former, but perhaps as much as £900K (i.e. drilling a reinjection borehole) for the latter. Depending on which of these it is, the payback time could be anything between about 10 and 25 years.

  4. Allison Riches says:

    Dear sir, do you see this being a system which individual communities may use in the near future or is it a system to be reserved for central UK economic usage to account for, say, 5% of total energy? It would be great if it was economically viable without the Government having to put massive subsidies into it, unless of course it became a nationalised industry…..

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