Industry

Cement bond problems at UKOG’s Broadford Bridge well –  announcement to investors

Broadford Bridge 170827 Weald Oil Watch 2

Broadford Bridge oil exploration site, 27 August 2017. Photo: Weald Oil Watch

The Broadford Bridge oil exploration well in West Sussex has problems with the cement bonding, UK Oil and Gas announced this afternoon.

In a statement made after the stock market closed, the company said the cement bond on sections of the well were “less than optimal”.

This is the second formal statement made by UKOG recently to explain problems with the well at Broadford Bridge near Billingshurst.

Two months ago, the company confirmed it had permanently abandoned the first well after sections were washed out and it had drilled a sidetrack well, called BB-1Z.

The company had been expected to be testing the flow of oil in the Kimmeridge limestone by now. Today’s news explains why observers have commented that they have not seen any tankers entering and leaving the site.

UKOG said the problem with the bond meant that the wellbore was “not effectively” connected to much of the best open natural fractures. It said:

“The testing to date has not properly evaluated the full flow potential of the overall Kimmeridge reservoir sequence.”

Further fresh cement slurry will now be squeezed through the 7-inch casing to rectify the problems, the company said, in what it described as standard oilfield practice.

UKOG will need to bring back a workover rig to clean the well and carry out the cement squeeze.

The need to drill a the sidetrack at Broadford Bridge during the summer delayed the release of the previous workover rig to Angus Energy’s Lidsey oil site near Bognor.

Stephen Sanderson, executive chairman of UKOG, said:

“Although the forthcoming workover presents additional unplanned work, the reservoir zone’s cement-bond integrity is readily rectifiable by the planned short cement-squeeze phase, a common-place and routine oilfield practice. The well will then be restored to an optimal condition for further testing.

“I am confident that the revised forward testing plan will be able to deliver the results that will help demonstrate BB-1z’s near term commercial viability.”

The statement also said UKOG had recovered “measurable volumes of light oil and solution hydrocarbon gas to surface”.

  • UKOG shares opened on Wednesday 11 October down 30%.

Link to statement 

Updated 11 October 2017 to include change to share price

39 replies »

  1. I would be interested to know if these problems with the integrity of the cement were detected during the leak-off test. I am aware of anomalies in well water levels during and just after these tests which may indicate that the fracture zones of which Mr Sanderson is so proud are more extensive than even he thought. If the conventional flow test failed and the nitrogen lifting was unsuccessful, I would be worried about how much of the acid/water/’inhibitors’ mixture is still in the well or whether it is down there working its merry way through the pyrite and carbonate fracture bonds of the target zones and further contributing to the inherent instability of the target area.

    It would appear that the flagship project has sprung a leak. We all saw the iceberg but the captain ignored us. I hope the rats find safer investments.

    • Hi TWF,

      The reported water well anomalies (for which actual data hasn’t been released as far as I know – it was just mentioned in a council meeting some time ago) happened long before the testing phase commenced.

      A leak-off test is actually performed when you drill out the previous casing string, so would never have been done on the Liner on BB-1z. It primarily checks the formation strength for well control purposes – it would not indicate a lack of isolation behind the casing.

      The fracture zones in the Kimmeridge cannot extend up to the water wells – if they did, then the oil in the structure would have migrated up into them a long time ago!

  2. UK shale investment is clearly a significant risk. Too many unknown politically and geologically. Too slow to make progress as well. It is getting more like a stranded asset.

    • TW
      Yes, shale gas has been slow to turn up.
      Big Oil in the Weald as well.
      But one makes its own fractures and the other has trouble with existing fractures.

      • Agreed. But what it appears to be is such a highly fractured and geologically complex area to target that, as predicted by geologist David Smythe, it’s a pig to drill. During my site visit with Stephen Sanderson, and again in his various statements to local people, he made much of the ‘integrity’ of the wells that he would be drilling in response to local concerns surrounding the contamination of the environment. So far he has drilled one shaft that couldn’t hold its drilling fluid and another that requires cement injections in order to render it viable. There seems to me to be a distinct lack of integrity all round.

        • Jonathan
          I think the integrity of the well is fine. Looking at the RNS I would also not worry too much about a large gushing blow out. Maybe no large flare? Maybe just pump the oil out?
          But early days yet, and nothing out of the ordinary, lots of wells have issues. The good news is that onshore you do not have to pay £250,000 day plus for a floating drill rig ( or less for a jack up ).

  3. Firstly, my apologies to Paul Seaman who asked me to comment on this article earlier – I’ve been a bit busy the last week or so and have only just got around to it.

    Bear in mind that what follows is all conjecture on my part, as obviously I don’t have access to all the data or a wellbore diagram.

    With respect to the RNS itself, the timing of the issue is a little strange, as really they don’t have much to say. However, looking at a couple of message boards, there were some weird and wonderful theories as to why there had not been a statement on testing yet, so I suppose they felt obliged to put some of the more outlandish talk to rest.

    Issuing it at 5pm instead of 8am the following morning was, I believe – a mistake, as it allowed the “Market Makers” to place a couple of relatively large trades at very low prices, which immediately depressed the share price so much it triggered the stop-loss positions of many of the small investors even before they were logged on (and they are not happy about it..) and the ‘Market Makers’ hoovered up the resulting shares at a bargain price.

    http://www.lse.co.uk/ShareChat.asp?page=1&ShareTicker=UKOG

    Anyway, is the RNS good or bad news? Well IMHO it’s a combination of both.

    Remember, when it comes to RNS, what is stated HAS to be factually correct. That doesn’t mean it won’t be worded very carefully to try and obfuscate the true meaning.

    In that respect, it is absolutely correct to say that rectifying a poor cement bond by squeezing cement behind the casing (actually a liner on BB-1z) is standard oilfield practice (done lots myself).

    https://ptrc.ca/+pub/document/Kirksey%20-%20Squeeze%20Cementing.pdf

    My guess it’s going to be a low pressure hesitation squeeze, but I don’t have enough information to know for certain which placement / pumping / squeeze process UKOG will use on BB-1z.

    With respect to the additional perforated sections, these were obviously added after further E-Log examination and interpretation found additional potential reservoir sections that were missed on first pass processing.

    With improvements and new developments to the actual E-Logging tools themselves, plus increases in computer processing power over the years, this is not as common as it used to be (at least two UKCS Gas Fields, Rough and Morecambe Bay, were each completely missed by the first Well that drilled them). These days it’s more likely to be a result of concentrating initial efforts on where you think the potential reservoir sections are, then looking more closely at other sections of the logs as more time permits.

    It’s also important to emphasize here that what has happened in or behind the Liner on BB-1z does not affect the integrity of the rest of the Well – that’s still fine.

    So what happened on the BB-1z Well to get UKOG into this situation?

    Let’s look at the drilling process to start with. Contrary to what some posters have said, the drilling of a fractured formation in this context is actually fairly simple.

    Indeed, horizontal Wells (yes, I know BB-1z isn’t horizontal, but bear with me) were very much a niche operation until the Austin Chalk formation was developed in the USA in the 1990’s. Originally it was developed with vertical or deviated Wells, but that meant hitting the fracture network was pretty hit or miss – you might hit one or two fractures – or none at all.

    By drilling horizontally perpendicular to the fracture network orientation, you are guaranteed to hit not just one, but multiple fractures in the network. In other words, if the main fracture orientation is North – South, drill in an East – West direction to hit the most fractures. This put a large emphasis on developing the techniques and equipment for drilling horizontal Wells much more cost-effectively than before and it is the basis of those (much refined and developed since then) that we use today.

    In that respect, the Austin Chalk is analogous to any Kimmeridge Development, whether it be at HH, BB or elsewhere – using horizontal drilling to connect to as much of a natural fracture network as possible.

    During drilling (and it’s the same whether or not it’s a vertical, deviated or horizontal Well), the main problem is controlling lost circulation into the fractures. You don’t want to lose too much of the drilling fluid (‘mud’) for two reasons; firstly any mud that goes into the formation is pushing the oil further away from the well bore and that mud has to be produced back before the oil comes out. Secondly, losing too much mud gets expensive and can also be logistically problematical, depending upon how long your supply chain line is.

    The cheapest way to control the losses is by using lost circulation material (‘LCM’). The best LCM is graded (different sizes) of Calcium Carbonate. It can be effective in plugging up the fractures and is easily removed by an acid wash after completion. Other LCM’s can be used if necessary, but they tend to increase costs and may not be as easily cleaned out to facilitate production.

    Looking at the mud chemicals that UKOG had permission to use, Calcium Carbonate was effective in sealing off the fractures.

    The most expensive option is to use a shear-thinning (‘thixotropic’) mud system. The way that works is as it enters the fracture, it slows down and quickly develops a high gel strength, preventing further mud losses into the fracture. It’s very effective stuff – put some thixotropic mud in a mug and slowly turn the mug upside down – the mud will stay in place. Or slowly insert a spoon in the middle and it will stand up. Give the mug a bit of a shake (i.e. putting a shearing force into it), the mud will turn liquid and the spoon falls over.

    Thixotropic mud systems are commonly used when geo-mechanical (as opposed to chemical) issues mean that the hole is not stable and you need to add a weighting material (usually Calcium Carbonate or Barite) to increase the density of the mud system.

    As it’s shear thinning, the mud is produced back when the well is put in an underbalanced condition during the early stages of production.

    Where the problems tend to come is during running and cementing the Production Casing – or Liner in the case of BB-1z.

    Now, if it’s just a single fracture network, then it’s common not to cement the whole length of the liner at all – put some (if required) around the very bottom (‘shoe’) and either squeeze some in from the top or use a Stage Collar to seal off the top of the liner – likely in conjunction with an External Casing Packer (see link below).

    If it’s multiple zones and they need to be isolated from each other, then the whole process becomes more complicated, especially on an Exploration Well (i.e. BB-1z) where you don’t yet know how the fractures will behave during a cement job.

    The fact that UKOG felt the need to run a multi-zone completion and now have to do a cement squeeze means that there are either two different pressure regimes, or perhaps that they believe there are two separate fracture networks in different areas of the Kimmeridge.

    In those situations, it is common for the first Well to be regarded as a throw-away Well rather than a keeper for later production. This is because getting the information required for a possible development outweighs the cost of maintaining zonal isolation or re-instating the well-bore integrity in the bottom section of the Well. As a Drilling type, I fully understand this, but it still hurts to have to P&A a Well you just spent five months and $60 Million drilling….

    Having said that, it certainly looks like UKOG originally intended this to be a keeper. However, after the issues they have experienced – AND I EMPHASIZE THAT THIS IS ONLY MY CONJECTURE – I think that after the formal DST program is finished, UKOG may put the Well on temporary production by co-mingling the flow from all zones to get some revenue and get a higher daily production rate (‘stock market test’), while planning to re-enter the Well, recomplete or possibly side-track (from just above the current side-track) horizontally into the best fracture network; or P&A BB-1z and drill a second Well from the same Well pad.

    Note that the OGA will not allow them to co-mingle production for any great length of time, as it will not result in optimal recovery from the different zones.

    So, on a Well with at least two payzones which are fractured, how do you isolate the zones? Well, this is normally done with a combination of cement and External Casing packers.

    If you design the Well from the start as a ‘throw away’ for information, then isolation can be achieved by use of only ECP’s, because they will last for several years – sufficiently long enough to get the DST information – but ultimately in themselves are not a long term solution to zonal isolation.

    http://www.tamintl.com/applications/drilling-completions/zonal-isolation/overview.html

    In a Production Well, these are often used in combination with cement (or these days, sometimes resin is used) to achieve long term zonal isolation.

    The big advantage you have in a Production Well is that you now know how the fractures will react to being exposed to cement during the cementing process – not the case in an Exploration Well.

    The fractures may support up to a certain density or hydrostatic head of cement before taking losses, they may not support any cement column at all, or you might be able to pump all the cement you want without worrying about them.

    Obviously you don’t want to cement up the fractures, as that is your source of production and the cement is not as easily removed by acid as it will have gone too far into the formation.

    Reading between the lines, I suspect that UKOG got ahead of themselves by running a multi-zone Completion and it’s come back to bite them, in that they have failed to achieve zonal isolation.

    This could be for a number of reasons. Normally the most likely is that they took losses during the cement job, so the top of cement did not get as high as planned. However, this is usually easy to diagnose and I don’t feel is the case here.

    It sounds more like the cement partially channeled during the cement job, so in at least one section they did not get full 360 degree circumferential coverage around the liner, potentially allowing communication between zones behind the liner. However, an additional possibility here is also that some gas entered the annulus after cementing was completed, but before the cement had hardened (‘set’) which can also lead to communication between zones. It also sounds like at least some of the fractures took more cement than anticipated during the cement job.

    So how is the quality of cement behind the liner checked?

    To answer a couple of posters questions, pressure testing will tell you that the top (inside and outside) and bottom of the liner (inside) are isolated (which they clearly are in BB-1z), but not the quality of cement behind the liner.

    A leak-off test is something completely different – it’s actually taken when drilling out the bottom of the previous casing (casing shoe) and is taken to ascertain what the formation fracture gradient (pressure) is. When taken properly, it will tell the fracture initiation pressure, fracture propagation pressure and fracture closure pressure and is used by Drilling to work out how far they can drill the next hole section before having to set another casing string for well control reasons.

    To tell the quality of the cement behind the casing, there are a number of different E-Logs that can be run.

    I believe Schlumberger did the E-Logging on BB, and the link below is to their options for cement evaluation logs – I don’t know which one was actually run on BB-1z.

    http://www.slb.com/services/drilling/cementing/cement_evaluation.aspx

    Despite their pretty diagrams and assurances, it is quite common for a cement bond log to be not absolutely ‘cut and dried’ in its interpretation. Depending upon which type of log they ran, the fact that some of the hole section is in Limestone can also complicate interpretation because it’s known as a ‘fast’ formation. A ‘fast’ formation is the equivalent of hitting something and it rings like a bell, while a slower formation gives more of a ‘thud’. This means that it can be hard to differentiate the sound arrivals between those that traveled from the tools source to the tools receiver via the casing, those via the cement and those via the formation.

    Hence why UKOG didn’t know that zonal isolation wasn’t achieved until after they actually started testing the Well.

    Reading between the lines of the RNS, my feeling (again WARNING – THIS IS ALL ONLY MY CONJECTURE) is that they lost more cement than anticipated into the bottom zone, but this was not immediately apparent from the volumetrics of the cement job because the cement channeled.

    This also explains why they needed to bring in Premier Oilfield Laboratories and Xodus, as normally the bond log interpretation is done by the E-Log provider in conjunction with the Drilling personnel in the office. Once they started getting unexpected results from the DST program, the others would have been brought in to help interpretation of the bond log in conjunction with the DST results.

    As the test continued, they got light oil and gas back to surface, but were probably expecting heavier oil with little gas so it became apparent that there was communication behind the liner and that the bottom zone (you test a Well from the bottom up) wasn’t flowing as expected (hence why I think they lost more cement into the lower fractures than expected).

    The fact that they don’t state any flow rates or volumes in the RNS indicates to me that they did not recover large quantities of oil, so the channel must be small – hence why they believe (and I agree, if this is the case) that it will be easy to squeeze off. But it also means that the section of hole they were actually testing was either non-productive, or the fractures had been sealed by cement.

    Given the situation that they were faced with, UKOG had two choices. The best short term choice would have been to carry on with the DST program so they could issue a statement with respect to the flow rates achieved etc etc, keep the Stock Market happy and sort out the communication problem later.

    However, this course of action is not in best in the long term, as they would not have got enough information on the separate zones to aid in planning the Appraisal and possible Development program, and could have resulted in having to drill an additional Well to get this information.

    Given that UKOG have been increasing their exposure in the Weald basin by recent acquisitions and therefore see a long term future there, I feel UKOG chose to ‘bite the bullet’ and get the communication issue sorted out prior to proceeding with the DST Program.

    What does all this mean for UKOG?

    Well, in the short term it’s obviously a bump in the road and the precipitous drop in the share price reflects that – the current share price essentially means that the market regards BB-1z as a ‘dry-hole’ – which it could still turn out to be.

    In the medium term, it means that the rampant speculation will continue to surround UKOG for several weeks, until they can come out with an RNS on the DST results (they will probably issue an earlier RNS that the squeeze job has been successful and the DST program has commenced).

    In the longer term, there are two things that I find particularly interesting. Firstly they recovered solution gas to surface. This is fairly uncommon in the Weald, was not mentioned on HH and means that there is some energy in the reservoir (i.e. easier to produce). Very few of the Weald Wells will flow to surface under normal conditions because it tends to be a heavier oil with very little gas to assist – hence why artificial lift is needed right from the start.

    Secondly, and more importantly, on BB-1z as with HH, there are at least two separate pay zones – the Portland and the Kimmeridge. However, again, reading between the lines (CONJECTURE!), there may be more than one pay zone within the Kimmeridge itself, or perhaps the Corallian has been identified as a potential pay zone as well.

    In the longer term, this can only be beneficial as it means increased reserves, but time will tell.

    My personal opinion? Well, I bought 100k more shares in UKOG last Thursday……

    Hopefully all the above makes sense, but if you have any questions I’ll try and answer them.

    Oh, one more thing – which also is a sort of answer to a query that Philip P posed some time ago and I haven’t yet got around to responding to.

    If there are indeed two separate payzones in the Kimmeridge (or even one in the Kimmeridge and one in the Portland), it won’t necessarily take two separate Wells to produce from them. A single Well can have two or more horizontal laterals drilled from it while maintaining wellbore integrity and keeping the production from the payzones separate. So a Well Pad with 20 ‘Mother’ Wells (i.e. 20 Wellheads at surface) on it may have 60 or more ‘Daughter’ Wells that actually penetrate the Reservoir. Given the height of the Bowland Shale, this could also be the case for an unconventional Shale development.

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