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I’m still holding and been reading the postings today. What a major milestone we passed in the news this morning.
Waiting to hear opinion from Beetham, whose timing in acquiring 25 million shares has been visionary.
Then there is Tiburn, whose comments I always value. He has been tied up posting about RMP, AAOG and others.
Also, whatever happened to GeoDave? I await the RNS on drilling plans, commencing next month and BB discussion on strategy to prove up HAV & open the speculation on Black Hills (Saddle Reefs) and Scallywag
That Twitter comment was a cause for concern to me, as someone who had a career in oil exploration and production. Oil reservoirs are normally pressured and figures can be calculated as a function of true vertical depth. If the pressure is 200 psi greater than expected, I take it that the water incursion is from a zone that is overpressured I.e. greater than 0.465 psi per foot depth (hydrostatic). We could be alarmed if we thought that the source of this over-pressured water influx was from a deeper source where water had been injected under high pressure. JTP needs to explain.
I welcome the input from Mr Silas242, the Geologist, but personally do not agree totally with the explanation of operations that his friend has offered. My opinion is that the uphole tickling they have done using nitrogen bottles has failed to maintain flow or clean up the brine.
Getting the well flowing is the task in hand. Electric wireline logging after the first or second flow periods was documented in the outline welltest programme (whatdotheyknow website). There are sophisticated production logging tools with spinner flowmeters that can verify the contribution of oil coming from any part of the perforated interval.
We are nowhere near needing Schlumberger to run a PLT. I am waiting for reassuring evidence that the well is flowing or an RNS to explain why not & what the Ops Director is doing about it.
I will concur. ANGS tried to gas lift this well on the cheap. The worrying factor is that Balcombe, by contrast, flowed like Starwars just by turning on the tap, yet BR-4X is a different story, despite PV’s assumptions.
There is another cheap way of bringing a well in & that is Swabbing. I’ve seen it work on depleted wells but modern HSE concerns would not allow it.
Look up my previous posts on Coiled Tubing lift. I agree with Alan, it is the conventional method to bring a well into production and flow clean oil. However, there are documented concerns. http://www.ukogplc.com/page.php?pID=115
I agree with Alan’s previous explanation as to why BB-1 did not flow. It was not because they stimulated using a CT unit.
One other consideration for all to ponder: If Angs go ahead and try to produce with a linear rod pump, it is not as efficient as a CT unit. Alan pointed out that the CT nozzle can flow nitrogen opposite the deepest perforations. They can later pump acid to wash and stimulate using CT. a downhole pump is a different beast. The pump is anchored inside the base of the production tubing, near the tailpipe. It pumps fluid from the bottom of the tubing string - however, in the Brockham well, there is a large volume sump below this. 200m of perforated liner in the wellbore. That is a comparatively large volume. If the upper perforations clean up, what do you do about the reluctant lower perforations?
My view is that Angs will have to bring in a CT unit. Expensive, yes, but they are otherwise looking at writing off the entire cumulative well cost to date.
Thanks for your opinion on the latest drone photography of the Brockham wellsite. I am very interested in the technical side of attempting to get this well to flow. I have not sold my substantial holding in ANGS although I have suspected since the Christmas / New Year lay-off that things were not going as PV had assured us. I am on record as saying that a coiled tubing unit is normally used to stimulate the conventional Oolite limestone reservoirs to flow naturally.
However, another poster has pointed out that UKOG attribute CT nitrogen lift as being responsible for wrecking the flow possibilities of the BB well. I do not agree with their assumptions.
http://www.ukogplc.com/page.php?pID=115
Careful, progressive lifting of the fluid column with N2 using a CT unit appears to be the logical next step. The completion brine in the ‘sump’ below the tubing tailpipe will be difficult to lift in a highly deviated well bore when the Kimmeridge perforated section could need to produce and clean up a volume of completion brine before it will flow clean oil. Like Alan, I have an insight from experience of well testing. Brockham has to be cajoled into producing oil with natural flow. CT is expensive kit, so they may choose to run a downhole pump.
It could be weeks before they are successful in flowing BR4 and it is cleaned up of all tubing contents and invasive brine. The SP will continue to slide if pessimistic investors can not be patient. The next RNS will announce further stimulation with nitrogen using Coiled Tubing. Followed by an HCl acid wash.
The 2019 drilling campaign at Havieron will not be limited to 800 m hole depth. The magnetic anomaly extends down to 2,400 meters, which is the limit of data resolution. One mining expert at the AGM confirmed open pit mining has been excavated to 3,000 meters. GH confirmed that a heavy duty rig had been contracted but there has been no announcement of the planned number of holes or depth. Expect at least one hole to be drilled to the depth limit of the core rig. We await the results from HAD009 but if there is gold & copper to depth you can expect many people to conclude that mineralisation with precious metals could extend beyond 2,000 meters depth. I want it to be bigger & better than Telfer!
Nice try scallywag but not the correct picture.
Terminology: The annulus is the volume of completion liquid brine between the production tubing and the casing or liner internal diameter. This volume will be significantly greater than the contents of the 2-7 eighth inch OD tubing.
Another major point is that there is a production packer set in the lower part of the 7” liner. You can not pump nitrogen or kill brine down the annulus unless the packer is unset.
In depleted wells, a gas lift valve is placed in the tubing string which enables gas to be pumped down the annulus into the tubing to enable lifting the tubing contents (oil & water). https://medium.com/@marleerosegreasebook/how-a-gas-lift-valve-works-in-oil-gas-production-6b4cb448d8b
Brockham is not a depleted field and will flow under existing reservoir pressure once the heavy brine is cleaned out to light crude oil. There are no gas lift mandrels in this completion string, according to published info.
Normally in Weald oil wells (conventional Oolite limestone or Purbeck sst producers) the wells are lifted or stimulated using coiled tubing units pumping nitrogen into the tubing at depth. This is not the case at Brockham and it did not work at Broadford Bridge.
The ongoing nitrogen lift operations are outside my wellsite experience but I guess they are able to pump gas into the tubing, lifting completion brine out in small volumes.
Alan can hopefully corroborate but the clean up will take more time and needs PI’s to be patient.
Superb link and document content. Thanks PaddyGall. I am impressed with how Havieron fits in a technical context compared to Telfer and other IOGC discoveries.
Thanks also to reddirt for his ears to the geology network down under.
I have held many millions of shares for well over a year and have a comfortable feeling that the coming year could bring sensational announcements.
Thanks for the link to that document, JS, it is very informative reading on the BB-1 well. I have not seen or read it before.
On a first reading, my impressions are that they do not refer to formation and reservoir damage - the events and consequences detailed in Alan’s postings - which I agree are all important.
They state that nitrogen lifting with coiled tubing had the effect if damaging the micro-fracture system and limiting productivity. In my view, the fact that the shale/limestone is tight and unproductive was because they had choked the fluid pathways with fluid suspended fine solids. I have to be brief, as one could speculate at length here.
Regarding the perforation at Brockham: It should be immaterial if they perforated underbalanced and then shut in the well over Christmas. The reservoir is not going to be adversely affected by any long shut-in.
Apologies that I cannot discuss at greater length right now. As stated in previous post, there is good reason. I’m on holiday in the sunny wine lands of South Africa. Off now to have breakfast!
Apologies for the belated comment. I have good reason, and I am not trying to distract the bulletin board, Alan.
Despite all well meaning comments about N2 gas lift, there has been mis-representation and confusion.
As Anselmo stated, a perforated well will normally unload, clean up invasive fluids and produce oil under virgin reservoir conditions and pressure.
The post on gas lift is informative on gas lift principles https://m.youtube.com/watch?v=naI54wnAqFw but it illustrates the wrong application: Brockham is not a depleted reservoir needing Secondary recovery techniques. More importantly, the published information shows that the completion string - 2-?” tubing, does not have Side Pocket Mandrels or valves to enable gas lift from annulus N2 injection.
A more accurate & brief overview is as follows: https://www.glossary.oilfield.slb.com/en/Terms/n/nitrogen_kickoff.aspx
Before anyone questions my professional right to comment, let me say that I am a retired former drilling, completions & welltest engineer with onshore experience in the Weald of stimulating tight formations (Portland, admittedly) to try to produce naturally, without a pump. In my experience, all liquid unloading work inside the production tubing was achieved using a Coiled Tubing unit pumping liquid nitrogen. See above link for more detail.
I have seen no comment from the Eyes on site that a CT unit was used. If stimulation and tubing contents were unloaded in another way then good on them. CT is expensive kit.
Hopefully, this discussion is for the record & of less relevance now we appear to have heater evidence that the well is flowing.
I have invested a large sum in Angus and remain very optimistic that B4 will be a good producer. I concur with Alan’s 1,000 bopd conservative figure. Remember, production will be constrained in the early period.
However, I have my concerns about proving up an untested hybrid reservoir. I was burnt when I sold my UKOG holding after the BB fiasco. Alan is correct, once again, in his analysis of what went wrong. If I remember correctly, even Vonk said at the time that they had used the wrong drilling fluid. Angus used Oil Based Mud.
Good luck all
My wife & I, both shareholders, will be voting to keep the present BOD. I agree with other posters that Vonk has not distinguished himself in the last year but he is the least disastrous option to carry Angus forward in the interest of shareholder investors.
Most likely requirement for the blue slick line unit is to run and set pressure monitoring gauges for the first 3 flow and shut-in periods once the well test commences. It is all stated clearly in documentation from Angus that was published on the whatdotheyknow website. There have been many links to this posted on the B.B. over the last few months
For the record, during the AGM GH stated the all-in costs of a drilling campaign.
$250 AUD / meter - equivalent to £140 GBP or $240 CAD.
This includes lab assay costs in addition to DDH, the core drilling contractor. A heavy duty rig capable of drilling beyond 850 meters would be higher dayrate or cost per meter.
Comparing apples to apples, this is 3x higher than the figures used by Tiburn. An excellent article, nevertheless.
Thanks Tiburn.
There is every possibility of good news on Friday. Look at the well test steps to initialise production. Page 2.
https://www.whatdotheyknow.com/request/424952/response/1066246/attach/5/Scan2017%2009%2004%202925%20001.pdf?cookie_passthrough=1
These steps - initial flow, initial shut in, 2nd or further flow periods followed by longer shut in & pressure build up periods - are standard well testing requirements that have been followed for 70 years or more by engineers for reservoir evaluation. For those who need further info on testing procedure, look at:
https://www.slb.com/-/media/Files/resources/oilfield_review/defining_series/Defining-Well-Testing.pdf?la=en&hash=1C0809A942A72A062C8FC4D5717D7DE1812217F8
There was never going to be any “turn the tap on” / open up the valve manifold on maximum choke to see immediately if it will produce above 3,000 bopd.
No! PV’s signature was on the above BRX-4Z document. He states that production will be initially constrained, based on assumptions made about the likely rate at which the fracture system can sustain production.
They are not going to screw up this well by flowing hard just to satisfy the expectations of impatient investors. These words come from the man who knows enough about how UKOG screwed up Broadford Bridge by wrecking a delicate natural fracture flow system by blocking the flow pathways with solid fines contained in the drilling and completion fluid.
The Production Logging Tool run on wireline is there in black & white text, Step 7.
Everything is going to programme. It may be too early on Friday to release information interpretation from the PLT but we could get a statement that flow continues and they will take advantage of the holiday period to do a long shut-in / pressure build up for reservoir evaluation.
Remember, they are unable to allow traffic into or out of the wellsite on Sundays or public holidays. Let them keep the local residents on-side.
Time to review some important documents over this weekend.
The rig and crew are on site and will be working 24/7. There is a constraint on HGV movements to Brockham site with restrictions on Sat half day & Sunday. The equipment is all assembled on site and my opinion is that we are in a quiet period between mob and demon, as shown on page 10 of this document:
https://planning.surreycc.gov.uk/DisplayImage.aspx?doc=cmVjb3JkX251bWJlcj01NTg4KmZpbGVuYW1lPVxcREVGXE1hc3RlckdvdlxEb2N1bWVudHNcUGxhbm5pbmdcU0NDIFJlZiAyMDE4LTAxNDBcQnJvY2toYW0tWDR6IFdvcmsgU2NoZW1lIGZvciBQcm9kdWN0aW9uIEV2YWx1YXRpb24gKFJldjAyKSAtIE1HTyBSZXZzIDE1LjExLjE4KDEpLnBkZippbWFnZV9udW1iZXI9Ni4wMDAwKmltYWdlX3R5cGU9cGxhbm5pbmcqbGFzdF9tb2RpZmllZF9mcm9tX2Rpc2s9MTYvMTEvMjAxOCAxMjo0NzowMg==
I am not as optimistic as Alan2017 in expecting the TCP guns will be fired today or this weekend even. It is worth looking at Angus’s summary of perforation and initial flow operations.
https://www.whatdotheyknow.com/request/424952/response/1066246/attach/5/Scan2017%2009%2004%202925%20001.pdf?cookie_passthrough=1
The production packer will be set after the guns have been activated. Once the packer is set, it is questionable whether the reservoir will be able to free-flow immediately, or require some lifting to provide the under balance of hydrostatic pressure that they refer to. I would not be surprised if they need to temporarily use the rig Derrick to swab-in the well until it flows. Alan Thornton may have a different opinion.
Any which way, in my opinion pi’s were being over-optimistic expecting flow today from this well. People should not start to panic if there is no RNS on Monday because preparatory operations are continuing.
I do believe one thing - that PV was right to say this well will have initial flow by Christmas and certainly a good idea of productivity will be clear before the end of the year.
Have a calm and confident weekend.
1. A sidetrack well at Brockham can not extend laterally beyond the Production licence area acreage. Nor would you need to.
2. Look up extended reach drilling ERD, on Wikipedia. The record for a well step-out is almost 7.4 miles. However, that was drilled to 13,500 meters depth and bears little in common with the well design at Brockham.
Good explanatory information on reservoir pressure relationship to oil flowrate. However, it fails to mention one important factor: Depletion.
We are aware of the water injection well at Brockham. The fact is that as oil is produced from a reservoir the formation pressure declines to a point where there is no natural flow and oil has to be pumped out. Equally important, water is injected to maintain reservoir pressure and fill the void / porous rock space, thereby driving oil up (to shallower depth in reservoir trap).
To use your analogy of fluid in a lake, or better still, a bucket - imagine the container half full of oil / the rest is water. Oil separates and fills the top half of the container. When they complete a well and perforate, whether it is a slant hole or horizontal well, the target zone will be the upper reservoir. Perforate and draw off the oil from the top of the structure. If they produced from the bottom, it may have a few psi more pressure but it would water out rapidly.
Now the final question is one of long term producibility from a naturally fractured and ‘hybrid’ reservoir. We know that once the KL-4 is put on production, there will potentially be a very high initial flow rate. This is expected to decline and stabilise at a high commercial rate. What is still unproven, both at HH and Brockham, is the drainage area. Are all these micro-fractures containing oil interconnected with each other like a massive spiders web that extends for miles around the Brockham sweet-spot. If the area of produceability is limited, the oil production will decline over months, maybe weeks, to a point where it matches Lidsey.
Nobody can be confident about long term oil depletion. We are in un-tested territory. I hope this is not too technical an explanation. Alan2017 will possibly give it authenticity. I hope it enables many of you to better understand some crucial issues in extended well testing.