Member Info for Slift

TimmyG,

The FID for Uganda will bring in investments of $20b to the project.
So the sale of 1/3 of the rights to Uganda is a big deal. Therefore, I'd expect it's own RNS for completion. Even if it doesn't come from Tullow, it will likely come from Uganda gov or Total etc.

"Nothing seems to make any sense with Tullow at the moment."
I think that the sentiment is just low in general for both Tullow and oil.
As at 30th June, Tullow was in good position, both operationally and financially.

I've said before that the concerns here (for the september update) are 1. Uganda sale (and hence RBL liquidity test) and 2. Ntomme-9 well.
If production hasn't dropped off between 30th June and now, then I expect liquidity to be in a good state too (even after delays in Ntomme-9 well).

Idk about addressing the fall in share price. Share price performance isn't down to Tullow. This is down to investors, and by the looks of it PI's after PMO's results.

All we could ask for right now is confirmation of completion of Uganda sale.
That would be a MAJOR DERISK to Tullow.

lol harryyoung,
The need for a RI and D4E is not because PMO reported a loss. I suggest you go research on PMO. While you're at it, research into Tullow too, because it seems like you're not talking any sense.

"last 4 months, most of the dealers think PMO is better than TLW, you can see the share price."
Lol, last 4 months TLW had more market cap than PMO.

"TLW have more debt"
Debt that is manageable as it stands (unlike PMO's prior to the recent creditor agreement)

"need some D4E to survive"
Will not deny this, but I think they can survive for the time being without.

"TLW is the same fate, it will be a loss"
Yes, this is obvious. Paper loss.

harryyoung,
"if TLW also report a loss, even may also have a D4E."

I'm quite clueless at this statement. But would love to know why there is a need for D4E if Tullow makes a loss.

JoeSoap,

"The reason for the RNS was therefore the first part"
IMO, I don't think so.. even with the AIM Rules Clause 11.
The word "material" downgrade was already mentioned on the 8th July RNS.
Also, the first part is titled "Technical Review Update". They have already said that the full technical review will be provided to us on or before the 11st September and that there will be a material downgrade following the technical review..

So they shouldn't even be providing us with this update as it is just repetition and not required. Especially when in the same RNS they state "technical review is ongoing and final conclusions have not been made".

Absolute disappointment. I'm not even fussed about the material downgrade, but i'm fussed about this RNS.

Just IMO.
Slift.

I'm still looking at this RNS and thinking "Wtf?".
https://ir.q4europe.com/Solutions/Hurricane2018tf/3942/newsArticle.aspx?storyid=14775353

No information here (including the shutdown of AM for repair) should have been provided as an RNS update.
The shutdown of AM would be under uptime and should not have been provided until results as an explanation as to why their uptime was low or why their production was lower.
The reserves downgrade should have been part of the technical review.

If they continue in this manner, then this is just shareholder destruction.

Conkclo,
Gas injection would only aid natural flow. I think the gas may cause cavitation with an ESP?
Agreed that water injection isn't ideal (unless both 6 and 7z are reworked shallower).

Hi SpruceGoose2,

Yes, agree that water injection is a candidate for future shallower-drilled wells. But I think deeper drilled wells with gas injection may be more derisked following the "new model" where the board has taken into consideration of a shallower OWC. With shallower drilled wells.. there's still the risk of OGC (oil/gas contact), which for the current Lancaster wells I don't believe we know anything about...?

"What is the connectivity at different levels, and would gas injection readily permeate the wider reservoir (if indeed there is one, and here i'm thinking Rona Ridge to Halifax), in which case a shipload* might need to be shoved in the cap"
Yes, we don't know the connectivity of the wells at different levels. But what can be managed is the pressure drop within the well. The pressure drop created by the 6 and 7z oil extraction can be offset by compressed gas injection. Thereby, maintaining the BHP and preventing other fractures (including the aquifer) from flowing in due to the pressure differential drive. This is probably easier said than done.

"Imho the most likely outcome of the reservoir situation is that the owc may be very variable"
I don't know what the technical model includes, and who knows, it may still be perched water. I prefer preparing for worst case scenario then finding out it's better than predicted.
And at the worse case scenario, the gas cap is connected via the aquifer - and so you have the aquifer displacing the oil in the well as the pressure is equalised throughout the connected fractures.
So in this case, the OWC will be variable and continue to rise up the depths of the well as oil is extracted.

"So Dr Trice, imo, may well be right, there. (I guess it depends where the temp's are being measured....) Or wrong."
Yes, agreed that there probably is insufficient time for heat transfer to take place until equilibrium. But we're also talking 2000 m3d-1 (Isn't this 4000..?) flow into a supposedly c. 4,500,000 m3 reservoir (at 1P reserves).
But who knows - as you say we don't know where T is measured, or if the 7z well ESP even pulls in directly from the aquifer fissure..

ALL just my understanding and opinion.
Slift.

PlantedBHA,
You really are an idiot. I don't know what you gain from being this deluded about a company you've invested in (or are you just here without an investment?).

Thanks conkclo,
They'd need a compressor to even inject gas in the first place. Ofcourse they'll have to keep reinjecting the returned gas and burn off the excess (if any). Most of the gas they inject will rise to fill a vapour space and also replace the volume lost due to oil extraction.

Now how much of the gas export/GWA TB longlead items (which they have already ordered) can they use for this? Tbh, I don't really care what equipment they need to make it happen.
I'm just after a single figure. I.e. Is it going to be $50m? Or is it going to be much more/less?

Slift.

@ngms27,
I'm not here to nick ideas or propose ideas.
Gas injection is common to increase the bottom hole pressure of wells.

In HUR's case however provides more than one benefit:
- Stabilisation of location of OWC (or possibly even force it deeper)
- Increase bottomhole pressure
- Decrease flaring
- Increase production
- No requirement for sidetracking wells/new well and so could be cost effective?
- etc.

But from what I can understand, if every other license is similar to Lancaster.. and if HUR wants to produce from another field.. then they're going to have to use gas injection from the get go (IF this is the option that they go for as the "production enhancement option")
So i'm only really after costs here as this impacts HUR's future regarding other fields.

@DiveCentre,
I totally understand RT's motive regarding data gathering. He had thought of the EPS as a pilot plant for the feasibility of FB. I think this concept is proven now.
But since the company is in survival mode, I don't think data gathering should come first here in my opinion. But we will see what the BOD thinks. But who knows, the BOD may have an EVEN BETTER MEANS of enhancing production.
But from what we know from what's available publicly, gas injection would be one of most effective solution.

ALL IMO.
Slift.

IMO, gas injection here will be the most effective solution.

Would anyone know the typical cost to incorporate gas injection? Will this be less than sidetrack of well 7z or new well?

Opinions appreciated.
Slift.

ngms27,

No, it really is that simple. No matter how complex it is. Because you are not displacing the oil within the reservoir (other than when producing). You cannot force the oil into other fractures as you are creating the pressure drop (negative pressure) within the well.
So are you saying that the laws of physics suddenly do not apply to this "complex reservoir"?

"when water produced = oil produced, watercut will be constant. When water produced > oil produced, watercut will drop. When oil produced > water produced, watercut will increase."
Just for clarification, this is rates of increase. If it really is the aquifer, then obviously watercut will increase until 100%. But the rates are:
When water produced = oil produced --> Linear
When water produced > oil produced --> Logrithmic/Linear
When oil produced > water produced --> Exponential

Slift.

Correction.
"When water produced > oil produced, watercut will drop"
This statement is depending on volume. If it's a finite volume, then watercut will drop as vapour headspace is produced. If it's an infinite volume, watercut will stay constant.
In this case, as it's an aquifer, it's safe to assume infinite volume in comparison to well.

ngms27,

I asked that question because I disagree with your statement. The watercut will increase at a slower rate as the watercut increases - due to the positioning, production and the current watercut of well 7z.

"there is no actual formula"
There is a formula, or rather 2. It's actually pretty simple.
1. Water from aquifer replaces volume of oil extracted. I.e. oil extracted = water inlet into well from aquifer
AND
The pressure drop that's driving the aquifer to replace the oil extracted. i.e. pressure drop in well = pressure drop in aquifer, for equilibrium.

You're saying "empirical evidence" of what's happened so far which is true.
If you actually provide scientific laws and explanation to what's happening, you'll know that the above with 7z is true, but also that watercut will increase at a slower rate as the watercut becomes higher.

Or in otherwords, when water produced = oil produced, watercut will be constant. When water produced > oil produced, watercut will drop. When oil produced > water produced, watercut will increase.

Slift.

ngms27,
"Water cut will not follow a linear pattern, I think it will increase quicker than your extrapolation if its coming from the aquifer"

Can you provide a technical explanation for this?

"Explain why the water ain’t perched then slift ?"

'I'm not saying that it is an aquifer or perched water.'

I don't work for Hurricane to answer that question. So rather than bothering me, why don't you go take that useless truck and pretend to drive 72 hours to Aberdeen to ask "Shiela" again? (P.S. Bev is likely based in Godalming.)

Or maybe instead, use whatever braincells you have left following the absolute crap you write on these boards to go understand what might be happening within the wells? That is if you really want to know.
And even then, what more crap you might come up with, it's not going to affect this company or the share price one little bit.

All IMO.
Slift.

PlantedBHA,

Point 1 and Point 2 is only really works if you do not consider the OWC and aquifer AT ALL.

I'm not saying that it is an aquifer or perched water.

But with the aquifer scenario:
Point 1) does not consider water settling due to Stokes' Law. The high percentage of water should settle into the aquifer, even when well is shut in.

Point 2) is not true with the 0th law of thermodynamics. The temperature of the aquifer at the oil/water contact will be at equilibrium (i.e. the same).

Slift.

oilheadgame,
Do you really spend your days and time watching people read word for word on a presentation?

I didn't learn much from watching the CMD. It was pretty self explanatory if you go through the slides yourself.
Sure there were some parts that were missed:
- Long lead items ordered
- Animations
- A few more points such as "data gathering this, data gathering that"

But everything else was pretty much provided in the slides.

Doc, shouldn't you be looking after your patients? I'm chilling working from home.

DiveCentre,

Yup sorry. I think adoubleuk had previously said that they were installed in a Y bypass arrangement.

Commissioning would still be under CAPEX if they required external contractors/manufacturers of the system to commission the ESPs. But yeah, still an unknown. I don't think unplanned costs would have exceeded $20m at a pure guess.

I think a bit too much has been priced into the SP, and it's partly Hurricane's fault in terms of releasing some information in RNS'.
At least revenue and cash in bank should have been provided in the corporate update on 8th July.. when they released Q2 and (H1) operational figures.

ALL IMO.
Slift.

DiveCentre,
I think I've also listened to the last few mins of the Q+A regarding perched water explanations. I'll have a listen to the Q+A at some point.

I don't want to get too technical, but I disagree with part of that animation in the CMD to explain why Hurricane were seeing high watercut at startup regarding the "downward ends" and the "upward ends".

Regarding cashflows:
Est. Revenue to date from 1st April: $66.1m
Est. Revenue from 1st April to end of year: $151.1m (assuming 14k bopd and $45/barrel for the rest of the year)

Company ops+CBond+G&A = c. $125m
OTHER costs (including hedge) at Est. $2/barrel: circa. $10m
Planned CAPEX for since 1st April: At least $27m

Free Cashflow (Not including unplanned CAPEX): c. -$11m

Hurricane will likely end the year with c. $140m free cash (Not including unplanned CAPEX/OPEX, i.e. installation of ESPs, repair of AM etc.).

Slift.