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Pressure depletion?

December 5th, 2009 · 2 Comments

It’s the last “argument” of the shorts. Is there anything in it… The argument is as follows: yes, those Elk, and more especially, those Antelope wells flow a very large amount of gas (as it happens, the Antelope wells set two consecutive world records), but we don’t know whether the pressure (and hence those flow rates) will be sustainable.

If they are not, it could be that InterOil will have to drill so many wells as to make the whole resource uneconomical.

Let’s put the latter into perspective.

1) A typical natural gas well

Lasts 3-10 years and produces less 1Bcf over its lifetime. If you open the choke at Antelope1&2, this would be close to what each of these wells could produce in a single day. We have yet to encounter anyone who argues these wells will peter out completely in a day.

We already know that at Elk1, two days of flowing the well didn’t produce any meaningful pressure decrease (see p.6 of this), let alone come to a complete flow stop. One has to realize that the Antelope wells are really quite something else, at least an order of magnitude bigger and better than the Elk wells:

  • They have 15-25 times the net payzone (88ft and 166ft for Elk1&4, 2277ft for Antelope1. Antelope2 already has over 1200ft and drilling hasn’t finished)
  • Higher average porosity because of much better quality rock in Antelope (reef with dolomite for a significant part).

Given the massive thickness of the reservoir in both wells, the fact that they are 2.3 miles apart and they all (including the Elk wells)appear to be in the same pressure regime, it’s not likely that pressure depletion of these individual wells will be a problem.

So it’s simply ridiculous to expect the Antelope wells to decrease to zero over a few days.

2) Coal seam gas projects need thousands of wells

There are wells that don’t flow at all, like the gas that comes from coal (‘coalbed methane’, or ‘coal seam’ gas). These wells don’t flow by themselves at all, they have to be made to flow by treating them with inordinate amounts of water. This is costly, and environmentally very damaging (the practice  is suspended for these reasons in a part of Canada).

The Conoco/Origin coal-seam gas project in Australia, for example, needs to drill (treat and man) 20,500 wells to supply it’s LNG facility. All that in a high-cost, high-regulatory environment (Australia), yet still the project is deemed economic, as billions of dollars are invested here, as well as in comparable coal seam projects. Coal seam gas is also of inferior quality, some Japanese utilities can’t even use it. If these are economical projects (billions of dollars are invested in these as we speak), we can now calculate backwards:

  • A single train LNG facility needs about 3Tcf of gas over it’s lifetime
  • If it takes 5,000 wells to achieve that, that’s 600MMcf per well over the lifetime of the well
  • Antelope1 and Antelope2 are each capable of producing that within a single day (remember the choke was far from fully open in their respective flowtests which yielded 382MMcf/d and 705MMcf/d respectively)

You might object that InterOil wells could be more costly to drill, but you have to remember:

  • It operates in a much cheaper environment (PNG versus Australia). This is reflected by the fact that the budgetted project cost of the coal seam projects are a multiple of the $6B InterOil project
  • It doesn’t need to treat those wells, with all the associated cost and risks
  • Past drilling cost for IOC are not a good indicator as there is something of a learning curve and the amount of testing new wells (which is largely done by third parties) will substantially decrease.
  • They already have four wells drilled and ready for production.
  • Unlike coal-seam gas, InterOil’s gas is of high quality (liquids and propane could be profitable byproducts)

So we’re not at all convinced drilling cost per well would be substantially more expensive at Elk/Antelope. And InterOil could very well have another crucial advantage (see 4 below). But for the sake of it, let’s assume that despite all the disadvantages of coal-seam gas, these wells cost only a quarter of the average Elk/Antelope well.

This changes the proposition somewhat, the Antelope wells merely have to sustain their flows for four days (and they can completely die down after that), or a little over a week if InterOil’s wells are eight times more expensive to drill. Again, the absence of any pressure depletion at the much inferior Elk1 well over two days makes this a very remote scenario indeed.

Operating cost wil be substantially higher. And as a matter of fact, because coal-seam wells flow much less, at any one time many more wells have to be in production. For a single-train LNG facility needing 500MMcf/d, this could be well over a hundred wells. Apart from the infrastructure that’s necessary for that, imagine also what kind of manpower is required to operate all these wells simultaneously. And this in a high-cost environment.

Break-even prices. That is why Morgan Stanley calculated that InterOil would have the lowest break-even price of any project in the area:

  • InterOil: $3.7 per Mcf
  • Exxon/OilSearch: $5.05 per Mcf
  • Seven Australian projects: $6-$8 per Mcf

3) Liquids and LPG production

Contrary to the dry coal-seam gas, InterOil’s gas is wet, that is, liquids stripping is a distinct possibility. Liquids stripping can be extremely profitable. Qatar is a good example of this, one could even argue that the gas is essentially a byproduct of the liquids, rather than the other way around. The production cost of the gas is reduced to near zero because of the liquids. Liquids are essentially a sort of very light crude oil. The presence of the refinery with almost half spare capacity further improves the economics of liquid stripping for InterOil (it now has to import crude from overseas).

The Elk/Antelope gas also contains LPG. LPG is primarily Butane and Propane (maybe a little Ethane). LPG is Liquefied Petroleum Gas which is liquid at atmospheric temperature but must be stored and transported in pressurized vessels. LPG must not be confused with LNG which must be stored and transported at very low temperature.

4) The Bertoni report

This is the report which is paid for by Barry Minkow’s FDI, who also shorts the stock) basically argues it is a ‘non-zero’ risk. Bertoni is the first person to bring this issue up. But saying it is a non-zero risk without even trying to argue whether it is a serious risk (or how serious) is not a particularly strong argument. The pressure in any well declines sooner or later, the question is how soon, and by how much.

His message board defenders say that it’s up to InterOil to show that it’s not a serious risk. As ‘serious risk’ we understand that it is so serious, as to make the whole Elk/Antelope structure uneconomical to develop. We already made some calculations above that the wells have to basically collapse to zero within a week to make the resource uneconomical (and even then the wells would be more productive than the typical gas well, with a lifespan of 3-10 years).

Bartoni could just as well have said that “earthquake’s” are a non-zero risk. And indeed, they are. But nobody forsakes an investment in the company because there is a “non-zero” risk for an earthquake. All of InterOil’s year-end filings and many others contain a long list of potentially “non-zero” risks (as do similar filings of basically all companies listed on a serious exchange).

That’s why Morgan Stanley (on page 6 of this first extensive Morgan Stanly report, there have been several updates since with higher price targets, available here) concluded that the Bertoni report was “not meaningful”. It’s also why the markets have yawned at the Bertoni report, InterOil has more than doubled since it appeared.

And, of course, that has also been the result of the fabulous new well that has been drilled since, Antelope2. Work is still ongoing, but the early result are really very good. The resource was found 345ft higher, leading to a larger resource and the dolomite section of the reef turned out to be larger than at Antelope1, leading to an average porosity of 14% so far.

It has also flown a staggering new world record of 705MMcf/d of gas and 11,200bbls/d of condensate, with the choke far from fully open). What Bertoni hasn’t done is to even faintly make credible that pressure depletion is anywhere near a serious risk.

All the available data point to the contrary. The wells could flow 90% less and still make this wells very productive (better than anything OilSearch has, for instance). One has to remember that in both the flow tests at Antelope1 and Antelope2 which produced those world records (382 and 705MMcf/d respectively) the choke was far from fully opened (in the case of Antelope1 only for 1/3). Morgan Stanley noted in an update on December1

  • Rapid pressure build-up following well shut-in, even at these record rates, offers further encouragement on both resource size and productivity

This a further indication that it is extremely unlikely that pressure depletion will ever be a serious problem, to the extent of making the Elk/Antelope resource uneconomical. And Bertoni wasn’t helped by the way his paymasters raped his report either.

5) Compartmentalization

This refers to a situation in which there are barriers to permeability that prevent vertical wells from completely draining the reservoir. The Bertoni report argues that this could be a risk, and significant pressure depletion over time is an indication. That is, compartmentalization is the root problem, and pressure depletion the manifestation.

The similar pressure regimes in the four wells drilled so far doesn’t indicate compartmentalization is a problem at Elk/Antelope, and even if it was, there is a way to deal with it, rather than having to drill many more wells.

A good example of this is provided by the Indonesian Arun field. Despite having a compartmentalization problem, it is one of the most profitable gasfields in Southeast Asia. Compartmentalization can be overcome by horizontal drilling, and that is exactly what has been done in the Arun field.

6) Cost

We think we have shown that it is unlikely that compartmentalization/pressure depletion is anywhere near a serious problem. That opinion seems to be widely shared as the Bertoni report hasn’t resonated.

Yet, one could argue, to end this issue once and for all, why doesn’t InterOil perform a long-term pressure depletion test? They might do that at a later stage when the resource is readied for production, but one has to reflect for a moment the cost of letting wells flow at 400-700MMcf/d, even for a couple of days.

These cost quickly become very substantial. This is gas that in it’s liquid form could sell for $10 per Mcf at least, so we could be talking about $5M per day. There doesn’t seem to be any compelling need for that right now.

Tags: IOC

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